Hess Midstream LP

Overview

We are a fee-based, growth-oriented, limited partnership that owns, operates, develops and acquires a diverse set of midstream assets and provides fee-based services to Chevron, its subsidiaries, and third-party customers. Our assets are primarily located in the Bakken and Three Forks shale plays in the Williston Basin area of North Dakota, which we collectively refer to as the Bakken and which is one of the most prolific crude oil producing basins in North America. Our Sponsor dedicated substantially all of its existing and future owned or controlled production in the Bakken under our long-term, fee-based agreements and intends to use us as the primary midstream vehicle to support its production goals in the Bakken and preserve value of its midstream business. We generate substantially all of our revenues by charging fees for gathering, compressing and processing natural gas and fractionating NGLs; gathering, terminaling, loading and transporting crude oil and NGLs; storing and terminaling propane; and gathering and disposing of produced water.

Prior to December 16, 2019, we were indirectly controlled by Hess Infrastructure Partners GP LLC, the general partner of Hess Infrastructure Partners LP (“HIP”). HIP was originally formed in 2015 as a 50/50 joint venture between Hess and GIP. On April 10, 2017, we completed an initial public offering (“IPO”) as a master limited partnership, pursuant to which HIP contributed to the Partnership a 20% controlling economic interest in each of (i) Hess North Dakota Pipelines Operations LP; (ii) Hess TGP Operations LP; and (iii) Hess North Dakota Export Logistics Operations LP (collectively, the “Joint Interest Assets”) and a 100% interest in Hess Mentor Storage Holdings LLC. HIP owned the remaining 80% economic interest in the Joint Interest Assets, a 100% interest in certain other businesses, including Hess’ Bakken water services business (“Hess Water Services”), which it acquired from Hess on March 1, 2019, and a 100% interest in Hess Midstream Partners GP LP, which held all of the Partnership’s outstanding incentive distribution rights and the general partner interest in the Partnership, and controlled the Partnership.

On December 16, 2019, the Company and the Partnership completed the transactions (the “Restructuring”) contemplated by the Partnership Restructuring Agreement, dated October 3, 2019, by and among the Company, the Partnership and the other parties thereto. Pursuant to the Restructuring, the Partnership acquired HIP, including HIP’s 80% interest in the Joint Interest Assets, 100% interest in Hess Water Services and the outstanding economic general partner interest and incentive distribution rights in the Partnership. The Partnership’s organizational structure converted from a master limited partnership into an “Up-C” structure, in which the Partnership’s public unitholders received newly issued Class A Shares in the Company in a one-for-one exchange. Class A Shares commenced trading on the New York Stock Exchange (“NYSE”) under the former symbol “HESM” on December 17, 2019. As a result of the Restructuring, the Company was delegated control of the Partnership and replaced the Partnership as its publicly traded successor. The Partnership changed its name to “Hess Midstream Operations LP” and became a consolidated subsidiary of the Company.

On May 30, 2025, GIP sold all of its limited partner interests in the Partnership and no longer holds a direct or indirect ownership interest in the Company, the Partnership or our general partner.

On July 18, 2025, Hess and Chevron completed the previously announced merger contemplated by the Agreement and Plan of Merger, dated October 22, 2023 (the “Merger”). As a result of the Merger, Chevron is the direct parent of Hess and, therefore, indirectly owns each of the following:

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100% of the limited liability company interests in Hess Infrastructure Partners GP LLC, the sole member of the general partner of our general partner;

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100% of the limited liability company interests in Hess Midstream GP LLC, the general partner of our general partner;

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100% of the partnership interests in Hess Midstream GP LP, our general partner;

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100% of the limited liability company interests in Hess Investments North Dakota LLC (“HINDL”), the holder of 449,000 Class A shares representing limited partner interests in the Company (“Class A Shares”) and all of the issued and outstanding Class B shares representing limited partner interests in the Company (“Class B Shares”) and Class B units representing limited partner interests in the Partnership (“Class B Units”), which Class B Shares and Class B Units together are exchangeable into Class A Shares and, together with HINDL’s Class A Shares, collectively represent an approximate 37.9% interest in the Company on a consolidated basis.

Throughout this filing and depending on the context, we make references to Chevron, as Chevron, following the completion of the Merger, is our Sponsor and indirectly wholly owns our general partner and, through its ownership of our general partner, has the indirect right to appoint all of the members of our board of directors. Our historical commercial, omnibus and employee secondment agreements with Hess remain in effect subsequent to the Merger, and we refer to Chevron as the counterparty to these agreements, as Chevron currently wholly owns the Hess entities that are counterparties to these agreements.

At December 31, 2025:

•

the Company held a 62.3% controlling interest in the Partnership and Chevron held a 37.7% noncontrolling economic interest in the Partnership;

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public limited partners held a 62.1% voting interest and a 99.7% economic interest in the Company, which represents an indirect 62.1% economic interest in the Partnership;

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Chevron and its affiliates held a 37.9% voting interest and a 0.3% economic interest in the Company, which, taken with their direct limited partnership interest in the Partnership, represents an indirect 37.9% economic interest in the Partnership. See Organizational Structure.

See Item 8. Financial Statements and Supplementary Data. Note 3, Equity Transactions and Note 8, Partners’ Capital and Distributions for further details.

LM4 Joint Venture

On January 25, 2018, we entered into a 50/50 joint venture with Targa Resources Corp. (“Targa”) to construct a new 200 MMcf/d gas processing plant called Little Missouri 4 (“LM4”). LM4 was placed in service in 2019. Targa is the operator of the plant.

Operating Segments

We conduct our business through three operating segments: (i) gathering, (ii) processing and storage and (iii) terminaling and export. See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations for further details.

Organizational Structure

The following chart summarizes our corporate structure at December 31, 2025.

Our Business and Properties

Our gathering business consists of the Partnership’s 100% interest in (i) Hess North Dakota Pipelines Operations LP (“Gathering Opco”), which owns our North Dakota natural gas, NGL and crude oil gathering systems, and (ii) Hess Water Services, which owns our produced water gathering and disposal facilities. The following sections describe in more detail these assets and the related services that we provide.

Natural Gas Gathering and Compression

A natural gas gathering and compression system located primarily in McKenzie, Williams and Mountrail Counties, North Dakota, connecting Chevron and third‑party owned or operated wells to the Tioga Gas Plant, the LM4 plant, and third‑party pipeline facilities. This gathering system consists of approximately 1,430 miles of high and low pressure natural gas and NGL gathering pipelines with a current capacity of up to approximately 685 MMcf/d. The system has an aggregate compression capacity of approximately 550 MMcf/d, including approximately 20 MMcf/d of net compression capacity added in 2025. Construction was also completed on an additional greenfield compressor station, which was placed in service in early 2026 and which further increased compression capacity by approximately 50 MMcf/d in 2026. The compressed gas and mixed NGLs are transported to the Tioga Gas Plant and the LM4 plant either as separate or combined streams for processing. Our gathering system capacity can be increased via installation of additional compression equipment.

