DT Midstream - 10-K annual report 2025

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UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

__________________________________________

FORM 10-K

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

For the fiscal year ended December 31, 2025

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

Commission File Number: 001-40392

DT Midstream, Inc.


Delaware						38-2663964
(State or other jurisdiction of incorporation or organization)						(I.R.S Employer Identification No.)

Registrant's address of principal executive offices: 500 Woodward Ave., Suite 2900, Detroit, Michigan 48226-1279

Registrant's telephone number, including area code: (313) 402-8532

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

Title of Each Class

Trading Symbol

Name of Exchange on which Registered

Common stock, par value $0.01

DTM

New York Stock Exchange

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

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

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

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yes ☒ No ☐

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

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

Large accelerated filer

Accelerated filer

Non-accelerated filer

Smaller reporting company

Emerging growth company

☒

☐

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

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

If securities are registered pursuant to Section 12(b) of the Exchange Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements. Yes ☐ No ☒

Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to Section 240.10D-1(b). Yes ☐ No ☒

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

On June 30, 2025, the aggregate market value of DT Midstream's voting common stock was approximately $11.0 billion (based on the New York Stock Exchange closing price on such date).

Number of shares of common stock outstanding at February 17, 2026:


Description						Shares
Common stock, par value $0.01						101,721,471

DOCUMENTS INCORPORATED BY REFERENCE

Certain information in DT Midstream's definitive Proxy Statement for our 2026 Annual Meeting of Common Shareholders to be held May 5, 2026, which will be filed with the Securities and Exchange Commission pursuant to Regulation 14A, not later than 120 days after the end of the registrant’s fiscal year covered by this report on Form 10-K, is incorporated herein by reference to Part III (Items 10, 11, 12, 13, and 14) of this Form 10-K.

TABLE OF CONTENTS


		Page
	Definitions	1
	Forward-Looking Statements	4
PART I
Items 1. and 2.	Business and Properties	6
Item 1A.	Risk Factors	24
Item 1B.	Unresolved Staff Comments	39
Item 1C.	Cybersecurity	39
Item 3.	Legal Proceedings	39
Item 4.	Mine Safety Disclosures	39
PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters, and Issuer Purchases of Equity Securities	40
Item 6.	[Reserved]	42
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	42
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	53
Item 8.	Financial Statements	55
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	94
Item 9A.	Controls and Procedures	94
Item 9B.	Other Information	94
Item 9C.	Disclosure Regarding Foreign Jurisdictions that Prevent Inspections	95
PART III
Item 10.	Directors, Executive Officers, and Corporate Governance	95
Item 11.	Executive Compensation	95
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	95
Item 13.	Certain Relationships and Related Transactions, and Director Independence	95
Item 14.	Principal Accountant Fees and Services	95
PART IV
Item 15.	Exhibits and Financial Statement Schedules	96
Item 16.	Form 10-K Summary	98
	Signatures	99

DEFINITIONS

Unless the context otherwise requires, references to "we," "us," "our," "Registrant," or the "Company" and words of similar importance refer to DT Midstream and, unless otherwise specified, our consolidated subsidiaries and our unconsolidated joint ventures. As used in this Form 10-K, the terms and definitions below have the following meanings:


AFUDC						Allowance for funds used during construction, represents the cost of financing construction projects for FERC-regulated businesses, including the estimated cost of debt and authorized return on equity

Appalachia Gathering						A 154-mile gathering system that gathers Marcellus shale natural gas and delivers to the Texas Eastern Pipeline and Stonewall

ASC 606						The Accounting Standards Codification of Revenue from Contracts with Customers issued by the FASB

ASC 980						The Accounting Standards Codification of Regulated Operations issued by the FASB

ASU						Accounting Standards Update issued by the FASB

Bcf						Billion cubic feet of natural gas

Bcf/d						Billion cubic feet of natural gas per day

Birdsboro						A 14-mile interstate pipeline transporting gas supply to a gas-fired power plant in Pennsylvania

Bluestone						A 65-mile gathering lateral pipeline, and two compression facilities, that gathers Marcellus shale natural gas and delivers to Millennium and the Tennessee Pipeline

Blue Union Gathering						A 443-mile gathering system that gathers shale natural gas from the Haynesville formation of Louisiana and Texas and delivers to markets in the Gulf Coast region; ancillary services include water impoundment, water transportation, water disposal and sand

Bridge Facility						The $700 million 364-day bridge loan facility committed by Barclays Bank PLC

CAD						Canadian Dollar ($)

CERCLA						Comprehensive Environmental Response, Compensation, and Liability Act

CFTC						Commodity Futures Trading Commission

Chicago Hub						A major natural gas market and transportation hub located in the Chicago area, serving as a critical interconnection point for multiple interstate pipelines

Clean Fuels Acquisition						The purchase of Clean Fuels Gathering from a privately held coal mine methane producer

Clean Fuels Gathering						A 93-mile gathering system that gathers and treats coal mine methane into pipeline quality gas

Columbia Pipeline						Columbia Gas Transmission, LLC, owned by TC Energy Corporation and Global Infrastructure Partners

Credit Agreement						DT Midstream's credit agreement which provides for the Revolving Credit Facility

MCA						Moderate consequence area

Distribution						Pro rata distribution to DTE Energy shareholders of all the outstanding common stock of DT Midstream upon the Separation

DTE Energy						DTE Energy Company, the consolidating entity of DT Midstream prior to the Separation

DT Midstream						DT Midstream, Inc. and our consolidated subsidiaries

DT Midstream Plan						The DT Midstream, Inc. Long-Term Incentive Plan

DTM Interstate Transportation						DTM Interstate Transportation, LLC, the consolidated subsidiary of DT Midstream created for the Midwest Pipeline Acquisition which is comprised of Guardian, Midwestern and Viking

EPA						U.S. Environmental Protection Agency

EPAct 2005						Energy Policy Act of 2005

ESA						The U.S. federal Endangered Species Act

ESG						Environmental, social and corporate governance

DEFINITIONS



Expand Energy						Expand Energy Corporation and/or its affiliates

FASB						Financial Accounting Standards Board

FERC						Federal Energy Regulatory Commission

GAAP						Generally Accepted Accounting Principles in the United States

Generation						A 25-mile intrastate pipeline in northern Ohio and owned by NEXUS

GHG						Greenhouse gas

Guardian						Guardian Pipeline, L.L.C., a 263-mile interstate pipeline which connects to the Chicago Hub and serves key Upper Midwest demand centers

Haynesville System						Pipeline and gathering system which is comprised of LEAP, Blue Union Gathering, and associated facilities

HCA						High consequence area

Inflation Reduction Act						The Inflation Reduction Act of 2022 (H.R. 5374)

Investment Grade Event						As defined in the indentures for the 2032 Notes and 2034 Notes and the Credit Agreement

LEAP						Louisiana Energy Access Project, a 221-mile gathering lateral pipeline that gathers Haynesville shale natural gas and delivers to markets in the Gulf Coast region

LNG						Liquefied natural gas

Michigan System						A 335-mile pipeline system in northern Michigan

Midwestern						Midwestern Gas Transmission Company, a 402-mile bi-directional interstate pipeline which connects Appalachia supply to the Midwest market region between Tennessee and the Chicago Hub

Midwest Pipeline Acquisition						The transaction with ONEOK, pursuant to which DTM Interstate Transportation acquired 100% of the equity interests in each of Guardian, Midwestern and Viking

Millennium						Millennium Pipeline Intermediate Holdings LLC, a joint venture that, through its wholly owned subsidiary, Millennium Pipeline Company, LLC, owns a 266-mile interstate transportation pipeline and compression facilities serving markets in the northeast and supply from the northeast Marcellus region, in which DT Midstream owns a 52.5% interest

Mountain Valley Pipeline						A 303-mile natural gas pipeline owned by Mountain Valley Pipeline, LLC which spans from West Virginia to Virginia and transports natural gas from the Marcellus and Utica shale regions to markets in the southeastern United States

MVC						Minimum volume commitment

NEPA						National Environmental Policy Act

NEXUS						NEXUS Gas Transmission, LLC, a joint venture that owns (i) a 256-mile interstate transportation pipeline and three compression facilities that transports Utica and Marcellus shale natural gas to Ohio, Michigan and Ontario market centers and (ii) Generation, in which DT Midstream owns a 50% interest

NGA						Natural Gas Act

NGPA						Natural Gas Policy Act

NWP 12						The U.S. Army Corps of Engineers Clean Water Act Section 404 Nationwide Permit 12

NYSE						New York Stock Exchange

Ohio Utica Gathering						A 26-mile gathering system, including compression and dehydration facilities, that gathers Utica shale natural gas from producer wells and delivers to a nearby processing plant

OBBBA						One Big Beautiful Bill Act, which was signed into law on July 4, 2025

DEFINITIONS


ONEOK						ONEOK, Inc., a publicly traded energy company engaged in the gathering, processing, storage, and transportation of natural gas, including through its ownership of ONEOK Partners Intermediate Limited Partnership and Border Midwestern Company

OSHA						The U.S. federal Occupational Safety and Health Act

PHMSA						Pipeline and Hazardous Materials Safety Administration

RCRA						Resource Conservation and Recovery Act

Revolving Credit Facility						DT Midstream's secured revolving credit facility issued under the Credit Agreement



SEC						Securities and Exchange Commission

Separation						The separation and spin-off of DT Midstream from DTE Energy, effective July 1, 2021

Separation and Distribution Agreement						The Separation and Distribution Agreement with DTE Energy was established before the Distribution to set forth DT Midstream's agreements with DTE Energy regarding the principal actions to be taken in connection with the Separation, as well as other agreements that govern aspects of DT Midstream's relationship with DTE Energy following the Separation

SOFR						Secured Overnight Financing Rate

South Romeo						South Romeo Gas Storage Company, LLC, a joint venture which owns the Washington 28 Storage Complex, in which DT Midstream owns a 50% interest

Stonewall						A 68-mile gathering lateral pipeline, in which DT Midstream owns an 85% interest, that gathers Marcellus and Utica shale natural gas and delivers to the Columbia Pipeline

Susquehanna Gathering						A 198-mile gathering system that gathers Marcellus shale natural gas and delivers to Bluestone

Tax Matters Agreement						The agreement that governs the respective rights, responsibilities and obligations of DTE Energy and DT Midstream after the Separation with respect to all tax matters

Tennessee Pipeline						Tennessee Gas Pipeline Company, LLC, owned by Kinder Morgan, Inc.

Term Loan Facility						DT Midstream's term loan facility issued under the Credit Agreement, which was repaid in 2024

Texas Eastern Pipeline						Texas Eastern Transmission, LP, owned by Enbridge Inc.

Tioga Gathering						A 3-mile gathering system that gathers shale natural gas to the Eastern Gas Transmission system

U.S.						United States of America

USD						United States Dollar ($)

Vector						Vector Pipeline LP, a joint venture that owns a 348-mile interstate transportation pipeline and five compression facilities connecting Illinois, Indiana, Michigan, and Ontario market centers, in which DT Midstream owns a 40% interest

VIE						Variable Interest Entity

Viking						Viking Gas Transmission Company, a 674-mile bi-directional interstate pipeline which serves key utility customers in Minnesota, Wisconsin and North Dakota

Washington 10 Storage Complex						An interstate storage system located in Michigan with 94 Bcf of storage capacity, in which DT Midstream owns a 91% interest, and associated compression facilities

WOTUS						Navigable Waters Protection Rule under the U.S. federal Clean Water Act

2020 PIPES Act						Protecting Our Infrastructure of Pipelines and Enhancing Safety Act of 2020

2029 Notes						Senior unsecured notes of $1.1 billion in aggregate principal amount due June 2029

2031 Notes						Senior unsecured notes of $1.0 billion in aggregate principal amount due June 2031

2032 Notes						Senior unsecured notes of $600 million in aggregate principal amount due April 2032

2034 Notes						Senior unsecured notes of $650 million in aggregate principal amount due December 2034

FORWARD-LOOKING STATEMENTS

Certain information presented herein includes "forward-looking statements" within the meaning of the Private Securities Litigation Reform Act of 1995 with respect to the financial condition, results of operations, and businesses of DT Midstream. Words such as "believe," "expect," "expectations," "plans," "strategy," "prospects," "estimate," "project," "target," "anticipate," "will," "should," "see," "guidance," "outlook," "confident," "may," and other words of similar meaning in connection with a discussion of future operating or financial performance may signify forward-looking statements. Forward-looking statements are not guarantees of future results and conditions, but rather are subject to numerous assumptions, risks, and uncertainties that may cause actual future results to be materially different from those contemplated, projected, estimated, or budgeted. Many factors may impact forward-looking statements of DT Midstream including, but not limited to, the following:

•changes in general economic conditions, including increases in interest rates and associated Federal Reserve policies, a potential economic recession, and the impact of inflation on our business;

•industry changes, including the impact of consolidations, alternative energy sources, technological advances, infrastructure constraints and changes in competition;

•changes in global trade policies and tariffs;

•global and domestic supply chain disruptions;

•actions taken by third-party operators, producers, processors, transporters and gatherers;

•changes in expected production from Expand Energy and other third parties in our areas of operation;

•demand for natural gas gathering, transmission, storage, and transportation;

•the availability and price of natural gas to the consumer compared to the price of alternative and competing fuels;

•our ability to successfully and timely implement our business plan;

•our ability to complete organic growth projects on time and on budget;

•our ability to finance, complete, or successfully integrate acquisitions;

•our ability to realize the anticipated benefits and manage the risks of the Midwest Pipeline Acquisition described herein;

•the price and availability of debt and equity financing;

•restrictions in our existing and any future credit facilities and indentures;

•the effectiveness of our information technology and operational technology systems and practices to detect and defend against evolving cyber attacks on United States critical infrastructure;

•changing laws regarding cybersecurity and data privacy, and any cybersecurity threat or event;

•operating hazards, environmental risks and other risks incidental to gathering, storing and transporting natural gas;

•geologic and reservoir risks and considerations;

•natural disasters, adverse weather conditions, casualty losses and other matters beyond our control;

•the impact of outbreaks of illnesses, epidemics and pandemics, and any related economic effects;

•the impacts of geopolitical events, including the Ukraine and the Middle East;

•labor relations and markets, including the ability to attract, hire and retain key employee and contract personnel;

•large customer defaults;

•changes in tax status, as well as changes in tax rates and regulations;

FORWARD-LOOKING STATEMENTS

•the effects and associated cost of compliance with existing and future laws and governmental regulations, such as the Inflation Reduction Act and the OBBBA;

•changes in environmental laws, regulations or enforcement policies, including laws and regulations relating to pipeline safety, climate change and GHG emissions;

•changes in laws, regulations or enforcement policies, including those relating to construction and operation of new interstate gas pipelines, ratemaking to which our pipelines may be subject, or other non-environmental laws and regulations;

•our ability to qualify for federal income tax credits;

•our ability to develop low carbon business opportunities and deploy GHG reducing technologies;

•changes in insurance markets impacting costs and the level and types of coverage available;

•the timing and extent of changes in commodity prices;

•the success of our risk management strategies;

•the suspension, reduction or termination of our customers’ obligations under our commercial agreements;

•disruptions due to equipment interruption or failure at our facilities, or third-party facilities on which our business is dependent; and

•the effects of future litigation.

The above list of factors is not exhaustive. New factors emerge from time to time. We cannot predict what factors may arise or how such factors may cause actual results to vary materially from those stated in forward-looking statements. Any forward-looking statements speak only as of the date on which such statements are made. We are under no obligation to, and expressly disclaim any obligation to, update or alter our forward-looking statements, whether as a result of new information, subsequent events or otherwise.

PART I

Items 1. and 2. Business and Properties

General

DT Midstream was incorporated in the state of Delaware in 2021. Our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, proxy statements, and all amendments to such reports are available free of charge through the Investors Relations page of DT Midstream's website: www.dtmidstream.com, as soon as reasonably practicable after they are filed with or furnished to the SEC. Additionally, the public may read and copy any materials that we file electronically with the SEC at www.sec.gov.

The DT Midstream Code of Conduct, Board of Directors' Code of Business Conduct and Ethics, Board of Directors' Governance Guidelines, Board of Directors' Committee Charters, and Categorical Standards for Director Independence are also posted on DT Midstream's website. The information on DT Midstream's website is not part of this report or any other report that DT Midstream files with, or furnishes to, the SEC.

Business Overview

We are an owner, operator, and developer of an integrated portfolio of natural gas midstream assets. We provide multiple, integrated natural gas services to customers through our interstate pipelines, intrastate pipelines, storage systems, gathering lateral pipelines and compression and surface facilities, and gathering systems including related treatment plants, and compression and surface facilities. We also own joint venture interests in equity method investees which own and operate interstate pipelines that connect to our wholly owned assets.

Our core assets strategically connect key demand centers in the Midwestern U.S., Eastern Canada and Northeastern U.S. regions to the premium production areas of the Marcellus/Utica natural gas formation in the Appalachian Basin and connect key demand centers and LNG export terminals in the Gulf Coast region to premium production areas of the Haynesville natural gas formation.

We have an established history of stable, long-term growth with contractual cash flows from customers that include natural gas producers, local distribution companies, electric power generators, industrials, and national marketers.

We believe that our properties are generally in good condition, well-maintained and suitable and adequate to carry on our business at capacity for the foreseeable future.

2025 Executive Summary

During the year ended December 31, 2025, DT Midstream's accomplishments and business developments included:

•Attained Net Income Attributable to DT Midstream of $441 million;

•Declared total cash dividends of $3.28 per common share;

•Delivered significant Pipeline segment growth with a full year of operations from the DTM Interstate Transportation assets acquired in the Midwest Pipeline Acquisition and advanced key integration milestones on schedule;

•Gathered a record high throughput on our Haynesville System;

•Placed the LEAP phase 4 expansion into service, which increased the system capacity to 2.1 Bcf/d;

•Reached a final investment decision on the Guardian G3 expansion, which will increase Guardian's capacity by approximately 40% and is supported by long-term negotiated rate precedent agreements with investment-grade utility customers;

•Reached a final investment decision on the initial phase of modernization across DTM Interstate Transportation assets. This initial phase will be predominantly focused on improving system efficiency and reliability on Guardian Pipeline;

•Received FERC approval (subject to a filed appeal) for the Bluestone Extended Supply Transportation ("BEST") agreement between Bluestone and Millennium, which will enable Millennium to establish a new supply lateral utilizing Bluestone’s existing interconnects, creating a transportation path between Millennium and Tennessee Pipeline;

•Achieved investment grade rating with all three major credit rating agencies; and

•Published our fourth annual Corporate Sustainability Report. The information in our Corporate Sustainability Report is not incorporated by reference into this Form 10-K.

Our Strategy

Our principal business objective is to safely and reliably operate and develop midstream natural gas assets across our premier footprint. Our proven leadership and highly engaged employees have an excellent track record. Prospectively, we intend to continue this track record by executing on our natural gas-centric business strategy focused on disciplined capital deployment and supported by a flexible, well capitalized balance sheet. Additionally, we intend to develop low carbon business opportunities and deploy GHG reducing technologies as part of our goal of being leading environmental stewards in the midstream industry. We are executing on a plan to achieve net zero carbon emissions by 2050.

Our strategy is premised on the following principles:

•Operate our assets in a sustainable and responsible manner. We believe that consistently serving our communities, customers, team members, and stakeholders is foundational.

•Provide exceptional service to our customers. We will continue to provide safe, highly reliable, timely and cost-competitive service, which is a key distinguishing competitive advantage.

•Disciplined capital deployment in assets supported by strong fundamentals. New capital spending will continue to go through a rigorous review process to ensure that it is accretive and deployed to assets meeting our strategic criteria and expected returns.

•Capitalize on asset integration and utilization opportunities. We intend to leverage the scale and scope of our large asset platforms, our services, and our capabilities to increase efficiency across our portfolio and in the strategically situated market regions where we operate.

•Pursue economically attractive opportunities. We intend to pursue economically attractive expansion and acquisition opportunities that leverage our current asset footprint and strategic relationships with our customers.

•Grow cash flows supported by long-term firm service revenue contracts. We will continue pursuing opportunities that increase the demand-based component of our contract portfolio and will focus on obtaining additional long-term firm service commitments from customers, which may include fixed demand charges, MVCs and acreage dedications.

Our Operations and Business Segments

DT Midstream sets strategic goals, allocates resources, and evaluates performance based on the following two segments: Pipeline and Gathering. For financial information by segment for the last three years, see Note 14, "Segment and Related Information," to the Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

Pipeline Segment

Description

Our Pipeline segment includes our interstate pipelines, intrastate pipelines, storage systems, gathering lateral pipelines and compression and surface facilities. The Pipeline segment also includes joint venture interests in equity method investees which own and operate interstate pipelines that connect to our wholly owned assets. Our subsidiary companies own and operate these types of assets across multiple states and Eastern Canada.

Our interstate pipelines are FERC-regulated assets that transport natural gas from interconnected pipelines to power plants, local distribution companies and industrial end users, as well as interconnected pipelines for delivery to additional markets. Our intrastate pipelines are typically state-regulated assets that transport natural gas from interconnected pipelines to power plants, local distribution companies and industrial end users. Our gathering lateral pipelines are assets that gather natural gas for our customers from multiple central delivery points within a basin and redeliver that natural gas to interstate pipelines, intrastate pipelines, and LNG export terminals for further downstream transportation and, accordingly, perform a gathering function not subject to FERC jurisdiction. Our storage systems provide natural gas storage services for customers, subject to FERC jurisdiction.

Revenues and Earnings from Equity Method Investees

DT Midstream primarily provides two types of pipeline and storage services: firm service and interruptible service. Firm service revenue contracts are typically long-term and structured using fixed demand charges or MVCs with fixed deficiency fee rates. This provides for fixed revenue commitments regardless of actual volumes of natural gas that flow, which leads to more stable operating performance, revenues and cash flows and limits our exposure to natural gas price fluctuations. For the year ended December 31, 2025, approximately 92% of our Pipeline revenue was generated under firm service revenue contracts and approximately 99% of the revenue of our unconsolidated joint ventures was generated under firm service revenue contracts. The earnings of our unconsolidated joint ventures are included in earnings from equity method investees in our Consolidated Statements of Operations. Interruptible service revenue contracts typically contain fixed rates, with total consideration dependent on actual natural gas volumes that flow.

For the year ended December 31, 2025, revenue from the Pipeline segment accounted for approximately 55% of our consolidated revenue. The cash flows from our Pipeline operations can be impacted in the short term by seasonality, weather fluctuations and the financial condition of our customers.

Competition

Our Pipeline operations compete for customers primarily based on geographic location, which determines connectivity and proximity to supply sources and end users, as well as price, operating reliability and flexibility, available capacity, and service offerings. Our primary competitors in the natural gas interstate pipelines and transmission market and in the gathering lateral pipelines market include major interstate pipelines and midstream companies that can transport and gather natural gas volumes between interstate systems and between central delivery points within a basin.

Properties

The following table presents certain information concerning our principal properties included in the Pipeline segment:

Property Classification

% Owned

Operator

Approximate Capacity (Bcf/d)

Approximate Compression Horsepower

Description

Location

Pipeline

FERC-Regulated Interstate Pipelines

Birdsboro

100%

Yes

0.2

—

A 14-mile interstate pipeline transporting gas supply to a gas-fired power plant in Pennsylvania

Guardian

100%

Yes

1.3

100,300

A 263-mile interstate pipeline which connects to the Chicago Hub and serves key Upper Midwest demand centers

IL and WI

Midwestern

100%

Yes

1.5

82,900

A 402-mile bi-directional interstate pipeline which connects Appalachia supply to the Midwest market region between Tennessee and the Chicago Hub

KY, IL, IN and TN

Millennium (a)

52.5%

1.9

87,960

A joint venture that owns a 266-mile interstate pipeline and compression facilities serving markets in the northeast and supply from the northeast Marcellus region

NEXUS (a)

50%

1.4

104,000

A joint venture that owns a 256-mile interstate pipeline and three compression facilities that transports Utica and Marcellus shale natural gas to Ohio, Michigan and Ontario market centers and Generation

OH and MI

Vector (a)

40%

2.8

120,000

A joint venture that owns a 348-mile interstate pipeline and five compression facilities connecting Illinois, Indiana, Michigan and Ontario market centers

Canada, IL, IN and MI

Viking

100%

Yes

1.0

69,500

A 674-mile bi-directional interstate pipeline which serves key utility customers in Minnesota, Wisconsin and North Dakota

MN, ND and WI

Intrastate Pipelines

Generation

50%

0.4

—

A 25-mile intrastate pipeline in northern Ohio and owned by NEXUS

Michigan System (b)

100%

Yes

0.8

2,400

A 335-mile pipeline system in northern Michigan

FERC-Regulated Storage System

Washington 10 Storage Complex (c)

91%

Yes

N/A

26,200

An interstate storage system with 94 Bcf of storage capacity and associated compression facilities

Gathering Lateral Pipelines

Bluestone

100%

Yes

1.2

31,400

A 65-mile gathering lateral pipeline, and two compression facilities, that gathers Marcellus shale natural gas to Millennium and the Tennessee Pipeline

PA and NY

LEAP

100%

Yes

2.1

36,000

A 221-mile gathering pipeline that gathers Haynesville shale natural gas to markets in the Gulf Coast region

Stonewall

85%

Yes

1.5

—

A 68-mile gathering lateral pipeline that gathers Marcellus and Utica shale natural gas to the Columbia Pipeline

__________________________________

(a)We account for our ownership interest in these joint venture properties as equity method investments in accordance with GAAP. See Note 1, "Description of the Business and Basis of Presentation" to the Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

(b)The Michigan System is comprised of both intrastate pipeline and gathering lateral pipeline assets. In 2025, the majority of the capacity, mileage, and revenue generated by the Michigan System were related to providing intrastate transportation services.

(c)The Washington 10 Storage Complex includes 16 Bcf of leased capacity from the Washington 28 Storage Complex, which is held by a joint venture, South Romeo, in which DT Midstream owns a 50% interest.

Business Updates

During the year ended December 31, 2025, we completed key integration milestones for the DTM Interstate Transportation assets acquired in the Midwest Pipeline Acquisition, including opening a new regional office in Tulsa, Oklahoma, which will largely support these assets. A full year of operations of the DTM Interstate Transportation assets contributed to growth of our Pipeline segment.

During 2025, we reached a final investment decision on the Guardian G3 expansion project, which will increase Guardian capacity by 537 MMcf/d or approximately 40% from current capacity, and is expected to be fully placed into service in the fourth quarter of 2028. The Guardian G3 expansion is anchored by 20-year negotiated rate precedent agreements with investment-grade utility customers. In addition, we also initiated phase 1 of a multi-year modernization program for the acquired pipelines. The initial phase will be predominantly focused on improving system efficiency and reliability on Guardian and is expected to be placed into service in the second half of 2027.

On July 31, 2025, the FERC approved (subject to a filed appeal) the Bluestone Extended Supply Transportation ("BEST") agreement between Bluestone and Millennium which will enable Millennium to establish a new supply lateral utilizing Bluestone’s existing interconnects, creating a transportation path between Millennium and Tennessee Gas Pipeline. The firm transportation service began on January 1, 2026.

In September 2025, we placed the LEAP phase 4 expansion into service on budget, increasing the system capacity to approximately 2.1 Bcf/d. We continue to evaluate opportunities for additional LEAP expansions to serve growing Gulf Coast LNG and industrial corridor demand. Additionally, during the year ended December 31, 2025, we began construction of an interconnect between Stonewall and Mountain Valley Pipeline as well as a lateral connecting Midwestern to a power plant. The Stonewall and Mountain Valley Pipeline interconnect was placed into service on February 1, 2026, and the Midwestern lateral is expected to be placed into service during the first half of 2026. Capital expenditure investments for our ongoing expansion projects are contemplated in our forecasted capital expenditures discussed under Part II, Item 7 "Management’s Discussion and Analysis of Financial Condition and Results of Operations—Capital Investments" of this Form 10-K.

Gathering Segment

Description

Our Gathering segment includes gathering systems, related treatment plants, and compression and surface facilities. Our subsidiary companies own and operate these types of assets across multiple states.

