# MPLX LP: Form 10-K for the period ended Dec 31, 2023

- Company: [MPLX LP](/companies/mplx.md) (CIK 1552000)
- Form: 10-K
- Filed: 2024-02-28
- Accepted by EDGAR: Feb 28, 2024, 14:35 ET
- Period: 2023-12-31
- Accession: 0001552000-24-000007
- Inline XBRL: yes
- Main document: https://www.sec.gov/Archives/edgar/data/1552000/000155200024000007/mplx-20231231.htm
- All documents and exhibits: https://www.sec.gov/Archives/edgar/data/1552000/000155200024000007/

## Figures reported in this filing

Standardized XBRL line items for the period ended 2023-12-31.

| Line item | Period | Value | XBRL concept |
| --- | --- | ---: | --- |
| Revenue | 12 months, 2023-01-01 to 2023-12-31 | $8.73bn | us-gaap:RevenueFromContractWithCustomerExcludingAssessedTax |
| Operating income | 12 months, 2023-01-01 to 2023-12-31 | $4.90bn | us-gaap:OperatingIncomeLoss |
| Income tax | 12 months, 2023-01-01 to 2023-12-31 | $11.0m | us-gaap:IncomeTaxExpenseBenefit |
| Net income | 12 months, 2023-01-01 to 2023-12-31 | $3.93bn | us-gaap:NetIncomeLoss |
| Operating cash flow | 12 months, 2023-01-01 to 2023-12-31 | $5.40bn | us-gaap:NetCashProvidedByUsedInOperatingActivities |
| Capital expenditure | 12 months, 2023-01-01 to 2023-12-31 | $937.0m | us-gaap:PaymentsToAcquirePropertyPlantAndEquipment |
| Share repurchases | 12 months, 2023-01-01 to 2023-12-31 | $0 | us-gaap:PaymentsForRepurchaseOfCommonStock |
| Cash and equivalents | at 2023-12-31 | $1.05bn | us-gaap:CashAndCashEquivalentsAtCarryingValue |
| Current assets | at 2023-12-31 | $2.81bn | us-gaap:AssetsCurrent |
| Total assets | at 2023-12-31 | $36.53bn | us-gaap:Assets |
| Current liabilities | at 2023-12-31 | $2.62bn | us-gaap:LiabilitiesCurrent |
| Total liabilities | at 2023-12-31 | $22.95bn | us-gaap:Liabilities |
| Current portion of debt | at 2023-12-31 | $1.14bn | us-gaap:DebtCurrent |

## Business

As filed, 85,704 characters.

### 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 processing and fractionation facilities. Our assets are positioned throughout the United States. The business consists of two segments based on the nature of services it offers: Logistics and Storage (“L&S”) and Gathering and Processing (“G&P”). The L&S segment primarily engages in the gathering, transportation, storage and distribution of crude oil, refined products, other hydrocarbon-based products, and renewables. The L&S segment also includes the operation of our refining logistics, fuels distribution and inland marine businesses, terminals, rail facilities and storage caverns. The G&P segment provides gathering, processing and transportation of natural gas as well as the transportation, fractionation, storage and marketing of 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, 2023:

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, 2023, MPC owned our general partner and approximately 65 percent of our outstanding common units. In 2023, MPC accounted for 50 percent of our total revenues and other income, primarily within our L&S 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.

MPLX remains guided by its strategic priorities of strict capital discipline, fostering a low-cost culture, and optimizing our asset portfolio. We continuously evaluate our portfolio to identify opportunities to develop, expand, debottleneck and participate in projects that complement our existing assets, assess strategic acquisitions, and ensure we are optimizing all assets in the portfolio. This includes positioning the MPLX portfolio and capabilities to be successful through the energy evolution.

### 2023 RESULTS

The following table summarizes the operating performance for each segment for the year ended December 31, 2023. 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.

### RECENT DEVELOPMENTS

- On January 24, 2024, we announced the board of directors of our general partner declared a distribution of $0.85 per common unit that was paid on February 14, 2024 to common unitholders of record on February 5, 2024.

### BUSINESS STRATEGIES

*Maintain Safe and Reliable Operations:* We are committed to maintaining and improving the safety, reliability and efficiency of our operations and promoting high standards for safety and environmental stewardship. Providing safe, reliable and efficient services is also a key component in generating stable cash flows.

*Grow Stable Cash Flows While Maintaining Strict Capital Discipline*: 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.

*Focus on Low-Cost Culture*: We are committed to achieving operational excellence by reducing costs, improving efficiency, and driving operational improvements. 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 fostering a low-cost culture, 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.

*Commitment to Sustainability*: Our approach to sustainability spans the environmental, social and governance dimensions of our business. That means strengthening resiliency by lowering carbon intensity and conserving natural resources; innovating for the future by investing in renewables and emerging technologies; and embedding sustainability in decision-making and in how we engage our people and many stakeholders. We are progressing towards meeting our 2025 and 2030 methane intensity reduction goals, as well as our biodiversity target, by applying sustainable landscapes to our compatible right of ways.

### ORGANIZATIONAL STRUCTURE

The following diagram depicts our organizational structure and MPC’s ownership interest in us as of February 23, 2024.

We are an MLP with outstanding common units held by MPC and public unitholders as well as preferred units. Our common units are publicly traded on the NYSE under the symbol “MPLX.” Our Series A preferred units rank senior to all common units. The holders of the Series A preferred units are entitled to receive a quarterly distribution equal to the greater of $0.528125 per unit or the amount of distributions they would have received on an as converted basis. Our 6.875 percent Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units (the “Series B preferred units”) were redeemed on February 15, 2023 and are no longer outstanding.

### INDUSTRY OVERVIEW

As of December 31, 2023, our diversified services in the midstream sector broken down by our segments are as follows:

### L&S:

The midstream sector plays a crucial role in the oil and gas industry by providing gathering, transportation, terminalling, storage and marketing services as depicted 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 over-the-road modes of 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, caverns, and tanks at refineries and terminals. The ability to store various products provides flexibility and logistics optionality which allows participants within the industry to take advantage of changing market conditions.

### G&P:

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 and further described below:

- *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.
- *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 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 operations in two reportable segments, which include L&S and G&P. Each of these segments is organized and managed based upon the nature of the products and services it offers.

### L&S:

The L&S segment includes gathering, transportation, storage and distribution of crude oil, refined products, other hydrocarbon-based products and renewables. These assets consist of a network of 15,361 miles of wholly and jointly-owned common carrier pipelines and associated storage assets, refining logistics assets at 13 refineries, 88 terminals including one export terminal, storage caverns, tank farm assets including rail and truck racks, an inland marine business and a fuels distribution business. For information related to our L&S assets, please see Item 2. Properties - Logistics and Storage. Our L&S 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 L&S 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, 2023, approximately 87 percent of L&S segment revenues and other income was generated from MPC.

### G&P:

The G&P segment gathers, processes and transports natural gas; and transports, fractionates, stores and markets NGLs. As of December 31, 2023, gathering and processing assets available to MPLX included approximately 9.7 Bcf/d of gathering capacity, 12.0 Bcf/d of natural gas processing capacity and 829 mbpd of fractionation and de-ethanization capacity. For a summary of our gas processing facilities, fractionation facilities, natural gas gathering systems, NGL pipelines and natural gas pipelines see Item 2. Properties - Gathering and Processing.

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, 2023, revenues with one customer primarily related to these NGL transactions in the Southwest region accounted for approximately 21 percent of G&P 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 G&P segment revenues. Neither of these customers was 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.

### 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 65 percent of the outstanding common units of MPLX as of December 31, 2023. 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 existing value chains that benefit both MPC and MPLX.

### OUR L&S CONTRACTS WITH MPC AND THIRD PARTIES

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

Our L&S 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, other than under our marine transportation services agreement, most of these agreements include minimum committed volumes from MPC. MPC has also committed to pay a fixed fee for 100 percent of available capacity for boats, barges and third-party chartered equipment under the marine transportation services agreements. 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 2024:

| Agreement Transportation Services (mbpd): | Initial Term (years) | MPC minimum commitment |
| --- | --- | ---: |
| Crude pipelines(1) | 4 - 10 | 1,875 |
| Refined product pipelines(2) | 1 - 15 | 1,549 |
| Marine(3) | 5 - 6 | N/A |
| **Storage Services (mbbls):** |  |  |
| Tank Farms(4) | 2 - 12 | 131,279 |
| Caverns(5) | 10 - 17 | 3,632 |
| **Terminal Services(6) (mbpd)** | Various | 1,995 |
| **Fuels Distribution Services(7) (millions of gallons per year)** | 10 | 23,449 |

(1) Commitments are adjusted for crude viscosity. 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. These agreements are each subject to one remaining renewal period of five years.

(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 vary and range from zero to 10 years. 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 initiated in February 2018 and includes one additional five-year renewal term.

Under transportation services agreements containing minimum volume commitments, if MPC fails to transport its minimum throughput volumes during any period, then 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, then 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.

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 indexes 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.

### Pipeline Operating Agreements with Third Parties

We maintain and operate six 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 renewal 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.

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 incurred arising out of those remediation obligations.

### OUR G&P CONTRACTS WITH MPC AND THIRD PARTIES

The majority of our revenues in the G&P segment are generated from natural gas gathering, transportation and processing; and NGL transportation, fractionation, exchange, 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 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 oil, natural gas and NGL prices. Any change in mix may influence our long-term financial results.

### Keep-whole agreement with MPC

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

### COMPETITION

Within our L&S 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 from 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 reduced 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 G&P 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 G&P competitors include:

- natural gas midstream providers, of varying financial resources and experience, that gather, 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.

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 enhances 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. We are insured under MPC and other third-party insurance policies. The MPC policies are subject to shared deductibles.

### 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 effects of seasonality on our L&S segment’s revenues are mitigated through the use of fee-based transportation and storage services agreements with MPC that include minimum volume commitments.

In our G&P 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. We are able to manage the seasonality impacts through the execution of our marketing strategy. 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 Federal Energy Regulatory Commission (“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.

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

FERC permits regulated oil pipelines to change their rates within prescribed ceiling levels that are tied to an inflation index. A carrier must, as a general rule, utilize the indexing methodology to change its rates. Cost-of-service ratemaking, market-based rates and settlement rates are alternatives to the indexing approach and may be used in certain specified circumstances to change rates.

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.

#### 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. EPAct 2005 gives the FERC civil penalty authority to impose penalties for certain violations of up to approximately $1.5 million per day for each violation, subject to FERC’s annual inflation adjustment. FERC also has the authority to order disgorgement of profits from transactions deemed to violate the NGA and 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, including inspecting and reburying pipelines in the Gulf of Mexico and its inlets, 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.

Notwithstanding the foregoing, PHMSA and one or more state regulators have, in isolated circumstances in the past, sought to expand the scope of their regulatory inspections to include certain in-plant equipment and pipelines found within NGL fractionation facilities and associated storage facilities in order to assess compliance with hazardous liquids pipeline safety requirements. If any of these actions were made broadly enforceable as part of a rule-making process or codified into law, they could result in additional capital costs, possible operational delays and increased costs of operation.

### 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 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.

On September 6, 2022, EPA issued a notice of proposed rulemaking that would designate Perfluorooctanoic Acid (“PFOA”) and Perfluorooctane Sulfonate (“PFOS”) as hazardous substances under CERCLA Section 102(a). EPA indicates it will issue a final action during the first quarter of 2024. In addition, EPA has received three petitions requesting regulatory action on 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 potential statutes or regulations on our remediation costs.

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

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

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

In May 2016, EPA issued lifetime health advisory levels (“HALs”) and health effects support documents for two PFAS substances - PFOA and PFOS. These HALs were updated in June 2022, when EPA also issued HALs for two additional PFAS substances. In February 2019, EPA issued a PFAS Action Plan identifying actions it is planning to take to study and regulate various PFAS chemicals. EPA identified that it would evaluate, among other actions, (1) proposing national drinking water standards for PFOA and PFOS, (2) developing cleanup recommendations for PFOA and PFOS, (3) evaluating listing PFOA and PFOS as hazardous substances under CERCLA, and (4) conducting toxicity assessments for other PFAS chemicals. On December 5, 2022, EPA issued to states and EPA regional offices a memorandum providing guidance for addressing PFAS discharges in wastewater and stormwater. Also, on March 29, 2023, EPA issued a notice of proposed rulemaking to establish national drinking water standards for PFOS, PFOA, perfluorohexane sulfonic acid , perfluorononanoic acid, PFBS, and hexafluoropropylene oxide dimer acid and its ammonium salt (also known as “GenX”). EPA indicates it will issue a final rule in late 2024. Congress may also take further action to regulate PFAS. We cannot currently predict the impact of potential statutes or regulations on our operations. In addition, many states are actively proposing and adopting legislation and regulations relating to the use of AFFFs containing PFAS. Additionally, many states are using EPA HALs for PFOS and PFOA and some states are adopting and proposing state-specific drinking water and cleanup standards for various PFAS, including but not limited to PFOS and PFOA. We cannot currently predict the impact of these regulations on our liquidity, financial position, or results of operations.