Crude Oil Gathering

A crude oil gathering system located primarily in McKenzie, Williams and Mountrail Counties, North Dakota, connecting Chevron and third‑party owned or operated wells to the Ramberg Terminal Facility, the Tioga Rail Terminal and the Johnson’s Corner Header System. The crude oil gathering system consists of approximately 615 miles of crude oil gathering pipelines with a current capacity of up to approximately 290 MBbl/d.

Included within our crude oil gathering system is our Hawkeye Oil Facility, which is a crude oil pumping and truck unloading facility located in McKenzie County, North Dakota. The Hawkeye Oil Facility entered into service in 2017. The facility receives crude oil through pipeline and truck deliveries from Chevron and third parties and transports it by pipeline to the Johnson’s Corner Header System. Total receipt capacity of the facility is approximately 75 MBbl/d, which can be filled solely through our crude oil gathering system or through a combination of our crude oil gathering system and truck unloading bays. The facility has six truck unloading bays with an aggregate capacity of approximately 30 MBbl/d. The facility has a redelivery capability of approximately 75 MBbl/d through a pipeline system connected to our crude oil export terminals. The facility also has two crude oil storage tanks with a combined working storage capacity of approximately 10 MBbls. Our gathering system capacity can be increased through the installation of additional pumping equipment.

Produced Water Gathering and Disposal

A produced water gathering system located primarily in Williams and Mountrail counties, North Dakota, that transports produced water from well sites by approximately 360 miles of pipelines in gathering systems or by third-party trucking to water handling facilities for disposal. As of December 31, 2025, we had 13 water handling and disposal facilities in service, with a combined permitted disposal capacity of 185 MBbl/d. These water handling and disposal facilities are owned and operated by Hess Water Services and primarily service the water pipeline gathering systems. We also transport produced water to 13 water handling and disposal facilities operated by third parties that have a combined permitted disposal capacity of approximately 180 MBbl/d.

The following table sets forth certain information regarding our gathering assets, which operate under long‑term, fee‑based commercial agreements with Chevron:

Gathering Assets

(1) Includes 75 MBbl/d of capacity at the Hawkeye Oil Facility.

Our processing and storage business consists of (i) the Partnership’s 100% interest in Hess TGP Operations LP (“HTGP Opco”), which owns the Tioga Gas Plant, (ii) the Partnership’s 50% interest in the LM4 gas processing plant operated by Targa, and (iii) the Partnership’s 100% interest in Hess Mentor Storage Holdings LLC (“Mentor Holdings”), which owns the Mentor Storage Terminal. The following sections describe in more detail these assets and the related services that we provide.

Tioga Gas Plant

The Tioga Gas Plant (“TGP”), which is located in Tioga, North Dakota, has a total processing capacity of 400 MMcf/d making it one of the largest natural gas processing and fractionation plants in North Dakota. The plant consists of (i) a state-of-the-art cryogenic processing facility with ethane extraction capabilities that produces low Btu, pipeline‑quality natural gas, (ii) a 60 MBbl/d fractionation facility with NGL fractionation capabilities for ethane, propane, butane and natural gasoline and (iii) 25 MBbl/d of stabilized y-grade liquid recovery capabilities. The plant receives natural gas produced from Chevron‑operated and third‑party operated wells in the Bakken through our North Dakota gathering systems as well as third‑party gathering systems.

TGP was initially constructed in 1954. It subsequently underwent a large‑scale expansion, refurbishment and optimization project that was completed in 2014, during which a new cryogenic processing train with a nameplate processing capacity of 250 MMcf/d was installed. In 2021, the TGP de-bottlenecking project was completed and commissioned, increasing total plant processing to 400 MMcf/d and adding y-grade liquids recovery of up to approximately 25 MBbl/d.

TGP has a multitude of residue gas and NGL export options. For residue gas, the plant has total export capacity of more than 250 MMcf/d with access to the Chicago, IL market through the Alliance Pipeline from the Tioga lateral; it also has access to the Ventura, IA market through the Northern Border Pipeline from the WBI North Bakken Expansion Pipeline. TGP also provides residue gas for local and regional uses through the WBI system and for gas lift and fuel through the North Dakota Natural Gas Pipeline, which also interconnects with the Northern Border pipeline. For ethane, TGP can recover and ship up to 30 MBbl/d of ethane to Canada on the Vantage Pipeline. Other fractionated products such as propane, butane and natural gasoline can be shipped via truck or rail to local and regional markets. Y-grade liquids are shipped on the Elk Creek Pipeline from the ONEOK NGL lateral to Bushton, KS with access to Mont Belvieu, TX.

The plant also includes four NGL truck loading racks with an aggregate loading capacity of approximately 10 MBbl/d of propane to serve the local propane market, as well as 14 NGL bullet storage tanks and 5 NGL storage tanks with a combined shell capacity of approximately 35 MBbls of propane, 10 MBbls of butane and 35 MBbls of natural gasoline. The total NGL production capability of the plant is approximately 80 MBbl/d, with interconnections into the Vantage Pipeline, the Alliance Pipeline and interconnecting pipelines with our Tioga Rail Terminal. Additionally, the plant includes a CNG terminal that is capable of compressing approximately 5.6 MMcf/d of natural gas to 3,600 psig and loading in excess of 100 light duty CNG‑fueled vehicles and up to 32 CNG cylinder trailers per day for drilling and hydraulic fracturing operations, for a combined capacity of approximately 40 Mdge/d.

LM4

The Partnership owns a 50% interest in a joint venture with Targa, which constructed and placed in service in the third quarter of 2019, a new 200 MMcf/d gas processing plant called Little Missouri 4, or LM4, located at Targa’s existing Little Missouri facility, south of the Missouri River in McKenzie County, North Dakota. We are entitled to 100 MMcf/d of the plant’s processing capacity. The plant receives natural gas produced from Chevron-operated and third-party operated wells in the Bakken through our gathering systems as well as third-party gathering systems. The plant also has direct residue gas and NGL pipeline connections at the tailgate of the plant, with export capacity of approximately 135 MMcf/d of natural gas to the Northern Border Interstate Pipeline and 40 MBbl/d of NGLs to ONEOK Elk Creek Pipeline.