Our natural gas gathering systems primarily consist of networks of pipelines that collect natural gas from points at or near our customers’ wells for delivery to plants for treating, to gathering pipelines for further gathering, or to pipelines for transportation. Natural gas is moved from the receipt points to the central delivery points on our gathering systems. We provide other ancillary services within our Gathering segment, including compression, dehydration, gas treatment, water impoundment, water transportation, water disposal, and sand mining. Our gathering systems provide a gathering function and are therefore not subject to FERC jurisdiction. Our gathering business has significant infrastructure within our customers' production acreage that is contractually dedicated to DT Midstream to provide gathering services.

Revenues

Our Gathering segment typically has firm revenue contracts that are long-term and structured using fixed demand charges or MVCs with fixed deficiency fee rates. This provides for fixed revenue commitments regardless of actual volumes of natural gas that flow, which leads to more stable operating performance, revenues and cash flows and limits our exposure to natural gas price fluctuations. Additional revenues are generated from proved developed producing reserves connected to our assets, which we refer to as "flowing gas." For the year ended December 31, 2025, approximately 57% and 36% of our Gathering segment revenue was generated under firm revenue contracts and flowing gas, respectively.

For the years ended December 31, 2025 and 2024, average throughput from the Gathering segment was 3.1 Bcf/d and 2.9 Bcf/d, respectively. For the year ended December 31, 2025, revenue from the Gathering segment accounted for approximately 45% of our consolidated revenue.

Competition

Our Gathering operations compete for customers based on geographic location, reputation, operating reliability and flexibility, price and service offerings, including interconnectivity to producer-desired takeaway options (i.e., processing facilities and pipelines). We mitigate the risk of competition by signing acreage dedications, entering firm revenue contracts, expanding treating capacity and expanding our systems to desirable production basins. Competition customarily is impacted by the level of drilling activity in a particular geographic region. Our primary competitors include other independent midstream companies with gathering operations and producer owned systems.

Properties

The following table presents certain information concerning our principal properties included in the Gathering segment:

Property Classification

% Owned

Operator

Approximate Capacity (Bcf/d)

Approximate Compression Horsepower

Description

Location

Gathering

Appalachia Gathering

100%

Yes

1.1

92,300

A 154-mile gathering system that gathers Marcellus shale natural gas to the Texas Eastern Pipeline and Stonewall

PA and WV

Blue Union Gathering

100%

Yes

2.6

81,600

A 443-mile gathering system that gathers shale natural gas from the Haynesville formation of Louisiana and Texas and delivers to markets in the Gulf Coast region; ancillary services are also provided

LA and TX

Clean Fuels Gathering

100%

Yes

0.0

9,400

A 93-mile gathering system that gathers and treats coal mine methane into pipeline quality natural gas

Ohio Utica Gathering

100%

Yes

0.1

12,500

A 26-mile gathering system, including compression and dehydration facilities, that gathers Utica shale natural gas from producer wells to a nearby processing plant

Susquehanna Gathering

100%

Yes

1.2

78,000

A 198-mile gathering system that gathers Marcellus shale natural gas to Bluestone

Tioga Gathering

100%

Yes

0.1

—

A 3-mile gathering system that gathers shale natural gas to the Eastern Gas Transmission system

Business Updates

During the year ended December 31, 2025, we gathered record high volumes on our Haynesville System, where we also placed into service an expansion on Blue Union Gathering. In addition, our Tioga Gathering expansion and Clean Fuels Gathering projects were placed into service. Our Class VI permit application for the Louisiana carbon capture and sequestration project advanced to formal technical review with the Louisiana Department of Conservation and Energy in July 2025, and the Company is awaiting the completion of that review.

Capital expenditure investments for our ongoing expansion projects are contemplated in our forecasted capital expenditures discussed under Part II, Item 7 "Management’s Discussion and Analysis of Financial Condition and Results of Operations—Capital Investments" of this Form 10-K.

Pipeline and Gathering Rights-of-Way

We obtain satisfactory title to the properties we own and use in our businesses, subject to liens for current taxes, liens incident to minor encumbrances, and easements and restrictions, which do not materially detract from the value of such property, the interests in those properties or the use of such properties in our businesses. Our storage facilities, treating and processing plants, compressor stations, offices and related facilities are located on real property owned or leased by us. In some cases, the real property we lease is on federal, state or local government land.

We typically obtain and maintain rights to construct and operate the pipelines on other people’s land under agreements that are perpetual or provide for renewal rights. Our pipelines are constructed on rights-of-way granted by the current record owners of such property. In many instances, lands over which rights-of-way have been obtained are subject to prior liens that have not been subordinated to the rights-of-way grants. All record owners have joined in the rights-of-way grants and signatures have been obtained, except in unusual cases where title is unclear and requires additional investigation.

Human Capital Resources

DT Midstream recognizes that being innovative is necessary for our continued growth. We currently employ 588 employees, all of whom are employed full-time, exclusive of our student intern program. All of our employees are in the U.S., with our headquarters in Detroit, Michigan. None of our employees are covered by collective bargaining agreements. We believe that our employee relations are good.

Know, Support and Respect Culture

Our human capital resources objectives continue to center around employee engagement, strengthening our culture, and leadership development. We accomplish this through our annual engagement survey and training focused on our Know, Support and Respect priorities discussed below. We maintain and grow our team through practices that help us identify and hire new talent, as well as incentivize and retain our existing employees. Our employees have access to online learning resources, tuition reimbursement programs, and formal leadership development for emerging leaders identified at various levels within our corporate structure. Our executive leadership team meets annually with our Board of Directors' Organization and Compensation Committee to discuss executive leadership succession planning, including successor candidates and emerging leaders for senior management positions within the Company.

DT Midstream is committed to building an empowered, and engaged team that delivers safe and reliable service to our customers. We integrate these practices into our overall operating model and focus on the outcomes of Knowing, Supporting, and Respecting one another. We regularly review our geographical availability, representation demographics, and engagement scores, and we evaluate our success based on our ability to advance our Know, Support and Respect Culture priorities:

•Know — Deliberately understanding the demographics and cultural norms of the communities where we live and operate;

•Support — Honestly understanding and listening to the perspectives and needs of all employees, regardless of location, position, or tenure, and developing strategic action plans based on annual engagement survey feedback; and

•Respect — Respect is required so that every employee feels comfortable being themselves at work.

Health and Safety

The health and safety of people, including our employees, contractors, customers, and the communities we serve is our top priority. Our safety culture is maintained and strengthened by our safety team, which monitors events, compliance, and training activities.

We monitor our safety performance with leading and lagging indicators, such as safety observations, near-misses and the OSHA recordable injury metrics.

Compensation and Benefits Description

Our human capital resources objectives include recruiting, incentivizing, fostering belonging, and retaining top talent. To achieve this, we offer all employees competitive compensation packages, annual and long-term incentive programs, defined contribution retirement savings plans and an employer contribution match, as well as paid time off, medical, dental, vision and other employee benefits. We review our compensation practices annually to ensure that pay is fair and internally equitable. For additional information on the metrics used in our incentive plans, see Part III, Item 11 "Executive Compensation" of this Form 10-K.

For additional information on our approach to managing our human capital resources, see our 2025 Corporate Sustainability Report on our website. The information in our Corporate Sustainability Report is not incorporated by reference into this Form 10-K.

Regulatory Environment

Our operations and investments are subject to extensive regulation by United States federal, state and local authorities. In addition, NEXUS and Vector are subject to applicable laws, rules, and regulations in Canada. Failure to comply with federal, state or local regulations may result in the imposition of administrative, civil and/or criminal remedies. We cannot predict whether a regulatory complaint or proceeding will be filed against us in the future or how a regulator may rule on any such complaint. We are not aware of any pending proceedings or complaints at this time.

Additional rules and legislation pertaining to these matters are considered and adopted from time to time. In certain instances, existing rules and legislation may be repealed or substantially modified in a way that reduces our regulatory compliance obligations. We cannot predict whether any such additional rules or legislation will be promulgated or enacted, whether any existing rules or legislation will be repealed or substantially modified, or what effect, if any, such changes might have on our operations, or existing regulatory requirements. To the extent that any new rules or legislation increase our regulatory compliance obligations, the industry could be required to incur additional capital expenditures and increased costs depending on future legislative and regulatory changes.

Federal Interstate Transportation & Storage Regulation

Many of our business operations are subject to extensive regulation by FERC under the NGA, the NGPA and regulations, rules and policies promulgated under those and other statutes. Specifically, Birdsboro, Guardian, Midwestern, Millennium, NEXUS, Vector, Viking and the Washington 10 Storage Complex are subject to FERC's NGA authority and provide interstate natural gas transportation or storage services in accordance with their FERC-approved tariffs. Notwithstanding the regulatory discussion below, we believe the regulatory burden does not currently affect our competitive condition.

Generally, FERC’s authority with respect to natural gas extends to:

•rates and charges for interstate pipelines and storage facilities as well as intrastate pipelines and storage facilities providing service in interstate commerce;

•terms and conditions of services and service contracts with customers;

•certification and construction of new interstate pipelines and storage services and facilities and expansion of such facilities;

•abandonment of interstate pipelines and storage services and facilities;

•maintenance of accounts and records;

•relationships between pipelines and certain affiliates;

•depreciation and amortization rates and policies;

•facility replacements and upgrades; and

•acquisitions and dispositions of interstate pipelines and storage facilities.

Under the NGA, rates charged by interstate pipelines must be just, reasonable, and not unduly discriminatory or preferential. For interstate pipeline transportation services subject to cost‑of‑service regulation, the recourse rate is the maximum rate an interstate pipeline may charge for its services under its tariff. It is established through FERC’s cost-of-service ratemaking process. Key determinants in the ratemaking process include the costs of providing service, the volumes of gas being transported, the rate design, the allocation of costs between services, the capital structure, the depreciation rate and the rate of return a natural gas company is permitted to earn. The maximum applicable recourse rates and terms and conditions for service on an interstate natural gas pipeline are set forth in the pipeline’s FERC-approved tariff unless market-based rates have been approved by FERC. Rate design and the allocation of costs also can affect a pipeline’s profitability. While the ratemaking process establishes the recourse rate, interstate pipelines such as some of our pipelines and storage systems that provide cost‑of‑service‑based services are permitted to charge discounted rates, which are lower than the recourse rates, without further FERC authorization down to the minimum rate set forth in the tariff for the applicable service. If a pipeline company desires to change its recourse rates or terms and conditions of service, including pro forma contracts, then it must propose such changes to FERC in a filing made pursuant to Section 4 of the NGA. Such changes may be challenged by intervening parties, including customers and state agencies, and such proposed changes may ultimately be rejected by FERC. By contrast, our natural gas storage facility operates pursuant to FERC‑approved market‑based rate authority, and the rates charged for storage services are not established through FERC’s cost‑of‑service ratemaking process.

Existing rates or terms and conditions of service and contracts also may be challenged by a complaint filed by interested persons, including customers, state agencies or FERC, under Section 5 of the NGA. Rate increases proposed by a pipeline may be allowed to become effective subject to refund and/or a period of suspension, while rates or terms and conditions of service that are the subject of a complaint under Section 5 of the NGA are subject only to prospective change by FERC. Any successful challenge against existing or proposed rates charged for our pipelines and storage services could materially adversely affect our business, financial condition and results of operations.

In addition, our interstate pipelines may also charge negotiated rates that may be above or below the recourse rate or that are subject to a different rate design than the rates specified in our interstate pipeline tariffs, provided that the pipeline has appropriate language in its tariff permitting negotiated rates, that affected customers are willing to agree to such rates rather than recourse rates, and that FERC has approved the negotiated rate agreement. A prerequisite for allowing the negotiated rates is that negotiated rate customers must have had the option to take service under the pipeline’s recourse rates. Some negotiated rate transactions are designed to fix the negotiated rate for the term of the firm transportation agreement and the fixed rate is generally not subject to adjustment for increased or decreased costs occurring during the contract term or for changes in the recourse rate during the contract term.

Interstate transportation and storage service agreements are required to conform, in all material respects, with the form of service agreements set forth in the pipeline’s FERC-approved tariff. Non-conforming agreements must be filed with, and accepted by, FERC. If FERC finds that an agreement is materially non-conforming, in whole or in part, it could reject, or require us to seek modification of, the agreement, or alternatively require us to modify our tariff so that the non-conforming provisions are generally available to all customers or class of customers.

Failure of an interstate pipeline to comply with its obligations under the NGA could result in the imposition of civil and criminal penalties. The EPAct 2005 amended the NGA to give FERC authority to impose civil penalties for violations of the NGA up to $1,584,648 per violation per day (as adjusted for inflation for 2025), and violators may be subject to criminal penalties of up to $1 million per violation per day and five years in prison.

State Intrastate Transportation Regulation

Many state agencies possess the authority to review and authorize natural gas transportation transactions and the construction, acquisition, abandonment and interconnection of physical facilities for intrastate pipelines. State agencies also may regulate transportation rates, service terms, and conditions and contract pricing. Other state regulations may not directly apply to our business but may nonetheless affect the availability of natural gas for purchase, compression and sale. Regulations within a particular state generally will affect all intrastate pipeline operators within the state on a comparable basis; thus, we believe that the regulation of intrastate transportation in any state in which we operate will not disproportionately affect our operations.

Gathering Pipeline Regulation

Section 1(b) of the NGA exempts natural gas gathering facilities from regulation by FERC. We believe that our gathering systems meet the traditional tests FERC has used to establish a pipeline’s status as an exempt gatherer not subject to regulation as a FERC-jurisdictional natural gas company. If FERC were to consider the status of an individual facility and determine that the facility is not a gathering pipeline and the pipeline provides interstate transmission service, the rates for, and terms and conditions of, services provided by such facility would become subject to regulation by FERC under the NGA or the NGPA. Such regulation could decrease revenue, increase operating costs and, depending upon the facility in question, adversely affect our business, financial condition and results of operations. In addition, if any of our facilities were found to have provided services or otherwise operated in violation of the NGA or NGPA, this could result in the imposition of civil penalties as well as a requirement to disgorge charges collected for such service in excess of the rate established by FERC.

Our gathering assets may be subject to the rules and regulations of various state utility commissions. State regulation of gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements and complaint-based rate regulation. States in which we operate may adopt ratable take and common purchaser statutes, which would require our gathering pipelines to take natural gas without undue discrimination in favor of one producer over another producer or one supply source over another similarly situated supply source. The regulations under these statutes may impose some restrictions on our ability as an owner of gathering facilities to decide with whom we contract to gather natural gas. States in which we operate may also adopt a complaint-based regulation of natural gas gathering activities, which allows natural gas producers and shippers to file complaints with state regulators in an effort to resolve grievances relating to gathering access and rate discrimination.

Our gathering operations could be adversely affected should they be subject in the future to different application of state regulation of rates and services. Our gathering operations also may be, or become, subject to additional safety and operational regulations relating to the design, installation, testing, construction, operation, replacement, and management of gathering facilities.

FERC and CFTC Enforcement

The EPAct 2005 amended the NGA and NGPA to prohibit fraud and manipulation in natural gas markets, and FERC issued a final rule making it unlawful for any entity, in connection with the purchase or sale of natural gas or transportation service subject to FERC’s jurisdiction, to defraud, make an untrue statement or omit a material fact, or engage in any practice, act or course of business that operates or would operate as a fraud. FERC’s anti-manipulation rules apply to interstate gas pipeline and storage companies and intrastate gas pipeline and storage companies that provide interstate services, such as Section 311 service, as well as otherwise non-jurisdictional entities to the extent the activities are conducted "in connection with" gas sales, purchases or transportation subject to FERC jurisdiction. The anti-manipulation rules apply to intrastate sales and gathering activities only to the extent that there is a "nexus" to FERC-jurisdictional transactions. The EPAct 2005 also provided FERC with the authority to impose civil penalties, which, as adjusted for inflation for 2025, is currently up to a maximum of $1,584,648 per violation per day.

In addition, the CFTC is directed under the Commodity Exchange Act to prevent price manipulations in the commodity and futures markets, including the energy futures markets. Pursuant to the Dodd-Frank Act and other authority, the CFTC has adopted anti-market manipulation regulations that prohibit fraud and price manipulation in the commodity and futures markets. The CFTC also has statutory authority to seek civil penalties of up to the greater of approximately $1.5 million (as adjusted for inflation for 2025) per violation or triple the monetary gain to the violator for violations of the anti-market manipulation provisions of the Commodity Exchange Act.

Pipeline Safety and Maintenance Regulation

Our natural gas pipeline assets are subject to the pipeline safety regulations implemented by PHMSA. PHMSA establishes and implements minimum federal safety standards and reporting requirements applicable to gas pipeline facilities, including associated underground natural gas storage. These standards include requirements that apply to the design, installation, testing, construction, operation and maintenance, and operator qualification as well as requirements for integrity management on certain pipelines. The integrity management requirements apply to gas transmission line segments located in HCAs and require operators to perform periodic risk-based assessments in addition to the minimum required inspections and other preventative and mitigation measures. Notwithstanding the investigatory and preventative maintenance costs incurred in our performance of customary pipeline management activities, we may incur significant additional expenses if anomalous pipeline conditions are discovered or additional preventative and mitigation measures need to be implemented.

PHMSA often issues new or amended safety standards and reporting requirements for gas pipeline facilities. For example, the "Safety of Gas Transmission Pipelines: MAOP Reconfirmation, Expansion of Assessment Requirements, and Other Related Amendments" rule, which became effective July 1, 2020, requires operators of certain gas transmission pipelines to reconfirm the maximum allowable operating pressure for certain portions of their systems and imposes periodic assessment requirements for certain areas outside of HCAs, including newly-defined MCAs. The rule also incorporates industry standards and guidelines as well as new requirements for integrity management programs. In August 2022, PHMSA published the "Safety of Gas Transmission Pipelines: Repair Criteria, Integrity Management Improvements, Cathodic Protection, Management of Change, and Other Related Amendments" rule, effective May 24, 2023, which increases gas integrity management and corrosion control requirements and establishes repair criteria for pipelines outside of HCAs, among other things. We have revised our operating and inspection procedures to address these requirements and have implemented these changes as required by the rules. We may incur additional expenses related to compliance activities associated with this rule but do not expect these expenses to be material.

In November 2021, PHMSA issued another final rule, entitled "Safety of Gas Gathering Pipelines: Extension of Reporting Requirements, Regulation of Large, High-Pressure Lines, and Other Related Amendments," effective May 16, 2022, that established new safety standards and reporting requirements for certain historically unregulated onshore gas gathering lines. The final rule created a new Type C category of regulated onshore gas gathering lines in Class 1 locations that are subject to PHMSA’s safety standards and reporting requirements and required operators to comply with certain regulatory requirements applicable to newly designated Type C gas gathering lines by May 16, 2023. The final rule also created a new Type R category of reporting-only onshore gas gathering pipelines that are subject to PHMSA’s incident and annual reporting requirements. We have revised our operating and maintenance procedures to address these requirements and have implemented these changes. We may incur additional expenses related to compliance activities but do not expect these expenses to be material.

In April 2022, PHMSA published the "Pipeline Safety: Requirement of Valve Installation and Minimum Rupture Detection Standard" rule, effective October 5, 2022, which required installation of remote control or automatic shut-off valves (or alternative equivalent technology) on certain newly constructed or replaced gas transmission pipelines. The final rule also imposed minimum performance standards for operation of those valves. We may incur additional expenses related to the requirements imposed by this rule, but do not expect these expenses to be material.

In May 2023, PHMSA issued a Notice of Proposed Rulemaking, entitled "Gas Pipeline Leak Detection and Repair," that proposes amendments to implement a congressional mandate in the 2020 PIPES Act and impose leak detection and repair criteria applicable to gas pipelines and underground natural gas storage facilities. The final rule was submitted for publication in the Federal Register in January 2025 but was withdrawn for further review by PHMSA with no timeframe for a final rule. The rulemaking has been classified as a long-term action in the Department of Transportation's regulatory agenda. PHMSA is also in the process of revising regulations applicable to requirements for operators in response to certain class location changes, developing a proposed rule to establish inspection and maintenance requirements for idled pipelines, and revising repair criteria for gas transmission pipelines. Congress is also required to periodically reauthorize the Pipeline Safety Act and is expected to do so in 2026. Through reauthorization of the Pipeline Safety Act, Congress may pass a bill that mandates other statutory changes or directs PHMSA to develop additional rulemaking.

It is unclear how the adoption of these new PHMSA rules could impact our pipeline assets and operations, including our operational costs. While some revised regulations require the installation of new or modified safety controls and the implementation of new capital projects or accelerated maintenance programs, which may increase our operational costs, other rulemaking initiatives are intended to be deregulatory in nature. We may also be affected by lost cash flows resulting from shutting down our pipelines during the pendency of any repairs and any testing, maintenance, and repair of pipeline facilities downstream from our own facilities.

Every state in which we operate is certified by PHMSA to regulate the safety of intrastate gas pipeline facilities consistent with the federal safety standards, and some of these states apply additional or more stringent safety standards or reporting requirements to intrastate gas pipeline facilities in their respective jurisdictions. We may incur significant costs and liabilities associated with repair, remediation, preventive or mitigation measures associated with complying with these additional or more stringent state requirements, including for certain gas gathering lines or other pipeline facilities that are not currently subject to PHMSA’s regulations. The costs, if any, for repair, remediation, preventive or mitigating actions that may be determined to be necessary, as well as lost cash flows resulting from shutting down our pipelines during the pendency of such actions, could be material.

We incur significant costs in complying with U.S. federal and state pipeline safety laws and regulations and otherwise administering our pipeline safety program, but we do not believe such costs of compliance will materially adversely affect our business, financial condition and results of operations. While we cannot predict the outcome of pending or future legislative or regulatory initiatives, we anticipate that pipeline safety requirements will continue to become more stringent over time. As a result, we may incur significant additional costs to comply with the new pipeline safety regulations, the pending pipeline safety regulations, and any new pipeline safety laws and regulations associated with our pipeline facilities, which could materially adversely affect our business, financial condition and results of operations.

Should we fail to comply with PHMSA or state regulations, where applicable, we could be subject to penalties and fines. PHMSA has the statutory authority to impose civil penalties for pipeline safety violations up to a maximum of approximately $272,926 per day for each violation and approximately $2.73 million for a related series of violations (as adjusted for inflation as prescribed in 2025). This maximum penalty authority established by statute will continue to be adjusted periodically to account for inflation, including in 2026.

Our operations are in substantial compliance with all existing U.S. federal, state and local pipeline safety laws and regulations. However, the adoption of new laws and regulations, such as those proposed by PHMSA, could result in significant added costs or delays in service or the termination of projects, which could have a material adverse effect on us in the future.

In the course of operating our pipeline facilities, we may experience a leak or a rupture on our system. These leaks and ruptures may cause explosions, fire, damage to the environment, damage to property, personal injury and/or death. Depending on the circumstances of the leak or rupture, PHMSA or the state agent may require that certain pipeline assets remain out of service and/or operate at a significantly reduced operating pressure until certain corrective measures are performed and a return to normal operation is approved by PHMSA or the state agent. In addition to any regulatory fines or corrective measures, we may be sued for any damages. Depending upon the facts and circumstances of a particular incident, state and federal regulatory authorities may also seek civil and/or criminal fines and penalties.

Natural Gas Storage Regulation

We operate natural gas storage facilities in Michigan as interstate facilities regulated by PHMSA and provide interstate storage and related services pursuant to a FERC-approved tariff. As such, our natural gas storage facilities are required to meet the federal safety standards as required by 49 C.F.R. §192.12, Underground natural gas storage facilities. New regulations that may expand requirements for underground natural gas storage facilities were under development by PHMSA based on the May 2023 PHMSA Notice of Proposed Rulemaking entitled "Gas Pipeline Leak Detection and Repair." PHMSA submitted a final rule for publication in the Federal Register in January 2025, which was subsequently withdrawn for further review by PHMSA with no projected timeframe for finalizing the regulations and the rulemaking has been classified as a long-term action in the Department of Transportation's regulatory agenda.

Our operations are in substantial compliance with 49 C.F.R. §192.12, Underground natural gas storage facilities. However, the adoption of new laws and regulations could result in significant added costs or delays in service or the termination of projects, which could have a material adverse effect on us in the future.

Environmental and Occupational Health and Safety Regulations

General. Our operations are subject to U.S. federal, state and local environmental laws and regulations relating to air quality, water quality, waste management, wildlife conservation, natural resources and worker health and safety. These laws and regulations require the acquisition of and compliance with permits and the installation of pollution control equipment or replacement of aging pipelines and other facilities; limit or prohibit construction activities in sensitive areas such as wetlands, wilderness or areas that provide habitat for endangered or threatened species; require investigatory and remedial actions to mitigate or eliminate pollution conditions caused by our operations or attributable to former operations; and apply health and safety criteria addressing worker protections.

In addition, our operations and construction activities are subject to county and local ordinances that restrict the time, place or manner in which those activities may be conducted to reduce or mitigate nuisance-type conditions, such as, for example, excessive levels of dust or noise or increased traffic congestion.

Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties; the occurrence of delays or cancellations in the permitting or performance or expansion of projects; the denial or termination of project authorizations; the imposition of restrictions or limitations on project authorizations; the addition or removal of conditions or terms in project authorizations; the issuance of injunctions limiting or preventing some or all of our operations in a particular area; and, under certain environmental laws, citizen suits, in which individuals and environmental organizations act in the place of the government and sue operators for alleged violations of environmental law.

We have implemented programs and policies designed to keep our pipelines and other facilities in compliance with existing environmental laws and regulations, and we incur significant costs in connection with compliance. We also incur, and expect to continue to incur, additional costs with respect to construction as existing environmental laws and regulations impact the cost of planning, design, permitting, installation and start-up, and with respect to capital expenditures for pollution control equipment that is necessary to achieve emission and discharge standards included in our permits.

Moreover, we incur, and expect to continue to incur, additional costs in connection with spill response. Spills can result in significant costs associated with the investigation and remediation of contaminated facilities, and with injury and damage claims arising from releases and related contamination.

The timing and complete extent of future expenditures related to environmental matters is difficult to estimate accurately because, among other things, interpretation and enforcement of environmental laws and regulations are constantly changing, our pollution control and clean-up cost estimates may change, especially when our current estimates are based on preliminary site investigations or agreements, and new contaminated facilities and sites may be found, or what we know about existing sites and facilities could change.

We do not believe that our compliance with environmental legal requirements will materially adversely affect our business, financial condition and results of operations. Nonetheless, the trend in environmental regulation is to place more restrictions and limitations on activities that may affect human health or the environment. Thus, there can be no assurance as to the amount or timing of future expenditures for environmental compliance or remediation, and actual future expenditures may be significantly in excess of the amounts we currently anticipate. For example, we try to anticipate future regulatory requirements that might be imposed and plan accordingly to remain in compliance with changing environmental laws and regulations and to minimize the costs of such compliance. While we are in substantial compliance with existing environmental laws and regulations, additional, unplanned measures and expenditures may be required to maintain compliance in the future.

The following is a discussion of several of the principal environmental laws and regulations, as amended from time to time, which relate to our business.

Hazardous Substances and Waste. CERCLA and comparable state laws impose liability, without regard to fault or the legality of the original conduct, on current and prior owners or operators of the sites where a release of hazardous substances occurred or extends and companies that transported, disposed or arranged for the transportation or disposal of the hazardous substances released. Under CERCLA, these "responsible parties" may be subject to strict and 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 parties 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. We generate materials in the course of our ordinary operations that are regulated as "hazardous substances" under CERCLA or similar state laws and, as a result, may be jointly and severally liable under CERCLA, or such laws, for all or part of the costs required to clean up sites at which these hazardous substances have been released into the environment.

In the ordinary course of our operations, we generate solid wastes and in some instances hazardous wastes, which are subject to the requirements of RCRA and comparable state statutes. While RCRA regulates both solid and hazardous wastes, it imposes strict requirements on the generation, storage, treatment, transportation and disposal of hazardous wastes. While certain petroleum production wastes are excluded from RCRA’s hazardous waste regulations, it is possible that these wastes will in the future be designated as "hazardous wastes" and be subject to more rigorous and costly disposal requirements, which could have a material adverse effect on our maintenance capital expenditures and operating expenses.

