Hess Midstream LP 10-Q

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations Management’s Discussion and Analysis of Financial Condition and Results of Operations should be read in conjunction with the unaudited financial statements and accompanying footnotes included under Item 1. Financial Statements and in conjunction with the audited consolidated financial statements and accompanying footnotes in our Annual Report on Form 10‑K for the year ended December 31, 2024 (our “2024 Annual Report”). Unless otherwise stated or the context otherwise indicates, references in this report to “Hess Midstream LP,” “the Company,” “us,” “our,” “we” or similar terms refer to Hess Midstream LP, including its consolidated subsidiaries. References to “Partnership” refer to Hess Midstream Operations LP. References to “Sponsor” or “Sponsors” refer to (a) Hess Corporation (“Hess”) and GIP II Blue Holding, L.P. (“GIP”) when referring to periods prior to May 30, 2025, (b) Hess from May 30, 2025 to July 17, 2025, and (c) Chevron from July 18, 2025 to present. As used in this report, the term “Chevron” may refer to Chevron Corporation, one or more of its consolidated subsidiaries, or to all of them taken as a whole. All of these terms are used for convenience only and are not intended as a precise description of any of the separate companies, each of which manages its own affairs. This discussion contains forward‑looking statements that involve risks and uncertainties. Our actual results could differ materially from those discussed below. Factors that could cause or contribute to such differences include, but are not limited to, those risk factors discussed in our 2024 Annual Report and risk factors included in Part II, Item 1A of this Quarterly Report on Form 10-Q. Overview Organization. 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 our Sponsor, 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. Our assets and operations are organized into the following three reportable segments: (1) gathering (2) processing and storage and (3) terminaling and export. We are managed and controlled by Hess Midstream GP LLC (“GP LLC”), the general partner of our general partner. Prior to May 30, 2025, GP LLC was owned 50/50 by affiliates of Hess and GIP. As described below, as of the closing of the May 2025 GIP equity offering transaction, GIP no longer holds any Class A Shares of the Company or any Class B Units of the Partnership and no longer holds a direct or indirect ownership interest in GP LLC, our general partner, the Company, or the Partnership. From May 30, 2025 to July 17, 2025, GP LLC was wholly owned by Hess. Chevron Merger. On July 18, 2025, Hess and Chevron completed the previously announced merger contemplated by the Agreement and Plan of Merger, dated as of October 22, 2023 (the “Merger”). As a result of the Merger, Chevron is the direct parent of Hess and, therefore, indirectly owns 100% of the limited liability company interests in GP LLC, 100% of the partnership interests in our general partner, and an approximate 37.9% interest in the Company on a consolidated basis. 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, following the completion of the Merger, Chevron wholly owns the Hess entities that are the counterparties to these agreements. Operational Highlights. In the third quarter of 2025, we completed the construction of a new compressor station. The new station provides approximately 35 MMcf/d of installed capacity and can be expanded to provide an additional 35 MMcf/d in the future. Equity Transactions. On January 15, 2025, the Partnership purchased directly from the Sponsors 2,572,677 Class B units representing limited partner interests in the Partnership (“Class B Units”) for an aggregate purchase price of approximately $100.0 million. The purchase price per Class B Unit was $38.87, the closing price of the Class A Shares on January 13, 2025. On May 9, 2025, the Partnership purchased directly from the Sponsors 5,151,842 Class B Units for an aggregate purchase price of approximately $190.0 million. The purchase price per Class B Unit was $36.88, the closing price of the Class A Shares on May 5, 2025. On August 8, 2025, the Partnership purchased directly from the Sponsor 695,894 Class B Units for an aggregate purchase price of approximately $30.0 million. The purchase price per Class B Unit was $43.11, the closing price of the Class A Shares on August 4, 2025. The repurchase transactions described above were funded using borrowings under the Partnership’s existing revolving credit facility. 20 PART I – FINANCIAL INFORMATION (CONT’D) Table of Contents On February 12, 2025, GIP sold an aggregate of 11,000,000 of our Class A Shares representing limited partner interests (the “Class A Shares”) in an underwritten public offering at a price of $39.45 per Class A Share, less underwriting discounts. GIP also granted the underwriter an option to purchase up to an additional 1,650,000 Class A Shares at the same price per Class A Share, which was exercised in full on February 19, 2025. GIP received net proceeds from the offering of approximately $494.7 million, after deducting underwriting discounts. On May 30, 2025, GIP sold an aggregate of 15,022,517 of our Class A Shares in an underwritten public offering at a price of $37.25 per Class A Share, less underwriting discounts. GIP received net proceeds from the offering of approximately $553.7 million, after deducting underwriting discounts. The Company did not receive any proceeds from the offering transactions described above. The offering transactions were conducted pursuant to a registration rights agreement among us and the Sponsors. In the second quarter of 2025, we repurchased $10.0 million of our publicly traded Class A Shares through an accelerated share repurchase (“ASR”) transaction with a financial institution. Under the terms of the ASR, we paid $10.0 million in cash to the financial institution and received 267,532 Class A Shares as determined by the average of the daily volume-weighted average prices of Class A Shares during the term of the transaction. In the third quarter of 2025, we repurchased $70.0 million of our publicly traded Class A Shares through an ASR transaction with a financial institution. Under the terms of the ASR, we paid $70.0 million in cash to the financial institution and received 1,706,118 Class A Shares as determined by the average of the daily volume-weighted average prices of Class A Shares during the term of the transaction. The ASR transactions described above were funded using borrowings under the Partnership’s existing revolving credit facility. As a result of the equity offering and unit and share repurchase transactions described above, our public ownership increased from approximately 47.3% at December 31, 2024, to approximately 62.1% at September 30, 2025, on a consolidated basis. Credit Ratings. On July 24, 2025, the Partnership received an investment grade rating from S&P. S&P