#### Air Emissions

The Clean Air Act (“CAA”) and comparable state laws restrict the emission of air pollutants from many sources, including processing plants and compressor stations, and also 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 in the future for installation of air pollution control equipment and 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, EPA released a final rule to lower the primary fine particulate matter annual standard from its current level of 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. 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. 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 amended regulation has been challenged in court and could impact the compliance timeline. Compliance with the regulation is expected to increase our costs at affected facilities.

#### Climate Change

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

Congress has from time to time considered legislation to reduce emissions of GHGs, and it is possible that such legislation could be enacted in the future. In the absence of federal climate legislation in the United States, 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, such as electric power plants, 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, 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. The Council on Environmental Quality has sought comment on the extent to which an environmental assessment must consider direct and indirect GHG emissions from a new project and is undergoing a two phase process for updating its regulations for implementing the National Environmental Policy Act. Uncertainty related to the environmental assessment can result in delay and increased costs in completing new projects.

On December 2, 2023, EPA issued its final rule to regulate methane emissions from the Oil and Natural Gas Sector. The rule titled “Standards of Performance for New, Reconstructed, and Modified Sources and Emissions Guidelines for Existing Sources: Oil and Gas Sector Climate Review” requires MPLX to control and reduce methane emissions within its natural gas gathering and boosting operations and gas processing facilities. The rule is consistent with the voluntary methane reduction programs that MPLX has been implementing through its Focus on Methane Program. As a result, although the rule requires MPLX to make additional investments to further reduce methane emissions, we do not believe the rule will have a material impact to our operations.

The Inflation Reduction Act of 2022 includes a charge on methane emissions above a certain threshold for facilities that report their GHG emissions under the EPA's Greenhouse Gas Emissions Reporting Program Part 98 regulations. The charge starts at $900 per metric ton of methane in 2024, $1,200 per metric ton in 2025, and increasing to $1,500 per metric ton in 2026 and beyond. 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 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, 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 amended, 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 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.

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 deems that such action is necessary in the interest of national defense. For example, the Secretary 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

Certain of our facilities are subject to the Department of Homeland Security Chemical Facility Anti-Terrorism Standards, which expired on July 28, 2023. Congress has introduced bills that, if passed, would extend the program. We also have several facilities that are subject to the United States Coast Guard’s Maritime Transportation Security Act, and a number of other facilities that are subject to the Transportation Security Administration’s Pipeline Security Guidelines and are designated as “Critical Facilities.” We have an internal inspection program designed to monitor and ensure compliance with all of these requirements. We believe that we are in material compliance with all applicable laws and regulations regarding the security of our facilities.

#### Tribal Lands

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

### 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 the 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, 2023, our general partner and its affiliates, had approximately 5,810 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 metrics include several employee, process and environmental safety metrics.

#### Talent Management

MPC’s People Strategy holistically addresses the dynamic business environment it operates in. It enables MPC to be an employer of choice with the best people and the right capabilities supporting its inclusive culture. Executing this People Strategy requires that it attracts and retains the best talent. Attracting and retaining top talent involves presenting new employees with the tools for success and providing opportunities for long-term engagement and career advancement. 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 diverse candidate brings a new perspective to its workforce, and it actively seeks candidates with a variety of backgrounds and experience.

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, 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 employees through the Marathon Petroleum Scholars Program. Both full-time and part-time employees are eligible for these benefits.

#### Inclusion

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

MPC promotes cultural inclusivity and respect among its employees. It recognizes that when employees feel valued, it shows in their performance. MPC’s employee networks are fundamental to achieving this goal and connect employees with others who have a shared identity and life experiences. These seven groups use a member and ally model to promote inclusion— Asian, Black, Hispanic, LGBTQ+, Veterans, Women and People with Disabilities. Led by employees with involvement and support from executive sponsors, MPC’s networks connect colleagues from across the company 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.

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 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.

## Risk factors

As filed, 113,557 characters.

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

### 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 oil and natural gas production in our areas of operation;
- challenges in accurately estimating expected production volumes of our producer customers;
- our dependence on third parties for the 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, 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;
- 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 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 oil and natural gas production in our areas of operation may adversely affect our business, financial condition, results of operation 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 local demand, production levels, changes in interstate pipeline gas quality specifications, imports and exports, seasonality and weather conditions, alternative energy sources such as wind, solar and other renewable energy technologies, economic and political conditions domestically and internationally and governmental regulations. Sustained periods of low prices could result in producers deciding to limit their oil and gas drilling operations, which could substantially delay the production and delivery of volumes of oil, natural gas and NGLs to 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 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 the purchases and then the subsequent sales. The significant volatility in natural gas, NGL and 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 oil, natural gas, NGL or refined product supplies committed to any new facility prior to its construction. We may construct facilities to capture anticipated future growth in production or satisfy anticipated market demand which does not materialize, the facilities may not operate as planned, or the facilities may be underutilized. In order to attract additional 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 oil, natural gas, NGLs or refined products to achieve our expected investment return. Alternatively, 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 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 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 oil, natural gas, NGLs and refined products comes from a limited number of key producers/suppliers, who may be under no obligation to deliver a specific volume to our facilities. If any of these significant suppliers, or a significant number of smaller producers, were to decrease the supply of 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. Because our operating costs are primarily fixed, a reduction in the volumes delivered to us would result not only in a reduction of revenues, but also a decline in 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 end-users purchase natural gas from more than one natural gas company and have the ability to change providers at any time. Some of these end-users also have the ability to switch between gas and alternative fuels in response to relative price fluctuations in the market. Because there are numerous companies of greatly varying size and financial capacity that compete with us in the marketing of natural gas, we often compete in the end-user and utilities markets primarily on the basis of price. The inability of our management to renew or replace our current contracts as they expire and to respond appropriately to changing market conditions could affect our profitability.

***The fees charged to third parties under our gathering, 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 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 conditions.***

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 risks 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.

### We may be negatively impacted by inflation.

Increases in inflation may have an adverse effect on us. Current and future inflationary effects may be driven by, among other things, supply chain disruptions and governmental stimulus or fiscal policies. Continuing increases in inflation could impact the commodity markets generally, the overall demand for our products and services, our costs for labor, material and services and the margins we are able to realize on our products 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 personally identifiable information such as employee, customer and investor data, and to manage or support a variety of business processes, including our supply chain, pipeline operations, gathering and processing operations, financial transactions, banking and numerous other processes and transactions.

Our information systems (and those of our third-party business partners and service providers), including our cloud computing environments and operational technology environments, are subject to numerous and evolving cybersecurity threats and attacks, including ransomware and other malware, and phishing and social engineering schemes, supply chain attacks, and advanced artificial intelligence cyberattacks, which can compromise our ability to operate, and the confidentiality, availability, and integrity of data in our systems or those of our third-party business partners and service providers. These and other cybersecurity threats may originate with criminal attackers, advanced persistent threats and nation-state actors, state-sponsored actors, or employee error or malfeasance. Because the techniques used to obtain unauthorized access, or to disable or degrade systems continuously evolve and have become increasingly complex and sophisticated, and can remain undetected for a period of time despite efforts to detect and respond in a timely manner, we (and our third-party business partners and service providers) are subject to the risk of cyberattacks.

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

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

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

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

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

Refining, gathering and processing, pipeline and terminal infrastructure, and other energy assets, may be the subject of terrorist attacks or other targeted operational disruptions. Any terrorist attack or targeted disruption of our operations, those of our customers or, in some cases, those of other energy industry participants, could have a material and adverse effect on our business. Similarly, any similar event that severely disrupts the markets we serve could materially and adversely affect our results of operations, financial position and cash flows.

***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, fractionator 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. For example, in 2021, MPC’s Galveston Bay refinery was adversely affected by Winter Storm Uri and MPC’s Garyville refinery was adversely affected by Hurricane Ida. The occurrence of these and similar events have had, and may in the future have, an adverse effect on our assets and operations. We have incurred and will continue to incur additional costs to protect our assets and operations from such physical risks and employ the evolving technologies and processes available to mitigate such risks. To the extent such severe weather events or other climate conditions increase in frequency and severity, we may be required to modify operations and incur costs that could materially and adversely affect our business, financial condition, results of operations and cash flows.

### 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 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, which impact the effectiveness of our hedging program; 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 enhancement 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 $20.7 billion as of December 31, 2023, including amounts, if any, outstanding under our loan agreement with a wholly owned subsidiary of MPC. We may incur significant debt obligations in the future. Our indebtedness may impose 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 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 a wholly owned subsidiary of 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.

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 and our ability to issue equity or incur debt for acquisitions or other purposes and to make distributions at our intended levels.

***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 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 reduce our ability to make distributions to our unitholders.

***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.

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

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

As of December 31, 2023, our balance sheet reflected $7.6 billion and $654 million 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.

### Legal and Regulatory Risks

***We expect to continue to incur substantial capital expenditures and operating costs to meet the requirements of evolving environmental or other laws or regulations. Future environmental laws and regulations may impact our current business plans and reduce demand for our products and services.***

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

- the emission or discharge of materials into the environment;
- solid and hazardous waste management;
- the regulatory classification of materials currently or formerly used in our business;
- pollution prevention;
- GHG emissions;
- climate change;
- public and employee safety and health;
- permitting;
- inherently safer technology; and
- facility security.

The specific impact of laws and regulations, and their enforcement, 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 may also face liability for personal injury, property damage, natural resource damage or clean-up costs due to alleged contamination and/or exposure to chemicals such as benzene and MTBE. There is also increased regulatory interest in PFAS, which we expect will lead to increased monitoring obligations and potential liability related thereto. Such expenditures could materially and adversely affect our business, financial condition, results of operations and cash flows.

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

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

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

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

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 are also considering ordinances that would prohibit construction or expansion of 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.

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

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

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

Governmental and other entities in various U.S. states have filed lawsuits against various energy companies, including MPC, upon which we depend for a substantial portion of our business. The lawsuits allege damages as a result of climate change and the plaintiffs are seeking unspecified damages and abatement under various tort theories. Similar lawsuits may be filed in other jurisdictions. 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, has been subject to, and may in the future be subject to, litigation seeking a permanent shutdown of the pipeline. There remains a high degree of uncertainty regarding the ultimate outcome of these types of proceedings, as well as their potential effect on our business, financial condition, results of operation and cash flows.

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

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

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

***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.

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

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

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

In recent years, increasing attention has been given to corporate activities related to ESG matters in public discourse and the investment community, including climate change, energy transition matters, and diversity, equity and inclusion. A number of advocacy groups, both domestically and internationally, have campaigned for governmental and private action to promote ESG-related change at public companies, including, but not limited to, through the investment and voting practices of investment advisers, pension funds, universities and other members of the investing community. These activities include increasing attention and demands for action related to climate change and energy transition matters, such as promoting the use of substitutes to fossil fuel products and encouraging the divestment of fossil fuel equities, as well as pressuring lenders and other financial services companies to limit or curtail activities with fossil fuel companies. If this were to continue, it could have a material adverse effect on our access to capital. Members of the investment community have begun to screen companies such as ours for sustainability performance, including practices related to GHG emission reduction and energy transition strategies. If we are unable to find economically viable, as well as publicly acceptable, solutions that reduce our GHG emissions, reduce GHG intensity for new and existing projects, increase our non-fossil fuel product portfolio, and/or address other ESG-related stakeholder concerns, we could experience additional costs or financial penalties, delayed or cancelled projects, or adverse unit price impacts, which could have a material and adverse effect on our business and results of operations. 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. In 2022, MPLX established a target to reduce methane emissions intensity and MPC, MPLX’s largest customer, has established a target to reduce GHG emissions. 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 and 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, including the SEC’s proposed disclosure requirements regarding, among other matters, GHG emissions, we may have to undertake additional costs to control, assess and report on ESG metrics. Our failure or perceived failure to pursue or fulfill such goals and targets or to satisfy various reporting standards within the timelines we announce, or at all, could have a negative impact on investor sentiment, ratings outcomes for evaluating our approach to ESG matters, 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 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 financial position or results of operations and 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 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.