We own, lease or operate properties where hydrocarbons are being or have been handled for many years, by us and by former owners or operators, and we send hydrocarbons and wastes to third-party sites for treatment or disposal. Under CERCLA, RCRA and analogous state laws, we could be required to remove or remediate previously disposed or released wastes (including wastes disposed of or released by prior owners or operators), to clean up contaminated property (including contaminated groundwater) or to perform remedial operations to prevent future contamination, as well as to reimburse for or contribute to the remediation of third-party disposal and treatment sites. We are not currently aware of any facts, events or conditions relating to the application of such requirements that could reasonably materially adversely affect our business, financial condition and results of operations.

Air Emissions. The U.S. federal Clean Air Act and comparable state laws and regulations restrict the emission of air pollutants from various industrial sources, including our compressor stations, and also impose various pre-construction, operational, monitoring and reporting requirements. Such laws and regulations may require that we obtain pre-approval for the construction or modification of certain projects or facilities, obtain and strictly comply with air permits containing various emissions and operational limitations, and utilize specific emission control technologies to limit emissions. Our failure to comply with these requirements could subject us to monetary penalties, injunctions, conditions or restrictions on operations and, potentially, criminal enforcement actions. We may be required to incur certain capital expenditures in the future for air pollution control equipment in connection with obtaining and maintaining permits and approvals for air emissions. Compliance with these requirements may require modifications to certain of our operations, including the installation of new equipment to control emissions from our compressors that could result in significant costs, increased capital expenditures and operating costs, and could adversely affect our business. Further, the permitting, regulatory compliance and reporting programs, taken as a whole, increase the costs and complexity of oil and gas operations with potential to adversely affect the cost of doing business for our customers resulting in reduced demand for our gas processing and transportation services. Although we can give no assurances, we believe such requirements will not materially adversely affect our business, financial condition and results of operations, and the requirements are not expected to be more burdensome to us than to any similarly situated midstream company.

Climate Change. Legislative and regulatory measures to address climate change and GHG emissions are in various phases of discussion or implementation. The EPA regulates GHG emissions from new and modified facilities that are potential major sources of criteria pollutants under the Clean Air Act’s Prevention of Significant Deterioration and Title V programs and has adopted regulations that require, among other things, preconstruction and operating permits for certain large stationary sources and the monitoring and annual reporting of GHGs from certain onshore oil and natural gas production sources. On December 2, 2023, the EPA released a final rule to regulate GHG emissions (in the form of methane limitations, as well as design, equipment, work practice, and operational standards) and volatile organic compound emissions from crude oil and natural gas production, processing, transmission, and storage. The final rule includes standards of performance for new, modified, and reconstructed sources and emission guidelines for existing sources. On December 3, 2025, the EPA published a final rule extending the compliance deadlines for certain requirements set forth in the rule released on December 2, 2023. Additionally, the U.S. Congress, along with U.S. federal and state agencies, has considered measures to reduce the emissions of GHGs. On August 16, 2022, the U.S. Congress enacted the Inflation Reduction Act, pursuant to which EPA issued regulations (announced November 12, 2024) that impose a charge on methane emissions that exceed certain thresholds from offshore and onshore petroleum and natural gas production, onshore natural gas processing, onshore natural gas transmission compression, certain kinds of natural gas and LNG storage, and onshore petroleum and natural gas gathering and boosting. On March 14, 2025, the President signed into law a joint resolution disapproving these regulations and rendering them without legal force of effect by operation of the Congressional Review Act. On July 4, 2025, the President signed the OBBBA, which amended the Clean Air Act to postpone the applicability of the waste emission charges set forth in the Inflation Reduction Act until calendar year 2034. Legislation or regulation that levies a charge related to our GHG emissions or that restricts GHG emissions could increase our cost of environmental compliance by requiring us to install new equipment to reduce emissions from larger facilities; purchase emission allowances; administer and manage a GHG emissions program; and otherwise increase the costs of our operations, including costs to operate and maintain our facilities.

FERC does not directly regulate GHG emissions. However, on February 17, 2022, FERC issued two policy statements providing guidance on its consideration of GHG emissions and other factors when reviewing proposed projects under the NGA. These policy statements have been the subject of public comments. On January 24, 2025, FERC issued an order terminating the Consideration of Greenhouse Gas Emissions in Natural Gas Infrastructure Project Reviews proceeding. FERC instead said it will address GHG emissions issues on a case-by-case basis.

PHMSA was working on a Congressionally-mandated rulemaking to impose leak detection and repair criteria to reduce GHG emissions associated with PHMSA-regulated gas pipeline facilities and underground natural gas storage facilities. PHMSA submitted a final rule for publication in the Federal Register in January 2025, which has since been withdrawn for further review by PHMSA with no timeframe for finalizing the regulations and the rulemaking has been classified as a long-term action in the Department of Transportation's regulatory agenda. If this rulemaking is finalized, we may incur additional expenses related to the requirements imposed by this rule, but do not expect these expenses to be material.

The effect of climate change legislation or regulation on our business is currently uncertain. If we incur additional costs to comply with such legislation or regulations, we may not be able to pass on the higher costs to our customers or recover all the costs related to complying with such requirements, and any such recovery may depend on events beyond our control, including the outcome of future rate proceedings before FERC or state regulatory agencies and the provisions of any final legislation or implementing regulations. Our future business, financial condition and results of operations could be adversely affected if such costs are not recovered through regulated rates or otherwise passed on to our customers. Additionally, our customers or suppliers may also be affected by legislation or regulation, which may adversely impact their demand for our services.

Climate change and GHG legislation or regulation could also delay or otherwise negatively affect efforts to obtain permits and other regulatory approvals with regard to existing and new facilities or impose additional monitoring and reporting requirements. The effect of any new legislative or regulatory measures on us will depend on the particular provisions that are ultimately adopted.

Water Discharges. The U.S. federal Clean Water Act and analogous state laws impose restrictions and strict controls regarding the discharge of pollutants or dredged and fill material into state waters as well as WOTUS, including adjacent wetlands. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of permits issued by the EPA, the U.S. Army Corps of Engineers, and/or an analogous state agency. The definition of WOTUS has been the subject of multiple regulatory interpretations and judicial decisions in recent years. In May 2023, the U.S. Supreme Court issued its decision in Sackett v. Environmental Protection Agency, which adopted a narrower test for wetlands covered under the Clean Water Act; and, in August 2023, the EPA and the U.S. Army Corps of Engineers promulgated final rule amendments for a new WOTUS definition that conformed to the Supreme Court's Sackett decision. The definition remains subject to litigation, with opponents arguing it is not sufficiently narrow. In November of 2025, the EPA and the U.S. Army Corps of Engineers proposed a narrower regulatory definition of WOTUS, but the definition has not yet been finalized. While recent and future changes to the definition may ease permitting in certain circumstances, continued controversy over the WOTUS definition may result in uncertainty, costs and delays with respect to obtaining permits for activities in jurisdictional waters, including wetlands.

Spill prevention, control and countermeasure requirements of U.S. federal laws require appropriate containment berms and similar structures to help prevent the contamination of regulated waters in the event of a hydrocarbon spill, rupture or leak. In addition, the Clean Water Act and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities. These permits may require us to monitor and sample the storm water runoff from some of our facilities. The Clean Water Act and regulations implemented thereunder also prohibit discharges of dredged and fill material in wetlands and other waters of the U.S. unless authorized by an appropriately issued permit. Some states also maintain groundwater protection programs that require permits for discharges or operations that may impact groundwater conditions. U.S. federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws. We believe that compliance with existing permits and foreseeable new permit requirements will not materially adversely affect our business, financial condition and results of operations.

National Environmental Policy Act. The construction of interstate natural gas transportation pipelines pursuant to the NGA requires authorization from FERC. Certain FERC actions relating to such pipelines are subject to NEPA, which requires U.S. federal agencies, such as FERC, to evaluate major U.S. federal actions having the potential to significantly affect the environment. During such evaluations, an agency will prepare a detailed Environmental Impact Statement unless it has found on the basis of an environmental assessment that no significant effect is likely. Such NEPA analyses have the potential to significantly delay or limit, and significantly increase the cost of, development of midstream infrastructure. Under the prior presidential administration, the White House Council on Environmental Quality implemented actions that generally require agencies to undertake more searching inquiries during their NEPA reviews of new projects that require federal permits. However, on November 12, 2024, the U.S. Court of Appeals for the D.C. Circuit Court issued an opinion in Marin Audubon Society v. Federal Aviation Administration finding that the Council’s regulations exceed the Council’s authority and do not bind the federal agencies. On February 25, 2025, the Council published an interim final rule removing the Council's regulations implementing NEPA. On May 29, 2025, the U.S. Supreme Court issued its decision in Seven County Infrastructure Coalition v. Eagle County, Colorado, holding that NEPA reviews need not address the effects of separate projects, including downstream projects. Following these events and in compliance with various Executive Orders, federal agencies rescinded or substantially revised their own NEPA regulations and issued NEPA procedures in line with Seven County Infrastructure Coalition v. Eagle County, Colorado, and with the presidential administration's policies regarding streamlining reviews.

Hydraulic Fracturing. We do not operate any assets that conduct hydraulic fracturing. However, our customers’ natural gas production is developed from unconventional sources that require hydraulic fracturing as part of the completion process. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into the formation to fracture the surrounding rock and stimulate crude oil and natural gas production. The process is regulated by state agencies, typically the state’s commission that regulates oil and gas production. A number of U.S. federal agencies, including the EPA and the U.S. Department of Energy, have analyzed, or have been requested to review, a variety of environmental issues associated with hydraulic fracturing. In addition, some states have adopted, and other states are considering adopting, regulations that could impose more stringent disclosure and/or well construction requirements on hydraulic fracturing operations.

Certain state and U.S. federal regulatory agencies are also focused on a possible connection between hydraulic fracturing-related activities, including wastewater disposal, and the increased occurrence of seismic activity. When caused by human activity, such events are called induced seismicity. In a few instances, operators of injection disposal wells in the vicinity of seismic events have been ordered by regulatory agencies to reduce injection volumes or suspend operations. Additionally, some state regulatory agencies have modified their regulations or issued orders to restrict disposal wells or enhance well construction and monitoring requirements.

These developments could result in additional regulation and restrictions on the use of injection disposal wells and hydraulic fracturing. The adoption of new laws, regulations or ordinances at the U.S. federal, state or local levels imposing more stringent restrictions on hydraulic fracturing or wastewater disposal could make it more difficult for our customers to complete natural gas wells, increase customers’ costs of compliance and doing business, and otherwise adversely affect the hydraulic fracturing services they perform, which could negatively impact demand for our services.

Endangered Species Act. The ESA restricts activities that may adversely affect endangered and threatened species or their habitats and it makes illegal the "take" of any protected species. U.S. federal agencies are required to ensure that any action authorized, funded or carried out by them is not likely to jeopardize the continued existence of listed species or modify their critical habitat. While some of our facilities are located in areas that are designated as habitats for endangered or threatened species, we have not incurred any material costs to comply or restrictions on our operations and we believe that we are in substantial compliance with the ESA. The designation of previously unprotected species as being endangered or threatened, or the designation of previously unprotected areas as a critical habitat for such species, could cause us to incur additional costs, result in delays in construction of pipelines and facilities, cause us to become subject to operating restrictions in areas where the species are known to exist or could result in limitations on our customers’ exploration and production activities that could have an adverse impact on demand for our services. For example, the U.S. Fish and Wildlife Service has received hundreds of petitions to consider listing additional species as endangered or threatened and is being regularly sued or threatened with lawsuits to address these petitions. Compliance with all applicable laws providing special protection for designated species has not posed a material cost on our business and operations to date.

Employee Health and Safety. We are subject to a number of U.S. federal and state laws and regulations, including OSHA, and comparable state statutes, whose purpose is to protect the health and safety of workers. In addition, the OSHA hazard communication standard, the EPA community "right-to-know" regulations, and comparable state laws and regulations require that information be maintained concerning hazardous materials used or produced in our operations and that this information be provided to employees, state and local government authorities and citizens. We are also subject to OSHA Process Safety Management regulations, which are designed to prevent or minimize the consequences of catastrophic releases of toxic, reactive, flammable or explosive chemicals. We are also subject to the EPA Risk Management Program, which addresses the prevention of chemical accidents and preparedness for emergencies. In February 2024, the EPA issued a final rule amending the Risk Management Program’s implementing regulations. The amended regulations impose numerous new or heightened requirements concerning incident investigations, third-party compliance auditing, consideration of alternative chemicals and technologies, and evaluation of risks from natural hazards and climate change, among other issues. The U.S. Court of Appeals for the D.C. Circuit has granted an EPA motion to hold a challenge of the final rule in abeyance to allow time for EPA to review the rule in relation to the administration’s policies.

We are in substantial compliance with all applicable laws and regulations relating to worker health and safety. Historically, worker safety and health compliance costs have not materially adversely affected our business, financial condition and results of operations; however, there can be no assurance that such costs will not be material in the future or that such future compliance will not materially adversely affect our business, financial condition and results of operations. While we may increase future expenditures to comply with higher industry and regulatory safety standards, such increases in costs of compliance, and the extent to which they might be recoverable through our rates, cannot be estimated at this time.

Item 1A. Risk Factors

You should carefully consider the following risks and other information in this Form 10-K. Any of the following risks and uncertainties could materially adversely affect our business, financial condition and results of operations.

Risks Relating to Our Business

Operational Risks

Any significant decrease in production or in demand of natural gas in our asset footprint could materially adversely affect our business, financial condition and results of operations.

Our business is dependent on the continued availability of and demand for natural gas in our areas of operation, which include the Midwestern U.S., Canada, Northeastern U.S. and Gulf Coast regions.

To maintain or increase the contracted capacity or the volume of natural gas gathered, transported and stored on our systems and cash flows associated therewith, our customers must continually obtain adequate supplies of natural gas. If new supplies of natural gas are not obtained to replace the natural decline in volumes from existing supply basins in our areas of operation, or if natural gas supplies are diverted to serve other markets, the overall volume of natural gas gathered, transported and stored on our systems would decline. The primary factors affecting our ability to obtain sources of natural gas include (i) the level of successful drilling activity near our systems, (ii) our ability to compete for volumes from successful new wells and (iii) our ability to compete successfully for volumes from sources connected to other pipelines. A reduction in the natural gas volumes supplied by producers for any of the factors mentioned above as well as national, regional, local, economic and political factors, including tariffs and periods of changing inflation, could result in reduced throughput on our systems and corresponding service revenues, which could materially adversely affect our business, financial condition and results of operations.

In addition, demand for our services is dependent on the demand for gas in the markets we serve. Alternative fuel sources such as coal, fuel oils, or nuclear energy, as well as technological advances and renewable sources of energy, could reduce demand for natural gas in our markets and have an adverse effect on our business. Government imposed constraints, such as changes in regulatory policy and permitting and environmental limitations, could also artificially limit new demand for natural gas, which could materially adversely affect our business, financial condition and results of operations.

We have one key customer, Expand Energy. The loss of, or reduction in volumes from, this customer could result in a decline in demand for our services and materially adversely affect our business, financial condition and results of operations.

Expand Energy accounted for approximately 45% of our operating revenues for the year ended December 31, 2025. Our operating revenues do not include revenues of unconsolidated joint ventures accounted for as equity method investments. The loss of all or even a portion of the contracted volumes of this or other customers, the failure to extend or replace customer contracts, or the extension or replacement of customer contracts on less favorable terms, as a result of competition, creditworthiness, reduced natural gas production or otherwise, could materially adversely affect our business, financial condition and results of operations.

We may be unable to renew or replace expiring contracts at favorable rates or on a long-term basis.

One of our exposures to market risk occurs when our existing contracts, including both our contracts with customers and our contracts with suppliers and other counterparties, expire and are subject to renegotiation and renewal. The majority of our customer contracts are firm service revenue contracts. Firm service revenue contracts are typically long-term and structured using fixed demand charges or MVCs with fixed deficiency fee rates. This provides for fixed revenue commitments regardless of actual volumes of natural gas that flow, which leads to more stable operating performance, revenues and cash flows and limits our exposure to natural gas price fluctuations. We may be unable to renew or replace these contracts at expiration, and our efforts to negotiate for similar fixed revenue commitments may be unsuccessful, which could cause our exposure to natural gas price risk to change or adversely affect the stability of our cash flows.

If third-party pipelines and other facilities interconnected to our assets become unavailable to transport natural gas, it could materially adversely affect our business, financial condition and results of operations.

We depend upon third-party pipelines and other facilities that provide receipt and delivery options to and from our assets. For example, our pipelines interconnect with multiple interstate pipelines in the Midwestern U.S., Canada, Northeastern U.S. and Gulf Coast regions and a significant number of intrastate pipelines. Because we do not own these third-party pipelines or facilities, their continuing operation is not within our control. If these pipeline connections become unavailable for current or future volumes of natural gas due to testing, turnarounds, repairs, maintenance, damage, reduced operating pressure, lack of capacity, regulatory requirements or any other reason, our ability to operate efficiently and continue shipping natural gas to end markets could be restricted, thereby reducing our revenues. Any temporary or permanent interruption at any key pipeline interconnect or other downstream facility utilized to move our customers’ product to their end destination that causes a material reduction in volumes transported on our pipelines could materially adversely affect our business, financial condition and results of operations.

In addition, the rates charged by treating plants, pipelines and other facilities interconnected to our assets affect the utilization and value of our services. Significant changes in the rates charged by these third parties, or the rates charged by the third parties that own "downstream" assets required to move commodities to their final destinations, could materially adversely affect our business, financial condition and results of operations.

Our operations are subject to operational hazards, unforeseen interruptions and damage caused by third parties and natural events. If a significant accident or event occurs that results in a business interruption or damage to our pipelines, storage and gathering systems, the facilities of our customers or other interconnected pipelines and facilities, it could materially adversely affect our business, financial condition and results of operations.

Our operations, our customers’ operations and other interconnected pipelines and facilities are subject to many operational hazards, including (i) damage to pipelines, facilities, equipment, environmental controls and surrounding properties, including damage resulting from landslide and ground movement slippage; (ii) leaks, migrations or losses of natural gas and other hydrocarbons, water, brine, other fluids and hazardous chemicals that we handle in our treating and other operations; (iii) inadvertent damage from third parties, including from construction, farm and utility equipment; (iv) uncontrolled releases of natural gas and other hydrocarbons; (v) ruptures, fires and explosions; (vi) product and waste spills and unauthorized discharges of products, wastes and other pollutants; (vii) pipeline freeze-offs or production curtailments due to cold weather; (viii) operator error; (ix) aging infrastructure, mechanical or other performance problems; (x) damages to and loss of availability of interconnecting third-party pipelines, railroads and terminals; (xi) disruption or failure of information technology systems and network infrastructure; (xii) floods; (xiii) severe weather; (xiv) lightning and (xv) terrorism.

These risks could result in loss of human life, personal injuries, significant property damage, environmental pollution, impairment of our operations, regulatory investigations and penalties and substantial financial losses. The location of certain segments of our systems in or near populated areas, including residential areas, commercial business centers and industrial sites, could increase the damages resulting from these risks. In spite of any precautions taken, the occurrence of an event such as those described above that is not fully covered by insurance could materially adversely affect our business, financial condition and results of operations. In addition, these risks could materially impact or completely prevent our customers from performing their respective obligations under our commercial agreements, which, in turn, could materially adversely affect our business, financial condition and results of operations.

Failure to successfully complete or realize the projected benefits of acquisitions, divestitures, and other strategic transactions may adversely affect our future results.

From time to time, the Company may undertake strategic transactions. The success of acquisitions and other transactions, depends in part on the Company’s ability to successfully complete and realize the anticipated benefits of such transactions. The Company’s ability to meet our objectives with respect to acquisitions, divestitures, and other strategic transactions may depend, as applicable, on our ability to identify suitable acquisition targets, buyers or counterparties; negotiate favorable financial and other contractual terms; obtain all necessary regulatory approvals on the terms expected; and complete those transactions. In addition, difficulties in integrating businesses and/or employees may result in the failure to realize anticipated results, benefits, and synergies in the expected timeframes, in operational challenges, and in the diversion of management’s attention from ongoing business concerns, as well as in unforeseen expenses associated with the transactions, which may have an adverse impact on our financial condition and results of operations.

Expansion projects that are expected to be accretive, may nevertheless reduce our cash from operations and could materially adversely affect our business, financial condition and results of operations.

We regularly review our portfolio of businesses and pursue growth through expansion that we expect to be accretive to our distributive cash flow, improve our business profile, and add to the backlog of future growth opportunities. However, even if we complete expansion projects that we believe will be accretive, these expansion projects may nevertheless reduce our cash from operations and could materially adversely affect our business, financial condition and results of operations. Any expansion project involves potential risks, including, among other things: (i) service interruptions or increased downtime associated with our projects; (ii) a decrease in our liquidity; (iii) an inability to complete expansion projects on schedule or within the budgeted cost; (iv) the assumption of unknown liabilities when undertaking expansion projects for which we are not indemnified or for which our indemnity is inadequate; (v) the diversion of our management’s attention from other business concerns; (vi) mistaken assumptions about the overall costs of equity or debt, demand for our services, supply volumes, reserves, revenues and costs, synergies and potential growth; (vii) an inability to secure adequate customer commitments to use the expanded or acquired systems or facilities; (viii) an inability to successfully integrate the businesses we build; (ix) an inability to receive cash flows from a newly built asset until it is operational; and (x) unforeseen difficulties operating in new service areas or new geographic areas.

We have entered into joint ventures, and may in the future enter into additional or modify existing joint ventures, which might restrict our operational and corporate flexibility. In addition, these joint ventures are subject to most of the same operational risks to which we are subject.

We conduct a meaningful portion of our operations through joint ventures with third parties, including through our interests in Vector, Millennium and NEXUS, and we may enter into additional joint venture arrangements in the future. Generally, we do not operate the assets owned by these joint ventures and our control over their operations is limited by the applicable governing provisions of such joint venture agreements. In certain cases, we could have limited ability to influence or control certain day-to-day activities affecting the operations, the amount of capital expenditures that we may be required to fund with respect to these operations and the amount of cash we will receive from the joint venture. We also could be dependent on our joint venture partners to fund their required share of capital expenditures and be exposed to third party credit risk through our contractual arrangements with our joint venture partners. Additionally, we may be subject to restrictions or limitations on our ability to sell or transfer our interests in the jointly owned assets, and we may be required to offer business opportunities to the joint venture, or rights of participation to other joint venture partners or participants in certain areas of mutual interest.

In addition, our joint venture arrangements may involve risks not otherwise present when operating assets directly. We may incur liabilities as a result of an action taken by our joint venture partners and may be required to devote significant management time to the requirements of and matters relating to the joint ventures. Our joint venture partners may be in a position to take actions contrary to our instructions or requests, or contrary to our policies or objectives. Any disputes between us and our joint venture partners may result in delays, litigation or operational impasses.

The risks described above or the failure to continue our joint ventures or to resolve disagreements with our joint venture partners could adversely affect our ability to conduct business that is the subject of a joint venture, which could in turn materially adversely affect our business, financial condition and results of operations. In addition, these joint ventures are subject to most of the same operational risks to which we are subject and the impact of any of these operational risks on our joint ventures’ respective business, financial condition or results of operations could in turn materially adversely affect our business, financial condition and results of operations.

We do not own the majority of the land on which our assets are located, which could disrupt our current and future operations.

We do not own the majority of the land on which our assets are located, and we are therefore subject to the possibility of more onerous terms and increased costs or delays to retain necessary land use rights required to conduct our operations if we do not have valid rights-of-way, if such rights-of-way lapse or terminate or if our facilities are not properly located within the boundaries of such rights-of-way. If we were to be unsuccessful in negotiating or renegotiating rights-of-way, we might have to institute condemnation proceedings on our FERC-regulated assets or relocate our facilities for non-regulated assets. Restrictions on our ability to use our rights-of-way, through our inability to renew right-of-way contracts or otherwise, or a relocation could materially adversely affect our business, financial condition and results of operations. Additionally, even when we own an interest in the land on which our assets are located, agreements with correlative rights owners may require us to relocate

pipelines and facilities, shut in storage facilities to facilitate the development of the correlative rights owners’ estate or pay the correlative rights owners the lost value of their estate if they are not willing to accommodate development.

We face and will continue to face opposition to the development or operation of our assets from various groups.

We face and will continue to face opposition to the development or operation of our assets from environmental groups, landowners, local and national groups, activists and other advocates. Such opposition could take many forms, including organized protests, attempts to block, vandalize or sabotage our development or operations, intervention in regulatory or administrative proceedings involving our assets directly or indirectly, lawsuits, legislation or other actions designed to prevent, disrupt or delay the development or operation of our assets and business. Any such event that delays or interrupts the revenues generated, or expected to be generated, by our operations, or which causes us to make significant expenditures not covered by insurance, could materially adversely affect our business, financial condition and results of operations.

The expansion of our existing assets and construction of new assets is subject to economic, market, regulatory, environmental, political, and legal risks, which could materially adversely affect our business, financial condition and results of operations. If we are unable to complete expansion projects, our future growth may be limited.

We may be unable to complete successful, accretive expansion projects for many reasons, including economic and market risks such as an inability to identify attractive expansion projects; an inability to successfully integrate the infrastructure we build; an inability to raise financing for expansion projects on economically acceptable terms; and because some of our competitors may be better positioned to compete for certain expansion projects that we believe would be accretive. In addition, the construction of additions or modifications to our existing energy infrastructure assets, and the construction of other new energy infrastructure assets, involve numerous regulatory, environmental, political and legal uncertainties beyond our control. The development and construction of pipeline and gathering infrastructure and storage facilities expose us to construction risks such as: (i) the failure of third parties to meet their contractual requirements; (ii) environmental hazards; (iii) adverse weather conditions; (iv) the performance of third-party contractors; and (v) the lack of available skilled labor, equipment and materials.

Certain of our internal growth projects may require regulatory approval from U.S. federal and state authorities and Canadian authorities prior to construction. The approval process for storage and transportation projects located in the Northeast has become increasingly challenging, as such projects in this region tend to face heightened opposition and permitting scrutiny. In addition, FERC has periodically considered to, and could in the future revisit, its policy governing the issuance of interstate natural gas pipeline authorizations, in part to address concerns about climate change. It is not clear at this time whether FERC will modify its policy governing the issuance of certificates and, if so, what those modifications will be. Policy and regulatory changes relating to the implementation of NEPA may increase scrutiny of environmental impacts associated with our projects. Authorizations required for our projects under existing or future agency policies may not be granted or, if granted, such authorization may include burdensome or expensive conditions.

Failure to retain and attract key executives and other skilled professional and technical employees could materially adversely affect our business, financial condition and results of operations.

Our business is dependent on our ability to attract, retain and motivate employees. We rely on our management team, which has significant experience in the midstream industry, to manage our day-to-day affairs and establish and execute our strategic and operational plans. The loss of any of our key executives or the failure to fill new positions created by expansion, turnover or retirement could adversely affect our ability to implement our business strategy. In addition, our operations require engineers, operational and field technicians and other highly skilled employees. The competition for talent has become increasingly intense, and we may experience increased employee turnover, increased wage inflation or an impediment of our ability to execute certain key strategic initiatives due to a tightening labor market and skilled labor shortages. Failure to successfully attract and retain an appropriately qualified workforce could materially adversely affect our business, financial condition and results of operations.

The lack of diversification of our assets and geographic locations could materially adversely affect our business, financial condition and results of operations.

We rely primarily on revenues generated from our pipeline, storage and gathering systems, substantially all of which are located in the Midwestern U.S., Eastern Canada, Northeastern U.S. and Gulf Coast regions. Due to our lack of diversification in assets and geographic location, an adverse development in these businesses or our areas of operations, including adverse developments due to catastrophic events, weather, regulatory action, state and local political activities, availability of equipment

and personnel, local prices, producer liquidity and decreases in demand for natural gas could have a more significant impact on our business, financial condition and results of operations than if we maintained more diverse assets and locations.

Liquidity, Credit and Financial Risks

We may not have access to additional financing sources on favorable terms, or at all, which could materially adversely affect our business, financial condition and results of operations, and independent third parties determine our credit ratings outside of our control.