assigned a rating of ‘BBB-’ to the Partnership’s unsecured debt and raised the Partnership’s issuer level credit rating to ‘BBB-’, with a stable outlook. As a result of this investment grade rating, the Partnership is not required to comply with certain restrictive covenants set forth in the unsecured notes indentures. Additionally, as a result of the investment grade rating, certain restrictive covenants on the Partnership’s Credit Facilities fell away and became more permissive. At September 30, 2025, the Partnership’s senior unsecured debt is rated ‘BBB-’ by S&P, BB+ by Fitch Ratings, and Ba2 by Moody’s Investors Service. Income Taxes. On July 4, 2025, the One Big Beautiful Bill Act (“Act”) was enacted into law in the U.S., providing for significant changes to U.S. Federal tax law. Under GAAP, the impact of tax law changes is recognized in the period of enactment. There was no material impact of the new Act on our consolidated financial statements for the three and nine months ended September 30, 2025, and we do not expect a material impact on our future results of operations or cash flows. Third Quarter Results Significant financial and operating highlights for the third quarter of 2025 included: • Consolidated net income of $175.5 million; • Net income attributable to Hess Midstream LP after deduction for noncontrolling interest of $97.7 million, or $0.75 basic earnings per Class A Share; • Net cash provided by operating activities of $258.9 million; • Adjusted EBITDA of $320.7 million; • Cash distribution of $0.7548 per Class A Share declared on October 27, 2025, an increase of $0.0178 per Class A Share for the third quarter of 2025 as compared with the second quarter of 2025. 21 PART I – FINANCIAL INFORMATION (CONT’D) Table of Contents Revenues and other income in the third quarter of 2025 were $420.9 million, up from $378.5 million in the prior‑year quarter, primarily due to higher physical volumes and higher tariff rates. Total operating costs and expenses in the third quarter of 2025 were $162.0 million, up from $146.8 million in the prior-year quarter, primarily due to higher employee costs, depreciation and pass-through electricity and produced water trucking and disposal costs. Interest expense, net of interest income, in the third quarter of 2025 was $57.1 million, up from $51.8 million in the prior-year quarter, primarily due to higher borrowings under the Company’s revolving credit facility. Income tax expense was $31.5 million, up from $18.9 million in the prior-year quarter, primarily resulting from ownership changes following the GIP secondary equity offering and Class A Share and Class B Unit repurchase transactions. As a result, consolidated net income increased $10.8 million and Adjusted EBITDA increased $33.8 million for the third quarter of 2025 compared with the third quarter of 2024. Throughput volumes increased 10% for gas processing, 7% for oil terminaling and 7% for water gathering in the third quarter of 2025 compared with the third quarter of 2024, primarily due to higher production and higher third-party gas volumes. For additional discussion of the results of operations at the segment level, see “ Results of Operations ” below. For additional information regarding Adjusted EBITDA, our non‑GAAP financial measure, see “ How We Evaluate Our Operations ” and “ Reconciliation of Non‑GAAP Financial Measure ” below. How We Generate Revenues We generate substantially all of our revenues by charging fees for gathering, compressing and processing natural gas and fractionating natural gas liquids (“NGLs”); gathering, terminaling, loading and transporting crude oil and NGLs; storing and terminaling propane; and gathering and disposing of produced water. We have entered into long‑term, fee‑based commercial agreements with Chevron effective January 1, 2014, for oil and gas services agreements, and effective January 1, 2019, for water services agreements. 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. 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 this gathering sub-system, the initial term is 15 years effective January 1, 2014, and the Secondary Term is 5 years. For the water services agreements the initial term is 14 years effective January 1, 2019, and the Secondary Term is 10 years. 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 subsequent one-year periods unless terminated by either party no later than 180 days prior to the end of the applicable Secondary Term. These agreements include dedications covering substantially all of Chevron’s existing and future owned or controlled production in the Bakken, minimum volume commitments, inflation escalators and fee recalculation mechanisms, all of which are intended to provide us with cash flow stability and growth, as well as downside risk protection. In particular, Chevron’s minimum volume commitments under our commercial agreements provide minimum levels of cash flows and the fee recalculation mechanisms under the agreements allow fees to be adjusted annually to provide us with cash flow stability during the initial term of the agreements. During the Secondary Term of the agreements, the fee recalculation model is replaced by an inflation-based fee structure. See Note 3, Related Party Transactions for additional description of our commercial agreements. Our revenues also include revenues from (i) third-party volumes contracted directly with us, (ii) third-party volumes contracted with Chevron and delivered to us under the commercial agreements with Chevron described above, and (iii) pass-through third-party rail transportation costs, third-party produced water trucking and disposal costs, electricity fees and certain other third-party fees, for which we recognize revenues in an amount equal to the costs. Together with our Sponsor, 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. 22 PART I – FINANCIAL INFORMATION (CONT’D) Table of Contents How We Evaluate Our Operations Our management uses a variety of financial and operating metrics to analyze our operating results and profitability. These metrics include (i) volumes, (ii) operating and maintenance expenses, and (iii) Adjusted EBITDA. Volumes. The amount of revenues we generate primarily depends on the volumes of crude oil, natural gas, NGLs and produced water that we handle at our gathering, processing, terminaling, storage facilities and disposal facilities. These volumes are affected primarily by the supply of and demand for crude oil, natural gas and NGLs in the markets served directly or indirectly by our assets, including changes in crude oil prices, which may further affect volumes delivered by Chevron. Although Chevron has committed to minimum volumes under our commercial agreements described above, our results of operations will be impacted by our ability to: • utilize the remaining uncommitted capacity on, or add additional capacity to, our existing assets, and optimize our existing assets; • identify and execute