Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
All statements in this section, other than statements of historical fact, are forward-looking statements that are inherently uncertain. See “Disclosures Regarding Forward-Looking Statements” and Item 1A. Risk Factors for a discussion of the factors that could cause actual results to differ materially from those projected in these statements. The following information concerning our business, results of operations and financial condition should also be read in conjunction with the information included under Item 1. Business, Item 1A. Risk Factors and Item 8. Financial Statements and Supplementary Data.
EXECUTIVE SUMMARY
Business Update
Our Refining & Marketing segment results for 2025 versus 2024 reflect higher realized refining margins supported by stable demand and by gasoline and distillate inventory levels in the U.S. that were at or below five-year averages. Longer term, global demand growth is expected to outpace the net impact of refining capacity additions and rationalizations through the end of the decade. We anticipate these fundamentals, as well as the U.S. refining industry’s current structural advantages over the rest of the world, will support a constructive environment for U.S. refiners.
Our Midstream segment contributed strong results and continued growth in 2025, benefitting from the expansion of its Permian to Gulf Coast natural gas and NGL value chains with the Northwind Midstream Acquisition and the BANGL Acquisition, progression of long-haul pipeline growth projects and expansion of Gulf Coast fractionation and export facilities. We believe our Midstream business is well positioned and has significant opportunities to support the development plans of its producer customers.
In response to the current business environment, we continue to focus on the following priorities for our business:
Commitment to Safety, Reliability and Sustainability
We remain steadfast in our commitment to safely and reliably operate our assets and protect the health and safety of our employees. We are focused on sustainable structural changes to improve our cost competitiveness while maintaining safe and reliable operations. Our approach to sustainability spans the environmental, social and governance dimensions of our business. That means strengthening resiliency by lowering the carbon intensity and conserving natural resources; innovating for the future by investing in renewables and emerging technologies; and embedding sustainability in decision-making and in how we engage our people and many stakeholders. We have existing targets for reducing Scope 1 & 2 GHG emissions intensity, for lowering methane emissions intensity and for lowering our freshwater withdrawal intensity.
Operational Excellence
We are committed to achieving operational excellence by reducing costs, improving efficiency, driving operational improvements and being disciplined in capital allocation. This means lowering our costs in all aspects of our business and challenging ourselves to be disciplined in every dollar we spend across our organization. We look to optimize our portfolio of investment opportunities to ensure efficient deployment of capital focusing on projects with the highest returns.
Commercial Performance
We are focused on leveraging the complexity of our facilities by selecting advantaged raw materials, new approaches in the commercial space to be more dynamic amidst changing market conditions and achieving technological improvements to advance our commercial performance.
Integrated Value Chain Optimization
We are committed to leveraging our value chain so that we are a leader in operational, financial, and sustainability performance. Our goal is to improve value chain optimization with a more integrated and advanced approach to decision making so that each individual asset generates free cash flow back to the business and contributes to shareholder returns. With our investments, we are focused on high returning projects that we believe will enhance the competitiveness of our portfolio, including our investments in sustainable fuels and technologies that lower our carbon intensity as the global energy mix evolves.
Strategic Updates
Midstream Transactions
Divestiture of Rockies Operations
On November 12, 2025, MPLX completed the sale of its Rockies gathering and processing assets (the “Rockies”) to a subsidiary of Harvest Midstream (“Harvest”) for $980 million in cash. The transaction resulted in a gain of $159 million.
See Item 8. Financial Statements and Supplementary Data – Note 5 for additional information on the sale of the Rockies.
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Northwind Midstream Acquisition
On August 29, 2025, MPLX completed the acquisition of 100 percent of Northwind Midstream for $2.4 billion in cash. Northwind Midstream provides sour gas gathering and treating services in Lea County, New Mexico, which enhances MPLX’s Permian natural gas and NGL value chain. The Northwind Midstream Acquisition was accounted for as a business combination. The Northwind Midstream Acquisition and incremental capital expenditures associated with in-process expansion projects, were financed with a portion of the net proceeds from MPLX's $4.5 billion senior notes issuance in August 2025.
See Item 8. Financial Statements and Supplementary Data – Note 5 for additional information on the Northwind Midstream Acquisition.
BANGL, LLC Acquisition
On July 1, 2025, MPLX purchased the remaining 55 percent interest in BANGL, LLC (“BANGL”) for $703 million cash, plus an earnout provision of up to $275 million based on targeted EBITDA growth from 2026 to 2029. As a result of the BANGL Acquisition, MPLX now owns 100 percent of BANGL and its results are reflected in our Midstream segment within our consolidated financial results. The BANGL Acquisition was accounted for as a business combination, resulting in the recognition of a $484 million gain.
See Item 8. Financial Statements and Supplementary Data – Note 5 for additional information on the BANGL Acquisition.
Whiptail Midstream Acquisition
On March 11, 2025, MPLX acquired gathering businesses from Whiptail Midstream, LLC for $235 million in cash (the “Whiptail Midstream Acquisition”). These San Juan basin assets consist primarily of crude and natural gas gathering systems in the Four Corners region. The acquisition was accounted for as a business combination.
See Item 8. Financial Statements and Supplementary Data – Note 5 for additional information on the Whiptail Midstream Acquisition.
Sale of Interest in Ethanol Joint Venture
On July 31, 2025, MPC sold its 49.9 percent interest in The Andersons Marathon Holdings LLC (“TAMH”) to The Andersons Ethanol LLC (the “Ethanol Joint Venture Sale”) in exchange for cash proceeds of $427 million. MPC’s investment in TAMH was accounted for as an equity method investment and previously reported in the Refining & Marketing segment. Upon closing, MPC derecognized the carrying value of the equity method investment of $173 million and recorded a gain of $254 million.
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Results
Our chief operating decision maker (“CODM”) evaluates the performance of our segments using segment adjusted EBITDA. Amounts included in income before income taxes and excluded from segment adjusted EBITDA include: (i) depreciation and amortization; (ii) net interest and other financial costs; (iii) turnaround expenses; and (iv) other adjustments as deemed necessary. These items are either: (i) believed to be non-recurring in nature; (ii) not believed to be allocable or controlled by the segment; or (iii) are not tied to the operational performance of the segment.
Select results for continuing operations for 2025 and 2024 are reflected in the following table.
(Millions of dollars)
Segment adjusted EBITDA for reportable segments
Refining & Marketing
Midstream
Renewable Diesel
Total reportable segments
Reconciliation of segment adjusted EBITDA for reportable segments to income before income taxes
Total reportable segments
Corporate
Refining & Renewable Diesel planned turnaround costs
Renewable Diesel JV planned turnaround costs (a)
LIFO inventory adjustment
Gain on sale of assets (b)
SRE
Transaction-related costs (c)
Legal settlements
Depreciation and amortization
Renewable Diesel JV depreciation and amortization (a)
Net interest and other financial costs
Income before income taxes
Net Income attributable to MPC per diluted share
(a) Represents MPC’s pro-rata share of expenses from joint ventures included within the Renewable Diesel segment.
(b) 2025 includes gains from the BANGL Acquisition, the Ethanol Joint Venture Sale and the Rockies divestiture. 2024 includes the gain resulting from MPLX and its joint venture partner contributing their respective membership interests in Whistler Pipeline, LLC to a newly formed joint venture, WPC Parent, LLC, and issuing a 19 percent voting interest in WPC Parent, LLC to an affiliate of Enbridge Inc. in exchange for the contribution of cash and the Rio Bravo Pipeline project (collectively the “Whistler Joint Venture Transaction”). See Item 8. Financial Statements and Supplementary Data - Note 5 for additional information on these transactions.
(c) Transaction-related costs include costs associated with the Northwind Midstream Acquisition, the BANGL Acquisition and the Rockies divestiture discussed in Item 8. Financial Statements and Supplementary Data - Note 5 .
Net income attributable to MPC increased $602 million, or $3.14 per diluted share, in 2025 compared to 2024. Refer to the Results of Operations section for a discussion of financial results by segment for the three years ended December 31, 2025.
MPLX
We received limited partner distributions of $2.56 billion and $2.27 billion from MPLX during 2025 and 2024, respectively. We owned approximately 647 million MPLX common units at December 31, 2025 with a market value of $34.55 billion based on the December 31, 2025 closing unit price of $53.37. On January 29, 2026, MPLX declared a quarterly cash distribution of $1.0765 per common unit, which was paid February 17, 2026. As a result, MPLX made distributions totaling $1.09 billion to its common unitholders for the fourth quarter of 2025. MPC’s portion of these distributions was approximately $697 million.
During the year ended December 31, 2025, MPLX repurchased approximately 8 million MPLX common units at an average cost per unit of $51.58 and paid approximately $400 million of cash. As of December 31, 2025, $1.12 billion remained available under the authorizations for future repurchases.
See Item 8. Financial Statements and Supplementary Data – Note 4 for additional information on MPLX.
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OVERVIEW OF SEGMENTS
Refining & Marketing
Refining & Marketing segment adjusted EBITDA depends largely on our refinery throughputs, Refining & Marketing margin, refining operating costs and distribution costs. Our total refining capacity was 2,986 mbpcd, 2,963 mbpcd and 2,950 mbpcd as of December 31, 2025, 2024 and 2023, respectively.
Refining & Marketing margin is the difference between the prices of refined products sold and the costs of crude oil and other charge and blendstocks refined, including the costs to transport these inputs to our refineries and the costs of products purchased for resale. The crack spread is a measure of the difference between market prices for refined products and crude oil, commonly used by the industry as a proxy for the refining margin. Crack spreads can fluctuate significantly, particularly when prices of refined products do not move in the same relationship as the cost of crude oil. As a performance benchmark and a comparison with other industry participants, we calculate Gulf Coast, Mid-Continent and West Coast crack spreads that we believe most closely track our operations and slate of products. The following are used for these crack-spread calculations:
• The Gulf Coast crack spread uses three barrels of MEH crude producing two barrels of USGC CBOB gasoline and one barrel of USGC ULSD;
• The Mid-Continent crack spread uses three barrels of WTI crude producing two barrels of Chicago CBOB gasoline and one barrel of Chicago ULSD; and
• The West Coast crack spread uses three barrels of ANS crude producing two barrels of LA CARBOB and one barrel of LA CARB Diesel.