The cost of capital for our business depends, in part, on our credit ratings; general market conditions; the market’s perception of our business risk and growth potential; our current debt levels; interest rate changes; our current and expected future earnings; our cash flow; and the market price per share of our common stock. In part based on our current credit ratings, potential lenders may be unwilling or unable to provide us with financing that is attractive to us, may increase collateral requirements or may charge us prohibitively high fees in order to obtain financing. Consequently, our ability to access the credit markets in order to attract financing on reasonable terms may be adversely affected. Depending on market conditions at the relevant time, we may have to rely more heavily on additional equity financings or on less efficient forms of debt financing that require a larger portion of our cash flow from operations, thereby reducing funds available for our operations, future business opportunities and other purposes. We may not have access to such equity or debt capital on favorable terms, at the desired times, or at all. In addition, declines in our credit ratings may influence our suppliers’ and customers’ willingness to transact with us, increase the cost of our debt capital, and we may be required to make prepayments or provide security to satisfy credit concerns.

Fluctuations in energy prices could materially adversely affect our business, financial condition and results of operations.

Fluctuations in energy prices can greatly affect the development of new natural gas reserves. Drilling and production activity generally decreases as commodity prices decrease. In general terms, the prices of natural gas, oil and other hydrocarbon products fluctuate in response to changes in supply and demand, market uncertainty and a variety of additional factors that are beyond our control. These factors include (i) worldwide political and economic conditions; (ii) weather conditions and seasonal trends; (iii) the levels of domestic production and consumer demand; (iv) the availability of imported and exported natural gas, LNG and other commodities; (v) the ability to export LNG; (vi) the availability of transportation systems with adequate capacity; (vii) the volatility and uncertainty of regional pricing differentials and premiums; (viii) the price and availability of alternative fuels; (ix) the effect of energy conservation measures; and (x) governmental regulation and taxation.

Prices of natural gas have been historically volatile, and we expect this volatility to continue. Consequently, even if new natural gas reserves are discovered in areas served by our assets, producers may choose not to develop those reserves. Sustained declines in natural gas prices could have a negative impact on exploration, development and production activity and could lead to a material decrease in such activity, which could result in reduced throughput on our systems and materially adversely affect our business, financial condition and results of operations. See also "Operational Risks—Any significant decrease in production or in demand of natural gas in our asset footprint could materially adversely affect our business, financial condition and results of operations."

We are exposed to our customers’ credit risk and our credit risk management and contractual terms may be inadequate to protect against such risk.

We are subject to the risk of loss resulting from nonpayment or nonperformance by our customers in the ordinary course of our business. While some of our customers are rated investment grade, others have sub-investment grade ratings. These customers are otherwise considered creditworthy or are required to make prepayments or provide security to satisfy credit concerns. However, our credit procedures and policies may not be adequate to fully eliminate customer credit risk. If we fail to adequately assess the creditworthiness of existing or future customers, the unanticipated deterioration in their creditworthiness and any resulting increase in nonpayment or nonperformance by them could materially adversely affect our business, financial condition and results of operations.

Our existing and future level of debt may limit our flexibility to obtain additional financing and to pursue other business opportunities.

As of December 31, 2025, we had outstanding approximately $3.35 billion of senior notes and no borrowings under our Revolving Credit Facility. Our existing and future level of debt could have important consequences to us, including the

following: (i) our ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be impaired, or such financing may not be available on favorable terms; (ii) the funds that we have available for operations and payment of dividends to shareholders will be reduced by that portion of our cash flow required to make principal and interest payments on outstanding debt; and (iii) our debt level could make us more vulnerable to competitive pressures than competitors with less debt or to a downturn in our business or the economy generally.

Our ability to service our debt will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control. In addition, our ability to service debt under our Revolving Credit Facility and other debt facilities with floating rate terms will depend on market interest rates, since we anticipate that the interest rates applicable to our borrowings will fluctuate with movements in interest rate markets. If our operating results are not sufficient to service our current or future indebtedness, we will be forced to take actions such as reducing dividends, reducing or delaying our business activities, acquisitions, investments or capital expenditures, selling assets, restructuring or refinancing our debt, or seeking additional equity capital. We may not be able to effect any of these actions on satisfactory terms, or at all.

Increases in interest rates could increase our interest expense and may adversely affect our cash flows, our ability to service our indebtedness and our ability to pay dividends to our shareholders.

Borrowings under our Revolving Credit Facility have, and we may in the future enter into debt instruments with, variable interest rates. We are unable to predict changes in interest rates which are affected by factors beyond our control. Increases in interest rates on variable rate debt would increase our interest expense unless we make arrangements to hedge the risk of rising interest rates. In addition, interest rates under our Revolving Credit Facility will, and interest rates under future debt instruments we enter into may, increase depending on our leverage ratio levels or, under certain circumstances, our public debt ratings. These increased costs could reduce our profitability, reduce our credit availability, limit our ability to pursue growth opportunities, impair our ability to meet our debt obligations, increase the cost of financing, place us at a competitive disadvantage and materially adversely affect our business, financial condition, cash flows and results of operations. An increase in interest rates also could limit our ability to refinance existing debt upon maturity or cause us to pay higher rates upon refinancing.

Restrictions under our existing or any future credit facilities, indentures and senior notes could adversely affect our business, financial condition, results of operations and ability to pay dividends to our shareholders.

Our existing Revolving Credit Facility and the indenture governing our senior notes limit our ability to, and any future credit facility or indenture we may enter into might limit our ability to, among other things: (i) incur additional indebtedness or guarantee other indebtedness; (ii) grant liens or make certain negative pledges; (iii) make certain dividends or investments; (iv) engage in transactions with affiliates; (v) transfer, sell or otherwise dispose of all or substantially all of our assets; or (vi) enter into a merger, consolidate, liquidate, wind up or dissolve. Upon the occurrence of the Investment Grade Event, certain negative covenants in our existing senior notes were terminated and the negative covenants in our Revolving Credit Facility were automatically amended to create additional flexibility for DT Midstream and its subsidiaries such that (i) the indebtedness negative covenant remains applicable solely to restrict DT Midstream’s restricted subsidiaries, (ii) the former restriction related to prepayments of junior indebtedness has fallen away, and (iii) the remaining negative covenants, including those related to liens, mergers, consolidations, liquidations or dissolutions, sales, transfers or other dispositions, investments, acquisitions, loans or advances, dividends and distributions or repurchases of capital stock, entering into agreements that limit the ability of the restricted subsidiaries to make distributions to DT Midstream, and transactions with affiliates, were amended automatically to provide for flexibility customary for investment grade companies.

Furthermore, our existing Revolving Credit Facility contains, or any future credit facility or indenture we may enter into may also contain, covenants requiring us to maintain certain financial ratios and tests. If we violate any of the restrictions, covenants, ratios or tests in the applicable credit facility or indentures, the lenders thereunder will be able to accelerate the maturity of all borrowings under the credit facility and demand repayment of amounts outstanding, and our lenders’ commitment to make further loans to us may terminate. We might not have, or be able to obtain, sufficient funds to make these accelerated payments. Any subsequent amendment to the terms of our Revolving Credit Facility, replacement of our Revolving Credit Facility or any new indebtedness could have similar or greater restrictions. For more information, see the section entitled "Management’s Discussion and Analysis of Financial Condition and Results of Operations—Capital Resources and Liquidity".

Inflation and cost increases may impact our sales margins and profitability.

Inflationary pressure could adversely impact our profitability. Inflation in the United States has recently declined; however, we are unable to predict changes in inflation which is affected by factors beyond our control, including the recent imposition of tariffs by the U.S. and certain of its trading partners. Rising inflation in the future could have an adverse impact on our operating and capital costs, which have historically increased with the market during inflationary periods and may continue to increase as a result of inflationary impacts on product costs, labor rates, and domestic transportation. We may not be able to fully offset these inflation increases by raising prices for our services, which could materially adversely affect our business, financial condition and results of operations.

If our intangible assets, goodwill, property, plant and/or equipment become impaired, we may be required to record a charge to earnings.

We annually review the carrying value of goodwill associated with business combinations we have made for impairment. Our intangible assets, goodwill, property, plant, and equipment are also reviewed whenever events or circumstances indicate that the carrying value of these assets may not be recoverable. Factors that may be considered for purposes of this analysis include a decline in stock price and market capitalization, slower industry growth rates, changes in cost of capital or material changes with customers or contracts that could negatively impact future cash flows. We cannot predict the timing, strength or duration of such changes or any subsequent recovery. If the carrying value of any of our intangible assets, goodwill, property, plant, and/or equipment is determined to be not recoverable, we may take a non-cash impairment charge, which could materially adversely affect our business, financial condition and results of operations.

Regulatory Risks

The adoption of legislation and introduction of regulations relating to hydraulic fracturing and the enactment of new or increased severance taxes and impact fees on natural gas production could cause our current and potential customers to reduce the number of future wells or curtail production of existing wells. If reductions are significant for those or other reasons, the reductions could materially adversely affect our business, financial condition and results of operations.

The U.S. Congress has from time to time considered the adoption of legislation to provide for U.S. federal regulation of hydraulic fracturing, while a growing number of states, including some of those in which we operate, have adopted, and other states are considering adopting, regulations that could impose more stringent disclosure and/or well construction requirements on hydraulic fracturing operations. Some states, such as Pennsylvania, have imposed fees on the drilling of new unconventional oil and gas wells. Also, certain local governments have adopted, and additional local governments may further adopt, ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular. Further, several U.S. federal governmental agencies, including the EPA and the U.S. Department of Energy, have conducted or are conducting reviews and studies on the environmental aspects of hydraulic fracturing. These completed, ongoing or proposed studies on the environmental aspects of hydraulic fracturing, depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing or other regulatory mechanisms aimed at imposing more stringent requirements on hydraulic fracturing.

Certain state and U.S. federal regulatory agencies have focused on, or are focused on a possible connection between hydraulic fracturing-related activities and the increased occurrence of seismic activity. In a few instances, operators of injection disposal wells in the vicinity of seismic events have been ordered to reduce injection volumes or suspend operations. These developments could result in additional regulation and restrictions on the use of injection disposal wells and hydraulic fracturing. The adoption of new laws, regulations or ordinances at the U.S. federal, state or local levels imposing more stringent restrictions on hydraulic fracturing could make it more difficult for our customers to complete natural gas wells, increase customers’ costs of compliance and doing business, and otherwise adversely affect the hydraulic fracturing services they perform, which could negatively impact demand for our services.

Risks related to climate change could materially adversely affect our business, financial condition, results of operations, cash flow, access to and cost of capital or insurance, reputation, and business strategies.

Our business is subject to physical risks and transition risks related to climate change. Physical risks may arise from more frequent or severe weather events such as floods, landslides, storms, rising water levels, and changes in established weather patterns that cause damage to our assets or to portions of the country’s natural gas infrastructure upon which we or our customers rely. Physical risks from climate change may reduce our ability to operate reliably, safely, and economically and may

cause significant insured or uninsured losses that affect our cash flows. In addition to physical risks, our business is subject to transition risks arising from efforts to address climate change through legislation and policies and through market preferences that disfavor fossil fuels and related businesses. State and federal governments, as well as foreign governments and international governing bodies such as the United Nations, continue to develop laws, policies, and goals to reduce carbon emissions, foster a lower-carbon economy, and transition away from fossil fuels. While these efforts are diverse and subject to change, they may impose additional compliance costs and may reduce market interest in our business. Changing customer behaviors may lead to less demand for our services, less favorable pricing for our services, inefficient utilization of our assets, and diminished reputation. Our ability to comply with laws and avoid or mitigate physical and transition risks related to climate change may be limited, insufficient, or dependent on technological developments (such as lower-emission equipment) that we do not control or that require substantial additional investments and increase our cost of doing business. If we are unable to implement business strategies that address the physical risks of climate change and that meet the changing expectations of regulators or investors concerning climate change, we may experience a material adverse effect on our business.

Our operations are subject to environmental laws and regulations that may expose us to significant costs and liabilities, and changes in these laws and regulations could materially adversely affect our business, financial condition and results of operations.

Our natural gas transmission, storage and gathering activities are subject to stringent and complex U.S. federal, state and local environmental laws and regulations relating to air quality, water quality, waste management, wildlife conservation, natural resources and worker health and safety. As with the industry generally, compliance with current and anticipated environmental laws and regulations increases our overall cost of conducting business, including our capital costs to construct, maintain and upgrade pipelines and other facilities, or may even cause us not to pursue a project. For instance, we may be required to obtain and maintain permits and other approvals issued by various U.S. federal, state and local governmental authorities; monitor for, limit or prevent releases of materials from our operations in accordance with these permits and approvals; install pollution control equipment or replace aging pipelines and other facilities; limit or prohibit construction activities in sensitive areas such as wetlands, wilderness or areas that provide habitat for endangered or threatened species; incur potentially substantial new obligations or liabilities for any pollution or contamination that may result from our operations; and apply health and safety criteria addressing worker protections. Failure to comply with environmental laws and regulations, or the permits issued under them, may result in the assessment of administrative, civil and criminal penalties, the imposition of investigatory, remedial or corrective action obligations or the incurrence of capital expenditures, the occurrence of delays in the permitting or performance or expansion of projects, the issuance of injunctions limiting or preventing some or all of our operations in a particular area, and private party claims for personal injuries or property damage.

Moreover, environmental laws, regulations and enforcement policies tend to become more stringent over time. New, modified or stricter environmental laws, regulations or enforcement policies, including climate change laws and regulations restricting emissions of GHGs, could be implemented that significantly increase our compliance costs, pollution mitigation costs, or the cost of any necessary remediation of environmental contamination. For example, in April 2020 the U.S. District Court for the District of Montana issued a broad order vacating NWP 12, a general permit issued by the U.S. Army Corps of Engineers relied upon by industry for expedited permitting of oil and gas pipelines, for alleged failure to comply with consultation requirements under the ESA. While the U.S. Supreme Court ultimately stayed the vacatur of NWP 12, the District Court’s action temporarily caused uncertainty and disruption in the industry. A challenge to the 2021 reissuance of NWP 12 (re-issued on a five-year schedule) is pending in the federal district court in Washington, D.C. after the case was transferred from federal court in Montana. The NWP 12 reissuance was among the agency actions listed for review in accordance with the January 20, 2021 Executive Order ("Protecting Public Health and the Environment and Restoring Science to Tackle the Climate Crisis"); and, in 2022 the U.S. Army Corps of Engineers sought public comment on the potential to revise NWP 12 in response to objections to the use of NWP 12 related, primarily, to environmental justice, public participation, and climate change. The prior presidential administration did not take final action to modify the current version of NWP 12 before its expiration and reissuance in March 2026. On June 18, 2025, the U.S. Army Corps of Engineers published a proposal to reissue multiple nationwide permits, including NWP 12, but a final rule reissuing NWP 12 has not yet been published. Any disruption in our ability to obtain coverage under NWP 12 or other general permits may result in increased costs and project delays if we are forced to seek individual permits from the U.S. Army Corps of Engineers. Our compliance with changing legal requirements could result in our incurring significant additional expenses and operating restrictions with respect to our operations, which may not be fully recoverable from customers and, thus, could materially adversely affect our business, financial condition and results of operations.

Our customers may similarly incur increased costs or restrictions that may limit or decrease those customers’ operations and have an indirect material adverse effect on our business, financial condition and results of operations. During the course of the prior presidential administration, litigation over the “pause” ensued. While lease sales ultimately continued, they have been scaled back and are subject to challenge by environmental groups. If key provisions of the Waste Prevention Rule or similar restrictions become effective, they could lead to increased costs for producers and increased need for pipeline capacity as operators would be required to have a plan to reduce venting and flaring as a predicate to approval of production of federal minerals. While the prior presidential administration had placed a temporary pause on the authorization of new LNG terminals, impacting LNG projects in various stages of planning and review, the current presidential administration has lifted this pause and the Department of Energy has been directed to review LNG export applications as expeditiously as possible. Moreover, a number of state and regional legal initiatives, including climate change laws, have emerged in recent years that seek to reduce GHGs emissions and the EPA, based on its findings that emissions of GHGs cause, or contribute to, air pollution which may reasonably be anticipated to endanger public health or welfare, has adopted regulations under existing provisions of the U.S. federal Clean Air Act that, among other things, restrict emissions of GHGs and require the monitoring and reporting of GHG emissions from specified onshore and offshore production sources and onshore treating sources in the U.S. on an annual basis. In addition, some communities and cities have banned new natural gas hook-ups or are expected to enact similar electrification measures in response to climate change concerns. Any new U.S. federal laws restricting emissions of GHGs, such as a carbon tax, from customer operations, or that limit the growth of pipelines and LNG exports from the U.S., could delay or curtail their activities and, in turn, adversely affect our business, financial condition and results of operations.

There is inherent risk of the incurrence of environmental costs and liabilities in our business due to our handling of natural gas and hazardous substances, and historical industry operations and waste management and disposal practices. For example, an accidental release from one of our facilities could subject us to substantial liabilities arising from environmental cleanup and restoration costs, claims made by neighboring landowners and other third parties for personal injury and property damage, or governmental claims for natural resource damages or imposing fines or penalties for related violations of environmental laws, permits or regulations. In addition, strict, joint and several liabilities may be imposed under certain environmental laws that govern the investigation and remediation of soil and groundwater contamination, which could cause us to become liable for the contamination caused by others, such as prior operators of our facilities, or for the consequences of our own actions that were in compliance with all applicable laws at the time those actions were taken, such as the historic disposal by us of hazardous substances or wastes at third party sites where contamination is subsequently discovered. Private parties, including the owners of the properties through which our assets pass and facilities where our wastes are taken for reclamation or disposal, may also have the right to pursue legal actions against us to enforce compliance, as well as to seek damages for non-compliance, with environmental laws and regulations or for personal injury or property damage that may result from environmental and other impacts of our operations. We may not be able to recover some or any of these costs through insurance or increased revenues, which could materially adversely affect our business, financial condition and results of operations. For more information, see the section entitled "Items 1. and 2. Business and Properties—Regulatory Environment—Environmental and Occupational Health and Safety Regulations".

Our natural gas transportation and storage operations are subject to extensive regulation by FERC and state regulatory authorities, and changes in FERC or state regulation could materially adversely affect our business, financial condition and results of operations.

Our business operations are subject to extensive regulation by FERC, and state regulatory authorities. Generally, FERC’s authority extends to rates and charges for interstate pipelines and storage facilities as well as intrastate pipelines and storage facilities providing service in interstate commerce; terms and conditions of services and service contracts with customers; certification and construction of new interstate pipelines and storage services and facilities and expansion of such facilities; abandonment of interstate pipelines and storage services and facilities; maintenance of accounts and records; relationships between pipelines and certain affiliates; depreciation and amortization rates and policies; facility replacements and upgrades; and acquisitions and dispositions of interstate pipelines and storage facilities.

While FERC may exercise jurisdiction over the rates and terms of service for certain of the services provided by our intrastate pipelines providing service in interstate commerce, such assets are not subject to FERC’s certification and construction authority. Prior to commencing construction of new or expanded existing interstate pipelines and storage facilities, an interstate pipeline must obtain a certificate from FERC authorizing the construction, either by filing a new certificate application or filing to amend its existing certificate. In reviewing certificate applications or amendments, FERC applies its Certificate Policy Statement, which FERC is considering revising, in part to address the consideration of climate change when

acting on such applications. A revised Certificate Policy Statement could result in more stringent review of future projects within FERC’s jurisdiction.

FERC regulations also extend to the terms and conditions set forth in agreements for our transportation and storage services executed between interstate transportation and storage service providers and their customers. These service agreements are required to conform, in all material respects, with the forms of service agreements set forth in the interstate company's FERC-approved tariff. Non-conforming agreements must be filed with, and accepted by, FERC. In the event that FERC finds that an agreement is materially non-conforming, in whole or in part, it could reject or require us to seek modification of the agreement, or alternatively require us to modify our tariff so that the non-conforming provisions are generally available to all customers or similarly-situated customers. Birdsboro, Guardian, Midwestern, Millennium, NEXUS, Vector, Viking and the Washington 10 Storage Complex provide interstate services in accordance with their FERC-approved tariffs.

Compliance with these requirements can be time-consuming, costly and burdensome and FERC action in any of these areas could adversely affect our ability to compete for business, construct new facilities, offer new services or recover the full cost of operating our pipelines. This regulatory oversight can result in longer lead times to develop and complete any future project than competitors that are not subject to FERC’s regulations. Furthermore, should FERC or state regulatory authorities find that we have failed to comply with all applicable FERC or state-administered statutes, rules, regulations and orders, or the terms of our tariffs on file with FERC, we could be subject to administrative and criminal remedies and substantial civil penalties and fines. We cannot give any assurance regarding the likely future regulations under which we will operate our assets or the effect such regulation could have on our business, financial condition and results of operations.

Any changes to the policies of FERC or state regulatory authorities regarding the natural gas industry may have an impact on us, including FERC’s approach as it considers policies affecting the establishment and modification of interstate pipeline rates and terms and conditions of service, policies that may affect rights of access to natural gas transmission capacity and policies that govern FERC's authorization of new or expanded pipeline and storage infrastructure. In addition, future U.S. federal, state or local legislation or regulations under which we will operate our assets could materially adversely affect our business, financial condition and results of operations. Guardian, Midwestern and Viking are subject to rate regulation and accounting requirements of FERC. The regulated operations of each of these subsidiaries have rates that are (i) established by independent, third-party regulators, (ii) set at levels that will recover our costs when considering the demand and competition for our services and (iii) charged to and collectible from our customers. Accordingly, we follow the accounting for regulated operations as defined in ASC 980 for these pipelines, which results in differences in the application of GAAP between our regulated and non-regulated businesses. Under ASC 980, our regulated operations are required to record regulatory assets and liabilities for certain transactions that would have been treated as revenue or expense in non-regulated businesses. Future regulatory changes could result in changes in the amounts of regulatory assets and liabilities or the discontinuance of this accounting treatment for regulatory assets and liabilities and may require the write-off of the portion of any regulatory asset or liability that is no longer probable of recovery through regulated rates. Actions by regulatory authorities could also have an effect on the amounts we charge to and collect from our customers. Any changes to ASC 980 or on the determination of whether Guardian, Midwestern or Viking will continue to meet the criteria of ASC 980 could materially adversely affect our business, financial condition and results of operations.

We are exposed to costs associated with lost and unaccounted-for volumes.

A certain amount of natural gas is inherently lost and unaccounted-for in connection with meter differences and movement across a pipeline or storage system, and under our contractual arrangements with our customers we are entitled to retain a specified volume of natural gas in order to compensate us for such volumes as well as the natural gas used to operate our compressor stations, which we refer to as "fuel usage." The level of fuel usage and lost and unaccounted-for volumes on our transportation, storage and gathering systems may exceed the natural gas volumes retained from our customers as compensation for such volumes. In addition, our gathering systems have contracts that provide for specified levels of fuel retainage. As such, we need to purchase natural gas in the market to make up for any of these differences, which exposes us to natural gas price risk. Future exposure to the volatility of natural gas prices as a result of gas imbalances on our transportation, storage and gathering systems could materially adversely affect our business, financial condition and results of operations.

A change in the jurisdictional characterization of our gathering assets may result in increased regulation by FERC, which could cause our revenues to decline and operating expenses to increase and could materially adversely affect our business, financial condition and results of operations.

We believe that our non-jurisdictional natural gas gathering facilities, including those which we refer to as "gathering lateral pipelines," meet the traditional tests FERC has used to establish a pipeline’s status as an exempt gatherer not subject to regulation as a FERC-jurisdictional natural gas company under the NGA, although FERC has not made a formal determination with respect to the jurisdictional status of those facilities. FERC regulation nonetheless affects our businesses and the markets for products derived from our gathering businesses. FERC’s policies and practices across the range of its gas regulatory activities, including, for example, its policies on certification of new interstate natural gas facilities, open access transportation, rate making, terms and conditions of service, capacity release and market center promotion, indirectly affect intrastate markets. We have no assurance that FERC will continue its current policies as it considers matters such as certification of new interstate natural gas facilities, pipeline rates and rules and policies that may affect rights of access to natural gas transportation capacity. In addition, the distinction between FERC-regulated transmission services and federally unregulated gathering services is regularly the subject of substantial litigation in the industry. Consequently, the classification and regulation of some of our gathering operations could change based on future determinations by FERC, the courts or the U.S. Congress. If our gathering operations become subject to FERC jurisdiction, the result may adversely affect the rates we are able to charge and the services we currently provide and may include the potential for a termination of certain gathering agreements, which could materially adversely affect our business, financial condition and results of operations.

State and local legislative and regulatory initiatives relating to gas operations could adversely affect our services and customers’ production and therefore, materially adversely affect our business, financial condition and results of operations.

State and municipal regulations also impact our business. Common purchaser statutes generally require gatherers to gather or provide services without undue discrimination as to source of supply or producer; as a result, these statutes restrict our right to decide whose production we gather or transport. U.S. federal law leaves any economic regulation of natural gas gathering to the states. Some of the states in which we currently operate have adopted complaint-based regulation of gathering activities, which allows gas producers and shippers to file complaints with state regulators in an effort to resolve access and rate grievances. Other state and municipal regulations may not directly regulate our gathering business but may nonetheless affect the availability of natural gas for purchase, treating and sale, including state regulation of production rates and maximum daily production allowable from gas wells. While our gathering lines currently are subject to limited state regulation, there is a risk that state laws will be changed, which may give producers a stronger basis to challenge the rates, terms and conditions of their gathering lines.

Certain states in which we operate have adopted or are considering adopting measures that could impose new or more stringent requirements on gas exploration and production activities. For example, the potential for adverse impacts to our business is present where state or local governments have enacted ordinances directly regulating production rates and maximum daily production allowable from gas wells, and private individuals have sponsored and may in the future sponsor citizen initiatives to limit hydraulic fracturing, increase mandatory setbacks of oil and gas operations from occupied structures and achieve more restrictive state or local control over such activities.

In the event state or local restrictions or prohibitions are adopted in our areas of operations, our customers may incur significant compliance costs or may experience delays or curtailment in the pursuit of their exploration, development or production activities, and possibly be limited or precluded in the drilling of certain wells altogether. Any adverse impact on our customers’ activities would have a corresponding negative impact on our throughput volumes. In addition, while the general focus of debate is on upstream development activities, certain proposals may, if adopted, directly impact our ability to competitively locate, construct, maintain and operate our own assets. Accordingly, such restrictions or prohibitions could materially adversely affect our business, financial condition and results of operations.

Changes in tax laws or regulations may have a material adverse effect on our business, cash flow, financial condition or results of operations.

New income, sales, use or other tax laws, statutes, rules, regulations or ordinances could be enacted at any time, which could adversely affect our business operations and financial performance. Further, existing tax laws, statutes, rules, regulations or ordinances could be interpreted, changed, modified or applied adversely to us. It cannot be predicted whether or when tax laws, statutes, rules, regulations or ordinances may be enacted, issued, or amended. Changes to existing tax laws or the enactment of future reform legislation could have a material impact on our financial condition, results of operations and ability to pay dividends to our shareholders.

Some of our operations cross the U.S./Canada border and are subject to cross-border regulation and potential tariffs which may have a material impact on our business, cash flow, financial condition or results of operations.

Our cross-border activities subject us to regulatory matters, including import and export licenses, tariffs, Canadian and U.S. customs and tax issues, and toxic substance certifications. Such regulations include the "Short Supply Controls" of the Export Administration Act, the United States-Mexico-Canada Agreement and the Toxic Substances Control Act. Violations of these licensing, tariff and tax-reporting requirements could result in the imposition of significant administrative, civil and criminal penalties, which could, in turn, materially adversely affect our business, financial condition and results of operations.

For example, tariffs or other restrictions placed on the import and export of natural gas with Canada and any related counter-measures that are taken by Canada could have an adverse effect on our financial condition or results of operations. Even in the absence of further tariffs, the related uncertainty could have a material adverse effect on our business, liquidity, financial condition or results of operations.

Pipeline Safety and Maintenance Risks

We may incur significant costs and liabilities to maintain our pipeline integrity management program and related testing, pipeline repair, and preventative or remedial measures, as well as other operational and maintenance requirements and assessments.