expansion projects, and capture incremental throughput volumes from Chevron and third parties for these expanded facilities; • increase throughput volumes at our Ramberg Terminal Facility, Tioga Rail Terminal and the Johnson’s Corner Header System by interconnecting with new or existing third‑party gathering pipelines; and • increase gas throughput volumes by interconnecting with new or existing third‑party gathering pipelines. Operating and Maintenance Expenses. Our management seeks to maximize the profitability of our operations by effectively managing operating and maintenance expenses. These expenses are comprised primarily of costs charged to us under our omnibus agreement and employee secondment agreement, third‑party contractor costs, utility costs, insurance premiums, third‑party service provider costs, related property taxes and other non‑income taxes and maintenance expenses, such as expenditures to repair, refurbish and replace storage facilities and to maintain equipment reliability, integrity and safety. These expenses generally remain relatively stable across broad ranges of throughput volumes but can fluctuate from period to period depending on the mix of activities performed during that period and the timing of substantial expenses, such as gas plant turnarounds. We seek to manage our maintenance expenditures by scheduling periodic maintenance on our assets in order to minimize significant variability in these expenditures and minimize their impact on our cash flow. Adjusted EBITDA. We define “Adjusted EBITDA” as reported net income (loss) before net interest expense, income tax expense (benefit), and depreciation and amortization, as further adjusted to eliminate the impact of certain items that we do not consider indicative of our ongoing operating performance, such as transaction costs, other income and other non‑cash and non‑recurring items, if applicable. We use Adjusted EBITDA to analyze our performance and liquidity. Adjusted EBITDA is a non‑GAAP supplemental financial measure that management and external users of our consolidated financial statements, such as industry analysts, investors, lenders and rating agencies, may use to assess: • our operating performance as compared to other publicly traded companies in the midstream energy industry, without regard to historical cost basis or financing methods; • the ability of our assets to generate sufficient cash flow to make distributions to our shareholders; • our ability to incur and service debt and fund capital expenditures; and • the viability of acquisitions and other capital expenditure projects and the returns on investment of various investment opportunities. We believe that the presentation of Adjusted EBITDA provides useful information to investors in assessing our financial condition and results of operations. The GAAP measures most directly comparable to Adjusted EBITDA are net income (loss) and net cash provided by (used in) operating activities. Adjusted EBITDA should not be considered as an alternative to GAAP net income (loss), income (loss) from operations, net cash provided by (used in) operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. Adjusted EBITDA has important limitations as an analytical tool because it excludes some but not all items that affect net income and net cash provided by operating activities. You should not consider Adjusted EBITDA in isolation or as a substitute for analysis of our results as reported under GAAP. Additionally, because Adjusted EBITDA may be defined differently by other companies in our industry, our definition of Adjusted EBITDA may not be comparable to similarly titled measures of other companies, thereby diminishing its utility. 23 PART I – FINANCIAL INFORMATION (CONT’D) Table of Contents Results of Operations Three Months Ended September 30, 2025 Compared to Three Months Ended September 30, 2024 Results of operations for the three months ended September 30, 2025 and 2024 are presented below (in millions, unless otherwise noted). For the Three Months Ended September 30, 2025 Gathering Processing and Storage Terminaling and Export Interest and Other Consolidated Hess Midstream LP Revenues Affiliate services $ 221.5 $ 151.4 $ 32.7 $ - $ 405.6 Third-party services 5.8 8.2 - - 14.0 Other income - - 1.3 - 1.3 Total revenues 227.3 159.6 34.0 - 420.9 Costs and expenses Operating and maintenance expenses (exclusive of depreciation shown separately below) 58.6 29.2 10.3 - 98.1 Depreciation expense 34.5 17.7 4.4 - 56.6 General and administrative expenses 2.7 1.9 0.3 2.4 7.3 Total operating costs and expenses 95.8 48.8 15.0 2.4 162.0 Income (loss) from operations 131.5 110.8 19.0 (2.4 ) 258.9 Income from equity investments - 5.2 - - 5.2 Interest expense, net - - - 57.1 57.1 Income (loss) before income tax expense 131.5 116.0 19.0 (59.5 ) 207.0 Income tax expense - - - 31.5 31.5 Net income (loss) 131.5 116.0 19.0 (91.0 ) 175.5 Less: Net income (loss) attributable to noncontrolling interest 49.4 43.6 7.2 (22.4 ) 77.8 Net income (loss) attributable to Hess Midstream LP $ 82.1 $ 72.4 $ 11.8 $ (68.6 ) $ 97.7 Throughput volumes Gas gathering (MMcf/d) (1) 480 480 Crude oil gathering (MBbl/d) (2) 123 123 Gas processing (MMcf/d) (1) 462 462 Crude oil terminaling (MBbl/d) (2) 130 130 NGL loading (MBbl/d) (2) 18 18 Water gathering (MBbl/d) (2) 137 137 (1) Million cubic feet per day (2) Thousand barrels per day 24 PART I – FINANCIAL INFORMATION (CONT’D) Table of Contents For the Three Months Ended September 30, 2024 Gathering Processing and Storage Terminaling and Export Interest and Other Consolidated Hess Midstream LP Revenues Affiliate services $ 201.7 $ 140.8 $ 28.9 $ - $ 371.4 Third-party services 1.8 4.3 0.1 - 6.2 Other income - - 0.9 - 0.9 Total revenues 203.5 145.1 29.9 - 378.5 Costs and expenses Operating and maintenance expenses (exclusive of depreciation shown separately below) 51.3 30.3 7.4 - 89.0 Depreciation expense 32.2 15.0 4.3 - 51.5 General and administrative expenses 2.4 1.2 0.3 2.4 6.3 Total operating costs and expenses 85.9 46.5 12.0 2.4 146.8 Income (loss) from operations 117.6 98.6 17.9 (2.4 ) 231.7 Income from equity investments - 3.7 - - 3.7 Interest expense, net - - - 51.8 51.8 Income (loss) before income tax expense 117.6 102.3 17.9 (54.2 ) 183.6 Income tax expense - - - 18.9 18.9 Net income (loss) 117.6 102.3 17.9 (73.1 ) 164.7 Less: Net income (loss) attributable to noncontrolling interest 68.0 59.0 10.5 (31.4 ) 106.1 Net income (loss) attributable to Hess Midstream LP $ 49.6 $ 43.3 $ 7.4 $ (41.7 ) $ 58.6 Throughput volumes Gas gathering (MMcf/d) (1) 442 442 Crude oil gathering (MBbl/d) (2) 116 116 Gas processing (MMcf/d) (1) 419 419 Crude oil terminaling (MBbl/d) (2) 122 122 NGL loading (MBbl/d) (2) 15 15 Water gathering (MBbl/d) (2) 128 128 (1) Million cubic feet per day (2) Thousand barrels per day Gathering Revenues and other income increased $23.8 million in the third quarter of 2025 compared to the third quarter of 2024, of which $6.5 million is attributable to higher tariff rates, $5.4 million is attributable to higher gas gathering physical volumes and $3.6 million is attributable to higher pass‑through revenue. Additionally, $3.4 million is attributable to services provided directly to third parties, $2.5 million is attributable to higher water gathering and disposal revenue and $2.4 million is attributable to higher crude oil gathering physical volumes. Operating and maintenance expenses (exclusive of depreciation) increased $7.3 million, of which $3.7 million is attributable to higher employee costs charged to us under our omnibus and employee secondment agreements and $3.6 million is attributable to higher pass-through costs, including produced water trucking and disposal and electricity fees. Depreciation expense increased $2.3 million due to new gathering assets brought into service. 