Mentor Storage Terminal

Our Mentor Storage Terminal consists of a propane storage cavern and a rail and truck loading and unloading facility located on approximately 40 acres in Mentor, Minnesota. The Mentor Storage Terminal has an aggregate working storage capacity of approximately 330 MBbls, consisting of an underground cavern with a working storage capacity of approximately 325 MBbls and three above‑ground bullet storage tanks with an aggregate working storage capacity of approximately 5 MBbls. The terminal also has a dehydration facility, 11 rail unloading racks and two truck loading racks. The cavern and truck loading racks each have a propane injection and withdrawal capacity of approximately 6 MBbl/d.

The Mentor Storage Terminal, a mined cavern for liquefied petroleum gas, was constructed in 1962. The rock from which the cavern was constructed is classified as zoisite, a rare, marble‑like rock that has essentially no porosity or permeability, which makes it excellent for the purpose of liquid hydrocarbon storage. Constant underground temperature provides uniform operating conditions in the cavern.

Propane is received at the Mentor Storage Terminal by rail, and shipments and deliveries vary by season. Chevron utilizes our propane storage services to mitigate the impact on its operations from seasonal variations in the demand for propane. As a result, at Chevron’s direction, we generally fill the cavern with propane during the warmer months when demand for propane is low, and gradually withdraw propane from the cavern during colder months when demand is higher.

The following table sets forth certain information regarding our processing and storage assets, which operate under long‑term, fee‑based commercial agreements with Chevron:

Processing and Storage Assets

(1)

Represents the total aggregate above-ground shell storage capacity of storage tanks at the Tioga Gas Plant.

(2)

Represents 50% of the total plant capacity. The LM4 plant was placed in service in the third quarter of 2019.

(3)

Represents a working storage capacity of approximately 325 MBbls at the storage cavern and an aggregate working capacity of approximately 5 MBbls of above‑ground storage tanks at the Mentor Storage Terminal.

Our terminaling and export business consists of the Partnership’s 100% interest in Hess North Dakota Export Logistics Operations LP (“Logistics Opco”), which owns the Ramberg Terminal Facility, the Tioga Rail Terminal, our crude oil rail cars, the Johnson’s Corner Header System and various connections into the Dakota Access Pipeline (“DAPL”). The following sections describe in more detail these assets and the related services that we provide.

Ramberg Terminal Facility

Our Ramberg Terminal Facility is a crude oil pipeline and truck unloading facility located in Williams County, North Dakota that receives crude oil by pipeline and truck from Chevron and third parties and exports crude oil by transporting it by pipeline to our Tioga Rail Terminal for loading onto crude oil rail cars or by injecting it directly into DAPL and other third‑party interstate pipeline systems. The facility has a combined pipeline and truck receipt capability of approximately 200 MBbl/d. Up to approximately 130 MBbl/d of crude oil can enter the facility through our crude oil gathering system. Crude oil can also enter the facility through truck unloading bays with a combined truck unloading capacity of approximately 70 MBbl/d.

The facility has a redelivery capability of up to approximately 285 MBbl/d through the following pipelines:

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a 14‑inch, 10‑mile crude oil pipeline with a current capacity of approximately 135 MBbl/d that connects to the Tioga Rail Terminal;

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two six‑inch crude oil pipelines with a combined capacity of approximately 25 MBbl/d that connects to third‑party long‑haul pipelines;

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one six‑inch and two eight‑inch crude oil pipelines with a combined capacity of approximately 55 MBbl/d that connects to third‑party long‑haul pipelines; and

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one 10‑inch crude oil pipeline with a capacity of approximately 70 MBbl/d that connects to a third‑party long‑haul pipeline.

The Ramberg Terminal Facility was constructed in 2006 and expanded in 2016. The facility has a combined shell storage capacity of approximately 40 MBbls, with an additional combined 240 MBbls of storage capacity with third parties.

Tioga Rail Terminal

The Tioga Rail Terminal is a 140 MBbl/d crude oil and 30 MBbl/d NGL rail loading terminal in Tioga, North Dakota that is connected to the Tioga Gas Plant, the Ramberg Terminal Facility and our crude oil gathering system.

The approximate 140 MBbl/d crude oil loading facility includes a dual loop track with 21 crude oil loading arms that commenced service in 2011. The terminal loads crude oil rail cars owned by us and third parties. The terminal also has three crude oil storage tanks with a combined shell storage capacity of approximately 290 MBbls. The terminal receives up to 30 MBbl/d of crude oil directly from a 14‑inch crude oil pipeline connected to, and included as part of, our Ramberg Terminal Facility.

The terminal is capable of loading crude oil unit trains, which are dedicated trains (typically ranging from approximately 100 to 110 cars) chartered for a single delivery destination that usually receive priority scheduling and result in a more cost‑effective method of shipping than standard rail shipment.

The terminal is capable of receiving up to 30 MBbl/d of NGLs through three NGL pipelines connected to the Tioga Gas Plant, including: (i) an eight‑inch propane pipeline with a capacity of approximately 35 MBbl/d; (ii) a six‑inch butane pipeline with a capacity of approximately 15 MBbl/d; and (iii) a six‑inch mixed NGL pipeline with a capacity of approximately 10 MBbl/d. The terminal also includes separate ladder tracks with track space for over 385 NGL rail cars and 16 NGL loading arms. The NGL rail cars are leased by Chevron and third parties.

The terminal has a direct rail connection to the BNSF Railway, which in turn connects to the Union Pacific, CSX, Norfolk Southern and other Class 1 railroads. Crude oil loaded onto rail cars at the terminal may be transported to various delivery points in the East Coast, West Coast and Gulf Coast regions of the United States. The terminal receives NGLs for loading onto rail cars for transportation to various delivery points in North America.

Crude Oil Rail Cars

We own a total of 550 crude oil rail cars, which we operate as unit trains consisting of approximately 100 to 110 crude oil rail cars, with which we provide crude oil transportation services to Chevron or third parties from the Tioga Rail Terminal to various delivery points in the East Coast, West Coast and Gulf Coast regions of the United States. Our crude oil rail cars were constructed between April 2015 and October 2015 to DOT‑117 safety standards. The effective capacity of the crude oil rail cars depends on round‑trip times to destination. For the year ended December 31, 2025, the average round‑trip duration was approximately 11 days and, based on this, the aggregate working capacity of our crude oil rail cars was approximately 32 MBbl/d. Our crude oil rail cars have a shell capacity of 728 Bbls per car and an effective loading capacity of approximately 92%, or approximately 670 Bbls per car.