The U.S. Department of Transportation, through PHMSA, has adopted regulations requiring pipeline operators to comply with a number of operational and maintenance requirements, including to continuously survey pipeline assets, conduct leakage surveys, and repair certain conditions. Additionally, these requirements require operators to develop integrity management programs for transportation pipelines located where a leak or rupture could do the most harm in an HCA. The regulations require operators to: (i) perform ongoing assessments of pipeline integrity; (ii) identify and characterize applicable threats to pipeline segments that could impact an HCA; (iii) improve data collection, integration and analysis; (iv) repair and remediate the pipeline as necessary; and (v) implement preventive and mitigating actions. PHMSA regulations also require assessment and repairs outside of HCAs in MCAs.

Additionally, while states are preempted by U.S. federal law from regulating pipeline safety for interstate lines, most are certified by PHMSA to assume responsibility for enforcing U.S. federal intrastate pipeline regulations and inspection of intrastate pipelines. In practice, states can adopt stricter standards for intrastate pipelines than those imposed by PHMSA for interstate pipelines, and states vary considerably in their authority and capacity to address pipeline safety. Accordingly, midstream operators of pipeline and associated storage facilities may be required to make operational changes or modifications at their facilities to meet standards beyond current federal requirements, where such changes or modifications may result in additional capital costs, possible operational delays and potentially significant increased costs of operations.

Failure to comply with PHMSA or state pipeline safety regulations could result in a number of consequences which may have an adverse effect on our operations. We incur significant costs in complying with existing PHMSA and state pipeline safety regulations, but we do not believe such costs of compliance will materially adversely affect our business, financial condition and results of operations. We may incur significant costs associated with repair, remediation, preventive and mitigation measures associated with our integrity management programs and may be required to comply with new safety regulations and make additional maintenance capital expenditures in the future for similar regulatory compliance initiatives that are not reflected in our forecasted maintenance capital expenditures.

Certain portions of our pipelines, storage and gathering infrastructure are aging, which could materially adversely affect our business, financial condition and results of operations.

Certain portions of our systems, particularly our DTM Interstate Transportation, Northern Michigan, and storage assets, have been in operation for many years, with some portions being more than 50 years old. In some cases, certain portions may have been in service for many years prior to our purchase of the relevant systems or have been operated by third parties not under our control and consequently, there may be historical occurrences or latent issues regarding our pipeline systems that management may be unaware of and that could materially adversely affect our business, financial condition and results of operations. Certain portions of our pipeline systems are located in or near areas determined to be HCAs, which are areas where a leak or rupture could have the most significant adverse consequences. The age and condition of these systems could result in increased maintenance or repair expenditures, and any downtime associated with increased maintenance and repair activities could materially reduce our revenue. If, due to their age, certain pipeline sections were to become unexpectedly unavailable for

current or future volumes of natural gas because of repairs, maintenance, damage, spills or leaks, or any other reason, it could materially adversely affect our business, financial condition and results of operation.

Our insurance policies do not cover all losses, costs or liabilities that we may experience, and there is no assurance that we will be able to purchase cost effective insurance in the future.

We are not fully insured against all risks inherent in our business, including environmental accidents that might occur as well as cyberattacks. In addition, we do not maintain business interruption insurance of the types and in amounts necessary to cover all possible risks of loss, like project delays caused by governmental action or inaction. The occurrence of any operating risk events not fully covered by insurance could materially adversely affect our business, financial condition and results of operations.

As a result of market conditions, premiums and deductibles for certain of our insurance policies may substantially increase. In some instances, certain insurance could become unavailable or available only for reduced coverage amounts. If significant changes in the number or financial solvency of insurance underwriters for the energy industry occur, we may be unable to obtain and maintain adequate insurance at a reasonable cost. The unavailability of full insurance coverage or our inability to maintain or obtain insurance of the type and amount we desire at reasonable rates to cover events in which we suffer significant losses could materially adversely affect our business, financial condition and results of operations.

A terrorist attack or armed conflict event, or the threat of them, could harm our business.

The U.S. Department of Homeland Security (DHS) has continued to issue public warnings that indicated that pipelines and other energy assets might be specific targets of terrorist organizations. Potential targets include our pipelines, storage and gathering systems and may affect our ability to operate or control our assets or utilize our customer service systems. Destructive forms of protests and opposition by extremists, and other disruptions, including acts of sabotage or eco-terrorism, against oil and natural gas development and production or midstream treating or transportation activities could potentially result in damage or injury to persons, property or the environment or lead to extended interruptions of our or our customers’ operations. The threat or occurrence of any of these events could cause a substantial decrease in revenues; increased costs or other financial losses; exposure or loss of customer information; damage to our reputation or business relationships; increased regulation or litigation; disruption of our operations; and inaccurate information reported from our operations.

Other Business Risks

Customers’, legislators’ or regulators’ perceptions of us are affected by many factors, including environmental and safety concerns, pipeline reliability, protection of customer information, media coverage, and public sentiment. Customers’, legislators’ or regulators’ negative opinion of us could materially adversely affect our business, financial condition and results of operations.

Many factors can affect customers’, legislators’ or regulators’ perceptions of us, including: safety concerns due to potential natural disasters, the rupture of pipelines, or other causes and our ability to promptly respond to such issues; our ability to safeguard sensitive customer information; media coverage, including the proliferation of social media, which may include factual and nonfactual information that could damage the public sentiment and perception of our company and the midstream industry.

If customers, legislators or regulators have or develop a negative opinion of us and our services, or of fossil fuels as an energy source generally, this could hinder our ability to achieve favorable legislative or regulatory outcomes. Negative opinions could also result in sales volumes reductions, increased use of alternative forms of energy, reduced access to capital markets, or greater challenges in developing or operating our assets.

In addition, in recent years, attention has been given to corporate activities related to ESG matters in public discourse and the investment community. Investor advocacy groups, proxy advisory firms, certain institutional investors and lenders, investment funds and other influential investors and rating agencies have been focused on climate change, societal expectations on companies to address climate change, investor and societal expectations regarding voluntary ESG disclosures, and consumer demand for alternative forms of energy. Attention to climate change and environmental conservation could result in increased costs, reduced access to insurance at reasonable rates, reduced demand for our services, reduced profits, negative impacts on our stock price, reduced access to capital markets, and governmental investigations and private litigation against us or our customers. To the extent that societal pressures or political or other factors are involved, it is possible that a liability could be imposed without regard to our causation of or contribution to the asserted damage, or to other mitigating factors. While we may

participate in various voluntary frameworks and certification programs to improve the ESG profile of our operations and products, we cannot guarantee that such participation or certification will have the intended results on our ESG profile.

A number of advocacy groups have campaigned for governmental and private action to promote change at public companies related to ESG matters, including demands for action related to climate change, promoting the use of alternative forms of energy, and encouraging the divestment of companies in the fossil fuel industry. Some organizations that provide corporate governance and related information to investors have ratings systems for evaluating companies on their approach to ESG matters. Unfavorable ESG ratings could lead to negative investor and bank financing sentiment toward us and our industry and to the diversion of investment to other companies or industries, which could adversely affect the demand for our services, our stock price, our access to and costs of capital and, in turn, materially adversely affect our business, financial condition and results of operations.

We published our fourth annual Corporate Sustainability Report in 2025, which detailed how we seek to manage our operations responsibly and ethically, as well as strategies and goals associated with reducing our environmental impact. The Corporate Sustainability Report included our policies and practices on a variety of social and ethical matters, including, but not limited to, corporate governance, environmental compliance, employee health and safety practices, human capital management and workforce inclusion and diversity. We believe providing disclosure on these topics in our Corporate Sustainability Report increases our transparency to our stakeholders and complements the disclosures regarding our contributions to sustainable development in this Form 10-K. It is possible that stakeholders may not be satisfied with our ESG practices or the speed of their adoption. We could also incur additional costs and require additional resources to monitor, report and comply with various ESG practices. Also, our failure, or perceived failure, to meet the standards set forth in the Corporate Sustainability Report could negatively impact our reputation, employee retention, and the willingness of our customers and suppliers to do business with us. Any of these consequences could materially adversely affect our business, financial condition and results of operations.

We are subject to cybersecurity and data privacy laws, regulations, litigation and directives relating to our processing of personal data.

Our business involves collection, uses and other processing of personal data of our employees, contractors, suppliers and service providers. Governmental standards and commonly accepted frameworks for the protection of computer-based systems and technology from cyber threats and attacks have been adopted. On November 7, 2024, the DHS's Transportation Security Administration issued a notice of proposed rulemaking seeking to impose cybersecurity requirements on certain pipeline facilities entitled "Enhancing Surface Cyber Risk Management." The Transportation Security Administration has not provided a timeframe for issuance of a final rule and the rulemaking has been classified as a long-term action in DHS’s regulatory agenda. New data privacy and cybersecurity laws add additional complexity, requirements, restrictions and potential legal risk, and compliance programs may require additional investment in resources, and could impact strategies and availability of previously useful data. Any failure by us or one of our technology service providers to comply with such laws and regulations could result in reputational harm, penalties, regulatory scrutiny, liabilities, legal claims, and/or mandated changes in our business practices.

We will report any confirmed cybersecurity incidents to the Cybersecurity and Infrastructure Security Agency. As legislation continues to develop and cyber incidents continue to evolve, we may be required to expend significant additional resources to respond to cyberattacks, to continue to modify or enhance our protective measures, or to detect, assess, investigate and remediate any security vulnerabilities and report any cyber incidents to the applicable regulatory authorities. Any failure to maintain compliance with these evolving government regulations may result in enforcement actions which may then result in significant time, support and cost and have a material adverse effect on our business and operations.

A cyberattack or threat could harm our business.

We have become increasingly dependent on digital information technologies, including computer-based systems, infrastructure, and cloud applications, to conduct almost all aspects of our business. These include operating our pipeline, storage and gathering assets, recording commercial transactions, communicating with employees supporting our operations and our customers or other business partners, and reporting financial information. We also collect and store sensitive data in the ordinary course of our business, including personally identifiable information of our employees, as well as our proprietary business information and that of our vendors, customers and other business partners. We depend on both our own systems, networks and technology, as well as the systems, networks and technology of our vendors, customers, and other business partners, including our joint venture partners. The secure processing, maintenance and transmission of this information is critical to our operations.

Our increasing reliance on digital technologies puts us at risk for system failures, disruptions, incidents, data breaches and cyberattacks, which could significantly impair our ability to conduct our business. Cyberattacks are becoming more sophisticated and include, but are not limited to, ransomware, credential stuffing, spear phishing, social engineering, AI-powered attacks, and other attempts to gain unauthorized access to data for purposes of extortion or malfeasance. The methodologies used by attackers change frequently and may not be recognized until such attack is underway. In April 2022, the cybersecurity authorities of the United States, Australia, Canada, New Zealand, and the United Kingdom issued a joint cybersecurity advisory warning of the increased risks of Russian state-sponsored cyberattacks following the international response to Russia’s invasion of Ukraine. We expect to continue to be targeted by cyberattacks as a critical infrastructure company.

We may not be able to anticipate, detect or prevent all cyberattacks, and the threat or occurrence of a cyberattack affecting our information technology systems or the information technology systems of our counterparties, depending on the extent or duration of the event, could materially adversely affect us, including by leading to corruption, misappropriation or loss of our proprietary and sensitive data, delays (which could be significant) in the performance of services for our customers, difficulty in completing and settling transactions, challenges in maintaining our books and records, communication interruptions, environmental damage, regulatory scrutiny, personal injury or death, property damage and other operational disruptions, as well as damage to our reputation, financial condition and cash flows and potential legal claims and liabilities.

Treated gas produced by Clean Fuels Gathering may not qualify for federal income tax credits for clean fuel production as had been projected.

The economic proceeds from Clean Fuels Gathering are expected to come from sales of treated gas, carbon offsets, and federal income tax credits. Clean Fuels Gathering produced gas may not qualify for federal income tax credits. The income tax credit value could be lower and/or uncertain compared to economic expectations. A change in tax law could lower or eliminate Clean Fuels Gathering from qualifying or receiving federal income tax credits, which would impact its projected economic return.

Risks Related to the Separation

We agreed to numerous restrictions to preserve the non-recognition treatment of the Distribution, and we could have an indemnification obligation to DTE Energy in accordance with the terms of the Tax Matters Agreement if the Distribution were determined not to qualify for non-recognition treatment for U.S. federal tax purposes.

We agreed in the Tax Matters Agreement to covenants and indemnification obligations that address compliance with Section 355(e) of the Internal Revenue Code. These covenants and indemnification obligations may limit our ability to pursue strategic transactions or engage in new businesses that may otherwise maximize the value of our Company and might discourage or delay a strategic transaction that our shareholders may consider favorable. Additionally, if it were determined that the Distribution did not qualify as a distribution to which Section 355(a), Section 355(c) and Section 361 of the Internal Revenue Code apply, we could, under certain circumstances, be required to indemnify DTE Energy for the resulting taxes and related expenses.

The Separation may expose us to potential liabilities arising out of state and U.S. federal fraudulent conveyance laws and legal dividend requirements.

If DTE Energy files for bankruptcy or is otherwise determined or deemed to be insolvent under U.S. federal bankruptcy laws, a court could deem the Separation or certain internal restructuring transactions undertaken by DTE Energy in connection with the Separation to be a fraudulent conveyance or transfer. Fraudulent conveyances or transfers are defined to include transfers made or obligations incurred with the actual intent to hinder, delay or defraud current or future creditors, or transfers made or obligations incurred for less than a reasonably equivalent value when the debtor was insolvent, or that rendered the debtor insolvent, inadequately capitalized or unable to pay its debts as they become due. A court could void the transactions or impose substantial liabilities upon us, which could materially adversely affect our business, financial condition and results of operations. Among other things, a court could require our shareholders to return to DTE Energy some or all of the shares of our common stock issued in the Separation or require us to fund liabilities of other companies involved in the restructuring transactions for the benefit of creditors. The distribution of our common stock is also subject to review under state corporate distribution statutes. Although DTE Energy intended to make a lawful distribution of our common stock, we cannot assure you that a court will not later determine that some or all of the Distribution to DTE Energy shareholders was unlawful.

Item 1B. Unresolved Staff Comments

None.

Item 1C. Cybersecurity

Cybersecurity Risk Management and Strategy

To identify, assess and manage the material risks of cybersecurity threats to our business, operations and control environments, we have made investments in our technology and have implemented policies, programs and controls, with a focus on cybersecurity incident prevention and mitigation. Our cybersecurity program is integrated into our risk management process as a distinct risk category of the Company’s enterprise risk management framework and evaluated using the same methodologies applied to other enterprise risks. The program operates under Board-level oversight through the Audit Committee and is managed by a dedicated cybersecurity team that is responsible for leading enterprise-wide cybersecurity strategy, policy, standards, architecture, and processes. The program is aligned with industry standards and best practices, such as the National Institute of Standards and Technology Cybersecurity Framework, and is responsive to emerging threat vectors, including AI-powered attacks. As part of our cybersecurity process, we engage external experts and consultants to assess our cybersecurity program and compliance with applicable practices and standards.

The Company mitigates risks from cybersecurity incidents using a multifaceted approach which includes but is not limited to: establishing information security policies, implementing information protection processes and technologies, assessing cybersecurity risk, implementing cybersecurity training, monitoring our information technology systems, and collaborating with public and private organizations on best practices. This approach includes processes to oversee and identify risks associated with third‑party service providers, including risk‑based due diligence, contractual security obligations, and ongoing vendor oversight. The Company is currently in material compliance with relevant information privacy and cybersecurity governmental standards with which it is required to comply.

The Company has not experienced a material cybersecurity incident during the year ended December 31, 2025. For more information on how material cybersecurity incidents may impact our business, see Part I, Item 1A. "Risk Factors—Risks Relating to Our Business—Other Business Risks—A cyberattack or threat could harm our business" of this Form 10-K.

Cybersecurity Governance

Our Chief Security Officer is responsible for overseeing the Company’s cybersecurity program and has over 20 years of relevant experience in cybersecurity and information security. The cybersecurity team monitors day-to-day risks using the approach described above, and material near-term and long-term risks are communicated with senior management and the Board of Directors. The Company's Board of Directors is engaged in overseeing and reviewing the Company’s strategic direction and objectives, taking into account, among other considerations, the Company’s risk profile and exposures. While the Board of Directors retains oversight over policy and strategy related to cybersecurity, it has delegated the responsibility for the oversight of the Company’s cybersecurity program to the Audit Committee. The Audit Committee is responsible for reviewing and discussing the Company’s policies regarding risk assessment and risk management, major accounting risk exposures and the implementation and effectiveness of risk management protocols with respect to information technology security and cybersecurity risks, as well as reviewing material breaches and attacks, as applicable. Management provides the Audit Committee with regular quarterly updates on cybersecurity risks and mitigations. Material cybersecurity matters would be escalated to the Audit Committee outside the regular quarterly meetings, if any were to occur.

Item 3. Legal Proceedings

For information on legal proceedings and matters related to DT Midstream, see Note 12, "Commitments and Contingencies" to the Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

Item 4. Mine Safety Disclosures

Our sand mining facility in Louisiana is subject to regulation by the Federal Mine Safety and Health Administration under the Federal Mine Safety and Health Act of 1977. Information concerning mine safety violations or other regulatory matters required by section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act and Item 104 of Regulation S-K is filed as Exhibit 95.1 to this Annual Report on Form 10-K.

PART II

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

DT Midstream's common stock is listed under the ticker symbol "DTM" on the NYSE, which is the principal market for such stock. As of December 31, 2025, there were 101,673,925 shares of DT Midstream common stock issued and outstanding. These shares were held by a total of 34,655 shareholders of record.

We expect to pay regular cash dividends to DT Midstream common stockholders in the future. Any payment of future dividends is subject to approval by the Board of Directors and may depend on our future earnings, cash flows, capital requirements, financial condition, and the effect a dividend payment would have on our compliance with relevant financial covenants. Over the long-term, we expect to grow our dividend with cash flow growth. For information on DT Midstream's historical dividends and dividend restrictions, see Note 8, "Earnings Per Share and Dividends " and Note 10, "Debt" to the Consolidated Financial Statements under Part II, Item 8 of this Form 10-K. There were no sales of unregistered equity securities during the past three years.

Securities Authorized for Issuance Under Equity Compensation Plans

DT Midstream's Long-Term Incentive Plan was approved by shareholders as an equity compensation plan that provides for the annual awarding of stock-based compensation to all employees. See Note 13, "Stock-Based Compensation and Defined Contribution Plans" to the Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

See the following table for information as of December 31, 2025:


	Number of Securities to be Issued Upon Exercise of Outstanding Options, Warrants, and Rights (a)	Weighted-Average Exercise Price of Outstanding Options, Warrants, and Rights		Number of Securities Remaining Available for Future Issuance Under Equity Compensation Plans
DT Midstream, Inc. Long-Term Incentive Plan	1,014,059	$	—	8,155,787

_____________________________________

(a)Includes 319,266 Restricted Stock Units and 694,793 Performance Share Awards.

COMPARISON OF CUMULATIVE TOTAL RETURN

Total Return to DT Midstream Investors

The graph below shows the cumulative total shareholder return assuming the investment of $100, including the reinvestment of dividends, on July 1, 2021 in our common stock, the Standard & Poor’s 500 Index, or S&P 500 Index, and the Alerian Midstream Energy Index. We believe the Alerian Midstream Energy Index is meaningful because it is an independent, objective view of the performance of similarly-sized midstream energy companies.


	Base Period	Indexed Returns
Company/Index	July 1, 2021	December 31, 2021	December 31, 2022	December 31, 2023	December 31, 2024	December 31, 2025
DT Midstream	100.00	117.18	141.56	148.29	280.16	347.74
S&P 500 Index	100.00	111.07	90.94	114.82	143.52	169.17
Alerian Midstream Energy Index	100.00	97.63	118.56	136.19	196.66	206.34

Item 6. [Reserved]

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

This discussion contains forward-looking statements that involve risks and uncertainties. The forward-looking statements are not historical facts, but rather are based on current expectations, estimates, assumptions and projections about the midstream industry and our business and financial results. Our actual results could differ materially from the results contemplated by these forward-looking statements due to a number of factors, including those discussed in the sections entitled "Forward-Looking Statements" and "Risk Factors."

OVERVIEW

Our Business

We are an owner, operator, and developer of an integrated portfolio of natural gas midstream assets. We provide multiple, integrated natural gas services to customers through our Pipeline segment, which includes interstate pipelines, intrastate pipelines, storage systems, and gathering lateral pipelines, and through our Gathering segment. We also own joint venture interests in equity method investees which own and operate interstate pipelines that connect to our wholly owned assets.

Our Strategy

See discussion of our strategy under Part I, Items 1. and 2. "Business and Properties—Our Strategy" of this Form 10-K.

RESULTS OF OPERATIONS

Management’s Discussion and Analysis of Financial Condition and Results of Operations includes financial information prepared in accordance with GAAP. The following sections discuss the operating performance and future outlook of our segments. Segment information includes intercompany revenues and expenses, as well as other income and deductions that are eliminated in the Consolidated Financial Statements.

For purposes of the following discussion, any increases or decreases refer to the comparison of the year ended December 31, 2025 to the year ended December 31, 2024, or the year ended December 31, 2024 to the year ended December 31, 2023, as applicable. The following table summarizes our consolidated financial results:



		Year Ended December 31,

		2025		2024		2023
	(millions, except per share amounts)
Operating revenues		$	1,243	$	981	$	922
Net Income Attributable to DT Midstream		441		354		384
Diluted Earnings per Common Share		$	4.30	$	3.60	$	3.94



		Year Ended December 31,
		2025		2024		2023

	(millions)
Net Income Attributable to DT Midstream
Pipeline		$	370	$	276	$	278
Gathering		71		78		106
Total		$	441	$	354	$	384

Pipeline

The Pipeline segment consists of our interstate pipelines, intrastate pipelines, storage systems, gathering lateral pipelines and compression and surface facilities. This segment also includes our equity method investments. The Midwest Pipeline Acquisition assets and results of operations after the December 31, 2024 acquisition date are presented in our Pipeline segment. Pipeline results and outlook are discussed below:



		Year Ended December 31,
		2025		2024		2023
	(millions)
Operating revenues		$	687	$	443	$	377
Operation and maintenance		134		68		55
Depreciation and amortization		111		74		69
Taxes other than income		27		22		15
Asset (gains) losses and impairments, net		—		—		(4)
Operating Income		415		279		242
Interest expense		51		47		55
Interest income		(1)		(4)		(1)
Earnings from equity method investees		(138)		(162)		(177)
Loss from financing activities		—		3		—
Other income		(1)		(1)		—
Income tax expense		121		107		75
Net Income		383		289		290
Less: Net Income Attributable to Noncontrolling Interests		13		13		12
Net Income Attributable to DT Midstream		$	370	$	276	$	278

Operating revenues increased $244 million for the year ended December 31, 2025 primarily due to activity from the interstate pipelines acquired in the Midwest Pipeline Acquisition of $212 million, new LEAP contracts of $31 million and higher long-term storage revenue at Washington 10 Storage Complex of $9 million, partially offset by lower Bluestone volumes of $7 million. Operating revenues increased $66 million for the year ended December 31, 2024 primarily due to new LEAP long-term firm service revenue contracts of $55 million, higher long-term contracting rates and volumes at the Washington 10 Storage Complex of $9 million and higher volumes at Stonewall of $9 million, partially offset by lower volumes at Bluestone of $8 million.

Operation and maintenance expense increased $66 million for the year ended December 31, 2025 primarily due to effects from the Midwest Pipeline Acquisition, including increases in direct operations of $25 million, increases in corporate overhead and the acquisition's impact on corporate overhead segment mix of $36 million, as well as production-related operating expenses from the LEAP expansion of $9 million. Operation and maintenance expense increased $13 million for the year ended December 31, 2024 primarily due to higher production-related operating expenses from the expansion of LEAP and acquisition related costs for the Midwest Pipeline Acquisition.

Depreciation and amortization expense increased $37 million for the year ended December 31, 2025 primarily due to the Midwest Pipeline Acquisition. Depreciation and amortization expense increased $5 million for the year ended December 31, 2024 primarily due to new LEAP assets placed into service.

Taxes other than income increased $5 million for the year ended December 31, 2025 primarily due to an increase in property taxes due to the Midwest Pipeline Acquisition. Taxes other than income increased $7 million for the year ended December 31, 2024 primarily due to LEAP assets placed into service.

Asset (gains) losses and impairments, net decreased $4 million for the year ended December 31, 2024 due to a one-time gain realized from an insurance settlement that occurred in the prior year.

Interest expense increased $4 million for the year ended December 31, 2025 primarily due to higher interest expense from the 2034 Notes issued in the three months ended December 31, 2024, partially offset by lower interest expense related to the Term Loan Facility and lower interest expense related to the Bridge Facility. Interest expense decreased $8 million for the year ended December 31, 2024 primarily due to lower outstanding borrowings under the Revolving Credit Facility and the repayment of the Term Loan Facility during 2024, partially offset by lower capitalized interest driven by lower construction in progress during 2024 and higher interest related to the Bridge Facility and 2034 Notes.

Earnings from equity method investees decreased $24 million for the year ended December 31, 2025 primarily due to higher interest expense from senior unsecured notes issued by Millennium in the three months ended September 30, 2024 of $16 million and higher property taxes, lower short-term revenue and higher maintenance expenses at Millennium of $7 million. Earnings from equity method investees decreased $15 million for the year ended December 31, 2024 primarily due to higher interest expense from new senior unsecured notes at Millennium and a full year of interest expense from senior unsecured notes at NEXUS.

Loss from financing activities increased $3 million for the year ended December 31, 2024 primarily due to the repayment of our remaining Term Loan Facility that occurred during the year.

Income tax expense increased $14 million for the year ended December 31, 2025 due to an increase in income before income taxes, partially offset by deferred tax remeasurements for changes in state tax rates and apportionment factors related to the Midwest Pipeline Acquisition in 2024. Income tax expense increased $32 million for the year ended December 31, 2024 primarily due to higher income before income taxes and deferred tax remeasurement adjustments for changes in state tax rates and apportionment factors due to the Midwest Pipeline Acquisition and enacted state legislation.

Pipeline Outlook

We believe our long-term agreements with customers and the location and connectivity of our pipeline assets position the business for future growth. We will continue to pursue economically attractive expansion opportunities that leverage our current asset footprint and strategic relationships. These growth opportunities include expansion opportunities on the DTM Interstate Transportation assets, further expansion at LEAP and Stonewall, new contracts at the Washington 10 Storage Complex and additional growth related to our equity method investments.

Gathering

The Gathering segment includes gathering systems, related treatment plants and compression and surface facilities. The Clean Fuels Gathering assets and results of operations after the July 1, 2024 acquisition date are presented in our Gathering segment. Gathering results and outlook are discussed below:



		Year Ended December 31,
		2025		2024		2023
	(millions)
Operating revenues		$	556	$	538	$	545
Operation and maintenance		195		176		190
Depreciation and amortization		147		135		113
Taxes other than income		15		17		13

Operating Income		199		210		229
Interest expense		110		106		95
Interest income		(1)		(3)		—
Loss from financing activities		—		2		—
Other income		(4)		(3)		(1)
Income tax expense		23		30		29
Net Income Attributable to DT Midstream		$	71	$	78	$	106

Operating revenues increased $18 million for the year ended December 31, 2025 primarily due to new Blue Union Gathering contracts of $18 million, higher Blue Union Gathering volumes of $15 million, higher volumes and deficiency fees due to expansion at Ohio Utica Gathering of $11 million and higher volumes at Tioga Gathering of $5 million, partially offset by lower volumes at Susquehanna Gathering of $22 million and Appalachia Gathering of $9 million. Operating revenues decreased $7 million for the year ended December 31, 2024 primarily due to lower volumes and recovery of production-related operating expenses on Blue Union Gathering of $19 million and lower Susquehanna Gathering volumes of $16 million, partially offset by a full year of operations at Ohio Utica Gathering of $18 million and higher Appalachia Gathering volumes of $12 million.