Our refineries can process a variety of sweet and sour crude oil, which typically can be purchased at a discount to crude oil referenced in our Gulf Coast, Mid-Continent and West Coast crack spreads. The amount of these discounts, which we refer to as the sweet differential and the sour differential, can vary significantly, causing our Refining & Marketing margin to differ from blended crack spreads. In general, larger sweet and sour differentials will enhance our Refining & Marketing margin.
Future crude oil differentials will be dependent on a variety of market and economic factors, as well as U.S. energy policy.
The following table provides sensitivities showing an estimated change in annual Refining & Marketing segment adjusted EBITDA due to potential changes in market conditions.
(Millions of dollars)
Blended crack spread sensitivity (a) (per $1.00/barrel change)
Sour differential sensitivity (b) (per $1.00/barrel change)
Sweet differential sensitivity (c) (per $1.00/barrel change)
Natural gas price sensitivity (d) (per $1.00/MMBtu)
(a) Crack spread based on 42 percent MEH, 40 percent WTI and 18 percent ANS with Gulf Coast, Mid-Continent and West Coast product pricing, respectively, and assumes all other differentials and pricing relationships remain unchanged.
(b) Sour crude oil basket consists of the following crudes: ANS, Argus Sour Crude Index, Maya and Western Canadian Select. We assume approximately 50 percent of the crude processed at our refineries in 2026 will be sour crude.
(c) Sweet crude oil basket consists of the following crudes: Bakken, Brent, MEH, WTI-Cushing and WTI-Midland. We assume approximately 50 percent of the crude processed at our refineries in 2026 will be sweet crude.
(d) This is consumption-based exposure for our Refining & Marketing segment and does not include the sales exposure for our Midstream segment.
In addition to the market changes indicated by the crack spreads, the sour differential and the sweet differential, our Refining & Marketing margin is impacted by factors such as:
• the selling prices realized for refined products;
• the types of crude oil and other charge and blendstocks processed;
• our refinery yields;
• the cost of products purchased for resale;
• the impact of commodity derivative instruments used to hedge price risk;
• the potential impact of lower of cost or market adjustments to inventories in periods of declining prices;
• the potential impact of LIFO adjustments; and
• the cost of purchasing RINs in the open market to comply with RFS requirements.
Inventories are stated at the lower of cost or market. Costs of crude oil, refinery feedstocks and refined products are stated under the LIFO inventory costing method and aggregated on a consolidated basis for purposes of assessing if the cost basis of these inventories may have to be written down to market values. At December 31, 2025, market values for refined products exceed
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their cost basis and, therefore, there is no lower of cost or market inventory valuation reserve at the end of the year. Based on movements of refined product prices, future inventory valuation adjustments could have a negative effect to earnings. Such losses are subject to reversal in subsequent periods if prices recover.
Refining & Marketing segment adjusted EBITDA is also affected by changes in refining operating costs in addition to committed distribution costs. Changes in operating costs are primarily driven by the cost of energy used by our refineries, including purchased natural gas, and the level of maintenance costs. Distribution costs primarily include long-term agreements with MPLX, which as discussed below include minimum commitments to MPLX, and will negatively impact segment adjusted EBITDA in periods when throughput or sales are lower or refineries are idled.
We have various long-term, fee-based commercial agreements with MPLX. Under these agreements, MPLX, which is reported in our Midstream segment, provides transportation, storage, distribution and marketing services to our Refining & Marketing segment. Certain of these agreements include commitments for minimum quarterly throughput and distribution volumes of crude oil and refined products and minimum storage volumes of crude oil, refined products and other products. Certain other agreements include commitments to pay for 100 percent of available capacity for certain marine transportation and refining logistics assets.
Midstream
Our Midstream segment gathers, transports, stores and distributes crude oil, refined products, including renewable diesel, and other hydrocarbon-based products, principally for our Refining & Marketing segment. Additionally, the segment markets refined products. The profitability of our pipeline transportation operations primarily depends on tariff rates and the volumes shipped through the pipelines. The profitability of our marine operations primarily depends on the quantity and availability of our vessels and barges. The profitability of our light product terminal operations primarily depends on the throughput volumes at these terminals. The profitability of our fuels distribution services primarily depends on the sales volumes of certain refined products. The profitability of our refining logistics operations depends on the quantity and availability of our refining logistics assets. A majority of the crude oil and refined product shipments on our pipelines and marine vessels and the refined product throughput at our terminals serve our Refining & Marketing segment and our refining logistics assets and fuels distribution services are used solely by our Refining & Marketing segment. As discussed above in the Refining & Marketing section, MPLX, which is reported in our Midstream segment, has various long-term, fee-based commercial agreements related to services provided to our Refining & Marketing segment. Under these agreements, MPLX has received various commitments of minimum throughput, storage and distribution volumes as well as commitments to pay for all available capacity of certain assets. The volume of crude oil that we transport is directly affected by the supply of, and refiner demand for, crude oil in the markets served directly by our crude oil pipelines, terminals and marine operations. Key factors in this supply and demand balance are the production levels of crude oil by producers in various regions or fields, the availability and cost of alternative modes of transportation, the volumes of crude oil processed at refineries and refinery and transportation system maintenance levels. The volume of refined products that we transport, store, distribute and market is directly affected by the production levels of, and user demand for, refined products in the markets served by our refined product pipelines and marine operations. In most of our markets, demand for gasoline and distillate peaks during the summer driving season, which extends from May through September of each year, and during the fall and winter months. As with crude oil, other transportation alternatives and system maintenance levels influence refined product movements.
Our Midstream segment also gathers, treats, processes and transports natural gas and transports, fractionates, stores and markets NGLs. NGL and natural gas prices are volatile and are impacted by changes in fundamental supply and demand, as well as market uncertainty, availability of NGL transportation and fractionation capacity and a variety of additional factors that are beyond our control. Our Midstream segment profitability is affected by prevailing commodity prices primarily as a result of processing or conditioning at our own or third‑party processing plants, purchasing and selling or gathering and transporting volumes of natural gas at index‑related prices and the cost of third‑party transportation and fractionation services. To the extent that commodity prices influence the level of natural gas drilling by our producer customers, such prices also affect profitability.
Renewable Diesel
Our Renewable Diesel segment processes renewable feedstocks into renewable diesel, markets and distributes renewable diesel and includes joint ventures that produce soybean oil and renewable diesel.
Inventories are stated at the lower of cost or market. Costs of renewable feedstocks and renewable diesel are stated under the LIFO inventory costing method and aggregated on a consolidated basis, including traditional and renewable products, for purposes of assessing if the cost basis of these inventories may have to be written down to market values. At December 31, 2025, market values for all refined product inventories exceed their cost basis and, therefore, there is no lower of cost or market inventory valuation reserve at the end of the year. Based on movements of renewable product prices, future inventory valuation adjustments could have a negative effect to earnings. Such losses are subject to reversal in subsequent periods if prices recover.
Our Renewable Diesel segment adjusted EBITDA is also affected by changes in operating costs, distribution costs, throughput and certain regulatory credits.
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RESULTS OF OPERATIONS
The following discussion includes comments and analysis relating to our results of operations for the years ended December 31, 2025, 2024 and 2023. This discussion should be read in conjunction with Item 8. Financial Statements and Supplementary Data and is intended to provide investors with a reasonable basis for assessing our historical operations, but should not serve as the only criteria for predicting our future performance.
Consolidated Results of Operations
(Millions of dollars)
2025 vs. 2024 Variance
2024 vs. 2023 Variance
Revenues and other income:
Sales and other operating revenues
Income from equity method investments
Net gain on disposal of assets
Other income
Total revenues and other income
Costs and expenses:
Cost of revenues (excludes items below)
Depreciation and amortization
Selling, general and administrative expenses
Other taxes
Total costs and expenses
Income from continuing operations
Net interest and other financial costs
Income before income taxes
Provision for income taxes
Net income
Less net income attributable to:
Redeemable noncontrolling interest
Noncontrolling interests
Net income attributable to MPC
2025 Compared to 2024
Net income attributable to MPC increased $602 million in 2025 compared to 2024, due to the following:
Total revenues and other income decreased $5.19 billion in 2025 compared to 2024 primarily due to:
• decreased sales and other operating revenues of $6.17 billion primarily due to a decrease in average refined product sales prices of $0.18 per gallon, or 8 percent, partially offset by increased refined product sales volumes of 133 mbpd, or 4 percent;
• increased income from equity method investments of $574 million largely due to gains from the BANGL Acquisition of $484 million and the Ethanol Joint Venture Sale of $254 million, partially offset by the absence of the gain on sale of assets of $151 million resulting from the Whistler Joint Venture Transaction in 2024;
• increased net gain on disposal of assets of $145 million mainly due to the $159 million gain on the divestiture of the Rockies operations; and
• increased other income of $256 million largely due to legal settlements of $253 million and higher income on RINs sales, partially offset by lower insurance proceeds.