25 PART I – FINANCIAL INFORMATION (CONT’D) Table of Contents Processing and Storage Revenues and other income increased $14.5 million in the third quarter of 2025 compared to the third quarter of 2024, of which $7.9 million is attributable to higher gas processing physical volumes, $3.6 million is attributable to higher tariff rates and $3.5 million is attributable to services provided directly to third parties, slightly offset by $0.5 million attributable to lower pass‑through revenue. Operating and maintenance expenses (exclusive of depreciation) decreased $1.1 million, of which $2.4 million is attributable to lower maintenance activity, partially offset by $1.3 million attributable to higher employee costs charged to us under our omnibus and employee secondment agreements. Depreciation expense increased $2.7 million, primarily related to suspension of the Capa gas plant project and related engineering cost write off. Income from equity investments increased $1.5 million, primarily due to higher volumes processed at the LM4 plant. Terminaling and Export Revenues and other income increased $4.1 million in the third quarter of 2025 compared to the third quarter of 2024, of which $2.7 million is attributable to higher physical volumes, $1.1 million is attributable to higher tariff rates and $0.3 million is attributable to services provided directly to third parties. Operating and maintenance expenses (exclusive of depreciation) increased $2.9 million, of which $2.3 million is attributable to higher maintenance activity and $0.6 million is attributable to higher employee costs charged to us under our omnibus and employee secondment agreements. Interest and Other Interest expense, net of interest income, increased $5.3 million in the third quarter of 2025 compared to the third quarter of 2024, of which $3.9 million is attributable to higher interest on higher borrowings under our Credit Facilities, $0.8 million is attributable to higher interest on senior unsecured notes, including amortization of deferred finance costs, and $0.6 million is attributable to lower interest income. Income tax expense increased $12.6 million in the third quarter of 2025 compared to the third quarter of 2024, primarily driven by increased ownership of the Partnership by Hess Midstream LP following equity offering and share and unit repurchase transactions in 2024 and 2025. 26 PART I – FINANCIAL INFORMATION (CONT’D) Table of Contents Nine Months Ended September 30, 2025 Compared to Nine Months Ended September 30, 2024 Results of operations for the nine months ended September 30, 2025 and 2024 are presented below (in millions, unless otherwise noted). For the Nine Months Ended September 30, 2025 Gathering Processing and Storage Terminaling and Export Interest and Other Consolidated Hess Midstream LP Revenues Affiliate services $ 642.6 $ 447.3 $ 95.3 $ - $ 1,185.2 Third-party services 10.7 18.0 0.2 - 28.9 Other income - - 3.0 - 3.0 Total revenues 653.3 465.3 98.5 - 1,217.1 Costs and expenses Operating and maintenance expenses (exclusive of depreciation shown separately below) 163.7 87.5 26.6 - 277.8 Depreciation expense 99.6 47.2 13.1 - 159.9 General and administrative expenses 8.9 5.5 0.8 7.7 22.9 Total operating costs and expenses 272.2 140.2 40.5 7.7 460.6 Income (loss) from operations 381.1 325.1 58.0 (7.7 ) 756.5 Income from equity investments - 12.6 - - 12.6 Interest expense, net - - - 168.9 168.9 Income (loss) before income tax expense 381.1 337.7 58.0 (176.6 ) 600.2 Income tax expense - - - 83.6 83.6 Net income (loss) 381.1 337.7 58.0 (260.2 ) 516.6 Less: Net income (loss) attributable to noncontrolling interest 163.2 144.7 24.9 (75.8 ) 257.0 Net income (loss) attributable to Hess Midstream LP $ 217.9 $ 193.0 $ 33.1 $ (184.4 ) $ 259.6 Throughput volumes Gas gathering (MMcf/d) (1) 459 459 Crude oil gathering (MBbl/d) (2) 122 122 Gas processing (MMcf/d) (1) 445 445 Crude oil terminaling (MBbl/d) (2) 131 131 NGL loading (MBbl/d) (2) 16 16 Water gathering (MBbl/d) (2) 134 134 (1) Million cubic feet per day (2) Thousand barrels per day 27 PART I – FINANCIAL INFORMATION (CONT’D) Table of Contents For the Nine Months Ended September 30, 2024 Gathering Processing and Storage Terminaling and Export Interest and Other Consolidated Hess Midstream LP Revenues Affiliate services $ 582.0 $ 411.4 $ 85.9 $ - $ 1,079.3 Third-party services 5.1 12.3 0.2 - 17.6 Other income - - 2.7 - 2.7 Total revenues 587.1 423.7 88.8 - 1,099.6 Costs and expenses Operating and maintenance expenses (exclusive of depreciation shown separately below) 148.4 82.8 23.4 - 254.6 Depreciation expense 94.5 44.3 13.0 - 151.8 General and administrative expenses 6.8 3.4 0.7 6.3 17.2 Total operating costs and expenses 249.7 130.5 37.1 6.3 423.6 Income (loss) from operations 337.4 293.2 51.7 (6.3 ) 676.0 Income from equity investments - 10.1 - - 10.1 Interest expense, net - - - 150.0 150.0 Income (loss) before income tax expense 337.4 303.3 51.7 (156.3 ) 536.1 Income tax expense - - - 49.2 49.2 Net income (loss) 337.4 303.3 51.7 (205.5 ) 486.9 Less: Net income (loss) attributable to noncontrolling interest 210.1 189.1 32.3 (97.3 ) 334.2 Net income (loss) attributable to Hess Midstream LP $ 127.3 $ 114.2 $ 19.4 $ (108.2 ) $ 152.7 Throughput volumes Gas gathering (MMcf/d) (1) 429 429 Crude oil gathering (MBbl/d) (2) 112 112 Gas processing (MMcf/d) (1) 410 410 Crude oil terminaling (MBbl/d) (2) 122 122 NGL loading (MBbl/d) (2) 15 15 Water gathering (MBbl/d) (2) 123 123 (1) Million cubic feet per day (2) Thousand barrels per day Gathering Revenues and other income increased $66.2 million in the first nine months of 2025 compared to the first nine months of 2024, of which $18.9 million is attributable to higher gas gathering physical volumes, $17.7 million is attributable to higher tariff rates, $8.4 million is attributable to higher pass‑through revenue and $8.0 million is attributable to higher water gathering and disposal revenue. Additionally, $7.7 million is attributable to higher crude oil gathering physical volumes, $4.2 million is attributable to services provided directly to third parties and $1.3 million is attributable to crude oil MVCs recognized in revenue upon expiration of shortfall fee credits. Operating and maintenance expenses (exclusive of depreciation) increased $15.3 million in the first nine months of 2025 compared to the first nine months of 2024, of which $10.9 million is attributable to higher employee costs charged to us under our omnibus and employee secondment agreements and $8.4 million is attributable to higher pass-through costs, including produced water trucking and disposal and electricity fees, partially offset by $4.0 million attributable to lower maintenance activities. Depreciation expense increased $5.1 million due to new compressors and other new gathering assets brought into service. General and administrative expenses increased $2.1 million due to higher employee costs charged to us under our omnibus and employee secondment agreements. 