Johnson’s Corner Header System

The Johnson’s Corner Header System is a crude oil pipeline header system located in McKenzie County, North Dakota that receives crude oil by pipeline from Chevron and third parties and delivers crude oil to DAPL and other third‑party interstate pipeline systems. It has a delivery capacity of approximately 100 MBbl/d of crude oil. The Johnson’s Corner Header System entered into service in 2017.

Other DAPL Connections

In addition to the connections at the Ramberg Terminal Facility and the Johnson’s Corner Header System, we also have other DAPL connections, which are crude oil delivery points within our terminal system located in Williams and Mountrail Counties, North Dakota that receive crude oil by pipeline from our crude oil gathering system for delivery into DAPL.

The following table sets forth certain information regarding our terminaling and export assets, which operate under a long‑term, fee‑based commercial agreement with Chevron:

Terminaling and Export Assets

(1)

Represents the aggregate redelivery capacity of the Ramberg Terminal Facility.

(2)

Represents the aggregate above-ground shell storage capacity of storage tanks at the Ramberg Terminal Facility.

(3)

Represents the aggregate above-ground shell storage capacity of storage tanks at the Tioga Rail Terminal.

(4)

We own a total of 550 crude oil rail cars, which we operate as unit trains consisting of approximately 100 to 110 crude oil rail cars. Our crude oil rail cars have been constructed to DOT‑117 safety standards.

(5)

For the year ended December 31, 2025, the average round‑trip duration was approximately 11 days and, based on this, the aggregate working capacity of our crude oil rail cars was approximately 32 MBbl/d. Our crude oil rail cars have a shell capacity of 728 Bbls per car and an effective loading capacity of approximately 92%, or approximately 670 Bbls per car.

(6)

Represents the aggregate redelivery capacity of the Johnson’s Corner Header System, which entered into service in 2017.

(7)

Represents the aggregate redelivery capacity of the DAPL Epping and Stanley connections, which entered into service in 2023.

Our Commercial Agreements with Chevron

We have long-term fee-based commercial agreements with certain subsidiaries of Chevron to provide (i) gas gathering, (ii) crude oil gathering, (iii) gas processing and fractionation, (iv) storage services, (v) terminaling and export services, and (vi) water handling services.

For the services performed under these commercial agreements, we receive a fee per barrel of crude oil, barrel of water, Mcf of natural gas, or Mcf equivalent of NGLs, as applicable, delivered during each month, and Chevron is obligated to provide us with minimum volumes of crude oil, water, natural gas and NGLs. Minimum volume commitments (“MVCs”) are equal to 80% of Chevron’s nominations in each development plan and apply on a three-year rolling basis such that MVCs are set for the three years following the most recent nomination. Without our consent, the MVCs resulting from the nominated volumes for any quarter or year contained in any prior development plan cannot be reduced by any updated development plan unless dedicated production is released by us. The applicable MVCs may, however, be increased as a result of the nominations contained in any such updated development plan. If Chevron fails to deliver its applicable MVCs during any quarter, then Chevron will pay us a shortfall fee equal to the volume of the deficiency multiplied by the applicable fee.

Except for the water services agreements and except for a certain gathering sub-system as described below, each of our commercial agreements with Chevron had an initial 10-year term effective January 1, 2014 (“Initial Term”). For this gathering sub-system, the Initial Term is 15 years effective January 1, 2014, and for the water services agreements the Initial Term is 14 years effective January 1, 2019. Each of our commercial agreements other than our storage services agreement includes an inflation escalator capped at 3% in any calendar year and a fee recalculation mechanism that allows fees to be adjusted annually during the Initial Term for updated estimates of cumulative throughput volumes and our capital and operating expenditures in order to target a return on capital deployed over the Initial Term of the applicable commercial agreement (or, with respect to the crude oil services fee under our terminal and export services agreement, the 20-year period commencing on the effective date of the agreement).

For certain crude oil gathering, terminaling, storage, gas processing and gas gathering commercial agreements with Chevron, we exercised our renewal options to extend each of these commercial agreements for one additional 10-year term (“Secondary Term”) effective January 1, 2024, through December 31, 2033. There were no changes to any provisions of the existing commercial agreements as a result of the exercise of the renewal options. For the remaining gathering sub-system, the Secondary Term is 5 years, and for the water services agreements the Secondary Term is 10 years, and we have the sole option to renew these remaining agreements for their Secondary Term that is exercisable at a later date. Upon the expiration of the Secondary Term, if any, the agreements will automatically renew for the subsequent one-year periods unless terminated by either party no later than 180 days prior to the end of the applicable Secondary Term.

Consistent with the existing terms of the commercial agreements, during the Secondary Term of each of our commercial agreements other than our storage services agreement and terminal and export services agreement (with respect to crude oil terminaling services), the fee recalculation model under each applicable agreement is replaced by an inflation-based fee structure. The initial fee for the first year of the Secondary Term is determined based on the average fees paid by Chevron under the applicable agreement during the last three years of the Initial Term (with such fees adjusted for inflation through the first year of the Secondary Term). For each year following the first year of the Secondary Term, the applicable fee is adjusted annually based on the percentage change in the consumer price index, provided that we may not increase any fee by more than 3% in any calendar year solely by reason of an increase in the consumer price index, and no fee will ever be reduced below the amount of the applicable fee payable by Chevron in the prior year as a result of a decrease in the consumer price index. During the Secondary Term, MVCs continue to be set at 80% of Chevron’s nominated volumes in each development plan set three years in advance. Except for the crude oil terminaling and water handling services, Chevron is entitled to receive a credit, calculated in barrels or Mcf, as applicable, with respect to the amount of any shortfall fee paid by Chevron and may apply such credit against any volumes delivered to us under the applicable agreement in excess of Chevron’s nominated volumes during any of the following four quarters after such credit is earned, after which time any unused credits will expire. The shortfall amounts received under MVCs during the Secondary Term (except for the crude oil terminaling and water handling services) are recorded as deferred revenue and recognized as revenue as the credits are utilized or expire.

Year 2023 was the final year of the annual rate redetermination process for the majority of our systems. At the end of 2023, the base rate for 2024 was set based on the average of the tariff rates from the years 2021 through 2023, adjusted for inflation, as described above. Rates are now adjusted each year based on an inflation escalator, as described above. For our terminaling and water gathering systems, the rates continue to be reset through our annual rate redetermination process through 2033. For all of our systems, MVCs continue to provide downside protection through 2033.

We believe these commercial agreements provide us with stable and predictable cash flows, an element of downside risk protection and minimal direct exposure to commodity price fluctuations.