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Total costs and expenses decreased $6.69 billion in 2025 compared to 2024 primarily due to:
• decreased cost of revenues of $6.79 billion primarily due to lower crude oil costs;
• decreased depreciation and amortization of $86 million largely due to major refining assets that were fully depreciated at the end of 2024, partially offset by depreciation from recent acquisitions;
• increased selling, general and administrative expenses of $128 million primarily due to increases in salaries and employee related expenses of $88 million, contract services costs of $39 million and insurance expenses of $24 million, partially offset by the absence of $30 million of expense in 2024 related to decommissioning of non-operating assets; and
• increased other taxes of $67 million largely due to the absence of a property tax appeal settlement of $49 million received in 2024 related to retroactive tax assessments for prior periods.
Net interest and other financial costs increased $437 million largely due to decreased interest income and discount amortization, primarily due to the liquidation of short-term investments that were held in 2024, and increased interest expense, largely due to increased MPLX borrowings, and non-service pension costs. We capitalized interest of $100 million in 2025 and $57 million in 2024. See Item 8. Financial Statements and Supplementary Data – Note 11 for further details.
We recorded combined federal, state and foreign income tax provisions of $1.14 billion and $890 million for the years ended December 31, 2025 and 2024, respectively, which were lower than the U.S. statutory rate primarily due to permanent tax benefits related to net income attributable to noncontrolling interests. See Item 8. Financial Statements and Supplementary Data – Note 12 for further details.
Net income attributable to noncontrolling interests increased $236 million mainly due to an increase in MPLX’s net income.
2024 Compared to 2023
Net income attributable to MPC decreased $6.24 billion in 2024 compared to 2023, due to the following:
Total revenues and other income decreased $9.90 billion in 2024 compared to 2023 primarily due to:
• decreased sales and other operating revenues of $9.52 billion primarily due to decreased average refined product sales prices of $0.24 per gallon, or 10 percent, partially offset by increased refined product sales volumes of 75 mbpd, or 2 percent;
• increased income from equity method investments of $306 million largely due to the gain on the sale of assets resulting from the Whistler Joint Venture Transaction and increased income from our Martinez Renewables joint venture;
• decreased net gain on disposal of assets of $189 million mainly due to the $106 million gain on the sale of MPC’s 25 percent interest in South Texas Gateway and $92 million associated with the remeasurement of MPLX’s existing equity investment in MarkWest Torñado GP, L.L.C. (“Torñado”), arising from the acquisition of the remaining 40 percent interest in 2023; and
• decreased other income of $497 million largely due to lower income on RINs sales and lower insurance proceeds.
Total costs and expenses decreased $2.18 billion in 2024 compared to 2023 primarily due to:
• decreased cost of revenues of $2.33 billion primarily due to lower crude oil costs and finished product purchases, partially offset by higher contract services and material and supply expenses related to increased turnaround activity;
• increased selling, general and administrative expenses of $182 million primarily due to increased contract services costs of $96 million, office and rent expenses of $31 million and $30 million of expense related to decommissioning of non-operating assets; and
• decreased other taxes of $63 million largely due to a property tax appeal settlement of $49 million related to retroactive tax assessments for prior periods.
Net interest and other financial costs increased $314 million largely due to decreased interest income of $154 million, primarily on short-term investments, increased pension non-service costs of $52 million and increased interest expense of $41 million due to higher MPLX borrowings. We capitalized interest of $57 million in 2024 and $60 million in 2023. See Item 8. Financial Statements and Supplementary Data – Note 11 for further details.
We recorded a combined federal, state and foreign income tax provision of $890 million for the year ended December 31, 2024, which was lower than the U.S. statutory rate primarily due to permanent tax benefits related to net income attributable to noncontrolling interests. We recorded a combined federal, state and foreign income tax provision of $2.82 billion for the year ended December 31, 2023, which was lower than the tax computed at the U.S. statutory rate primarily due to permanent tax benefits related to net income attributable to noncontrolling interests, partially offset by state taxes. See Item 8. Financial Statements and Supplementary Data – Note 12 for further details.
Net income attributable to noncontrolling interests increased $198 million mainly due to an increase in MPLX’s net income.
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Segment Results
We classify our business in the following reportable segments: Refining & Marketing, Midstream and Renewable Diesel. Segment adjusted EBITDA represents adjusted EBITDA attributable to the reportable segments. Amounts included in income before income taxes and excluded from segment adjusted EBITDA include: (i) depreciation and amortization; (ii) net interest and other financial costs; (iii) turnaround expenses and (iv) other adjustments as deemed necessary. These items are either: (i) believed to be non-recurring in nature; (ii) not believed to be allocable or controlled by the segment; or (iii) are not tied to the operational performance of the segment.
Our segment adjusted EBITDA for reportable segments was approximately $12.78 billion, $12.10 billion and $19.81 billion for the years ended December 31, 2025, 2024 and 2023, respectively.
Refining & Marketing
The following includes key financial and operating data for 2025, 2024 and 2023.
(a) Includes intersegment sales to the Midstream segment and sales destined for export.
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Refining & Marketing Operating Statistics
Net refinery throughput (mbpd )
Refining & Marketing margin per barrel (a)(b)
Less:
Refining operating costs per barrel (c)
Distribution costs per barrel (d)
LIFO inventory adjustment
Other per barrel (e)
Refining & Marketing adjusted EBITDA per barrel
Refining planned turnaround costs per barrel
Depreciation and amortization per barrel
Per barrel fees paid to MPLX included in distribution costs above
(a) Sales revenue less cost of refinery inputs and purchased products, divided by net refinery throughput.
(b) See “Non-GAAP Measures” section for reconciliation and further information regarding this non-GAAP measure.
(c) Refining operating costs exclude planned turnaround and depreciation and amortization expense.
(d) Distribution costs exclude depreciation and amortization expense.
(e) Includes income (loss) from equity method investments, net gain (loss) on disposal of assets and other income.
The following table presents certain benchmark prices in our marketing areas and market indicators that we believe are helpful in understanding the results of our Refining & Marketing segment. The benchmark crack spreads below do not reflect the market cost of RINs necessary to meet the EPA renewable volume obligations for attributable products under the Renewable Fuel Standard.
Benchmark spot prices (dollars per gallon)
Chicago CBOB unleaded regular gasoline
Chicago ultra-low sulfur diesel
USGC CBOB unleaded regular gasoline
USGC ultra-low sulfur diesel
LA CARBOB
LA CARB diesel
Market Indicators (dollars per barrel)
WTI
MEH
ANS
Crack Spreads
Mid-Continent WTI 3-2-1
USGC MEH 3-2-1
West Coast ANS 3-2-1
Blended 3-2-1 (a)
Crude Oil Differentials
Sweet
Sour
(a) Beginning in the second quarter of 2024, the blended crack spreads are weighted 42 percent of the USGC crack spread, 40 percent of the Mid-Continent crack spread and 18 percent of the West Coast crack spread. The blended crack spreads for prior periods were weighted 40 percent of the USGC crack spread, 40 percent of the Mid-Continent crack spread and 20 percent of the West Coast crack spread. These blends are based on MPC’s refining capacity by region in each period.
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2025 Compared to 2024
Refining & Marketing segment revenues decreased $7.45 billion primarily due to a decrease in average refined product sales prices of $0.18 per gallon, partially offset by increased refined product sales volumes of 133 mbpd.
Refinery crude oil capacity utilization was 94 percent during 2025 and net refinery throughput increased 67 mbpd in 2025.
Refining & Marketing segment adjusted EBITDA increased $435 million primarily driven by increased per barrel margins and increased refined product sales volumes.
Refining & Marketing margin was $16.87 per barrel for 2025 compared to $16.01 per barrel for 2024. Refining & Marketing margin is affected by the market indicators shown earlier, which use spot market values and an estimated mix of crude purchases and product sales. Based on the market indicators and our crude oil throughput, we estimate a net positive impact of approximately $300 million on Refining & Marketing margin, primarily due to higher crack spreads, partially offset by narrower sour and sweet crude oil differentials. Our reported Refining & Marketing margin differs from market indicators due to the mix of crudes purchased and their costs, the effects of market structure on our crude oil acquisition prices, RIN prices on the crack spread and other items like refinery yields and other feedstock variances, direct dealer fuel margin, and for 2025, a LIFO inventory adjustment of $82 million and for 2024, a LIFO inventory adjustment of $106 million. These factors had an estimated net positive impact on Refining & Marketing segment adjusted EBITDA of approximately $1.0 billion in 2025 compared to 2024.
We purchase RINs to satisfy a portion of our RFS compliance. Our expenses associated with purchased RINs were $1.33 billion in 2025 and $1.07 billion in 2024 and are included in Refining & Marketing margin. The increase in 2025 was primarily due to increased obligated volumes and RINs prices, partially offset by higher RINs generated and acquired from our Martinez Renewables JV. In addition, MPC was granted an SRE for one of our refineries for 50 percent of the renewable volume obligation for the 2024 compliance year. There is an additional credit for the closed 2023 compliance year recognized in items not allocated to the segments.
For the year ended December 31, 2025, refining operating costs, excluding depreciation and amortization, were $6.10 billion. This was an increase of $385 million, compared to the year ended December 31, 2024, largely due to higher energy and maintenance and repair costs and the absence of a property tax appeal settlement received in 2024 related to retroactive tax assessments for prior periods.
Distribution costs, excluding depreciation and amortization, were $6.19 billion and $5.86 billion for 2025 and 2024, respectively, and include fees paid to MPLX of $4.03 billion and $3.95 billion for 2025 and 2024, respectively. On a per barrel basis, distribution costs, excluding depreciation and amortization, increased $0.19 primarily due to an increase in logistics fees including third party marine, pipeline and terminalling costs.
Refining planned turnaround costs increased $117 million, or $0.08 per barrel, due to the scope and timing of turnaround activity.
Other income decreased by $0.15 per barrel largely due to lower insurance proceeds in 2025.
2024 Compared to 2023
Refining & Marketing segment revenues decreased $10.21 billion primarily due to a decrease in average refined product sales prices of $0.24 per gallon, partially offset by increased refined product sales volumes of 75 mbpd.