28 PART I – FINANCIAL INFORMATION (CONT’D) Table of Contents Processing and Storage Revenues and other income increased $41.6 million in the first nine months of 2025 compared to the first nine months of 2024, of which $26.2 million is attributable to higher gas processing physical volumes, $9.1 million is attributable to higher tariff rates, $4.4 million is attributable to services provided directly to third parties and $1.9 million is attributable to higher pass-through revenue. Operating and maintenance expenses (exclusive of depreciation) increased $4.7 million in the first nine months of 2025 compared to the first nine months of 2024, of which $3.1 million is attributable to higher employee costs charged to us under our omnibus and employee secondment agreements, $2.7 million is attributable to higher third‑party processing fees, $1.9 million is attributable to higher pass-through costs, partially offset by $3.0 million attributable to lower maintenance activity. Depreciation expense increased $2.9 million, primarily related to suspension of the Capa gas plant project and related engineering cost write off. General and administrative expenses increased $2.1 million due to higher employee costs charged to us under our omnibus and employee secondment agreements. Income from equity investments increased $2.5 million, primarily due to higher volumes processed at the LM4 plant. Terminaling and Export Revenues and other income increased $9.7 million in the first nine months of 2025 compared to the first nine months of 2024, of which $6.1 million is attributable to higher physical volumes, $3.3 million is attributable to higher tariff rates and $0.3 million is attributable to services provided directly to third parties. Operating and maintenance expenses (exclusive of depreciation) increased $3.2 million of which $1.8 million is attributable to higher employee costs charged to us under our omnibus and employee secondment agreements and $1.4 million is attributable to higher maintenance activity. Interest and Other Interest expense, net of interest income, increased $18.9 million in the first nine months of 2025 compared to the first nine months of 2024, of which $29.8 million is attributable to interest on $800.0 million 5.875% fixed-rate senior unsecured notes issued in February 2025, $14.7 million is attributable to interest on $600.0 million 6.500% fixed-rate senior unsecured notes issued in May 2024, $2.2 million is attributable to higher amortization of deferred finance costs and $2.0 million is attributable to extinguishment loss related to early redemption of $800.0 million 5.625% fixed-rate senior unsecured notes. These increases were partially offset by $25.8 million attributable to lower interest on $800.0 million 5.625% fixed-rate senior unsecured notes that were redeemed in March 2025 and $4.0 million attributable to lower interest on lower borrowings under our Credit Facilities. Income tax expense increased $34.4 million in the first nine months of 2025 compared to the first nine months of 2024, primarily driven by increased ownership of the Partnership by Hess Midstream LP following equity offering and share and unit repurchase transactions in 2024 and 2025. 29 PART I – FINANCIAL INFORMATION (CONT’D) Table of Contents Other Factors Expected to Significantly Affect Our Future Results We currently generate substantially all of our revenues under fee‑based commercial agreements with Chevron, including third parties contracted with affiliates of Chevron. These contracts provide cash flow stability and minimize our direct exposure to commodity price fluctuations, since we generally do not own any of the crude oil, natural gas, or NGLs that we handle and do not engage in the trading of crude oil, natural gas, or NGLs. However, commodity price fluctuations indirectly influence our activities and results of operations over the long-term, since they can affect production rates and investments by our Sponsor and third parties in the development of new crude oil and natural gas reserves. The markets for oil and natural gas are volatile and will likely continue to be volatile in the future. The throughput volumes at our facilities depend primarily on the volumes of crude oil and natural gas produced by our Sponsor and third parties in the Bakken, which, in turn, are ultimately dependent on our Sponsor’s and third parties’ exploration and production margins. Exploration and production margins depend on the price of crude oil, natural gas, and NGLs. These prices are volatile and influenced by numerous factors beyond our or our customers’ control, including the domestic and global supply of and demand for crude oil, natural gas and NGLs. Sustained periods of low prices for oil and natural gas could materially and adversely affect the quantities of oil and natural gas that our Sponsor and third parties can economically produce. The commodities trading markets, as well as global and regional supply and demand factors, may also influence the selling prices of crude oil, natural gas and NGLs. To the extent our plans include revenues for volumes above currently established MVC levels, such revenues could decline to the MVC levels as a result of market volatility. Furthermore, our ability to execute our growth strategy in the Bakken, including attracting third-party volumes, will depend on crude oil and natural gas production in that area, which is also affected by the supply of and demand for crude oil and natural gas. The majority of our systems entered the Secondary Term of our commercial agreements, which includes a fixed fee structure based on the average fees paid by Chevron during 2021-2023 adjusted annually for inflation up to 3% a year. Such a fee structure may provide less downside risk protection in the future compared to the fee structure we had during the initial term of the commercial agreements. For our terminaling and water gathering systems, the rates will continue to be reset through our annual rate redetermination process through 2033. For all of our systems, MVCs will continue to provide downside risk protection through 2033. Generally, all of our volumes are expected to be above currently established MVC levels in 2025, 2026 and 2027. 