Operation and maintenance expense increased $19 million for the year ended December 31, 2025 primarily due to new assets placed into service and higher production-related operating expenses at Blue Union Gathering of $20 million and a reduction in environmental contingent liabilities of $9 million at Appalachia Gathering in 2024, partially offset by the Midwest Pipeline Acquisition’s impact on corporate overhead segment mix of $10 million. Operation and maintenance expense decreased $14 million for the year ended December 31, 2024 primarily due to lower planned maintenance and production-related operating expenses on Blue Union Gathering of $18 million, partially offset by a full year of operations at Ohio Utica Gathering.

Depreciation and amortization expense increased $12 million for the year ended December 31, 2025 primarily due to assets placed in service at Blue Union Gathering, Ohio Utica Gathering and Clean Fuels Gathering. Depreciation and amortization expense increased $22 million for the year ended December 31, 2024 primarily due to assets placed into service at Ohio Utica Gathering, Blue Union Gathering, and Appalachia Gathering.

Taxes other than income increased $4 million for the year ended December 31, 2024 primarily due to assets placed into service at Blue Union Gathering.

Interest expense increased $4 million for the year ended December 31, 2025 primarily due to higher interest expense from the 2034 Notes issued in the three months ended December 31, 2024, partially offset by lower interest expense related to the Term Loan Facility and lower interest expense related to the Bridge Facility. Interest expense increased $11 million for the year ended December 31, 2024 primarily due to lower capitalized interest driven by lower construction in progress during 2024 and higher interest related to the Bridge Facility and 2034 Notes issued in 2024. This increase was partially offset by lower outstanding borrowings under the Revolving Credit Facility and the repayment of the Term Loan Facility during 2024.

Loss from financing activities increased $2 million for the year ended December 31, 2024 primarily due to the repayment of our remaining Term Loan Facility that occurred during the year.

Income tax expense decreased $7 million for the year ended December 31, 2025 due to decreases in income before income taxes and deferred tax remeasurements for changes in state tax rates and apportionment factors related to the Midwest Pipeline Acquisition in 2024. Income tax expense increased $1 million for the year ended December 31, 2024 primarily due to deferred tax remeasurement adjustments for changes in state tax rates and apportionment factors due to the Midwest Pipeline Acquisition and enacted state legislation, partially offset by lower income before income taxes.

Gathering Outlook

We believe our long-term agreements with producers and the quality of the natural gas reserves in the Marcellus/Utica and Haynesville formations position the business for future growth. We will continue to pursue economically attractive expansion opportunities that leverage our current asset footprint and strategic relationships. These growth opportunities include further expansions at Blue Union Gathering, Appalachia Gathering, Ohio Utica Gathering, and Tioga Gathering.

ENVIRONMENTAL MATTERS

We are subject to U.S. federal, state, and local laws and environmental regulations, including laws and regulations relating to pipeline safety, climate change and GHG emissions. Additional compliance costs may result as the effects of various substances on the environment and human health are studied and laws and regulations are developed and implemented. Actual costs to comply with such laws and regulations could vary substantially from our expectations. Pending or future legislation or regulation could have a material impact on our operations and financial position. Potential impacts include unplanned expenditures for environmental equipment, such as pollution control equipment, financing costs related to additional capital expenditures, and the replacement costs of aging pipelines and other facilities.

For further discussion of environmental matters, see Part I, Items 1. and 2. "Business and Properties — Regulatory Environment — Environmental and Occupational Health and Safety Regulations" and Note 12, "Commitments and Contingencies" to the Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

CLIMATE CHANGE

We believe we have an opportunity to address climate change and have made strategically aligned environmental investment decisions a priority. Our Board of Directors includes a committee focused on environmental, social and governance initiatives, and our strategy will focus on targeted growth from carbon-reducing technologies associated with our current platforms. We have announced our intent to employ carbon-reducing technologies as part of our goal of being leading environmental stewards in the midstream industry, and we are executing on a plan to achieve net zero carbon emissions by 2050. We established our baseline Scope 1 carbon emissions in 2021 and are targeting a 30% reduction from this baseline by 2030.

In 2024, we completed the Clean Fuels Acquisition and advanced our carbon capture and sequestration project in Louisiana through completion of the Class V test well. The carbon capture and sequestration Class VI permit application moved to formal technical review with the Louisiana Department of Conservation and Energy in July 2025, and we are awaiting the completion of that review.

In future years, we plan to continue to make progress on opportunities for energy transition advancements leveraging our existing assets, competencies and partnerships. These opportunities include the following:

•Our efforts to advance our Louisiana carbon capture project, as well as other potential carbon capture projects across our geographic regions; and

•Our Clean Fuels Gathering project to capture fugitive methane emissions.

Capital project investments have been contemplated in our forecasted capital expenditures discussed in the Capital Investments section below. DT Midstream published our fourth annual Corporate Sustainability Report in 2025. The information in our Corporate Sustainability Report is not incorporated by reference into this Form 10-K.

For discussion of various risks including transitional risks associated with climate change related laws and regulations, reputational risks of climate change, and the physical risks of climate change, see Part I, Item 1A. "Risk Factors—Risks Relating to Our Business—Regulatory Risks—Risks related to climate change could materially adversely affect our business, financial condition, results of operations, cash flow, access to and cost of capital or insurance, reputation, and business strategies." of this Form 10-K. For discussion of recent climate change related laws and regulations, see Part I, Items 1. and 2. "Business and Properties—Regulatory Environment—Environmental and Occupational Health and Safety Regulations—Climate Change" of this Form 10-K.

CAPITAL RESOURCES AND LIQUIDITY

Cash Requirements

Our principal liquidity requirements are to finance our operations, fund capital expenditures, satisfy our indebtedness obligations, and pay approved dividends. We believe we will have sufficient internal and external capital resources to fund anticipated capital and operating requirements.



	Year Ended December 31,
		2025		2024		2023
	(millions)
Cash and Cash Equivalents at Beginning of Period		$	68	$	56	$	61
Net cash and cash equivalents from operating activities		867		763		798
Net cash and cash equivalents used for investing activities		(372)		(1,081)		(351)
Net cash and cash equivalents from (used for) financing activities		(509)		330		(452)
Net Increase (Decrease) in Cash and Cash Equivalents		(14)		12		(5)
Cash and Cash Equivalents at End of Period		$	54	$	68	$	56

For purposes of the following discussion, any increases or decreases refer to the comparison of the year ended December 31, 2025 to the year ended December 31, 2024 and the year ended December 31, 2024 to the year ended December 31, 2023.

Operating Activities

Cash flows from our operating activities can be impacted in the short term by the natural gas volumes gathered or transported through our systems under interruptible service revenue contracts, changing natural gas prices, seasonality, weather fluctuations, dividends received from equity method investees, working capital changes and the financial condition of our customers. Our preference to enter into firm service revenue contracts leads to more stable operating performance, revenues and cash flows and limits our exposure to natural gas price fluctuations.

Net cash and cash equivalents from operating activities increased $104 million for the year ended December 31, 2025 primarily due to an increase in operating income of $176 million after adjustment for non-cash items including depreciation and amortization expense, stock-based compensation, and amortization of operating lease right-of-use assets, and a decrease in cash paid for income taxes, net of refunds received, of $7 million, partially offset by a decrease of $44 million due to changes in net working capital, a decrease in dividends received from equity method investees of $23 million, higher interest

expense of $8 million and lower interest income of $5 million.

Net cash and cash equivalents from operating activities decreased $35 million for the year ended December 31, 2024 primarily due to a decrease in working capital changes and a decrease in dividends received from equity method investees, partially offset by a decrease in cash paid for income taxes and an increase in operating income after adjustment for non-cash items including depreciation and amortization expense, stock-based compensation, and amortization of operating lease right-of-use assets.

Investing Activities

Cash outflows associated with our investing activities are primarily the result of plant and equipment expenditures, acquisitions, and contributions to equity method investees. Cash inflows from our investing activities are generated from proceeds from sale or collection of Notes receivable, distributions received from equity method investees, and proceeds from asset sales.

On December 31, 2024, we closed on the Midwest Pipeline Acquisition of three FERC-regulated natural gas transmission pipelines for $1.2 billion. See Note 16, "Acquisition" to the Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

As a result of the sales of senior unsecured notes at our equity method investees, we received net distributions from Millennium of $416 million and NEXUS of $371 million during the years ended December 31, 2024 and 2023, respectively. See Note 1, "Description of the Business and Basis of Presentation" to the Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

Net cash and cash equivalents used for investing activities decreased $709 million for the year ended December 31, 2025 primarily due to cash consideration for the Midwest Pipeline Acquisition in 2024, partially offset by lower distributions received from equity method investees of $423 million, due to the Millennium distribution in 2024 of $416 million, and an increase in cash used for plant and equipment expenditures of $76 million.

Net cash and cash equivalents used for investing activities increased $730 million for the year ended December 31, 2024 primarily due to cash consideration for the Midwest Pipeline Acquisition, partially offset by a decrease in cash used for plant and equipment expenditures and higher distributions received from equity method investees, including those noted above.

Financing Activities

In December 2024, we issued the 2034 Notes in aggregate principal amount of $650 million, and we amended the Credit Agreement to, among other things, extend the Revolving Credit Facility maturity date to 2029. In November 2024, we amended our Credit Agreement to permit the Company to incur certain customary bridge loans, including the Bridge Facility. In September 2024, we repaid the remaining indebtedness under the Term Loan Facility of $399 million. See Note 10, "Debt" to the Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

In November 2024, we issued 4,168,750 common shares for net proceeds of approximately $406 million. DT Midstream paid cash dividends on common stock of $324 million, $280 million, and $263 million during the years ended December 31, 2025, 2024 and 2023, respectively. See Note 8, "Earnings Per Share and Dividends" to the Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

Net cash and cash equivalents used for financing activities of $509 million for the year ended December 31, 2025 decreased as compared to net cash and cash equivalents from financing activities of $330 million for the year ended December 31, 2024. The decrease was primarily due to proceeds received in 2024 from the issuance of common shares and from the issuance of the 2034 Notes, higher dividends paid on common stock of $44 million, higher payroll taxes paid related to vested stock-based compensation of $19 million and lower net borrowings under the Revolving Credit Facility of $135 million, partially offset by lower repayments on long-term debt of $399 million and higher contributions from noncontrolling interests of $7 million.

Net cash and cash equivalents from financing activities of $330 million for the year ended December 31, 2024 increased as compared to net cash and cash equivalents used for financing activities of $452 million for the year ended December 31, 2023. The increase was primarily due to proceeds received from the issuance of common shares, proceeds received from the issuance of the 2034 Notes, and lower net repayments of borrowings under the Revolving Credit Facility, partially offset by the repayment of the Term Loan Facility and higher dividends paid on common stock.

Outlook

We expect to continue executing on our natural gas-centric business strategy focused on disciplined capital deployment and supported by a flexible, well capitalized balance sheet. Other than the impact of the items discussed below on our debt and equity capitalization, we are not aware of any trends, other demands, commitments, events or uncertainties that are reasonably likely to materially impact our liquidity position.

Our working capital requirements will be primarily driven by changes in accounts receivable, accounts payable and taxes payable. We continue our efforts to identify opportunities to improve cash flows through working capital initiatives and obtaining long-term firm service revenue contracts from customers.

Our sources of liquidity include cash and cash equivalents generated from operating activities and available borrowings under our Revolving Credit Facility. As of December 31, 2025, we had $17 million of letters of credit outstanding and no borrowings outstanding under our Revolving Credit Facility. We had approximately $1 billion of available liquidity as of December 31, 2025, consisting of cash and cash equivalents and available borrowings under our Revolving Credit Facility.

We believe we will have sufficient operating flexibility, cash resources and funding sources to maintain adequate liquidity amounts and to meet future operating cash, capital expenditure and debt servicing requirements. However, our business is capital intensive, and an inability to access adequate capital could adversely impact future earnings and cash flows.

The Credit Agreement covering the Revolving Credit Facility includes financial covenants that DT Midstream must maintain. See Note 10, "Debt" to the Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

See also Note 12, "Commitments and Contingencies" to the Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

Credit Ratings

Credit ratings are intended to provide banks and capital market participants with a framework for comparing the credit quality of securities and are not a recommendation to buy, sell, or hold securities. Our credit ratings affect our cost of capital and other terms of financing, as well as our ability to access the credit and commercial paper markets. We believe that the current credit ratings provide sufficient access to capital markets. However, disruptions in the banking and capital markets not specifically related to us may affect our ability to access these funding sources or cause an increase in the return required by investors. During the year ended December 31, 2025, our credit rating was upgraded to investment grade by both Moody’s Ratings and S&P Global Ratings, and the Company remained investment grade with Fitch Ratings following its 2024 upgrade. As a result, DT Midstream has achieved investment grade rating with all three major credit rating agencies.

Contractual Obligations

The following table details our contractual obligations due by year as of December 31, 2025:


	2026		2027		2028		2029		2030 and Thereafter
	(millions)

Long-term debt:
Senior unsecured notes (a)	$	—	$	—	$	—	$	1,100	$	1,000
Senior unsecured notes (b)	—		—		—		—		1,250
Letters of credit	—		—		—		—		17
Interest expense (c)	153		153		153		130		316
Operating lease payments	18		17		7		3		8
Purchase commitments	16		15		13		13		33
Total Contractual Obligations	$	187	$	185	$	173	$	1,246	$	2,624

_____________________________

(a) Excludes $15 million of unamortized debt issuance costs.

(b) Excludes $1 million of unamortized debt discount and $10 million of unamortized debt issuance costs. These were formerly secured notes whose collateral was released on May 16, 2025 following an Investment Grade Event under the respective indentures. In the event of a Reversion Event (as defined in the respective indentures), the collateral is required to be reinstated in accordance with the respective indentures.

CAPITAL INVESTMENTS

Capital spending within our Company is primarily for ongoing maintenance and expansion of our existing assets, and if identified, attractive growth opportunities. We have been disciplined in our capital deployment and make growth investments that meet our criteria in terms of strategy, management skills, and identified risks and expected returns. All potential investments are analyzed for their rates of return and cash payback on a risk-adjusted basis. Our total capital investments were $431 million for the year ended December 31, 2025, inclusive of $5 million in contributions to equity method investees and $426 million in plant and equipment expenditures. These were primarily related to expansions on Blue Union Gathering, Appalachia Gathering, LEAP, Clean Fuels Gathering, Stonewall and Ohio Utica Gathering. We anticipate total capital investments, inclusive of contributions to equity method investees, for the year ended December 31, 2026 of approximately $490 million to $570 million.

OFF-BALANCE SHEET ARRANGEMENTS

We are party to off-balance sheet arrangements, which include our equity method investments. See Note 1, "Description of the Business and Basis of Presentation—Principles of Consolidation" to the Consolidated Financial Statements under Part II, Item 8 of this Form 10-K for further discussion of the nature, purpose and other details of such agreements.

Other off-balance sheet arrangements include the Vector line of credit and our surety bonds, which are discussed in Note 12, "Commitments and Contingencies" to the Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

INDEMNIFICATION OBLIGATIONS

We could have an indemnification obligation to DTE Energy pursuant to the Tax Matters Agreement and the Separation and Distribution Agreement. See Part I, Item 1A. "Risk Factors—Risks Related to the Separation—We agreed to numerous restrictions to preserve the non-recognition treatment of the Distribution, and we could have an indemnification obligation to DTE Energy in accordance with the terms of the Tax Matters Agreement if the Distribution were determined not to qualify for non-recognition treatment for U.S. federal tax purposes." of this Form 10-K for further details.

CRITICAL ACCOUNTING ESTIMATES

The preparation of our Consolidated Financial Statements in conformity with GAAP requires that management apply accounting policies and make estimates and assumptions that affect results of operations and the amounts of assets and liabilities reported in the Consolidated Financial Statements. Management believes that the areas described below require significant judgment in the application of the accounting policy or in making estimates and assumptions in matters that are inherently uncertain and that may change in subsequent periods. See additional discussion of our accounting policies in the Notes to Consolidated Financial Statements in Item 8 of this Form 10-K.

Purchase Accounting

In accordance with business combination accounting guidance, the assets acquired and liabilities assumed in an acquired business are measured at their estimated fair values at the acquisition date. As discussed in the Regulation paragraph below, the FERC-regulated pipelines acquired in the Midwest Pipeline Acquisition are accounted for under ASC 980, and thus, the fair value of assets acquired and liabilities assumed subject to these provisions approximate their regulated basis, and therefore no fair value adjustments have been reflected related to these amounts. Customer relationship intangible assets are not subject to rate making and cost recovery provisions, and therefore do include fair value adjustments. Determining the fair value of these items required management's judgment and involved the use of significant estimates and assumptions with respect to the timing and amounts of future cash inflows and outflows, discount rates, market prices and asset lives, among other items. During the year ended December 31, 2025, the Company recorded measurement period adjustments related to the Midwest Pipeline Acquisition as additional information became available and the purchase price allocation was finalized. For income tax purposes, the transaction is treated as a taxable deemed asset acquisition. Accordingly, the majority of deferred income tax assets and liabilities of the acquired entities are eliminated as the tax bases were increased to fair market value which equals net book value.

See Note 7, "Income Taxes" and Note 16, "Acquisition" to the Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

Goodwill

We have goodwill that resulted from business combinations. Annually as of October 1st, an impairment test for goodwill is performed which compares the fair value of each reporting unit to its carrying value including goodwill. If the carrying value including goodwill exceeds the fair value of a reporting unit, an impairment loss would be recognized. A goodwill impairment loss is measured as the amount by which a reporting unit’s carrying value exceeds its fair value, not to exceed the carrying amount of goodwill.

The October 1, 2025 fair values for the reporting units were calculated using an income approach. The estimated fair value in our annual goodwill impairment analysis utilizes significant assumptions that require judgment by management. One such significant assumption is the weighted average cost of capital (WACC) which is used to discount estimates of projected future results and cash flows to be generated by each reporting unit. The WACC is based on our cost of debt, which includes U.S. industrial bond spreads, and cost of equity, which consists of U.S. Treasury Rates plus an equity risk premium. Another significant assumption is the terminal value that utilizes an assumed long-term growth rate, which incorporates management’s judgment regarding sustainable long-term growth of the reporting units.

Our annual goodwill impairment analysis included a comparison of the estimated fair value of the Company as a whole to our market capitalization. Management also compared the implied market multiple of the estimated fair value of each reporting unit to midstream industry transaction multiples and considered other market indicators to support the appropriateness of the fair value estimates.

We performed our annual impairment test as of October 1, 2025 and determined that the estimated fair value of each reporting unit exceeded its carrying value, and no impairment existed. The results of the impairment test are as follows as of the October 1, 2025 valuation date:


Reporting Unit	Goodwill		Weighted Average Costs of Capital		Fair Value Reduction % (a)		Valuation Methodology (b)
	(millions)
Pipeline	$	361	6.8	%	73	%	DCF
Gathering	420		7.5	%	44	%	DCF
	$	781

_________________________________

(a) Percentage by which the estimated fair value of the reporting unit would need to decline to equal its carrying value including goodwill.

(b) Discounted cash flows (DCF) incorporated 2025 (fourth quarter) through 2030 projected cash flows plus a calculated terminal value. We calculated the terminal-year cash flows using an estimated long-term growth rate of 2.5% discounted at the WACC for each of the reporting units.

In between annual impairment tests, we monitor our estimates and assumptions regarding estimated future cash flows, including the impact of movements in market indicators, and will update the impairment analysis if a triggering event occurs. While we believe the estimates and assumptions in the fair value are reasonable, the actual results may differ from projections. To the extent projected results or cash flows are revised downward, the reporting unit may be required to write down all or a portion of its goodwill, which would adversely impact our earnings. If current expectations of future long-term growth are not met or market factors outside of our control change, such as U.S. Treasury Rates or a decline in midstream industry transaction multiples, this may lead to a goodwill impairment in the future. See Part II, Item 7A., "Quantitative and Qualitative Disclosures About Market Risk", in this Form 10-K for more information on our exposure to market risk.

Assessment of Long-Lived Assets for Impairment

We evaluate the carrying value of long-lived assets, excluding goodwill, when circumstances indicate that the carrying value of those assets may not be recoverable. Conditions that could have an adverse impact on the cash flows and fair value of the long-lived assets are a deteriorating business climate, condition of the asset, or plans to dispose of or abandon the asset before the end of its useful life, which could result from the loss of or reduction in volume from our customers. The review of long-lived assets for impairment requires significant assumptions about operating strategies and estimates of future cash flows, which require assessments of current and projected market conditions and anticipated customer revenues. An impairment evaluation is based on an undiscounted cash flow analysis at the lowest level for which independent cash flows of long-lived assets can be identified from other groups of assets and liabilities. Impairment may occur when the carrying value of the asset exceeds the future undiscounted cash flows. When the undiscounted cash flow analysis indicates a long-lived asset is not recoverable, the amount of the impairment loss is determined by measuring the excess of the long-lived asset over its fair value. An impairment would require us to reduce both the long-lived asset and current period earnings by the amount of the impairment, which would adversely impact our earnings. As part of our ongoing reviews of business operations and associated long-lived assets, we did not identify any indicators of impairment that existed during 2025.

Depreciation and Amortization of Long-Lived Assets

We compute depreciation and amortization based on estimated useful lives. These estimates are based on various factors including condition, manufacturing specifications, technological advances and historical data concerning useful lives of similar assets. Uncertainties that impact these estimates include economic conditions and supply and demand in the area. When assets are put into service, we make estimates with respect to useful lives and salvage values that we believe are reasonable. However, subsequent events could cause us to change our estimates, thus impacting the future calculation of depreciation and amortization. For our regulated assets, depreciation studies to assess the estimated useful lives of the asset are typically conducted as part of rate proceedings or tariff filings, which can result in changes in economic lives. Changes in economic lives, if applicable, are implemented prospectively as of the tariff approved effective date.

Assessment of Equity Method Investments for Impairment

We assess at each balance sheet date whether there is objective evidence that the equity method investment is impaired by completing a quantitative or qualitative analysis of factors impacting the investment. If there is objective evidence of impairment, we determine whether the decline below carrying value is other than temporary. If the decline is determined to be other than temporary, an impairment charge is recorded in earnings with an offsetting reduction to the carrying value of the investment. As part of our ongoing reviews of equity method investment operations, we did not identify any indicators of impairment that existed during 2025.

Regulation

Guardian, Midwestern and Viking are subject to rate regulation and accounting requirements of FERC. The regulated operations of each of these subsidiaries have rates that are (i) established by independent, third-party regulators, (ii) set at levels that will recover our costs when considering the demand and competition for our services and (iii) charged to and collectible from our customers. Accordingly, we follow the accounting for regulated operations as defined in ASC 980 for these pipelines, which results in differences in the application of GAAP between our regulated and non-regulated businesses. These entities are required to record regulatory assets and liabilities for certain transactions that would have been treated as revenue or expense in non-regulated businesses. Future regulatory changes could result in changes in the amounts of regulatory assets and liabilities or the discontinuance of this accounting treatment for regulatory assets and liabilities for some or all of our regulated businesses. We believe that currently available facts support the continued use of regulatory accounting and that all regulatory assets and liabilities are recoverable or refundable in the current regulatory environment.

See Note 17, "Regulatory Matters" to the Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

NEW ACCOUNTING PRONOUNCEMENTS

See Note 3, "New Accounting Pronouncements" to the Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

Market Price Risk

Our gathering business is dependent on the continued availability of natural gas production and reserves in our geographical areas of operation. Low prices for natural gas, including those resulting from regional basis differentials, could adversely affect development of additional reserves and future natural gas production that is accessible by our pipeline and storage assets. We manage our exposure through the use of short, medium, and long-term transportation, gathering, and storage contracts. Consequently, our existing operations and cash flows have limited direct exposure to natural gas price risk.

Credit Risk

We are exposed to credit risk, which is the risk of loss resulting from nonpayment or nonperformance under a contract. We manage our exposure to credit risk associated with customers through credit analysis, credit approval, credit limits and monitoring procedures. For certain transactions, we may request letters of credit, cash collateral, prepayments or guarantees as forms of credit support. Our FERC tariffs require tariff customers that do not meet specified credit standards to provide three months of credit support, however, we are exposed to credit risk beyond this three-month period when our tariffs do not require our customers to provide additional credit support. For some long-term contracts with associated system construction or expansion, we have entered into negotiated credit agreements that provide for enhanced forms of credit support if certain customer credit standards are not met.

We depend on a key customer, Expand Energy, in the Haynesville formation in the Gulf Coast and in the Marcellus formation in the Northeastern U.S. for a significant portion of our revenues. The loss of, or reduction in volumes from, this key customer could result in a decline in demand for our services and materially adversely affect our business, financial condition and results of operations.

Our key customer, Expand Energy, is investment grade. We engage with other customers that are sub-investment grade. These customers are otherwise considered creditworthy or are required to make prepayments or provide security to satisfy credit concerns. We regularly monitor for bankruptcy proceedings that may impact our customers and had no bankruptcy proceedings during the year ended December 31, 2025.

Interest Rate Risk

We are subject to interest rate risk in connection with floating rate debt borrowings under our Revolving Credit Facility. Our exposure to interest rate risk arises primarily from changes in SOFR. As of December 31, 2025, we had no floating rate debt borrowings outstanding under our Revolving Credit Facility. See Note 10, "Debt" to the Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

We are subject to interest rate risk in connection with our goodwill impairment assessment. See "Critical Accounting Estimates" under Part II, Item 7 of this Form 10-K.

International Markets Risk

While virtually all of our business is in the United States, we also have an equity method investment in Vector, which operates in Canada. Rapidly changing global trade policies, such as tariffs, may increase capital expenditures, operating costs and market uncertainty. We continue to monitor regulatory developments.

Summary of Sensitivity Analysis

A sensitivity analysis was performed on the fair values of our long-term debt obligations. The sensitivity analysis involved increasing and decreasing interest rates as of December 31, 2025 by a hypothetical 10% and calculating the resulting change in the fair values. We have no debt maturing until 2029, as described in Note 10, "Debt" to the Consolidated Financial Statements under Part II, Item 8 of this Form 10-K. The hypothetical losses related to long-term debt would be realized only if we transferred all of our fixed-rate long-term debt to other creditors. The results of the sensitivity analysis are as follows:

Assuming a 10% Increase in Rates

Assuming a 10% Decrease in Rates

Change in the Fair Value of

Activity

As of December 31, 2025

(millions)

Interest rate risk

(77)

Long-term debt

Item 8. Financial Statements

The following Consolidated Financial Statements are included herein:


			Page
Report of Independent Registered Public Accounting Firm (PCAOB ID 238)			56
Consolidated Statements of Operations			58
Consolidated Statements of Comprehensive Income			59
Consolidated Statements of Financial Position			60
Consolidated Statements of Cash Flows			62
Consolidated Statements of Changes in Stockholders' Equity			63
Notes to Consolidated Financial Statements			64
Note 1 — Description of the Business and Basis of Presentation			64
Note 2 — Significant Accounting Policies			67
Note 3 — New Accounting Pronouncements			68
Note 4 — Revenue			69
Note 5 — Goodwill			72
Note 6 — Property, Plant, and Equipment and Intangible Assets			73
Note 7 — Income Taxes			74
Note 8 — Earnings Per Share and Dividends			77
Note 9 — Fair Value			78
Note 10 — Debt			79
Note 11 — Leases			81
Note 12 — Commitments and Contingencies			84
Note 13 — Stock-Based Compensation and Defined Contribution Plans			85
Note 14 — Segment and Related Information			87
Note 15 — Related Party Transactions			90
Note 16 — Acquisition			90
Note 17 — Regulatory Matters			91
Note 18 — Subsequent Event			93

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Stockholders of DT Midstream, Inc.

Opinions on the Financial Statements and Internal Control over Financial Reporting

We have audited the accompanying consolidated statements of financial position of DT Midstream, Inc. and its subsidiaries (the “Company”) as of December 31, 2025 and 2024, and the related consolidated statements of operations, of comprehensive income, of changes in stockholders' equity and of cash flows for each of the three years in the period ended December 31, 2025, including the related notes (collectively referred to as the “consolidated financial statements”). We also have audited the Company's internal control over financial reporting as of December 31, 2025, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2025 and 2024, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2025 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2025, based on criteria established in Internal Control - Integrated Framework (2013) issued by the COSO.