Refinery crude oil capacity utilization was 92 percent during 2024 and net refinery throughput increased 19 mbpd in 2024.
Refining & Marketing segment adjusted EBITDA decreased $8.0 billion primarily driven by decreased per barrel margins.
Refining & Marketing margin was $16.01 per barrel for 2024 compared to $23.00 per barrel for 2023. Refining & Marketing margin is affected by the market indicators shown earlier, which use spot market values and an estimated mix of crude purchases and product sales. Based on the market indicators and our crude oil throughput, we estimate a net negative impact of approximately $7 billion on Refining & Marketing margin, primarily due to lower crack spreads. Our reported Refining & Marketing margin differs from market indicators due to the mix of crudes purchased and their costs, the effects of market structure on our crude oil acquisition prices, RIN prices on the crack spread and other items like refinery yields and other feedstock variances, direct dealer fuel margin, and for 2024, a LIFO inventory adjustment of $106 million and for 2023, a LIFO inventory adjustment of $157 million. These factors had an estimated net negative impact on Refining & Marketing segment adjusted EBITDA of approximately $200 million in 2024 compared to 2023.
We purchase RINs to satisfy a portion of our RFS compliance. Our expenses associated with purchased RINs were $1.07 billion in 2024 and $2.07 billion in 2023 and are included in Refining & Marketing margin. The decrease in 2024 was primarily due to lower average RIN prices, increased RINs generated and acquired from our Martinez Renewables joint venture and lower RIN sale activity.
For the year ended December 31, 2024, refining operating costs, excluding depreciation and amortization, were $5.71 billion. This was an increase of $87 million, compared to the year ended December 31, 2023, primarily driven by higher expenses for
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projects conducted during turnaround activity, partially offset by a property tax appeal settlement related to retroactive tax assessments for prior periods.
Distribution costs, excluding depreciation and amortization, were $5.86 billion and $5.65 billion for 2024 and 2023, respectively, and include fees paid to MPLX of $3.95 billion and $3.84 billion for 2024 and 2023, respectively. On a per barrel basis, distribution costs, excluding depreciation and amortization, increased $0.15 primarily due to higher pipeline tariff rates and logistics fee escalations.
Refining planned turnaround costs increased $216 million, or $0.20 per barrel, due to the scope and timing of turnaround activity.
Other income decreased by $0.19 per barrel mainly due to lower insurance proceeds in 2024.
Supplemental Refining & Marketing Statistics
Refining & Marketing Operating Statistics
Crude oil capacity utilization percent (a)
Refinery throughputs ( mbpd ):
Crude oil refined
Other charge and blendstocks
Net refinery throughput
Sour crude oil throughput percent
Sweet crude oil throughput percent
Refined product yields ( mbpd ):
Gasoline
Distillates
Propane
NGLs and petrochemicals
Heavy fuel oil
Asphalt
Total
Refined product export sales volumes (mbpd) (b)
(a) Based on calendar-day capacity, which is an annual average that includes down time for planned maintenance and other normal operating activities.
(b) Represents fully loaded export cargoes for each time period. These sales volumes are included in the total sales volumes amounts.
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Midstream
The following includes key financial and operating data for 2025, 2024 and 2023.
(a) On owned common-carrier pipelines, excluding equity method investments.
(b) Includes operating data for entities that have been consolidated into the MPLX financial statements as well as operating data for partnership-operated equity method investments.
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Benchmark Prices
Natural Gas NYMEX HH ( per MMBtu )
C2 + NGL Pricing ( per gallon ) (a)
(a) For 2025 and 2024, C2 + NGL pricing based on Mont Belvieu prices assuming an NGL barrel of approximately 10 percent ethane, 60 percent propane, five percent Iso-Butane, 15 percent normal butane and 10 percent natural gasoline. For 2023, C2 + NGL pricing based on Mont Belvieu prices assuming an NGL barrel of approximately 35 percent ethane, 35 percent propane, six percent Iso-Butane, 12 percent normal butane and 12 percent natural gasoline.
2025 Compared to 2024
Midstream segment adjusted EBITDA increased $206 million, which includes contributions from recent acquisitions, primarily $59 million related to the BANGL Acquisition and $15 million related to the Whiptail Midstream Acquisition, partially offset by $17 million resulting from the divestiture of the Rockies operations. Additionally, sales and operating revenues increased $540 million resulting from higher rates and throughputs and a $37 million non-recurring benefit associated with a customer agreement, partially offset by higher operating expenses.
2024 Compared to 2023
Midstream segment adjusted EBITDA increased $373 million. Sales and operating revenues increased $486 million mainly due to rate escalations, contributions from recently acquired assets and higher natural gas gathering and processing volumes. Income from equity method investments increased approximately $35 million.
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Renewable Diesel
The following includes key financial and operating data for 2025, 2024 and 2023.
(a) Includes intersegment sales to the Refining & Marketing segment.
(b Includes Dickinson facility production and purchased product from our Martinez Renewables joint venture.
2025 Compared to 2024
Renewable Diesel segment revenues increased $726 million primarily due to increased sales volume of 187 thousand gallons per day. Renewable Diesel segment adjusted EBITDA increased $40 million as lower product margins were more than offset by an increase in utilization of our facilities, higher regulatory benefit and increased income from equity method investments. Reduced production capacity in 2024 due to an event at the refinery in late 2023 resulted in lower throughput and impacted margins. Renewable Diesel margins were $151 million in 2025 and $186 million in 2024.
See “Non-GAAP Financial Measures” section for reconciliation of Renewable Diesel margin.
2024 Compared to 2023
Renewable Diesel segment revenues increased $440 million primarily due to increased sales volume of 419 thousand gallons per day. Renewable Diesel segment adjusted EBITDA decreased $86 million as reduced production capacity in 2024 due to an event at the refinery in late 2023 resulted in lower throughput and impacted margins. The lower renewable diesel margins, which were $186 million in 2024 and $304 million in 2023, were partially offset by increased income from equity method investments of $129 million.
See “Non-GAAP Financial Measures” section for reconciliation of Renewable Diesel margin.
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Corporate
(millions of dollars)
Corporate (a)
(a) Corporate costs consist primarily of MPC’s corporate administrative expenses and costs related to certain non-operating assets, except for corporate overhead expenses attributable to MPLX, which are included in the Midstream segment. Corporate costs include depreciation and amortization of $105 million, $90 million and $100 million for the years ended December 31, 2025, 2024 and 2023, respectively.
2025 Compared to 2024
Corporate expenses increased $63 million in 2025 compared to 2024 largely due to an increase in contract services of $52 million.
2024 Compared to 2023
Corporate expenses increased $27 million in 2024 compared to 2023 largely due to increases in contract services of $35 million, office expenses of $24 million and compensation expense of $21 million, partially offset by a decrease in stock-based compensation of $52 million.
Items not Allocated to Segments
Our CODM evaluates the performance of our segments using segment adjusted EBITDA. Items identified in the table below are either believed to be non-recurring in nature or not believed to be allocable, controlled by the segment or are not tied to the operational performance of the segment.
(millions of dollars)
Items not allocated to segments:
Gain on sale of assets
SRE
Transaction-related costs
Legal settlements
Total items not allocated to segments
2025 Compared to 2024
In 2025, total items not allocated to segments of $1.17 billion primarily includes gain on sale of assets of $897 million, which includes gains from the BANGL Acquisition of $484 million, the Ethanol Joint Venture Sale of $254 million and the divestiture of the Rockies operations of $159 million. See Item 8. Financial Statements and Supplementary Data – Note 5 for additional information on these transactions. In addition, items not allocated to segments in 2025 includes legal settlements of $253 million and the 2023 compliance year SRE credit, partially offset by transaction costs related to Midstream acquisitions during the year. In 2024, items not allocated to segments includes a $151 million gain resulting from the Whistler Joint Venture Transaction.
2024 Compared to 2023
In 2024, items not allocated to segments includes a $151 million gain resulting from the Whistler Joint Venture Transaction. In 2023, total items not allocated to segments includes the $106 million gain on the sale of MPC’s 25 percent interest in South Texas Gateway and the $92 million gain associated with the remeasurement of MPLX’s existing equity investment in Torñado arising from the acquisition of the remaining 40 percent interest.
Non-GAAP Financial Measures
Management uses financial measures to evaluate our operating performance that are calculated and presented on the basis of methodologies other than in accordance with GAAP. The non-GAAP financial measures we use are as follows:
Refining & Marketing Margin
Refining & Marketing margin is defined as sales revenue less cost of refinery inputs and purchased products. We use and believe our investors use this non-GAAP financial measure to evaluate our Refining & Marketing segment’s operating and financial performance as it is the most comparable measure to the industry’s market reference product margins. This measure should not be considered a substitute for, or superior to, Refining & Marketing gross margin or other measures of financial performance prepared in accordance with GAAP, and our calculations thereof may not be comparable to similarly titled measures reported by other companies.
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Reconciliation of Refining & Marketing segment adjusted EBITDA to Refining & Marketing gross margin and Refining & Marketing margin
(Millions of dollars)
Refining & Marketing segment adjusted EBITDA
Plus (Less):
Depreciation and amortization
Refining planned turnaround costs
LIFO inventory adjustment
Selling, general and administrative expenses
Income from equity method investments
Net (gain) loss on disposal of assets
Other income
Refining & Marketing gross margin
Plus (Less):
Operating expenses (excluding depreciation and amortization)
Depreciation and amortization
Gross margin excluded from and other income included in Refining & Marketing margin (a)
Other taxes included in Refining & Marketing margin
Refining & Marketing margin
(a) Reflects the gross margin, excluding depreciation and amortization, of other related operations included in the Refining & Marketing segment and processing of credit card transactions on behalf of certain of our marketing customers, net of other income.