30 PART I – FINANCIAL INFORMATION (CONT’D) Table of Contents Reconciliation of Non‑GAAP Financial Measure The following table presents a reconciliation of Adjusted EBITDA to net income and net cash provided by operating activities, the most directly comparable GAAP financial measures, for each of the periods indicated. Three Months Ended September 30, Nine Months Ended September 30, (in millions) 2025 2024 2025 2024 Reconciliation of Adjusted EBITDA to net income: Net income $ 175.5 $ 164.7 $ 516.6 $ 486.9 Plus: Depreciation expense 56.6 51.5 159.9 151.8 Interest expense, net 57.1 51.8 168.9 150.0 Income tax expense 31.5 18.9 83.6 49.2 Adjusted EBITDA $ 320.7 $ 286.9 $ 929.0 $ 837.9 Reconciliation of Adjusted EBITDA to net cash provided by operating activities: Net cash provided by operating activities $ 258.9 $ 224.9 $ 738.2 $ 681.8 Changes in assets and liabilities 8.9 14.0 36.9 15.7 Amortization of deferred financing costs (3.0 ) (2.6 ) (11.1 ) (7.0 ) Interest expense, net 57.1 51.8 168.9 150.0 Distribution from equity investments (5.5 ) (4.4 ) (15.1 ) (11.8 ) Income from equity investments 5.2 3.7 12.6 10.1 Other (0.9 ) (0.5 ) (1.4 ) (0.9 ) Adjusted EBITDA $ 320.7 $ 286.9 $ 929.0 $ 837.9 31 PART I – FINANCIAL INFORMATION (CONT’D) Table of Contents Capital Resources and Liquidity We expect our ongoing sources of liquidity to include: • cash on hand; • cash generated from operations; • borrowings under our revolving credit facility; • issuances of additional debt securities; and • issuances of additional equity securities. We believe that cash generated from these sources will be sufficient to meet our operating requirements, our planned short‑term capital expenditures, debt service requirements, our quarterly cash distribution requirements, future internal growth projects or potential acquisitions. Our partnership agreement requires that we distribute all of our available cash, as defined in the agreement, to our shareholders. On October 27, 2025, we declared a quarterly cash distribution of $0.7548 per Class A Share, to be paid on November 14, 2025 to shareholders of record on November 6, 2025. Simultaneously, the Partnership will make a distribution of $0.7548 per Class B Unit of the Partnership to our Sponsor. Fixed‑Rate Senior Notes On February 12, 2025, the Partnership issued $800.0 million aggregate principal amount of 5.875% fixed‑rate senior unsecured notes due 2028 to qualified institutional investors. Interest is payable semi‑annually on March 1 and September 1, commencing September 1, 2025. The Partnership used the net proceeds from the issuance of the new notes, along with borrowings under its revolving credit facility, to redeem its outstanding $800.0 million aggregate principal amount of 5.625% fixed‑rate senior unsecured notes due 2026 (the “2026 Notes”). The Partnership redeemed the 2026 Notes on March 5, 2025, and recognized an extinguishment loss of approximately $2.0 million included in Interest expense, net in the accompanying unaudited consolidated statements of operations. As of September 30, 2025, the Partnership had: • $400.0 million aggregate principal amount of 5.500% fixed‑rate senior unsecured notes due 2030 that were issued to qualified institutional investors. Interest is payable semi‑annually on April 15 and October 15. • $750.0 million aggregate principal amount of 4.250% fixed‑rate senior unsecured notes due 2030 that were issued to qualified institutional investors. Interest is payable semi‑annually on February 15 and August 15. • $600.0 million aggregate principal amount of 6.500% fixed‑rate senior unsecured notes due 2029 that were issued to qualified institutional investors. Interest is payable semi‑annually on June 1 and December 1. • $550.0 million aggregate principal amount of 5.125% fixed‑rate senior unsecured notes due 2028 that were issued to qualified institutional investors. Interest is payable semi‑annually on June 15 and December 15. • $800.0 million aggregate principal amount of 5.875% fixed‑rate senior unsecured notes due 2028 that were issued to qualified institutional investors. Interest is payable semi‑annually on March 1 and September 1. Each of the indentures for the senior unsecured notes described above contains covenants that the Partnership considers to be customary. On July 24, 2025 (the “Investment Grade Rating Date”), the Partnership received an investment grade rating from S&P. S&P assigned a rating of ‘BBB-’ to the Partnership’s unsecured debt and raised the Partnership’s issuer level credit rating to ‘BBB-’, with a stable outlook. As a result of this investment grade rating, the Partnership is not required to comply with certain restrictive covenants set forth in the unsecured notes indentures, including those related to (i) declaring or paying any dividend or making any other restricted payments; (ii) transfer or sale of assets or subsidiary stock; (iii) incurrence of additional debt; (iv) restricted investments; and (v) affiliate transactions. As of September 30, 2025, the Partnership was in compliance with all debt covenants under the indentures. 32 PART I – FINANCIAL INFORMATION (CONT’D) Table of Contents In addition, the covenants included in the indentures governing the senior unsecured notes contain provisions that allow the Company to satisfy the Partnership’s reporting obligations under the indenture, as long as any such financial information of the Company contains information reasonably sufficient to identify the material differences, if any, between the financial information of the Company, on the one hand, and the Partnership and its subsidiaries on a stand-alone basis, on the other hand and the Company does not directly own capital stock of any person other than the Partnership and its subsidiaries, or material business operations that would not be consolidated with the financial results of the Partnership and its subsidiaries. The Company is a holding company and has no independent assets or operations. Other than the interest in the Partnership and the effect of federal and state income taxes that are recognized at the Company level, there are no material differences between the consolidated financial statements of the Partnership and the consolidated financial statements of the Company. Credit Facilities As of September 30, 2025, the Partnership had $1.4 billion senior unsecured credit facilities (the “Credit Facilities”) consisting of a $1.0 billion five-year revolving credit facility and a $400.0 million five‑year Term Loan A facility. The Credit Facilities mature in July 2027. Facility fees accrue on the total capacity of the revolving credit facility. Borrowings under the five-year Term Loan A facility generally bear interest at Secured Overnight Financing Rate (“SOFR”) plus the applicable margin that, prior to the Investment