***Future acquisitions will involve the integration of new assets or businesses and may present substantial risks that could adversely affect our business, financial conditions, results of operations and cash flows.***

Future transactions involving the addition of new assets or businesses will present potential 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 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 the pursuit of 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, 2023, MPC had consolidated long-term indebtedness of approximately $27.6 billion, of which $6.9 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 ability to grow our business and 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.

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.

***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 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” is generally 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 is also computed without regard to any depreciation or amortization.

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 23, 2024. 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;
- 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 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 its fiduciary 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 23, 2024, 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. 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 23, 2024, 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.

***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.

## Cybersecurity

As filed, 5,643 characters.

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.

### 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 cybersecurity risks and include, but are not limited to:

- placing security limits on physical and network access to our information technology (“IT”) and operating technology (“OT”) systems;
- employing internal IT and OT controls designed to detect cybersecurity threats by collecting and analyzing data in 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 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 MPC’s cybersecurity practices, including a periodical assessment of our cybersecurity program 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, protect, detect, respond and recover from 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 28, 2024, we do not believe that any past cybersecurity incidents have had, or are reasonably likely to have, a material adverse effect on the company, including our business, operations or financial condition. However, there can be no assurance that MPC’s cybersecurity processes will prevent or mitigate cybersecurity incidents or threats and that efforts will always be successful. It is possible that these events may occur and could have a material adverse effect on our business, operations or financial condition. See “Business and Operational Risks--We are increasingly dependent on the performance of our information technology systems and those of our third-party business partners and service providers” in Item 1A. Risk Factors of this Annual Report on Form 10-K.

### Governance

The full Board of Directors of MPLX GP oversees enterprise-level risks and has delegated to the Audit Committee of the MPLX GP Board oversight of 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 provides regular cybersecurity briefings to the MPLX GP Board of Directors and the MPLX GP Audit Committee as needed, with a minimum of two briefings per year. The MPLX GP Audit Committee further reviews and provides input on our cybersecurity and information security strategy.

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

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.

## Properties

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### LOGISTICS AND STORAGE

### Crude Oil and Refined Product Pipelines

The following table sets forth information regarding our crude oil and refined product pipeline systems as of December 31, 2023.

|  | Diameter | Length (miles) |
| --- | --- | ---: |
| Crude Systems(1) | 2" - 42" | 5,159 |
| Refined Product Systems(2) | 4" - 36" | 3,788 |

(1) Includes approximately 16 miles of pipeline leased from third parties and 1,192 miles of inactive pipeline.

(2) Includes approximately 2 miles of pipeline leased from third parties, 201 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, 2023.

| Crude Systems: | Diameter | Length (miles) | Ownership Percentage |
| --- | --- | ---: | ---: |
| 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% |
| Natural Gas and NGL Systems: |  |  |  |
| Whistler Pipeline LLC(4) | 36" - 42" | 498 | 38% |
| BANGL LLC(5) | 12" - 24" | 109 | 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 15 percent indirect interest in a joint venture that has partial ownership of the Wink to Webster pipeline system.

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

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

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

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

### Terminal Assets

The following table sets forth certain information regarding our owned and operated terminals as of December 31, 2023.

| Owned and Operated Terminals(1) Refined Product Terminals: | Number of Terminals | Tank Shell Capacity (mbbls) | Number of Tanks |
| --- | ---: | ---: | ---: |
| Alabama | 2 | 443 | 16 |
| Alaska | 3 | 1,540 | 35 |
| California | 8 | 3,484 | 67 |
| Florida | 3 | 2,265 | 48 |
| Georgia | 4 | 982 | 30 |
| Idaho | 3 | 999 | 49 |
| Illinois | 2 | 562 | 15 |
| Indiana | 7 | 3,770 | 68 |
| Kentucky | 6 | 2,587 | 56 |
| Louisiana | 2 | 5,469 | 53 |
| Michigan | 8 | 2,440 | 73 |
| Minnesota | 1 | 13 | 5 |
| New Mexico | 2 | 470 | 21 |
| North Carolina | 3 | 1,343 | 26 |
| North Dakota | 1 | — | — |
| Ohio | 12 | 3,144 | 99 |
| Pennsylvania | 1 | 390 | 12 |
| South Carolina | 1 | 371 | 8 |
| Tennessee | 4 | 1,149 | 30 |
| Texas | 1 | 76 | 15 |
| Utah | 1 | 21 | 2 |
| Washington | 4 | 920 | 25 |
| West Virginia | 2 | 1,564 | 24 |
| Total Refined Product Terminals | 81 | 34,002 | 777 |
| Asphalt Terminals: |  |  |  |
| Arizona | 3 | 556 | 60 |
| Minnesota | 1 | — | — |
| Nevada(2) | 1 | 283 | 19 |
| New Mexico | 1 | 38 | 9 |
| Texas | 1 | 197 | 20 |
| Total Asphalt Terminals | 7 | 1,074 | 108 |
| Total Terminals | 88 | 35,076 | 885 |

(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, 2023. The marine business currently has an associated transportation service agreement with MPC.

| Marine Vessels | Number of Boats and Barges | Capacity (mbbls) |
| --- | ---: | ---: |
| Inland tank barges | 305 | 8,123 |
| Inland towboats | 29 | 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 towing vessels, barges and local terminal facilities.

### Refining Logistics Assets

The following table outlines the tankage owned by us, serving MPC’s refineries as of December 31, 2023. 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.

| MPC Refining Logistics Assets | Tank Capacity (mbbls) |
| --- | ---: |
| Galveston Bay, Texas City, Texas | 18,977 |
| Garyville, Louisiana | 16,466 |
| Los Angeles, California | 14,242 |
| Robinson, Illinois | 6,913 |
| Anacortes, Washington | 5,448 |
| Catlettsburg, Kentucky | 5,098 |
| Detroit, Michigan | 5,006 |
| El Paso, Texas | 5,084 |
| St. Paul Park, Minnesota | 3,983 |
| Kenai, Alaska | 3,488 |
| Mandan, North Dakota | 3,180 |
| Canton, Ohio | 2,695 |
| Salt Lake City, Utah | 2,139 |
| Total | 92,719 |

MPC formed the Martinez Renewables joint venture and began producing renewable diesel at the Martinez facility in 2023. MPLX owns refining logistics assets with 5,977 mbbls of storage capacity associated with the facility, and has entered into terminalling and storage service agreements with the joint venture and its partners to provide services for the facility.

### Other L&S Assets

MPLX owns and operates various other midstream assets, including 31 barge docks with a total capacity of 4,859 mbpd and 8 storage caverns with a storage commitment of 3,632 mbbls. As of December 31, 2023, 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 33,452 mbbls. Our operations also include a renewable fuels rail loading hub in North Dakota with 180 mbbls of storage capacity, and more than 100 miles of water pipeline systems in North Dakota and Wyoming 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.

### GATHERING AND PROCESSING

The following tables set forth certain information relating to our consolidated and operated joint venture gas processing facilities, fractionation facilities, natural gas gathering systems, NGL pipelines and natural gas pipelines as of and for the year ended December 31, 2023. See further discussion about our joint ventures in Item 8. Financial Statements and Supplementary Data - Note 5.

### Gas Processing Complexes

| Region | Design Throughput Capacity (MMcf/d) | Natural Gas Throughput(1) (MMcf/d) | Utilization of Design Capacity(1) |
| --- | ---: | ---: | ---: |
| Marcellus Operations | 6,320 | 5,773 | 91% |
| Utica Operations | 1,325 | 564 | 43% |
| Southwest Operations(2) | 2,545 | 1,772 | 70% |
| Southern Appalachia Operations | 495 | 216 | 44% |
| Bakken Operations(3) | 185 | 163 | 88% |
| Rockies Operations | 1,177 | 483 | 41% |
| Total Gas Processing | 12,047 | 8,971 | 74% |

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

(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 159 MMcf/d representing our share of processed volumes is also included and used to compute the utilization presented above.

(3) 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 | 323 | 78% |
| Utica Operations(2)(3)(4) | — | — | —% |
| Southern Appalachia Operations(2)(5) | 24 | 11 | 46% |
| Bakken Operations | 33 | 20 | 61% |
| Rockies Operations | 5 | 3 | 60% |
| Total C3+ Fractionation | 475 | 357 | 75% |

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

(2) Certain complexes have above-ground NGL storage with a usable capacity of 1,334 thousand barrels.

(3) The capacity, throughput and utilization of design capacity at the Hopedale fractionation complex is presented in the Marcellus Operations totals, however, the Hopedale fractionation complex is jointly owned by MarkWest Ohio Fractionation Company, L.L.C. (“Ohio Fractionation”) and MarkWest Utica EMG, L.L.C. (“MarkWest Utica EMG”). Ohio Fractionation is a joint venture between MarkWest Liberty Midstream & Resources, L.L.C. (“MarkWest Liberty Midstream”) and Sherwood Midstream (a joint venture between MarkWest Liberty Midstream and Antero Midstream LLC). MarkWest Liberty Midstream and Sherwood Midstream are entities that operate in the Marcellus region, and MarkWest Utica EMG is an entity that operates in the Utica region. During the year ended December 31, 2023, the Marcellus Operations and Utica Operations utilized an average of 89 percent and 11 percent of the Hopedale fractionation complex, respectively. Additionally, Sherwood Midstream has the right to fractionation revenue and the obligation to pay expenses related to 40 mbpd of capacity in the Hopedale 3 and 4 fractionators.

(4) We operate a condensate stabilization facility with a capacity of 23 mbpd and 77 thousand barrels of condensate storage that is owned by a joint venture in which we have a 62 percent ownership interest. Actual NGL throughput at this facility was 13 mbpd for the year ended December 31, 2023.

(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.

### De-ethanization Facilities

| Region | Design Throughput Capacity (mbpd) | NGL Throughput(1) (mbpd) | Utilization of Design Capacity(1) |
| --- | ---: | ---: | ---: |
| Marcellus Operations | 309 | 233 | 75% |
| Utica Operations | 40 | 7 | 18% |
| Rockies Operations | 5 | — | —% |
| Total De-ethanization | 354 | 240 | 68% |

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

### Natural Gas Gathering Systems

| Region | Design Throughput Capacity (MMcf/d) | Natural Gas Throughput(1) (MMcf/d) | Utilization of Design Capacity(1) |
| --- | ---: | ---: | ---: |
| Marcellus Operations | 1,622 | 1,389 | 88% |
| Utica Operations | 3,183 | 2,338 | 73% |
| Southwest Operations | 2,980 | 1,772 | 59% |
| Bakken Operations | 239 | 165 | 69% |
| Rockies Operations(2) | 1,637 | 593 | 36% |
| Total Natural Gas Gathering | 9,661 | 6,257 | 65% |

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

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

### NGL Pipelines

| Region | Diameter | Length (miles) |
| --- | --- | ---: |
| Marcellus Operations | 4" - 20" | 448 |
| Utica Operations | 4" - 20" | 178 |
| Southern Appalachia Operations | 6" - 8" | 140 |
| Southwest Operations | 6" - 10" | 28 |
| Bakken Operations | 6" - 12" | 104 |
| Rockies Operations | 4" - 10" | 36 |

### 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 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 20, 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.

## Legal proceedings

As filed, 6,340 characters.

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

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

### Dakota Access Pipeline

We hold a 9.19 percent indirect interest in a joint venture (“Dakota Access”), which owns and operates the Bakken Pipeline system. In 2020, the D.D.C. ordered the United States Army Corps of Engineers (“Army Corps”), which granted permits and an easement for the Bakken Pipeline system, to prepare an environmental impact statement (“EIS”) relating to an easement under Lake Oahe in North Dakota. The D.D.C. later vacated the easement. The Army Corps issued a draft EIS in September 2023 detailing various options for the easement, including denying the easement, approving the easement with additional measures, rerouting the easement, or approving the easement with no changes. The Army Corps has not selected a preferred alternative, but will make a decision in its final review, after considering input from the public and other agencies. The pipeline remains operational while the Army Corps finalizes its decision which is expected to be issued by the end of 2024.