Renewable Diesel Margin
Renewable Diesel margin is defined as sales revenue plus value attributable to qualifying regulatory credits earned during the period less cost of renewable inputs and purchased products. We use and believe our investors use this non-GAAP financial measure to evaluate our Renewable Diesel segment’s operating and financial performance. This measure should not be considered a substitute for, or superior to, Renewable Diesel gross margin or other measures of financial performance prepared in accordance with GAAP, and our calculation thereof may not be comparable to similarly titled measures reported by other companies.
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Reconciliation of Renewable Diesel segment adjusted EBITDA to Renewable Diesel gross margin and Renewable Diesel margin
(Millions of dollars)
Renewable Diesel segment adjusted EBITDA
Plus (Less):
Depreciation and amortization
Renewable Diesel JV depreciation and amortization (a)
Renewable Diesel planned turnaround costs
Renewable Diesel JV planned turnaround costs (a)
LIFO inventory adjustment
Selling, general and administrative expenses
(Income) loss from equity method investments
Net gain on disposal of assets
Other income
Renewable Diesel gross margin
Plus (Less):
Operating expenses (excluding depreciation and amortization)
Depreciation and amortization
Martinez JV depreciation and amortization
Renewable Diesel margin
(a) Represents MPC’s pro-rata share of expenses from joint ventures included within the Renewable Diesel segment.
LIQUIDITY AND CAPITAL RESOURCES
Cash Flows
Our cash and cash equivalents balance was $3.67 billion at December 31, 2025, compared to $3.21 billion at December 31, 2024. Net cash provided by (used in) operating activities, investing activities and financing activities for the past three years is presented in the following table.
(Millions of dollars)
Net cash provided by (used in):
Operating activities
Investing activities
Financing activities
Total increase (decrease) in cash
Operating Activities
Net cash provided by operating activities decreased $412 million in 2025 compared to 2024, primarily due to an unfavorable change in working capital of $955 million, partially offset by an increase in operating results. Net cash provided by operating activities decreased $5.45 billion in 2024 compared to 2023, primarily due to a decrease in operating results partially offset by a favorable change in working capital of $105 million. The above changes in working capital exclude changes in short-term debt.
For 2025, changes in working capital were a net $485 million use of cash, primarily due to the effect of decreases in energy commodity prices, partially offset by increases in volumes at the end of the year on working capital. Accounts payable decreased primarily due to decreases in crude oil prices, partially offset by increases in crude oil volumes. Current receivables decreased primarily due to decreases in crude oil and refined product prices and income tax receivables, partially offset by an increase in crude oil volumes. Inventories increased primarily due to increases in materials and supplies and refined product inventories. Additionally, working capital was favorably impacted by changes in current liabilities and other current assets.
For 2024, changes in working capital were a net $470 million source of cash, primarily due to the effect of decreases in energy commodity prices and volumes at the end of the year on working capital. Current receivables decreased primarily due to decreases in refined product and crude oil prices and crude oil volumes. Accounts payable increased primarily due to increased crude oil volumes and liability for a purchase of tax credits from a third party, partially offset by decreased crude oil prices. Inventories increased primarily due to increases in refined product and materials and supplies inventories, partially offset by a
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decrease in crude oil inventory. Additionally, working capital was favorably impacted by changes in income tax receivable and unfavorably impacted by changes in current liabilities and other current assets.
For 2023, changes in working capital were a net $365 million source of cash, primarily due to the effect of decreases in energy commodity prices and volumes at the end of the year on working capital. Current receivables decreased primarily due to decreases in crude oil volumes and prices. Accounts payable decreased primarily due to decreases in crude oil prices and volumes. Inventories increased primarily due to increases in refined product, crude oil and materials and supplies inventories. Additionally, working capital was favorably impacted by changes in income tax receivable and current liabilities and other current assets.
Investing Activities
Net cash used in investing activities was $5.87 billion in 2025 and $3.10 billion in 2023, compared to net cash provided by investing activities of $1.53 billion in 2024.
• Short-term investments were liquidated in the fourth quarter of 2024 and, therefore, there was no activity related to short-term investments in 2025. In 2024, the change in net cash provided was primarily due to maturities and sales of short-term investments of $4.53 billion and $3.30 billion, respectively, partially offset by purchases of short-term investments of $2.95 billion. The cash provided by maturities and sales of short-term investments was primarily used to fund our return of capital initiatives.
• In 2023, the change in net cash used was primarily due to purchases of short-term investments of $8.62 billion, partially offset by maturities and sales of short-term investments of $5.05 billion and $2.08 billion, respectively. The cash provided by maturities and sales of short-term investments was primarily used to fund our return of capital initiatives announced as part of the Speedway sale.
• Cash used for additions to property, plant and equipment was $3.49 billion in 2025, compared to $2.53 billion in 2024 and $1.89 billion in 2023. See the “Capital Requirements” section for additional information on our capital investment plan.
• Cash used for acquisitions was $3.32 billion in 2025 and $688 million in 2024 largely due to acquisitions in our Midstream segment, including $2.4 billion for the Northwind Midstream Acquisition, $703 million for the BANGL Acquisition and $235 million for the Whiptail Midstream Acquisition. Cash used for acquisitions in 2024 included $625 million of cash to purchase additional ownership interests in existing Midstream joint ventures and gathering assets. Cash used for acquisitions was $246 million in 2023 due to MPLX’s acquisition of the remaining interest in a gathering and processing joint venture for approximately $270 million, offset by cash acquired of $24 million.
• Cash used in net investments was $343 million in 2025, $348 million in 2024 and $205 million in 2023. In 2025, investments mainly included contributions to Midstream equity method investments, partially offset by proceeds from the Ethanol Joint Venture Sale and a return of capital of $150 million related to a Midstream joint venture. In 2024, investments primarily included a return of capital of $134 million related to the Whistler Joint Venture Transaction which was more than offset by Midstream equity method investments, including a $92 million contribution made in March 2024 for the repayment of MPLX’s share of the Dakota Access joint venture’s debt due in 2024. In 2023, investments primarily included the Martinez Renewables joint venture and the acquisition of a 49.9 percent equity interest in LF Bioenergy for approximately $56 million, partially offset by cash received from the sale of MPC’s 25 percent interest in South Texas Gateway.
• Cash provided by disposal of assets totaled $1.01 billion, $35 million and $36 million in 2025, 2024 and 2023, respectively, primarily due to the divestiture of the Rockies operations in 2025, the sale of Corporate and Refining & Marketing assets in 2024 and the sale of Midstream assets in 2023.
The consolidated statements of cash flows exclude changes to the consolidated balance sheets that did not affect cash. A reconciliation of additions to property, plant and equipment to total capital expenditures and investments follows for each of the last three years.
(Millions of dollars)
Additions to property, plant and equipment per consolidated statements of cash flows
Increase in capital accruals
Total capital expenditures
Investments in equity method investees
Total capital expenditures and investments
Financing Activities
Financing activities were a use of cash of $1.92 billion in 2025, $12.43 billion in 2024 and $14.21 billion in 2023.
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• During 2025, MPLX issued $6.5 billion aggregate principal amount of senior notes and repaid $1.70 billion aggregate principal amount of senior notes and MPC issued $2.0 billion in aggregate principal amount of senior notes and repaid $1.250 billion in aggregate principal amount of senior notes.
• During 2024, MPLX issued $1.65 billion aggregate principal amount of 5.50 percent senior notes due June 2034 and used the proceeds to repay $1.15 billion aggregate principal amount of senior notes. MPC repaid $750 million aggregate principal amount of senior notes that matured September 2024.
• During 2023, MPLX issued $1.6 billion of senior notes and used the proceeds to redeem $1.0 billion of senior notes and all of its outstanding Series B preferred units for $600 million.
• Cash used in common stock repurchases totaled $3.49 billion in 2025, $9.19 billion in 2024 and $11.57 billion in 2023. See the “Capital Requirements” section for further discussion of our stock repurchases.
• Cash used in dividend payments totaled $1.14 billion in 2025, $1.15 billion in 2024 and $1.26 billion in 2023. Dividends per share were $3.73 in 2025, $3.39 in 2024 and $3.08 in 2023. The decreases in 2025 and 2024 are primarily due to share repurchases, partially offset by increases in per share dividends.
• Cash used in distributions to noncontrolling interests totaled $1.51 billion in 2025, $1.38 billion in 2024 and $1.28 billion in 2023 due to distributions to MPLX common and preferred public unitholders.
• Cash used in repurchases of noncontrolling interests totaled $400 million in 2025 and $326 million in 2024 due to MPLX’s repurchases of its common units. There were no repurchases of noncontrolling interests in 2023. See the “Capital Requirements” section for further discussion of MPLX’s unit repurchases.
Derivative Instruments
See Item 7A. Quantitative and Qualitative Disclosures about Market Risk for a discussion of derivative instruments and associated market risk.
Capital Resources
MPC, Excluding MPLX
We control MPLX through our ownership of the general partner; however, the creditors of MPLX do not have recourse to MPC’s general credit through guarantees or other financial arrangements, except as noted. MPC has effectively guaranteed certain indebtedness of LOOP and LOCAP, in which MPLX holds an interest. Therefore, in the following table, we present the liquidity of MPC, excluding MPLX. MPLX liquidity is discussed in the following section.
Our liquidity, excluding MPLX, totaled $6.63 billion at December 31, 2025 consisting of:
December 31, 2025
(Millions of dollars)
Total Capacity
Outstanding Borrowings
Outstanding Letters
of Credit
Available
Capacity
Bank revolving credit facility
Trade receivables facility (a)
Total
Cash and cash equivalents and short-term investments (b)
Total liquidity
(a) The committed borrowing and letter of credit issuance capacity under the trade receivables securitization facility is $100 million. In addition, the facility allows for the issuance of letters of credit in excess of the committed capacity at the discretion of the issuing banks.