Basis for Opinions

The Company's management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in Management’s report on internal control over financial reporting appearing under Item 9A. Our responsibility is to express opinions on the Company’s consolidated financial statements and on the Company's internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.

Our audits of the consolidated financial statements included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

Definition and Limitations of Internal Control over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Critical Audit Matters

The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that (i) relates to accounts or disclosures that are material to the consolidated financial statements and (ii) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

Equity Method Investments in NEXUS Gas Transmission, LLC and Millennium Pipeline Intermediate Holdings, LLC

As described in Note 1 to the consolidated financial statements, non-controlled investments are accounted for using the equity method of accounting when the Company is able to significantly influence the operating policies of the investee. Under the equity method of accounting, investments are recorded at historical cost as an asset and adjusted for capital contributions, dividends and distributions received, and the Company’s share of the investee’s earnings or losses, which are recorded as earnings from equity method investees. The Company’s equity method investments are periodically evaluated for certain factors that may be indicative of other-than-temporary impairment. As of December 31, 2025, the Company’s equity method investment balance in NEXUS Gas Transmission, LLC (“NEXUS”) and Millennium Pipeline Intermediate Holdings, LLC (“Millennium”) was $867 million and $252 million, respectively. For the year ended December 31, 2025, earnings from equity method investees for NEXUS and Millennium were $64 million and $36 million, respectively.

The principal consideration for our determination that performing procedures relating to the equity method investments in NEXUS and Millennium is a critical audit matter is a high degree of auditor effort in performing procedures related to these equity method investments.

Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to equity method investments. These procedures also included, among others, the following, which were performed as of and for the year ended December 31, 2025 for NEXUS and Millennium (collectively “the investees”): (i) vouching capital contributions, dividends and distributions to source documents, (ii) confirming specific unaudited financial information with the investees, (iii) reconciling the investee financial information per Company records to the investees’ independently audited financial statements, (iv) recalculating the Company’s carrying amount of its investments in the investees that exceeded the Company’s share of the underlying equity in the net assets and the related amortization of such differences, (v) performing inquiries with management, and inspecting supporting evidence and documentation, to understand and evaluate management’s consideration of accounting matters, including management’s assertion that there were no indicators of other-than-temporary impairment, and (vi) performing procedures to evaluate subsequent events impacting the investees.

/s/ PricewaterhouseCoopers LLP

Detroit, Michigan

February 19, 2026

We have served as the Company’s auditor since 2020.

DT Midstream, Inc.

Consolidated Statements of Operations


	Year Ended December 31,
	2025		2024		2023
	(millions, except per share amounts)
Revenues
Operating revenues	$	1,243	$	981	$	922
Operating Expenses
Operation and maintenance	329		244		245
Depreciation and amortization	258		209		182
Taxes other than income	42		39		28
Asset (gains) losses and impairments, net	—		—		(4)
Operating Income	614		489		471
Other (Income) and Deductions
Interest expense	161		153		150
Interest income	(2)		(7)		(1)
Earnings from equity method investees	(138)		(162)		(177)
Loss from financing activities	—		5		—
Other income	(5)		(4)		(1)
Income Before Income Taxes	598		504		500
Income Tax Expense	144		137		104
Net Income	454		367		396
Less: Net Income Attributable to Noncontrolling Interests	13		13		12
Net Income Attributable to DT Midstream	$	441	$	354	$	384

Basic Earnings per Common Share
Net Income Attributable to DT Midstream	$	4.34	$	3.63	$	3.97

Diluted Earnings per Common Share
Net Income Attributable to DT Midstream	$	4.30	$	3.60	$	3.94

Weighted Average Common Shares Outstanding
Basic	101.6		97.6		96.9
Diluted	102.5		98.4		97.5

See Notes to Consolidated Financial Statements

DT Midstream, Inc.

Consolidated Statements of Comprehensive Income


	Year Ended December 31,
	2025		2024		2023
	(millions)
Net Income	$	454	$	367	$	396
Other comprehensive income, net of tax
Foreign currency translation, net of tax	1		—		2
Total other comprehensive income, net of tax	1		—		2
Comprehensive income	455		367		398
Less: Comprehensive income attributable to noncontrolling interests	13		13		12
Comprehensive Income Attributable to DT Midstream	$	442	$	354	$	386

See Notes to Consolidated Financial Statements

DT Midstream, Inc.

Consolidated Statements of Financial Position



	December 31,
	2025		2024
	(millions)
ASSETS
Current Assets
Cash and cash equivalents	$	54	$	68
Accounts receivable (net of $— allowance for expected credit loss for each period end)	186		172



Deferred property taxes	42		33
Taxes receivable	2		8
Prepaid expenses and other	34		29
	318		310
Investments
Investments in equity method investees	1,253		1,297

Property
Property, plant, and equipment	6,958		6,525
Accumulated depreciation	(1,192)		(998)
	5,766		5,527
Other Assets
Goodwill	781		776
Long-term notes receivable — related party	4		4
Operating lease right-of-use assets	46		49
Intangible assets, net	1,862		1,921

Other	50		51
	2,743		2,801
Total Assets (a)	$	10,080	$	9,935

__________________________________

(a) Our consolidated assets include $943 million and $914 million at December 31, 2025 and 2024, respectively, of certain assets that can be used only to settle obligations of the VIE. See Note 1, "Description of the Business and Basis of Presentation," to the Consolidated Financial Statements.

See Notes to Consolidated Financial Statements

DT Midstream, Inc.

Consolidated Statements of Financial Position



	December 31,
	2025		2024
	(millions, except shares)
LIABILITIES AND EQUITY
Current Liabilities
Accounts payable	$	65	$	77

Short-term borrowings	—		150
Operating lease liabilities	16		16
Dividends payable	83		75
Interest payable	11		12
Property taxes payable	48		42
Accrued compensation	25		19
Contract liabilities	25		18
Other	23		17
	296		426

Long-Term Debt, net	3,324		3,319

Other Liabilities
Deferred income taxes	1,270		1,129
Operating lease liabilities	32		36
Contract liabilities	160		135
Regulatory liabilities	90		90
Other	30		34
	1,582		1,424
Total Liabilities (b)	5,202		5,169

Commitments and Contingencies (Note 12)

Stockholders' Equity
Preferred stock ($0.01 par value, 50,000,000 shares authorized, and no shares issued or outstanding as of December 31, 2025 and December 31, 2024)	—		—
Common stock ($0.01 par value, 550,000,000 shares authorized, and 101,673,925 and 101,324,894 shares issued and outstanding as of December 31, 2025 and December 31, 2024, respectively)	1		1
Additional paid-in capital	3,915		3,911
Retained earnings	827		723
Accumulated other comprehensive loss	(7)		(8)
Total DT Midstream Equity	4,736		4,627
Noncontrolling interests	142		139
Total Equity	4,878		4,766
Total Liabilities and Equity	$	10,080	$	9,935

__________________________________

(b) Our consolidated liabilities include $16 million and $8 million at December 31, 2025 and 2024, respectively, of certain liabilities for which creditors do not have recourse to the general credit of the primary beneficiary. See Note 1, "Description of the Business and Basis of Presentation," to the Consolidated Financial Statements.

See Notes to Consolidated Financial Statements

DT Midstream, Inc.

Consolidated Statements of Cash Flows


	Year Ended December 31,
	2025		2024		2023
	(millions)
Operating Activities
Net Income	$	454	$	367	$	396
Adjustments to reconcile Net Income to Net cash and cash equivalents from operating activities:
Depreciation and amortization	258		209		182
Stock-based compensation	26		23		20
Amortization of operating lease right-of-use assets	17		18		18
Deferred income taxes	137		120		110
Earnings from equity method investees	(138)		(162)		(177)
Dividends from equity method investees	138		161		196

Loss from financing activities	—		5		—
Changes in assets and liabilities:
Accounts receivable, net	(24)		11		7
Accounts payable	(13)		11		(5)

Contract liabilities	26		23		97
Other current and noncurrent assets and liabilities	(14)		(23)		(46)
Net cash and cash equivalents from operating activities	867		763		798
Investing Activities
Plant and equipment expenditures	(426)		(350)		(772)
Acquisition accounted for as a business combination (and purchase price adjustment)	10		(1,198)		—

Distributions from equity method investees	49		472		427
Contributions to equity method investees	(5)		(5)		(7)


Other investing activities	—		—		1
Net cash and cash equivalents used for investing activities	(372)		(1,081)		(351)
Financing Activities
Issuance of long-term debt, net of discount and issuance costs	—		644		—
Repayment of long-term debt	—		(399)		—
Borrowings under the Revolving Credit Facility	330		385		540
Repayment of borrowings under the Revolving Credit Facility	(480)		(400)		(705)
Payment of Revolving Credit Facility issuance costs	—		(3)		—
Issuance of common stock, net of issuance costs	—		406		—

Contributions from noncontrolling interests	7		—		—
Distributions to noncontrolling interests	(17)		(17)		(18)

Dividends paid on common stock	(324)		(280)		(263)
Other financing activities	(25)		(6)		(6)
Net cash and cash equivalents from (used for) financing activities	(509)		330		(452)
Net Increase (Decrease) in Cash and Cash Equivalents	(14)		12		(5)
Cash and Cash Equivalents at Beginning of Period	68		56		61
Cash and Cash Equivalents at End of Period	$	54	$	68	$	56

Supplemental disclosure of cash information
Cash paid for:
Interest, net of interest capitalized	$	152	$	140	$	140

Supplemental disclosure of non-cash investing and financing activities
Plant and equipment expenditures in accounts payable and other accrued liabilities	$	50	$	44	$	80

See Notes to Consolidated Financial Statements

DT Midstream, Inc.

Consolidated Statements of Changes in Stockholders' Equity


				Additional Paid-In Capital		Retained Earnings		Accumulated Other Comprehensive Income (Loss)		Noncontrolling Interests
	Common Stock
	Shares	Amount										Total
	(dollars in millions, shares in thousands)










Balance, December 31, 2022	96,755	$	1	$	3,469	$	547	$	(10)	$	147	$	4,154
Net Income	—	—		—		384		—		12		396
Dividends declared on common stock ($2.76 per common share)	—	—		—		(268)		—		—		(268)
Distributions to noncontrolling interests	—	—		—		—		—		(18)		(18)
Stock-based compensation and other	216	—		16		(2)		—		—		14

Other comprehensive income, net of tax	—	—		—		—		2		—		2
Balance, December 31, 2023	96,971	$	1	$	3,485	$	661	$	(8)	$	141	$	4,280
Net Income	—	—		—		354		—		13		367
Issuance of common stock, net of issuance costs (a)	4,169	—		406		—		—		—		406
Dividends declared on common stock ($2.94 per common share)	—	—		—		(288)		—		—		(288)
Contributions from noncontrolling interests	—	—		—		—		—		2		2
Distributions to noncontrolling interests	—	—		—		—		—		(17)		(17)
Stock-based compensation and other	185	—		20		(4)		—		—		16
Balance, December 31, 2024	101,325	$	1	$	3,911	$	723	$	(8)	$	139	$	4,766
Net Income	—	—		—		441		—		13		454

Dividends declared on common stock ($3.28 per common share)	—	—		—		(332)		—		—		(332)
Contributions from noncontrolling interests	—	—		—		—		—		7		7
Distributions to noncontrolling interests	—	—		—		—		—		(17)		(17)
Stock-based compensation and other	349	—		4		(5)		—		—		(1)
Other comprehensive income, net of tax	—	—		—		—		1		—		1
Balance, December 31, 2025	101,674	$	1	$	3,915	$	827	$	(7)	$	142	$	4,878

_____________________________________

(a)Issuance of common shares at $0.01 par value. See Note 8, "Earnings Per Share and Dividends ," to the Consolidated Financial Statements.

See Notes to Consolidated Financial Statements

DT Midstream, Inc.

Notes to Consolidated Financial Statements

NOTE 1 — DESCRIPTION OF THE BUSINESS AND BASIS OF PRESENTATION

Description of the Business

DT Midstream is an owner, operator, and developer of an integrated portfolio of natural gas midstream assets. We provide multiple, integrated natural gas services to customers through two segments: (i) Pipeline, which includes interstate pipelines, intrastate pipelines, storage systems, gathering lateral pipelines and compression and surface facilities, and (ii) Gathering, which includes gathering systems, related treatment plants, and compression and surface facilities. Our Pipeline segment also includes joint venture interests in equity method investees which own and operate interstate pipelines that connect to our wholly owned assets.

Our core assets strategically connect key demand centers in the Midwestern U.S., Eastern Canada and Northeastern U.S. regions to the premium production areas of the Marcellus/Utica natural gas formation in the Appalachian Basin, and connect key demand centers and LNG export terminals in the Gulf Coast region to premium production areas of the Haynesville natural gas formation.

Basis of Presentation

The Consolidated Financial Statements and Notes to Consolidated Financial Statements are prepared under GAAP.

These accounting principles require management to use estimates and assumptions that impact reported amounts of assets, liabilities, revenues and expenses, and the disclosure of contingent assets and liabilities. Actual results may differ from our estimates. We believe the assumptions underlying these financial statements are reasonable.

Cash Management

Our sources of liquidity include cash generated from operations and available borrowings under our Revolving Credit Facility.

Principles of Consolidation

We consolidate all majority-owned subsidiaries and investments in entities in which we have a controlling influence. Non-controlled investments are accounted for using the equity method of accounting when we are able to significantly influence the operating policies of the investee. When we do not influence the operating policies of an investee, the equity investment is measured at fair value, if readily determinable, or if not readily determinable, at cost less impairment, if applicable. We eliminate all intercompany balances and transactions.

We evaluate whether an entity is a VIE whenever reconsideration events occur. We consolidate VIEs for which we are the primary beneficiary. When assessing the determination of the primary beneficiary, we consider all relevant facts and circumstances, including: the power, through voting or similar rights, to direct the activities of the VIE that most significantly impact the VIE's economic performance and the obligation to absorb the expected losses and/or the right to receive the expected returns of the VIE. We perform ongoing reassessments of all VIEs to determine if the primary beneficiary status has changed.

We own an 85% interest in the Stonewall VIE and are the primary beneficiary, therefore Stonewall is consolidated. We own a 50% interest in the South Romeo VIE and are the primary beneficiary, therefore South Romeo is consolidated.

DT Midstream, Inc.

Notes to Consolidated Financial Statements

The following table summarizes the major line items in the Consolidated Statements of Financial Position for consolidated VIEs as of December 31, 2025 and December 31, 2024. All assets and liabilities of a consolidated VIE are included in the table when it has been determined that a consolidated VIE has either (1) assets that can be used only to settle obligations of the VIE or (2) liabilities for which creditors do not have recourse to the general credit of the primary beneficiary. The assets and liabilities of consolidated VIEs that meet the definition of a business and whose assets can be used for purposes other than the settlement of the VIEs' obligations have been excluded from the table below.



	December 31,
	2025		2024
	(millions)
ASSETS (a)
Cash	$	20	$	17
Accounts receivable	10		11
Other current assets	3		2
Intangible assets, net	454		468
Property, plant and equipment, net	431		391
Goodwill	25		25
	$	943	$	914

LIABILITIES (a)
Accounts payable and other current liabilities	$	13	$	5
Other noncurrent liabilities	3		3
	$	16	$	8

_____________________________________

(a)Amounts shown are 100% of the consolidated VIEs' assets and liabilities.

Related Parties

Transactions between DT Midstream and our equity method investees have been presented as related party transactions in the accompanying Consolidated Financial Statements. See Note 15, "Related Party Transactions" to the Consolidated Financial Statements.

Equity Method Investments

Non-controlled investments are accounted for using the equity method of accounting when we are able to significantly influence the operating policies of the investee. Under the equity method of accounting, investments are recorded at historical cost as an asset and adjusted for capital contributions, dividends and distributions received, and our share of the investee's earnings or losses, which are recorded as earnings from equity method investees on the Consolidated Statements of Operations. Equity method investments and related activity are included in the Pipeline segment.

Our equity method investments are periodically evaluated for certain factors that may be indicative of other-than-temporary impairment. As of December 31, 2025 and December 31, 2024, our carrying amounts of investments in equity method investees exceeded our share of the underlying equity in the net assets of the investees by $320 million and $336 million, respectively. The difference will be amortized over the life of the underlying assets. As of both December 31, 2025 and December 31, 2024, our consolidated retained earnings balance did not have undistributed earnings from equity method investments. We use the cumulative earnings approach to classify proceeds received from equity method investees as dividends or distributions on the Consolidated Statements of Cash Flows.

Earnings from equity method investees include:




	Year Ended December 31,
	2025		2024		2023
			(millions)
NEXUS	$	64	$	62	$	68
Vector	38		41		38
Millennium	36		59		71
Total earnings from equity method investees	$	138	$	162	$	177

DT Midstream, Inc.

Notes to Consolidated Financial Statements

Equity method investees are described below:


	Investments As of				% Owned As of

	December 31,				December 31,
Equity Method Investee	2025		2024		2025	2024


	(millions)
NEXUS	$	867	$	880	50%	50%
Vector	134		134		40%	40%
Millennium	252		283		52.5%	52.5%
Total investments in equity method investees	$	1,253	$	1,297

In September 2024, Millennium closed on the sale of $800 million of senior unsecured notes with a weighted-average coupon rate of 5.88%. We received a distribution from Millennium of $416 million, net of fees and expenses, which reduced our investment balance. We used the proceeds from the distribution to repay our existing indebtedness under our Term Loan Facility and for general corporate purposes.

In May 2023, NEXUS closed on the sale of $750 million of senior unsecured notes with a weighted-average coupon rate of 5.52%. We received a distribution from NEXUS of $371 million, net of fees and expenses, which reduced our investment balance. We used the proceeds from the distribution to repay borrowings outstanding under our Revolving Credit Facility.

The following tables present summarized financial information of our non-consolidated equity method investees. The amounts included below represent 100% of the results of continuing operations of such entities, including the portion owned by other parties.

Summarized balance sheet data is as follows:


	December 31,
	2025		2024
	(millions)
Current assets	$	185	$	170
Noncurrent assets	$	3,827	$	3,939
Current liabilities	$	184	$	209
Noncurrent liabilities	$	1,913	$	1,930

Summarized income statement data is as follows:



		Year Ended December 31,
			2025		2024		2023
	(millions)
Operating revenues			$	822	$	818	$	823
Operating expenses			$	393	$	376	$	377
Net Income			$	321	$	364	$	392

DT Midstream, Inc.

Notes to Consolidated Financial Statements

NOTE 2 — SIGNIFICANT ACCOUNTING POLICIES

Cash and Cash Equivalents

Cash and cash equivalents include cash in banks and highly liquid money market investments with remaining maturities of three months or less, when purchased. Cash equivalents are stated at cost, which approximates fair value.

Financing Receivables

Financing receivables are primarily composed of trade accounts receivable and notes receivable, which are stated at net realizable value.

We regularly monitor the credit quality of our financing receivables by reviewing counterparty credit quality indicators and monitoring for triggering events, such as a credit rating downgrade or bankruptcy. We have three internal grades of credit quality, with internal grade 1 as the lowest risk and internal grade 3 as the highest risk. The related credit quality indicators and risk ratings utilized to develop the internal grades have been updated through December 31, 2025. As of December 31, 2025, the notes receivable — related party of $4 million, which originated prior to 2021, were classified as internal grade 1. There are no notes receivable on nonaccrual status and no past due financing receivables as of December 31, 2025.

Notes receivable are typically considered delinquent (past due) when payment is not received for periods ranging from 60 to 120 days. We cease accruing interest income (nonaccrual status) and may either write off or establish an allowance for expected credit loss for the note receivable when it is expected that all contractual principal or interest amounts due will not be collected. In determining an allowance for expected credit losses for or the write off of notes receivable, we consider the historical payment experience and other factors that are expected to have a specific impact on collection, including existing and future economic conditions. Cash receipts for notes receivable on nonaccrual status that do not bring the account contractually current are first applied to contractually owed past due interest, with any remainder applied to principal. Recognition of interest income is generally resumed when the note receivable becomes contractually current.

For trade accounts receivable, the customer allowance for expected credit loss is calculated based on specific review of future collections based on receivable balances generally in excess of 30 days. Existing and future economic conditions, historical loss rates, customer trends and other relevant factors that may affect our ability to collect are also considered. Receivables are written off on a specific identification basis and determined based on the particular circumstances of the associated receivable. Uncollectible expense (recovery) was zero for each of the years ended December 31, 2025 and 2024.

Our collections on accounts receivable from customers are current, and no material rate of historical loss was noted, which resulted in no allowance for expected credit loss as of December 31, 2025 or December 31, 2024. Any balance would be shown as a deduction from the respective financing receivable's balance in the Consolidated Statements of Financial Position.

Property, Plant, and Equipment

Property is stated at cost and includes construction-related labor, materials, overhead and capitalized interest. Property for FERC-Regulated entities also includes equity AFUDC. Equity AFUDC represents the capitalization of the estimated average cost of equity during construction projects and is recorded as a credit to allowance for funds used during construction in our Consolidated Statements of Operations. Expenditures for maintenance and repairs are charged to expense when incurred. Property, plant and equipment is depreciated over its estimated useful life using the straight-line method. See Note 6, "Property, Plant, and Equipment and Intangible Assets" to the Consolidated Financial Statements.

Certain regulated properties are accounted for under ASC 980, which in some cases requires that the cost of regulated property retired or sold, plus removal costs, less salvage, be charged to accumulated depreciation. For regulated property, depreciation studies to assess the estimated useful lives of the asset are typically conducted as part of rate proceedings or tariff filings. Changes in economic lives, if applicable, are implemented prospectively as of the approved effective date. See Note 17, "Regulatory Matters" to the Consolidated Financial Statements.

Intangible Assets

Intangible assets with finite useful lives are amortized on a straight-line basis over the periods benefited. See Note 6, "Property, Plant, and Equipment and Intangible Assets" to the Consolidated Financial Statements.

DT Midstream, Inc.

Notes to Consolidated Financial Statements

Long-Lived Assets

Long-lived assets are reviewed for impairment whenever events or changes in circumstances indicate the carrying amount of an asset may not be recoverable. If the carrying amount of the asset exceeds the expected undiscounted future cash flows generated by the asset, an impairment loss is recognized resulting in the asset being written down to its estimated fair value. Assets to be disposed of are reported at the lower of the carrying amount or fair value, less costs to sell.

Purchase Accounting

In accordance with the business combination acquisition method of accounting, the assets acquired and liabilities assumed in an acquired business are measured at their estimated fair values at the acquisition date.

Goodwill

DT Midstream has goodwill resulting from business combinations. For each reporting unit with goodwill, we perform an impairment test annually or whenever events or circumstances indicate that the value of goodwill may be impaired.

Operation and Maintenance

Operation and maintenance is primarily comprised of costs for labor and employee benefits, outside services, materials, compression, purchased natural gas, operating lease costs, office costs, and other operating and maintenance costs.

Depreciation and Amortization

Depreciation and amortization is related to Property, plant and equipment and Customer relationships and other intangible assets, net, used in our transportation, storage and gathering businesses.

Other Significant Accounting Policies


Footnote						Title
Note 1						Equity Method Investments
Note 4						Revenue
Note 7						Income Taxes
Note 9						Fair Value
Note 11						Leases
Note 14						Reportable Segments
Note 16						Acquisition
Note 17						Regulation

NOTE 3 — NEW ACCOUNTING PRONOUNCEMENTS

Recently Adopted Pronouncements

In December 2023, the FASB issued ASU No. 2023-09, Income Taxes (Topic 740): Improvements to Income Tax Disclosures. The amendments improve transparency of income tax disclosure requirements, primarily through enhanced disclosures of rate reconciliation and income taxes paid. The amendments are effective for annual reporting periods beginning after December 15, 2024. We adopted this ASU effective for the year ended December 31, 2025, and applied the disclosure requirements retrospectively to all prior periods presented. See Note 7, "Income Taxes," to the Consolidated Financial Statements.

DT Midstream, Inc.

Notes to Consolidated Financial Statements

Recently Issued Pronouncements

In November 2024, the FASB issued ASU No. 2024-03, Income Statement—Reporting Comprehensive Income—Expense Disaggregation Disclosures (Subtopic 220-40): Disaggregation of Income Statement Expenses. The amendments require enhanced disclosures of specified costs and expenses included in significant expense captions in the income statement, including purchases of inventory, employee compensation, depreciation, amortization, and other key amounts. The FASB subsequently issued ASU No. 2025-01 in January 2025 to clarify the effective date of ASU No. 2024-03. The amendments are effective for annual reporting periods beginning after December 15, 2026 and interim reporting periods within annual reporting periods beginning after December 15, 2027. Early adoption is permitted. The Company is currently evaluating the impact of this standard's adoption on our Consolidated Financial Statements.

In September 2025, the FASB issued ASU No. 2025-06, Intangibles—Goodwill and Other—Internal-Use Software (Subtopic 350-40): Targeted Improvements to the Accounting for Internal-Use Software. The amendments modernize the guidance by replacing the stage-based capitalization model with a “probable-to-complete” threshold, aligning impairment testing with the long-lived asset model under ASC 360, and requiring enhanced disclosures for significant internal-use software projects. The amendments are effective for annual reporting periods beginning after December 15, 2027, and interim reporting periods within those annual periods. Early adoption is permitted. The Company is currently evaluating the impact of this standard's adoption on our Consolidated Financial Statements.

In September 2025, the FASB issued ASU No. 2025-07, Derivatives and Hedging (Topic 815) and Revenue from Contracts with Customers (Topic 606): Derivatives Scope Refinements and Scope Clarification for Share-Based Noncash Consideration from a Customer in a Revenue Contract. The amendments provide a scope exception from derivative accounting for certain non-exchange traded contracts with underlyings based on operations or activities specific to one of the parties to the contract and clarify the application of revenue recognition guidance when entities receive share-based noncash consideration from customers in exchange for goods or services. The amendments are effective for annual reporting periods beginning after December 15, 2026, and interim reporting periods within those annual reporting periods. Early adoption is permitted. The Company is currently evaluating the impact of this standard's adoption on our Consolidated Financial Statements, however, the adoption of this standard is not expected to have a significant impact on our Consolidated Financial Statements.

In December 2025, the FASB issued ASU No. 2025‑10, Government Grants (Topic 832): Accounting for Government Grants Received by Business Entities. This update establishes authoritative GAAP for accounting for government grants received by business entities, replacing prior diversity that arose from analogies to IAS 20 or not‑for‑profit guidance. The guidance also introduces enhanced disclosures regarding the nature, terms, and financial statement effects of government grants. The amendments are effective for annual reporting periods beginning after December 15, 2028, and interim reporting periods within those annual periods. Early adoption is permitted. The Company is currently evaluating the impact of this standard's adoption on our Consolidated Financial Statements.

In December 2025, the FASB issued ASU No. 2025‑11, Interim Reporting (Topic 270): Narrow‑Scope Improvements. The amendments clarify the types of interim financial statements subject to ASC 270, reorganize interim disclosure requirements by consolidating cross‑Topic disclosures into a single framework, and introduce a disclosure principle requiring entities to describe material events occurring after the most recent annual reporting period. The amendments are effective for interim reporting periods within annual reporting periods beginning after December 15, 2027. Early adoption is permitted. The Company is currently evaluating the impact of this standard's adoption on our interim financial reporting and interim disclosures.

NOTE 4 — REVENUE

Significant Accounting Policy – Revenue

Pipeline revenues consist of services related to the gathering, transportation and/or storage of natural gas. Gathering revenues consist of services related to the gathering, processing, and/or treating of natural gas. Revenue is measured based upon the pricing or consideration for such services specified in the contract with a customer. Consideration may consist of both fixed components including fixed demand charges and fixed deficiency fee rates for MVCs, and variable components including fixed rates for the actual volumes flowed under interruptible services and other associated fees.

DT Midstream, Inc.

Notes to Consolidated Financial Statements

Our contracts with customers generally contain a single performance obligation, which is a promise to deliver either a distinct service or a series of distinct services to the customer. When multiple performance obligations exist, the contract consideration is allocated between the performance obligations based on the relative standalone selling price, which is determined by prices charged to customers or the adjusted market assessment approach. The adjusted market assessment approach involves evaluating the market in which we sell services and estimating the price that a customer in that market would be willing to pay.

