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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

(Mark One)


☒			ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2025


☐			TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from ___________________ to __________________

Commission file number 001-35714

MPLX LP

(Exact name of registrant as specified in its charter)


Delaware						27-0005456
(State or other jurisdiction of incorporation or organization)						(I.R.S. Employer Identification No.)

200 E. Hardin Street, Findlay, OH 45840-3229

(Address of principal executive offices) (Zip code)

(419) 422-2121

(Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act:


Title of each class	Trading Symbol(s)	Name of each exchange on which registered
Common Units Representing Limited Partnership Interests	MPLX	New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☑ No ☐

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ☐ No ☑

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☑ No ☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☑ No ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act:

Large accelerated filer ☑ Accelerated filer ☐ Non-accelerated filer ☐ Smaller reporting company ☐ Emerging growth company ☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☑

If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements. ☐

Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to §240.10D-1(b). ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ☐ No ☑

The aggregate market value of common units held by non-affiliates as of June 30, 2025 was approximately $19.1 billion. This amount is based on the closing price of the registrant’s common units on the New York Stock Exchange on June 30, 2025, the last trading day of the registrant’s most recently completed second fiscal quarter. Common units held by executive officers and directors of the registrant and its affiliates are not included in the computation. The registrant, solely for the purpose of this required presentation, has deemed its directors and executive officers and those of its affiliates to be affiliates.

MPLX LP had 1,015,204,337 common units outstanding as of February 20, 2026.

Documents Incorporated by Reference: None

Table of Contents


		Page
PART I
Item 1.	Business	3
Item 1A.	Risk Factors	19
Item 1B.	Unresolved Staff Comments	39
Item 1C.	Cybersecurity	39
Item 2.	Properties	42
Item 3.	Legal Proceedings	47
Item 4.	Mine Safety Disclosures	47
PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	48
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	49
Item 7A.	Quantitative and Qualitative Disclosures about Market Risk	72
Item 8.	Financial Statements and Supplementary Data	74
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	118
Item 9A.	Controls and Procedures	118
Item 9B.	Other Information	118
Item 9C.	Disclosures Regarding Foreign Jurisdictions that Prevent Inspections	119
PART III
Item 10.	Directors, Executive Officers and Corporate Governance	120
Item 11.	Executive Compensation	128
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	151
Item 13.	Certain Relationships and Related Transactions, and Director Independence	153
Item 14.	Principal Accountant Fees and Services	154
PART IV
Item 15.	Exhibits and Financial Statement Schedules	155

	Signatures	162

Unless otherwise stated or the context otherwise indicates, all references in this Annual Report on Form 10-K to “MPLX LP,” “MPLX,” “the Partnership,” “us,” “our,” “we,” or like terms refer to MPLX LP and its consolidated subsidiaries. References to our sponsor and customer, “MPC,” refer collectively to Marathon Petroleum Corporation and its subsidiaries, other than the Partnership. Additionally, throughout this Annual Report on Form 10-K, we have used terms in our discussion of the business and operating results that have been defined in our Glossary of Terms.

Table of Contents

Glossary of Terms

The abbreviations, acronyms and industry terminology used in this report are defined as follows:


ANDX			Andeavor Logistics LLC (formerly known as Andeavor Logistics LP), a wholly-owned subsidiary of the Partnership
ARO			Asset retirement obligation
ASC			Accounting Standards Codification
ASU			Accounting Standards Update

Barrel (Bbl)			One stock tank barrel, or 42 United States gallons of liquid volume, used in reference to crude oil or other liquid hydrocarbons.

Bcf/d			One billion cubic feet per day
Btu			One British thermal unit, an energy measurement


DCF (a non-GAAP financial measure)			Distributable Cash Flow
DOT			United States Department of Transportation

EBITDA (a non-GAAP financial measure)			Earnings Before Interest, Taxes, Depreciation and Amortization

EPA			United States Environmental Protection Agency
ESG			Environmental, social and governance
FASB			Financial Accounting Standards Board
FCF (a non-GAAP financial measure)			Free Cash Flow
FERC			Federal Energy Regulatory Commission
GAAP			Accounting principles generally accepted in the United States of America
GHG			Greenhouse gas



IRS			Internal Revenue Service

MarkWest			MarkWest Energy Partners, L.P., a wholly-owned subsidiary of the Partnership
mbbls			Thousands of barrels
mbpd			Thousand barrels per day
MMBtu			One million British thermal units, an energy measurement
MMcf/d			One million cubic feet per day



NGL			Natural gas liquids, such as ethane, propane, butanes and natural gasoline
NYSE			New York Stock Exchange


PHMSA			Pipeline and Hazardous Materials Safety Administration



SEC			United States Securities and Exchange Commission


SOFR			Secured Overnight Financing Rate
USCG			United States Coast Guard
VIE			Variable interest entity

Table of Contents

Disclosures Regarding Forward-Looking Statements

This Annual Report on Form 10-K, particularly Item 1. Business, Item 1A. Risk Factors, Item 3. Legal Proceedings, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations and Item 7A. Quantitative and Qualitative Disclosures about Market Risk, includes forward-looking statements that are subject to risks, contingencies or uncertainties. You can identify forward-looking statements by words such as “advance,” “anticipate,” “believe,” “commitment,” “continue,” “could,” “design,” “drive,” “endeavor,” “estimate,” “expect,” “focus,” “forecast,” “goal,” “guidance,” “intend,” “may,” “objective,” “opportunity,” “outlook,” “plan,” “policy,” “position,” “potential,” “predict,” “priority,” “progress,” “project,” “prospective,” “pursue,” “seek,” “should,” “strategy,” “strive,” “support,” “target,” “trends,” “will,” “would” or other similar expressions that convey the uncertainty of future events or outcomes.

Forward-looking statements include, among other things, statements regarding:

•future financial and operating results;

•ESG plans and goals, including those related to GHG emissions and intensity, biodiversity, inclusion and ESG reporting;

•future levels of capital, environmental or maintenance expenditures, general and administrative and other expenses;

•the success or timing of completion of ongoing or anticipated capital or maintenance projects;

•business strategies, growth opportunities and expected investments, including plans to grow stable cash flows, lower costs and return capital to unitholders;

•the timing and amount of future distributions or unit repurchases; and

•the anticipated effects of actions of third parties such as competitors, activist investors, federal, foreign, state or local regulatory authorities or plaintiffs in litigation.

Our forward-looking statements are not guarantees of future performance and you should not rely unduly on them, as they involve risks, uncertainties and assumptions that we cannot predict. Forward-looking and other statements regarding our ESG plans and goals are not an indication that these statements are material to investors or required to be disclosed in our filings with the SEC. In addition, historical, current, and forward-looking ESG-related statements may be based on standards for measuring progress that are still developing, internal controls and processes that continue to evolve, and assumptions that are subject to change in the future. Material differences between actual results and any future performance suggested in our forward-looking statements could result from a variety of factors, including the following:

•general economic, political or regulatory developments, including tariffs, inflation, interest rates, governmental shutdowns, changes in governmental policies relating to refined petroleum products, crude oil, natural gas, NGLs, renewable diesel and other renewable fuels or taxation, including changes in tax regulations or guidance promulgated pursuant to the new legislation implemented in the One Big Beautiful Bill Act;

•the ability of MPC to achieve its strategic objectives and the effects of those strategic decisions on us;

•further impairments;

•negative capital market conditions, including an increase of the current yield on common units;

•the ability to achieve strategic and financial objectives, including with respect to distribution coverage, future distribution levels, proposed projects and completed transactions;

•the success of MPC’s portfolio optimization, including the ability to complete any divestitures on commercially reasonable terms and/or within the expected timeframe, if at all, and the effects of any such divestitures on our business, financial condition, results of operations and cash flows;

•consumer demand for refined products, natural gas, renewable diesel and other renewable fuels and NGLs;

•the adequacy of capital resources and liquidity, including the availability of sufficient cash flow to pay distributions and access to debt on commercially reasonable terms, and the ability to successfully execute business plans, growth strategies and self-funding models;

•the timing and extent of changes in commodity prices and demand for crude oil, refined products, feedstocks or other hydrocarbon-based products or renewable diesel and other renewable fuels;

•volatility in or degradation of general economic, market, industry or business conditions, including as a result of pandemics, other infectious disease outbreaks, natural hazards, extreme weather events, regional conflicts such as hostilities in the Middle East and Ukraine, tariffs, inflation or rising interest rates;

•changes to the expected construction costs and timing of projects and planned investments, and the ability to obtain regulatory and other approvals with respect thereto;

•the inability or failure of our joint venture partners to fund their share of operations and capital investments;

•the financing and distribution decisions of joint ventures we do not control;

•the availability of desirable strategic alternatives to optimize portfolio assets and our ability to obtain regulatory and other approvals with respect thereto;

•completion of midstream infrastructure by competitors;

•disruptions due to equipment interruption or failure, including electrical shortages and power grid failures;

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•the suspension, reduction or termination of MPC’s obligations under MPLX’s commercial agreements;

•modifications to financial policies, capital budgets, and earnings and distributions;

•the ability to manage disruptions in credit markets or changes to credit ratings;

•our ability to comply with federal and state environmental, economic, health and safety, energy and other policies and regulations or enforcement actions initiated thereunder;

•adverse results in litigation;

•the effect of restructuring or reorganization of business components;

•the potential effects of changes in tariff rates on our business, financial condition, results of operations and cash flows;

•foreign imports and exports of crude oil, refined products, natural gas and NGLs;

•the establishment or increase of tariffs on goods, including crude oil and other feedstocks imported into the United States, other trade protection measures or restrictions or retaliatory actions from foreign governments;

•changes in producer customers’ drilling plans or in volumes of throughput of crude oil, natural gas, NGLs, refined products, other hydrocarbon-based products or renewable diesel and other renewable fuels;

•changes in the cost or availability of third-party vessels, pipelines, railcars and other means of transportation for crude oil, natural gas, NGLs, feedstocks, refined products or renewable diesel and other renewable fuels;

•the price, availability and acceptance of alternative fuels and alternative-fuel vehicles and laws mandating such fuels or vehicles;

•actions taken by our competitors, including pricing adjustments and the expansion and retirement of pipeline capacity, processing, fractionation and treating facilities in response to market conditions;

•expectations regarding joint venture arrangements and other acquisitions or divestitures of assets;

•midstream and refining industry overcapacity or undercapacity;

•industrial incidents or other unscheduled shutdowns affecting our machinery, pipelines, processing, fractionation and treating facilities or equipment, means of transportation, or those of our suppliers or customers;

•acts of war, terrorism or civil unrest that could impair our ability to gather, process, fractionate or transport crude oil, natural gas, NGLs, refined products or renewable diesel and other renewable fuels;

•labor and material shortages;

•the ability to realize expected returns or other benefits on anticipated or ongoing projects or planned or recently completed acquisitions or other transactions, including the recently completed acquisitions of Northwind Delaware Holdings LLC (the “Northwind Midstream Acquisition”) and BANGL, LLC (the “BANGL Acquisition”);

•the timing and ability to obtain necessary regulatory approvals and permits and to satisfy other conditions necessary to complete planned projects or to consummate planned transactions within the expected timeframe, if at all;

•political pressure and influence of environmental groups and other stakeholders that are adverse to the production, gathering, refining, processing, fractionation, transportation and marketing of crude oil or other feedstocks, refined products, natural gas, NGLs, other hydrocarbon-based products or renewable diesel and other renewable fuels;

•the imposition of windfall profit taxes, maximum margin penalties, minimum inventory requirements or refinery maintenance and turnaround supply plans on companies operating in the energy industry in California or other jurisdictions;

•our ability to successfully implement our sustainable energy strategy and principles and achieve our ESG plans and goals within the expected timeframe, if at all; and

•the other factors described in Item 1A. Risk Factors.

We undertake no obligation to update any forward-looking statements except to the extent required by applicable law.

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PART I

Item 1. Business

OVERVIEW

We are a diversified, large-cap master limited partnership formed by MPC in 2012 (as our sponsor) that owns and operates midstream energy infrastructure and logistics assets, and provides fuels distribution services. Our assets include a network of crude oil and refined product pipelines; an inland marine business; light-product, asphalt, heavy oil and marine terminals; storage caverns; refinery tanks, docks, loading racks, and associated piping; crude oil and natural gas gathering systems and pipelines; as well as natural gas and NGL treating, processing and fractionation facilities. Our assets are positioned throughout the United States. The business consists of two segments based on the product-based value chain each supports: Crude Oil and Products Logistics and Natural Gas and NGL Services. The Crude Oil and Products Logistics segment primarily engages in the gathering, transportation, storage and distribution of crude oil, refined products, other hydrocarbon-based products, and renewables. The Crude Oil and Products Logistics segment also includes the operation of our refining logistics, fuels distribution and inland marine businesses, terminals, rail facilities and storage caverns. The Natural Gas and NGL Services segment provides wellhead to market services including gathering, treating, processing and transportation of natural gas and NGLs. For more information on these segments, see Our Operating Segments discussion below. The map below and Item 2. Properties provide information about our assets as of December 31, 2025:

MPLX-Operation-US MAP with key_12-25.jpg

We continue to have a strategic relationship with MPC, which is a large source of our revenues. We have executed numerous long-term, fee-based agreements with minimum volume commitments with MPC which provide us with a stable and predictable revenue stream and source of cash flows. As of December 31, 2025, MPC owned our general partner and approximately 64 percent of our outstanding common units. In 2025, MPC accounted for 48 percent of our total revenues and other income, primarily within our Crude Oil and Products Logistics segment, and will continue to be an important source of our revenues and cash flows for the foreseeable future. We also have long-term relationships with a diverse set of producer customers in many crude oil and natural gas resource plays, including the Marcellus Shale, Permian Basin, Utica Shale, STACK Shale and Bakken Shale, among others.

PRIORITIES AND COMMITMENTS

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 those that operate them. 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. This means strengthening resiliency by lowering carbon intensity and conserving natural resources; innovating for the future by

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investing in emerging technologies; and embedding sustainability in decision-making and in how we engage our people and many stakeholders.

Commitment to Durable Cash Flow Growth

We are focused on growing our fee-based services through long-term contracts, which provide through-cycle cash flow stability. We also challenge ourselves to be disciplined in our capital spending as we look to effectively deploy capital to grow our business and its cash flows. We look to optimize our portfolio of investment opportunities to ensure efficient deployment of capital focusing on projects with the highest returns.

Commitment to Cost Competitiveness

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.

Commitment to Return Capital to Unitholders

We are committed to generating cash flows in excess of both our capital spending and our distributions, while maintaining a strong balance sheet. With our commitment to strict-capital discipline and cost competitiveness, we expect to continue generating strong cash flow, enhancing our financial flexibility to invest in and grow the business, while also supporting the return of capital to MPLX unitholders.

2025 RESULTS

The following table summarizes the operating performance for each segment for the year ended December 31, 2025. For further discussion of our segments and a reconciliation of Non-GAAP measures to our Consolidated Statements of Income, see Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations as well as Item 8. Financial Statements and Supplementary Data – Note 10.

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RECENT DEVELOPMENTS

•On January 29, 2026, we announced that the board of directors of our general partner declared a distribution of $1.0765 per common unit that was paid on February 17, 2026 to common unitholders of record on February 9, 2026.

•On February 12, 2026, MPLX issued $1.0 billion aggregate principal amount of 5.30 percent senior notes due 2036 (the “2036 Senior Notes”) and $500 million aggregate principal amount of 6.10 percent senior notes due 2056 (the “2056 Senior Notes”) in an underwritten public offering.

ORGANIZATIONAL STRUCTURE

We are a Master Limited Partnership (“MLP”) with outstanding common units held by MPC and public unitholders. Our common units are publicly traded on the NYSE under the symbol “MPLX.”

The following diagram depicts our organizational structure and MPC’s ownership interest in us as of February 20, 2026.

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INDUSTRY OVERVIEW

As of December 31, 2025, our diversified services in the midstream sector broken down by our segments are as follows:

Crude Oil and Products Logistics:

The midstream sector plays a crucial role in the oil and gas industry by providing gathering, transportation, terminalling, storage and marketing services as depicted in blue below.

Crude oil is the primary raw material for transportation fuels and the basis for many products, including plastics, petrochemicals and heating oil for homes. Pipelines bring advantaged North American crude oil from the upper Great Plains, Louisiana, Texas, Canada and West Coast to numerous refineries throughout the United States. Terminals provide for the receipt, storage, blending, additization, handling and redelivery of refined products via pipeline, rail, marine and truck transportation. This network of logistics infrastructure also allows for export opportunities by connecting supply to global demand markets. The hydrocarbon market is often volatile and the ability to take advantage of fast-moving market conditions is enhanced by the ability to store crude oil, refined products, other hydrocarbon-based products and renewables at tank farms and caverns. The ability to store various products provides flexibility and logistics optionality which allows participants within the industry to take advantage of changing market conditions.

Natural Gas and NGL Services:

The midstream natural gas industry is the link between the exploration for, and production of, natural gas and the delivery of its hydrocarbon components to end-use markets, as graphically depicted in blue and further described below:

mplx_vc_icons12-25 R1_Value Chain 2 - Horizontal.jpg

•Gathering. The natural gas production process begins with the drilling of wells into gas-bearing rock formations. At the initial stages of the midstream value chain, our network of pipelines, known as gathering systems, directly connect to wellheads in the production area. Our gathering systems then transport raw, or untreated, natural gas to a central location for treating and processing.

•Treating. Certain natural gas streams have significant amounts of carbon dioxide (CO2), hydrogen sulfide (H2S) and nitrogen (N2) contaminants that must be removed prior to entering a processing complex. Our treating facilities remove these contaminants so that the resulting sweet gas can be transported to one of our downstream processing facilities.

•Processing. Natural gas has a widely varying composition depending on the field, formation reservoir or facility from which it is produced. Our natural gas processing complexes remove the heavier and more valuable hydrocarbon

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components, which are extracted as a mixed NGL stream that includes ethane, propane, butanes and natural gasoline (also referred to as “y-grade”). Processing aids in allowing the residue gas remaining after extraction of NGLs to meet the quality specifications for long-haul pipeline transportation and commercial use.

•Fractionation. Fractionation is the further separation of the mixture of extracted NGLs into individual components for end-use sale. Fractionation systems typically exist either as an integral part of a gas processing plant or as a central fractionator.

•Storage, transportation and marketing. Once the raw natural gas has been treated or processed and the raw NGL mix has been fractionated into individual NGL components, the natural gas is delivered to downstream transmission pipelines and NGL components are stored, transported and marketed to end-use markets.

Due to advances in well completion technology and horizontal drilling techniques, unconventional sources such as shale and tight sand formations, have become a source of current and expected future natural gas production. The industry as a whole is characterized by regional competition based on the proximity of gathering systems and processing/fractionation plants to producing natural gas wells, or to facilities that produce natural gas as a byproduct of refining crude oil. Due to the shift in the source of natural gas production, midstream providers with a significant presence in the shale plays will likely have a competitive advantage. Well-positioned operations allow access to all major NGL markets and provide for the development of export solutions for producers. This proximity is enhanced by infrastructure build-out and pipeline projects.

OUR OPERATING SEGMENTS

We conduct our business in two reportable segments: Crude Oil and Products Logistics and Natural Gas and NGL Services. Each of these segments is organized and managed based upon the product-based value chain each supports.

Crude Oil and Products Logistics:

The Crude Oil and Products Logistics segment includes the gathering, transportation, storage and distribution of crude oil, refined products, other hydrocarbon-based products and renewables. These assets consist of a network of 14,853 miles of wholly and jointly-owned pipelines and associated storage assets, refining logistics assets at 13 refineries, 88 terminals including rail and truck racks, one export terminal, storage caverns, tank farm assets, an inland marine business and a fuels distribution business. For information related to our Crude Oil and Products Logistics assets, please see Item 2. Properties – Crude Oil and Products Logistics. Our Crude Oil and Products Logistics assets are integral to the success of MPC’s operations. We continue to evaluate projects and opportunities that will further enhance our existing operations and provide valuable services to MPC and third parties.

We generate revenue in the Crude Oil and Products Logistics segment primarily by charging tariffs for gathering and transporting crude oil, refined products, other hydrocarbon-based products and renewables through our pipelines and at our barge docks delivering to domestic and international destinations, and fees for storing crude oil, refined products and renewables at our storage facilities. Our marine business generates revenue under a fee-for-capacity contract with MPC. Our fuels distribution business provides services related to the scheduling and marketing of products on behalf of MPC, for which it generates revenue based on the volume of MPC’s products sold each month. We are also the operator of additional crude oil and refined product pipelines either owned by MPC, or in which MPLX or MPC has an ownership interest, for which we are paid operating fees. For the year ended December 31, 2025, approximately 88 percent of Crude Oil and Products Logistics segment revenues and other income was generated from MPC.

Natural Gas and NGL Services:

The Natural Gas and NGL Services segment gathers, treats, processes and transports natural gas; and transports, fractionates, stores and markets NGLs. As of December 31, 2025, gathering and processing assets available to MPLX included approximately 9.4 Bcf/d of gas gathering capacity, 11.2 Bcf/d of natural gas processing capacity and 819 mbpd of fractionation and de-ethanization capacity. MPLX also owns or operates approximately 1,401 miles of NGL pipelines. For a summary of our gas processing facilities, fractionation facilities, natural gas gathering systems and NGL and natural gas pipelines see Item 2. Properties – Natural Gas and NGL Services.

Revenue from the sale of products purchased after services are provided is reported as Product sales on the Consolidated Statements of Income and recognized on a gross basis, as MPLX takes control of the product and is the principal in the transaction. For the year ended December 31, 2025, revenues with one customer primarily related to these NGL transactions in the Southwest region accounted for approximately 20 percent of Natural Gas and NGL Services segment revenues. Revenues earned from two customers within the Marcellus region were also significant to the segment; however, neither of these customers represented more than 15 percent of Natural Gas and NGL Services segment revenues. These customers were not significant to MPLX consolidated revenues.

For further financial information regarding our segments, see Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations and Item 8. Financial Statements and Supplementary Data included in this Annual Report on Form 10-K.

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OUR RELATIONSHIP WITH MPC

One of our competitive strengths is our strategic relationship with MPC, which operates one of the largest refining systems in the United States in terms of refining capacity. MPC owns and operates 13 refineries in the Gulf Coast, Mid-Continent and West Coast regions of the United States and distributes refined products, including renewable diesel, through transportation, storage, distribution and marketing services provided primarily by MPLX.

MPC retains a significant interest in us through its non-economic ownership of our general partner and held approximately 64 percent of the outstanding common units of MPLX as of December 31, 2025. Given MPC’s significant interest in us, we believe MPC will promote and support the successful execution of our business strategies. We have implemented and continue to pursue growth and integration opportunities along the existing product-based value chains that benefit both MPC and MPLX, demonstrated by the continued expansion of the Permian to Gulf Coast integrated value chain, which includes the recently completed Northwind Midstream Acquisition and BANGL Acquisition.

OUR CRUDE OIL AND PRODUCTS LOGISTICS CONTRACTS WITH MPC AND THIRD PARTIES

Transportation Services Agreements, Storage Services Agreements, Terminal Services Agreements and Fuels Distribution Services Agreement with MPC

Our Crude Oil and Products Logistics assets are strategically located within, and integral to, MPC’s operations. We have entered into multiple transportation, terminal and storage services agreements with MPC. Under these long-term, fee-based agreements, we provide transportation, terminal and storage services to MPC and most of these agreements include minimum committed volumes from MPC. Under the marine transportation services agreement, MPC has committed to pay a fixed fee for 100 percent of available capacity for boats, barges and third-party chartered equipment. We also have a fuels distribution agreement with MPC under which we provide scheduling and other services for MPC’s products.

The following table sets forth additional information regarding our transportation, storage, terminal and fuels distribution services agreements with MPC as expected to be in effect throughout 2026:


Agreement	Initial Term (years)	MPC minimum commitment
Transportation Services (mbpd):
Crude pipelines(1)	4 - 10	1,933
Refined product pipelines(2)	1 - 15	1,597
Marine(3)	3	N/A
Storage Services (mbbls):



Tank Farms(4)	2 - 12	135,013
Caverns(5)	10 - 20	3,632
Terminal Services(6) (mbpd)	Various	2,256
Fuels Distribution Services(7) (millions of gallons per year)	10	23,449

(1) Renewal terms include multiple two to five-year terms.

(2) Renewal terms include multiple one to five-year terms.

(3) MPC has committed to utilize 100 percent of our available capacity of boats and barges. This agreement is subject to two renewal periods of three years each.

(4) Volume shown represents total shell capacity available for MPC’s use and includes refining logistics tanks. Renewal terms vary and range from year-to-year to multiple additional five-year terms.

(5) Renewal terms include multiple four to five-year terms. Volume shown represents total shell capacity.

(6) Renewal terms vary and range from month-to-month to two additional five-year terms.

(7) The contract was effective in February 2018 and includes one additional five-year renewal term, subject to negotiation by the parties.

Under transportation services agreements containing minimum volume commitments, if MPC fails to transport its minimum throughput volumes during any period, MPC will pay us a deficiency payment equal to the volume of the deficiency multiplied by the tariff rate then in effect. Under certain transportation services agreements, the amount of any deficiency payment paid by MPC may be applied as a credit for any volumes transported on the applicable pipeline in excess of MPC’s minimum volume commitment during a limited number of succeeding periods, after which time any unused credits will expire.

Under most of our terminal services agreements, if MPC fails to meet its minimum volume commitment during any period, MPC will pay us a deficiency payment equal to the volume of the deficiency multiplied by the contractual fee then in effect. Some of our terminal services agreements contain minimum commitments for various additional services such as storage and blending.

We have numerous storage services agreements governing storage services at various types of facilities including terminals, pipeline tank farms, caverns and refineries, under which MPC pays MPLX per-barrel fees for providing storage services. Some of these agreements provide MPC with exclusive access to storage at certain locations, such as storage located at MPC’s refineries or storage in certain caverns. Under these agreements, MPC pays MPLX a per-barrel fee for such storage capacity, regardless of whether MPC fully utilizes the available capacity.

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Through our fuels distribution services, we distribute refined products through an extensive network of retail locations owned or operated by independent entrepreneurs. We have a fuels distribution service agreement with MPC under which MPC pays MPLX a tiered monthly fee based on the volume of MPC’s products marketed by MPLX each month, subject to a maximum annual volume. MPLX has agreed to use commercially reasonable efforts to sell not less than a minimum quarterly volume of MPC’s products during each calendar quarter. If MPLX sells less than the minimum quarterly volume of MPC’s products during any calendar quarter despite its commercially reasonable efforts, MPC will pay MPLX a deficiency payment equal to the volume deficiency multiplied by the applicable tiered fee. The dollar amount of actual sales volume of MPC’s products that exceeds the minimum quarterly volume (an “Excess Sale”) for a particular quarter will be applied as a credit, on a first-in-first-out basis, against any future deficiency payment owed by MPC to MPLX during the four calendar quarters immediately following the calendar quarter in which the Excess Sale occurs.

Our agreements with MPC provide for annual escalations that are either fixed or based on a variety of factors including the FERC index and various other inflation-based indices depending on the nature and geography of the services provided.

Pipeline Operating Agreements with MPC

We operate various pipelines owned by MPC under operating services agreements. Under these operating services agreements, we receive an operating fee for operating the assets, which include certain MPC wholly owned or partially owned crude oil, natural gas and refined product pipelines, and for providing various operational services with respect to those assets. We are generally reimbursed for all direct and indirect costs associated with operating the assets and providing such operational services. These agreements vary in length and automatically renew with most agreements being indexed for inflation.

Other Pipeline Operating Agreements

We maintain and operate five pipelines in which either MPC or MPLX has a joint interest. We receive an operating fee for each of these pipelines, which is subject to adjustment for inflation. In addition, we are reimbursed for specific costs associated with operating each pipeline. The length and renewal terms for each agreement vary.

Transportation, Terminal and Storage Services Agreements with Third Parties

We have multiple transportation and terminal services agreements with third parties under which we provide use of pipelines and tank storage, and provide services, facilities and other infrastructure related to the receipt, storage, throughput, blending and delivery of commodities. Some of these agreements contain minimum volume commitments under which we agree to handle a certain amount of product throughput each month in exchange for a predetermined fixed fee. Under the remaining agreements, we receive an agreed-upon fee based on actual product throughput following the completion of services.

Marine Management Services Agreements with MPC

MPLX has an agreement with MPC under which it provides management services to assist MPC in the oversight and management of the marine business. MPLX receives fixed annual fees for providing the required services, which are subject to predetermined annual escalation rates. This agreement is subject to an initial term of five years and automatically renews for one additional five-year period unless terminated by either party.

Other Agreements with MPC

We have omnibus agreements with MPC that address our payment of a fixed annual fee to MPC for the provision of executive management services by certain executive officers of our general partner and our reimbursement to MPC for the provision of certain services to us, as well as MPC’s indemnification of us for certain matters, including certain environmental, title and tax matters. In addition, we indemnify MPC for certain matters under these agreements. The omnibus agreements also provide for other reimbursements, including certain capital and expense projects.