We have entered into a Contingent Equity Contribution Agreement whereby MPLX LP, along with the other joint venture owners in the Bakken Pipeline system, has agreed to make equity contributions to the joint venture upon certain events occurring to allow the entities that own and operate the Bakken Pipeline system to satisfy their senior note payment obligations. The senior notes were issued to repay amounts owed by the pipeline companies to fund the cost of construction of the Bakken Pipeline system.

If the vacation of the easement results in a temporary shutdown of the pipeline, MPLX would have to contribute its 9.19 percent pro rata share of funds required to pay interest accruing on the notes and any portion of the principal that matures while the pipeline is shutdown. MPLX also expects to contribute its 9.19 percent pro rata share of any costs to remediate any deficiencies to reinstate the easement and/or return the pipeline into operation. If the vacation of the easement results in a permanent shutdown of the pipeline, MPLX would have to contribute its 9.19 percent pro rata share of the cost to redeem the bonds (including the one percent redemption premium required pursuant to the indenture governing the notes) and any accrued and unpaid interest. As of December 31, 2023, our maximum potential undiscounted payments under the Contingent Equity Contribution Agreement were approximately $170 million.

### Tesoro High Plains Pipeline

In July 2020, Tesoro High Plains Pipeline Company, LLC (“THPP”), a subsidiary of MPLX, received a Notification of Trespass Determination from the Bureau of Indian Affairs (“BIA”) relating to a portion of the Tesoro High Plains Pipeline that crosses the Fort Berthold Reservation in North Dakota. The notification demanded the immediate cessation of pipeline operations and assessed trespass damages of approximately $187 million. After subsequent appeal proceedings and in compliance with a new order issued by the BIA, in December 2020, THPP paid approximately $4 million in assessed trespass damages and ceased use of the portion of the pipeline that crosses the property at issue. In March 2021, the BIA issued an order purporting to vacate the BIA's prior orders related to THPP’s alleged trespass and direct the Regional Director of the BIA to reconsider the issue of THPP’s alleged trespass and issue a new order. In April 2021, THPP filed a lawsuit in the District of North Dakota against the United States of America, the U.S. Department of the Interior and the BIA (collectively, the “U.S. Government Parties”) challenging the March 2021 order purporting to vacate all previous orders related to THPP’s alleged trespass. On February 8, 2022, the U.S. Government Parties filed their answer and counterclaims to THPP’s suit claiming THPP is in continued trespass with respect to the pipeline and seek disgorgement of pipeline profits from June 1, 2013 to present, removal of the pipeline and remediation. On November 8, 2023, the Court granted THPP’s motion to sever and stay the U.S. Government Parties’ counterclaims. The case will proceed on the merits of THPP’s challenge to the March 2021 order purporting to vacate all previous orders related to THPP’s alleged trespass. THPP continues not to operate the portion of the pipeline that crosses the property at issue.

### Edwardsville Incident

In March 2022, the State of Illinois brought an action in Madison County Circuit Court in Illinois against Marathon Pipe Line LLC (“MPL”), an indirect wholly owned subsidiary of MPLX LP, asserting various violations and demanding a permanent injunction and civil penalties in connection with a release of crude oil on the Wood River to Patoka 22" line near Edwardsville, Illinois. In September 2023, the U.S. Department of Justice and EPA confirmed they will be pursuing federal enforcement for alleged Clean Water Act violations arising from this incident as well as three pipeline incidents in Illinois and Indiana in 2018, 2020, and 2021.

We cannot currently estimate the amount of any civil penalty or the timing of the resolution of this matter but do not believe any civil penalty will have a material impact on our consolidated results of operations, financial position or cash flows.

## Management's discussion and analysis

As filed, 83,405 characters.

This section of the Annual Report on Form 10-K does not address certain items regarding the year ended December 31, 2021. Discussion and analysis of 2021 and year-to-year comparisons between 2022 and 2021 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, 2022.

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 nature of services it offers: Logistics and Storage (“L&S”) and Gathering and Processing (“G&P”). Our assets are positioned throughout the United States. The L&S segment primarily engages in the gathering, transportation, storage and distribution of crude oil, refined products, other hydrocarbon-based products, and renewables. The L&S segment also includes the operation of our refining logistics, fuels distribution and inland marine businesses, terminals, rail facilities and storage caverns. The G&P segment provides gathering, 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, 2023, 2022 and 2021 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) The year ended December 31, 2022 includes a gain on a lease reclassification of $509 million. See Item 8. Financial Statements and Supplementary Data - Note 20 in the Consolidated Financial Statements for additional information.

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

### Other Highlights

- Generated $5.4 billion of net cash provided by operating activities, $5.3 billion of distributable cash flow attributable to MPLX, and $4.1 billion of adjusted free cash flow.
- Paid $3.3 billion in distributions during the year ended December 31, 2023, which includes a 10 percent increase in our quarterly distribution effective for the third quarter of 2023, in line with our commitment to return capital to unitholders.
- Issued $1.6 billion of senior notes and used the proceeds to redeem all of the $0.6 billion outstanding Series B preferred units and $1.0 billion of senior notes due July 2023.
- Acquired the remaining 40 percent interest in a G&P joint venture in the Permian Basin in December 2023.

### Acquisition of 40 percent Interest in G&P Joint Venture

On December 15, 2023, MPLX used $303 million of cash on hand to purchase the remaining 40 percent interest in MarkWest Torñado GP, L.L.C. (“Torñado”) for approximately $270 million, including cash paid for working capital, and to extend the term of a gathering and processing agreement for approximately $33 million. As a result of this transaction, we now own 100 percent of Torñado and reflect it as a consolidated subsidiary within our consolidated financial results. It was previously accounted for as an equity method investment. Torñado provides natural gas gathering and processing related services in the Permian basin. The results for this business are reported under our G&P segment.

At December 15, 2023, the carrying value of our 60 percent equity investment in Torñado was $311 million. Upon acquisition of the remaining 40 percent member interest, our existing equity investment was remeasured to fair value resulting in the recognition of a $92 million gain, which is presented in Other income on the Consolidated Statements of Income.

### Current Economic Environment

In an effort to control inflation in pursuit of its monetary policy goals, the Federal Reserve raised interest rates throughout the past several years and continues to pursue a restrictive monetary policy in 2024. We cannot predict the effect of higher interest rates, any effects of a potential recession, or the impact of inflation and fuel prices on demand for our services. In response to this business environment, MPLX remains focused on executing its strategic priorities of strict capital discipline, fostering a low-cost culture, and portfolio optimization. Also, to the extent permitted by regulations and our existing agreements, we have increased the fees we charge our customers to reflect higher levels of inflation. Many of our agreements provide for inflation-based adjustments, including the FERC index, which increased by 13 percent in 2023 and 9 percent in 2022.

### Succession Planning

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

### 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 free cash flow (“Adjusted FCF”), and Adjusted FCF after distributions. The amount of Adjusted EBITDA and DCF generated is considered by the board of directors of our general partner in approving MPLX’s cash 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) 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) gain on sales-type leases and equity method investments; (vii) impairment expense; (viii) noncontrolling interests; and (ix) other adjustments, as applicable.

DCF is a financial performance measure used by management 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) 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 free cash flow after distributions are financial performance 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 base 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 GAAP net income or net cash provided by operating 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 ASU No. 2016-02, Leases (“ASC 842”), which can impact the classification of revenues or costs associated with the agreement. These reassessments may impact the comparability of our financial results.

### RESULTS OF OPERATIONS

The following tables and discussion summarize our results of operations for the years ended 2023, 2022 and 2021, 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)*

| Revenues and other income: | 2023 | 2022 | $ Change | 2021 | $ Change |
| --- | ---: | ---: | ---: | ---: | ---: |
| Total revenues and other income(1) | $11,281 | $11,613 | $(332) | $10,027 | $1,586 |
| **Costs and expenses:** |  |  |  |  |  |
| Cost of revenues (excludes items below) | 1,401 | 1,369 | 32 | 1,184 | 185 |
| Purchased product costs | 1,598 | 2,063 | (465) | 1,585 | 478 |
| Rental cost of sales | 82 | 123 | (41) | 136 | (13) |
| Rental cost of sales - related parties | 33 | 54 | (21) | 109 | (55) |
| Purchases - related parties | 1,544 | 1,413 | 131 | 1,219 | 194 |
| Depreciation and amortization | 1,213 | 1,230 | (17) | 1,287 | (57) |
| Impairment expense | — | — | — | 42 | (42) |
| General and administrative expenses | 379 | 335 | 44 | 353 | (18) |
| Other taxes | 131 | 115 | 16 | 120 | (5) |
| Total costs and expenses | 6,381 | 6,702 | (321) | 6,035 | 667 |
| **Income from operations** | 4,900 | 4,911 | (11) | 3,992 | 919 |
| Interest and other financial costs | 923 | 925 | (2) | 879 | 46 |
| **Income before income taxes** | 3,977 | 3,986 | (9) | 3,113 | 873 |
| Provision for income taxes | 11 | 8 | 3 | 1 | 7 |
| **Net income** | 3,966 | 3,978 | (12) | 3,112 | 866 |
| Less: Net income attributable to noncontrolling interests | 38 | 34 | 4 | 35 | (1) |
| **Net income attributable to MPLX LP** | $3,928 | $3,944 | $(16) | $3,077 | $867 |
| **Adjusted EBITDA attributable to MPLX LP(2)** | $6,269 | $5,775 | $494 | $5,560 | $215 |
| **DCF attributable to MPLX(2)** | $5,340 | $4,981 | $359 | $4,785 | $196 |

(1) The year ended December 31, 2022 includes a $509 million gain on a lease reclassification. See Item 8. Financial Statements and Supplementary Data - Note 20 for additional information.

(2) Non-GAAP measure. See reconciliation below for the most directly comparable GAAP measures.

*(In millions)*

| Reconciliation of Adjusted EBITDA attributable to MPLX LP and DCF attributable to GP and LP unitholders from Net income: | 2023 | 2022 | 2021 |
| --- | ---: | ---: | ---: |
| **Net income** | $3,966 | $3,978 | $3,112 |
| Provision for income taxes | 11 | 8 | 1 |
| Interest and other financial costs | 923 | 925 | 879 |
| **Income from operations** | 4,900 | 4,911 | 3,992 |
| Depreciation and amortization | 1,213 | 1,230 | 1,287 |
| Income from equity method investments | (600) | (476) | (321) |
| Distributions/adjustments related to equity method investments | 774 | 652 | 537 |
| Gain on sales-type leases and equity method investments | (92) | (509) | — |
| Impairment expense | — | — | 42 |
| Garyville Incident response costs(1) | 16 | — | — |
| Other(2) | 100 | 5 | 62 |
| **Adjusted EBITDA** | 6,311 | 5,813 | 5,599 |
| Adjusted EBITDA attributable to noncontrolling interests | (42) | (38) | (39) |
| **Adjusted EBITDA attributable to MPLX LP** | 6,269 | 5,775 | 5,560 |
| Deferred revenue impacts | 97 | 158 | 88 |
| Sales-type lease payments, net of income(3) | 12 | 18 | 71 |
| Net interest and other financial costs(4) | (859) | (851) | (819) |
| Maintenance capital expenditures, net of reimbursements | (150) | (144) | (88) |
| Equity method investment maintenance capital expenditures paid out | (15) | (13) | (7) |
| Other | (14) | 38 | (20) |
| **DCF attributable to MPLX LP** | 5,340 | 4,981 | 4,785 |
| Preferred unit distributions | (99) | (129) | (141) |
| **DCF attributable to GP and LP unitholders** | $5,241 | $4,852 | $4,644 |

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

(2) Includes unrealized derivative gain/(loss), equity-based compensation and other miscellaneous items.

(3) The year ended December 31, 2021 includes a one-time impact from the Refining Logistics harmonization project of $54 million.

(4) Excludes gain/loss on extinguishment of debt and amortization of deferred financing costs.