(b) Excludes $2.14 billion of MPLX cash and cash equivalents.
Because of the alternatives available to us, including internally generated cash flow and access to capital markets and a commercial paper program, we believe that our short-term and long-term liquidity is adequate to fund not only our current operations, but also our near-term (less than twelve months) and long-term funding requirements, including capital spending programs, the repurchase of shares of our common stock, dividend payments, defined benefit plan contributions, repayment of debt maturities and other amounts that may ultimately be paid in connection with contingencies.
On February 10, 2025, MPC issued $2.0 billion aggregate principal amount of senior notes in an underwritten public offering (“2025 Senior Notes Offering”), consisting of:
• $1.1 billion aggregate principal amount of 5.150 percent senior notes due March 2030; and
• $900 million aggregate principal amount of 5.700 percent senior notes due March 2035.
The 2025 Senior Note Offering replaced the $750 million aggregate principal amount of 3.625 percent senior notes that matured in September 2024 and was used to repay the $1.250 billion aggregate principal amount of 4.700 percent senior notes at maturity on May 1, 2025.
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We have a commercial paper program that allows us to have a maximum of $2.0 billion in commercial paper outstanding, with maturities up to 397 days from the date of issuance. We do not intend to have outstanding commercial paper borrowings in excess of available capacity under our bank revolving credit facility. At December 31, 2025, we had no borrowings outstanding under the commercial paper program.
MPC’s bank revolving credit facility and trade receivables facility contain representations and warranties, affirmative and negative covenants and restrictions, including financial covenants, and events of default that we consider usual and customary for agreements of a similar type and nature. As of December 31, 2025, we were in compliance with such covenants and restrictions. See Item 8. Financial Statements and Supplementary Data – Note 19 for further discussion of MPC’s revolving bank credit facility, trade receivables facility and related covenants and restrictions.
Our intention is to maintain an investment-grade credit profile. As of January 31, 2026, the credit ratings on our senior unsecured debt are as follows.
Company
Rating Agency
Rating
MPC
Moody’s
Baa2 (stable outlook)
Standard & Poor’s
BBB (stable outlook)
Fitch
BBB (stable outlook)
The ratings reflect the respective views of the rating agencies and should not be interpreted as a recommendation to buy, sell or hold our securities. Although it is our intention to maintain a credit profile that supports an investment-grade rating, there is no assurance that these ratings will continue for any given period of time. The ratings may be revised or withdrawn entirely by the rating agencies if, in their respective judgments, circumstances so warrant. A rating from one rating agency should be evaluated independently of ratings from other rating agencies.
The agreements governing MPC’s debt obligations do not contain credit rating triggers that would result in the acceleration of interest, principal or other payments in the event that our credit ratings are downgraded. However, any downgrades of our senior unsecured debt could increase the applicable interest rates, yields and other fees payable under such agreements and may limit our flexibility to obtain financing in the future, including to refinance existing indebtedness. In addition, a downgrade of our senior unsecured debt rating to below investment-grade levels could, under certain circumstances, impact our ability to purchase crude oil on an unsecured basis and could result in us having to post letters of credit under existing transportation services or other agreements.
See Item 8. Financial Statements and Supplementary Data – Note 19 for further discussion of our debt.
MPLX
MPLX’s liquidity totaled $5.64 billion at December 31, 2025 consisting of:
December 31, 2025
(Millions of dollars)
Total Capacity
Outstanding Borrowings
Outstanding Letters
of Credit
Available
Capacity
MPLX bank revolving credit facility
MPC intercompany loan agreement
Total
Cash and cash equivalents
Total liquidity
On February 18, 2025, MPLX repaid all of MPLX's outstanding $500 million aggregate principal amount of 4.000 percent senior notes due February 2025 at maturity.
On March 10, 2025, MPLX issued $2.0 billion in aggregate principal amount of senior notes in an underwritten public offering (“March 2025 MPLX Senior Notes”), consisting of:
• $1.0 billion aggregate principal amount of 5.400 percent senior notes due April 2035; and
• $1.0 billion aggregate principal amount of 5.950 percent senior notes due April 2055.
On April 9, 2025, MPLX used a portion of the net proceeds from the March 2025 MPLX Senior Notes Offering to redeem all of (i) MPLX LP’s outstanding $1,189 million aggregate principal amount of 4.875 percent senior notes due June 2025 and (ii) MarkWest Energy Partners, L.P.’s outstanding $11 million aggregate principal amount of 4.875 percent senior notes due June 2025. MPLX used the remaining net proceeds for general partnership purposes.
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On July 3, 2025, MPLX used cash on hand to extinguish approximately $656 million principal amount of debt outstanding, including interest, related to certain term and revolving loans assumed as part of the BANGL Acquisition. See Item 8. Financial Statements and Supplementary Data – Note 5 for additional information on this transaction.
On August 11, 2025, MPLX issued $4.5 billion in aggregate principal amount of senior notes in an underwritten public offering (“August 2025 MPLX Senior Notes Offering”), consisting of:
• $1.25 billion aggregate principal amount of 4.800 percent senior notes due February 2031;
• $750 million aggregate principal amount of 5.000 percent senior notes due January 2033;
• $1.5 billion aggregate principal amount of 5.400 percent senior notes due September 2035; and
• $1.0 billion aggregate principal amount of 6.200 percent senior notes due September 2055.
MPLX used a portion of the net proceeds from the August 2025 MPLX Senior Notes Offering to fund the Northwind Midstream Acquisition and incremental capital expenditures associated with in-process expansion projects, including the payment of related fees and expenses, and to increase cash and cash equivalents following the recently completed BANGL Acquisition and BANGL Debt Repayment. The remainder of the net proceeds from the August 2025 MPLX Senior Notes Offering were used for general partnership purposes.
On February 12, 2026, MPLX issued $1.5 billion aggregate principal amount of senior notes in an underwritten public offering, consisting of $1.0 billion aggregate amount of 5.300 percent senior notes due April 2036 and $500 million aggregate principal amount of 6.100 percent senior notes due April 2056. MPLX intends to use the net proceeds from this offering to repay MPLX’s outstanding $1.5 billion aggregate principal amount of 1.750 percent senior notes due March 2026 at maturity. Pending final use, MPLX may invest the proceeds in short-term marketable securities or other investments.
MPLX’s bank revolving credit facility contains representations and warranties, covenants and restrictions, including financial covenants, and events of default that we consider usual and customary for agreements of a similar type and nature. As of December 31, 2025, we were in compliance with such covenants and restrictions. See Item 8. Financial Statements and Supplementary Data – Note 19 for further discussion of MPLX’s bank revolving credit facility and related covenants and restrictions.
Our intention is to maintain an investment-grade credit profile for MPLX. As of January 31, 2026, the credit ratings on MPLX’s senior unsecured debt are as follows.
Company
Rating Agency
Rating
MPLX
Moody’s
Baa2 (stable outlook)
Standard & Poor’s
BBB (stable outlook)
Fitch
BBB (stable outlook)
The ratings reflect the respective views of the rating agencies and should not be interpreted as a recommendation to buy, sell or hold MPLX securities. Although it is our intention to maintain a credit profile that supports an investment-grade rating for MPLX, there is no assurance that these ratings will continue for any given period of time. The ratings may be revised or withdrawn entirely by the rating agencies if, in their respective judgments, circumstances so warrant. A rating from one rating agency should be evaluated independently of ratings from other rating agencies.
The agreements governing MPLX’s debt obligations do not contain credit rating triggers that would result in the acceleration of interest, principal or other payments in the event that MPLX credit ratings are downgraded. However, any downgrades of MPLX senior unsecured debt to below investment grade ratings could increase the applicable interest rates, yields and other fees payable under such agreements. In addition, a downgrade of MPLX senior unsecured debt ratings to below investment-grade levels may limit MPLX’s ability to obtain future financing, including to refinance existing indebtedness.
See Item 8. Financial Statements and Supplementary Data – Note 19 for further discussion of MPLX’s debt.
Capital Requirements
Capital Spending
MPC’s capital investment outlook for 2026 totals approximately $1.5 billion for capital projects and investments, excluding capitalized interest, potential acquisitions, if any, and MPLX’s capital investment plan. MPC’s 2026 capital investment outlook includes all of the planned capital spending for Refining & Marketing, Renewable Diesel and Corporate as well as a portion of the planned capital investments for Midstream. The remainder of the planned capital spending for Midstream reflects the capital investment plan for MPLX. We continuously evaluate our capital plan and make changes as conditions warrant. The 2026 capital investment outlook for MPC and MPLX and capital expenditures and investments for each of the last three years are summarized by segment below.
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(Millions of dollars)
2026 Outlook
Capital expenditures and investments: (a)
MPC, excluding MPLX
Refining & Marketing
Midstream - Other
Renewable Diesel
Corporate and Other (b)
Total MPC, excluding MPLX
Midstream - MPLX (c)(d)
(a) Capital expenditures include changes in capital accruals.
(b) Excludes capitalized interest of $94 million, $56 million and $55 million for 2025, 2024 and 2023, respectively. The 2026 capital investment plan excludes capitalized interest.
(c) The 2026 capital investment outlook for Midstream - MPLX excludes $260 million of capital expenditures, which is expected to be incurred primarily by MPC and other MPLX customers on MPLX’s behalf. This reimbursable capital will be included in the 2026 MPC Midstream capital expenditures.
(d) Includes reimbursable capital of $168 million, $163 million and $196 million for 2025, 2024 and 2023, respectively.