Grade Rating Date, ranged from 1.65% to 2.55%, while the applicable margin for the five‑year syndicated revolving credit facility ranged from 1.375% to 2.050%. As a result of the investment grade rating, on and after the Investment Grade Rating Date, borrowings under the Partnership’s five-year Term Loan A facility bear interest at SOFR plus the applicable margin ranging from 1.10% to 1.85%, while the applicable margin for the five-year syndicated revolving credit facility ranges from 1.00% to 1.60%. On and after the Investment Grade Rating Date, pricing levels for the facility fee and interest rate margins are based on the Partnership’s Designated Rating (as defined in the Credit Facilities). As of September 30, 2025, borrowings of $356.0 million were drawn and outstanding under the Partnership’s revolving credit facility, and borrowings of $370.0 million, excluding deferred issuance costs, were drawn and outstanding under the Partnership’s Term Loan A facility. The Credit Facilities can be used for borrowings and letters of credit for general corporate purposes. After the Investment Grade Rating Date, each of the guarantors was released from its obligations under the guarantee agreement, each of the loan parties was released from its obligations under the security documents to which it was a party and all liens granted to the administrative agent by the loan parties on any collateral were released. Additionally, after the Investment Grade Rating Date, the covenant that requires the Partnership to maintain a ratio of secured debt to Consolidated EBITDA (as defined in the Credit Facilities) for the prior four fiscal quarters of not greater than 4.00 to 1.00 as of the last day of each fiscal quarter fell away. The Credit Facilities contain representations and warranties, affirmative and negative covenants and events of default that the Partnership considers to be customary for an agreement of this type, including a covenant that requires the Partnership to maintain a ratio of total debt to Consolidated EBITDA (as defined in the Credit Facilities) for the prior four fiscal quarters of not greater than 5.00 to 1.00 as of the last day of each fiscal quarter (5.50 to 1.00 during the specified period following certain acquisitions). As of September 30, 2025, the Partnership was in compliance with this financial covenant. Cash Flows Operating Activities. Net cash provided by operating activities increased $56.4 million for the nine months ended September 30, 2025, compared to the same period in 2024, primarily due to an increase in revenues and other income of $117.5 million and an increase in distributions received from equity investments of $3.3 million, partially offset by an increase in expenses, other than depreciation, amortization, equity-based compensation and other non-cash gains and losses of $43.2 million and an increase in cash used by changes in working capital of $21.2 million. Investing Activities. Net cash used in investing activities decreased $22.1 million for the nine months ended September 30, 2025, compared to the same period in 2024, primarily driven by the timing of payments for additions to property, plant, and equipment predominantly related to our compression capacity and associated pipeline infrastructure expansion program. 33 PART I – FINANCIAL INFORMATION (CONT’D) Table of Contents Financing Activities. Net cash used in financing activities increased $82.2 million for the nine months ended September 30, 2025, compared to the same period in 2024. In the first nine months of 2025, we received proceeds of $787.5 million, net of financing costs, from our issuance of the new 5.875% fixed-rate senior unsecured notes due 2028, compared to $590.5 million in proceeds, net of financing costs, from our issuance of the 6.500% fixed-rate senior unsecured notes in 2024. In addition, we received $341.0 million net proceeds from borrowings under our Credit Facilities compared to $310.0 million of repayments of borrowings under our Credit Facilities in 2024. We used the net proceeds from the issuance of the new 5.875% fixed-rate senior unsecured notes, along with borrowings under our revolving credit facility, to redeem the $800.0 million notes due 2026. Our repayments of the term loan facility were $7.5 million higher in the first nine months of 2025 compared to the same period in 2024. In addition, in the first nine months of 2025, we spent $100.0 million more for share and unit repurchases, paid higher distributions to shareholders and noncontrolling interests of $22.1 million, as well as paid higher transaction costs of $0.6 million compared to the same period in 2024. Capital Expenditures Our operations can be capital intensive, requiring investments to expand, upgrade, maintain or enhance existing operations and to meet environmental and operational regulations. The following table sets forth a summary of capital expenditures and reconciles capital expenditures on an accrual basis to additions to property, plant and equipment on a cash basis: Nine Months Ended September 30, 2025 2024 (in millions) Total capital expenditures $ 199.9 $ 204.2 (Increase) decrease in accrued capital expenditures 11.2 16.5 (Increase) decrease in capital expenditures included in accounts payable - affiliate (22.2 ) (9.7 ) Additions to property, plant and equipment $ 188.9 $ 211.0 Capital expenditures in 2025 are primarily attributable to continued expansion of our compression capacity and gas capture capabilities and related pipeline infrastructure to meet our Sponsor’s and third parties’ current and future production growth and gas capture targets. The activities focus on the construction of two new compressor stations and associated pipeline infrastructure, one of which was placed in service in the third quarter of 2025 and the other one is expected to be placed in service in early 2026. Capital expenditures in 2024 were also attributable to continued expansion of our compression capacity and related pipeline infrastructure. 