We also have various employee services agreements and a secondment agreement under which we reimburse MPC for the provision of certain operational and management services to us. All of the employees that conduct our business are directly employed by affiliates of our general partner.

Additionally, we have certain indemnification agreements with MPC under which MPC retains responsibility for remediation of environmental liabilities due to the use or operation of the assets prior to our ownership, and indemnifies us for any losses we incur arising out of those remediation obligations.

OUR NATURAL GAS AND NGL SERVICES CONTRACTS WITH MPC AND THIRD PARTIES

The majority of our revenues in the Natural Gas and NGL Services segment are generated from wellhead to market services, including natural gas gathering, treating, transportation and processing; and NGL transportation, fractionation, marketing and storage. MPLX enters into a variety of contract types including fee-based, percent-of-proceeds, keep-whole and purchase arrangements in order to generate revenues. See Item 8. Financial Statements and Supplementary Data – Note 2 for a further description of these different types of arrangements.

In many cases, MPLX provides services under contracts that contain a combination of more than one of the arrangements described above. The terms of MPLX’s contracts vary based on gas quality conditions, the competitive environment when the

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contracts are signed and customer requirements. In addition, minimum volume commitments may create contract liabilities or deferred credits if current period payments can be used for future services. These are recognized into service revenue in instances where it is probable the customer will not use the credit in future periods.

MPLX’s contract mix and exposure to natural gas and NGL prices may change as a result of changes in producer preferences, MPLX expansion in regions where some types of contracts are more common and other market factors, including current market and financial conditions which have increased the risk of volatility in crude oil, natural gas and NGL prices. Any change in mix may influence our long-term financial results.

Keep-whole Agreement with MPC

MPLX had a keep-whole commodity agreement related to our Rockies operations with MPC. Under the agreement, MPC paid us a processing fee for NGLs related to keep-whole agreements and we paid MPC a marketing fee in exchange for assuming the commodity risk. The pricing structure under this agreement provided for a base volume subject to a base rate and incremental volumes subject to variable rates, which were calculated with reference to certain of our costs incurred as processor of the volumes. The pricing for both the base and incremental volumes was subject to revision each year. This agreement expired in March 2025.

Other Service Agreements

We provide general and administrative services for many of our operated joint ventures under services agreements. Under these services agreements, MPLX receives a management fee, indexed for inflation, for the general and administrative services provided by the Partnership necessary to manage, maintain and report the operating results of the joint ventures’ assets, including natural gas processing plants, natural gas gathering pipelines, natural gas liquids pipelines, fractionation facilities, compressors and related equipment. These service agreements also provide for set fees related to engineering and construction services related to capital projects. These agreements generally remain in force as long as MPLX is the operator of the joint venture.

COMPETITION

Within our Crude Oil and Products Logistics segment, our competition primarily comes from independent terminal and pipeline companies, integrated petroleum companies, refining and marketing companies, distribution companies with marketing and trading arms and other wholesale petroleum products distributors. Competition in any particular geographic area is affected significantly by the volume of products produced by refineries in the area, and in areas where no refinery is present, by the availability of products and the cost of transportation to the area from other locations. Competition for oil supplies is based primarily on the price and scope of services, location of the facility and connectivity to the best priced markets.

As a result of our contractual relationship with MPC under our transportation and storage services agreements, our terminal services agreement, our fuels distribution agreement and our physical asset connections to MPC’s refineries and terminals, we believe that MPC will continue to utilize our assets for transportation, storage, distribution and marketing services. If MPC’s customers reduce their purchases of refined products from MPC due to increased availability of less expensive refined product from other suppliers or for other reasons, MPC may only receive or deliver the minimum volumes through our terminals (or pay the shortfall payment if it does not deliver the minimum volumes), which could decrease our revenues.

In our Natural Gas and NGL Services segment, we face competition for natural gas gathering and in obtaining natural gas supplies for our processing and related services; in obtaining unprocessed NGLs for transportation and fractionation; and in marketing our products and services. Competition for natural gas supplies is based primarily on the location of gas gathering systems and gas processing plants, operating efficiency and reliability, residue gas and NGL market connectivity, the ability to obtain a satisfactory price for products recovered and the fees charged for services supplied to the customer. Competitive factors affecting our fractionation services include availability of fractionation capacity, proximity to supply and industry marketing centers, the fees charged for fractionation services and operating efficiency and reliability of service. Competition for customers to purchase our natural gas and NGLs is based primarily on price, credit and market connectivity.

Our Natural Gas and NGL Services competitors include:

•natural gas midstream providers, of varying financial resources and experience, that gather, treat, transport, process, fractionate, store and market natural gas and NGLs;

•major integrated oil companies and refineries;

•independent exploration and production companies;

•interstate and intrastate pipelines; and

•other marine and land-based transporters of natural gas and NGLs.

Certain competitors, such as major oil and gas and pipeline companies, may have capital resources and contracted supplies of natural gas substantially greater than ours. Smaller local distributors may have a marketing advantage in their immediate service areas.

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We believe that our customer focus, demonstrated by our ability to offer an integrated package of services and our flexibility in considering various types of contractual arrangements, allows us to compete more effectively. This includes having access to both NGL and natural gas markets to allow for flexibility in our gathering and processing in addition to having critical connections to a strong sponsor and key market outlets for NGLs and natural gas. Our strategic gathering and processing agreements with key producers enhance our competitive position to participate in the further development of our resource plays. The strategic location of our assets, including those connected to MPC, and the long-term nature of many of our contracts also provide a significant competitive advantage.

INSURANCE

Our assets may experience physical damage as a result of an accident or natural disaster. These hazards can also cause personal injury and loss of life, severe damage to and destruction of property and equipment, pollution or environmental damage and business interruption. While certain insurance policies are shared with MPC, MPLX maintains its own retention structure.

SEASONALITY

The volume of crude oil and refined products transported and stored utilizing our assets is affected by the level of supply and demand for crude oil and refined products in the markets served directly or indirectly by our assets. The majority of the effects of seasonality on the Crude Oil and Products Logistics segment’s revenues are mitigated through the use of capacity-based agreements and minimum volume commitments.

In our Natural Gas and NGL Services segment, we experience minimal impacts from seasonal fluctuations, which impact the demand for natural gas and NGLs and the related commodity prices caused by various factors including variations in weather patterns from year to year. Overall, our exposure to the seasonality fluctuations is limited due to the nature of our fee-based business.

REGULATORY MATTERS

Our operations are subject to numerous laws and regulations, including those relating to the protection of the environment. Such laws and regulations include, among others, the Interstate Commerce Act (“ICA”), the Natural Gas Act (“NGA”), the Clean Water Act (“CWA”) with respect to water discharges, the Clean Air Act (“CAA”) with respect to air emissions, the Resource Conservation and Recovery Act (“RCRA”) with respect to solid and hazardous waste treatment, storage and disposal, the Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”) with respect to releases and remediation of hazardous substances and the Oil Pollution Act of 1990 (“OPA-90”) with respect to oil pollution and response. In addition, many states where we operate have similar laws. New laws are being enacted and regulations are being adopted on a continuing basis, and the costs of compliance with such new laws and regulations are very difficult to estimate until finalized.

For a discussion of environmental capital expenditures and costs of compliance, see Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Environmental Matters and Compliance Costs. For additional information regarding regulatory risks, see Item 1A. Risk Factors.

Pipeline Regulations

Liquids Pipelines

Some of our existing pipelines are considered interstate common carrier pipelines subject to regulation by the FERC under the ICA, Energy Policy Act of 1992 (“EPAct 1992”) and the rules and regulations promulgated under those laws. The ICA and FERC regulations require that tariff rates for oil pipelines, a category that includes crude oil and petroleum product pipelines, be just and reasonable and the terms and conditions of service must not be unduly discriminatory. The ICA permits interested persons to challenge newly proposed tariff rates or terms and conditions of service, or any change to tariff rates or terms and conditions of service, and authorizes FERC to suspend the effectiveness of such proposal or change for a period of time to investigate. If, upon completion of an investigation, FERC finds that the new or changed service or rate is unlawful, it is authorized to require the carrier to refund the revenues in excess of the prior tariff collected during the pendency of the investigation. An interested person may also challenge existing terms and conditions of service or rates and FERC may order a carrier to change its terms and conditions of service or rates prospectively. Upon an appropriate showing, a shipper may also obtain reparations, from a pipeline, for damages sustained as a result of rates or terms which FERC deemed were not just and reasonable. Such reparation damages may accrue from the complaint through the final order and during the two years prior to the filing of a complaint.

The EPAct 1992 deemed certain interstate petroleum pipeline rates then in effect to be just and reasonable under the ICA. These rates are commonly referred to as “grandfathered rates.” Our rates for interstate transportation service in effect for the 365-day period ending on the date of the passage of the EPAct 1992 were deemed just and reasonable and therefore are grandfathered. Subsequent changes to those rates are not grandfathered. New rates have since been established after the EPAct 1992 for certain pipelines, and certain of our pipelines have subsequently been approved to charge market-based rates.

FERC permits regulated oil pipelines to change their rates within prescribed ceiling levels that are tied to an inflation index. A carrier must, as a general rule, utilize the indexing methodology to change its rates. Cost-of-service ratemaking, market-based

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rates and settlement rates are alternatives to the indexing approach and may be used in certain specified circumstances to change rates.

Intrastate services provided by certain of our liquids pipelines are subject to regulation by state regulatory authorities. Much of the state regulation is complaint-based, both as to rates and priority of access. Not all state regulatory bodies allow for changes based on an index method similar to that used by FERC. In those instances, rates are generally changed only through a rate case process. The state regulators could limit our ability to increase our rates or to set rates based on our costs or could order us to reduce our rates and could, if permitted under state law, require the payment of refunds to shippers.

FERC and state regulatory agencies generally have not investigated rates on their own initiative when those rates are not the subject of a protest or a complaint by a shipper. FERC or a state commission could investigate our rates on its own initiative or at the urging of a third party if the third party is either a current shipper or is able to show that it has a substantial economic interest in our tariff rate level.

Natural Gas Pipelines

Our natural gas pipeline operations are subject to federal, state and local regulatory authorities. Under the NGA, FERC has authority to regulate natural gas companies that provide natural gas pipeline transportation services in interstate commerce. FERC’s authority to regulate those services includes the rates charged for the services, terms and conditions of service, certification and construction of new facilities, the extension or abandonment of services and facilities, the maintenance of accounts and records, the acquisition and disposition of facilities, the initiation and discontinuation of services and various other matters. Natural gas companies may not charge rates that have been determined to be unjust and unreasonable, or unduly discriminatory by FERC. In addition, FERC prohibits FERC-regulated natural gas companies from unduly preferring, or unduly discriminating against, any person with respect to pipeline rates or terms and conditions of service or other matters. Pursuant to FERC’s jurisdiction, existing rates and/or other tariff provisions may be challenged (e.g., by complaint) and rate increases proposed by the pipeline or other tariff changes may be challenged (e.g., by protest). Any successful complaint or protest related to our services or facilities could have an adverse impact on our revenues.

Some of our intrastate gas pipeline facilities are subject to various state laws and regulations that affect the rates we charge and terms of service. Although state regulation is typically less onerous than FERC, state regulation typically requires pipelines to charge just and reasonable rates and to provide service on a non-discriminatory basis. The rates and service of an intrastate pipeline generally are subject to challenge by complaint. Additionally, FERC has adopted certain regulations and reporting requirements applicable to intrastate natural gas pipelines (and Hinshaw natural gas pipelines) that provide certain interstate services subject to FERC’s jurisdiction. We are subject to such regulations and reporting requirements to the extent that any of our intrastate pipelines provide, or are found to provide, such interstate services.

Natural Gas Gathering

Section 1(b) of the NGA exempts natural gas production and gathering from the jurisdiction of FERC. There is, however, no bright-line test for determining the jurisdictional status of pipeline facilities. We own a number of facilities that we believe qualify as production and gathering facilities not subject to FERC jurisdiction. The distinction between FERC-regulated transmission services and federally unregulated gathering services is the subject of litigation from time to time, so we cannot provide assurance that FERC will not at some point assert that these facilities are within its jurisdiction or that such an assertion would not adversely affect our results of operations and revenues. In such a case, we would possibly be required to file a tariff with FERC, potentially provide a cost justification for the transportation charge and obtain certificate(s) of public convenience and necessity for the FERC-regulated pipelines, and comply with additional FERC reporting requirements.

In the states in which we operate, regulation of gathering facilities and intrastate pipeline facilities generally includes various safety, environmental and, in some circumstances, open access, non-discriminatory take requirement and complaint-based rate regulation. For example, some of our natural gas gathering facilities are subject to state ratable take and common purchaser statutes and regulations. Ratable take statutes and regulations generally require gatherers to take, without undue discrimination, natural gas production that may be tendered to the gatherer for handling. Similarly, common purchaser statutes and regulations generally require gatherers to purchase gas without undue discrimination as to source of supply or producer. These statutes are designed to prohibit discrimination in favor of one producer over another producer or one source of supply over another source of supply. Although state regulation is typically less onerous than at FERC, these statutes and regulations have the effect of restricting our right as an owner of gathering facilities to decide with whom we contract to purchase or gather natural gas.

Our gathering operations could be adversely affected should they be subject in the future to the application of state or federal regulation of rates and services or regulated as a public utility. Our gathering operations also may be or become subject to safety and operational regulations and permitting requirements relating to the design, siting, installation, testing, construction, operation, replacement and management of gathering facilities. Additional rules and legislation pertaining to these matters are considered or adopted from time to time. We cannot predict what effect, if any, such changes might have on our operations, but the industry could be required to incur additional capital expenditures and increased costs depending on future legislative and regulatory changes.

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Energy Policy Act of 2005

Under the Domenici-Barton Energy Policy Act of 2005 (“EPAct 2005”) and related regulations, it is unlawful for gas pipelines and storage companies that provide interstate services to: (i) directly or indirectly, use or employ any device, scheme or artifice to defraud in connection with the purchase or sale of natural gas subject to the jurisdiction of FERC, or the purchase or sale of transportation services subject to the jurisdiction of FERC; (ii) make any untrue statement of material fact or omit to make any such statement necessary to make the statements made not misleading; or (iii) engage in any act or practice that operates as a fraud or deceit upon any person. The EPAct 2005 gives the FERC civil penalty authority to impose penalties for certain violations. FERC also has the authority to order disgorgement of profits from transactions deemed to violate the NGA and the EPAct 2005.

Standards of Conduct

FERC has adopted affiliate standards of conduct applicable to interstate natural gas pipelines and certain other regulated entities, defined as “Transmission Providers.” Under these rules, a Transmission Provider becomes subject to the standards of conduct if it provides service to affiliates that engage in marketing functions (as defined in the standards). If a Transmission Provider is subject to the standards of conduct, the Transmission Provider’s transmission function employees (including the transmission function employees of any of its affiliates) must function independently from the Transmission Provider’s marketing function employees (including the marketing function employees of any of its affiliates). The Transmission Provider must also comply with certain posting and other requirements.

PHMSA Regulation

We are subject to regulation by the DOT under the Hazardous Liquid Pipeline Safety Act of 1979 (“HLPSA”). The HLPSA delegated to the DOT the authority to develop, prescribe and enforce minimum federal safety standards for the transportation of hazardous liquids by pipeline. Congress also enacted the Pipeline Safety Act of 1992, also known as the PSA, which added the environment to the list of statutory factors that must be considered in establishing safety standards for hazardous liquid pipelines, required regulations be issued to define the term “gathering line” and establish safety standards for certain “regulated gathering lines,” and mandated that regulations be issued to establish criteria for operators to use in identifying and inspecting pipelines located in High Consequence Areas (“HCAs”), defined as those areas that are unusually sensitive to environmental damage, that cross a navigable waterway, or that have a high population density. In 1996, Congress enacted the Accountable Pipeline Safety and Partnership Act, which limited the operator identification requirement mandate to pipelines that cross a waterway where a substantial likelihood of commercial navigation exists, required that certain areas where a pipeline rupture would likely cause permanent or long-term environmental damage be considered in determining whether an area is unusually sensitive to environmental damage, and mandated that regulations be issued for the qualification and testing of certain pipeline personnel. In the Pipeline Inspection, Protection, Enforcement, and Safety Act of 2006, Congress required mandatory inspections for certain U.S. crude oil and natural gas transmission pipelines in HCAs and mandated that regulations be issued for low-stress hazardous liquid pipelines and pipeline control room management. We are also subject to the Pipeline Safety, Regulatory Certainty and Job Creation Act of 2011, which increased penalties for safety violations, established additional safety requirements for newly constructed pipelines and required studies of certain safety issues that could result in the adoption of new regulatory requirements for existing pipelines. Additionally, we are subject to the Protecting our Infrastructure of Pipelines and Enhancing Safety Act of 2016, which required PHMSA to develop underground gas storage standards within two years and provided PHMSA with significant new authority to issue industry-wide emergency orders if an unsafe condition or practices results in an imminent hazard.

The DOT has delegated its authority under these statutes to the PHMSA, which administers compliance with these statutes and has promulgated comprehensive safety standards and regulations for the transportation of natural gas by pipeline (49 C.F.R. Part 192), as well as hazardous liquids by pipeline (49 C.F.R. Part 195), including regulations for the design and construction of new pipelines or those that have been relocated, replaced or otherwise changed (Subparts C and D of 49 C.F.R., Part 195); pressure testing of new pipelines (Subpart E of 49 C.F.R. Part 195); operation and maintenance of pipelines, establishing programs for public awareness and damage prevention, managing the integrity of pipelines in HCAs and managing the operation of pipeline control rooms (Subpart F of 49 C.F.R. Part 195); protecting steel pipelines from the adverse effects of internal and external corrosion (Subpart H of 49 C.F.R. Part 195); and integrity management requirements for pipelines in HCAs (49 C.F.R. 195.452). PHMSA has undertaken a number of initiatives to reevaluate its pipeline safety regulations. We do not anticipate that we would be impacted by these regulatory initiatives to any greater degree than other similarly situated competitors.

Environmental and Other Regulations

General

Our processing and fractionation plants, storage facilities, pipelines and associated facilities are subject to multiple obligations and potential liabilities under a variety of federal, regional, state and local laws and regulations relating to environmental protection. Such environmental laws and regulations may affect many aspects of our present and future operations, including for example, requiring the acquisition of permits or other approvals to conduct regulated activities that may impose burdensome conditions or potentially cause delays, restricting the manner in which we handle or dispose of our wastes, limiting or prohibiting construction or other activities in environmentally sensitive areas such as wetlands or areas inhabited by threatened or endangered species, requiring us to incur capital costs to construct, maintain and/or upgrade processes, equipment and/or facilities, restricting the locations in which we may construct our compressor stations and other facilities and/or requiring the relocation of existing stations and facilities, and requiring remedial actions to mitigate any pollution that might be caused by our

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operations or attributable to former operations. Spills, releases or other incidents may occur in connection with our active operations or as a result of events outside of our reasonable control, which incidents may result in non-compliance with such laws and regulations. Any failure to comply with these legal requirements may expose us to the assessment of sanctions, including administrative, civil and criminal penalties, the imposition of remedial or corrective actions and the issuance of orders enjoining or limiting some or all of our operations.

We believe that our operations and facilities are in substantial compliance with applicable environmental laws and regulations and the cost of continued compliance with such laws and regulations will not have a material adverse effect on our results of operations or financial condition. Generally speaking, however, the trend in environmental law is to place more restrictions and limitations on activities that may be perceived to adversely affect the environment, which may cause significant delays in obtaining permitting approvals for our facilities, result in the denial of our permitting applications, or cause us to become involved in time consuming and costly litigation. Thus, there can be no assurance as to the amount or timing of future expenditures for compliance with environmental laws and regulations, permits and permitting requirements or remedial actions pursuant to such laws and regulations, and actual future expenditures may be different from the amounts we currently anticipate. Revised or additional environmental requirements may result in increased compliance and mitigation costs or additional operating restrictions, particularly if those costs are not fully recoverable from our customers, and could have a material adverse effect on our business, financial condition, results of operations and cash flow. We may not be able to recover some or any of these costs from insurance. Such revised or additional environmental requirements may also result in substantially increased costs and material delays in the construction of new facilities or expansion of our existing facilities, which may materially impact our ability to meet our construction obligations with our producer customers.

Remediation

A comprehensive framework of environmental laws and regulations governs our operations as they relate to the possible release of hazardous substances or non-hazardous or hazardous wastes into soils, groundwater and surface water and measures taken to mitigate pollution into the environment. CERCLA, also known as the “Superfund” law, as well as comparable state laws, impose liability without regard to fault or the legality of the original conduct on certain classes of persons who are considered to be responsible for the release of a hazardous substance into the environment. These persons include current and prior owners or operators of a site where a release occurred and companies that transported or disposed or arranged for the transport or disposal of the hazardous substances released from the site. Under CERCLA, these persons may be subject to strict joint and several liability for the costs of removing or remediating hazardous substances that have been released into the environment and for restoration costs and damages to natural resources. RCRA and similar state laws may also impose liability for removing or remediating releases of hazardous or non-hazardous wastes from impacted properties.

We currently own or lease, and have in the past owned or leased, properties that have been used over the years for natural gas gathering, processing and transportation, for NGL fractionation, for the storage, gathering and transportation of crude oil, or for the storage and transportation of refined products. During the normal course of operation, whether by us or prior owners or operators, releases of petroleum hydrocarbons or other non-hazardous or hazardous wastes have or may have occurred. We could be required to remove or remediate previously disposed wastes or property contamination, including groundwater contamination, or to perform remedial operations to prevent future contamination. We do not believe that we have any current material liability for cleanup costs under such laws or for third-party claims.

The EPA’s rule designating Perfluorooctanoic Acid (“PFOA”) and Perfluorooctane Sulfonate (“PFOS”) as hazardous substances under CERCLA Section 102(a) became effective on July 8, 2024. The rule has been challenged in court. In addition, the EPA has received three petitions requesting regulatory action on per- and polyfluoroalkyl substances (“PFAS”) under RCRA and in February 2024, proposed two regulations that would add nine PFAS, including PFOA and PFOS, to the list of RCRA hazardous constituents and broaden the definition of hazardous waste applicable to corrective action requirements at hazardous waste treatment, storage, and disposal facilities. We cannot currently predict the impact of these regulations on our remediation costs.

Solid and Hazardous Wastes

We may incur liability under RCRA, and comparable or more stringent state statutes, which impose requirements relating to the handling and disposal of non-hazardous and hazardous wastes. In the course of our operations, we generate some amount of ordinary industrial wastes, such as paint wastes, waste solvents and waste oils that may be regulated as hazardous wastes. It is possible that some wastes generated by us that are currently classified as non-hazardous wastes may in the future be designated as hazardous wastes, resulting in the wastes being subject to more rigorous and costly transportation, storage, treatment and disposal requirements.

Water

We maintain numerous discharge permits as required under the National Pollutant Discharge Elimination System program of the CWA and have implemented systems to oversee our compliance with these permits. In addition, we are regulated under OPA-90, which, among other things, requires the owner or operator of a tank vessel or a facility to maintain an emergency plan to respond to releases of oil or hazardous substances. OPA-90 also requires the responsible company to pay resulting removal costs and damages and provides for civil penalties and criminal sanctions for violations of its provisions. We operate tank vessels and facilities from which spills of oil and hazardous substances could occur. We have implemented emergency oil response plans for all of our components and facilities covered by OPA-90 and we have established Spill Prevention, Control and Countermeasures

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plans for all facilities subject to such requirements. Some coastal states in which we operate have passed state laws similar to OPA-90, but with expanded liability provisions, that include provisions for cargo owner responsibility as well as ship owner and operator responsibility.

Construction or maintenance of our plants, compressor stations, pipelines, barge docks and storage facilities may impact wetlands or other surface water bodies, which are also regulated under the CWA by the EPA, the United States Army Corps of Engineers (“Army Corps”) and state water quality agencies. Regulatory requirements governing wetlands and other surface water bodies (including associated mitigation projects) may result in the delay of our projects while we obtain necessary permits and may increase the cost of new projects and maintenance activities. We believe that we are in substantial compliance with the CWA and analogous state laws. However, there is no assurance that we will not incur material increases in our operating costs or delays in the construction or expansion of our facilities because of future developments, the implementation of new laws and regulations, the reinterpretation of existing laws and regulations, or otherwise, including, for example, increased construction activities, potential inadvertent releases arising from pursuing borings for pipelines, and earth slips due to heavy rain and/or other causes.

On October 22, 2019, the EPA and the Army Corps published a final rule to repeal the 2015 “Clean Water Rule: Definition of Waters of the United States” (“2015 Rule”), which amended portions of the Code of Federal Regulations to restore the regulatory text that existed prior to the 2015 Rule, effective December 23, 2019. The rule repealing the 2015 Rule has been challenged in multiple federal courts. On April 21, 2020, the EPA and the Army Corps promulgated the Navigable Waters Protection Rule (“2020 Rule”) to define “waters of the United States.” The 2020 Rule has been vacated by a federal court. On January 18, 2023, the EPA and the Army Corps published a final rule (“2023 Rule”) repealing the 2020 Rule defining “waters of the United States” and adopting a rule largely based upon the definition adopted in 1986 with some revisions based upon subsequent United States Supreme Court rulings, in particular Rapanos v. United States (2006), which produced two different tests for determining “waters of the United States,” the relatively permanent waters and significant nexus tests. The 2023 Rule has been challenged in multiple federal courts and has been enjoined from applying in 27 states where the pre-2015 “waters of the United States” definition and guidance applies. On May 25, 2023, the United States Supreme Court issued its decision in Sackett v. EPA rejecting the significant nexus test in favor of the relatively permanent waters test, thereby narrowing the scope of wetlands and other water bodies regulated as “waters of the United States.” On September 8, 2023, the EPA and the Army Corps revised the 2023 Rule to conform to the Sackett decision (“Revised 2023 Rule”). The Revised 2023 Rule applies in only 23 states and has also been challenged in multiple federal courts. On November 20, 2025, the EPA and the Army Corps published a proposed rule revising the definition of “waters of the United States," which may provide further clarification and increase Clean Water Act program predictability and consistency, and the public comment period ended January 5, 2026. The regulatory uncertainty could result in delays in permitting and impact pipeline construction and maintenance activities.

In April 2020, the U.S. District Court in Montana vacated Nationwide Permit 12 (“NWP 12”), which authorizes the placement of fill material in “waters of the United States” for utility line activities as long as certain best management practices are implemented. The decision was ultimately appealed to the United States Supreme Court, which partially reversed the district court’s decision, temporarily reinstating NWP 12 for all projects except the Keystone XL oil pipeline. The Army Corps subsequently reissued its nationwide permit authorizations on January 13, 2021, by dividing the NWP that authorizes utility line activities (NWP 12) into three separate NWPs that address the differences in how different utility line projects are constructed, the substances they convey, and the different standards and best management practices that help ensure those NWPs authorize only those activities that have no more than minimal adverse environmental effects. A challenge of the 2021 authorization is currently pending before the U.S. District Court for the District of Columbia (“D.D.C.”), after being transferred from the U.S. District Court for the District of Montana in August 2022 and the plaintiffs request the court vacate and remand the 2021 authorization. Also, a petition has been filed with the Army Corps asking it to revoke the 2021 authorization. On January 8, 2026, the Army Corps published a final action reissuing NWP 12 without any substantive changes. The reissued permit goes into effect on March 15, 2026, and replaces the 2021 version of the permit, which expires on March 14, 2026.

As part of our emergency response activities, we have used aqueous film forming foam (“AFFF”) containing PFAS chemicals as a vapor and fire suppressant. At this time, AFFFs containing PFAS are the most effective foams to prevent and control a flammable petroleum-based liquid fire involving a large storage tank or tank containment area. Fluorine-free firefighting foams are currently under development but have not yet proven to be as effective as AFFFs containing PFAS for all applications.

In May 2016, the EPA issued lifetime health advisory levels (“HALs”) and health effects support documents for two PFAS substances - PFOA and PFOS. These HALs were updated in June 2022, when the EPA also issued HALs for two additional PFAS substances. In February 2019, the EPA issued a PFAS Action Plan identifying actions it is planning to take to study and regulate various PFAS chemicals. The EPA identified that it would evaluate, among other actions, (1) proposing national drinking water standards for PFOA and PFOS, (2) developing cleanup recommendations for PFOA and PFOS, (3) evaluating the listing of PFOA and PFOS as hazardous substances under CERCLA, and (4) conducting toxicity assessments for other PFAS chemicals. Also, on April 26, 2024, the EPA issued a final rule establishing national drinking water standards for PFOS, PFOA, perfluorohexane sulfonic acid (“PFHxS”), perfluorononanoic acid (“PFNA”), perfluorobutane sulfonic acid (“PFBS”), and hexafluoropropylene oxide dimer acid and its ammonium salt (also known as “GenX”). Congress may also take further action to regulate PFAS. We cannot currently predict the impact of these regulations on our operations. In addition, many states are actively proposing and adopting legislation and regulations relating to the use of AFFFs containing PFAS. Additionally, many states are using the EPA HALs for PFOS and PFOA and some states are adopting and proposing state-specific drinking water

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and cleanup standards for various PFAS, including but not limited to PFOS and PFOA. We cannot currently predict the impact of these regulations on our liquidity, financial position, or results of operations.