Refining & Marketing
The Refining & Marketing segment’s forecasted 2026 capital spending and investments is approximately $1.41 billion. This amount includes approximately $710 million for Refining value enhancing capital projects and $250 million for Marketing investments to strengthen our retail portfolio. Our capital investment outlook for Refining includes continued high-return investments at its Galveston Bay, Robinson, El Paso, and Garyville refineries. In addition to these multi-year investments, we are executing shorter-term projects that offer high returns through margin enhancement and cost reduction. Our capital investment outlook for Marketing includes continuing to expand the reach and presence of our branded stations in support of strong value capture. Refining m aintenance capital is expected to be approximately $450 million, which is essential to maintain the safety, integrity and reliability of our assets.
Major capital projects completed over the last three years have focused on refinery optimization, production of higher value products, increased capacity to upgrade residual fuel oil and expanded export capacity. We executed on projects such as the STAR project at our Galveston Bay refinery, the utility modernization project at the Los Angeles refinery and projects expected to reduce future operating costs.
Midstream
MPLX’s capital investment outlook totals approximately $2.7 billion, net of reimbursements and excluding capitalized interest and potential acquisitions, if any, and includes approximately $2.4 billion of growth capital and $300 million of maintenance capital. MPLX’s growth capital plans are focused on expanding its Permian to Gulf Coast integrated value chain, progressing long-haul pipeline growth projects to support producer activity, and investing in new gas processing plants in the Marcellus and Permian. The remainder of its capital plan targets debottlenecking of existing assets to meet customer demand.
Major capital projects over the last three years included investments for the development of natural gas and natural gas liquids infrastructure to support MPLX’s producer customers, primarily in the Marcellus, Utica and Permian regions and development of various crude oil and refined petroleum products infrastructure projects.
The remaining Midstream segment’s capital investment outlook, excluding MPLX, is approximately $40 million.
Renewable Diesel
There is no major forecasted 2026 capital spending and investments for the Renewable Diesel segment. Major projects over the last three years included investments in the Martinez Renewables joint venture and the Green Bison Soy Processing joint venture.
Corporate and Other
The 2026 capital forecast includes approximately $50 million to support corporate and other activities. Major projects over the last three years included upgrades to information technology systems.
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Share Repurchases
From January 1, 2012 through December 31, 2025, our board of directors approved $60.05 billion in total share repurchase authorizations and we have repurchased a total of $55.67 billion of our common stock. As of December 31, 2025, MPC had $4.38 billion remaining under its share repurchase authorization. The table below summarizes our total share repurchases for the last three years. See Item 8. Financial Statements and Supplementary Data – Note 9 for further discussion of the share repurchase plans.
(In millions, except per share data)
Number of shares repurchased
Cash paid for shares repurchased (a)
Average cost per share (b)
(a) 2025 excludes $89 million paid in 2025 for excise tax on 2024 share repurchases. 2024 excludes $112 million paid in 2024 for excise tax on 2023 share purchases.
(b) The average cost per share includes excise tax on share repurchases resulting from the Inflation Reduction Act of 2022, but the excise tax does not reduce the remaining share repurchase authorization.
We may utilize various methods to effect the repurchases, which could include open market repurchases, negotiated block transactions, tender offers, accelerated share repurchases or open market solicitations for shares, some of which may be effected through Rule 10b5-1 plans. The timing and amount of future repurchases, if any, will depend upon several factors, including market and business conditions, and such repurchases may be suspended or discontinued at any time.
MPLX Unit Repurchases
The table below summarizes MPLX’s total unit repurchases for the last three years.
(In millions, except per unit data)
Number of common units repurchased
Cash paid for common units repurchased
Average cost per unit
As of December 31, 2025, MPLX had approximately $1.12 billion remaining under its unit repurchase authorizations. The repurchase authorizations have no expiration date.
MPLX may utilize various methods to effect the repurchases, which could include open market repurchases, negotiated block transactions, accelerated unit repurchases, tender offers or open market solicitations for units, some of which may be effected through Rule 10b5-1 plans. The timing and amount of future repurchases, if any, will depend upon several factors, including market and business conditions, and such repurchases may be discontinued at any time.
See Item 8. Financial Statements and Supplementary Data – Note 4 for further discussion of the MPLX unit repurchase program.
Material Cash Commitments
Contractual Obligations
We have purchase commitments primarily consisting of obligations to purchase and transport crude oil and feedstocks used in our refining operations. As of December 31, 2025, we had purchase obligations for crude oil, NGLs and renewable feedstocks of $12.04 billion, with $10.15 billion payable within 12 months, and crude oil transportation obligations of $8.87 billion, with $875 million payable within 12 months. These contracts include variable price arrangements. For purposes of this disclosure, we have estimated prices to be paid primarily based on futures curves for the commodities to the extent available. Our contractual obligations do not include our contractual obligations to MPLX under various fee-based commercial agreements as these transactions are eliminated in the consolidated financial statements.
At December 31, 2025, our contractual commitment under contracts to acquire property, plant and equipment was $453 million, with $446 million payable within 12 months.
At December 31, 2025, we had an aggregate principal amount of outstanding senior notes of $32.45 billion, with $2.25 billion payable within 12 months, and interest on the debt of $21.62 billion, with $1.56 billion payable within 12 months. See Item 8. Financial Statements and Supplementary Data – Note 19 for additional information on our debt. We intend to repay the short-term maturities with existing cash on hand and/or with the proceeds of new long-term debt, depending on, among other things, market conditions.
Our other contractual obligations primarily consist of pension and post-retirement obligations, finance and operating leases and environmental credits liabilities, for which additional information is included in Item 8. Financial Statements and Supplementary Data – Notes 24, 26 and 22, respectively.
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Other Cash Commitments
On January 30, 2026, we announced our board of directors approved a $1.00 per share dividend, payable March 10, 2026 to shareholders of record at the close of business on February 18, 2026.
We may, from time to time, repurchase our senior notes and preferred units in the open market, in tender offers, in privately-negotiated transactions or otherwise in such volumes, at such prices and upon such other terms as we deem appropriate.
TRANSACTIONS WITH RELATED PARTIES
See Item 8. Financial Statements and Supplementary Data – Note 7 for discussion of activity with related parties.
ENVIRONMENTAL MATTERS AND COMPLIANCE COSTS
We have incurred and may continue to incur substantial capital, operating and maintenance, and remediation expenditures as a result of environmental laws and regulations. If these expenditures, as with all costs, are not ultimately reflected in the prices of our products and services, our operating results will be adversely affected. We believe that substantially all of our competitors must comply with similar environmental laws and regulations. However, the specific impact on each competitor may vary depending on a number of factors, including the age and location of its operating facilities, marketing areas, production processes and whether it is also engaged in the petrochemical business or the marine transportation of crude oil and refined products.
Legislation and regulations pertaining to fuel specifications, climate change and GHG emissions have the potential to materially adversely impact our business, financial condition, results of operations and cash flows, including costs of compliance and permitting delays. The extent and magnitude of these adverse impacts cannot be reliably or accurately estimated at this time because specific regulatory and legislative requirements have not been finalized and uncertainty exists with respect to the measures being considered, the costs and the time frames for compliance, and our ability to pass compliance costs on to our customers.
Our environmental expenditures, including non-regulatory expenditures, for each of the last three years were:
(Millions of dollars)
Capital
Compliance: (a)
Operating and maintenance
Remediation (b)
Total
(a) Based on the American Petroleum Institute’s definition of environmental expenditures.
(b) These amounts include spending charged against remediation reserves, where permissible, but exclude non-cash provisions recorded for environmental remediation.
We accrue for environmental remediation activities when the responsibility to remediate is probable and the amount of associated costs can be reasonably estimated. As environmental remediation matters proceed toward ultimate resolution or as additional remediation obligations arise, charges in excess of those previously accrued may be required.
New or expanded environmental requirements, which could increase our environmental costs, may arise in the future. It is not possible to predict all of the ultimate costs of compliance, including remediation costs that may be incurred and penalties that may be imposed.
Our environmental capital expenditures accounted for 20 percent, 22 percent and 12 percent of capital expenditures for 2025, 2024 and 2023, respectively, excluding acquisitions. Our environmental capital expenditures are expected to be approximately $183 million, or 4 percent, of total planned capital expenditures in 2026. Actual expenditures may vary as the number and scope of environmental projects are revised as a result of improved technology or changes in regulatory requirements and could increase if additional projects are identified or additional requirements are imposed.
For more information on environmental regulations that impact us, or could impact us, see Item 1. Business – Regulatory Matters and Item 1A. Risk Factors.
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CRITICAL ACCOUNTING ESTIMATES
The preparation of financial statements in accordance with GAAP requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities as of the date of the consolidated financial statements and the reported amounts of revenues and expenses during the respective reporting periods. Accounting estimates are considered to be critical if (1) the nature of the estimates and assumptions is material due to the levels of subjectivity and judgment necessary to account for highly uncertain matters or the susceptibility of such matters to change; and (2) the impact of the estimates and assumptions on financial condition or operating performance is material. Actual results could differ from the estimates and assumptions used. See Item 8. Financial Statements and Supplementary Data – Note 2 for additional information on these policies and estimates, as well as a discussion of additional accounting policies and estimates.
Fair Value Estimates
Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. There are three approaches for measuring the fair value of assets and liabilities: the market approach, the income approach and the cost approach, each of which includes multiple valuation techniques. The market approach uses prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities. The income approach uses valuation techniques to measure fair value by converting future amounts, such as cash flows or earnings, into a single present value amount using current market expectations about those future amounts. The cost approach is based on the amount that would currently be required to replace the service capacity of an asset. This is often referred to as current replacement cost. The cost approach assumes that the fair value would not exceed what it would cost a market participant to acquire or construct a substitute asset of comparable utility, adjusted for obsolescence.