*(In millions)*

| Reconciliation of Adjusted EBITDA attributable to MPLX LP and DCF attributable to GP and LP unitholders from Net cash provided by operating activities: | 2023 | 2022 | 2021 |
| --- | ---: | ---: | ---: |
| **Net cash provided by operating activities** | $5,397 | $5,019 | $4,911 |
| Changes in working capital items | (146) | (121) | (157) |
| All other, net | 16 | (34) | (26) |
| Loss/(gain) on extinguishment of debt | 9 | 1 | (10) |
| Net interest and other financial costs(1) | 859 | 851 | 819 |
| Other adjustments to equity method investment distributions | 38 | 74 | 29 |
| Garyville Incident response costs(2) | 16 | — | — |
| Other | 122 | 23 | 33 |
| **Adjusted EBITDA** | 6,311 | 5,813 | 5,599 |
| Adjusted EBITDA attributable to noncontrolling interests | (42) | (38) | (39) |
| **Adjusted EBITDA attributable to MPLX LP** | 6,269 | 5,775 | 5,560 |
| Deferred revenue impacts | 97 | 158 | 88 |
| Sales-type lease payments, net of income(3) | 12 | 18 | 71 |
| Net interest and other financial costs(1) | (859) | (851) | (819) |
| Maintenance capital expenditures, net of reimbursements | (150) | (144) | (88) |
| Equity method investment maintenance capital expenditures paid out | (15) | (13) | (7) |
| Other | (14) | 38 | (20) |
| **DCF attributable to MPLX LP** | 5,340 | 4,981 | 4,785 |
| Preferred unit distributions | (99) | (129) | (141) |
| **DCF attributable to GP and LP unitholders** | $5,241 | $4,852 | $4,644 |

(1) Excludes gain/loss on extinguishment of debt and amortization of deferred financing costs.

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

(3) The year ended December 31, 2021 includes a one-time impact from the Refining Logistics harmonization project of $54 million.

### 2023 Compared to 2022

Total revenues and other income decreased $332 million in 2023 compared to 2022. The decrease was driven by a contract modification that resulted in a gain on sales-type lease of $509 million in 2022 and lower product sales revenue as a result of the decrease in average NGL prices during 2023 as compared to 2022. The decrease was partially offset by rate escalations and higher throughput across the business, a $124 million increase in income from equity method investments primarily due to higher throughput, and a $92 million gain on remeasurement of our existing equity investment in Torñado in conjunction with the purchase of the remaining joint venture interest in 2023.

Cost of revenues increased $32 million and rental cost of sales (including related party) decreased $62 million in 2023 compared to 2022. These offsetting variances reflect the modification of a gathering and compression agreement in the third quarter of 2022 (“Third-Party Lease Modification”), which resulted in a change in the presentation of expenses from rental cost of sales to cost of revenues. The increase in cost of revenues was partially offset by $24 million higher environmental and remediation costs in 2022 associated with a release of crude oil on our pipeline near Edwardsville, Illinois.

Purchased product costs decreased $465 million in 2023 compared to 2022. This was primarily due to lower NGL prices of $917 million, partially offset by higher volumes of $405 million and an increase of $47 million due to changes in the fair value of an embedded derivative in a natural gas purchase commitment.

Purchases-related parties increased $131 million in 2023 compared to 2022. The increase is primarily attributable to higher processing fees and transportation costs of $76 million. The increase in 2023 was also driven by Garyville Incident response costs of $16 million, net of insurance proceeds, as well as $16 million of higher employee costs from MPC.

General and administrative expenses increased $44 million in 2023 compared to 2022 due to increased costs from MPC, primarily higher employee costs, as well as an increase in contractor service costs.

Interest and other financial costs decreased $2 million in 2023 compared to 2022. The decrease reflects the benefit of a $39 million increase in interest income earned as a result of higher interest rates in 2023. This decrease was offset by higher interest expense in 2023 associated with refinancing debt with fixed rate debt at higher interest rates in 2022 and 2023 in addition to taking on incremental debt in order to finance the redemption of the 6.875 percent Fixed-to-Floating Rate Cumulative

Redeemable Perpetual Preferred Units (the “Series B preferred units”) in the first quarter of 2023. Refer to the Liquidity and Capital Resources section for further information.

### SEGMENT REPORTING

We classify our business in the following reportable segments: L&S and G&P. 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) interest and other financial costs; (iii) income/(loss) from equity method investments; (iv) distributions and adjustments related to equity method investments; (v) gain on sales-type leases and equity method investments; (vi) impairment expense; (vii) noncontrolling interests; 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 information about Segment Adjusted EBITDA for the reported segments for the years ended December 31, 2023, 2022 and 2021.

### L&S Segment

### L&S Segment Financial Highlights (in millions)

Revenue and other income Segment Adjusted EBITDA

*(In millions)*

|  | 2023 | 2022 | $ Change | 2021 | $ Change |
| --- | ---: | ---: | ---: | ---: | ---: |
| Service revenue | $4,335 | $4,057 | $278 | $3,918 | $139 |
| Rental income | 857 | 803 | 54 | 772 | 31 |
| Product related revenue | 18 | 19 | (1) | 14 | 5 |
| Sales-type lease revenue | 500 | 465 | 35 | 435 | 30 |
| Income from equity method investments | 345 | 267 | 78 | 153 | 114 |
| Other income | 68 | 57 | 11 | 61 | (4) |
| Total segment revenues and other income | 6,123 | 5,668 | 455 | 5,353 | 315 |
| Cost of revenues | 624 | 645 | (21) | 630 | 15 |
| Purchases - related parties | 1,075 | 1,042 | 33 | 913 | 129 |
| Depreciation and amortization | 530 | 515 | 15 | 546 | (31) |
| General and administrative expenses | 217 | 182 | 35 | 180 | 2 |
| Other taxes | 90 | 68 | 22 | 72 | (4) |
| Total costs and expenses | 2,536 | 2,452 | 84 | 2,341 | 111 |
| Segment Adjusted EBITDA | 4,228 | 3,818 | 410 | 3,681 | 137 |
| Capital expenditures | 414 | 325 | 89 | 316 | 9 |
| Investments in unconsolidated affiliates(1) | $26 | $97 | $(71) | $33 | $64 |

(1) The year ended December 31, 2022 includes a contribution of $60 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 a debt repayment by the joint venture.

### 2023 Compared to 2022

Service revenue increased $278 million in 2023 compared to 2022. This was primarily due to higher pipeline tariff rates and increased pipeline throughput of approximately $228 million, and $43 million from refining logistics fee escalations. There was also increased revenue from higher terminal throughput and additional marine equipment. These increases were partially offset by a decrease of $42 million from changes in the presentation of revenue between service revenue, rental income and sales-type lease revenue driven by modifications to agreements with MPC.

Rental income increased $54 million in 2023 compared to 2022. This was primarily due to an increase of $31 million from storage fee escalations and $18 million from changes in the presentation of revenue between service revenue, rental income and sales-type lease revenue driven by modifications to agreements with MPC.

Sales-type lease revenue increased $35 million in 2023 compared to 2022. This was primarily due to an increase of $24 million from changes in the presentation of revenue between service revenue, rental income and sales-type lease revenue as a result of modifications to agreements with MPC, as well as an increase of $20 million from refining logistics due to fee escalations.

Income from equity method investments increased $78 million in 2023 compared to 2022. This was primarily driven by increased throughput on equity method investment pipeline systems from recent expansions.

Cost of revenues decreased $21 million in 2023 compared to 2022. This was primarily due to higher environmental and remediation costs in 2022 associated with a release of crude oil on our pipeline near Edwardsville, Illinois, as well as lower energy costs in 2023.

Purchases - related parties increased $33 million in 2023 compared to 2022, primarily due to $16 million of Garyville Incident response costs, net of insurance proceeds, as well as increased employee costs from MPC.

General and administrative expenses increased $35 million in 2023 compared to 2022, due to increased costs from MPC, primarily higher employee costs, as well as increased contractor services costs.

Other taxes increased $22 million in 2023 compared to 2022, primarily due to higher property taxes in 2023 and a tax credit in 2022 resulting from a favorable state tax settlement.

### L&S Operating Data

| L&S Crude oil transported for (mbpd): | 2023 | 2022 | 2021 |
| --- | ---: | ---: | ---: |
| MPC | 3,053 | 2,908 | 2,810 |
| Third parties | 719 | 641 | 570 |
| Total | 3,772 | 3,549 | 3,380 |
| % MPC | 81% | 82% | 83% |
| Refined products transported for (mbpd): |  |  |  |
| MPC | 1,941 | 2,016 | 1,982 |
| Third parties | 99 | 95 | 91 |
| Total | 2,040 | 2,111 | 2,073 |
| % MPC | 95% | 95% | 96% |
| Average tariff rates ($ per Bbl)(1): |  |  |  |
| Crude oil pipelines | $0.96 | $0.91 | $0.95 |
| Refined product pipelines | 0.90 | 0.81 | 0.78 |
| Total pipelines | $0.94 | $0.87 | $0.89 |
| Terminal throughput (mbpd) | 3,130 | 3,022 | 2,886 |
| Marine Assets (number in operation)(2) |  |  |  |
| Barges | 305 | 296 | 297 |
| Towboats | 29 | 23 | 23 |

(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.

(2) Represents total at end of period.

### G&P Segment

### G&P Segment Financial Highlights (in millions)

Revenue and other income(1) Segment Adjusted EBITDA

(1) 2022 includes gain on a lease reclassification of $509 million. See Item 8. Financial statements and Supplementary Data - Note 20 for additional information.

*(In millions)*

|  | 2023 | 2022 | $ Change | 2021 | $ Change |
| --- | ---: | ---: | ---: | ---: | ---: |
| Service revenue | $2,189 | $2,056 | $133 | $2,023 | $33 |
| Rental income | 208 | 287 | (79) | 347 | (60) |
| Product related revenue | 2,191 | 2,792 | (601) | 2,066 | 726 |
| Sales-type lease revenue | 136 | 62 | 74 | — | 62 |
| Income from equity method investments | 255 | 209 | 46 | 168 | 41 |
| Other income(1) | 179 | 539 | (360) | 70 | 469 |
| Total segment revenues and other income | 5,158 | 5,945 | (787) | 4,674 | 1,271 |
| Cost of revenues | 892 | 901 | (9) | 799 | 102 |
| Purchased product costs | 1,598 | 2,063 | (465) | 1,585 | 478 |
| Purchases - related parties | 469 | 371 | 98 | 306 | 65 |
| Depreciation and amortization | 683 | 715 | (32) | 741 | (26) |
| Impairment expense | — | — | — | 42 | (42) |
| General and administrative expenses | 162 | 153 | 9 | 173 | (20) |
| Other taxes | 41 | 47 | (6) | 48 | (1) |
| Total costs and expenses | 3,845 | 4,250 | (405) | 3,694 | 556 |
| Segment Adjusted EBITDA | 2,041 | 1,957 | 84 | 1,879 | 78 |
| Capital expenditures | 605 | 528 | 77 | 224 | 304 |
| Investments in unconsolidated affiliates | $72 | $120 | $(48) | $118 | $2 |

(1) The year ended December 31, 2022 includes a $509 million gain on a lease reclassification. See Item 8. Financial Statements and Supplementary Data - Note 20 for additional information.

### 2023 Compared to 2022

Service revenue increased $133 million in 2023 compared to 2022. This was primarily due to fees from higher volumes of $76 million and higher throughput fee rates of $57 million in the Marcellus and Rockies.

Rental income decreased $79 million and sales-type lease revenue increased $74 million in 2023 compared to 2022. This was primarily due to changes in the presentation of revenue between rental income and sales-type lease revenue as a result of the Third-Party Lease Modification in the third quarter of 2022.

Product related revenue decreased $601 million in 2023 compared to 2022. This was primarily due to lower prices across all regions of $1,059 million, partially offset by fees from higher volumes in the Southwest of $451 million.

Income from equity method investments increased $46 million in 2023 compared to 2022 primarily due to higher volumes associated with several of our joint ventures in the Marcellus and Utica. Additionally, our recently acquired joint venture in the Southwest region added processing capacity in the fourth quarter of 2022 driving higher volumes over the prior period.

Other income decreased $360 million in 2023 compared to 2022 due primarily to a gain on lease reclassification of $509 million in 2022 partially offset by the impact of a $92 million gain on remeasurement of our existing equity investment in Torñado in conjunction with the purchase of the remaining joint venture interest in 2023, as well as the impact of asset disposals year over year.

Cost of revenues decreased $9 million in 2023 compared to 2022. This decrease is attributable to lower energy costs partially offset by higher maintenance project costs.

Purchased product costs decreased $465 million in 2023 compared to 2022. This was primarily due to lower NGL prices of $917 million in the Southwest and Southern Appalachia, partially offset by higher volumes in the Southwest of $405 million and a $47 million increase due to changes in the fair value of an embedded derivative in a natural gas purchase commitment.