Air Emissions

The CAA and comparable state laws restrict the emission of air pollutants from many sources and impose various monitoring and reporting requirements. These laws and any implementing regulations may require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with stringent air permit requirements, utilize specific equipment or technologies to control emissions, or aggregate two or more of our facilities into one application for permitting purposes. We believe that our operations are in substantial compliance with applicable air permitting and control technology requirements. However, we may be required to incur capital expenditures and may continue to incur capital expenditures in the future for installation of air pollution control equipment and may encounter construction or operational delays while applying for, or awaiting the review, processing and issuance of, new or amended permits, and we may be required to modify certain of our operations which could increase our operating costs.

In February 2024, the EPA lowered the primary annual National Ambient Air Quality Standard (“NAAQS”) for particulate matter (“PM2.5””) from 12.0 µg/m3 to 9.0 µg/m3. Lowering of the NAAQS and subsequent designation as a nonattainment area could result in increased costs associated with, or result in cancellation or delay of, capital projects at our or our customers’ facilities, or could require emission reductions that could result in increased costs to us or our customers. The final rule is under appeal, and on November 24, 2025, the EPA filed a motion indicating the rule had been issued in error and asked the court to vacate the rule. We cannot predict the effects of the various state implementation plan requirements at this time.

In 2007, the California Air Resources Board (“CARB”) adopted the At-Berth Regulation to control airborne emissions from ocean-going vessels at berth but excluded tanker vessels due to safety and technological challenges for stack emission capture on vessels with hazardous cargo, which challenges still exist today. CARB amended the regulation in August 2020 to include maximum emission rates from auxiliary engines and boilers used to unload tanker vessels at berth. The obligation to meet the emission rates applies to both a vessel and the terminal where it is unloading or loading. The emission rates apply to vessels unloading at terminals at the Port of Long Beach and the Port of Los Angeles beginning January 1, 2025, and at all other terminals beginning January 1, 2027. The waiver issued by the US EPA for the amended regulation has been challenged. Compliance with the regulation is expected to increase our costs at affected facilities; however, to the extent permitted by regulations and our existing agreements, we expect to pass these costs on to our customers.

GHG Emissions

A number of state and regional efforts have emerged that are aimed at tracking and/or reducing GHG emissions by means of cap and trade programs that typically require major sources of GHG emissions to acquire and surrender emission allowances in return for emitting those GHGs. Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would impact our business, any such future laws and regulations could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emission allowances or comply with new regulatory or reporting requirements including the imposition of a carbon tax. Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, crude oil and natural gas produced by our exploration and production customers that, in turn, could reduce the demand for our services and thus adversely affect our cash available for distribution to our unitholders.

Under the National Environmental Policy Act, environmental assessments must be performed for certain projects, including construction of certain new pipelines. Uncertainty related to the environmental assessment, including whether the environmental assessment must consider direct and indirect GHG emissions, can result in delay and increased costs in completing new projects.

The EPA’s final rule titled “Standards of Performance for New, Reconstructed, and Modified Sources and Emissions Guidelines for Existing Sources: Oil and Natural Gas Sector Climate Review,” which was published in March 2024, requires MPLX to control and reduce methane emissions within its natural gas gathering and boosting operations and gas processing facilities. In 2025, the EPA extended the compliance deadlines for several provisions in the rule. The rule is consistent with the voluntary methane reduction programs that MPLX has been implementing through its Focus on Methane Program. As a result, although the rule requires MPLX to make additional investments to further reduce methane emissions, we do not believe the rule will have a material impact to our operations.

The Inflation Reduction Act of 2022 includes a charge on methane emissions above a certain threshold at facilities emitting more than 25,000 metric tons of carbon dioxide equivalent annually. The charge starts at $900 per metric ton of methane in the first year, $1,200 per metric ton in the second year, and increasing to $1,500 per metric ton in the third year and beyond. The One Big Beautiful Bill Act, signed into law on July 4, 2025, postponed implementation of the methane waste emissions charge until 2034, with payments due in 2035. At this time, we do not expect it to have a material adverse effect on our operations, financial condition or results of operations.

Endangered Species Act and Migratory Bird Treaty Act Considerations

The federal Endangered Species Act (“ESA”) and analogous state laws regulate activities that may affect endangered or threatened species, including their habitats. If protected species are located in areas where we propose to construct new gathering or transportation pipelines, processing or fractionation facilities, or other infrastructure, such work could be prohibited

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or delayed in certain of those locations or during certain times, when our operations could result in a taking of the species or destroy or adversely modify critical habitat that has been designated for the species. We also may be obligated to develop plans to avoid potential takings of protected species and provide mitigation to offset the effects of any unavoidable impacts, the implementation of which could materially increase our operating and capital costs. Existing laws, regulations, policies and guidance relating to protected species may also be revised or reinterpreted in a manner that further increases our construction and mitigation costs or restricts our construction activities. Additionally, construction and operational activities could result in inadvertent impact to a listed species and could result in alleged takings under the ESA, exposing MPLX to civil or criminal enforcement actions and fines or penalties. The existence of threatened or endangered species in areas where we conduct operations or plan to construct pipelines or facilities may cause us to incur increased costs arising from species protection measures or could result in delays in, or prohibit, the construction of our facilities or limit our customer’s exploration and production activities, which could have an adverse impact on demand for our midstream operations.

The Migratory Bird Treaty Act implements various treaties and conventions between the United States and certain other nations for the protection of migratory birds. In accordance with this law, the taking, killing or possessing of migratory birds covered under this act is unlawful without authorization. If there is the potential to adversely affect migratory birds as a result of our operations or construction activities, we may be required to seek authorization to conduct those operations or construction activities, which may result in specified operating or construction restrictions on a temporary, seasonal, or permanent basis in affected areas and thus have an adverse impact on our ability to provide timely gathering, treating, processing or fractionation services to our exploration and production customers.

Safety Matters

We are subject to oversight pursuant to the federal Occupational Safety and Health Act, as amended (“OSH Act”), as well as comparable state statutes that regulate the protection of the health and safety of workers. We believe that we have conducted our operations in substantial compliance with regulations promulgated pursuant to the OSH Act, including general industry standards, record-keeping requirements and monitoring of occupational exposure to regulated substances.

We are also subject at regulated facilities to the Occupational Safety and Health Administration’s Process Safety Management and the EPA’s Risk Management Program requirements, which are intended to prevent or minimize the consequences of catastrophic releases of toxic, reactive, flammable or explosive chemicals. The application of these regulations can result in increased compliance expenditures.

In general, we expect industry and regulatory safety standards to become more stringent over time, resulting in increased compliance expenditures. While these expenditures cannot be accurately estimated at this time, we do not expect such expenditures will have a material adverse effect on our results of operations.

The DOT has adopted safety regulations with respect to the design, construction, operation, maintenance, inspection and management of our pipeline assets. These regulations contain requirements for the development and implementation of pipeline integrity management programs, which include the inspection and testing of pipelines and the correction of anomalies. These regulations also require that pipeline operation and maintenance personnel meet certain qualifications and that pipeline operators develop comprehensive spill response plans.

Product Quality Standards

Refined products and other hydrocarbon-based products that we transport are generally sold by us or our customers for consumption by the public. Various federal, state and local agencies have the authority to prescribe product quality specifications for products. Changes in product quality specifications or blending requirements could reduce our throughput volumes, require us to incur additional handling costs or require capital expenditures. For example, different product specifications for different markets affect the fungibility of the products in our system and could require the construction of additional storage. In addition, changes in the product quality of the products we receive on our product pipelines could reduce or eliminate our ability to blend products.

Marine Transportation

Our marine transportation business is subject to regulation by the USCG, federal laws, including the Jones Act, state laws and certain international conventions, as well as numerous environmental regulations. The majority of our vessels are subject to inspection by the USCG and carry certificates of inspection. The crews employed aboard the vessels are licensed or certified by the USCG. We are required by various governmental agencies to obtain licenses, certificates and permits for our vessels.

Our marine transportation business competes principally in markets subject to the Jones Act, a federal cabotage law that restricts domestic marine transportation in the United States to vessels built and registered in the United States, and manned and owned by United States citizens. We presently meet all of the requirements of the Jones Act for our vessels. The loss of Jones Act status could have a significant negative effect on our marine transportation business. The requirements that our vessels be United States built and manned by United States citizens, the crewing requirements and material requirements of the USCG, and the application of United States labor and tax laws increases the cost of United States flag vessels when compared with comparable foreign flag vessels. Our marine transportation business could be adversely affected if the Jones Act were to be modified so as to permit foreign competition that is not subject to the same United States government-imposed burdens.

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The Secretary of Homeland Security is vested with the authority and discretion to waive the Jones Act to such extent and upon such terms as the Secretary may prescribe whenever the Secretary of Homeland Security deems that such action is necessary in the interest of national defense. For example, the Secretary of Homeland Security has waived the Jones Act for limited periods of time and in limited areas following the occurrence of certain natural disasters such as hurricanes. Waivers of the Jones Act can result in increased competition from foreign tank vessel operators, which could negatively impact our marine transportation business.

Security

We have several facilities that are subject to the United States Coast Guard’s Maritime Transportation Security Act, and a number of other facilities that are subject to the Transportation Security Administration’s Pipeline Security Guidelines and are designated as “Critical Facilities.” We have an internal inspection program designed to monitor and ensure compliance with all of these requirements. We believe that we are in material compliance with all applicable laws and regulations regarding the security of our facilities.

Tribal Lands

Various federal agencies, including the EPA and the Department of the Interior, along with certain Native American tribes, promulgate and enforce regulations pertaining to oil and gas operations on Native American tribal lands where we operate. These regulations include such matters as lease provisions, drilling and production requirements, and standards to protect environmental quality and cultural resources. In addition, each Native American tribe is a sovereign nation having the right to enforce certain laws and regulations and to grant approvals independent from federal, state and local statutes and regulations. These laws and regulations may increase our costs of doing business on Native American tribal lands and impact the viability of, or prevent or delay our ability to conduct, our operations on such lands.

HUMAN CAPITAL

We are managed and operated by the board of directors and executive officers of MPLX GP LLC (“MPLX GP”), our general partner and a wholly owned subsidiary of MPC. Our general partner has the sole responsibility for providing the employees and other personnel necessary to conduct our operations. All of the employees that conduct our business are directly employed by affiliates of our general partner. We believe that our general partner and its affiliates have a satisfactory relationship with those employees.

MPC believes its employees are its greatest asset of strength, and its culture reflects the quality of individuals across its workforce. Its collaborative efforts, which include fostering an inclusive environment, providing broad-based development and mentorship opportunities, recognizing and rewarding accomplishments and offering benefits that support the well-being of its employees and their families, contribute to increased engagement and fulfilling careers. Empowering people and prioritizing accountability are also key components for developing a high-performing culture, which is critical to achieving MPC’s strategic vision.

Employee Profile

As of December 31, 2025, our general partner and its affiliates had approximately 5,762 full-time employees that provide services to us under our employee services agreements.

Safety

MPC is committed to safe operations to protect the health and safety of its employees, contractors and communities. MPC’s commitment to safe operations is reflected in its safety systems design, its well-maintained equipment and by learning from its incidents. Part of MPC’s effort to promote safety includes the Operational Excellence Management System, which expands on the RC14001® scope, incorporates a Plan-Do-Check-Act continual improvement cycle, and aligns with ISO 9001, incorporating quality and an increased stakeholder and process focus. Together, these components of MPC’s safety management system provide it with a comprehensive approach to managing risks and preventing incidents, illnesses and fatalities. Additionally, MPC’s annual cash bonus program includes a broad set of measures tied to safety, environmental stewardship and human capital management.

Talent Management

MPC’s People Strategy holistically addresses the dynamic business environment it operates in. It enables MPC to be an employer of choice in the face of shifting talent needs and availability. Executing this People Strategy requires that it attracts and retains the best talent with the right skills and capabilities when we need them. Attracting and retaining top talent involves presenting employees with the tools for success and providing opportunities for long-term engagement and career advancement. MPC also provides job architecture with defined skills and competencies, along with tools and people processes to identify skill gaps and support career development to help its employees grow. Its Talent Acquisition team consists of three segments: Executive Recruiting, Experienced Recruiting and University Recruiting. The specialization within each group allows it to specifically address MPC’s broad range of current and future talent needs, as well as devote time and attention to candidates during the hiring process. MPC believes each candidate brings a new perspective to its workforce, and it actively seeks candidates with a variety of backgrounds and experience.

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MPC equips its employees at every level with classroom training, online courses and on the job activities that provide the knowledge and skills necessary to perform their daily job functions safely and successfully. Simultaneously, it supports its employees with a wide range of career development programs, tools and key talent processes to help them advance and grow their careers within MPC.

Compensation and Benefits

To ensure MPC is offering competitive pay packages, it annually benchmarks compensation, including base salaries, bonus levels and long-term incentive targets. MPC’s annual bonus program, for which all employees are eligible, is a critical component of its compensation as it rewards employees for MPC’s achievement against preset goals, encouraging employee commitment and ownership of results. Employees in the senior leader pay grades, as well as most other leaders, receive long-term incentive awards annually to align their compensation to the interests of MPC shareholders and MPLX unitholders.

MPC offers comprehensive benefits that are also benchmarked annually, including medical, dental and vision insurance for employees, their spouses or domestic partners, and their dependents. MPC also provides retirement programs, including a 401(k) plan and active defined benefit plan, life insurance, family building and support programs, sick and disability benefits, education assistance, as well as supports the well-being of employees and their families through a comprehensive Employee Assistance Program and financial wellness tools. In addition, MPC encourages employees to refresh and recharge by providing competitive vacation programs and paid parental leave benefits for birth mothers and nonbirth parents. Further, MPC awards a significant number of college and trade school scholarships to the high school senior children of its employees through the Marathon Petroleum Scholars Program. Both full-time and part-time employees are eligible for these benefits.

Inclusion

Inclusion is embedded in MPC’s People Strategy, guided by core values, and supported by a dedicated team of subject matter experts and leadership. MPC’s approach is grounded in a belief that a workplace where employees feel respected, supported and empowered to contribute their best leads to better performance and safer operations. By embedding inclusion and opportunity into the way it works, MPC strengthens collaboration, fuels innovation and positions MPLX for long-term success.

MPC promotes inclusivity and respect among its employees. MPC recognizes that when employees feel valued, it shows in their performance. MPC’s employee networks demonstrate this by offering voluntary opportunities for employees to connect with others. Any employee may choose to join any of the seven groups - ADAPT, ARISE, FAMILIA, HONOR, HOPE, PRIDE, and PROMISE. Led by employees with involvement and support from executive sponsors, these networks connect colleagues from across MPC and provide opportunities for development, networking and community involvement.

AVAILABLE INFORMATION

General information about MPLX LP and its general partner, MPLX GP LLC, including Governance Principles, Audit Committee Charter, Conflicts Committee Charter and Certificate of Limited Partnership, can be found at www.mplx.com. In addition, our Code of Business Conduct and Code of Ethics for Senior Financial Officers are available in this same location. We would post on our website any amendments to, or waivers from, either of our codes requiring disclosure under applicable rules within four business days following any such amendment or waiver.

MPLX LP uses its website, www.mplx.com, as a channel for routine distribution of important information, including news releases, analyst presentations, and financial information. Our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q and Current Reports on Form 8-K, as well as any amendments and exhibits to those reports, are available free of charge through our website as soon as reasonably practicable after the reports are filed or furnished with the SEC, or on the SEC’s website. The SEC maintains a website that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC at www.sec.gov. These documents are also available in hard copy, free of charge, by contacting our Investor Relations office. In addition, our website allows investors and other interested persons to sign up to automatically receive email alerts when we post news releases and financial information on our website. Information contained on our website is not incorporated into this Annual Report on Form 10-K or other securities filings.

Item 1A. Risk Factors

You should carefully consider each of the following risks and all the other information contained in this Annual Report on Form 10-K in evaluating us and our common units. Although the risks are organized by headings, and each risk is discussed separately, many are interrelated. Our business, financial condition, results of operations and cash flows could be materially and adversely affected by these risks, and, as a result, the trading price of our common units could decline. We have in the past been adversely affected by certain of, and may in the future be affected by, these risks.

Summary of Risk Factors

We have in the past been adversely affected by certain of, and may in the future be adversely affected by, the following:

•a significant decrease in crude oil and natural gas production in our areas of operation;

•challenges in accurately estimating expected production volumes of our producer customers;

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•our dependence on third parties for the crude oil, natural gas and refined products we gather, transport and store, the natural gas we process, and the NGLs we fractionate and stabilize at our facilities;

•our ability to retain existing customers or acquire new customers;

•our ability to increase fees enough to cover costs incurred under our gathering, treating, processing, transmission, transportation, fractionation, stabilization and storage agreements;

•unplanned maintenance of the United States (“U.S.”) inland waterway infrastructure;

•interruptions in operations at any of our facilities or those of our customers, including MPC;

•inflation;

•problems affecting our information technology systems and those of our third-party business partners and service providers;

•business, compliance and reputational risks associated with increasing regulatory focus on data privacy issues, integrating artificial intelligence into our processes and expanding laws in those areas;

•in our joint ventures, our lack of sole decision-making authority, our reliance on our joint venture partners’ financial condition and disputes between us and our joint venture partners;

•terrorist attacks or other targeted operational disruptions aimed at our facilities or that impact our customers or the markets we serve;

•increases to our maintenance or repair costs;

•severe weather events, other climate conditions and earth movement and other geological hazards;

•insufficient cash from operations after the establishment of cash reserves and payment of our expenses to enable us to pay the intended quarterly distribution to our unitholders;

•our substantial debt and other financial obligations;

•increases in interest rates;

•our exposure to the credit risks of our key customers and derivative counterparties;

•negative effects of our commodity derivative activities;

•uninsured losses;

•future costs relating to evolving environmental or other laws or regulations;

•increased regulation of hydraulic fracturing;

•climate-related and GHG emission regulation;

•climate-related litigation;

•societal and political pressures and other forms of opposition to the future development, transportation and use of carbon-based fuels;

•market deterioration prior to the completion of large capital projects;

•increasing attention to ESG matters;

•goals, targets and disclosures related to ESG matters;

•federal and tribal approvals, regulations and lawsuits relating to our facilities that are located on Native American tribal lands;

•our ability to maintain or obtain real property rights required for our business;

•the consequences resulting from foreign investment in us or our general partner exceeding certain levels;

•federal or state rate and service regulation or rate-making policies;

•costs and liabilities resulting from performance of pipeline integrity programs and related repairs;

•future impairments;

•difficulties in making strategic acquisitions on economically acceptable terms from MPC or third parties;

•integration risks from significant future acquisitions;

•the failure by MPC to satisfy its obligations to us, or a significant reduction in volumes transported through our facilities or stored at our storage assets;

•MPC materially suspending, reducing or terminating its obligations under its agreements with us;

•MPC’s level of indebtedness or credit ratings;

•various tax risks inherent in our master limited partnership structure, including the potential for unexpected tax liabilities for us or our unitholders, more burdensome tax filing requirements and future legislative changes to the expected tax treatment of an investment in us;

•MPC’s conflicts of interest with us, its limited duties to us and our unitholders, and its potential favoring of its interests over our interests and the interests of our unitholders;

•the requirements and restrictions arising under our Sixth Amended and Restated Agreement of Limited Partnership, dated as of February 1, 2021 (“Partnership Agreement”), including the requirement that we distribute all of our available

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cash, limitations on our general partner’s duties, limited unitholder voting rights, and limited unitholder recourse in the event unitholders are dissatisfied with our operations;

•cost reimbursements and fees paid to our general partner and its affiliates, which in certain circumstances are subject to our general partner’s sole discretion;

•control of our general partner being transferred to a third party without unitholder consent;

•the issuance of additional units resulting in the dilution of limited unitholder interests, which issuances may be made without unitholder approval;

•the sale of units - and the adverse impact on the trading price of the common units which might result from such sale - by MPC of the units it holds in public or private markets, and such sales could have an adverse impact on the trading price of the common units;

•affiliates of our general partner, including MPC, competing with us, and neither our general partner nor its affiliates having any obligation to present business opportunities to us;

•our general partner having a limited call right that may require unitholders to sell common units at an undesirable time or price;

•a unitholder’s liability not being limited if a court finds that unitholder action constitutes control of our business;

•unitholders may have to repay distributions that were wrongfully distributed to them;

•the NYSE not requiring a publicly traded limited partnership like us to comply with certain of its corporate governance requirements; and

•the Court of Chancery of the State of Delaware being, to the extent permitted by law, the sole and exclusive forum for substantially all disputes between us and our limited partners.

Business and Operational Risks

A significant decrease in crude oil and natural gas production in our areas of operation may adversely affect our business, financial condition, results of operations and cash available for distribution.

A significant portion of our operations is dependent on the continued availability of natural gas and crude oil production. The production from oil and natural gas reserves and wells owned by our producer customers will naturally decline over time, which means that our cash flows associated with these wells will also decline over time. To maintain or increase throughput levels and the utilization rate of our facilities, we must continually obtain new oil, natural gas, NGL and refined product supplies, which depend in part on the level of successful drilling activity near our facilities, our ability to compete for volumes from successful new wells and our ability to expand our system capacity as needed.

We have no control over the level of drilling activity in the areas of our operations, the amount of reserves associated with the wells or the rate at which production from a well will decline. In addition, we have no control over producers or their production decisions, which are affected by demand, prevailing and projected energy prices, drilling costs, operational challenges, access to downstream markets, the level of reserves, geological considerations, governmental regulations and the availability and cost of capital. Reductions or changes in exploration or production activity in our areas of operations could lead to reduced throughput on our pipelines and utilization rates of our facilities.

Fluctuations in energy prices can negatively affect drilling activity, production rates and investments by third parties in the development of new oil and natural gas reserves. The prices for oil, natural gas and NGLs depend upon factors beyond our control, including global and regional demand, production levels, changes in interstate pipeline gas quality specifications, imports and exports, seasonality and weather conditions, alternative energy sources such as wind, solar and other renewable energy technologies, economic and political conditions domestically and internationally and governmental regulations. Sustained periods of low energy prices could result in producers deciding to limit their oil and gas drilling operations, which could substantially delay the production and delivery of volumes of oil, natural gas and NGLs to our facilities and adversely affect our revenues and cash available for distribution.

This impact may also be exacerbated in circumstances where our compensation for services is commodity-based, which are more directly impacted by changes in natural gas and NGL prices than our fee-based contracts due to frac spread exposure and may result in operating losses when natural gas becomes more expensive on a Btu equivalent basis than NGL products. In addition, our purchase and resale of natural gas and NGLs in the ordinary course exposes us to significant risk of volatility in natural gas or NGL prices due to the potential difference in price at the time of purchase and subsequent sale. The significant volatility in natural gas, NGL and crude oil prices could adversely impact our unit price, thereby increasing our distribution yield and cost of capital. Such impacts could adversely impact our ability to execute our long-term organic growth projects, satisfy our obligations to our customers, and make distributions to unitholders at intended levels, and may also result in non-cash impairments of long-lived assets or goodwill or other-than-temporary non-cash impairments of our equity method investments.

We may not always be able to accurately estimate expected production volumes of our producer customers; therefore, volumes we service in the future could be less than we anticipate.

We may not be able to accurately estimate expected production volumes of our producer customers. Furthermore, we may have only limited crude oil, natural gas, NGL or refined product supplies committed to any new facility prior to its construction. We may

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build new facilities based on expected production growth or market demand. If these expectations are not met, the facilities may be underutilized or may not operate as planned. In order to attract additional crude oil, natural gas, NGL or refined product supplies from a customer, we may be required to order equipment and facilities, obtain rights of way or other land rights or otherwise commence construction activities for facilities that will be required to serve such customer’s additional supplies prior to executing agreements with the customer. If such agreements are not executed, we may be unable to recover such costs and expenses. Additionally, new facilities may not be able to attract enough crude oil, natural gas, NGLs or refined products to achieve our expected investment return. Alternatively, crude oil, natural gas, NGL or refined product supplies committed to facilities under construction may be delivered prior to completion of such facilities. In such event, we may be required to temporarily utilize third-party facilities to offload crude oil, natural gas, NGLs or refined products, which may increase our operating costs and reduce our cash available for distribution.

We depend on third parties for the crude oil, natural gas and refined products we gather, transport and store, the natural gas we process, and the NGLs we fractionate and stabilize at our facilities, and a reduction in these quantities could reduce our revenues and cash flow.

A significant portion of our supply of crude oil, natural gas, NGLs and refined products comes from few key suppliers, who may be under no obligation to deliver a minimum volume. If these or several smaller producers, were to decrease the supply of crude oil, natural gas, NGLs or refined products to our systems and facilities for any reason, we could experience difficulty in replacing those lost volumes. In some cases, the producers or suppliers are responsible for gathering or delivering oil, natural gas, NGLs or refined products to our facilities or we rely on other third parties to deliver volumes to us on behalf of the producers or suppliers. If such producers, suppliers or other third parties are unable, or otherwise fail to, deliver the volumes to our facilities, or if our agreements with any of these third parties terminate or expire such that our facilities are no longer connected to their gathering or transportation systems or the third parties modify the flow of natural gas or NGLs on those systems away from our facilities, the throughput on and utilization of our facilities may be reduced, or we may be required to incur significant capital expenditures to construct and install gathering pipelines or other facilities to be able to receive such volumes. Since most of our operating costs are fixed, a reduction in delivered volumes lowers revenue, net income and cash flow.

We may not be able to retain existing customers, or acquire new customers, which would reduce our revenues and limit our future profitability.

A significant portion of our business comes from a limited number of key customers. The renewal or replacement of existing contracts with our customers at rates sufficient to maintain current revenues and cash flows depends on a number of factors beyond our control, including competition from other gatherers, processors, pipelines and fractionators, and the price of, and demand for, natural gas, NGLs, crude oil and refined products in the markets we serve. Our competitors include large oil, natural gas, refining and petrochemical companies, some of which have greater financial resources, more numerous or greater capacity pipelines, processing and other facilities, greater access to natural gas, crude oil and NGL supplies than we do or other synergies with existing or new customers that we cannot provide. Our competitors may also include our joint venture partners, who in some cases are permitted to compete with us and may have a competitive advantage due to their familiarity with our business arising from our joint venture arrangements, as well as third parties on whom we rely to deliver natural gas, NGLs, crude oil and refined products to our facilities, who may have a competitive advantage due to their ability to modify the flow of natural gas, NGLs, crude oil and refined products on their systems away from our facilities. Additionally, our customers that gather gas through facilities that are not otherwise dedicated to us may develop their own processing and fractionation facilities in lieu of using our services.

As a consequence of the increase in competition in the industry, as well as the volatility of natural gas prices, end-users and utilities are reluctant to enter into long-term purchase contracts. Many customers purchase natural gas from multiple suppliers and can switch providers or even switch to alternative fuels when prices fluctuate. Because we compete with many companies of varying size and resources in the natural gas market, we often rely on price. If management cannot renew contracts or adapt to market changes, our profitability may be impacted.

The fees charged to third parties under our gathering, treating, processing, transmission, transportation, fractionation, stabilization and storage agreements may not escalate sufficiently to cover increases in costs, or the agreements may not be renewed or may be suspended in some circumstances.

Our costs may increase at a rate greater than the fees we charge to third parties. Furthermore, third parties may not renew their contracts with us. Additionally, some third parties’ obligations under their agreements with us may be permanently or temporarily reduced due to certain events, some of which are beyond our control, including force majeure events wherein the supply of natural gas, NGLs, crude oil or refined products are curtailed or cut-off due to events outside our control, and in some cases, certain of those agreements may be terminated in their entirety if the duration of such events exceeds a specified period of time. If the escalation of fees is insufficient to cover increased costs, or if third parties do not renew or extend their contracts with us, or if third parties suspend or terminate their contracts with us, our financial results would suffer.

The U.S. inland waterway infrastructure is aging and may result in increased costs and disruptions to our operations.