The following table sets forth additional information regarding Chevron’s MVCs:

(1)

Under each of our commercial agreements other than our storage services agreement, Chevron is obligated to provide minimum volumes of crude oil, natural gas, NGLs and produced water, as applicable, to our assets on a quarterly basis and such volumes are reflected in the table above as annual averages of each year’s quarterly MVCs. The amounts under the gathering agreements also reflect the aggregate annual averages of the quarterly MVCs on our gathering subsystems.

(2)

The terminaling and export services agreement covers the Ramberg Terminal Facility, the Tioga Rail Terminal, our crude oil rail cars and the Johnson’s Corner Header System.

(3)

Represents MVCs for operated produced water gathering services.

For the year ended December 31, 2025, 97% of our revenues were attributable to our fee‑based commercial agreements with Chevron, including revenues from third‑party volumes delivered under these agreements. Our gas gathering and gas processing revenues comprised 77% of total affiliate revenues, excluding affiliate pass-through revenues. In 2023, we began providing our services directly to third-party customers. Together with Chevron, we are pursuing strategic relationships with third‑party producers and other midstream companies with operations in the Bakken in order to maximize our utilization rates.

Regulation of Our Operations

Environmental Regulation

General

Our operations are subject to extensive and frequently changing federal, state and local laws, regulations and ordinances relating to the protection of the environment. Among other things, these laws and regulations govern the emission or discharge of pollutants into or onto the land, air and water, the handling and disposal of solid and hazardous wastes and the remediation of contamination. As with the industry generally, compliance with existing and anticipated environmental laws and regulations increases our overall cost of business, including our costs to construct, maintain, operate and upgrade equipment and facilities. While these laws and regulations affect our capital expenditures and net income, we believe they do not currently affect our competitive position. However, these laws and regulations are subject to changes, or to changes in the interpretation of such laws and regulations, by regulatory authorities, and continued and future compliance with such laws and regulations may require us to incur significant expenditures. Additionally, noncompliance with environmental laws, regulations and permits can result in the imposition of significant administrative, civil and criminal penalties, injunctions limiting our operations, investigatory or remedial liabilities or bans or delays in the construction of additional facilities or equipment. While we are confident in our compliance with current environmental laws and regulations, we acknowledge the potential for policy shifts that could impact our operations. Since January 20, 2025, President Trump has issued executive orders and memoranda signaling a shift in environmental and energy policy in the United States. While the Trump Administration’s changes to the environmental regulatory landscape in the United States continue to develop, it is possible that additional changes in the future could impact our results of operations and those of our customers.

Furthermore, a release of hydrocarbons or hazardous substances into the environment could, to the extent the event is not insured, subject us to substantial expenses, including costs to clean up and remediate the release, comply with applicable laws and regulations and to resolve claims by third parties for personal injury or property damage, or by the U.S. federal government or state governments for natural resources damages. These impacts could directly and indirectly affect our business and have an adverse impact on our financial position, results of operations and liquidity. We cannot currently determine the amounts of such potential future impacts.

Air Emissions and Climate Change

We are subject to the Clean Air Act and its regulations and comparable state and local statutes and regulations in connection with air emissions from our operations. Under these laws, permits may be required before construction can commence on a new source of potentially significant air emissions, and operating permits may be required for sources that are already constructed. These permits may require controls on our air emission sources, and we may become subject to more stringent regulations requiring the installation of additional emission control technologies.

Future expenditures may be required to comply with the Clean Air Act and other federal, state and local requirements for our various sites, including our pipeline, processing, transportation, and storage facilities.

These air emissions requirements also affect Chevron’s Bakken operations from which we receive substantially all of our revenues. Chevron has been required in the past, and may be required in the future, to incur significant capital expenditures to comply with new legislative and regulatory requirements relating to its operations. To the extent these capital expenditures have a material effect on Chevron, they could have a material effect on our business and results of operations.

Legislative and regulatory measures to address greenhouse gas emissions (including carbon dioxide, methane and other gases) are in various phases of discussion, rescission or implementation, and some regulatory bodies have proposed or passed climate-related laws, rules and/or regulations. These include certain state actions to develop and implement statewide or regional carbon reduction or climate-related disclosure programs, each of which require or could require reductions in our greenhouse gas emissions or those of Chevron or disclosure of climate-related matters. Additionally, our customers or other business partners may require additional climate-related information from us if they are also subject to these or additional climate-related disclosure laws or regulations. Requiring reductions in greenhouse gas 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 greenhouse gas emissions programs, including acquiring emission credits or allotments. Additionally, climate-related disclosure requirements may result in increased compliance costs, and possible litigation and reputational risks if such disclosures are incomplete, inaccurate, misleading or do not otherwise meet the expectations of our stakeholders. Moreover, such requirements may not always be uniform across jurisdictions, which may result in increased uncertainty, complexity and cost for compliance. These requirements may also significantly affect Chevron’s Bakken operations and may have an indirect effect on our business, financial condition and results of operations. See“Risk Factors—Regulatory, Legal and Environmental Risks—Legislation, regulation, and other government actions and shifting customer and consumer preferences and other private efforts related to greenhouse gas (“GHG”) emissions and climate change could continue to increase our operational costs and reduce demand for our services, resulting in a material adverse effect on the Company’s results of operations and financial condition.”

Further, the Environmental Protection Agency (the “EPA”) has in the past finalized, and may in the future propose, regulations under the Clean Air Act addressing greenhouse gases, to which some of our facilities may become subject. In recent years, such rules and regulations, including compliance deadlines, have been proposed, amended, rescinded, challenged, and finalized, including with respect to rules and regulations governing greenhouse gas emissions or methane emissions from oil and natural gas production and natural gas processing and transmission facilities. Congress periodically considers legislation on greenhouse gas emissions, although the ultimate adoption and form of any federal legislation cannot presently be predicted. The current U.S. presidential administration has expressed an intention to scale back various other climate regulations launched under previous administrations. Most recently, on February 18, 2026, the EPA published a final rule repealing the 2009 greenhouse gas endangerment finding and the regulation of tailpipe greenhouse gas emissions from new motor vehicles and motor vehicle engines. The final rule is expected to be subject to litigation, and the impact of such repeal is difficult to predict at this time.

In addition to domestic regulation of greenhouse gases, there continues to be international interest in a global framework for greenhouse gas reductions. However, on January 20, 2025, President Trump issued an executive order that initiated the process to withdraw the United States from the Paris Agreement, which became effective in January 2026, mandated the end of the United States’ financial commitments under the UN Framework Convention on Climate Change, and revoked the U.S. International Climate Finance Plan. Nevertheless, several states and geographic regions in the United States have adopted legislation and regulations to reduce emissions of greenhouse gases, including cap and trade regimes and commitments to contribute to meeting the goals of the Paris Agreement. The withdrawal of the United States from the Paris Agreement may animate stronger actions by various other policymakers at the local, state, or regional levels.