Purchases - related parties increased $98 million in 2023 compared to 2022. The increase is attributable to higher processing fees and transportation costs of $76 million in the Southwest in addition to increased employee costs from MPC.

Depreciation and amortization decreased $32 million in 2023 compared to 2022. This was primarily due to lower depreciation as a result of the derecognition of fixed assets in connection with the Third-Party Lease Modification in 2022. This decrease was partially offset by depreciation on new assets placed in service in 2022 and 2023.

### G&P Operating Data

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

| G&P Gathering Throughput (MMcf/d) | MPLX LP(1) 2023 | 2022 | 2021 | MPLX LP Operated(2) 2023 | 2022 | 2021 |
| --- | ---: | ---: | ---: | ---: | ---: | ---: |
| Marcellus Operations | 1,389 | 1,321 | 1,336 | 1,389 | 1,321 | 1,336 |
| Utica Operations | — | — | — | 2,338 | 2,134 | 1,690 |
| Southwest Operations | 1,369 | 1,374 | 1,346 | 1,772 | 1,629 | 1,494 |
| Bakken Operations | 165 | 152 | 150 | 165 | 152 | 150 |
| Rockies Operations | 474 | 427 | 439 | 593 | 558 | 588 |
| Total gathering throughput | 3,397 | 3,274 | 3,271 | 6,257 | 5,794 | 5,258 |
| Natural Gas Processed (MMcf/d) |  |  |  |  |  |  |
| Marcellus Operations | 4,179 | 4,035 | 4,150 | 5,773 | 5,515 | 5,639 |
| Utica Operations | — | — | — | 564 | 495 | 482 |
| Southwest Operations(5) | 1,466 | 1,448 | 1,328 | 1,772 | 1,637 | 1,471 |
| Southern Appalachia Operations | 216 | 217 | 231 | 216 | 217 | 231 |
| Bakken Operations | 163 | 146 | 149 | 163 | 146 | 149 |
| Rockies Operations | 483 | 438 | 429 | 483 | 438 | 429 |
| Total natural gas processed | 6,507 | 6,284 | 6,287 | 8,971 | 8,448 | 8,401 |
| C2 + NGLs Fractionated (mbpd) |  |  |  |  |  |  |
| Marcellus Operations(3) | 530 | 488 | 484 | 530 | 488 | 484 |
| Utica Operations(3) | — | — | — | 33 | 28 | 26 |
| Southwest Operations(5) | — | — | 2 | — | — | 2 |
| Southern Appalachia Operations | 11 | 11 | 12 | 11 | 11 | 12 |
| Bakken Operations | 20 | 21 | 23 | 20 | 21 | 23 |
| Rockies Operations | 3 | 4 | 4 | 3 | 4 | 4 |
| Total C2 + NGLs fractionated(4) | 564 | 524 | 525 | 597 | 552 | 551 |

(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) 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.

(4) Purity ethane makes up approximately 233 mbpd, 204 mbpd and 192 mbpd of MPLX LP consolidated total fractionated products for the years ended December 31, 2023, 2022 and 2021, respectively. Purity ethane makes up approximately 240 mbpd, 209 mbpd and 197 mbpd of MPLX operated total fractionated products for the years ended December 31, 2023, 2022 and 2021, respectively.

(5) The Southwest Operations include the Javelina complex, which was sold on February 12, 2021. The processing and fractionated volumes calculated for the number of days MPLX owned these assets during 2021 were 96 MMcf/d and 17 mbpd, respectively.

| Pricing Information | 2023 | 2022 | 2021 |
| --- | ---: | ---: | ---: |
| Natural Gas NYMEX HH ($/MMBtu) | $2.66 | $6.52 | $3.72 |
| C2 + NGL Pricing/gallon(1) | $0.69 | $1.03 | $0.87 |

(1) 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.

### LIQUIDITY AND CAPITAL RESOURCES

### Cash Flows

Our cash and cash equivalents were $1,048 million and $238 million at December 31, 2023 and December 31, 2022, respectively. Net cash provided by (used in) operating activities, investing activities and financing activities for the past three years were as follows:

*(In millions)*

| Net cash provided by/(used in): | 2023 | 2022 | 2021 |
| --- | ---: | ---: | ---: |
| Operating activities | $5,397 | $5,019 | $4,911 |
| Investing activities | (1,252) | (956) | (518) |
| Financing activities | (3,335) | (3,838) | (4,395) |
| Total | $810 | $225 | $(2) |

***Cash Flows Provided by Operating Activities -*** Net cash provided by operating activities increased $378 million, or eight percent, in 2023 compared to 2022, primarily due to improved results from operations and increased cash distributions from equity method investments.

***Cash Flows Used in Investing Activities -*** Net cash used in investing activities increased $296 million in 2023 compared to 2022 due to higher capital spending and the acquisition of the remaining 40 percent interest in Torñado in 2023. The increase was partially offset by higher contributions to equity method investments in 2022, which included a $60 million contribution to Dakota Access to fund our share of a scheduled debt repayment by the joint venture, and $28 million for the acquisition of assets in 2022.

***Cash Flows Used in and Provided by Financing Activities -*** Net cash used in financing activities decreased $503 million in 2023 compared to 2022. The decrease was driven by net borrowings in 2023 as compared to net repayments in 2022, resulting in a decreased use of cash of $861 million. There were no units repurchased in 2023, which drove an additional $491 million decrease in use of cash during 2023. The decrease in the use of cash was partially offset by the use of $600 million to redeem all of the outstanding Series B preferred units, and higher distributions to unitholders of $249 million in 2023 as a result of 10 percent increases to the quarterly distribution effective for the third quarters of 2023 and 2022.

***Adjusted Free Cash Flow -*** For the year ended December 31, 2023, we generated Adjusted FCF of $4.1 billion after net cash used in investing activities of $1.3 billion. This provided us the flexibility to return capital to our unitholders by increasing our quarterly distribution by 10 percent for the second consecutive year. 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, 2023, 2022 and 2021.

*(In millions)*

|  | 2023 | 2022 | 2021 |
| --- | ---: | ---: | ---: |
| Net cash provided by operating activities(1) | $5,397 | $5,019 | $4,911 |
| Adjustments to reconcile net cash provided by operating activities to adjusted free cash flow |  |  |  |
| Net cash used in investing activities | (1,252) | (956) | (518) |
| Contributions from MPC | 31 | 44 | 45 |
| Distributions to noncontrolling interests | (41) | (38) | (39) |
| Adjusted free cash flow | 4,135 | 4,069 | 4,399 |
| Base distributions paid to common and preferred unitholders(2) | (3,296) | (3,047) | (2,970) |
| Adjusted free cash flow after distributions | $839 | $1,022 | $1,429 |

(1) The years ended December 31, 2023, 2022 and 2021 include working capital draws of $146 million, $121 million and $157 million, respectively.

(2) For the year ended December 31, 2021, this amount excludes the Supplemental Distribution Amount of $0.575 per unit, or a total of $603 million distributed to unitholders in the fourth quarter of 2021.

### Debt and Liquidity Overview

#### Senior Notes

On February 9, 2023, MPLX issued $1.6 billion aggregate principal amount of notes, consisting of $1.1 billion principal amount of 5.00 percent senior notes due 2033 (the “2033 Senior Notes”) and $500 million principal amount of 5.65 percent senior notes due 2053 (the “2053 Senior Notes”). The 2033 Senior Notes were offered at a price to the public of 99.170 percent of par with interest payable semi-annually in arrears, commencing on September 1, 2023. The 2053 Senior Notes were offered at a price to the public of 99.536 percent of par with interest payable semi-annually in arrears, commencing on September 1, 2023.

On February 15, 2023, MPLX used $600 million of the net proceeds from the offering of the 2033 Senior Notes and 2053 Senior Notes described above to redeem all of the outstanding Series B preferred units. On March 13, 2023, MPLX used the remaining proceeds from the offering, and cash on hand, to redeem all of MPLX’s and MarkWest’s $1.0 billion aggregate principal amount of 4.50 percent senior notes due July 2023, at par, plus accrued and unpaid interest.

As of December 31, 2023, we had $20.7 billion in aggregate principal amount of senior notes outstanding. The increase of $0.6 billion compared to year-end 2022 resulted from financing the redemption of the Series B preferred units with the issuance of senior notes, as discussed above.

#### 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.

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 that type that could, among other things, limit our ability to pay distributions to our unitholders. The financial covenant 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, 2023, we were in compliance with this financial covenant with a ratio of Consolidated Total Debt to Consolidated EBITDA of 3.3 to 1.0, as well as all other covenants contained in 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, 2024, 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 the maturity date. 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. All other terms of the MPC Loan Agreement remain unchanged.

There was no activity on the MPC Loan Agreement or MPLX Credit Agreement during 2023. There were no outstanding balances on either facility as of December 31, 2023. The MPLX Credit Agreement had less than $1 million in letters of credit outstanding.

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, 2024, the credit ratings on our senior unsecured debt were at or above investment grade level as follows:

|  |  |
| --- | --- |
| Rating Agency | Rating |
| Moody’s | Baa2 (stable outlook) |
| Fitch | BBB (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 in the event that our credit ratings are downgraded. However, any downgrades in the credit ratings of our senior unsecured debt ratings could, among other things, increase the applicable interest rates and other fees payable under the MPLX Credit Agreement, and limit our flexibility to obtain future financing, including refinancing existing indebtedness.

Our liquidity totaled $4.5 billion at December 31, 2023, consisting of:

*(In millions)*

|  | December 31, 2023 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 |  |  | 1,048 |
| Total liquidity |  |  | $4,548 |

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 PP&E and our operating leases and service agreements. We may also, from time to time repurchase our senior notes and preferred units in the open market, in tender offers, in privately-negotiated transactions or otherwise in such volumes, at such prices and upon such other terms as we deem appropriate 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. 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

*Series A 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 Series A preferred units rank senior to all common units with respect to distributions and rights upon liquidation. The holders of the Series A preferred units received cumulative quarterly distributions equal to $0.528125 per unit for each quarter prior to the second quarter of 2018. Beginning with the second quarter of 2018, the holders of the Series A preferred units are entitled to receive a quarterly distribution 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, 2023, 2022 and 2021 were $94 million, $85 million and $100 million, respectively. The distribution for the year ended December 31, 2021 includes a Supplemental Distribution Amount of $18 million, or $0.5750 per unit.

During the years ended December 31, 2023 and December 31, 2021, certain Series A preferred unitholders exercised their rights to convert their Series A preferred units into 2,281,831 common units and 93,108 common units, respectively. Approximately 27.2 million Series A preferred units remain outstanding as of December 31, 2023.

*Redemption of the Series B Preferred Units -* On February 15, 2023, MPLX exercised its right to redeem all 600,000 outstanding Series B preferred units. MPLX paid unitholders the Series B preferred unit redemption price of $1,000 per unit. MPLX made a final cash distribution of $21 million to Series B preferred unitholders on February 15, 2023, in conjunction with the redemption.

### Unit Repurchase Program

On November 2, 2020, MPLX announced the board authorization of a unit repurchase program for the repurchase of up to $1 billion of MPLX’s outstanding common units held by the public, which was exhausted during the fourth quarter of 2022. On August 2, 2022, we announced the board authorization for the repurchase of up to an additional $1 billion of MPLX common units held by the public. This repurchase authorization has no expiration date. MPLX may utilize various methods to effect the repurchases, which could include open market repurchases, negotiated block transactions, tender offers, accelerated unit repurchases or open market solicitations for units, some of which may be effected through Rule 10b5-1 plans. The timing and amount of repurchases depends upon several factors, including market and business conditions, and repurchases may be suspended, discontinued, or restarted at any time. The following table summarizes activity executed on the unit repurchase program during the years ended December 31, 2023, 2022 and 2021:

*(In millions, except per unit data)*

|  | 2023 | 2022 | 2021 |
| --- | ---: | ---: | ---: |
| Units repurchased | — | 15 | 23 |
| Cash paid for common units repurchased(1) | $— | $491 | $630 |
| Average cost per unit(1) | $— | $31.96 | $27.52 |

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

As of December 31, 2023, we had $846 million available under our remaining unit repurchase authorization.