Maintenance of the U.S. inland waterway system is vital to our marine transportation operations. The system is composed of over 12,000 miles of commercially navigable waterway, supported by approximately 240 locks and dams designed to provide flood control, maintain pool levels of water in certain areas of the country and facilitate navigation on the inland river system. The U.S. inland waterway infrastructure is aging, with more than half of the locks over 50 years old. As a result, due to the age of the

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locks, planned and unplanned maintenance may create more frequent outages, resulting in delays and additional operating expenses. Part of the costs for new construction and major rehabilitation of locks and dams is funded by marine transportation companies through taxes and the other portion is funded by general federal tax revenues. Failure of the federal government to adequately fund infrastructure maintenance and improvements in the future would have a negative impact on our ability to deliver products to our customers on a timely basis. Furthermore, any additional user taxes that may be imposed in the future to fund infrastructure improvements would increase our operating expenses.

Our operations are subject to business interruptions and present inherent hazards and risks, which could adversely impact our results of operations and financial condition.

Our operations are subject to business interruptions, such as unplanned maintenance, explosions, fires, pipeline releases, product quality incidents, power outages, severe weather, labor disputes, acts of terrorism or other natural or man-made disasters. These types of incidents adversely affect us. Our customers’ operations, including MPC’s refining operations, are subject to similar risks.

These types of incidents adversely affect our operations and may result in serious personal injury or loss of human life, significant damage to property and equipment, environmental pollution, impairment of operations and substantial losses. We and our customers have experienced certain of these incidents in the past. For assets located near populated areas, the level of damage resulting from these incidents could be greater. Due to the nature of our operations, certain interruptions could impact operations in other regions.

Our marine transportation business, in particular, is subject to weather conditions. Adverse weather conditions such as high or low water on the inland waterway systems, fog and ice, tropical storms, hurricanes and tsunamis on both the inland waterway systems and throughout the U.S. coastal waters can impair the operating efficiencies of the marine fleet. Such adverse weather conditions can cause a delay, diversion or postponement of shipments of products and are beyond our control.

In addition, we operate in and adjacent to environmentally sensitive waters where tanker, pipeline, rail car and refined product transportation and storage operations are closely regulated by federal, state and local agencies and monitored by environmental interest groups. Transportation and storage of crude oil, other feedstocks and refined products over and adjacent to water involves inherent risk and subjects us to the provisions of the OPA-90 and state laws in U.S. coastal and Great Lakes states and states bordering inland waterways on which we operate. If we are unable to promptly and adequately contain any accident or discharge involving tankers, pipelines, rail cars or above ground storage tanks transporting or storing crude oil, other feedstocks or refined products, we may be subject to substantial liability. In addition, the service providers contracted to aid us in a discharge response may be unavailable due to weather conditions, governmental regulations or other local or global events.

The construction and operation of certain of our facilities may be impacted by surface or subsurface mining operations by one or more third parties, which could adversely impact our construction activities or cause subsidence or other damage to our facilities. In such event, our construction may be prevented or delayed, or the costs and time increased, or our operations at such facilities may be impaired or interrupted, and we may not be able to recover the costs incurred for delays or to relocate or repair our facilities from such third parties.

Damages resulting from an incident involving any of our assets or operations may result in our being named as a defendant in one or more lawsuits asserting potentially substantial claims or in our being assessed potentially substantial fines by governmental authorities.

We may be negatively impacted by inflation.

Increases in inflation may have an adverse effect on us. Such increases in inflation could impact the commodity markets generally, the overall demand for our products and services, our costs for labor, material and services and the margins we are able to realize on our products and services, all of which could have an adverse impact on our business, financial position, results of operations and cash flows. Inflation may also result in higher interest rates, which in turn would result in higher interest expense related to our variable rate indebtedness and any borrowings we undertake to refinance existing fixed rate indebtedness.

We are increasingly dependent on the performance of our information technology systems and those of our third-party business partners and service providers.

We are increasingly dependent on our information technology systems and those of our third-party business partners and service providers for the safe and effective operation of our business. We rely on such systems to process, transmit and store electronic information, including financial records and personal data, and to manage or support a variety of business processes, including our supply chain, pipeline operations, gathering and processing operations, financial transactions, banking and numerous other processes and transactions.

Our information systems (and those of our third-party business partners and service providers), including our cloud computing environments and operational technology environments, are subject to numerous and evolving cybersecurity threats and attacks, including ransomware and other malware, phishing and social engineering schemes, supply chain attacks, and advanced artificial intelligence attacks, which can compromise our ability to operate, and the confidentiality, availability, and integrity of data in our systems or those of our third-party business partners and service providers. These and other cybersecurity threats may

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originate with criminal attackers, advanced persistent threats and nation-state actors, state-sponsored actors, or employee error or malfeasance. Cybersecurity threat actors also may attempt to exploit vulnerabilities in software, including software commonly used by companies in cloud-based services and bundled software. Because the techniques used to obtain unauthorized access, or to disable or degrade systems, continuously evolve and some have become increasingly complex and sophisticated, and can remain undetected for a period of time despite efforts to detect and respond in a timely manner, we (and our third-party business partners and service providers) are subject to the risk of cyberattacks and cybersecurity incidents.

Our cybersecurity and infrastructure protection technologies, disaster recovery plans and systems, employee training and vendor risk management may not be sufficient to defend us against all unauthorized attempts to access our information or impact our systems. We and our third-party vendors and service providers have been and may in the future be subject to cybersecurity events and incidents of varying degrees. To date, the impacts of prior events and incidents have not had a material adverse effect on us.

Cybersecurity incidents involving our information technology systems or those of our third-party business partners and service providers can result in theft, destruction, loss, misappropriation or release of confidential financial data, personal data, intellectual property and other information; give rise to remediation or other expenses; result in litigation, claims and increased regulatory review, investigations, or scrutiny; reduce our customers’ willingness to do business with us; disrupt our operations and the services we provide to customers; and subject us to litigation and legal liability under international, U.S. federal and state laws. Any of such results could have a material adverse effect on our reputation, business, financial condition, results of operations and cash flows.

Increasing regulatory focus on and expanding laws related to data privacy issues could expose us to increased liability, subject us to lawsuits, investigations, reputational harm and increase costs and restrictions on our operations that could significantly and adversely affect our business.

Along with our own data and information collected in the normal course of our business, we, and some of our third-party service providers, collect, use, transfer and retain certain data that is subject to specific laws and regulations. The transfer and use of this data is becoming increasingly complex. This data is subject to governmental regulation at international, federal, state and local levels in many areas of our business, including data privacy and security laws such as the California Consumer Privacy Act, as amended by the California Privacy Rights Act (“CCPA”). To date, comprehensive state privacy laws have been proposed or passed in more than twenty U.S. states. Additionally, the U.S. Federal Trade Commission and multiple state attorneys general are interpreting federal and state consumer protection laws to impose standards for the online collection, use, dissemination and security of data as well as requiring disclosures regarding such practices. Existing and potential future data privacy laws pose increasingly complex compliance, monitoring and control obligations and could potentially elevate our costs and risk exposure. As the implementation, interpretation, and enforcement of such laws continue to progress and evolve, there may also be developments that amplify such costs and risk exposure. Any failure by us, or by a third-party service provider upon which we rely, to comply with these laws and regulations, including as a result of a cybersecurity incident or privacy breach, could expose us to significant penalties and liabilities, including individual claims or consumer class actions, commercial litigation, administrative, and investigations or actions, regulatory intervention and sanctions or fines.

As we integrate artificial intelligence technologies into our processes, these technologies may present business, compliance and reputational risks.

Recent and continuously evolving technological advances in artificial intelligence (“AI”) and machine-learning technology present new opportunities and also pose new risks. Our integration of these technologies, whether developed internally or procured through our third-party service providers, into our processes may result in new or expanded risks and liabilities. Such risks and liabilities include enhanced governmental or regulatory scrutiny, litigation, compliance issues, ethical concerns, confidentiality or security risks, as well as other factors that could adversely affect our business, reputation, and financial results. The utilization of AI could also result in loss of intellectual property and subject us to heightened risks related to intellectual property infringement or misappropriation. The use of AI can lead to unintended consequences, including generating content that is inaccurate, misleading or otherwise flawed, or that results in unintended biases and discriminatory outcomes, which could harm our reputation and expose us to risks related to inaccuracies or errors in the output of such technologies.

Our investments in joint ventures could be adversely affected by our reliance on our joint venture partners and their financial condition, and our joint venture partners may have interests or goals that are inconsistent with ours.

We conduct some of our operations through joint ventures in which we share control over certain economic and business interests with our joint venture partners. Our joint venture partners may have economic, business or legal interests or goals that are inconsistent with our goals and interests or may be unable to meet their obligations. Failure by us, or an entity in which we have an interest, to adequately manage the risks associated with any joint ventures could have a material adverse effect on the financial condition or results of operations of our joint ventures and adversely affect our reputation, business, financial condition, results of operations and cash flows.

Terrorist attacks or other targeted operational disruptions may affect our facilities or those of our customers and suppliers.

Refining, gathering and processing, pipeline and terminal infrastructure, and other energy assets, may be the subject of terrorist attacks or other targeted operational disruptions. Any attack or targeted disruption of our operations, those of our customers or, in

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some cases, those of other energy industry participants, could have a material and adverse effect on our business. Similarly, any similar event that severely disrupts the markets we serve could materially and adversely affect our results of operations, financial position and cash flows.

Many of our assets have been in service for many years and, as a result, our maintenance or repair costs may increase in the future.

Our pipelines, terminals, fractionators, processing facilities and storage assets are generally long-lived assets, and many of them have been in service for many years. The age and condition of our assets could result in increased maintenance or repair expenditures in the future. Any significant increase in these expenditures could adversely affect our results of operations, financial position or cash flows, as well as our ability to make cash distributions to our unitholders.

Severe weather events, other climate conditions and earth movement and other geological hazards may adversely affect our and our customers’ assets and ongoing operations.

Our and our customers’ assets are subject to acute physical risks, such as floods, hurricane-force winds, wildfires, winter storms, and earth movement in variable, steep and rugged terrain and terrain with varied or changing subsurface conditions, and chronic physical risks, such as sea-level rise or water shortages. The occurrence of these and similar events have had, and may in the future have, an adverse effect on our assets and operations. We have incurred and will continue to incur additional costs to protect our assets and operations from such physical risks and employ the evolving technologies and processes available to mitigate such risks. To the extent such severe weather events or other climate conditions increase in frequency and severity, we may be required to modify operations and incur costs that could materially and adversely affect our business, financial condition, results of operations and cash flows.

Financial Risks

We may not have sufficient cash from operations after the establishment of cash reserves and payment of our expenses, including cost reimbursements to MPC and its affiliates, to enable us to pay the intended quarterly distribution to our unitholders.

The amount of cash we can distribute to our common unitholders principally depends on the amount of cash we generate from our operations, which fluctuates from quarter to quarter based on, among other things:

•the volumes of natural gas, crude oil, NGLs and refined products we gather, process, store, transport and fractionate;

•the fees and tariff rates we charge and the margins we realize for our services and sales;

•the prices of, level of production of and demand for crude oil, natural gas, NGLs and refined products;

•the level of our operating costs including repairs and maintenance;

•the relative prices of NGLs and crude oil; and

•prevailing economic conditions.

In addition, the actual amount of cash available for distribution also depends on other factors, some of which are beyond our control, including:

•the amount of our operating expenses and general and administrative expenses, including cost reimbursements to MPC;

•our debt service requirements and other liabilities;

•fluctuations in our working capital needs;

•our ability to borrow funds and access capital markets;

•restrictions in our joint venture agreements or agreements governing our debt;

•the level and timing of capital expenditures we make, including capital expenditures incurred in connection with our growth projects;

•the cost of acquisitions, if any; and

•the amount of cash reserves established by our general partner in its discretion, which may increase in the future and which may in turn further reduce the amount of cash available for distribution.

Furthermore, the amount of cash we have available for distribution depends primarily on our cash flow and not solely on profitability, which is affected by non-cash items. As a result, we may make distributions during periods when we record net losses and may not make distributions during periods when we record net income.

Our substantial debt and other financial obligations could impair our financial condition, results of operations and cash flow, and our ability to fulfill our debt obligations.

We have significant debt obligations, which totaled $26.0 billion as of December 31, 2025, including amounts, if any, outstanding under our loan agreement with MPC. We may incur significant debt obligations in the future. Our indebtedness may impose

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various restrictions and covenants on us that could have, or the incurrence of such debt could otherwise result in, material adverse consequences, including:

•We may have difficulties obtaining additional financing for working capital, capital expenditures, acquisitions, or general business purposes on favorable terms, if at all, or our cost of borrowing may increase.

•We may be at a competitive disadvantage compared to our competitors who have proportionately less debt, or we may be more vulnerable to, and have limited flexibility to respond to, competitive pressures or a downturn in our business or the economy generally.

•If our operating results are not sufficient to service our indebtedness, we may be required to reduce our distributions, reduce or delay our business activities, investments or capital expenditures, sell assets or issue equity, which could materially and adversely affect our financial condition, results of operations, cash flows and ability to make distributions to unitholders, as well as the trading price of our common units.

•The operating and financial restrictions and covenants in our revolving credit facility and any future financing agreements could restrict our ability to finance our operations or capital needs or to expand or pursue our business activities, which may, in turn, limit our ability to make distributions to our unitholders. Our ability to comply with these covenants may be impaired from time to time if the fluctuations in our working capital needs are not consistent with the timing for our receipt of funds from our operations.

•If we fail to comply with our debt obligations and an event of default occurs, our lenders could declare the outstanding principal of that debt, together with accrued interest, to be immediately due and payable, which may trigger defaults under our other debt instruments or other contracts. Our assets may be insufficient to repay such debt in full, and the holders of our units could experience a partial or total loss of their investment.

Increases in interest rates could adversely impact our unit price, our ability to issue equity or incur additional debt for acquisitions or other purposes or refinance existing debt and our ability to make distributions at our intended levels.

Our revolving credit facility and our loan agreement with MPC have variable interest rates. As a result, future interest rates on our debt could be higher than current levels, causing our financing costs to increase accordingly. In addition, we may in the future refinance outstanding borrowings under our revolving credit facility with fixed-rate indebtedness. Interest rates payable on fixed-rate indebtedness typically are higher than the short-term variable interest rates that we pay on borrowings under our revolving credit facility. We also have other fixed-rate indebtedness that we may need or desire to refinance in the future at or prior to the applicable stated maturity. A prolonged rising interest rate environment could have an adverse impact on our ability to issue equity, refinance existing debt or incur additional debt for acquisitions or other purposes on favorable terms, if at all. Accordingly, increases in interest rates could adversely impact our business, financial conditions, results of operations, cash flows and our ability to make distributions at our intended levels.

As with other yield-oriented securities, our unit price will be impacted by our cash distributions and the implied distribution yield. The distribution yield is often used by investors to compare and rank yield-oriented securities for investment decision-making purposes. Therefore, changes in interest rates, either positive or negative, may affect the yield requirements of investors who invest in our units, and a rising interest rate environment could have an adverse impact on our unit price.

We are exposed to the credit risks of our key customers, and any material non-payment or non-performance by our key customers could reduce our ability to make distributions to our unitholders.

We are subject to risks of loss resulting from non-payment or non-performance by our customers, which risks may increase during periods of economic uncertainty. Furthermore, some of our customers may be highly leveraged and subject to their own operating and regulatory risks, which increases the risk that they may default on their obligations to us. This risk is further heightened during sustained periods of declines of natural gas, NGL and crude oil prices. To the extent any of our customers are in financial distress or commence bankruptcy proceedings, our contracts with them, including provisions relating to dedications of production, may be subject to renegotiation or rejection under applicable provisions of the United States Bankruptcy Code. If a contract with a customer is altered or rejected in bankruptcy proceedings, we could lose some or all of the expected revenues associated with that contract. Any such material non-payment or non-performance could have a material adverse effect on our business, financial condition, results of operations and cash flows.

We do not insure against all potential losses, and, therefore, our business, financial condition, results of operations and cash flows could be adversely affected by unexpected liabilities and increased costs.

We maintain insurance coverage in amounts we believe to be prudent against many, but not all, potential liabilities arising from operating hazards. Uninsured liabilities arising from operating hazards such as explosions, fires, pipeline releases, cybersecurity breaches or other incidents involving our assets or operations can reduce the funds available to us for capital and investment spending and could have a material adverse effect on our business, financial condition, results of operations and cash flows. Historically, we also have maintained insurance coverage for physical damage and resulting business interruption to our major facilities, with significant self-insured retentions. In the future, we may not be able to maintain insurance of the types and amounts we desire at reasonable rates.

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We have recorded goodwill and other intangible assets that could become further impaired and result in material non-cash charges to our results of operations.

We accounted for certain acquisitions using the acquisition method of accounting, which requires that the assets and liabilities of the acquired business be recorded to our balance sheet at their respective fair values as of the acquisition date. Any excess of the purchase consideration over the fair value of the acquired net assets is recognized as goodwill.

As of December 31, 2025, our balance sheet reflected $8.8 billion and $1.4 billion of goodwill and other intangible assets, respectively. We have in the past recorded significant impairments of our goodwill. To the extent the value of goodwill or intangible assets becomes further impaired, we may be required to incur additional material non-cash charges relating to such impairment. Our operating results may be significantly impacted from both the impairment and the underlying trends in the business that triggered the impairment.

Large capital projects may be subject to delays, can take years to complete, and market conditions could deteriorate significantly between the project approval date and the project startup date, negatively impacting project returns.

Delays in completing capital projects or making required changes or upgrades to our facilities could subject us to fines or penalties as well as affect our ability to supply certain products we produce. Such delays or cost increases may arise as a result of unpredictable factors, many of which are beyond our control, including:

•denials of, delays in receiving, or revocations of requisite regulatory approvals or permits;

•unplanned increases in the cost of construction materials or labor, whether due to inflation or other factors;

•disruptions in transportation of components or construction materials;

•adverse weather conditions, natural disasters or other events (such as equipment malfunctions, explosions, fires or spills) affecting our facilities, or those of vendors or suppliers;

•shortages of sufficiently skilled labor, or labor disagreements resulting in unplanned work stoppages;

•market-related increases in a project’s debt or equity financing costs;

•global supply chain disruptions;

•nonperformance by, or disputes with, vendors, suppliers, contractors or subcontractors; and

•delays due to citizen, state or local political or activist pressure.

Any one or more of these factors could have a significant impact on our ongoing capital projects. If we were unable to make up the delays associated with such factors or to recover the related costs, or if market conditions change, it could materially and adversely affect our capital project returns and our business, financial condition, results of operations and cash flows.

Legal and Regulatory Risks

We expect to continue to incur substantial capital expenditures and operating costs to meet the requirements of evolving environmental and other laws or regulations. Changes to the federal government’s policies and operations could lead to increased regulatory uncertainty and volatility and increased state regulation, which may impact our business, financial condition and results of operations.

Our business is subject to numerous environmental laws and regulations at the federal, state and local level. These laws and regulations continue to increase in both number and complexity and affect our business. Laws and regulations expected to become more stringent relate to the following:

•the emission or discharge of materials into the environment;

•solid and hazardous waste management;

•the regulatory classification of materials currently or formerly used in our business;

•pollution prevention;

•climate change and GHG emissions;

•the production, importation, use, and disposal of specific chemicals;

•public and employee safety and health;

•permitting;

•inherently safer technology; and

•facility security.

The specific impact of laws and regulations on us and our competitors may vary depending on a number of factors, including the age and location of operating facilities, marketing areas and production processes and subsequent judicial interpretation of such laws and regulations. We have incurred and will continue to incur substantial capital, operating and maintenance, and remediation expenditures to modify operations, install pollution control equipment, perform site cleanups or curtail operations. We have incurred and may in the future incur liability for personal injury, property damage, natural resource damage or clean-up costs due to alleged contamination and/or exposure to chemicals such as benzene and methyl tert-butyl ether (“MTBE”). There is also increased regulatory interest in PFAS, which we expect will lead to increased monitoring and remediation obligations and

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potential liability related thereto. Such expenditures could materially and adversely affect our business, financial condition, results of operations and cash flows.

In 2025, the U.S. presidential administration announced wide-ranging policy changes and issued numerous executive actions. The U.S. EPA and other federal agencies began proposing and promulgating regulations consistent with the administration’s policy changes. If the federal government relaxes or revokes certain environmental regulations, states may pass laws that vary in stringency and scope by state, creating a patchwork of regulation. For example, various states have passed laws regulating the use of materials containing PFAS and setting action levels for the remediation of certain PFAS. We cannot predict the extent to which states will pass such legislation, or the ultimate effect these state laws will have on our business, financial condition and results of operations.

Increased regulation of hydraulic fracturing and other oil and gas production activities could result in reductions or delays in U.S. production of crude oil and natural gas, which could adversely affect our results of operations and financial condition.

While we do not conduct hydraulic fracturing operations, we do provide gathering, treating, processing and fractionation services with respect to natural gas and natural gas liquids produced by our customers as a result of such operations. A range of federal, state and local laws and regulations currently govern or, in some cases, prohibit, hydraulic fracturing in some jurisdictions. Stricter laws, regulations and permitting processes may be enacted in the future. If federal, state and local legislation and regulatory initiatives relating to hydraulic fracturing or other oil and gas production activities are enacted or expanded, such efforts could impede oil and gas production, increase producers’ cost of compliance, and result in reduced volumes available for our midstream assets to gather, treat, process and fractionate.

Climate change and GHG emission regulation could affect our operations, energy consumption patterns and regulatory obligations, any of which could adversely impact our business, results of operations and financial condition.

Currently, multiple legislative and regulatory measures to address GHG and other emissions are in various phases of consideration, promulgation or implementation. These include actions to develop international, federal, regional or statewide programs, which could require reductions in our GHG or other emissions, establish a carbon tax and decrease the demand for refined products. Requiring reductions in these emissions could result in increased costs to (i) operate and maintain our facilities, (ii) install new emission controls at our facilities and (iii) administer and manage any emissions programs, including acquiring emission credits or allotments.

Certain municipalities have also proposed or enacted restrictions on the installation of natural gas appliances and infrastructure in new residential or commercial construction, which could affect demand for the natural gas that we transport and store. Certain jurisdictions have enacted or are considering ordinances that would prohibit construction or expansion of fossil fuel terminals.

Regional and state climate change and air emissions goals and regulatory programs are complex, subject to change and considerable uncertainty due to a number of factors including technological feasibility, legal challenges and potential changes in federal policy. Increasing concerns about climate change and carbon intensity have also resulted in societal concerns and a number of international and national measures to limit GHG emissions. Additional stricter measures and investor pressure can be expected in the future and any of these changes may have a material adverse impact on our business or financial condition.

The scope and magnitude of the changes to U.S. climate change strategy under the current and future administrations, however, remain subject to the passage of legislation and interpretation and action of federal and state regulatory bodies; therefore, the impact to our industry and operations due to GHG regulation is unknown at this time.

Energy companies are subject to increasing environmental and climate-related litigation.

Governmental and other entities in various U.S. states have filed lawsuits against various energy companies, including MPC, alleging damages as a result of climate change, false statements about climate change, and violations of various consumer protection statutes. The plaintiffs are seeking unspecified damages and abatement under various tort theories.

Additionally, private plaintiffs and government parties have undertaken efforts to shut down energy assets by challenging operating permits, the validity of easements or the compliance with easement conditions. For example, the Dakota Access Pipeline, in which we have a minority interest, is subject to, and may in the future be subject to, litigation seeking a permanent shutdown of the pipeline. There remains a high degree of uncertainty regarding the ultimate outcome of these types of proceedings, as well as their potential effect on our business, financial condition, results of operation and cash flows.

We are subject to risks associated with societal and political pressures and other forms of opposition to the development, transportation and use of carbon-based fuels. Such risks could adversely impact our business and our ability to continue to operate or realize certain growth strategies.

We operate and develop our business with the expectation that regulations and societal sentiment will continue to enable the development, transportation and use of carbon-based fuels. However, policy decisions relating to the production, refining, transportation, storage and marketing of carbon-based fuels are subject to political pressures and the influence of public sentiment on GHG emissions, climate change, and climate adaptation. Additionally, societal sentiment regarding carbon-based fuels may adversely impact our reputation and MPC’s ability to attract and retain the employees who provide services to us.

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The approval process for our projects has become increasingly challenging, due in part to state and local concerns related to pipelines, negative public perception regarding the oil and gas industry, and concerns regarding GHG emissions downstream of pipeline operations. Our expansion or construction projects may not be completed on schedule (or at all), or at the budgeted cost. We also may be required to incur additional costs and expenses in connection with the design and installation of our facilities due to their location and the surrounding terrain. We may be required to install additional facilities, incur additional capital and operating expenditures, or experience interruptions in or impairments of our operations to the extent that the facilities are not designed or installed correctly.

Increasing attention to environmental, social and governance matters may impact our business and financial results.

In recent years, increasing attention has been given to corporate activities related to ESG matters in public discourse and the investment community, including climate change, energy transition matters, and inclusion. A number of advocacy groups, both domestically and internationally, have campaigned for governmental and private action to promote ESG-related change at public companies, including, but not limited to, through the investment and voting practices of investment advisers, pension funds, universities and other members of the investing community. These activities include increasing attention and demands for action related to climate change and energy transition matters, such as promoting the use of substitutes to fossil fuel products and encouraging the divestment of fossil fuel equities, as well as pressuring lenders and other financial services companies to limit or curtail activities with fossil fuel companies. If this were to continue, it could have a material adverse effect on our access to capital. Members of the investment community have begun to screen companies such as ours for sustainability performance, including practices related to GHG emission reduction and energy transition strategies. If we are unable to find economically viable, as well as publicly acceptable, solutions that reduce our GHG emissions, reduce GHG intensity for new and existing projects, increase our non-fossil fuel product portfolio, and/or address other ESG-related stakeholder concerns, our business and results of operations could be materially and adversely affected. Further, our reputation could be damaged as a result of our support of, association with or lack of support or disapproval of certain social causes, as well as any decisions we make to continue to conduct, or change, certain of our activities in response to such considerations.

Our goals, targets and disclosures related to ESG matters expose us to numerous risks, including risks to our reputation and unit price.

Companies across all industries are facing increasing scrutiny from stakeholders related to ESG matters, including practices and disclosures regarding climate-related initiatives. MPLX has established a target to reduce methane emissions intensity and MPC, MPLX’s largest customer, has established a target to reduce GHG emissions intensity. These targets reflect our current plans and aspirations and are not guarantees that we will be able to achieve them. We assess progress with these targets on an annual basis. We may modify, discontinue, update or expand targets or adopt new metrics as new information, opportunities, and technologies become available. Further, there are conflicting expectations and priorities from regulatory authorities, investors, voluntary reporting frame works, and other stakeholders surrounding accounting and disclosure of ESG matters and climate related initiatives. Our efforts to accomplish and accurately report on these goals and objectives, which may be, in part, dependent on the actions of suppliers and other third parties, present numerous operational, regulatory, reputational, financial, legal, and other risks, any of which could have a material negative impact, including on our reputation and unit price.

Efforts to achieve goals and targets, such as the foregoing and future internal climate-related initiatives, may increase costs, require purchase of carbon credits, or limit or impact our business plans and financial results, potentially resulting in the reduction to the economic end-of-life of certain assets and an impairment of the associated net book value, among other material adverse impacts. Additionally, as the nature, scope and complexity of ESG reporting, calculation methodologies, voluntary reporting standards and disclosure requirements expand, we may have to undertake additional costs to control, assess and report on ESG metrics. Our failure or perceived failure to pursue or fulfill such goals and targets or to satisfy various reporting standards within the timelines we announce, or at all, could have a negative impact on investor sentiment, ratings outcomes for evaluating our approach to ESG matters, unit price, and cost of capital and expose us to government enforcement actions and private litigation, among other material adverse impacts.

Certain of our facilities are located on Native American tribal lands and are subject to various federal and tribal approvals and regulations, which can increase our costs and delay or prevent our efforts to conduct operations.

Various federal agencies within the U.S. Department of the Interior, particularly the Bureau of Indian Affairs, along with each Native American tribe, regulate natural gas and oil operations on Native American tribal lands. In addition, each Native American tribe is a sovereign nation having the right to enforce laws and regulations and to grant approvals independent from federal, state and local statutes and regulations. These tribal laws and regulations include various taxes, fees, requirements to employ Native American tribal members and other conditions that apply to operators and contractors conducting operations on Native American tribal lands. Persons conducting operations on tribal lands are generally subject to the Native American tribal court system. In addition, if our relationships with any of the relevant Native American tribes were to deteriorate, we could face significant risks to our ability to continue operations on Native American tribal lands. One or more of these factors has in the past and may in the future increase our cost of doing business on Native American tribal lands and impact the viability of, or prevent or delay our ability to conduct our operations on such lands. For example, we are subject to ongoing litigation regarding trespass claims relating to a portion of the Tesoro High Plains Pipeline in North Dakota.

Our operations could be disrupted if we are unable to maintain or obtain real property rights required for our business.