While significant uncertainty exists as to regulation of methane or other greenhouse gas emissions under the Clean Air Act or other local, regional, or international regulatory regimes, the impact of future regulatory and legislative developments, if adopted or enacted, is likely to result in increased compliance costs, increased utility costs, additional operating restrictions on our business and an increase in the cost of products generally. Although such costs may impact our business directly or indirectly by impacting Chevron’s facilities or operations, the extent and magnitude of that impact cannot be reliably or accurately estimated due to the present uncertainty regarding the additional measures and how they will be implemented.

Waste Management and Related Liabilities

Many of the environmental laws and regulations affecting our operations relate to the release of hazardous substances or solid wastes into soils, groundwater and surface water, and include measures to control pollution of the environment. These laws generally regulate the generation, storage, treatment, transportation and disposal of solid and hazardous waste. They also require corrective action, including investigation and remediation, at a facility where such waste may have been released or disposed.

CERCLA. The Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”), which is also known as Superfund, and comparable state laws impose liability, without regard to fault or to the legality of the original conduct, on certain classes of persons that contributed to the release of a “hazardous substance” into the environment. These persons include former and present owners or operators of the site where the release occurred and the transporters and generators of the hazardous substances found at the site. Under CERCLA, these persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources, and for the costs of certain health studies. CERCLA also authorizes the EPA and, in some instances, third parties to act in response to threats to the public health or the environment and to seek to recover from the responsible persons the costs they incur. It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances or other pollutants released into the environment. In the course of our ordinary operations, we may generate waste and use substances that fall within CERCLA’s definition of a “hazardous substance” and, as a result, may be jointly and severally liable under CERCLA for all or part of the costs required to clean up sites contaminated by those substances. Additionally, emerging contaminants, like per- and polyfluoroalkyl substances (“PFAS”) such as perfluorooctanesulfonic acid (“PFOS”) and perfluorooctanoic acid (“PFOA”) compounds, have become subject to CERCLA regulation in addition to existing federal and state chemicals regulation, and PFAS has recently been regulated under the Toxic Substances Control Act (“TSCA”). Other emerging contaminants could also become subject to regulation under CERCLA, TSCA or comparable state laws. We cannot provide any assurance that the costs and liabilities associated with the future imposition of such remedial or regulatory compliance obligations upon us would not have a material adverse effect on our operations or financial position.

RCRA. We also generate solid wastes, including hazardous wastes, that are subject to the requirements of the federal Resource Conservation and Recovery Act (“RCRA”), and comparable state statutes. From time to time, the EPA considers the adoption of stricter disposal standards for non‑hazardous wastes. Hazardous wastes are subject to more rigorous and costly disposal requirements than are non‑hazardous wastes. Any changes in the regulations for treatment, storage or disposal of RCRA‑regulated waste could increase our capital expenditures and operating expenses. We continue to seek methods to minimize the generation of hazardous wastes in our operations.

Hydrocarbon wastes. We and Chevron currently own and lease, and have in the past owned and leased, properties where hydrocarbons have been handled for many years. Although we have aimed to utilize operating and disposal practices that we believe were standard in the industry at the time, hydrocarbons or other waste may have been disposed of or released on or under the properties owned or leased by us or on or under other locations where these wastes have been taken for disposal. In addition, many of these properties have been operated by third parties whose treatment and disposal or release of hydrocarbons or other wastes was not under our control. These properties and wastes disposed thereon may be subject to CERCLA, RCRA and comparable state laws. Assuming liability is established under these laws, we could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators), to clean up contaminated property (including contaminated groundwater) or to perform additional remedial activities to prevent further contamination.

Water

Our operations have the potential to result in the discharge of pollutants, including crude oil. Regulations under the Clean Water Act (“CWA”), the Oil Pollution Act of 1990 (“OPA‑90”), and state laws impose regulatory burdens on our operations. Spill prevention control and countermeasure requirements of federal laws and some state laws require containment to mitigate or prevent contamination of jurisdictional waters in the event of an oil overflow, rupture or leak. For example, the CWA requires us to maintain Spill Prevention Control and Countermeasure (“SPCC”), plans at many of our facilities. We maintain discharge permits for facilities required under the National Pollutant Discharge Elimination System program of the CWA and have implemented processes to oversee our compliance efforts.

In addition, the transportation and storage of crude oil or other hazardous substances over and adjacent to water involves risk and subjects us to the provisions of OPA‑90 and related state requirements. Among other requirements, OPA‑90 and the National Contingency Plan requires the owner or operator of a tank vessel or a facility to maintain an emergency plan to respond to releases of oil or other hazardous substances. Also, in case of any such release, OPA‑90 requires the responsible company to pay resulting removal costs and damages. OPA‑90 also provides for civil penalties and imposes criminal sanctions for violations of its provisions. We operate facilities at which releases of oil or other hazardous substances could occur. We have implemented emergency oil response plans for our components and facilities covered by OPA‑90, and we have established SPCC plans for facilities subject to CWA SPCC requirements.

Construction or maintenance of our pipelines, terminals and storage facilities may impact wetlands, which are also regulated under the CWA by the EPA and the U.S. Army Corps of Engineers. Regulatory requirements governing wetlands (including associated mitigation projects) may result in the delay of our pipeline projects while we obtain necessary permits and may increase the costs of new projects and maintenance activities. The definition of “waters of the United States” and, relatedly, the scope of CWA jurisdiction, are, and have been for many years, subject to notable rulemaking efforts and judicial challenges.

Employee and Community Safety

We are subject to the requirements of the Occupational Safety and Health Administration (“OSHA”), and comparable state statutes that regulate the protection of the health and safety of workers, as applied to seconded employees from Chevron. In addition, the OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of CERCLA and similar state statutes and regulations require that information be maintained about hazardous materials used or produced in operations and that this information be provided as applicable to employees, state and local government authorities and citizens.

Other Regulation

Rail Regulation

We work to ensure all of our rail cars in crude oil service meet the current United States Department of Transportation (the “DOT”) DOT‑117 safety standard applicable to “high hazard flammable trains”. The adoption of additional federal, state or local laws or regulations, including any voluntary measures by the rail industry regarding rail car design or crude oil and liquid hydrocarbon rail transport activities, or efforts by local communities to restrict or limit rail traffic involving crude oil, could affect our business by increasing compliance costs and decreasing demand for our services, which could adversely affect our financial position and cash flows. Moreover, any disruptions in the operations of railroads, including those due to shortages of rail cars, locomotives or labor, weather‑related problems, flooding, drought, derailments, mechanical difficulties, strikes, lockouts or bottlenecks, or other force majeure events could adversely impact our customers’ ability to move their product and, as a result, could affect our business.