### Distributions

On January 24, 2024, we announced that the board of directors of our general partner had declared a distribution of $0.8500 per common unit, which was paid on February 14, 2024 to common unitholders of record on February 5, 2024. This represents a 10 percent increase over the fourth quarter of 2022 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 limited and preferred partners is as follows for the years ended December 31, 2023, 2022 and 2021. 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)*

| Distribution declared: | 2023 | 2022 | 2021 |
| --- | ---: | ---: | ---: |
| Limited partner common units - public | $1,152 | $1,063 | $1,257 |
| Limited partner common units - MPC | 2,104 | 1,917 | 2,175 |
| Total distributions declared to limited partner common units(1) | 3,256 | 2,980 | 3,432 |
| Series A preferred units(1) | 94 | 88 | 100 |
| Series B preferred units | 5 | 41 | 41 |
| Total distribution declared | $3,355 | $3,109 | $3,573 |
| Cash distributions declared per limited partner common unit: |  |  |  |
| Quarter ended March 31, | $0.7750 | $0.7050 | $0.6875 |
| Quarter ended June 30, | 0.7750 | 0.7050 | 0.6875 |
| Quarter ended September 30,(1) | 0.8500 | 0.7750 | 1.2800 |
| Quarter ended December 31, | 0.8500 | 0.7750 | 0.7050 |
| Year ended December 31, | $3.2500 | $2.9600 | $3.3600 |

(1) Includes the Supplemental Distribution Amount of $0.5750 per unit and base distribution amount of $0.7050 per unit for the third quarter ended September 30, 2021.

### 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 operating income 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 those 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 in maintaining existing system volumes and related cash flows.

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

*(In millions)*

| Capital expenditures: | 2023 | 2022 | 2021 |
| --- | ---: | ---: | ---: |
| Growth capital expenditures | $838 | $665 | $407 |
| Growth capital reimbursements(1) | (165) | (151) | (35) |
| Investments in unconsolidated affiliates | 98 | 217 | 151 |
| Return of capital | (3) | (11) | (36) |
| Capitalized interest | (14) | (8) | (13) |
| Total growth capital expenditures(2) | 754 | 712 | 474 |
| Maintenance capital expenditures | 181 | 188 | 133 |
| Maintenance capital reimbursements | (31) | (44) | (45) |
| Capitalized interest | (1) | (1) | (1) |
| Total maintenance capital expenditures | 149 | 143 | 87 |
| Total growth and maintenance capital expenditures | 903 | 855 | 561 |
| Investments in unconsolidated affiliates(3) | (98) | (217) | (151) |
| Return of capital(3) | 3 | 11 | 36 |
| Growth and maintenance capital reimbursements(1)(4) | 196 | 195 | 80 |
| Increase in capital accruals | (82) | (47) | (11) |
| Capitalized interest | 15 | 9 | 14 |
| Additions to property, plant and equipment(3) | $937 | $806 | $529 |

(1) Growth capital reimbursements include reimbursements from customers and our Sponsor.

(2) Total growth capital expenditures exclude $246 million and $28 million of acquisitions in 2023 and 2022, respectively.

(3) Investments in unconsolidated affiliates, return of capital, acquisitions, and additions to property, plant and equipment are shown as separate lines within investing activities in the Consolidated Statements of Cash Flows.

(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 2024, we announced a capital outlook of $1.1 billion, net of reimbursements, which includes growth capital of $950 million and maintenance capital of $150 million. Our growth capital plans are anchored in the Marcellus and Permian basins. In addition to new gas processing plants in the Marcellus and Permian, the remainder of our capital plan is focused on other investments targeted at the expansion or debottlenecking of existing assets to meet customer demand. The capital outlook excludes approximately $100 million for the repayment of MPLX’s share of the Dakota Access joint venture’s debt due in 2024. This contribution is expected to reduce our maximum potential undiscounted payments under the Contingent Equity Contribution Agreement. See Item 3. Legal Proceedings for additional information regarding the Contingent Equity Contribution Agreement. We continuously evaluate our capital plan and make changes as conditions warrant.

### Cash Commitments

Our material cash requirements include the following contractual obligations and other cash commitments as of December 31, 2023.

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, 2023 was $33.5 billion, with $2.1 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, 2023. These agreements obligate us to pay MPC for operational and other services provided to the subsidiaries of MPLX Operations LLC. The co-location agreements have remaining terms up to 46 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 20 for further discussion about our lease obligations. Our cash commitment at December 31, 2023 was $934 million.

Transportation, terminalling, and gathering and processing agreements that obligate us to minimum volume, throughput or payment commitments over the remaining terms of the agreements, have terms that range from less than one year to eight 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 21 for further discussion. Our cash commitment at December 31, 2023 was $833 million.

At December 31, 2023, our contractual commitment under contracts to acquire property, plant and equipment was $136 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, 2023 totaled $339 million.

In addition, we have omnibus agreements and employee 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 L&S and G&P segments’ operations.

We incurred $1.8 billion of costs under various agreements with MPC, including the omnibus, co-location and employee agreements for 2023.

### Effects of Inflation

Inflation did not have a material impact on our results of operations for the years ended December 31, 2023, 2022 or 2021. We have observed higher costs for labor and materials used in our business during the year ended December 31, 2023. 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, 2023, MPC owned our general partner and an approximate 65 percent limited partner interest in us. We perform a variety of services for MPC related to the transportation of crude and refined products, including renewable diesel, 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 50 percent, 47 percent and 50 percent of our total revenues and other income for the years ended December 31, 2023, 2022 and 2021, respectively. Of our total costs and expenses, MPC accounted for 27 percent, 25 percent and 26 percent for the years ended December 31, 2023, 2022 and 2021, 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. MPC will indemnify us for certain of these costs.

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 %)*

|  | 2023 | 2022 | 2021 |
| --- | ---: | ---: | ---: |
| Capital | $29 | $15 | $15 |
| Percent of total capital expenditures | 3% | 2% | 3% |
| Compliance:(1) |  |  |  |
| Operating and maintenance | $10 | $15 | $28 |
| Remediation(2) | 19 | 33 | 17 |
| Total | $29 | $48 | $45 |

(1) Based on the American Petroleum Institute’s definition of environmental expenditures.

(2) These amounts include spending charged against remediation reserves and exclude non-cash accruals for environmental remediation. Environmental remediation costs increased in 2022 compared to 2021 due to a release of crude oil on our pipeline near Edwardsville, Illinois in March of 2022.

We accrue for environmental remediation activities when the responsibility to remediate is probable and the amount of associated costs can be reasonably estimated. As environmental remediation matters proceed toward ultimate resolution or as additional remediation obligations arise, charges in excess of those previously accrued may be required.

New or expanded environmental requirements, which could increase our environmental costs, may arise in the future. We believe we comply with all legal requirements regarding the environment, but since not all of them are fixed or presently determinable (even under existing legislation) and may be affected by future legislation or regulations, it is not possible to predict all of the ultimate costs of compliance, including remediation costs that may be incurred and penalties that may be imposed.

Our environmental capital expenditures are expected to approximate $31 million in 2024. Actual expenditures may vary as the number and scope of environmental projects are revised as a result of improved technology or changes in regulatory requirements and could increase if additional projects are identified or additional requirements are imposed.

For more information on environmental regulations that impact us, or could impact us, see Item 1. Business – Regulatory Matters and Item 1A. Risk Factors.

### CRITICAL ACCOUNTING ESTIMATES

The preparation of financial statements in accordance with GAAP requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities as of the date of the consolidated financial statements and the reported amounts of revenues and expenses during the respective reporting periods. Accounting estimates are considered to be critical if (i) the nature of the estimates and assumptions is material due to the levels of subjectivity and judgment necessary to account for highly uncertain matters or the susceptibility of such matters to change and (ii) the impact of the estimates and assumptions on financial condition or operating performance is material. Actual results could differ from the estimates and assumptions used. See Item 8. Financial Statements and Supplementary Data – Note 2 for additional information on these policies and estimates, as well as a discussion of additional accounting policies and estimates.

### Fair Value Estimates

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. There are three approaches for measuring the fair value of assets and liabilities: the market approach, the income approach and the cost approach, each of which includes multiple valuation techniques. The market approach uses prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities. The income approach uses valuation techniques to measure fair value by converting future amounts, such as cash flows or earnings, into a single present value amount using current market expectations about those future amounts. The cost approach is based on the amount that would currently be required to replace the service capacity of an asset. This is often referred to as current replacement cost. The cost approach assumes that the fair value would not exceed what it would cost a market participant to acquire or construct a substitute asset of comparable utility, adjusted for obsolescence.

The fair value accounting standards do not prescribe which valuation technique should be used when measuring fair value and do not prioritize among the techniques. These standards establish a fair value hierarchy that prioritizes the inputs used in applying the various valuation techniques. Inputs broadly refer to the assumptions that market participants use to make pricing decisions, including assumptions about risk. Level 1 inputs are given the highest priority in the fair value hierarchy while Level 3 inputs are given the lowest priority. The three levels of the fair value hierarchy are as follows:

- Level 1 - Observable inputs that reflect unadjusted quoted prices for identical assets or liabilities in active markets as of the measurement date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis.
- Level 2 - Observable market-based inputs or unobservable inputs that are corroborated by market data. These are inputs other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the measurement date.
- Level 3 - Unobservable inputs that are not corroborated by market data and may be used with internally developed methodologies that result in management’s best estimate of fair value.

Valuation techniques that maximize the use of observable inputs are favored. Assets and liabilities are classified in their entirety based on the lowest priority level of input that is significant to the fair value measurement. The assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement of assets and liabilities within the levels of the fair value hierarchy. We use an income or market approach for recurring fair value measurements and endeavor to use the best information available. We use a cost method approach for non-recurring fair value measurements related to the valuation of our leased assets. See Item 8. Financial Statements and Supplementary Data - Note 15 for disclosures regarding our fair value measurements.

Significant uses of fair value measurements include:

- assessment of impairment of long-lived assets, intangible assets, goodwill and equity method investments;
- assessment of values for assets in implicit leases, including sales-type leases;
- assessment of values for underlying assets to record net investment in sales-type leases;
- recorded values for assets acquired and liabilities assumed in connection with acquisitions; and
- recorded values of derivative instruments.

### Impairment Assessments of Long-Lived Assets, Intangible Assets, Goodwill and Equity Method Investments

Fair value calculated for the purpose of testing our long-lived assets, intangible assets, goodwill and equity method investments for impairment is estimated using the expected present value of future cash flows method and comparative market prices when appropriate. Significant judgment is involved in performing these fair value estimates since the results are based on forecasted assumptions. Significant assumptions include:

- *Future Operating Performance.* Our estimates of future operating performance are based on our analysis of various supply and demand factors, which include, among other things, industry-wide capacity, our planned utilization rate, end-user demand, capital expenditures and economic conditions as well as commodity prices. Such estimates are consistent with those used in our planning and capital investment reviews.
- *Future volumes.* Our estimates of future throughput of crude oil, natural gas, NGL and refined product volumes are based on internal forecasts and depend, in part, on assumptions about our customers’ drilling activity which is inherently subjective and contingent upon a number of variable factors (including future or expected crude oil and natural gas pricing considerations), many of which are difficult to forecast. Management considers these volume forecasts and other factors when developing our forecasted cash flows.
- *Discount rate commensurate with the risks involved.* We apply a discount rate to our cash flows based on a variety of factors, including market and economic conditions, operational risk, regulatory risk and political risk. This discount rate is also compared to recent observable market transactions, if possible. A higher discount rate decreases the net present value of cash flows.
- *Future capital requirements.* These are based on authorized spending and internal forecasts.

Assumptions about the macroeconomic environment are inherently subjective and difficult to forecast. We base our fair value estimates on projected financial information which we believe to be reasonable. However, actual results may differ from these projections.

The need to test for impairment can be based on several indicators, including a significant reduction in prices of or demand for commodities, a poor outlook for profitability, a significant reduction in pipeline throughput volumes, a significant reduction in natural gas or NGL volumes processed, other changes to contracts or changes in the regulatory environment in which the asset or equity method investment is located.

### Long-lived Asset Impairment Assessments

Long-lived assets used in operations are assessed for impairment whenever changes in facts and circumstances indicate that the carrying value of the assets may not be recoverable based on the expected undiscounted future cash flow of an asset group. For purposes of impairment evaluation, long-lived assets must be grouped at the lowest level for which independent cash flows can be identified, which is at least at the segment level and in some cases for similar assets in the same geographic region where cash flows can be separately identified. If the sum of the undiscounted cash flows is less than the carrying value of an asset group, fair value is calculated, and the carrying value is written down if greater than the calculated fair value.