We do not own all of the land on which our assets are located, but rather obtain the rights to construct and operate such assets on land owned by third parties and governmental agencies for a specific period of time. Therefore, we are subject to the

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possibility of more burdensome terms and increased costs to obtain and retain necessary land use if our leases, rights-of-way or other property rights lapse, terminate or are reduced or it is determined that we do not have valid leases, rights-of-way or other property rights. For example, a portion of the Tesoro High Plains Pipeline in North Dakota remains shut down following delays in renewing a right-of-way necessary for the operation of a section of the pipeline. Any loss of or reduction in these rights, including loss or reduction due to legal, governmental or other actions or difficulty renewing leases, right-of-way agreements or permits on satisfactory terms or at all, could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to our unitholders.

If foreign investment in us or our general partner exceeds certain levels, we could be prohibited from operating inland river vessels, which could materially and adversely affect our business, financial condition, results of operations and cash flows.

The Shipping Act of 1916 and Merchant Marine Act of 1920 (together, the “Maritime Laws”), generally require that vessels engaged in U.S. coastwise trade be owned by U.S. citizens. Among other requirements to establish citizenship, entities that own such vessels must be owned at least 75 percent by U.S. citizens. If we fail to maintain compliance with the Maritime Laws, we would be prohibited from operating vessels in the U.S. inland waters. Such a prohibition could materially and adversely affect our business, financial condition, results of operations and cash flows.

Some of our natural gas, NGL, crude oil and refined product pipelines are subject to FERC’s rate-making policies that could have an adverse impact on our ability to establish rates that would allow us to recover the full cost of operating our pipelines, plus a reasonable return.

A number of our pipelines provide interstate service that is subject to regulation by FERC. FERC prescribes rate methodologies for developing regulated tariff rates for these natural gas, interstate oil and products pipelines. FERC’s regulated tariff may not allow us to recover all of our costs of providing services. Changes in FERC’s approved rate methodologies, or challenges to our application of an approved methodology, could also adversely affect our rates. Additionally, shippers may protest (and FERC may investigate) the lawfulness of tariff rates. FERC can require refunds of amounts collected pursuant to rates that are ultimately found to be unlawful and prescribe new rates prospectively. Action by FERC could adversely affect our ability to establish reasonable rates that cover operating costs and allow for a reasonable return. An adverse determination in any future rate proceeding brought by or against us could have a material adverse effect on our business, financial condition and results of operations.

Pipelines and operations not subject to regulation by FERC may still be subject to regulation by various state agencies. The applicable statutes and regulations generally require that our rates and terms and conditions of service provide no more than a fair return on the aggregate value of the facilities used to render services and that we offer service to our shippers on a not unduly discriminatory basis. FERC rate cases can involve complex and expensive proceedings. For more information regarding regulatory matters that could affect our business, please read Item 1. Business – Regulatory Matters as set forth in this Annual Report on Form 10-K.

We may incur significant costs and liabilities resulting from performance of pipeline integrity programs and related repairs, and the expansion of pipeline safety laws and regulations could require us to use more comprehensive and stringent safety controls and subject us to increased capital and operating costs.

The DOT through the PHMSA has adopted regulations requiring pipeline operators to develop integrity management programs for gas transmission and hazardous liquids pipelines located where a leak or rupture could do the most harm. The regulations require the following of operators of covered pipelines to:

•perform ongoing assessments of pipeline integrity;

•identify and characterize applicable threats to pipeline segments that could impact a high consequence area;

•improve data collection, integration and analysis;

•repair and remediate the pipeline as necessary; and

•implement preventive and mitigating actions.

Some states have adopted regulations similar to existing PHMSA regulations for intrastate gathering and transmission lines. The adoption of additional laws or regulations that apply more comprehensive or stringent safety standards to gas, NGL, crude oil and refined product lines or other facilities, or the expansion of regulatory inspections by regulators, could require us to install new or modified safety controls, pursue added capital projects, make modifications or operational changes, or conduct maintenance programs on an accelerated basis, all of which could require us to incur increased capital and operational costs or operational delays that could be significant and have a material adverse effect on our business, financial position, results of operations, cash flows and our ability to make distributions to our unitholders.

Transaction Risks

If we are unable to make strategic acquisitions on economically acceptable terms from MPC or third parties, our ability to implement our business strategy may be impaired.

In addition to organic growth, a component of our business strategy can include the expansion of our operations through strategic acquisitions. If we are unable to make accretive strategic acquisitions from MPC or third parties that increase the cash

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generated from operations per unit, whether due to an inability to identify attractive acquisition candidates, to negotiate acceptable purchase contracts, or to obtain financing for these acquisitions on economically acceptable terms, then our ability to successfully implement our business strategy may be impaired.

Significant acquisitions, including the Northwind Midstream Acquisition and the BANGL Acquisition, will involve the integration of new assets or businesses and may present substantial risks that could adversely affect our business, financial conditions, results of operations and cash flows.

Significant acquisitions, including the Northwind Midstream Acquisition and the BANGL Acquisition, involving the addition of new assets or businesses will present risks, which may include, among others:

•inaccurate assumptions about future synergies, revenues, capital expenditures and operating costs;

•an inability to successfully integrate, or a delay in the successful integration of, assets or businesses we acquire;

•a decrease in our liquidity resulting from using a portion of our available cash or borrowing capacity under our revolving credit agreement to finance transactions;

•a significant increase in our interest expense or financial leverage if we incur additional debt to finance transactions;

•the assumption of unknown environmental and other liabilities, losses or costs for which we are not indemnified or for which our indemnity is inadequate;

•the diversion of management’s attention from other business concerns;

•the loss of customers or key employees from the acquired businesses; and

•the incurrence of other significant charges, such as impairment of goodwill or other intangible assets, asset devaluation or restructuring charges.

Risks Relating to the Business and Operations of MPC

MPC accounts for a substantial portion of our revenues. If MPC is unable to satisfy its obligations to us or significantly reduces the volumes transported through our facilities or stored at our storage assets, our revenues would decline and our financial condition, results of operations, cash flows, and ability to make distributions to our unitholders would be materially and adversely affected.

We derive a substantial portion of our revenues from MPC. Any event that materially and adversely affects MPC’s financial condition, results of operations or cash flows may adversely affect our ability to sustain or increase distributions to our unitholders. Accordingly, we are indirectly subject to the operational and business decisions and risks of MPC, which include the following:

•the timing and extent of changes in commodity prices and demand for MPC’s products, and the availability and costs of crude oil and other refinery feedstocks;

•a material decrease in the refining margins at MPC’s refineries;

•disruptions due to equipment interruption or failure at MPC’s facilities or at third-party facilities on which MPC’s business is dependent;

•any decision by MPC to temporarily or permanently alter, curtail or shut down operations at one or more of its refineries or other facilities and reduce or terminate its obligations under our transportation and storage or refining logistics and fuels distribution agreements;

•changes to the routing of volumes shipped by MPC on our crude oil and refined product pipelines or the ability of MPC to utilize third-party pipeline connections to access our pipelines;

•MPC’s ability to remain in compliance with the terms of its outstanding indebtedness;

•changes in the cost or availability of third-party pipelines, railways, vessels, terminals and other means of delivering and transporting crude oil, feedstocks, refined products, other hydrocarbon-based products and renewables;

•state and federal environmental, economic, health and safety, energy and other policies and regulations, and any changes in those policies and regulations;

•imposition of new economic sanctions against Russia or other countries and the effects of potential responsive countermeasures;

•environmental incidents and violations and related remediation costs, fines and other liabilities;

•operational hazards and other incidents at MPC’s refineries and other facilities, such as explosions and fires, that result in temporary or permanent shut downs of those refineries and facilities;

•changes in crude oil and refined product inventory levels and carrying costs; and

•disruptions due to hurricanes, tornadoes or other forces of nature.

MPC is not obligated to use our services with respect to volumes in excess of the minimum volume commitments under its agreements with us. If MPC satisfies only its minimum obligations under, or if we are unable to renew or extend, the transportation, terminal, fuels distribution, marketing and storage services agreements we have with MPC, or if MPC elects to

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use credits upon the expiration or termination of an agreement, our cash available for distribution will be materially and adversely affected.

In addition, significant stockholders of MPC may attempt to effect changes at MPC or acquire control of the company, which could impact MPC’s business strategies. Campaigns by stockholders to effect changes at publicly traded companies are sometimes led by investors seeking to increase short-term stockholder value through actions such as financial restructuring, increased debt, special dividends, stock repurchases or sales of assets or the entire company. As a result, stockholder campaigns at MPC could directly or indirectly adversely affect our results of operations and financial condition and our ability to sustain or increase distributions to our unitholders.

MPC may suspend, reduce or terminate its obligations under its agreements with us in some circumstances, which could have a material adverse effect on our financial condition, results of operations, cash flows and ability to make distributions to our unitholders.

Certain of our transportation, terminal, fuels distribution, marketing and storage services agreements with MPC include provisions that permit MPC to suspend, reduce or terminate its obligations under the applicable agreement if certain events occur. These events include a material breach of the applicable agreement by us, MPC being prevented from transporting its full minimum volume commitment because of capacity constraints on our pipelines, certain force majeure events that would prevent us from performing some or all of the required services under the applicable agreement and MPC’s determination to suspend refining operations at one of its refineries. MPC has the discretion to make such decisions notwithstanding the fact that they may significantly and adversely affect us. These actions could result in a suspension, reduction or termination of MPC’s obligations under one or more transportation and storage services agreements.

Any such reduction, suspension or termination of MPC’s obligations could have a material adverse effect on our financial condition, results of operations, cash flows and ability to make distributions to our unitholders.

MPC’s level of indebtedness, the terms of its borrowings and its credit ratings could adversely affect our ability to grow our business and our ability to make distributions to our unitholders. Our ability to obtain credit in the future may also be adversely affected by MPC’s credit rating.

MPC must devote a portion of its cash flows from operating activities to service its indebtedness, and therefore, cash flows may not be available for use in pursuing its growth strategy. Furthermore, a higher level of indebtedness at MPC in the future increases the risk that it may default on its obligations to us under our transportation and storage services agreements. As of December 31, 2025, MPC had consolidated long-term indebtedness of approximately $33.3 billion, of which $7.3 billion was a direct obligation of MPC or its subsidiaries other than MPLX or its consolidated subsidiaries. The covenants contained in the agreements governing MPC’s outstanding and future indebtedness may limit its ability to borrow additional funds for development and make certain investments and may directly or indirectly impact our operations in a similar manner.

Furthermore, if MPC were to default under certain of its debt obligations, there is a risk that MPC’s creditors would attempt to assert claims against our assets during the litigation of their claims against MPC. The defense of any such claims could be costly and could materially impact our financial condition, even absent any adverse determination. If these claims were successful, our ability to meet our obligations to our creditors, make distributions and finance our operations could be materially and adversely affected.

Rating agencies have in the past, and may in the future, change MPLX’s credit ratings or credit outlook following developments at MPC. If these ratings are lowered in the future, the interest rate and fees MPC pays on its credit facilities may increase. Credit rating agencies will likely consider MPC’s debt ratings when assigning ours because of MPC’s ownership interest in us, the significant commercial relationships between MPC and us, and our reliance on MPC for a portion of our revenues. If one or more credit rating agencies were to downgrade the outstanding indebtedness of us or MPC, we could experience an increase in our borrowing costs or difficulty accessing the capital markets. Such a development could adversely affect our business, financial positions, results of operations, cash flows and our ability to make distributions to our unitholders.

Tax Risks

Our tax treatment depends on our status as a partnership for federal income tax purposes as well as our not being subject to a material amount of entity level taxation by individual states. If the IRS were to treat us as a corporation for federal income tax purposes, or we become subject to a material amount of entity level taxation for state tax purposes, it would substantially reduce the amount of cash available for distribution to our unitholders.

The anticipated after-tax economic benefit of an investment in our common units depends largely on our being treated as a partnership for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the IRS on this.

A publicly traded partnership such as us may be treated as a corporation for federal income tax purposes unless it satisfies a “qualifying income” requirement. Based on our current operations, we believe that we are treated as a partnership rather than as a corporation for such purposes; however, a change in our business or a change in current law could cause us to be treated as a corporation for federal income tax purposes. The IRS may adopt positions that differ from the ones we take. A successful IRS contest of the federal income tax positions we take may adversely impact the market for our common units, and the costs of any IRS contest will reduce our cash available for distribution to unitholders.

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If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate, which is currently a maximum of 21 percent, and likely would pay state and local income tax at varying rates. Distributions to unitholders generally would be taxed again as corporate dividends, and no income, gains, losses, deductions, or credits would flow through to our unitholders. Treatment of us as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to our unitholders, likely causing a substantial reduction in the value of our common units. Changes in current state or local law may subject us to additional entity-level taxation by individual states and localities. For example, we are currently subject to state and local taxes in Texas and Tennessee and certain localities in Kentucky, Michigan and Ohio. Imposition of any such additional taxes on us may substantially reduce the cash available for distribution to unitholders.

Our Partnership Agreement provides that, if a law is enacted or an existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for federal, state or local income tax purposes, the minimum quarterly distribution amount and the target distribution amounts may be adjusted to reflect the impact of that law on us.

If the IRS contests the federal income tax positions we take, the market for our common units may be adversely impacted and the cost of any IRS contest will reduce our cash available for distribution.

The IRS has made no determination as to our status as a partnership for federal income tax purposes. The IRS may adopt positions that differ from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all the positions we take. A court may not agree with some or all of the positions we take. Any contest with the IRS may materially and adversely impact the market for our common units and the price at which they trade. In addition, our costs of any contest with the IRS will be borne indirectly by our unitholders and our general partner because the costs will reduce our cash available for distribution.

Our unitholders will be required to pay taxes on their share of income even if they do not receive any distributions from us.

Because our unitholders will be treated as partners to whom we will allocate taxable income that could be different in amount than the cash we distribute, our unitholders will be required to pay any federal income taxes and, in some cases, state and local income taxes on their share of our taxable income even if they receive no distributions from us. Our unitholders may not receive distributions from us equal to their share of our taxable income or even equal to the actual tax liability that result from that income.

Tax gain or loss on the disposition of our common units could be more or less than expected.

If our unitholders sell their common units, they will recognize gain or loss equal to the difference between the amount realized and their tax basis in those common units. Because distributions in excess of a unitholder’s allocable share of our net taxable income decrease the unitholder’s tax basis in their common units, the amount, if any, of such prior excess distributions with respect to their units will, in effect, increase taxable income to the unitholder. Furthermore, a substantial portion of the amount realized, whether or not representing gain, may be taxed as ordinary income due to potential recapture items, including depreciation recapture. In addition, because the amount realized includes a unitholder’s share of our non-recourse liabilities, if a unitholder sells units, the unitholder may incur taxable income in excess of the amount of cash received from the sale.

Tax-exempt entities face unique tax issues from owning our common units that may result in adverse tax consequences to them.

Investment in our common units by tax-exempt entities, such as employee benefit plans and individual retirement accounts (known as IRAs), raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. Furthermore, a tax-exempt entity’s gain on sale of common units may be treated, at least in part, as unrelated business taxable income. Tax-exempt entities should consult their tax advisor before investing in our common units.

Non-U.S. unitholders will be subject to United States taxes and withholding with respect to their income and gain from owning our units.

Non-U.S. unitholders are generally taxed and subject to income tax filing requirements by the United States on income effectively connected with a U.S. trade or business. All income allocated to our unitholders and any gain from the sale of our units will generally be considered to be “effectively connected” with a U.S. trade or business. As a result, all distributions to non-U.S. unitholders will be subject to withholding taxes at the highest applicable effective tax rate, and, in the event of a sale of our units by a non-U.S. unitholder, such non-U.S. unitholder will be subject to withholding taxes on all proceeds attributable to the sale of such units.

Furthermore, while non-U.S. unitholders are subject to additional withholding on distributions in excess of cumulative net income, we do not calculate cumulative net income for withholding purposes. Consequently, all of our distributions to non-U.S. unitholders will be subject to such additional withholding.

Non-U.S. unitholders will be required to file U.S. federal tax returns and pay tax on their share of our taxable income. Non-U.S. unitholders will also potentially have tax filings and payment obligations in additional jurisdictions.

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We treat each purchaser of common units as having the same tax benefits without regard to the actual units purchased. The IRS may challenge this treatment, which could adversely affect the value of the common units.

Because we cannot match transferors and transferees of common units and to enable the uniformity of the economic and tax characteristics of common units, we have adopted depreciation and amortization positions that may not conform to all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to our unitholders. It also could affect the timing of these tax benefits or the amount of gain from the sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to our unitholders’ tax returns.

Our unitholders will likely be subject to state and local taxes and return filing requirements in states where they do not live as a result of investing in our units.

In addition to federal income taxes, our unitholders will likely be subject to other taxes, including state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we do business or own property now or in the future, even if our unitholders do not live in any of those jurisdictions. Our unitholders will likely be required to file state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Further, our unitholders may be subject to penalties for failure to comply with those requirements. We currently conduct business in a substantial number of states, most of which currently impose a personal income tax and many of which impose an income tax on corporations and other entities. As we make acquisitions or expand our business, we may own assets or conduct business in additional states. It is our unitholders’ responsibility to file all U.S. federal, state and local tax returns.

We have adopted certain valuation methodologies that may result in a shift of income, gain, loss and deduction between our general partner and our unitholders. The IRS may challenge this treatment, which could adversely affect the value of the common units.

When we issue additional units or engage in certain other transactions, we must determine the fair market value of our assets and allocate any unrealized gain or loss attributable to our assets to the capital accounts of our unitholders and our general partner. Our methodology may be viewed as understating the value of our assets. In that case, there may be a shift of income, gain, loss and deduction between certain unitholders and the general partner, which may be unfavorable to such unitholders. Moreover, under our valuation methods, subsequent purchasers of common units may have a greater portion of their Internal Revenue Code Section 743(b) adjustment allocated to our tangible assets and a lesser portion allocated to our intangible assets. The IRS may challenge our valuation methods, our allocation of the Section 743(b) adjustment attributable to our tangible and intangible assets, or our allocations of income, gain, loss and deduction between our general partner and certain of our unitholders.

A successful IRS challenge to these methods or allocations could adversely affect the amount of taxable income or loss being allocated to our unitholders. It also could affect the amount of gain from our unitholders’ sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to our unitholders’ tax returns without the benefit of additional deductions.

A unitholder whose common units are the subject of a securities loan (e.g., a loan to a short seller) may be considered as having disposed of those common units. If so, the unitholder would no longer be treated for tax purposes as a partner with respect to those common units during the period of the loan and may recognize gain or loss from the disposition.

A unitholder whose common units are the subject of a securities loan (i) may be considered as having disposed of the loaned common units, (ii) may no longer be treated for tax purposes as a partner with respect to those common units during the period of the loan to the short seller and (iii) may recognize gain or loss from such disposition.

Moreover, during the period of the loan, any of our income, gain, loss or deduction with respect to those common units may not be reportable by the unitholder and any distributions received by the unitholder as to those common units could be fully taxable as ordinary income. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a securities loan are urged to consult a tax adviser to discuss whether it is advisable to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their common units.

The tax treatment of publicly traded partnerships or an investment in our units could be subject to potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis.

The present U.S. federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative or judicial interpretation at any time. From time to time, the President and members of the U.S. Congress propose and consider substantive changes to the existing U.S. federal income tax laws that would affect publicly traded partnerships, including proposals that would eliminate our ability to qualify for partnership tax treatment.

We are unable to predict whether any such changes will ultimately be enacted. Any modification to the U.S. federal income tax laws and interpretations thereof may or may not be applied retroactively and could make it more difficult or impossible to meet

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the exception for certain publicly traded partnerships to be treated as partnerships for U.S. federal income tax purposes or increase the amount of taxes payable by unitholders in publicly traded partnerships.

We generally prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our unitholders.

We generally prorate our items of income, gain, loss and deduction between existing unitholders and unitholders who purchase our units based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. Similarly, we generally allocate certain deductions for depreciation of capital additions, gain or loss realized on a sale or other disposition of our assets and, in the discretion of our general partner, any other extraordinary item of income, gain, loss or deduction based upon ownership on the allocation date. Treasury Regulations allow a similar monthly simplifying convention, but such regulations do not specifically authorize all aspects of the proration method we have adopted. If the IRS were to challenge our proration method or new Treasury Regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.

Unitholders may be subject to limitations on their ability to deduct interest expense we incur.

In general, we are entitled to a deduction for interest paid or accrued on indebtedness properly allocable to our trade or business during our taxable year. However, under the Tax Cuts and Jobs Act, for taxable years beginning after December 31, 2017, our deduction for “business interest” generally became limited to the sum of our business interest income and 30 percent of our “adjusted taxable income.” For the purposes of this limitation, our adjusted taxable income is computed without regard to any business interest expense or business interest income, and in the case of taxable years beginning before January 1, 2022, our adjusted taxable income was also computed without regard to any depreciation or amortization. The Tax Cuts and Jobs Act provided that for taxable years beginning on or after January 1, 2022, adjusted taxable income would need to be computed taking into account any depreciation or amortization for this purpose, but the One Big Beautiful Bill Act, passed on July 4, 2025, reversed this change, and we may again add back depreciation and amortization in computing adjusted taxable income.

If our “business interest” is subject to limitation under these rules, our unitholders will be limited in their ability to deduct their share of any interest expense that has been allocated to them in the current taxable year and may be limited in their ability to deduct such interest expense in a future taxable year. As a result, unitholders may be subject to limitation on their ability to deduct interest expense incurred by us.

If the IRS makes audit adjustments to our income tax returns for tax years beginning after 2017, it (and some states) may collect any resulting taxes (including any applicable penalties and interest) directly from us, in which case our cash available for distribution to our unitholders might be substantially reduced.

If the IRS makes audit adjustments to our income tax returns for tax years beginning after December 31, 2017, it (and some states) may collect any resulting taxes (including any applicable penalties and interest) directly from us. We will generally have certain limited rights to shift any such tax liability to our general partner and our unitholders in accordance with their interests in us during the year under audit, but there can be no assurance that we will be able to do so (or choose to do so) under all circumstances. As a result, our current unitholders may bear some or all of the tax liability resulting from such audit adjustment, even if such unitholders did not own units in us during the tax year under audit. If we are required to make payments of taxes, penalties and interest resulting from audit adjustments, our cash available for distribution to our unitholders might be reduced.

Common Unit Ownership Risks

Our general partner and its affiliates, including MPC, have conflicts of interest with us and limited duties to us and our unitholders, and they may favor their own interests to our detriment and that of our unitholders. Additionally, we have no control over MPC’s business decisions and operations, and MPC is under no obligation to adopt a business strategy that favors us.

MPC owned our general partner and approximately 64 percent of our outstanding common units as of February 20, 2026. Although our general partner has a duty to manage us in a manner that is not adverse to the best interests of our partnership,

conflicts of interest may arise between MPC and its affiliates, including our general partner, on the one hand, and us and our unitholders, on the other hand. In resolving these conflicts, the general partner may favor its own interests and the interests of its affiliates, including MPC, over the interests of our common unitholders, which may occur under our Partnership Agreement without being independently reviewed by the conflicts committee. These conflicts include, among others, the following situations:

•neither our Partnership Agreement nor any other agreement requires MPC to pursue a business strategy that favors us or utilizes our assets, which could involve decisions by MPC to increase or decrease refinery production, shut down or reconfigure a refinery, or pursue and grow particular markets;

•MPC’s directors and officers have a fiduciary duty to make decisions in the best interests of the stockholders of MPC;

•disputes may arise under agreements pursuant to which MPC and its affiliates are our customers;

•MPC may be constrained by the terms of its debt instruments from taking actions, or refraining from taking actions, that may be in our best interests;

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•except in limited circumstances, our general partner has the power and authority to conduct our business without unitholder approval;

•our general partner will determine the amount and timing of asset purchases and sales, borrowings, issuance of additional partnership securities and the creation, reduction or increase of cash reserves, each of which can affect the amount of cash that is distributed to our unitholders;

•our general partner will determine the amount and timing of many of our cash expenditures and whether a cash expenditure is classified as an expansion capital expenditure, which would not reduce operating surplus, or a maintenance capital expenditure, which would reduce our operating surplus. This determination can affect the amount of cash that is distributed to our unitholders, including MPC, and the amount of adjusted operating surplus generated in any given period;

•our general partner will determine which costs incurred by it are reimbursable by us and may cause us to pay it or its affiliates for any services rendered to us;

•our general partner may cause us to borrow funds in order to permit the payment of distributions;

•our Partnership Agreement permits us to classify up to $60 million as operating surplus, even if it is generated from asset sales, non-working capital borrowings or other sources that would otherwise constitute capital surplus. This cash may be used to fund distributions to our unitholders, including MPC;

•our Partnership Agreement does not restrict our general partner from entering into additional contractual arrangements with it or its affiliates on our behalf;

•our general partner intends to limit its liability regarding our contractual and other obligations;

•our general partner may exercise its right to call and purchase all of the common units not owned by it and its affiliates if it and its affiliates own more than 85 percent of the common units;

•our general partner controls the enforcement of obligations owed to us by our general partner and its affiliates, including our transportation and storage services agreements with MPC; and

•our general partner decides whether to retain separate counsel, accountants or others to perform services for us.

Under the terms of our Partnership Agreement, the doctrine of corporate opportunity, or any analogous doctrine, does not apply to our general partner or any of its affiliates, including its executive officers, directors and owners.

Any such person or entity that becomes aware of a potential transaction, agreement, arrangement or other matter that may be an opportunity for us will not have any duty to communicate or offer such opportunity to us. Any such person or entity will not be liable to us or to any limited partner for breach of any fiduciary duty or other duty by reason of the fact that such person or entity pursues or acquires such opportunity for itself, directs such opportunity to another person or entity or does not communicate such opportunity or information to us. This may create actual and potential conflicts of interest between us and affiliates of our general partner and result in less than favorable treatment of us and our unitholders.

Our Partnership Agreement requires that we distribute all of our available cash, which could limit our ability to grow and make acquisitions.

Our Partnership Agreement requires that we distribute all of our available cash to our unitholders. As a result, we may require external financing sources, including commercial bank borrowings and the issuance of debt and equity securities, to fund our acquisitions and expansion capital expenditures. Therefore, to the extent we are unable to finance our growth externally, our cash distribution policy will significantly impair our ability to grow. In addition, because we will distribute all of our available cash, our growth may not be as fast as that of businesses that reinvest their available cash to expand ongoing operations. To the extent we issue additional units in connection with any acquisitions or expansion capital expenditures, the payment of distributions on those additional units may increase the risk that we will be unable to maintain or increase our per unit distribution level. The incurrence of additional commercial borrowings or other debt to finance our growth strategy would result in increased interest expense, which, in turn, may reduce the amount of cash available to distribute to our unitholders.

Our Partnership Agreement replaces our general partner’s fiduciary duties to holders of our common units with contractual standards governing its duties and restricts the remedies available to unitholders for actions taken by our general partner.

Our Partnership Agreement contains provisions that eliminate the fiduciary standards to which our general partner would otherwise be held by state fiduciary duty law and replaces those duties with several different contractual standards. For example, our Partnership Agreement permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner, free of any duties to us and our unitholders other than the implied contractual covenant of good faith and fair dealing. Our general partner is entitled to consider only the interests and factors that it desires and is relieved of any duty or obligation to give consideration to any interest of, or factors affecting, us, our affiliates or our limited partners.

Our Partnership Agreement contains provisions that restrict the remedies available to unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty under state fiduciary duty law. For example, our Partnership Agreement:

•provides that whenever our general partner makes a determination or takes, or declines to take, any other action in its capacity as our general partner, our general partner is required to make such determination, or take or decline to take

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such other action, in good faith and will not be subject to any other or different standard imposed by our Partnership Agreement, Delaware law, or any other law, rule or regulation, or at equity;

•provides that our general partner will not have any liability to us or our unitholders for decisions made in its capacity as a general partner so long as it acted in good faith;

•provides that our general partner and its officers and directors will not be liable for monetary damages to us or our limited partners resulting from any act or omission unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that our general partner or its officers and directors, as the case may be, acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was criminal; and

•provides that our general partner will not be in breach of its obligations under our Partnership Agreement or any of its duties to us or our limited partners if a transaction with an affiliate or the resolution of a conflict of interest is approved in accordance with, or otherwise meets the standards set forth in, our Partnership Agreement.

In connection with a transaction with an affiliate or a conflict of interest, our Partnership Agreement provides that any determination by our general partner must be made in good faith, and that our conflicts committee and the board of directors of our general partner are entitled to a presumption that they acted in good faith. In any proceeding brought by or on behalf of any limited partner or the partnership, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. By purchasing a common unit, a unitholder is treated as having consented to the provisions in our Partnership Agreement, including the provisions discussed above.

Unitholders have very limited voting rights and, even if they are dissatisfied, they have limited ability to remove our general partner without its consent.

Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Unitholders did not elect our general partner or the board of directors of our general partner and will have no right to elect our general partner or the board of directors of our general partner on an annual or other continuing basis. The board of directors of our general partner is chosen by the members of our general partner, which are wholly owned subsidiaries of MPC. Furthermore, if the unitholders are dissatisfied with the performance of our general partner, they will have little ability to remove our general partner. The vote of the holders of at least 66 2/3 percent of all outstanding common units voting together as a single class is required to remove our general partner. As of February 20, 2026, our general partner and its affiliates owned approximately 64 percent of the outstanding common units (excluding common units held by officers and directors of our general partner and MPC). As a result of these limitations, the price at which our common units will trade could be diminished because of the absence or reduction of a takeover premium in the trading price.

Furthermore, unitholders’ voting rights are further restricted by the Partnership Agreement provision providing that any units held by a person that owns 20 percent or more of any class of units then outstanding, other than our general partner, its affiliates, their transferees, and persons who acquired such units with the prior approval of the board of directors of our general partner, cannot vote on any matter.

Our Partnership Agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting the unitholders’ ability to influence the manner or direction of management.

If unitholders are not both citizenship-eligible holders and rate-eligible holders, their common units may be subject to redemption.

In order to avoid (1) any material adverse effect on the maximum applicable rates that can be charged to customers by our subsidiaries on assets that are subject to rate regulation by the FERC or analogous regulatory body and (2) any substantial risk of cancellation or forfeiture of any property, including any governmental permit, endorsement or other authorization, in which we have an interest, we have adopted certain requirements regarding those investors who may own our common units. Citizenship eligible holders are individuals or entities whose nationality, citizenship or other related status does not create a substantial risk of cancellation or forfeiture of any property, including any governmental permit, endorsement or authorization, in which we have an interest, and will generally include individuals and entities who are U.S. citizens. Rate-eligible holders are individuals or entities subject to U.S. federal income taxation on the income generated by us or entities not subject to U.S. federal income taxation on the income generated by us, so long as all of the entity’s owners are subject to such taxation. If unitholders are not persons who meet the requirements to be citizenship-eligible holders and rate-eligible holders, they run the risk of having their units redeemed by us at the market price as of the date three days before the date the notice of redemption is mailed. The redemption price will be paid in cash or by delivery of a promissory note, as determined by our general partner. In addition, if unitholders are not persons who meet the requirements to be citizenship eligible holders, they will not be entitled to voting rights.

Cost reimbursements, which will be determined in our general partner’s sole discretion, and fees due our general partner and its affiliates for services provided will be substantial and will reduce our cash available for distribution.

Under our Partnership Agreement, we are required to reimburse our general partner and its affiliates for all costs and expenses that they incur on our behalf for managing and controlling our business and operations. Except to the extent specified under our omnibus agreements or our employee services agreements, our general partner determines the amount of these expenses.

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Under the terms of the omnibus agreements, we will be required to reimburse MPC for the provision of certain general and administrative services to us. Under the terms of our employee services agreements, we have agreed to reimburse MPC or its affiliates for the provision of certain operational and management services to us in support of our facilities. Our general partner and its affiliates also may provide us other services for which we will be charged fees as determined by our general partner. Payments to our general partner and its affiliates are substantial and reduce the amount of cash available for distribution to unitholders.

The control of our general partner may be transferred to a third party without unitholder consent.

There is no restriction in our Partnership Agreement on the ability of MPC to transfer its membership interest in our general partner to a third party. The new members of our general partner would then be in a position to replace the board of directors and officers of our general partner with their own choices and to control the decisions taken by our general partner.

We may issue additional units without unitholder approval, which will dilute limited unitholder interests.

At any time, we may issue an unlimited number of limited partner interests of any type, including limited partner interests that are convertible into our common units, without the approval of our unitholders and our unitholders will have no preemptive or other rights (solely as a result of their status as unitholders) to purchase any such limited partner interests. Further, neither our Partnership Agreement nor our bank revolving credit facility prohibits the issuance of additional preferred units, or other equity securities that may effectively rank senior to our common units as to distributions or liquidations. The issuance by us of additional common units, preferred units or other equity securities of equal or senior rank will have the following effects:

•our unitholders’ proportionate ownership interest in us will decrease;

•it may be more difficult to maintain or increase our distributions to unitholders, and the amount of cash available for distribution on each unit may decrease;

•the ratio of taxable income to distributions may increase;

•the relative voting strength of each previously outstanding unit may be diminished; and

•the market price of our common units may decline.

MPC may sell units in the public or private markets, and such sales could have an adverse impact on the trading price of the common units.

As of February 20, 2026, MPC held 647,415,452 common units. Additionally, we have agreed to provide MPC with certain registration rights. The sale of these units in the public or private markets could have an adverse impact on the price of the common units or on any trading market that may develop.

Affiliates of our general partner, including MPC, may compete with us, and neither our general partner nor its affiliates have any obligation to present business opportunities to us.

MPC and other affiliates of our general partner are not prohibited from owning assets or engaging in businesses that compete directly or indirectly with us. In addition, MPC and other affiliates of our general partner may acquire, construct or dispose of additional midstream assets in the future without any obligation to offer us the opportunity to purchase any of those assets. As a result, competition from MPC and other affiliates of our general partner could materially and adversely impact our results of operations and cash available for distribution to unitholders.

Our general partner has a limited call right that may require unitholders to sell common units at an undesirable time or price.

If at any time our general partner and its affiliates own more than 85 percent of our common units, our general partner will have the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price not less than their then current market price. As a result, unitholders may be required to sell their common units at an undesirable time or price and may not receive any return on their investment. Unitholders may also incur a tax liability upon a sale of such units.

A unitholder’s liability may not be limited if a court finds that unitholder action constitutes control of our business.

A general partner of a partnership generally has unlimited liability for the obligations of the partnership, except for those contractual obligations of the partnership that are expressly made non-recourse to the general partner. Our partnership is organized under Delaware law, and we conduct business in a number of other states. The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some jurisdictions. A unitholder could be liable for our obligations as if they were a general partner if a court or government agency were to determine that:

•we were conducting business in a state but had not complied with that particular state’s partnership statute; or

•a unitholder’s right to act with other unitholders to remove or replace the general partner, to approve some amendments to our Partnership Agreement or to take other actions under our Partnership Agreement constitute “control” of our business.

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Unitholders may have to repay distributions that were wrongfully distributed to them.

Under certain circumstances, unitholders may have to repay amounts wrongfully distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, we may not make a distribution to unitholders if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of the impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. Transferees of common units are liable for the obligations of the transferor to make contributions to the partnership that are known to the transferee at the time of the transfer and for unknown obligations if the liabilities could be determined from our Partnership Agreement. Liabilities to partners on account of their partnership interest and liabilities that are non-recourse to the partnership are not counted for purposes of determining whether a distribution is permitted.

The NYSE does not require a publicly traded limited partnership like us to comply with certain of its corporate governance requirements.

We list our common units on the NYSE. Because we are a publicly traded limited partnership, the NYSE does not require us to have a majority of independent directors on our general partner’s board of directors or to establish a compensation committee or a nominating and corporate governance committee. Accordingly, unitholders will not have the same protections afforded to certain corporations that are subject to all of the NYSE corporate governance requirements.

The Court of Chancery of the State of Delaware will be, to the extent permitted by law, the sole and exclusive forum for substantially all disputes between us and our limited partners.

Our limited partnership agreement provides that the Court of Chancery of the State of Delaware will be the sole and exclusive forum for any claims, actions or proceedings:

•arising out of or relating in any way to our limited partnership agreement, or the rights or powers of, or restrictions on, our limited partners or the limited partnership;

•brought in a derivative manner on behalf of the limited partnership;

•asserting a claim of breach of a duty owed by any director, officer, or other employee of the limited partnership or the general partner, or owed by the general partner, to the partnership or the limited partners;

•asserting a claim arising pursuant to any provision of the Delaware Revised Uniform Limited Partnership Act; or

•asserting a claim governed by the internal affairs doctrine.

The forum selection provision may restrict a limited partner's ability to bring a claim against us or directors, officers or other employee of ours or our general partner in a forum that it finds favorable, which may discourage limited partners from bringing such claims at all. Alternatively, if a court were to find the forum selection provision contained in our limited partnership agreement to be inapplicable or unenforceable in an action, we may incur additional costs associated with resolving such action in another forum, which could materially adversely affect our business, financial condition and results of operations. However, the forum selection provision does not apply to any claims, actions or proceedings arising under the Securities Act or the Exchange Act.

Item 1B. Unresolved Staff Comments

None.

Item 1C. Cybersecurity

We are managed and operated by the board of directors and executive officers of MPLX GP, our general partner and a wholly owned subsidiary of MPC. Our general partner has the sole responsibility for providing the employees and other personnel necessary to conduct our operations, including processes for the assessment, identification and management of material risks from cybersecurity threats.

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Risk Management and Strategy

MPC has processes in place designed to protect our information systems, data, assets, infrastructure and computing environments from cybersecurity threats and risks while maintaining confidentiality, integrity, and availability. These enterprise-wide processes are based upon policies, practices and standards that guide MPC on identifying, assessing, and managing material risks from cybersecurity threats and include, but are not limited to:

•placing security limits on physical and network access to our information technology (“IT”) and operating technology (“OT”) systems;

•employing internal IT and OT controls designed to detect cybersecurity threats by collecting and analyzing data in MPC’s centralized cybersecurity operations center;

•utilizing layers of defensive methodologies designed to facilitate cyber resilience, minimize attack surfaces, and provide flexibility and scalability in MPC’s ability to address cybersecurity risks and threats;

•providing cybersecurity threat and awareness training to employees and contractors;

•limiting remote network access to our IT and OT network environments; and

•assessing our cybersecurity resiliency through various methods, including penetration testing, tabletop exercises with varying scenarios and participants ranging from individuals on our operations teams to executive leadership, and analyzing our corporate cybersecurity incident response plan.

MPC applies an enterprise risk management (“ERM”) methodology as established and led by the MPC and MPLX GP executive leadership team and overseen by the Board to identify, assess, and manage enterprise-level risks. MPC’s cybersecurity risk program directly integrates and is intended to align with MPC’s governing ERM program.

MPC engages with external resources to contribute to and provide independent evaluation of its cybersecurity practices, including a periodic assessment of its cybersecurity program that is performed by a third party. MPC’s cybersecurity leadership and operational teams monitor cybersecurity threat intelligence and applicable cybersecurity regulatory requirements in a variety of ways, including by communicating with federal agencies, trade associations, service providers, and other miscellaneous third-party resources. MPLX GP’s management team, through consultation with MPC’s Senior Vice President and Chief Digital Officer (“CDO”), Vice President and Chief Information Security Officer (“CISO”), and the MPLX GP Audit Committee of the MPLX GP Board, use the information gathered from these sources to inform long-term cybersecurity investments and strategies which seek to identify cybersecurity threats and protect against, detect, respond to and recover from cybersecurity incidents.

The information systems, data, assets, infrastructure, and computing environments of MPC’s third-party service providers are also at risk of cybersecurity incidents. MPC manages third-party service provider cybersecurity risks through contract management, evaluation of applicable security control assessments, and third-party risk assessment processes.

As of February 26, 2026, we do not believe that any risks from cybersecurity threats, including as a result of past cybersecurity incidents have had, or are reasonably likely to have, a material adverse effect on the Partnership, including our business strategy, results of operations, or financial condition. However, there can be no assurance that MPC’s cybersecurity processes will prevent or mitigate cybersecurity incidents or threats and that efforts will always be successful. It is possible that cybersecurity incidents may occur and could have a material adverse effect on our business strategy, results of operations, or financial condition. See “Business and Operational Risks--We are increasingly dependent on the performance of our information technology systems and those of our third-party business partners and service providers” in Item 1A. Risk Factors of this Annual Report on Form 10-K.

Governance

The full Board of Directors of MPLX GP oversees enterprise-level risks and in conjunction with the Audit Committee of the MPLX GP Board oversees risks from cybersecurity threats as informed through MPC’s ERM program. MPC’s CDO and CISO are standing members of the ERM committee, comprised of members of senior management, and as part of the committee, report on and evaluate cybersecurity threats and risk management efforts, as communicated to them by way of their direct reports and the larger cybersecurity team. The MPC CDO and CISO are responsible for assessing and managing risks from cybersecurity threats. The CDO and CISO provide regular cybersecurity briefings to the MPLX GP Board of Directors including the MPLX GP Audit Committee, with a minimum of two briefings per year and additional briefings as needed. The MPLX GP Audit Committee also has direct access to the CDO and CISO and their management teams for other updates on cybersecurity and information security strategy throughout the year. Additionally, the CDO and CISO, from time to time, meet with members of management to discuss cybersecurity risks, strategy and threats.

MPC’s CISO is responsible for implementing the cybersecurity program which is comprised of Cybersecurity GRC (Governance, Risk & Compliance), Cybersecurity Architecture, Engineering & Operations, and a Cyber Fusion Center that includes Threat Intelligence, Vulnerability Management, & Incident Response. MPC’s CISO has more than 30 years of experience in the oil and gas industry and has held various leadership and strategic roles related to information security and related technology, including collectively serving as a chief information security officer for seven years at two publicly traded companies. Its CISO also holds an Executive Master in Cybersecurity degree and a Master of Computer Science degree.

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MPC’s CISO works at the direction of MPC’s CDO, who has more than 20 years of executive IT leadership experience and leads the company’s Digital and Information Technology functions that seek to provide innovative, secure, and reliable technology products and services to MPC and its customers. Prior to joining MPC in 2021, its CDO was employed by General Electric Company (“GE”) and its subsidiary companies for over 20 years, holding several executive IT leadership roles with increasing responsibility. He was then named Senior Vice President and Chief Information Officer of Services for parent company GE in 2017 and was later named the Vice President and Chief Information Officer of GE Healthcare. MPC’s CDO holds a Bachelor’s degree in Business Administration, Management and Information Systems.

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Item 2. Properties

CRUDE OIL AND PRODUCTS LOGISTICS

Crude Oil and Refined Product Pipelines

Our crude oil pipeline and related assets are strategically positioned to support diverse and flexible crude oil supply options for MPC’s refineries, which receive imported and domestic crude oil through a variety of sources. Imported and domestic crude oil is transported to supply hubs from a variety of regions, including: Cushing, Oklahoma; Western Canada; Wyoming; North Dakota; the Gulf Coast and Patoka, Illinois. Crude oil pipelines from the Delaware and Midland Basins, as well as from the Bakken region transport crude oil into major regional takeaway pipelines and refining centers. Our major crude oil pipelines are connected to these supply hubs and transport crude oil to refineries owned by MPC and third parties.

Our product pipelines are strategically positioned to transport products from certain MPC refineries to MPC and MPLX operations, as well as those of third parties. Our product pipelines are integrated with MPC’s and MPLX’s expansive network of refined product terminals, which support MPC’s integrated business.

The following table sets forth information regarding our crude oil and refined product pipeline systems as of December 31, 2025.

Diameter

Length
(miles)

Crude Systems(1)

2" - 42"

5,259

Refined Product Systems(2)

4" - 36"

3,787

(1) Includes approximately 16 miles of pipeline leased from third parties and 1,168 miles of inactive pipeline.

(2) Includes approximately 2 miles of pipeline leased from third parties, 197 miles of inactive refined product pipeline, 87 miles in which we have partial ownership of 65 percent and 17 miles in which we have partial ownership of 50 percent.

The following table sets forth information regarding the pipeline systems which we have an interest in through ownership of our equity method investments as of December 31, 2025.


	Diameter	Length (miles)	Ownership Percentage
Crude Systems:
MarEn Bakken Company LLC(1)	30"	1,916	25%
Minnesota Pipe Line Company LLC	16" - 24"	975	17%
W2W Holdings LLC(2)	24” - 36”	652	50%
Illinois Extension Pipeline Company LLC	24"	168	35%
Andeavor Logistics Rio Pipeline LLC	12"	119	67%
LOCAP LLC	48"	57	59%
LOOP LLC(3)	48"	48	41%
Refined Product Systems:
Explorer Pipeline Company	10" - 28"	1,872	25%

(1) The investment in MarEn Bakken Company LLC includes our 9.19 percent indirect interest in a joint venture that owns and operates the Dakota Access Pipeline and Energy Transfer Crude Oil Pipeline projects (collectively referred to as the “Bakken Pipeline system”).

(2) The investment in W2W Holdings LLC includes our 16 percent indirect interest in Wink to Webster Pipeline LLC.

(3) LOOP LLC also includes the Louisiana Offshore Oil Port, a deepwater offloading crude oil port, as well as temporary crude oil storage.

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Terminal Assets

The following table sets forth certain information regarding our owned and operated terminals as of December 31, 2025.


Owned and Operated Terminals	Number of Terminals	Tank Shell Capacity (mbbls)	Number of Tanks
Refined Product Terminals:
Alabama	2	443	16
Alaska	3	1,536	35
California	8	3,472	56
Florida	3	2,265	48
Georgia	4	952	28
Idaho	3	1,020	51
Illinois	2	562	15
Indiana	7	3,689	67
Kentucky	6	2,606	57
Louisiana	2	5,469	53
Michigan	8	2,440	73
Minnesota	1	13	5
New Mexico	2	467	20
North Carolina(1)	3	1,343	26
North Dakota	1	—	—
Ohio	12	3,132	99
Pennsylvania	1	390	12
South Carolina	1	371	8
Tennessee	4	1,148	30
Texas	1	76	15
Utah	1	41	3
Washington	4	920	25
West Virginia	2	1,564	24
Total Refined Product Terminals	81	33,919	766
Asphalt Terminals:
Arizona	3	558	53
Minnesota	1	—	—
Nevada(2)	1	274	19
New Mexico	1	36	6
Texas	1	206	22
Total Asphalt Terminals	7	1,074	100
Total Terminals	88	34,993	866

(1) MPLX also has partial ownership interest in one terminal with a tank shell capacity of 415 mbbls, of which MPLX is not the operator.

(2) This terminal is accounted for as an equity method investment.

Marine Assets

The following table sets forth certain information regarding our marine assets in operation as of December 31, 2025. The marine business currently has an associated transportation service agreement with MPC.

Marine Vessels

Number of Boats and Barges

Capacity
(mbbls)

Inland tank barges

320

8,655

Inland towboats

N/A

Our fleet of boats and barges transport light products, heavy oils, crude oil, renewable fuels, chemicals and feedstocks to and from refineries and terminals owned by MPC in the Mid-Continent and Gulf Coast regions. We also have a marine repair facility (“MRF”), which is a full-service marine shipyard, located on the Ohio River, adjacent to MPC’s Catlettsburg, Kentucky refinery. The MRF is responsible for the preventive routine and unplanned maintenance of towboats, barges and local terminal facilities.

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Refining Logistics Assets

The following table outlines the tankage owned by us, serving MPC’s refineries as of December 31, 2025. We also own and operate rail and truck racks and docks at certain of these refineries. Each of the following assets are currently included in storage services agreements with MPC.


Refining Logistics Assets						Tank Capacity (mbbls)
Galveston Bay, Texas City, Texas						19,206
Garyville, Louisiana						17,419
Los Angeles, California						14,176
Robinson, Illinois						6,859
Anacortes, Washington						5,448
Catlettsburg, Kentucky						5,085
El Paso, Texas						5,084
Detroit, Michigan						5,013
St. Paul Park, Minnesota						3,983
Kenai, Alaska						3,488
Mandan, North Dakota						3,059
Canton, Ohio						2,684
Salt Lake City, Utah						2,139
Total						93,643

Additionally, MPLX owns refining logistics assets at MPC’s Martinez Renewable Fuels joint venture with 5,914 mbbls of associated storage capacity, and has entered into terminalling and storage service agreements with the joint venture and its partners to provide services for the facility.

Other Crude Oil and Products Logistics Assets

MPLX owns and operates various other midstream assets, including 31 barge docks with a total capacity of 5,104 mbpd and eight storage caverns with a storage capacity of 3,632 mbbls. As of December 31, 2025, in addition to the storage tanks at MPC’s refineries, we operated 32 tank farms, including one leased tank farm, with total available storage capacity of 35,456 mbbls. Our operations also include a renewable fuels rail loading hub in North Dakota with 180 mbbls of storage capacity and more than 200 miles of water pipeline systems, primarily in North Dakota and the Four Corners region, dedicated to gathering and handling produced water associated with well completion and production activities. These assets each currently have associated service agreements with MPC or third parties.

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NATURAL GAS AND NGL SERVICES

The following tables set forth certain information relating to our consolidated and operated joint venture natural gas gathering systems, gas processing facilities, fractionation facilities and NGL pipelines for the year ended December 31, 2025. See further discussion about our joint ventures in Item 8. Financial Statements and Supplementary Data – Note 5.

Natural Gas Gathering Systems


Region	Design Throughput Capacity (MMcf/d)	Natural Gas Throughput(1) (MMcf/d)	Utilization of Design Capacity(1)
Marcellus Operations	1,823	1,526	89	%
Utica Operations	3,923	2,672	68	%
Southwest Operations	3,445	1,826	56	%
Bakken Operations	239	160	67	%
Total Natural Gas Gathering	9,430	6,184	68	%

(1) Natural gas throughput is the average daily rate based on calendar days, irrespective of days in operation. The utilization of design capacity has been calculated using the weighted average design throughput capacity.

Gas Processing Complexes


Region	Design Throughput Capacity (MMcf/d)	Natural Gas Throughput(1) (MMcf/d)	Utilization of Design Capacity(1)
Marcellus Operations	6,520	6,123	94	%
Utica Operations	1,325	961	73	%
Southwest Operations(2)(3)	2,745	1,904	69	%
Southern Appalachia Operations	425	191	45	%
Bakken Operations(4)	185	159	86	%
Total Gas Processing	11,200	9,338	83	%

(2) The capacity presented above includes our proportionate share of Centrahoma Processing LLC’s processing capacity of 550 MMcf/d, as we own a non-operating 40 percent interest in this joint venture. Actual throughput of 99 MMcf/d, representing our share of processed volumes, is also included and used to compute the utilization presented above.

(3) The amounts presented above exclude Northwind Midstream design throughput capacity and treated volumes.

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

Fractionation Facilities


Region	Design Throughput Capacity (mbpd)	NGL Throughput(1) (mbpd)	Utilization of Design Capacity(1)
Marcellus Operations(2)(3)	413	343	83	%
Utica Operations(2)(3)(4)	—	—	—	%
Southern Appalachia Operations(5)	24	11	46	%

Bakken Operations	33	14	42	%
Total C3+ Fractionation	470	368	78	%

(1) NGL throughput is the average daily rate based on calendar days, irrespective of days in operation. The utilization of design capacity has been calculated using the weighted average design throughput capacity.

(2) Certain complexes have above-ground NGL storage with a usable capacity of 1,333 thousand barrels.

(3) Entities within the Marcellus and Utica Operations jointly own the Hopedale fractionation complex. Hopedale throughput is included in the Marcellus Operations totals for purposes of utilization calculations. During the year ended December 31, 2025, the Marcellus Operations and Utica Operations accounted for approximately 83 percent and 17 percent of total throughput at the Hopedale fractionation complex, respectively. Actual throughput presented within Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations for Marcellus and Utica Operations includes each region’s actual utilization of the complex.

(4) We own and operate a condensate stabilization facility with a capacity of 23 mbpd and 179 thousand barrels of condensate storage. Actual NGL throughput at this facility was 15 mbpd for the year ended December 31, 2025.

(5) This region includes complexes with both above-ground, pressurized NGL storage facilities with usable capacity of 48 thousand barrels, and underground storage facilities with usable capacity of 238 thousand barrels.

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De-ethanization Facilities


Region	Design Throughput Capacity (mbpd)	NGL Throughput(1) (mbpd)	Utilization of Design Capacity(1)
Marcellus Operations	309	267	86	%
Utica Operations	40	21	53	%

Total De-ethanization	349	288	83	%

NGL Pipelines


Region	Diameter	Length (miles)	Throughput(1) (mbpd)
Marcellus Operations	6" - 20"	442	457
Utica Operations	4" - 20"	185	65
Southwest Operations(2)	4" - 20"	530	180
Southern Appalachia Operations	6" - 8"	140	11
Bakken Operations	6" - 12"	104	14
Total NGL Pipelines		1,401	727

(1) NGL throughput is the average daily rate based on calendar days, irrespective of days in operation.

(2) Includes the BANGL Pipeline system, which also owns a 50 percent undivided joint interest in a 323 mile NGL pipeline.

Other Natural Gas and NGL Services Assets

In addition to the MPLX-operated equity method investments included in the above tables, we also have ownership interests in natural gas and NGL pipeline systems through the following entities:

Diameter

Length
(miles)

Ownership Percentage

Natural Gas Pipelines:

Delaware Basin Residue, LLC(1)

10" - 42"

298

10%

MXP Parent, LLC(2)

36" - 42"

580

10%

WPC Parent, LLC(3)

36" - 42"

541

30%

NGL Pipelines:

Panola Pipeline Company, LLC

8" - 20"

253

15%

(1) Includes Agua Blanca Pipeline and Carlsbad Gateway Pipeline.

(2) Includes Matterhorn Express Pipeline.

(3) Includes our indirect interest in Whistler Pipeline as well as our 70 percent indirect ownership in the ADCC Pipeline lateral. Also includes our 50 percent indirect interest in Waha Gas Storage, which primarily owns natural gas storage facilities.

Title to Properties

We believe that our properties and facilities are adequate for our operations and that our facilities are adequately maintained. Substantially all of our pipelines are constructed on rights-of-way granted by the apparent record owners of the property. In many instances, lands over which pipeline rights-of-way have been obtained may be subject to prior liens that have not been subordinated to the right-of-way grants, as well as potential conflicts with other mineral or surface use owners. We have obtained, where determined necessary, permits, leases, license agreements and franchise ordinances from public authorities to cross over or under, or to lay facilities in or along water courses, county roads, municipal streets and state highways, as applicable. We also have obtained easements and license agreements from railroad companies to cross over or under railroad properties or rights-of-way. Some of the property rights we have obtained are revocable at the election of the grantor. In addition, we lease vehicles, building spaces and pipeline equipment under long-term operating leases, most of which include renewal options. Many of our compression, processing, fractionation and other facilities, including certain fractionation plants and certain of our pipelines and other facilities, are on land that we either own in fee or that is held under long-term leases. For any such facilities that are on land that we lease, we could be required to remove our facilities upon the termination or expiration of the leases.

Some of the leases, easements, rights-of-way, permits, licenses and franchise ordinances that were transferred to us required the consent of the then-current landowner to transfer these rights, which in some instances was a governmental entity. We believe that we have obtained sufficient third-party consents, permits and authorizations for the transfer of the assets necessary for us to operate our business. We also believe we have satisfactory title or other right to our material land assets. Title to these properties is subject to encumbrances in some cases, such as coal, that may require payment to other holders of title in the property at issue; however, we believe that none of these burdens will materially detract from the value of these properties or

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from our interest in these properties, or will materially interfere with their use in the operation of our business. See Item 8. Financial Statements and Supplementary Data – Note 21, for additional information regarding our leases.

MPC indemnifies us for certain title defects and for failures to obtain certain consents and permits necessary to conduct our business with respect to the assets contributed to us by MPC. Although title to these properties is subject to encumbrances in some cases, such as customary interests generally retained in connection with acquisition of real property, liens that can be imposed in some jurisdictions for government-initiated action to clean up environmental contamination, liens for current taxes and other burdens, and easements, restrictions and other encumbrances to which the underlying properties were subject at the time of acquisition. We believe that none of these burdens should materially detract from the value of these properties or from our interest in these properties or should materially interfere with their use in the operation of our business.

Item 3. Legal Proceedings

We are the subject of, or a party to, a number of pending or threatened legal actions, contingencies and commitments involving a variety of matters, including laws and regulations relating to the environment. While it is possible that an adverse result in one or more of the lawsuits or proceedings in which we are a defendant could be material to us, based upon current information and our experience as a defendant in other matters, we believe that these lawsuits and proceedings, individually or in the aggregate, will not have a material adverse effect on our consolidated results of operations, financial position or cash flows.

See “Tesoro High Plains Pipeline” and “Dakota Access Pipeline” of Note 22 in Item 8. Financial Statements and Supplementary Data for additional information regarding Legal Proceedings and other regulatory matters.

ENVIRONMENTAL ENFORCEMENT MATTERS

Item 103 of Regulation S-K promulgated by the SEC requires disclosure of certain environmental matters when a governmental authority is a party to the proceedings and such proceedings involve potential monetary sanctions, unless we reasonably believe that the matter will result in no monetary sanctions, or in monetary sanctions, exclusive of interest and costs, of less than a specified threshold. We use a threshold of $1 million for this purpose.