Pipeline Regulation

The Federal Energy Regulatory Commission (“FERC”) has comprehensive regulatory authority over companies that transport natural gas in interstate commerce as well as jurisdiction over the interstate transportation of oil, NGLs and liquid hydrocarbons. While most of our facilities and operations are not subject to FERC jurisdiction, some of them are regulated by FERC, and FERC policies potentially could affect our other assets as well.

Section 1(b) of the Natural Gas Act (“NGA”) exempts natural gas gathering facilities from regulation by FERC. Most of our natural gas facilities – those upstream of the Tioga Gas Plant and LM4 processing plant – meet the traditional tests FERC has used to establish whether a pipeline qualifies as “gathering” that is exempt from its jurisdiction under the NGA. Accordingly, we believe that none of those facilities or related operations are subject to FERC regulation under the NGA or the Natural Gas Policy Act (“NGPA”). In December 2024, FERC granted, subject to certain conditions, NGA certificates allowing us to transport natural gas in interstate commerce on the 60.5 mile North Dakota pipeline extending from the outlet of the Tioga Gas Plant (our sole facility providing such interstate transportation service) to an interstate pipeline. Because our pipeline from the Tioga Plant will be used solely to transport gas owned by an affiliate, FERC granted the pipeline waivers from many of its regulatory requirements generally applicable to interstate natural gas pipelines, including “open access” requirements and various tariff and filing requirements. In that same order, FERC also confirmed the non-jurisdictional status of the Tioga Gas Plant and our gathering system upstream of the plant.

We believe that the crude oil and NGL pipelines in our gathering system similarly are not subject to FERC jurisdiction under the Interstate Commerce Act (“ICA”) because they do not provide transportation in interstate commerce. In July 2024, FERC granted our request for temporary waiver of ICA filing and reporting requirements related to a pipeline lease on a third-party pipeline for the transportation in interstate commerce of crude oil produced by an affiliate from production wells in McKenzie County, North Dakota to the affiliate’s leased storage tank at a storage hub in Williams County, North Dakota. The waiver was based on the fact that the lessee’s affiliate will own all of the crude transported and that there was no demonstrated or likely third-party interest in shipping on the crude oil pipeline.

The FERC waivers from more extensive jurisdiction over both the natural gas pipeline from the Tioga Gas Plant and the referenced North Dakota crude oil pipeline were based on the facts and FERC policies at the time of the orders; potential future changes in those facts or policies could subject the pipelines to additional FERC regulation. In addition, the classification and regulation of our facilities may be subject to change based on factual developments or future determinations or policy changes by FERC, the courts, or Congress. If it is subsequently determined that an individual facility is not exempt from FERC regulation under the NGA, NGPA, or ICA, or subject to additional regulation under those statutes with the elimination of the existing waivers, such a determination could decrease revenue, increase operating costs, and, depending upon the facility in question, adversely affect our results of operations and cash flows. In addition, if we or any of our facilities were found to have violated the NGA or the NGPA, FERC has civil penalty authority to impose penalties for such violations of up to $1,584,648 per violation per day for 2025 (with annual inflation adjustments going forward), as well as disgorgement of profits associated with any violation.

In addition to FERC-regulation of interstate transportation, state regulation of gathering facilities and intrastate transportation pipelines generally includes various safety, environmental and, in some circumstances, nondiscriminatory take and common purchaser requirements, as well as complaint‑based rate regulation. Other state regulations may not directly apply to our business, but may nonetheless affect the availability of natural gas, crude oil and NGLs for purchase, compression and sale.

Safety and Maintenance

Our terminal operations, including associated pipelines, are subject to strict safety laws and regulations, including regulations under OSHA and comparable state and local regulations. We believe our terminal facilities are operated in a manner consistent with industry safe practices and standards and have fire protection in compliance with local, state and federal regulations. The tanks designed for crude oil storage at our terminals are equipped with appropriate controls that minimize emissions and promote safety. Our terminal facilities have response plans, spill prevention and control plans and other programs to respond to emergencies. Generally, rail operations are subject to federal regulations and the Association of American Railroad rules.

The transportation and storage of crude oil and other hydrocarbon products involve a risk that hazardous liquids may be released into the environment, potentially causing harm to the public or the environment. The DOT, through the Pipeline and Hazardous Materials Safety Administration (“PHMSA”) and state agencies, enforces safety regulations with respect to the design, construction, operation, maintenance, inspection and management of our pipeline and storage facilities. PHMSA requires pipeline operators to implement integrity management programs, including more frequent inspections and other measures to ensure pipeline safety 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. The regulations require operators, including us, to (i) perform ongoing assessments of pipeline integrity, (ii) identify and characterize applicable threats to pipeline segments that could impact a HCA, (iii) improve data collection, integration and analysis, (iv) repair and remediate pipelines as necessary and (v) implement preventive and mitigating actions. 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. PHMSA’s regulations also require that pipeline operation and maintenance personnel meet certain qualifications and that pipeline operators develop comprehensive spill response plans, including extensive spill response training for pipeline personnel.

States are largely preempted by federal law from regulating pipeline safety for interstate lines, but most states are certified by the DOT to assume responsibility for enforcing federal intrastate pipeline regulations and inspection of intrastate pipelines. States may adopt stricter standards for intrastate pipelines than those imposed by the federal government for interstate lines; however, states vary considerably in their authority and capacity to address pipeline safety. State standards may include requirements for facility design and management in addition to requirements for pipelines. We do not expect these developments to have a material effect on our operations or revenues.

We inspect our pipelines to determine their condition and use the inspection information to evaluate appropriate preventative maintenance activities to validate line integrity and safety. Our inspections include the use of internal line inspection tools that provide information on the physical condition of our pipelines.

State regulations and our commercial agreements with Chevron contain product quality specification limits. However, if new or more stringent federal, state or local legal restrictions relating to the quality specification of crude oil or to crude oil transportation are adopted in areas where Chevron and our other customers operate, Chevron and our other customers could incur potentially significant added costs to comply with such requirements and experience delays or curtailment in the pursuit of production or development activities, which could reduce demand for our midstream services.