The fair value accounting standards do not prescribe which valuation technique should be used when measuring fair value and do not prioritize among the techniques. These standards establish a fair value hierarchy that prioritizes the inputs used in applying the various valuation techniques. Inputs broadly refer to the assumptions that market participants use to make pricing decisions, including assumptions about risk. Level 1 inputs are given the highest priority in the fair value hierarchy while Level 3 inputs are given the lowest priority. The three levels of the fair value hierarchy are as follows:
• Level 1 – Observable inputs that reflect unadjusted quoted prices for identical assets or liabilities in active markets as of the measurement date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis.
• Level 2 – Observable market-based inputs or unobservable inputs that are corroborated by market data. These are inputs other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the measurement date.
• Level 3 – Unobservable inputs that are not corroborated by market data and may be used with internally developed methodologies that result in management’s best estimate of fair value.
Valuation techniques that maximize the use of observable inputs are favored. Assets and liabilities are classified in their entirety based on the lowest priority level of input that is significant to the fair value measurement. The assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement of assets and liabilities within the levels of the fair value hierarchy. We use an income or market approach for recurring fair value measurements and endeavor to use the best information available. See Item 8. Financial Statements and Supplementary Data – Note 17 for disclosures regarding our fair value measurements.
Significant uses of fair value measurements include:
• assessment of impairment of long-lived assets, intangible assets, goodwill and equity method investments;
• recorded values for assets acquired and liabilities assumed in connection with acquisitions; and
• recorded values of derivative instruments.
Impairment Assessments of Long-Lived Assets, Intangible Assets, Goodwill and Equity Method Investments
Fair value calculated for the purpose of testing our long-lived assets, intangible assets, goodwill and equity method investments for impairment is estimated using the expected present value of future cash flows method and comparative market prices when appropriate. Significant judgment is involved in performing these fair value estimates since the results are based on forecasted financial information prepared using significant assumptions including:
• Future operating performance . Our estimates of future operating performance are based on our analysis of various supply and demand factors, which include, among other things, industry-wide capacity, our planned utilization rate, end-user demand, capital expenditures and economic conditions, as well as commodity prices. Such estimates are consistent with those used in our planning and capital investment reviews.
• Future volumes. Our estimates of future refinery, pipeline throughput and natural gas and natural gas liquid processing volumes are based on internal forecasts prepared by our Refining & Marketing and Midstream segments operations personnel. Assumptions about our customers’ drilling activity are inherently subjective and contingent upon a number of variable factors (including future or expected crude oil and natural gas pricing considerations), many of which are
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difficult to forecast. Management considers these volume forecasts and other factors when developing our forecasted cash flows.
• Discount rate commensurate with the risks involved . We apply a discount rate to our cash flows based on a variety of factors, including market and economic conditions, operational risk, regulatory risk and political risk. This discount rate is also compared to recent observable market transactions, if possible. A higher discount rate decreases the net present value of cash flows.
• Future capital requirements . These are based on authorized spending and internal forecasts.
Assumptions about the macroeconomic environment are inherently subjective and difficult to forecast. We base our fair value estimates on projected financial information which we believe to be reasonable. However, actual results may differ from these projections.
The need to test for impairment can be based on several indicators, including a significant reduction in prices of or demand for products produced, a weakened outlook for profitability, a significant reduction in pipeline throughput volumes, a significant reduction in natural gas or natural gas liquids processed, a significant reduction in refining margins, other changes to contracts or changes in the regulatory environment. The following sections detail our critical accounting estimates related to impairment assessments for long-lived assets, goodwill and equity method investments.
Long-lived Asset Impairment Assessments
Long-lived assets used in operations are assessed for impairment whenever changes in facts and circumstances indicate that the carrying value of the assets may not be recoverable based on the expected undiscounted future cash flow of an asset group. For purposes of impairment evaluation, long-lived assets must be grouped at the lowest level for which independent cash flows can be identified, which generally is the refinery and associated distribution system level for Refining & Marketing segment assets, and the plant level or pipeline system level for Midstream segment assets. If the sum of the undiscounted estimated pretax cash flows is less than the carrying value of an asset group, fair value is calculated, and the carrying value is written down to the calculated fair value.
Goodwill Impairment Assessments
Unlike long-lived assets, goodwill must be tested for impairment at least annually, and between annual tests if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying amount. Goodwill is tested for impairment at the reporting unit level. We have seven reporting units, five of which have goodwill allocated to them. A goodwill impairment loss is measured as the amount by which a reporting unit’s carrying value exceeds its fair value, without exceeding the recorded amount of goodwill.
At December 31, 2025, MPC had five reporting units with goodwill totaling approximately $9.35 billion. For the annual impairment assessment as of November 30, 2025, management performed only qualitative assessments for all five reporting units as we determined it was more likely than not that the fair values of the reporting units exceeded their carrying values. See Item 8. Financial Statements and Supplementary Data – Note 16 for additional information relating to our reporting units and goodwill.
Equity Method Investment Impairment Assessment
Equity method investments are assessed for impairment whenever factors indicate an other than temporary loss in value. Factors providing evidence of such a loss include the fair value of an investment that is less than its carrying value, absence of an ability to recover the carrying value or the investee’s inability to generate income sufficient to justify our carrying value. At December 31, 2025, we had $6.80 billion of investments in equity method investments recorded on our consolidated balance sheet.
See Item 8. Financial Statements and Supplementary Data – Note 14 for additional information on our equity method investments. See Item 8. Financial Statements and Supplementary Data – Note 16 for additional information on our goodwill and intangibles, including a table summarizing our recorded goodwill by segment.
Acquisitions
In accounting for business combinations, acquired assets, assumed liabilities and contingent consideration are recorded based on estimated fair values as of the date of acquisition. The excess or shortfall of the purchase price when compared to the fair value of the net tangible and identifiable intangible assets acquired, if any, is recorded as goodwill or a bargain purchase gain, respectively. A significant amount of judgment is involved in estimating the individual fair values of property, plant and equipment, intangible assets, contingent consideration and other assets and liabilities. We use all available information to make these fair value determinations and, for certain acquisitions, engage third-party consultants for valuation assistance.
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The fair value of assets and liabilities, including contingent consideration, as of the acquisition date are often estimated using a combination of approaches, including the income approach, which requires us to project future volumes and associated cash flows, and apply an appropriate discount rate; the cost approach, which may require estimates of replacement costs, reproduction costs and depreciation and obsolescence estimates; and the market approach which uses market data and adjusts for entity-specific differences. The estimates used in determining fair values are based on assumptions believed to be reasonable but which are inherently uncertain. Accordingly, actual results may differ materially from the projected results used to determine fair value.
See Item 8. Financial Statements and Supplementary Data – Note 5 for additional information on our acquisitions. See Item 8. Financial Statements and Supplementary Data – Note 17 for additional information on fair value measurements.
Derivatives
We record all derivative instruments at fair value. Substantially all of our commodity derivatives are cleared through exchanges which provide active trading information for identical derivatives and do not require any assumptions in arriving at fair value. Fair value estimation for all our derivative instruments is discussed in Item 8. Financial Statements and Supplementary Data – Note 17. Additional information about derivatives and their valuation may be found in Item 7A. Quantitative and Qualitative Disclosures about Market Risk.
Pension and Other Postretirement Benefit Obligations
Accounting for pension and other postretirement benefit obligations involves numerous assumptions, the most significant of which relate to the following:
• the discount rate for measuring the present value of future plan obligations;
• the expected long-term return on plan assets;
• the rate of future increases in compensation levels;
• health care cost projections; and
• the mortality table used in determining future plan obligations.
We utilize the work of third-party actuaries to assist in the measurement of these obligations. We have selected different discount rates for each of our pension plans and retiree health and welfare based on the projected benefit payment patterns of each individual plan. The selected rates are compared to various similar bond indexes for reasonableness. In determining the assumed discount rates, we use our third-party actuaries’ discount rate models. These models calculate an equivalent single discount rate for the projected benefit plan cash flows using yield curves derived from Aa or higher corporate bond yields. The yield curves represent a series of annualized individual spot discount rates from 0.5 to 99 years. The bonds used have an average rating of Aa or higher from a recognized rating agency and generally only non-callable bonds are included. Outlier bonds that have a yield to maturity that deviate significantly from the average yield within each maturity grouping are not included. Each issue is required to have at least $300 million par value outstanding.
Of the assumptions used to measure the year-end obligations and estimated annual net periodic benefit cost, the discount rate has the most significant effect on the periodic benefit cost reported for the plans. Decreasing the discount rates of 5.50 percent for our pension plans and 5.20 percent for our other postretirement benefit plans by 0.25 percent would increase pension obligations and other postretirement benefit plan obligations by $75 million and $15 million, respectively, would increase defined benefit pension expense by $11 million, and would decrease other postretirement benefit plan expense and by less than $1 million.
The long-term asset rate of return assumption considers the asset mix of the plans (currently targeted at approximately 50 percent equity securities and 50 percent fixed income securities for the primary funded pension plan), past performance and other factors. Certain components of the asset mix are modeled with various assumptions regarding inflation and returns. In addition, our long-term asset rate of return assumption is compared to those of other companies and to historical returns for reasonableness. We used the 7.10 percent long-term rate of return to determine our 2025 defined benefit pension expense. After evaluating activity in the capital markets, along with the current and projected plan investments, we decreased the asset rate of return for our primary plan to 6.90 percent effective for 2026. Decreasing the 7.10 percent asset rate of return assumption by 0.25 percentage points would increase our defined benefit pension expense by $5 million.
Compensation change assumptions are based on historical experience, anticipated future management actions and demographics of the benefit plans.
Health care cost trend assumptions are developed based on historical cost data, the near-term outlook and an assessment of likely long-term trends.
We utilized the 2021 mortality tables from the U.S. Society of Actuaries.