In March 2022, the State of Illinois brought an action in Madison County Circuit Court in Illinois against Marathon Pipe Line LLC, an indirect wholly owned subsidiary of MPLX, asserting various violations and demanding a permanent injunction and civil penalties in connection with a release of crude oil on the Wood River to Patoka 22-inch line near Edwardsville, Illinois. In September 2023, the U.S. Department of Justice and the EPA confirmed they will be pursuing federal enforcement for alleged Clean Water Act violations arising from this incident as well as three pipeline incidents in Illinois and Indiana in 2018, 2020 and 2021. We cannot currently estimate the timing of the resolution of this matter, but do not believe any civil penalty will have a material impact on our consolidated results of operations, financial position or cash flows.

On August 29, 2025, MPLX acquired Northwind Delaware Holdings LLC (“Northwind Midstream”), including its subsidiary Northwind Midstream Partners LLC, which owns and operates a sour gas treating facility in Lea County, New Mexico. We have disclosed to the New Mexico Environment Department (“NMED”) excess air emissions from the facility flares. We initiated discussions with NMED to resolve this matter and have entered into a new owner audit agreement with NMED as a result of those discussions. We do not believe any civil penalty will have a material impact on our consolidated results of operations, financial position or cash flows.

Item 4. Mine Safety Disclosures

Not applicable.

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PART II

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

Our common units are listed on the NYSE and traded under the symbol “MPLX.” As of February 20, 2026, there were approximately 210 registered holders of our outstanding common units.

Issuer Purchases of Equity Securities

The following table sets forth a summary of our purchases during the quarter ended December 31, 2025, of equity securities that are registered by MPLX pursuant to Section 12 of the Securities Exchange Act of 1934, as amended.


					Millions of Dollars
Period	Total Number of Common Units Purchased	Average Price Paid per Common Unit(1)		Total Number of Common Units Purchased as Part of Publicly Announced Plans or Programs	Maximum Dollar Value of Common Units that May Yet Be Purchased Under the Plans or Programs(2)(3)
10/1/2025-10/31/2025	556,511	$	49.59	556,511	$	1,192
11/1/2025-11/30/2025	418,560	53.02		418,560	1,170
12/1/2025-12/31/2025	920,871	54.52		920,871	$	1,120
Total	1,895,942	$	52.74	1,895,942

(1)Amounts in this column reflect the weighted average price paid for units purchased under our unit repurchase authorizations. The weighted average price includes any commissions paid to brokers during the relevant period.

(2)On August 2, 2022, we announced a board authorization for the repurchase of up to $1.0 billion of MPLX common units held by the public. On August 5, 2025, we announced a board authorization for the repurchase of up to an incremental $1.0 billion of MPLX common units held by the public. These unit repurchase authorizations have no expiration date.

(3)The maximum dollar value remaining has been reduced by the amount of any commissions paid to brokers.

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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

This section of the Annual Report on Form 10-K does not address certain items regarding the year ended December 31, 2023. Discussion and analysis of 2023 and year-to-year comparisons between 2024 and 2023 not included in this Annual Report on Form 10-K can be found in Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations of our Annual Report on Form 10-K for the year ended December 31, 2024.

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.

MPLX OVERVIEW

We are a diversified, large-cap MLP formed by MPC in 2012 that owns and operates midstream energy infrastructure and logistics assets, and provides fuels distribution services. Our assets include a network of crude oil and refined product pipelines; an inland marine business; light-product, asphalt, heavy oil and marine terminals; storage caverns; refinery tanks, docks, loading racks and associated piping; crude oil and natural gas gathering systems and pipelines; as well as natural gas and NGL processing and fractionation facilities. The business consists of two segments based on the product-based value chain each supports: Crude Oil and Products Logistics and Natural Gas and NGL Services. Our assets are positioned throughout the United States. The Crude Oil and Products Logistics segment primarily engages in the gathering, transportation, storage and distribution of crude oil, refined products, other hydrocarbon-based products and renewables. The Crude Oil and Products Logistics segment also includes the operation of our refining logistics, fuels distribution and inland marine businesses, terminals, rail facilities and storage caverns. The Natural Gas and NGL Services segment provides gathering, treating, processing and transportation of natural gas as well as the transportation, fractionation, storage and marketing of NGLs.

SIGNIFICANT FINANCIAL AND OTHER HIGHLIGHTS

Significant financial and other highlights for the years ended December 31, 2025, 2024 and 2023 are shown in the chart below. Refer to the Results of Operations, the Liquidity and Capital Resources, and Non-GAAP Financial Information sections for further information.

(1) Non-GAAP measure. See reconciliations that follow for the most directly comparable GAAP measures.

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Other Highlights

•Generated $5.9 billion of net cash provided by operating activities, $5.8 billion of distributable cash flow attributable to MPLX, and $1.0 billion of adjusted free cash flow (“Adjusted FCF”).

•Paid $4.0 billion in distributions during the year ended December 31, 2025, which includes a 12.5 percent increase in our quarterly distribution effective for the third quarter of 2025, in line with our commitment to return capital to unitholders.

•Repurchased $400 million of common units held by the public during the year ended December 31, 2025.

•Expanded our crude oil value chain in March 2025 by acquiring gathering businesses from Whiptail Midstream, LLC.

•In June 2025, acquired an additional five percent interest in the joint venture that owns and operates the Matterhorn Express Pipeline.

•Completed the acquisition of the remaining 55 percent interest in BANGL, LLC (“BANGL”), in July 2025 for $703 million in cash, plus an earnout provision of up to $275 million based on targeted EBITDA growth from 2026 to 2029 (the “BANGL Acquisition”).

•Completed the acquisition of Northwind Midstream in August 2025 for $2.4 billion in cash (the “Northwind Midstream Acquisition”).

•Sold our Rockies gathering and processing operations to a subsidiary of Harvest Midstream in November 2025 for $980 million in cash consideration.

Current Economic Environment

We continue to see production increases across our key operating regions in the Marcellus and Utica, where rig counts remain steady and volumes remain strong. Producer consolidation further illustrates the value in the liquids-rich acreage of the Utica, where condensate development activity continues to increase. In the Permian, rising gas-oil ratios and the progression of export projects will support growth opportunities for our business. More broadly, we expect natural gas demand will accelerate over the next few years to provide increased electricity generation required for data centers and overall electric grid demand. As demand for natural gas-powered electricity rises, MPLX is well-positioned to support the development plans of its producer-customers. Additionally, we believe MPLX is protected from significant volatility in our Crude Oil and Products Logistics segment and in the Marcellus and Utica regions due to our business model structured around long-term take-or-pay and capacity contracts.

NON-GAAP FINANCIAL INFORMATION

Our management uses a variety of financial and operating metrics to analyze our performance. These metrics are significant factors in assessing our operating results and profitability and include the non-GAAP financial measures of Adjusted EBITDA, DCF, Adjusted FCF, and Adjusted FCF after distributions.

Adjusted EBITDA is a financial performance measure used by management, industry analysts, investors, lenders, and rating agencies to assess the financial performance and operating results of our ongoing business operations. Additionally, we believe adjusted EBITDA provides useful information to investors for trending, analyzing and benchmarking our operating results from period to period as compared to other companies that may have different financing and capital structures. We define Adjusted EBITDA as net income adjusted for: (i) provision for income taxes; (ii) net interest and other financial costs; (iii) depreciation and amortization; (iv) income/(loss) from equity method investments; (v) distributions and adjustments related to equity method investments; (vi) impairment expense; (vii) noncontrolling interests; (viii) transaction-related costs; and (ix) other adjustments, as applicable.

DCF is a financial performance and liquidity measure used by management and by the board of directors of our general partner as a key component in the determination of cash distributions paid to unitholders. We believe DCF is an important financial measure for unitholders as an indicator of cash return on investment and to evaluate whether the partnership is generating sufficient cash flow to support quarterly distributions. In addition, DCF is commonly used by the investment community because the market value of publicly traded partnerships is based, in part, on DCF and cash distributions paid to unitholders. We define DCF as Adjusted EBITDA adjusted for: (i) deferred revenue impacts; (ii) sales-type lease payments, net of income; (iii) adjusted net interest and other financial costs; (iv) net maintenance capital expenditures; (v) equity method investment capital expenditures paid out; and (vi) other adjustments as deemed necessary.

Adjusted FCF and Adjusted FCF after distributions are financial liquidity measures used by management in the allocation of capital and to assess financial performance. We believe that unitholders may use this metric to analyze our ability to manage leverage and return capital. We define Adjusted FCF as net cash provided by operating activities adjusted for: (i) net cash used in investing activities; (ii) cash contributions from MPC; and (iii) cash distributions to noncontrolling interests. We define Adjusted FCF after distributions as Adjusted FCF less distributions to common and preferred unitholders.

We believe that the presentation of Adjusted EBITDA, DCF, Adjusted FCF and Adjusted FCF after distributions provides useful information to investors in assessing our financial condition and results of operations. The GAAP measures most directly comparable to Adjusted EBITDA and DCF are net income and net cash provided by operating activities while the GAAP measure most directly comparable to Adjusted FCF and Adjusted FCF after distributions is net cash provided by operating activities. These non-GAAP financial measures should not be considered alternatives to net income or net cash provided by operating

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activities as they have important limitations as analytical tools because they exclude some but not all items that affect net income and net cash provided by operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. These non-GAAP financial measures should not be considered in isolation or as substitutes for analysis of our results as reported under GAAP. Additionally, because non-GAAP financial measures may be defined differently by other companies in our industry, our definitions may not be comparable to similarly titled measures of other companies, thereby diminishing their utility. For a reconciliation of Adjusted EBITDA and DCF to their most directly comparable measures calculated and presented in accordance with GAAP, see Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations. For a reconciliation of Adjusted FCF and Adjusted FCF after distributions to their most directly comparable measure calculated and presented in accordance with GAAP, see Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources.

COMPARABILITY OF OUR FINANCIAL RESULTS

During the normal course of business, we amend or modify our contractual agreements with customers. These amendments or modifications require the agreements to be reassessed under GAAP, which can impact the classification of revenues or costs associated with the agreement. These reassessments may impact the comparability of our financial results.

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RESULTS OF OPERATIONS

The following tables and discussion summarize our results of operations for the years ended 2025, 2024 and 2023, including a reconciliation of Adjusted EBITDA and DCF from Net income and Net cash provided by operating activities, the most directly comparable GAAP financial measures.


(In millions)	2025		2024		$ Change		2023		$ Change
Revenues and other income:
Service revenue	$	7,292	$	6,950	$	342	$	6,524	$	426
Rental income	1,149		1,104		45		1,065		39
Product related revenue	2,434		2,239		195		2,209		30
Sales-type lease revenue	599		611		(12)		636		(25)
Income from equity method investments	697		802		(105)		600		202
Gain on equity method investments	484		20		464		92		(72)
Other income	343		207		136		155		52
Total revenues and other income	12,998		11,933		1,065		11,281		652
Costs and expenses:
Cost of revenues (excludes items below)	1,561		1,560		1		1,401		159
Purchased product costs	1,815		1,561		254		1,598		(37)
Rental cost of sales	96		100		(4)		115		(15)
Purchases - related parties	1,649		1,583		66		1,544		39
Depreciation and amortization	1,351		1,283		68		1,213		70
General and administrative expenses	446		427		19		379		48
Other taxes	137		131		6		131		—
Total costs and expenses	7,055		6,645		410		6,381		264
Income from operations	5,943		5,288		655		4,900		388
Net interest and other financial costs	983		921		62		923		(2)
Income before income taxes	4,960		4,367		593		3,977		390
Provision for income taxes	8		10		(2)		11		(1)
Net income	4,952		4,357		595		3,966		391
Less: Net income attributable to noncontrolling interests	40		40		—		38		2
Net income attributable to MPLX LP	$	4,912	$	4,317	$	595	$	3,928	$	389

Adjusted EBITDA attributable to MPLX LP(1)	$	7,017	$	6,764	$	253	$	6,269	$	495
DCF attributable to MPLX(1)	$	5,791	$	5,697	$	94	$	5,340	$	357

(1) Non-GAAP measure. See reconciliation below to the most directly comparable GAAP measures.

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(In millions)	2025		2024		2023
Reconciliation of Adjusted EBITDA attributable to MPLX LP and DCF attributable to LP unitholders from Net income:
Net income	$	4,952	$	4,357	$	3,966
Provision for income taxes	8		10		11
Net interest and other financial costs	983		921		923
Income from operations	5,943		5,288		4,900
Depreciation and amortization	1,351		1,283		1,213
Income from equity method investments	(697)		(802)		(600)
Distributions/adjustments related to equity method investments	962		928		774
Gain on equity method investments	(484)		—		(92)
Gain on sale of assets	(159)		—		—
Transaction-related costs(1)	33		—		—
Garyville incident response costs(2)	—		—		16
Other(3)	112		111		100
Adjusted EBITDA	7,061		6,808		6,311
Adjusted EBITDA attributable to noncontrolling interests	(44)		(44)		(42)
Adjusted EBITDA attributable to MPLX LP	7,017		6,764		6,269
Deferred revenue impacts	(57)		31		97
Sales-type lease payments, net of income	62		32		12
Adjusted net interest and other financial costs(4)	(950)		(867)		(859)
Maintenance capital expenditures, net of reimbursements	(256)		(206)		(150)
Equity method investment maintenance capital expenditures paid out	(20)		(18)		(15)
Other	(5)		(39)		(14)
DCF attributable to MPLX LP	5,791		5,697		5,340
Preferred unit distributions	—		(27)		(99)
DCF attributable to LP unitholders	$	5,791	$	5,670	$	5,241

(1)Transaction-related costs include costs associated with the Northwind Midstream Acquisition, the BANGL Acquisition and the divestiture of the Rockies gathering and processing operations discussed in Item 8. Financial Statements and Supplementary Data – Note 4.

(2)In August 2023, a naphtha release and resulting fire occurred at our Garyville Tank Farm resulting in the loss of four storage tanks with a combined shell capacity of 894 thousand barrels (“Garyville Incident”). We incurred $16 million of incident response costs, net of insurance recoveries, during the year ended December 31, 2023.

(3)Includes unrealized derivative gains and/or losses, equity-based compensation and other miscellaneous items.

(4)Represents Net interest and other financial costs excluding gains and/or losses on extinguishment of debt and amortization of deferred financing costs.

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(In millions)	2025		2024		2023
Reconciliation of Adjusted EBITDA attributable to MPLX LP and DCF attributable to LP unitholders from Net cash provided by operating activities:
Net cash provided by operating activities	$	5,909	$	5,946	$	5,397
Changes in working capital items	(65)		(241)		(169)
All other, net	1		(5)		39
Loss on extinguishment of debt	3		—		9
Adjusted net interest and other financial costs(1)	950		867		859
Other adjustments to equity method investment distributions	98		102		38
Transaction-related costs(2)	33		—		—
Garyville Incident response costs(3)	—		—		16
Other	132		139		122
Adjusted EBITDA	7,061		6,808		6,311
Adjusted EBITDA attributable to noncontrolling interests	(44)		(44)		(42)
Adjusted EBITDA attributable to MPLX LP	7,017		6,764		6,269
Deferred revenue impacts	(57)		31		97
Sales-type lease payments, net of income	62		32		12
Adjusted net interest and other financial costs(1)	(950)		(867)		(859)
Maintenance capital expenditures, net of reimbursements	(256)		(206)		(150)
Equity method investment maintenance capital expenditures paid out	(20)		(18)		(15)
Other	(5)		(39)		(14)
DCF attributable to MPLX LP	5,791		5,697		5,340
Preferred unit distributions	—		(27)		(99)
DCF attributable to LP unitholders	$	5,791	$	5,670	$	5,241

(1) Represents Net interest and other financial costs excluding gains and/or losses on extinguishment of debt and amortization of deferred financing costs.

(2) Transaction-related costs include costs associated with the Northwind Midstream Acquisition, the BANGL Acquisition and the divestiture of the Rockies gathering and processing operations discussed in Item 8. Financial Statements and Supplementary Data – Note 4.

(3) We incurred $16 million of Garyville Incident response costs, net of insurance recoveries, during the year ended December 31, 2023.

2025 Compared to 2024

Net income attributable to MPLX increased $595 million in 2025 compared to 2024 primarily due to a $484 million gain from the BANGL Acquisition, annual fee escalations, higher throughputs and benefits from recent acquisitions.

Total revenues and other income increased by $1.1 billion in 2025 compared to 2024 primarily due to:

•Increased Service revenue of $342 million primarily due $132 million of crude oil and products logistics tariff and other fee increases, $96 million from recent acquisitions, $93 million of higher pipeline throughput and a $37 million benefit from a FERC tariff ruling issued in November 2025.

•Increased Rental income of $45 million primarily due to changes in the presentation of lease income between sales-type lease revenue, service revenue and rental income as a result of lease contract modifications, and annual fee escalations related to our refining logistics assets.

•Increased Product related revenue of $195 million due to higher NGL sales volumes in the Southwest and Marcellus of $347 million and a $27 million non-recurring benefit associated with a customer agreement, partially offset by lower revenue in the Rockies of $101 million, including the impact of the Rockies divestiture, and lower NGL prices in the Southwest, Marcellus and Southern Appalachia of $76 million.

•Decreased Income from equity method investments of $105 million primarily driven by a $151 million gain in the 2024 period related to the dilution of our ownership interest in connection with the formation of a new joint venture to strategically combine the Whistler Pipeline and the Rio Bravo Pipeline project (the “Whistler Joint Venture Transaction”), partially offset by increased throughput and fee rates in certain processing and pipeline joint ventures and a $25 million gain in the first half of 2025 related to the formation of a new joint venture, Texas City Logistics LLC. See Supplemental Information on Equity Method Investments for additional information regarding the results of our equity method investments.

•Increased Gain on equity method investments of $464 million, primarily driven by a $484 million gain from the BANGL Acquisition, partially offset by a $20 million gain related to the acquisition of additional ownership interest in existing joint ventures and gathering assets in the Utica basin (the “Utica Midstream Acquisition”) in the 2024 period.

•Increased Other income of $136 million primarily due to a $159 million gain from the Rockies divestiture, partially offset by lower insurance proceeds of $41 million.

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Total costs and expenses increased by $410 million in 2025 compared to 2024 primarily due to:

•Increased Cost of revenues of $1 million primarily due to lower NGL purchases in the Rockies of $89 million, which are now reflected in Purchased product costs due to changes in certain customer contracts, partially offset by higher net operating costs and repairs and maintenance costs of $60 million and the consolidation of recent acquisitions of $34 million.

•Increased Purchased product costs of $254 million primarily due to higher NGL volumes in the Southwest of $276 million and higher NGL volumes in the Rockies of $47 million, which were previously recorded in Cost of revenues due to changes in certain customer contracts, partially offset by lower NGL prices in the Southwest of $52 million.

•Increased Purchases-related parties of $66 million primarily due to increased employee costs from MPC.

•Increased Depreciation and amortization of $68 million primarily due to incremental depreciation associated with recent acquisitions as well as other assets placed in service in 2025.

SEGMENT RESULTS

We classify our business in the following reportable segments: Crude Oil and Products Logistics and Natural Gas and NGL Services. Each of these segments is organized and managed based upon the product-based value chain each supports.

We evaluate the performance of our segments using Segment Adjusted EBITDA. Segment Adjusted EBITDA represents Adjusted EBITDA attributable to the reportable segments. Amounts included in net income and excluded from Segment Adjusted EBITDA include: (i) depreciation and amortization; (ii) net interest and other financial costs; (iii) income/(loss) from equity method investments; (iv) distributions and adjustments related to equity method investments; (v) impairment expense; (vi) noncontrolling interests; (vii) transaction-related costs; and (viii) other adjustments, as applicable. 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.

The tables below present additional financial information about our reportable segments for the years ended December 31, 2025, 2024 and 2023.

Crude Oil and Products Logistics Segment

Crude Oil and Products Logistics Segment Financial Highlights (in millions)


Segment revenues and other income			Segment Adjusted EBITDA


(In millions)	2025		2024		$ Change		2023		$ Change






Total segment revenues and other income	$	6,575	$	6,339	$	236	$	6,048	$	291








Segment Adjusted EBITDA	4,547		4,375		172		4,134		241
Capital expenditures	538		482		56		414		68
Investments in unconsolidated affiliates(1)	$	—	$	93	$	(93)	$	8	$	85

(1) The year ended December 31, 2024 includes a contribution of $92 million to a joint venture (“Dakota Access”) that owns and operates the Dakota Access Pipeline and Energy Transfer Crude Oil Pipeline projects (collectively referred to as the “Bakken Pipeline system”), to fund our share of debt repayments by the joint venture.

2025 Compared to 2024

Total segment revenues and other income increased $236 million in 2025 compared to 2024. The increase was primarily driven by $132 million of tariff and other fee increases, $93 million of increased pipeline throughput, a $37 million benefit from a FERC tariff ruling issued in November 2025, $21 million from the March 2025 Whiptail Midstream, LLC acquisition and $14 million of additional marine equipment in operation, partially offset by lower insurance proceeds of $41 million. Income from equity method investments decreased $26 million in 2025 compared to 2024, primarily driven by lower throughput on certain equity method

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investment pipeline systems. See Supplemental Information on Equity Method Investments for additional information regarding the results of our equity method investments.

Segment Adjusted EBITDA increased $172 million in 2025 compared to 2024. The increase was primarily driven by $132 million of tariff and other fee increases, $93 million of increased pipeline throughput, a $37 million benefit from a FERC tariff ruling issued in November 2025, $17 million from the March 2025 Whiptail Midstream, LLC acquisition and $14 million of additional marine equipment in operation. These increases were partially offset by lower insurance proceeds of $41 million, higher project related spending of $41 million, higher operating costs of $37 million, driven primarily by higher employee costs from MPC, and increased energy costs as a result of higher throughputs, as well as lower distributions and adjustments from equity method investments of $29 million.

Crude Oil and Products Logistics Operating Data


	2025		2024		2023
Crude Oil and Products Logistics
Crude oil transported for (mbpd):
MPC	3,188		3,086		3,053
Third parties	711		699		719
Total	3,899		3,785		3,772
% MPC	82%		82%		81%
Refined products transported for (mbpd):
MPC	1,955		1,891		1,941
Third parties	111		106		99
Total	2,066		1,997		2,040
% MPC	95%		95%		95%
Average tariff rates ($ per Bbl)(1):
Crude oil pipelines	$	1.06	$	1.03	$	0.96
Refined product pipelines	1.08		1.00		0.90
Total pipelines	$	1.06	$	1.02	$	0.94

Terminal throughput (mbpd)	3,132		3,131		3,130

Marine Assets (number in operation)
Barges	322		319		305
Towboats	30		29		29

(1)Average tariff rates calculated using pipeline transportation revenues divided by pipeline throughput barrels. Transportation revenues include tariff and other fees, which may vary by region and nature of services provided.

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Natural Gas and NGL Services Segment

Natural Gas and NGL Services Segment Financial Highlights (in millions)


Segment revenues and other income(1)			Segment Adjusted EBITDA


(In millions)	2025		2024		$ Change		2023		$ Change







Total segment revenues and other income(1)	$	6,423	$	5,594	$	829	$	5,233	$	361









Segment Adjusted EBITDA	2,470		2,389		81		2,135		254
Capital expenditures	1,418		568		850		605		(37)
Investments in unconsolidated affiliates	$	794	$	143	$	651	$	90	$	53

(1)The year ended December 31, 2024 includes a $151 million gain related to the dilution of ownership interest in connection with the Whistler Joint Venture Transaction. See Item 8. Financial Statements and Supplementary Data – Note 4 for additional information.

2025 Compared to 2024

Total segment revenues and other income increased $829 million in 2025 compared to 2024. The increase was primarily due to the recognition of a $484 million gain from the BANGL Acquisition, $347 million of higher NGL sales volumes in the Southwest and Marcellus, a $159 million gain from the Rockies divestiture, $71 million from recent acquisitions and a $34 million non-recurring benefit associated with a customer agreement. These increases were partially offset by lower income from equity method investments of $79 million, primarily driven by a $151 million gain in the second quarter of 2024 related to the dilution of our ownership interest in connection with the Whistler Joint Venture Transaction, $76 million of lower NGL prices in the Southwest, Marcellus and Southern Appalachia and $57 million of lower throughput and fee rates in the Rockies and Bakken.

Additional impacts from equity method investments included increased throughput and fee rates in certain processing and pipeline joint ventures and a $25 million gain in 2025 related to the formation of a new joint venture, Texas City Logistics LLC. See Supplemental Information on Equity Method Investments for additional information regarding the results of our equity method investments.

Segment Adjusted EBITDA increased $81 million in 2025 compared to 2024. The increase is primarily due to $80 million in contributions from recent acquisitions, $63 million of higher distributions and adjustments from equity method investments, $40 million of higher throughput fee rates, $40 million of higher NGL sales volumes in the Southwest and Marcellus and a $37 million non-recurring benefit associated with a customer agreement. These increases were partially offset by higher operating costs of $55 million, lower volumes in the Rockies and Bakken of $45 million, the impact of the divestiture of non-core gathering and processing assets of $31 million, lower NGL pricing of $26 million and higher project related spending of $18 million.

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Natural Gas and NGL Services Operating Data

(1) Other includes Southern Appalachia, Bakken and Rockies Operations


	MPLX LP(1)			MPLX LP Operated(2)
	2025	2024	2023	2025	2024	2023
Natural Gas and NGL Services
Gathering Throughput (MMcf/d)
Marcellus Operations	1,526	1,521	1,389	1,526	1,521	1,389
Utica Operations	66	264	—	2,672	2,544	2,338
Southwest Operations	1,826	1,698	1,369	1,826	1,698	1,772
Bakken Operations	160	183	165	160	183	165
Rockies Operations	465	560	474	525	633	593
Total gathering throughput	4,043	4,226	3,397	6,709	6,579	6,257
Natural Gas Processed (MMcf/d)
Marcellus Operations	4,431	4,366	4,179	6,123	5,974	5,773
Utica Operations	—	—	—	961	832	564
Southwest Operations(3)	1,904	1,844	1,466	1,904	1,844	1,772
Southern Appalachia Operations	191	215	216	191	215	216
Bakken Operations	159	182	163	159	182	163
Rockies Operations	518	616	483	518	616	483
Total natural gas processed	7,203	7,223	6,507	9,856	9,663	8,971
C2 + NGLs Fractionated (mbpd)
Marcellus Operations(4)	566	565	530	566	565	530
Utica Operations(4)	—	—	—	65	52	33



Other(5)	29	37	34	29	37	34
Total C2 + NGLs fractionated(6)	595	602	564	660	654	597
NGL Pipeline Throughput (mbpd)
Marcellus Operations	457	431	354	457	431	354
Utica Operations	—	—	—	65	52	33
Southwest Operations	98	—	—	180	148	114
Other(5)	29	37	34	29	37	34
Total NGL pipeline throughput	584	468	388	731	668	535

(1) This column represents operating data for entities that have been consolidated into the MPLX financial statements.

(2) This column represents operating data for entities that have been consolidated into the MPLX financial statements as well as operating data for MPLX-operated equity method investments.

(3) The amounts presented above exclude Northwind Midstream treated volumes during the year ended December 31, 2025.

(4) Entities within the Marcellus and Utica Operations jointly own the Hopedale fractionation complex. Hopedale throughput is included in the Marcellus and Utica Operations and represents each region’s utilization of the complex.

(5) Other includes Southern Appalachia, Bakken and Rockies Operations.

(6) Purity ethane makes up approximately 267 mbpd, 265 mbpd and 233 mbpd of MPLX LP consolidated total fractionated products for the years ended December 31, 2025, 2024 and 2023, respectively. Purity ethane makes up approximately 288 mbpd, 282 mbpd and 240 mbpd of MPLX operated total fractionated products for the years ended December 31, 2025, 2024 and 2023, respectively.

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	2025		2024		2023
Pricing Information
Natural Gas NYMEX HH ($/MMBtu)	$	3.63	$	2.41	$	2.66
C2 + NGL Pricing/gallon(1)	$	0.79	$	0.84	$	0.69

(1) 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. The changes in mix from 2023 to 2024 resulted in an approximate $0.13 increase in the calculated C2 + NGL price per gallon.

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SUPPLEMENTAL INFORMATION ON EQUITY METHOD INVESTMENTS

The following table presents MPLX’s income from equity method investments for the years ended December 31, 2025, 2024 and 2023:


(In millions)	2025		2024		2023
Income from equity method investments:
Crude Oil and Products Logistics
Illinois Extension Pipeline Company, L.L.C.	$	50	$	57	$	49
LOOP LLC	14		11		30
MarEn Bakken Company LLC	79		98		88








Other	100		103		103
Total Crude Oil and Products Logistics	243		269		270
Natural Gas and NGL Services
MarkWest EMG Jefferson Dry Gas Gathering Company, L.L.C.	77		67		64
MarkWest Utica EMG, L.L.C.	127		82		57
Ohio Gathering Company L.L.C.	36		13		—
Sherwood Midstream LLC	114		109		105
WPC Parent, LLC(1)	71		252		80
















Other(2)	29		10		24
Total Natural Gas and NGL Services	454		533		330
Total	$	697	$	802	$	600

(1) In May 2024, MPLX completed the Whistler Joint Venture Transaction, which resulted in the formation of a new entity, WPC Parent, LLC. Results include the equity method investment income of our interest in Whistler Pipeline, LLC prior to the transaction date, and results of the equity method investment income of our ownership in WPC Parent, LLC subsequent to the transaction date. The year ended December 31, 2024 includes a gain of $151 million related to the dilution of our ownership interest in connection with the Whistler Joint Venture Transaction.