### Goodwill Impairment Assessments

Unlike long-lived assets, goodwill must be tested for impairment at least annually, and between annual tests if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying amount. Goodwill is tested for impairment at the reporting unit level. We have five reporting units, three of which have goodwill allocated to them. A goodwill impairment loss is measured as the amount by which a reporting unit’s carrying value exceeds its fair value, without exceeding the recorded amount of goodwill.

At December 31, 2023, MPLX had three reporting units with goodwill totaling approximately $7.6 billion, which includes goodwill associated with our Crude Gathering reporting unit of $1.1 billion. For the annual impairment assessment as of November 30, 2023, management performed only a qualitative assessment for two reporting units as we determined it was more likely than not that the fair values of the reporting units exceeded their carrying values. The fair value of the Crude Gathering reporting unit for which a quantitative assessment was performed was determined based on applying both a discounted cash flow, or income approach, as well as a market approach which resulted in the fair value of the reporting unit exceeding its carrying value by greater than 10 percent. The significant assumptions that were used to develop the estimate of the fair value included management’s best estimates of the discount rate as well as estimates of future cash flows, which are impacted primarily by producer customers’ development plans, which impact the reporting unit’s future volumes and capital requirements. A 100-basis point increase to the discount rate used to estimate the fair value of the reporting unit would not have resulted in a goodwill impairment charge as of November 30, 2023.

Fair value determinations require considerable judgment and are sensitive to changes in underlying assumptions and factors. As a result, there can be no assurance that the estimates and assumptions made for purposes of the impairment tests will prove to be an accurate prediction of the future. See Item 8. Financial Statements and Supplementary Data - Note 14 for additional information relating to our reporting units and goodwill.

### Equity Method Investment Impairment Assessments

Equity method investments are assessed for impairment whenever factors indicate an other-than-temporary loss in value. Factors providing evidence of such a loss include the fair value of an investment that is less than its carrying value, absence of an ability to recover the carrying value or the investee’s inability to generate income sufficient to justify our carrying value. At December 31, 2023, we had $3.7 billion of equity method investments recorded on the Consolidated Balance Sheets.

An estimate of the sensitivity to net income resulting from impairment calculations is not practicable, given the numerous assumptions (e.g., pricing, volumes and discount rates) that can materially affect our estimates. That is, unfavorable adjustments to some of the above listed adjustments may be offset by favorable adjustments in other assumptions.

See Item 8. Financial Statements and Supplementary Data - Note 5 for additional information on our equity method investments and Note 14 for additional information on our goodwill and intangibles.

### Leases

In accounting for leases, we analyze new or modified leases for lease classification. One of the key inputs into the lease classification analysis is the fair value of the leased assets. For newly classified sales-type leases, the net investment in the lease is recorded at the estimated fair value of the underlying leased assets. Significant assumptions used to estimate the leased assets’ fair value include market information for comparable assets and cost estimates to replace the service capacity of an asset.

### Variable Interest Entities

We evaluate all legal entities in which we hold an ownership or other pecuniary interest to determine if the entity is a VIE. Our interests in a VIE are referred to as variable interests. Variable interests can be contractual, ownership or other pecuniary interests in an entity that change with changes in the fair value of the VIE’s assets. When we conclude that we hold an interest in a VIE, we must determine if we are the entity’s primary beneficiary. A primary beneficiary is deemed to have a controlling financial interest in a VIE. This controlling financial interest is evidenced by both (i) the power to direct the activities of the VIE that most significantly impact the VIE’s economic performance and (ii) the obligation to absorb losses that could potentially be significant to the VIE or the right to receive benefits that could potentially be significant to the VIE. We consolidate any VIE when we determine that we are the primary beneficiary. We must disclose the nature of any interests in a VIE that is not consolidated.

Significant judgment is exercised in determining that a legal entity is a VIE and in evaluating our interest in a VIE. We use primarily a qualitative analysis to determine if an entity is a VIE. We evaluate the entity’s need for continuing financial support; the equity holder’s lack of a controlling financial interest; and/or if an equity holder’s voting interests are disproportionate to its obligation to absorb expected losses or receive residual returns. We evaluate our interests in a VIE to determine whether we are the primary beneficiary. We use a primarily qualitative analysis to determine if we are deemed to have a controlling financial interest in the VIE, either on a standalone basis or as part of a related party group. We continually monitor our interests in legal entities for changes in the design or activities of an entity and changes in our interests, including our status as the primary beneficiary to determine if the changes require us to revise our previous conclusions.

Changes in the design or nature of the activities of a VIE, or our involvement with a VIE, may require us to reconsider our conclusions on the entity’s status as a VIE and/or our status as the primary beneficiary. Such reconsideration requires significant judgment and understanding of the organization. This could result in the deconsolidation or consolidation of the affected subsidiary, which would have a significant impact on our financial statements.

VIEs are discussed in Item 8. Financial Statements and Supplementary Data - Note 5.

### Contingent Liabilities

We accrue contingent liabilities for legal actions, claims, litigation, environmental remediation, tax deficiencies related to operating taxes and third-party indemnities for specified tax matters when such contingencies are both probable and estimable. We regularly assess these estimates in consultation with legal counsel to consider resolved and new matters, material developments in court proceedings or settlement discussions, new information obtained as a result of ongoing discovery and past experience in defending and settling similar matters. Actual costs can differ from estimates for many reasons. For instance, settlement costs for claims and litigation can vary from estimates based on differing interpretations of laws, opinions on degree of responsibility and assessments of the amount of damages. Similarly, liabilities for environmental remediation may vary from estimates because of changes in laws, regulations and their interpretation, additional information on the extent and nature of site contamination and improvements in technology.

We generally record losses related to these types of contingencies as cost of revenues or selling, general and administrative expenses on the Consolidated Statements of Income, except for tax deficiencies unrelated to income taxes, which are recorded as other taxes.

An estimate of the sensitivity to net income if other assumptions had been used in recording these liabilities is not practical because of the number of contingencies that must be assessed, the number of underlying assumptions and the wide range of reasonably possible outcomes, in terms of both the probability of loss and the estimates of such loss.

For additional information on contingent liabilities, see Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Environmental Matters and Compliance Costs and Item 8. Financial Statements and Supplementary Data - Note 21.

## Market risk

As filed, 7,346 characters.

We are exposed to market risks related to the volatility of commodity prices. We employ various strategies, including the potential use of commodity derivative instruments, to economically hedge the risks related to these price fluctuations. We are also exposed to market risks related to changes in interest rates. As of December 31, 2023, we did not have any open financial or commodity derivative instruments to hedge the economic risks related to interest rate fluctuations or the volatility of commodity prices, respectively; however, we continually monitor the market and our exposure and may enter into these arrangements in the future.

### Commodity Price Risk

We may at times use a variety of commodity derivative instruments, including futures and options, as part of an overall program to economically hedge commodity price risk. A portion of our profitability is directly affected by prevailing commodity prices primarily as a result of purchasing and selling NGLs and natural gas at index-related prices. To the extent that commodity prices influence the level of drilling by our producer customers, such prices also indirectly affect profitability. We may enter into derivative contracts, which are primarily swaps traded on the Over-the-Counter market as well as fixed price forward contracts. Our risk management policy does not allow us to enter into speculative positions with our derivative contracts. Execution of our hedge strategy and the continuous monitoring of commodity markets and our open derivative positions are carried out by our hedge committee, comprised of members of senior management.

To mitigate our cash flow exposure to fluctuations in the price of NGLs, we may use NGL derivative swap contracts. A small portion of our NGL price exposure may be managed by using crude oil contracts. To mitigate our cash flow exposure to fluctuations in the price of natural gas, we may use natural gas derivative swap contracts, taking into account the partial offset of our long and short natural gas positions resulting from normal operating activities.

We would be exposed to additional commodity risk in certain situations such as if producers under-deliver or over-deliver products or if processing facilities are operated in different recovery modes. In the event that we have derivative positions in excess of the product delivered or expected to be delivered, the excess derivative positions may be terminated.

Management conducts a standard credit review on counterparties to derivative contracts, and we have provided the counterparties with a guaranty as credit support for our obligations. We use standardized agreements that allow for offset of certain positive and negative exposures in the event of default or other terminating events, including bankruptcy.

### Outstanding Derivative Contracts

We have a natural gas purchase commitment embedded in a keep-whole processing agreement with a producer customer in the Southern Appalachian region expiring in December 2027. The customer has the unilateral option to extend the agreement for one five-year term through December 2032. For accounting purposes, the natural gas purchase commitment and the term extending option has been aggregated into a single compound embedded derivative. The probability of the customer exercising its option is determined based on assumptions about the customer’s potential business strategy decision points that may exist at the time they would elect whether to renew the contract. The changes in fair value of this compound embedded derivative are based on the difference between the contractual and index pricing, and the probability of the producer customer exercising its option to extend. The changes in fair value are recorded in earnings through Purchased product costs on the Consolidated Statements of Income. As of both December 31, 2023 and 2022, the estimated fair value of this contract was a liability of $61 million.

### Open Derivative Positions and Sensitivity Analysis

The estimated fair value of our Level 2 and 3 financial instruments are sensitive to the assumptions used in our pricing models. Sensitivity analysis of a ten percent difference in our estimated fair value of Level 2 and 3 commodity derivatives (excluding embedded derivatives) as of December 31, 2023 would not have incremental effects on income before income taxes, given we had no open commodity derivative contracts as of December 31, 2023. We evaluate our portfolio of commodity derivative instruments on an ongoing basis and add or revise strategies in anticipation of changes in market conditions and in risk profiles.

### Interest Rate Risk

Sensitivity analysis of the effect of a hypothetical 100-basis-point change in interest rates on third-party outstanding debt, excluding finance leases, is provided in the following table. Fair value of cash and cash equivalents, receivables, accounts payable and accrued interest approximate carrying value and are relatively insensitive to changes in interest rates due to the short-term maturity of the instruments. Accordingly, these instruments are excluded from the table.

*(In millions)*

| Outstanding debt | Fair Value as of December 31, 2023(1) | Change in Fair Value (2) | Change in Income before income taxes for the Year Ended December 31, 2023 (3) |
| --- | ---: | ---: | ---: |
| Fixed-rate | $19,377 | $1,568 | N/A |
| Variable-rate(4) | $— | $— | $— |

(1) Fair value was based on market prices, where available, or current borrowing rates for financings with similar terms and maturities.

(2) Assumes a 100-basis-point decrease in the weighted average yield-to-maturity at December 31, 2023.

(3) Assumes a 100-basis-point change in interest rates. The change to income before income taxes was based on the weighted average balance of all outstanding variable-rate debt for the year ended December 31, 2023.

(4) MPLX had no outstanding borrowings on the MPLX Credit Agreement as of December 31, 2023.

Our use of fixed or variable-rate debt directly exposes us to interest rate risk. Fixed rate debt, such as our senior notes, exposes us to changes in the fair value of our debt due to changes in market interest rates. Fixed rate debt also exposes us to the risk that we may need to refinance maturing debt with new debt at higher rates or that our current fixed rate debt may be higher than the current market. Variable-rate debt, such as borrowings under our revolving credit facilities, exposes us to short-term changes in market rates that impact our interest expense.

### Credit Risk

We are subject to risk of loss resulting from non-payment by our customers to whom we provide services, lease assets, or sell natural gas or NGLs. We believe that certain contracts where we sell NGLs and act as our producer customers’ agent would allow us to pass those losses through to our customers, thus reducing our risk. Our credit exposure related to these customers is represented by the value of our trade receivables or lease receivables. Where exposed to credit risk, we analyze the customer’s financial condition prior to entering into a transaction or agreement, establish credit terms and monitor the appropriateness of these terms on an ongoing basis. In the event of a customer default, we may sustain a loss and our cash receipts could be negatively impacted.

## Controls and procedures

As filed, 1,010 characters.

### Disclosure Controls and Procedures

An evaluation of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended) was carried out under the supervision and with the participation of our management, including the chief executive officer and chief financial officer of our general partner. Based upon that evaluation, the chief executive officer and chief financial officer of our general partner concluded that the design and operation of these disclosure controls and procedures were effective as of December 31, 2023, the end of the period covered by this Annual Report on Form 10-K.

### Changes in Internal Control over Financial Reporting

During the quarter ended December 31, 2023, there were no changes in our internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Filed Feb 28, 2024.
Source: SEC EDGAR, the filing index for accession 0001552000-24-000007. Last ingested by Listed: Oct 29, 2026, 17:01 ET. No prices; not investment advice.