34 PART I – FINANCIAL INFORMATION (CONT’D) Table of Contents Cautionary Note Regarding Forward-looking Information This Quarterly Report on Form 10‑Q, including information incorporated by reference herein, contains “forward-looking statements” within the meaning of U.S. federal securities laws. Words such as “anticipate,” “estimate,” “expect,” “forecast,” “guidance,” “could,” “may,” “should,” “would,” “believe,” “intend,” “project,” “plan,” “predict,” “will,” “target” and similar expressions identify forward-looking statements, which are not historical in nature. Our forward-looking statements may include, without limitation: our future financial and operational results; our business strategy; our industry; our expected revenues; our future profitability; our maintenance or expansion projects; our projected budget and capital expenditures and the impact of such expenditures on our performance; our ability to deliver ongoing return of capital to our shareholders; future economic and market conditions in the oil and gas industry; and information about sustainability goals and targets and planned social, safety environmental policies, programs and initiatives. Forward-looking statements are based on our current understanding, assessments, estimates and projections of relevant factors and reasonable assumptions about the future. Forward-looking statements are subject to certain known and unknown risks and uncertainties that could cause actual results to differ materially from our historical experience and our current projections or expectations of future results expressed or implied by these forward-looking statements. The following important factors could cause actual results to differ materially from those in our forward-looking statements: • the ability of Chevron and other parties to satisfy their obligations to us, including Chevron’s ability to meet its drilling and development plans on a timely basis or at all, its ability to deliver its nominated volumes to us, and the operation of joint ventures that we may not control; • our ability to generate sufficient cash flow to pay current and expected levels of distributions; • reductions in the volumes of crude oil, natural gas, NGLs and produced water we gather, process, terminal or store; • the actual volumes we gather, process, terminal and store for Chevron in excess of our MVCs and relative to Chevron’s nominations; • fluctuations in the prices and demand for crude oil, natural gas and NGLs; • changes in global economic conditions and the effects of a global economic downturn or inflation on our business and the business of our suppliers, customers, business partners and lenders; • our ability to comply with government regulations or make capital expenditures required to maintain compliance, including our ability to obtain or maintain permits necessary for capital projects in a timely manner, if at all, or the revocation or modification of existing permits; • our ability to successfully identify, evaluate and timely execute our capital projects, investment opportunities and growth strategies, whether through organic growth or acquisitions; • costs or liabilities associated with federal, state and local laws, regulations and governmental actions applicable to our business, including legislation and regulatory initiatives relating to environmental protection and health and safety, such as spills, releases, pipeline integrity and measures to limit greenhouse gas emissions and climate change; • our ability to comply with the terms of our credit facility, indebtedness and other financing arrangements, which, if accelerated, we may not be able to repay; • reduced demand for our midstream services, including the impact of weather or the availability of the competing third-party midstream gathering, processing and transportation operations; • potential disruption or interruption of our business due to catastrophic events, such as accidents, severe weather events, labor disputes, information technology failures, constraints or disruptions and cyber-attacks; • any limitations on our ability to access debt or capital markets on terms that we deem acceptable, including as a result of weakness in the oil and gas industry or negative outcomes within commodity and financial markets; • liability resulting from litigation; • risks and uncertainties associated with Hess’ integration with Chevron following the completion of the Merger, including the following: o Chevron’s ability to integrate Hess’ operations in a successful manner and in the expected time period; o the possibility that any of the anticipated benefits and projected synergies of the transaction will not be realized or will not be realized within the expected time period; o the effect of the completion of the transaction on the parties’ business relationships and business generally, and the risks that the transaction disrupts current plans and operations of Chevron or Hess and potential difficulties in Hess employee retention as a result of the transaction, as well as the risk of disruption of Chevron’s or Hess’ management and business disruption following the transaction; and • other factors described in Item 1A — Risk Factors in our 2024 Annual Report, as well as any additional risks described in our other filings with the Securities and Exchange Commission. 35 PART I – FINANCIAL INFORMATION (CONT’D) Table of Contents As and when made, we believe that our forward-looking statements are reasonable. However, given these risks and uncertainties, caution should be taken not to place undue reliance on any such forward-looking statements since such statements speak only as of the date when made and there can be no assurance that such forward-looking statements will occur and actual results may differ materially from those contained in any forward-looking statement we make. Except as required by law, we undertake no obligation to publicly update or revise any forward-looking statements, whether because of new information, future events or otherwise. Item 3. Quantitative and Qualitati ve Disclosures about Market Risk Market risk is the risk of loss arising from adverse changes in market rates and prices. We generally do not take ownership of the crude oil, natural gas or NGLs that we currently gather, process, terminal, store or transport for our customers. Because we generate substantially all of our revenues by charging fees under long-term commercial agreements with Chevron with minimum volume commitments, our Sponsor bears the risks associated with fluctuating commodity prices and we have minimal direct exposure to commodity prices. In the normal course of our business, we are exposed to market risks related to changes in interest rates. Our financial risk management activities may include transactions designed to reduce risk by reducing our exposure to interest rate movements. Interest rate swaps may be used to convert interest payments on certain long‑term debt. At September 30, 2025, we did not have in place any derivative instruments to hedge any exposure to changes in interest rates. At September 30, 2025, our total debt had a carrying value of $3,794.9 million and a fair value of approximately $3,840.1 million, based on Level 2 inputs in the fair value measurement hierarchy. A 15% increase or decrease in interest rates would decrease or increase the fair value of our fixed rate debt by approximately $75.4 million or $71.9 million, respectively. The carrying value of the amounts under our Term Loan A facility and revolving credit facility at the quarter-end approximated their fair value. Any changes in interest rates do not impact cash outflows associated with fixed rate interest payments or settlement of debt principal, unless a debt instrument is repurchased prior to maturity. Our exposure to market risk related to changes in interest rates has not materially changed from what we previously disclosed in our 2024 Annual Report.