(2) Includes a $25 million gain in 2025 related to the formation of a new joint venture, Texas City Logistics LLC.

The following table presents the impact of equity method investment distributions and other adjustments included in MPLX’s Adjusted EBITDA for the years ended December 31, 2025, 2024 and 2023:


(In millions)	2025		2024		2023
Distributions/adjustments related to equity method investments:
Crude Oil and Products Logistics
Illinois Extension Pipeline Company, L.L.C.	$	60	$	67	$	58
LOOP LLC	30		20		9
MarEn Bakken Company LLC	103		113		116







Other	126		147		124
Total Crude Oil and Products Logistics	319		347		307
Natural Gas and NGL Services
MarkWest EMG Jefferson Dry Gas Gathering Company, L.L.C.	78		83		86
MarkWest Utica EMG, L.L.C.	172		123		89
Ohio Gathering Company L.L.C.	64		38		—
Sherwood Midstream LLC	127		122		117
WPC Parent, LLC(1)	119		162		94














Other	83		53		81
Total Natural Gas and NGL Services	643		581		467
Total	$	962	$	928	$	774

(1) In May 2024, MPLX completed the Whistler Joint Venture Transaction, which resulted in the formation of a new entity, WPC Parent, LLC. Results include the equity method investment distributions and adjustments of our interest in Whistler Pipeline, LLC prior to the transaction date, and results of the equity method investment distributions and adjustments of our ownership in WPC Parent, LLC subsequent to the transaction date.

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LIQUIDITY AND CAPITAL RESOURCES

Cash Flows

Our cash and cash equivalents were $2,137 million and $1,519 million at December 31, 2025 and December 31, 2024, respectively. The change in cash and cash equivalents was due to the factors discussed below. Net cash provided by (used in) operating activities, investing activities and financing activities for the past three years were as follows:


(In millions)	2025		2024		2023
Net cash provided by/(used in):
Operating activities	$	5,909	$	5,946	$	5,397
Investing activities	(4,856)		(1,995)		(1,252)
Financing activities	(435)		(3,480)		(3,335)
Total	$	618	$	471	$	810

Cash Flows Provided by Operating Activities - Net cash provided by operating activities decreased $37 million in 2025 compared to 2024 primarily due to a $182 million increase in working capital requirements, partially offset by improved results of operations and higher cash distributions from equity method investments.

Cash Flows Used in Investing Activities - Net cash used in investing activities increased $2,861 million in 2025 compared to 2024 primarily due to the acquisition of Northwind Midstream for $2,413 million, higher capital spending and the purchase of the remaining 55 percent interest in BANGL for $703 million. The year ended December 31, 2025 also reflects the use of $235 million for the acquisition of Whiptail Midstream, LLC and the purchase of an additional five percent ownership interest in the joint venture that owns and operates the Matterhorn Express pipeline for $151 million. These increases were partially offset by $971 million received from the sale of our Rockies operations.

Cash Flows Used in Financing Activities - Net cash used in financing activities decreased $3,045 million in 2025 compared to 2024. The decrease was primarily driven by increased net debt borrowings of $3,598 million, partially offset by higher distributions paid to unitholders of $421 million as a result of the 12.5 percent increase in our quarterly distribution effective for the third quarter of 2025 and higher unit repurchases of $74 million.

Adjusted Free Cash Flow - For the year ended December 31, 2025, we generated Adjusted FCF of $1.0 billion. This provided us the flexibility to return capital to our unitholders by increasing our quarterly distribution by 12.5 percent in the third quarter of 2025. The table below provides a reconciliation of Adjusted FCF and Adjusted FCF after distributions from net cash provided by operating activities for the years ended December 31, 2025, 2024 and 2023.




(In millions)	2025		2024		2023
Net cash provided by operating activities(1)	$	5,909	$	5,946	$	5,397
Adjustments to reconcile net cash provided by operating activities to adjusted free cash flow
Net cash used in investing activities(2)	(4,856)		(1,995)		(1,252)
Contributions from MPC	24		35		31
Distributions to noncontrolling interests	(44)		(44)		(41)
Adjusted FCF	1,033		3,942		4,135





Distributions paid to common and preferred unitholders	(4,024)		(3,603)		(3,296)
Adjusted FCF after distributions	$	(2,991)	$	339	$	839

(1) The years ended December 31, 2025, 2024 and 2023 include working capital draws of $65 million, $241 million and $169 million, respectively.

(2) The year ended December 31, 2025 includes $2.4 billion for the Northwind Midstream Acquisition, $703 million for the BANGL Acquisition, $235 million for the acquisition of Whiptail Midstream, LLC, $151 million for the purchase of an additional five percent ownership interest in the joint venture that owns and operates the Matterhorn Express pipeline, a $49 million capital contribution to WPC Parent, LLC to redeem Enbridge’s special membership interest in the Rio Bravo Pipeline project, and $971 million received from the sale of our Rockies gathering and processing operations.

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Debt and Liquidity Overview

Senior Notes

The following table summarizes debt issuances during the year ended December 31, 2025, all of which were issued in underwritten public offerings:


Issue Date	Aggregate Principal Amount (in millions)		Note	Coupon (percent)	Price to Public (percent of par)	Interest Payment Dates	Maturity Date
March 10, 2025	$	1,000	(1)	5.400	99.398	April 1 and October 1	April 1, 2035
March 10, 2025	1,000		(1)	5.950	98.331	April 1 and October 1	April 1, 2055
August 11, 2025	1,250		(2)	4.800	99.880	February 15 and August 15	February 15, 2031
August 11, 2025	750		(2)	5.000	98.936	January 15 and July 15	January 15, 2033
August 11, 2025	1,500		(2)	5.400	98.943	March 15 and September 15	September 15, 2035
August 11, 2025	1,000		(2)	6.200	98.277	March 15 and September 15	September 15, 2055

(1) On April 9, 2025, MPLX used $1.2 billion of the net proceeds from the issuance of senior notes in March 2025 to redeem all of (i) MPLX’s outstanding $1,189 million aggregate principal amount of 4.875 percent senior notes due June 2025 and (ii) MarkWest’s outstanding $11 million aggregate principal amount of 4.875 percent senior notes due June 2025. The remaining net proceeds from this offering were used for general partnership purposes.

(2) We used a portion of the net proceeds from this offering to fund the Northwind Midstream Acquisition, including the payment of related fees and expenses, and to increase cash and cash equivalents following the recently completed BANGL Acquisition and BANGL Debt Repayment (as defined below). The remainder of the net proceeds from this offering were used for general partnership purposes.

On July 3, 2025, MPLX used cash on hand to extinguish approximately $656 million principal amount of debt outstanding, including interest, related to certain term and revolving loans assumed as part of the BANGL Acquisition (the “BANGL Debt Repayment”). See Note 4 for additional information on the BANGL Acquisition.

On May 20, 2024, MPLX issued $1.65 billion aggregate principal amount of the 5.50 percent senior notes due June 2034 (the “2034 Senior Notes”) in an underwritten public offering. The 2034 Senior Notes were offered at a price to the public of 98.778 percent of par, with interest payable semi-annually in arrears, commencing on December 1, 2024. On December 1, 2024, MPLX used $1,150 million of the net proceeds from the issuance of the 2034 Senior Notes to repay all of (i) MPLX’s outstanding $1,149 million aggregate principal amount of 4.875 percent senior notes due December 2024 and (ii) MarkWest’s outstanding $1 million aggregate principal amount of 4.875 percent senior notes due December 2024. On February 18, 2025, MPLX used the remaining net proceeds from the issuance of the 2034 Senior Notes to repay all of MPLX’s outstanding $500 million aggregate principal amount of 4.000 percent senior notes due February 2025.

The total issuances of $6.5 billion and total redemptions of $1.7 billion of senior notes during 2025 as discussed above resulted in an aggregate principal amount of senior notes outstanding as of December 31, 2025 of $26 billion, an increase of $4.8 billion compared to December 31, 2024.

On February 12, 2026, MPLX issued $1.0 billion aggregate principal amount of 5.30 percent senior notes due 2036 (the “2036 Senior Notes”) and $500 million aggregate principal amount of 6.10 percent senior notes due 2056 (the “2056 Senior Notes”) in an underwritten public offering. The 2036 Senior Notes were offered at a price to the public of 99.678 percent of par, with interest payable semi-annually in arrears, commencing on October 1, 2026. The 2056 Senior Notes were offered at a price to the public of 98.453 percent of par, with interest payable semi-annually in arrears, commencing on October 1, 2026. We intend to use the net proceeds from the 2036 Senior Notes and 2056 Senior Notes to repay MPLX’s outstanding $1,500 million aggregate principal amount of 1.750 percent senior notes due March 2026 at maturity. Pending final use, we may invest the proceeds in short-term marketable securities or other investments.

Credit Agreement

MPLX’s credit agreement (the “MPLX Credit Agreement”) matures in July 2027 and, among other things, provides for a $2 billion unsecured revolving credit facility and letter of credit issuing capacity under the facility of up to $150 million. Letter of credit issuing capacity is included in, not in addition to, the $2 billion borrowing capacity. Borrowings under the MPLX Credit Agreement bear interest, at MPLX’s election, at either the Adjusted Term SOFR or the Alternate Base Rate, both as defined in the MPLX Credit Agreement, plus an applicable margin.

The borrowing capacity under the MPLX Credit Agreement may be increased by up to an additional $1 billion, subject to certain conditions, including the consent of lenders whose commitments would increase. In addition, the maturity date may be extended for up to two additional one-year periods, subject to, among other conditions, the approval of lenders holding the majority of the commitments then outstanding, provided that the commitments of any non-consenting lenders will terminate on the then-effective maturity date. We are charged various fees and expenses in connection with the agreement, including administrative agent fees, commitment fees on the unused portion of the bank revolving credit facility and fees with respect to issued and outstanding letters of credit. The applicable margins to the benchmark interest rates and certain fees fluctuate based on the credit ratings in effect from time to time on MPLX’s long-term debt.

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The MPLX Credit Agreement contains certain representations and warranties, affirmative and negative covenants and events of default that we consider usual and customary for an agreement of this type, including a financial covenant that requires us to maintain a ratio of Consolidated Total Debt as of the end of each fiscal quarter to Consolidated EBITDA (both as defined in the MPLX Credit Agreement) for the prior four fiscal quarters of no greater than 5.0 to 1.0 (or 5.5 to 1.0 for up to two fiscal quarters following certain acquisitions). Consolidated EBITDA is subject to adjustments, including for certain acquisitions completed and capital projects undertaken during the relevant period. Other covenants restrict us and/or certain of our subsidiaries from incurring debt, creating liens on our assets and entering into transactions with affiliates. As of December 31, 2025, we were in compliance with the covenants contained in the MPLX Credit Agreement.

Activity on the MPLX Credit Agreement during the year ended December 31, 2025 is summarized in the table below.


(in millions, except %)	2025
Borrowings	$	106
Weighted average interest rate of borrowings	7.74		%
Repayments	$	106
Outstanding balance at end of period(1)	$	—

(1) There was less than $1 million in letters of credit outstanding on the MPLX Credit Agreement.

MPC Loan Agreement

MPLX is party to a loan agreement with MPC (the “MPC Loan Agreement”). Under the terms of the MPC Loan Agreement, MPC extends loans to MPLX on a revolving basis as requested by MPLX and as agreed to by MPC. The borrowing capacity of the MPC Loan Agreement is $1.5 billion aggregate principal amount of all loans outstanding at any one time. The MPC Loan Agreement is scheduled to expire, and borrowings under the loan agreement are scheduled to mature and become due and payable, on July 31, 2029, provided that MPC may demand payment of all or any portion of the outstanding principal amount of the loan, together with all accrued and unpaid interest and other amounts (if any), at any time prior to maturity. Borrowings under the MPC Loan Agreement bear interest at one-month term SOFR adjusted upward by 0.10 percent plus 1.25 percent or such lower rate as would be applicable to such loans under the MPLX Credit Agreement as discussed in Item 8. Financial Statements and Supplementary Data – Note 17.

Activity on the MPC Loan Agreement during the year ended December 31, 2025 is summarized in the table below.


(In millions, except %)	2025
Borrowings	$	50
Weighted average interest rate of borrowings	5.68		%
Repayments	$	50
Outstanding balance at end of period	$	—

For further discussion, see Item 8. Financial Statements and Supplementary Data – Note 6 and Note 17.

Our intention is to maintain an investment grade credit profile. As of February 1, 2026, the credit ratings on our senior unsecured debt were at or above investment grade level as follows:


Rating Agency						Rating
Fitch						BBB (stable outlook)
Moody’s						Baa2 (stable outlook)
Standard & Poor’s						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 our debt obligations do not contain credit rating triggers that would result in the acceleration of interest, principal or other payments solely in the event that our credit ratings are downgraded. However, any downgrades in the credit ratings of our senior unsecured debt ratings to below investment grade ratings could, among other things, increase the applicable interest rates and other fees payable under the MPLX Credit Agreement, and may limit our ability to obtain future financing, including refinancing existing indebtedness.

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Our liquidity totaled $5.6 billion at December 31, 2025, consisting of:


	December 31, 2025
(In millions)	Total Capacity		Outstanding Borrowings		Available Capacity
MPLX Credit Agreement	$	2,000	$	—	$	2,000
MPC Loan Agreement	1,500		—		1,500
Total	$	3,500	$	—	3,500
Cash and cash equivalents					2,137
Total liquidity					$	5,637

We expect our ongoing sources of liquidity to include cash generated from operations, borrowings under our revolving credit facilities and access to capital markets. We believe that cash generated from these sources will be sufficient to meet our short-term and long-term funding requirements, including working capital requirements, capital expenditure requirements, contractual obligations and quarterly cash distributions. Our material future obligations include interest on debt, payments of debt principal, purchase obligations including contracts to acquire property, plant and equipment and our operating leases and service agreements. We may also, from time to time, repurchase our senior notes in the open market, in tender offers, in privately negotiated transactions or otherwise in such volumes, at market prices and upon such other terms as we deem appropriate and execute unit repurchases under our unit repurchase program.

MPC manages our cash and cash equivalents on our behalf directly with third-party institutions as part of the treasury services that it provides to us under our omnibus agreement. From time to time, we may also utilize other sources of liquidity, including the formation of joint ventures or sales of non-strategic assets.

Equity and Preferred Units Overview

Preferred Units

On May 13, 2016, MPLX completed the private placement of approximately 30.8 million Series A preferred units for a cash purchase price of $32.50 per unit. The aggregate net proceeds of approximately $984 million from the sale of the preferred units were used for capital expenditures, repayment of debt and general business purposes.

The following conversions were executed in accordance with the conversion provisions outlined in our Partnership Agreement. During the years ended December 31, 2024 and 2023, certain Series A preferred unitholders exercised their rights to convert their Series A preferred units into 21 million common units and 2 million common units, respectively. On February 11, 2025, MPLX exercised its right to convert the remaining 6 million outstanding Series A preferred units into common units. As a result, there were no Series A preferred units outstanding at December 31, 2025.

Prior to conversion, the holders of the Series A preferred units received quarterly distributions equal to the greater of $0.528125 per unit or the amount of distributions they would have received on an as converted basis. Distributions paid to Series A preferred unitholders during the years ended December 31, 2025, 2024 and 2023 were $6 million, $44 million and $94 million, respectively.

Unit Repurchase Program

On August 5, 2025, we announced a board authorization for the repurchase of $1.0 billion of MPLX common units held by the public in addition to the $1.0 billion common unit repurchase authorization announced on August 2, 2022. These unit repurchase authorizations have no expiration date.

We may utilize various methods to effect the repurchases, which could include open market repurchases, negotiated block transactions, accelerated unit repurchases, tender offers, or open market solicitations for units, some of which may be effected through Rule 10b5-1 plans. The timing and amount of future repurchases, if any, will depend upon several factors, including market and business conditions, and such repurchases may be suspended, discontinued or restarted at any time.

Total unit repurchases were as follows for the respective periods:


(In millions, except per unit data)	2025		2024		2023
Units repurchased	8		8		—
Cash paid for common units repurchased(1)	$	400	$	326	$	—
Average cost per unit(1)	$	51.58	$	43.04	$	—

(1)Cash paid for common units repurchased and average cost per unit includes commissions paid to brokers during the period.

As of December 31, 2025, we had $1,120 million remaining under the unit repurchase authorizations.

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Distributions

On January 29, 2026, we announced that the board of directors of our general partner had declared a quarterly cash distribution of $1.0765 per common unit for the fourth quarter of 2025, which was paid on February 17, 2026 to common unitholders of record on February 9, 2026. This represents a 12.5 percent increase over the fourth quarter of 2024 distribution. Although our Partnership Agreement requires that we distribute all of our available cash each quarter, we do not otherwise have a legal obligation to distribute any particular amount per common unit.

The allocation of total quarterly cash distributions to common and preferred unitholders is as follows for the years ended December 31, 2025, 2024 and 2023. Our distributions are declared subsequent to quarter end; therefore, the following table represents total cash distributions applicable to the period in which the distributions were earned. See additional discussion in Item 8. Financial Statements and Supplementary Data – Note 8.


(In millions, except per unit data)	2025		2024		2023
Distribution declared:
Limited partner common units - public	$	1,506	$	1,339	$	1,152
Limited partner common units - MPC	2,632		2,339		2,104
Total distributions declared to limited partner common units	4,138		3,678		3,256
Series A preferred units	—		27		94
Series B preferred units	—		—		5
Total distribution declared	$	4,138	$	3,705	$	3,355
Cash distributions declared per limited partner common unit:
Quarter ended March 31,	$	0.9565	$	0.8500	$	0.7750
Quarter ended June 30,	0.9565		0.8500		0.7750
Quarter ended September 30,	1.0765		0.9565		0.8500
Quarter ended December 31,	1.0765		0.9565		0.8500
Year ended December 31,	$	4.0660	$	3.6130	$	3.2500

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Capital Expenditures

Our operations are capital intensive, requiring investments to expand, upgrade, enhance or maintain existing operations and to meet environmental and operational regulations. Our capital requirements consist of growth capital expenditures and maintenance capital expenditures. Growth capital expenditures are those incurred for acquisitions or capital improvements that we expect will increase our operating capacity for volumes gathered, processed, transported or fractionated, decrease operating expenses within our facilities or increase income from operations over the long term. Examples of growth capital expenditures include costs to develop or acquire additional pipeline, terminal, processing or storage capacity. In general, growth capital includes costs that are expected to generate additional or new cash flow for MPLX. In contrast, maintenance capital expenditures are expenditures made to replace partially or fully depreciated assets, to maintain the existing operating capacity of our assets and to extend their useful lives, or other capital expenditures that are incurred to maintain existing system volumes and related cash flows.

Our capital expenditures for the past three years are shown in the table below:


(In millions)	2025		2024		2023
Capital expenditures:
Growth capital expenditures	$	1,668	$	796	$	838
Growth capital reimbursements	(136)		(115)		(165)
Investments in unconsolidated affiliates(1)	794		236		98
Return of capital(2)	(251)		(12)		(3)
Capitalized interest	(38)		(16)		(14)
Total growth capital expenditures(3)	2,037		889		754

Maintenance capital expenditures	288		254		181
Maintenance capital reimbursements	(32)		(48)		(31)
Capitalized interest	(4)		(3)		(1)
Total maintenance capital expenditures	252		203		149

Total growth and maintenance capital expenditures	2,289		1,092		903
Investments in unconsolidated affiliates(1)	(794)		(236)		(98)
Return of capital(2)	251		12		3
Growth and maintenance capital reimbursements(4)	168		163		196
(Increase)/decrease in capital accruals	(170)		6		(82)
Capitalized interest	42		19		15
Other	22		—		—
Additions to property, plant and equipment	$	1,808	$	1,056	$	937

(1) Investments in unconsolidated affiliates and additions to property, plant and equipment, net are shown as separate lines within investing activities in the Consolidated Statements of Cash Flows. Investments in unconsolidated affiliates for the years ended December 31, 2025 and December 31, 2024 exclude payments associated with purchases of equity interests in unconsolidated affiliates totaling $213 million and $228 million, respectively.

(2) Return of capital for the year ended December 31, 2025 excludes $42 million in special distributions received in exchange for the contribution of assets to a joint venture. Return of capital for the year ended December 31, 2024 excludes a $134 million cash distribution in connection with the Whistler Joint Venture Transaction.

(3) Total growth capital expenditures exclude $3,316 million, $622 million and $246 million of acquisitions, net of cash acquired, in 2025, 2024 and 2023, respectively, and a $134 million cash distribution received in 2024 in connection with the Whistler Joint Venture Transaction. Total growth capital expenditures also exclude purchases of additional equity interests in unconsolidated affiliates of $213 million and $228 million for the years ended December 31, 2025 and December 31, 2024, respectively.

(4) Growth capital reimbursements are generally included in changes in deferred revenue within the operating activities section of the Consolidated Statements of Cash Flows. Maintenance capital reimbursements are included in the Contributions from MPC line within financing activities section of the Consolidated Statements of Cash Flows.

For 2026, we announced a capital outlook of $2.7 billion, net of reimbursements, and excluding potential acquisitions, if any, which includes growth capital of $2.4 billion and maintenance capital of $300 million. Our growth capital plans are focused on expanding our 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 our capital plan targets the debottlenecking of existing assets to meet customer demand. We continuously evaluate our capital plan and make changes as conditions warrant.

We participate in joint ventures, which, in turn, also invest in capital projects. Certain of our joint ventures fund capital expenditures with project debt financings at the joint venture level or with cash from operations. Growth capital projects funded through debt at the joint venture level or cash from operations of the joint venture do not require capital contributions by us

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unless otherwise noted. Our pro-rata share of these growth capital projects for our equity method investments that have been funded at the joint venture level for the periods presented are shown in the table below.


(In millions, except ownership percentages)	MPLX Ownership	2025		2024		2023
BANGL, LLC(1)	100%	$	60	$	160	$	20
MXP Parent, LLC(2)	10%	12		56		39
WPC Parent, LLC(3)	30%	270		5		96
All other		7		49		87
Total		$	349	$	270	$	242

(1) The year ended December 31, 2025 reflects activity through June 30, 2025, prior to the BANGL Acquisition.

(2) Includes growth capital for Matterhorn Express Pipeline.

(3) Disclosed amounts include growth capital related to WPC Parent, LLC, including the ADCC Pipeline lateral, Rio Bravo Pipeline, Whistler Pipeline and our indirect and 12.5 percent direct ownership interest in Blackcomb and Traverse Pipeline Holdings, LLC.

Project debt at the joint venture level is typically secured by the assets owned by the joint venture. In certain cases, MPLX’s interest in the joint venture, unless otherwise noted, is non-recourse to MPLX in excess of the value of MPLX’s investment in the joint venture. At December 31, 2025, debt held by our unconsolidated joint ventures based on our equity ownership percentage was $1.8 billion.

Cash Commitments

Our material cash requirements include the following contractual obligations and other cash commitments as of December 31, 2025.

Our contractual obligations primarily consist of outstanding borrowings on debt, commitment and administrative fees and interest. Additional information for third-party debt is included in Item 8. Financial Statements and Supplementary Data – Note 17. See Item 8. Financial Statements and Supplementary Data – Note 6 for additional information for the related party loan. Our cash commitment at December 31, 2025 was $43.4 billion, with $2.7 billion payable within 12 months. We intend to repay the short-term maturities with existing cash on hand, short-term borrowings under our revolving credit agreements or with the proceeds of new long-term debt, depending on, among other things, market conditions.

Our contractual commitment for co-location services agreements was $4.1 billion at December 31, 2025. These agreements obligate us to pay MPC for operational and other services provided to the subsidiaries of MPLX Operations LLC. The co-location services agreements have remaining terms up to 43 years.

Finance and operating leases relate primarily to facilities and equipment under lease, including ground leases, building space, office and field equipment, storage facilities and transportation equipment. See Item 8. Financial Statements and Supplementary Data – Note 21 for further discussion about our lease obligations. Our cash commitment at December 31, 2025 was $938 million.

We execute various third-party transportation, terminalling, and gathering and processing agreements that obligate us to minimum volume, throughput or payment commitments over the remaining terms, which range from less than one year to seven years. We expect to pass any minimum payment commitments through to producer customers. These agreements may include escalation clauses based on various inflationary indices; however, those potential increases have not been incorporated in minimum fees due under these agreements presented below. See Item 8. Financial Statements and Supplementary Data – Note 22 for further discussion. Our cash commitment for these agreements at December 31, 2025 was $509 million.

At December 31, 2025, our contractual commitment under contracts to acquire property, plant and equipment was $311 million.

Our other cash commitments consist of expense projects, right of way and easement obligations, natural gas purchase obligations and ARO commitments. These other cash commitments at December 31, 2025 totaled $358 million.

In addition, we have omnibus agreements and employee services agreements with MPC. One of the omnibus agreements with MPC addresses our payment of a fixed annual fee to MPC for the provision of executive management services by certain executive officers of our general partner and our reimbursement to MPC for the provision of certain general and administrative services to us.

We also pay MPC additional amounts based on the costs actually incurred by MPC in providing other services, except for the portion of the amount attributable to engineering services, which is based on the amounts actually incurred by MPC and its affiliates plus an incremental surcharge. In addition, we are obligated to reimburse MPC for most out-of-pocket costs and expenses incurred by MPC on our behalf.

MPLX has various employee agreements with MPC under which MPLX reimburses MPC for employee benefit expenses, along with the provision of operational and management services in support of both our Crude Oil and Products Logistics and Natural Gas and NGL Services segments’ operations.

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We incurred $2.1 billion of costs under various agreements with MPC, including the omnibus, co-location and employee service agreements for 2025.

Effects of Inflation

Inflation did not have a material impact on our results of operations for the years ended December 31, 2025, 2024 or 2023. We have observed higher costs for labor and materials used in our business during the year ended December 31, 2025. Many of our agreements provide for inflation-based adjustments, including the Producer Price Index-FG, Consumer Price Index or the FERC index. To the extent permitted by competition, regulation and our existing agreements, we have and expect to continue to pass along a portion of increased costs to our customers in the form of higher fees.

TRANSACTIONS WITH RELATED PARTIES

As of December 31, 2025, MPC owned our general partner and an approximate 64 percent limited partner interest in us. We perform a variety of services for MPC related to the transportation of crude and refined products, including renewables, via pipeline or marine, as well as terminal services, storage services and fuels distribution and marketing services, among others. The services that we provide may be based on regulated tariff rates or on contracted rates. In addition, MPC performs certain services for us related to information technology, engineering, legal, accounting, treasury, human resources and other administrative services. For further discussion of agreements and activity with MPC and related parties see Item 1. Business and Item 8. Financial Statements and Supplementary Data – Note 6.

Excluding significant non-cash items, MPC accounted for 48 percent, 49 percent and 50 percent of our total revenues and other income for the years ended December 31, 2025, 2024 and 2023, respectively. Of our total costs and expenses, MPC accounted for 26 percent, 27 percent and 27 percent for the years ended December 31, 2025, 2024 and 2023, respectively.

ENVIRONMENTAL MATTERS AND COMPLIANCE COSTS

We are subject to extensive federal, state and local environmental laws and regulations. These laws, which change frequently, regulate the discharge of materials into the environment or otherwise relate to protection of the environment. Compliance with these laws and regulations may require us to remediate environmental damage from any discharge of hazardous, petroleum or chemical substances from our facilities or require us to install additional pollution control equipment on our equipment and facilities. Our failure to comply with these or any other environmental or safety-related regulations could result in the assessment of administrative, civil or criminal penalties, the imposition of investigatory and remedial liabilities, and the issuance of injunctions that may subject us to additional operational constraints.

Future expenditures may be required to comply with the CAA and other federal, state and local requirements for our various facilities. The impact of these legislative and regulatory developments, if enacted or adopted, could result in increased compliance costs and additional operating restrictions on our business, each of which could have an adverse impact on our financial position, results of operations and liquidity. We expect that certain of these costs will be subject to indemnification by MPC.

Legislation and regulations pertaining to 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.

We have incurred and may continue to incur substantial capital, operating and maintenance, and remediation expenditures as a result of these environmental laws and regulations. If these expenditures, as with all costs, are not ultimately reflected in the fees and tariff rates we receive for our 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, but not limited to, the age and location of its operating facilities. Our environmental expenditures for each of the past three years were:


(In millions, except %)	2025		2024	2023
Capital	$	74

MPLX LP 10-K