In October 2019, PHMSA started the rulemaking process for the three-part Mega Rule, which focused on: the safety of gas transmission pipelines (the first part of the Mega Rule), the safety of hazardous liquid pipelines, and enhanced emergency order procedures. In November 2021, PHMSA issued the second part of the Mega Rule that expands certain federal pipeline safety requirements to all onshore gas gathering pipelines, regardless of size or location. In August 2022, PHMSA issued the third and final part of the Mega Rule expanding the Management of Change process, extending corrosion control requirements for gas transmission pipelines, adding requirements that operators ensure no conditions exist following an extreme weather event that could adversely affect the safe operation of the pipeline, and adopting repair criteria for non-HCAs similar to those applicable to HCAs. In October 2024, PHMSA issued a notice of proposed rulemaking recommending modernizing and simplifying the hazardous material regulations, enhancing safety standards across rail, highway, and vessel transportation while also providing $100 million in annual cost savings for businesses and consumers. Following the change in Presidential Administration, PHMSA in January 2025 extended the public comment period for the rulemaking until April 28, 2025, but has not otherwise acted on that proposed rulemaking. In May 2025, PHMSA issued two Advance Notices of Proposed Rulemaking (“ANPRM”) seeking public comment on updates to its safety regulations for pipelines and LNG facilities aimed at implementing the President’s “Unleashing American Energy” Executive Order. In June 2025, PHMSA issued another ANPRM to solicit stakeholder feedback on whether to repeal or amend any requirements in its pipeline safety regulations to eliminate undue burdens on the identification, development, and use of domestic energy resources and to improve government efficiency. The ultimate impact of those efforts of the Trump Administration remains to be seen. If safety standards were to become more stringent in the future, it could cause us, like other similarly situated pipeline operators, to incur increased costs for operating our pipelines, to incur increased costs for developing future projects, or to suffer potential adverse impacts to our operations. We do not, however, expect the costs to comply with these rules to be material to our overall financial results.

Security

Since the September 11, 2001, terrorist attacks on the United States, the U.S. government has issued warnings that energy infrastructure assets may be future targets of terrorist organizations. These developments have subjected our operations to increased risks. Increased security measures taken by us as a precaution against possible terrorist attacks may have resulted in increased costs to our business. Where required by federal, state or local laws, we believe we have prepared effective security plans for the storage and distribution facilities we operate. Terrorist attacks aimed at our facilities and any global and domestic economic repercussions from terrorist activities could adversely affect our financial condition, results of operations and cash available for distribution to our shareholders.

Governmental standards for the protection of computer-based systems and technology from cyber threats and attacks, have either been adopted or are being considered in the U.S. Congress and by U.S. Executive Branch departments and agencies, including the Department of Homeland Security. We currently may be subject to existing standards or standards implemented in the future. We and Chevron have implemented a cybersecurity risk management program (see Item 1C. Cybersecurity). While we continually seek to improve our cybersecurity risk management program, we cannot guarantee it will be fully implemented, complied with or effective. A significant cyber‑attack could have a material adverse effect on our operations and those of our customers.

Title to Properties and Permits

Certain of the pipelines connecting our facilities are constructed on rights‑of‑way granted by the apparent record owners of the property and in some instances these rights‑of‑way are revocable at the election of the grantor. In several instances, lands over which rights‑of‑way have been obtained could be subject to prior liens that have not been subordinated to the right‑of‑way grants. We have obtained permits from public authorities to cross over or under, or to lay pipelines in or along, watercourses, county roads, municipal streets and state highways and, in some instances, these permits are revocable at the election of the grantor. These permits may also be subject to renewal from time to time and we will generally seek renewal or arrange alternative means of transport through additional investment or commercial agreements. We have also obtained permits from railroad companies to cross over or under lands or rights-of-way, many of which are also revocable at the grantor’s election.

We work to maintain satisfactory permits and/or title to all our rights-of-way and satisfactory title to all of our assets.

Other Items

Competition

As a result of our contractual relationship with Chevron under our commercial agreements and our direct connections to Chevron’s production operations in the Williston Basin, we believe that we will not face significant competition from other midstream service providers for Chevron’s crude oil, natural gas or NGL gathering, processing or terminaling services or for other midstream services relating to Chevron’s production operations in the Bakken.

If Chevron’s production volumes decrease or if Chevron’s customers reduce their purchases of crude oil, natural gas or NGLs from Chevron due to the increased availability of less expensive products from other suppliers or for other reasons, Chevron may meet only the minimum volume commitments of our commercial agreements (or pay the shortfall fee if it does not meet the minimum volume), which could cause a material decrease in our revenues.

Seasonality

The crude oil, natural gas and NGLs that we handle, process and store are directly affected by the level of supply and demand for crude oil, natural gas and NGLs in the markets served directly or indirectly by our assets. For example, we generally fill the storage cavern at our Mentor Storage Terminal with propane during the warmer months when demand for propane is low, and gradually withdraw propane from the cavern during the colder months when demand is higher. However, we believe that many effects of seasonality on our revenues are substantially mitigated through the use of our fee-based commercial agreements with Chevron that include minimum volume commitments.

Insurance

Our assets may experience physical damage as a result of an accident or natural disaster. These hazards have the potential to cause personal injury and loss of life, severe damage to and destruction of property and equipment, pollution or environmental damage, and suspension of operations. We carry insurance policies for business interruption, certain property damage and third-party liabilities, which include sudden and accidental pollution liabilities, at varying levels of deductibles and limits that we believe are reasonable and prudent under the circumstances to cover our operations and assets. As we continue to grow, we will continue to evaluate our policy limits and deductibles as they relate to the overall cost and scope of our insurance program.

Human Capital Resources

We are managed by the board of directors and executive officers of Hess Midstream GP LLC, the general partner of our general partner. Neither we nor our subsidiaries have any employees. Hess Midstream GP LLC, as the general partner of our general partner, has the sole responsibility for providing the personnel necessary to conduct our operations and has entered into an employee secondment agreement with Chevron and certain of its subsidiaries pursuant to which Chevron and its subsidiaries make available the services of their employees in exchange for a fee. As a result, all of the employees that conduct our business are employed by affiliates of our general partner, including Chevron. As of December 31, 2025, Hess Midstream GP LLC and its affiliates had approximately 195 full‑time employee equivalents supporting our operations, including employees in the field performing services and support staff from other offices.

Office

The principal office of our Company is located at 1400 Smith Street, Houston, Texas 77002.

Website Access to Our Reports

We make available free of charge through our website, at www.hessmidstream.com, our annual reports on Form 10‑K, quarterly reports on Form 10‑Q, current reports on Form 8‑K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), as soon as reasonably practicable after such material is electronically filed with or furnished to the SEC. The reports are also available on the SEC’s website at www.sec.gov. The information on our website is not incorporated by reference into this report. Our Code of Business Conduct and Ethics, Corporate Governance Guidelines, and the Audit Committee Charter are available on our website and are also available in print free of charge upon request to Investor Relations at our principal executive office.