Revenue is recognized when performance obligations are satisfied by delivering a service to a customer, which occurs when the service is provided to the customer. When a customer simultaneously receives and consumes the service provided, revenue is recognized over time. Alternatively, if it is determined that the criteria for recognition of revenue over time is not met, the revenue is considered to be recognized at a point in time. Our revenues, including estimated unbilled amounts, are generally recognized over time as actual services are provided, or ratably over time when providing a stand-ready service. Unbilled amounts are generally determined using preliminary meter data volumes and contracted pricing, and typically result in minor adjustments. Generally, uncertainties in the variable consideration components are resolved and revenue amounts are known at the time of recognition. We have determined that the above methods represent a faithful depiction of delivering a service to the customer. Revenues are typically billed and consideration received monthly, however, certain deficiency fees related to MVCs are billed quarterly or annually.

Disaggregation of Revenue

The following is a summary of revenues disaggregated by segment:


		Year Ended December 31,

			2025		2024		2023
	(millions)
Pipeline (a)			$	687	$	443	$	377
Gathering			556		538		545

Total operating revenues			$	1,243	$	981	$	922

__________________________________

(a) Includes revenues outside the scope of ASC 606 primarily related to contracts accounted for as leases of $78 million, $9 million and $7 million for the years ended December 31, 2025, 2024 and 2023, respectively. The lease income increased for the year ended December 31, 2025 from the operating lease obtained as part of the Midwest Pipeline Acquisition.

Nature of Services

We primarily provide two types of revenue services: firm service and interruptible service. Firm service revenue contracts provide for fixed revenue commitments regardless of actual volumes of natural gas that flow, which leads to more stable operating performance, revenues and cash flows and limits our exposure to natural gas price fluctuations. Firm service revenue contracts are typically long-term and structured using fixed demand charges or MVCs with fixed deficiency fee rates. Contracts structured using fixed demand charges contain a performance obligation of a stand-ready series of distinct services that are substantially the same with the same pattern of transfer to the customer, therefore revenue is recognized ratably over time. Contracts structured using MVCs with fixed deficiency fee rates require customers to transport or store a minimum volume of natural gas over a specified time period. If a customer fails to meet its MVCs for the specified time period, the contract consideration includes a fixed rate for the actual volumes gathered, transported or stored, and a deficiency fee for the shortfall between the MVCs and the actual volumes gathered, transported, or stored. If a customer exceeds its MVC for the specified time period, the contract consideration is based on fixed rates for the actual volumes gathered, transported, or stored. The contract consideration is allocated to each distinct monthly performance obligation, consistent with the allocation objective and based upon the level of effort required to satisfy the service obligation. Revenues are generally recognized over time based on the output measure of natural gas volumes gathered, transported, or stored, with the recognition of the deficiency fee revenue in the period when it is known the customer cannot make up the deficient volumes in the specified time period. Interruptible service revenue contracts typically contain fixed rates, with total consideration dependent on actual natural gas volumes that flow. Interruptible service revenues are recognized over time based on the output measure of natural gas volumes gathered, transported, or stored. Certain of our contracts allow for the recovery of production-related operating expenses, which are offsetting in revenue and operating expense. Recovery of production-related operating expenses were $61 million, $51 million and $53 million for the years ended December 31, 2025, 2024 and 2023, respectively.

DT Midstream, Inc.

Notes to Consolidated Financial Statements

Contract Liabilities

The following is a summary of contract liability activity:


	2025		2024
	(millions)
Balance as of January 1	$	153	$	129
Increases due to cash received or receivable, excluding amounts recognized as revenue during the period (a)	69		47
Revenue recognized that was included in the balance at the beginning of the period	(37)		(23)

Balance as of December 31	$	185	$	153

__________________________________

(a) During the year ended December 31, 2025 and 2024, we collected prepayment amounts from customers under various long-term revenue contracts on Ohio Utica Gathering, Appalachia Gathering, Blue Union Gathering and LEAP.

Contract liabilities generally represent amounts paid by or receivable from customers for which the associated performance obligation has not yet been satisfied. Contract liabilities associated with these services are recognized upon delivery of the service to the customer.

The following table presents contract liability amounts as of December 31, 2025 that are expected to be recognized as revenue in future periods:


	(millions)
2026	$	25
2027	24
2028	22
2029	22
2030	22
2031 and thereafter	70
Total	$	185

Transaction Price Allocated to the Remaining Performance Obligations

In accordance with optional exemptions available under ASC 606, we do not disclose the value of unsatisfied performance obligations for (1) contracts with an original expected length of one year or less, (2) with the exception of fixed consideration, contracts for which the amount of revenue recognized depends upon our invoices for actual volumes gathered, transported, or stored, and (3) contracts for which variable consideration relates entirely to an unsatisfied performance obligation.

Such contracts consist of various types of performance obligations, including providing midstream services. Contracts with variable volumes and/or variable pricing, including those with pricing provisions tied to a consumer price or other index, have also been excluded as the related contract consideration is variable at the contract inception. Contract lengths vary from cancellable to multi-year.

The following table presents revenue amounts related to fixed consideration associated with unsatisfied performance obligations as of December 31, 2025 that are expected to be recognized as revenue in future periods:


	(millions)
2026	$	259
2027	209
2028	154
2029	126
2030	106
2031 and thereafter	287
Total	$	1,141

DT Midstream, Inc.

Notes to Consolidated Financial Statements

Costs to Obtain or Fulfill a Contract

We recognize an asset from the costs incurred to obtain a revenue contract only if we expect to recover those costs. In addition, the costs to fulfill a revenue contract are capitalized if the costs are specifically identifiable to a revenue contract, would result in enhancing resources that will be used in satisfying performance obligations in the future, and are expected to be recovered. These capitalized costs are amortized on a systematic basis consistent with the pattern of transfer of the services to which such costs relate.

As of December 31, 2025 and December 31, 2024, we had capitalized costs to obtain or fulfill a contract of $17 million and $18 million, respectively, which are included in other current assets and other noncurrent assets in the accompanying Consolidated Statements of Financial Position. During the years ended December 31, 2025, 2024 and 2023 we recognized $1 million of amortization expense related to such capitalized costs.

Major Customers

The following table summarizes customers which represent 10% or more of our total revenue for the years ended December 31, 2025, 2024 and 2023. Both Pipeline and Gathering segments provide services to these customers.


	2025				2024				2023
	Customer		Percentage		Customer		Percentage		Customer		Percentage
	Revenue		of Total		Revenue		of Total		Revenue		of Total
Customer:	(millions, except percentages)
Expand Energy	$	560	45	%	$	555	56	%	$	560	60	%

NOTE 5 — GOODWILL

We have goodwill that resulted from business combinations. The carrying value of goodwill is evaluated for impairment on an annual basis or whenever events or circumstances indicate that the value of goodwill may be impaired. We performed our annual impairment test as of October 1, 2025 and determined that the estimated fair value of each reporting unit exceeded its carrying value, and no impairment existed. During the year ended December 31, 2025, we recorded a net $5 million increase to Pipeline goodwill related to measurement period adjustments from the Midwest Pipeline Acquisition completed December 31, 2024. See Note 16, "Acquisition" to the Consolidated Financial Statements.

The following is the summary of the change in the carrying amount of goodwill:


	2025		2024
	(millions)
Balance at January 1	$	776	$	473
Goodwill attributable to the Midwest Pipeline Acquisition (including measurement period adjustments)	5		303
Balance at December 31	$	781	$	776

The following is a summary of the carrying value of goodwill by reporting unit:


	December 31,
	2025		2024
	(millions)
Pipeline	$	361	$	356
Gathering	420		420
Total goodwill	$	781	$	776

While we believe the estimates and assumptions in the estimated fair value are reasonable, the actual results may differ from projections. To the extent projected results or cash flows are revised downward, the reporting unit may be required to write down all or a portion of its goodwill, which would adversely impact our earnings.

DT Midstream, Inc.

Notes to Consolidated Financial Statements

NOTE 6 — PROPERTY, PLANT, AND EQUIPMENT AND INTANGIBLE ASSETS

Property, Plant, and Equipment

The following is a summary of Property, plant, and equipment by classification:


	Average Estimated Useful Life	December 31,
		2025		2024
	(years)	(millions)
Property, plant, and equipment
Land and other non-depreciable assets	N/A	$	105	$	105
Rights of way and easements	25 to 53	168		168
Pipelines and interconnects	10 to 95	4,699		4,437
Facilities and processing plants	7 to 50	1,656		1,364
Wells and well equipment	40 to 70	70		70
General plant	3 to 40	73		60
Construction in progress	N/A	187		321
Total Property, plant, and equipment		6,958		6,525
Less accumulated depreciation		(1,192)		(998)
Net Property, plant, and equipment		$	5,766	$	5,527

Intangible Assets

The following is a summary of Intangible Assets by classification:


		December 31, 2025						December 31, 2024
	Useful Lives	Gross Carrying Value		Accumulated Amortization		Net Carrying Value		Gross Carrying Value		Accumulated Amortization		Net Carrying Value
		(millions)
Intangible assets subject to amortization
Customer relationships	3 - 40 years (a)	$	2,262	$	(403)	$	1,859	$	2,262	$	(345)	$	1,917
Contract intangibles	14 - 26 years	18		(15)		3		18		(14)		4
Total		$	2,280	$	(418)	$	1,862	$	2,280	$	(359)	$	1,921

_____________________________________

(a) The useful lives of the customer relationship intangible assets are based on the number of years in which the assets are expected to economically contribute to the business. The expected economic benefit incorporates existing customer contracts and expected renewal rates based on the estimated volume and production lives of natural gas resources in each region.

The following table summarizes estimated customer relationships and contract intangibles amortization expense to be recognized during each year through 2030:


	2026		2027		2028		2029		2030
	(millions)
Estimated amortization expense	$	60	$	60	$	59	$	59	$	56

Depreciation and Amortization

The following is a summary of depreciation and amortization expense by asset type:


	Year Ended December 31,
	2025		2024		2023
	(millions)
Property, plant, and equipment	$	198	$	152	$	125
Customer relationships and other intangible assets, net	60		57		57
Total Depreciation and amortization	$	258	$	209	$	182

DT Midstream, Inc.

Notes to Consolidated Financial Statements

NOTE 7 — INCOME TAXES

Significant Accounting Policy – Accounting for Income Taxes

We record the effect of income taxes in accordance with GAAP, which provides for the use of an asset and liability approach. Deferred income tax assets and liabilities are recognized for temporary differences between the basis of assets and liabilities for financial reporting and tax purposes and measured using enacted tax rates in effect for the year in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities as a result of changes in the enacted tax rates is recognized in earnings in the period of enactment. Our recognition of deferred tax assets is based upon a more-likely-than-not criterion. We routinely assess realizability based on objectively-weighted, available positive and negative evidence.

We account for uncertainties in income taxes using a benefit recognition model with a two-step approach: a more-likely-than-not recognition criterion, and a measurement attribute that measures the position as the largest amount of tax benefit that is greater than a 50% likelihood of being realized upon ultimate settlement. If the benefit does not meet the more likely than not criteria for being sustained on its technical merits, no benefit will be recorded. Uncertain tax positions that relate only to timing of when an item is included on a tax return are considered to have met the recognition threshold.

Midwest Pipeline Acquisition

The Midwest Pipeline Acquisition, which closed on December 31, 2024, was treated as a deemed asset acquisition for federal and state income tax purposes pursuant to an Internal Revenue Code §338(h)(10) election. Accordingly, the majority of deferred income tax assets and liabilities of the acquired entities were eliminated as the tax bases were increased to fair market value which equals net book value. The election resulted in tax-deductible goodwill which was subject to revision during the applicable one-year measurement period. During the year ended December 31, 2025, we completed the tax purchase price allocation study under Internal Revenue Code §1060, and tax goodwill was adjusted accordingly.

As a result of changes to state apportionment factors and rates due to the Midwest Pipeline Acquisition, during the year ended December 31, 2024, the Company recorded a remeasurement to increase the existing deferred income tax liabilities of DT Midstream (acquiring entity) by $22 million which was charged to income tax expense.

Tax Legislation

On July 4, 2025, the OBBBA was signed into law in the U.S., which contains a broad range of tax reform provisions that amend, eliminate, and extend tax rules under the Inflation Reduction Act. Impacts to the Company of the OBBBA include permanent reinstatement of bonus depreciation on qualified property and modifications to the calculation for excess business interest expense limitation to the current tax estimate. The impact will defer the payment of a portion of our current federal tax for multiple years, but because our tax provision is based on both current and deferred tax, the impact to our income statement is not material.

As part of tax reform enacted in December 2024, the State of Louisiana implemented a flat 5.5% corporate income tax rate (previously tiered from 3.5% to 7.5%) effective January 1, 2025. In accordance with tax accounting guidance, DT Midstream recorded a deferred income tax benefit of $4 million as of December 31, 2024. Other enacted law changes include the repeal of the Louisiana franchise tax and increased state sales and use tax rates, which will take effect in future years and are not expected to have a material impact on the financial statements.

On July 8, 2022, the Commonwealth of Pennsylvania enacted House Bill 1342 which includes a corporate income tax rate reduction from 9.99% to 4.99% that will phase-in over a nine-year period.

DT Midstream, Inc.

Notes to Consolidated Financial Statements

Income before income taxes, by tax jurisdiction, was as follows:


	Year Ended December 31,
	2025		2024		2023
	(millions)
United States	$	596	$	502	$	499
Canada	2		2		1
Total income before income taxes	$	598	$	504	$	500

Our total Income Tax Expense varied from the statutory federal income tax rate for the following reasons:


	Year Ended December 31,
	2025			2024			2023
	Amount		Percent	Amount		Percent	Amount		Percent
	(millions, except percentages)
Income tax expense at U.S. federal statutory rate	$	126	21.0%	$	106	21.0%	$	105	21.0%
State and local income taxes, net of federal income tax effect (a)	24		4.0%	33		6.6%	—		—

Other, net	(6)		(0.9)%	(2)		(0.3)%	(1)		(0.1)%
Income Tax Expense and Effective Income Tax Rate	$	144	24.1%	$	137	27.3%	$	104	20.9%

_____________________________

(a) The state that contributed to the majority (greater than 50%) of the tax effect in this category was Louisiana in each of the years ended December 31, 2025, 2024, and 2023.

The State and local income taxes, net of federal effect line in the table above includes state deferred remeasurements recorded in each of the respective years discussed below.

Our 2025 effective tax rate includes $22 million of state and local statutory tax expense in addition to a $2 million expense driven by updates to state rates and apportionment factors primarily related to tax legislation, as discussed above.

Our 2024 effective tax rate includes $18 million of state and local statutory tax expense in addition to a $15 million expense driven by updates to state rates and apportionment factors, primarily related to the Midwest Pipeline Acquisition and tax legislation, as discussed above.

Our 2023 effective tax rate includes $18 million of state and local statutory tax expense offset by the impact of state tax rate changes of an $18 million benefit driven by changes in tax status and updates to state apportionment which were completed in 2023 as a part of ongoing corporate tax structuring, simplification initiatives, and initial post-separation full-year tax return filings.

DT Midstream, Inc.

Notes to Consolidated Financial Statements

Components of Income tax expense were as follows:


	Year Ended December 31,
	2025		2024		2023
	(millions)
Current income tax expense (benefit)
Federal	$	1	$	13	$	(4)
State and other	6		4		(2)
Total current income tax expense (benefit)	7		17		(6)
Deferred income tax expense
Federal	114		84		109
State and other	23		36		1
Total deferred income tax expense	137		120		110
Total Income Tax Expense	$	144	$	137	$	104

Deferred tax assets and liabilities are recognized for the estimated future tax effect of temporary differences between the tax basis of assets or liabilities and the reported amounts in our Consolidated Financial Statements. We believe it is more likely than not that we will generate sufficient taxable income in future periods to realize our deferred tax assets.

Deferred tax assets (liabilities) were comprised of the following:


	December 31,
	2025		2024
	(millions)
Deferred income tax balance components
Property, plant, and equipment	$	(403)	$	(369)
Federal net operating loss carry-forward	110		117
State and local net operating loss carry-forward, net of federal benefit	86		75
Investment in equity method investees and partnerships	(1,057)		(970)
Other	(6)		18
Net deferred income tax liability	$	(1,270)	$	(1,129)

Total deferred income tax assets and liabilities
Deferred income tax assets	$	271	$	266
Deferred income tax liabilities	(1,541)		(1,395)
Net deferred income tax liability	$	(1,270)	$	(1,129)

We have recorded a deferred tax asset related to a federal net operating loss carry-forward of $110 million as of December 31, 2025. U.S. federal net operating losses will be available to be carried forward indefinitely and available to offset 80% of taxable income in future years.

We have recorded state and local deferred tax assets related to net operating loss carry-forwards of $86 million as of December 31, 2025. Of the state and local net operating loss carry-forwards, $80 million can be carried indefinitely and $6 million will expire from 2031 through 2043 and are available to offset varying amounts of taxable income in future years.

DT Midstream, Inc.

Notes to Consolidated Financial Statements

Income taxes paid, net of refunds received, were as follows:


	Year Ended December 31,
	2025		2024		2023
	(millions)
Federal	$	2	$	7	$	6
Foreign - Canada	1		—		—
State and local
Michigan	2		3		3
Minnesota	1		—		—
Pennsylvania	(3)		—		6
West Virginia	1		—		1
Other	1		2		6
Total state and local	2		5		16
Total Income Taxes Paid	$	5	$	12	$	22

Amounts paid to Canada reflect Canadian federal corporate tax withholding. Foreign tax expense was not material to the Company’s effective tax rate for the periods presented.

Uncertain Tax Positions

As of December 31, 2025 and 2024, we did not have any unrecognized tax benefits. Our income tax returns remain subject to examination by federal, state, and local taxing jurisdictions.

NOTE 8 — EARNINGS PER SHARE AND DIVIDENDS

Basic earnings per share is calculated by dividing Net Income attributable to DT Midstream by the weighted-average number of common shares outstanding during the period. Diluted earnings per share reflect the dilution that would occur if any potentially dilutive instruments were exercised or converted into common shares, using the treasury stock method. Restricted stock units and performance share awards, including dividend equivalents on those grants, are potentially dilutive and, if dilutive, are included in the determination of weighted-average shares outstanding. Restricted stock units and performance share awards do not receive cash dividends, as such, these awards are not considered participating securities.

In November 2024, we issued 4,168,750 common shares at a price to the public of $101.00 per share and received net proceeds of approximately $406 million which was used to partially fund the Midwest Pipeline Acquisition. See Note 16, "Acquisition" to the Consolidated Financial Statements.

The following is a reconciliation of basic and diluted earnings per share:


		Year Ended December 31,

			2025		2024		2023
	(millions, except per share amounts)
Basic and Diluted Earnings per Common Share
Net Income Attributable to DT Midstream			$	441	$	354	$	384
Average number of common shares outstanding — basic			101.6		97.6		96.9

Incremental shares attributable to:
Average dilutive restricted stock units and performance share awards			0.9		0.8		0.6
Average number of common shares outstanding — diluted			102.5		98.4		97.5

Basic Earnings per Common Share			$	4.34	$	3.63	$	3.97
Diluted Earnings per Common Share			$	4.30	$	3.60	$	3.94

DT Midstream, Inc.

Notes to Consolidated Financial Statements

We declared the following cash dividends:


Dividends Declared	Dividend Amount				Dividend Payment Date
(quarter ended)	(per-share)		(millions)
2023
March 31	$	0.69	$	67	April 2023
June 30	$	0.69	$	67	July 2023
September 30	$	0.69	$	67	October 2023
December 31	$	0.69	$	67	January 2024
2024
March 31	$	0.735	$	71	April 2024
June 30	$	0.735	$	71	July 2024
September 30	$	0.735	$	71	October 2024
December 31	$	0.735	$	75	January 2025
2025
March 31	$	0.820	$	83	April 2025
June 30	$	0.820	$	83	July 2025
September 30	$	0.820	$	83	October 2025
December 31	$	0.820	$	83	January 2026

NOTE 9 — FAIR VALUE

Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date in a principal or most advantageous market. Fair value is a market-based measurement that is determined based on inputs, which refer broadly to assumptions that market participants use in pricing assets or liabilities. These inputs can be readily observable, market corroborated, or generally unobservable inputs. We make certain assumptions we believe that market participants would use in pricing assets or liabilities, including assumptions about risk, and the risks inherent in the inputs to valuation techniques. We believe we use valuation techniques that maximize the use of observable market-based inputs and minimize the use of unobservable inputs.

Significant Accounting Policy – Fair Value

A fair value hierarchy has been established that prioritizes the inputs to valuation techniques used to measure fair value in three broad levels. The fair value hierarchy gives the highest priority to quoted prices (unadjusted) in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). In some cases, the inputs used to measure fair value might fall in different levels of the fair value hierarchy. All assets and liabilities are required to be classified in their entirety based on the lowest level of input that is significant to the fair value measurement in its entirety. Assessing the significance of a particular input may require judgment considering factors specific to the asset or liability and may affect the valuation of the asset or liability and its placement within the fair value hierarchy. We classify fair value balances based on the fair value hierarchy defined as follows:

•Level 1 — Consists of unadjusted quoted prices in active markets for identical assets or liabilities that we have the ability to access as of the reporting date.

•Level 2 — Consists of inputs other than quoted prices included within Level 1 that are directly observable for the assets or liabilities or indirectly observable through corroboration with observable market data.

•Level 3 — Consists of unobservable inputs for assets or liabilities whose fair value is estimated based on internally developed models or methodologies using inputs that are generally less readily observable and supported by little, if any, market activity at the measurement date. Unobservable inputs are developed based on the best available information and subject to cost-benefit constraints.

DT Midstream, Inc.

Notes to Consolidated Financial Statements

Fair Value of Financial Instruments

The following table presents the carrying amount and fair value of financial instruments:


	December 31, 2025								December 31, 2024
	Carrying		Fair Value						Carrying		Fair Value
	Amount		Level 1		Level 2		Level 3		Amount		Level 1		Level 2		Level 3
	(millions)
Cash equivalents (a)	$	23	$	—	$	23	$	—	$	—	$	—	$	—	$	—
Long-term notes receivable — related party	4		—		—		4		4		—		—		4
Short-term borrowings (a)	—		—		—		—		150		—		150		—
Long-term debt (b)	$	3,324	$	—	$	3,318	$	—	$	3,319	$	—	$	3,136	$	—

______________________________________

(a)Cash equivalents and Short-term borrowings are stated at cost, which approximates fair value.

(b)Carrying value represents principal of $3.4 billion, net of unamortized debt discounts and issuance costs.

NOTE 10 — DEBT

Amendments to Credit Agreement

In December 2024, we amended our Credit Agreement to, among other things, extend the Revolving Credit Facility maturity date to December 2029 and implement customary "limited condition transaction provisions", enabling us to enter into future acquisitions and other transactions with the conditionality to the consummation thereof subject only to customary "SunGard" conditions, which provide additional financing certainty and reduce the number of conditions required. In November 2024, we amended our Credit Agreement to permit the Company to incur certain customary bridge loans, including the Bridge Facility, a $700 million 364-day bridge loan facility committed by Barclays Bank PLC, which provided certain backstop funding for our Midwest Pipeline Acquisition. Bridge Facility issuance fees of $4 million were incurred during the year ended December 31, 2024 and recorded as interest expense on our Consolidated Statements of Operations.

Debt Issuances

In November 2024, we issued $650 million in aggregate principal amount of 5.800% senior notes due December 2034. At issuance, the 2034 Notes were guaranteed by certain of our subsidiaries and secured by a first priority lien on certain assets of DT Midstream and our subsidiary guarantors that secure our existing credit facilities. The collateral was released on May 16, 2025 following an Investment Grade Event under the respective indenture. In the event of a Reversion Event (as defined in the respective indenture), the collateral is required to be reinstated. As part of the issuance of the 2034 Notes, we capitalized debt issuance costs and discount costs of approximately $5 million and $1 million, respectively.

Debt Redemptions

In September 2024, we repaid the remaining indebtedness under the Term Loan Facility of $399 million. The early redemption resulted in a loss on extinguishment of debt of $4 million related to the write-off of unamortized discount and issuance costs, which was recorded as a loss from financing activities on our Consolidated Statements of Operations for the year ended December 31, 2024. There were no prepayment costs in conjunction with the early redemption of the Term Loan Facility.

Interest Expense

The following table summarizes our interest expense:


	Year Ended December 31,
		2025		2024		2023
		(millions)
Interest expense		$	169	$	163	$	170
Capitalized interest		(8)		(10)		(20)
Total interest expense, net		$	161	$	153	$	150

DT Midstream, Inc.

Notes to Consolidated Financial Statements

Long-Term Debt

The following is a summary of long-term debt:


			Maturity	December 31,		December 31,
Title	Type	Interest Rate	Date	2025		2024
				(millions)
2029 Notes	Senior Notes (a)	4.125%	2029	$	1,100	$	1,100
2031 Notes	Senior Notes (a)	4.375%	2031	1,000		1,000
2032 Notes	Senior Notes (b), (c)	4.300%	2032	600		600
2034 Notes	Senior Notes (a), (c)	5.800%	2034	650		650
Long-term debt principal				3,350		3,350
Unamortized debt discount				(1)		(1)
Unamortized debt issuance costs				(25)		(30)

Long-term debt, net				$	3,324	$	3,319

______________________________

(a) Interest payable semi-annually in arrears each June 15 and December 15.

(b) Interest payable semi-annually in arrears each April 15 and October 15.

(c) The collateral was released on May 16, 2025 following an Investment Grade Event under the respective indentures. In the event of a Reversion Event (as defined in the respective indentures), the collateral is required to be reinstated in accordance with the respective indentures.

The following table presents scheduled debt maturities, excluding any unamortized discount on debt:


		2026		2027	2028	2029	2030 and thereafter	Total
	(millions)
Debt maturities		$	—	—	—	1,100	2,250	$	3,350

Short-Term Credit Arrangements and Borrowings

The following table presents the availability under the Revolving Credit Facility:


	December 31,
	2025
	(millions)
Total availability
Revolving Credit Facility, expiring December 2029 (a)	$	1,000
Amounts outstanding
Revolving Credit Facility borrowings	—
Letters of credit (b)	17
	17
Net availability	$	983

______________________________

(a) The collateral was released on May 16, 2025 following an Investment Grade Event under the Credit Agreement. To the extent the collateral is reinstated under either of the 2032 Notes or the 2034 Notes, the collateral would also be reinstated under the Credit Agreement.

(b) This amount includes $16 million of letters of credit issued to third-party creditors on behalf of Millennium to support its outstanding debt obligations.

Borrowings under the Revolving Credit Facility, if any, are used for general corporate purposes, acquisitions, and letter of credit issuances to support our operations and liquidity. The 2024 amendment costs of the Revolving Credit Facility of $3 million were capitalized during the year ended December 31, 2024. Revolving Credit Facility issuance and amendment costs, net of amortization, of $6 million and $7 million as of December 31, 2025 and 2024, respectively, are included in other noncurrent assets in our Consolidated Statements of Financial Position and are being amortized over the remaining term of the Revolving Credit Facility.

On May 16, 2025, an Investment Grade Event occurred under our Credit Agreement which, among other changes, automatically released the guarantees and collateral supporting our obligations under the Credit Agreement.

DT Midstream, Inc.

Notes to Consolidated Financial Statements

Upon the occurrence of the Investment Grade Event, the negative covenants were automatically amended to create additional flexibility for DT Midstream and its subsidiaries such that (i) the indebtedness negative covenant remains applicable solely to restrict DT Midstream’s restricted subsidiaries, (ii) the former restriction related to prepayments of junior indebtedness has fallen away, and (iii) the remaining negative covenants, including those related to liens, mergers, consolidations, liquidations or dissolutions, sales, transfers or other dispositions, investments, acquisitions, loans or advances, dividends and

distributions or repurchases of capital stock, entering into agreements that limit the ability of the restricted subsidiaries to make distributions to DT Midstream, and transactions with affiliates, were amended automatically to provide for flexibility customary for investment grade companies.

From and after the occurrence of the Investment Grade Event, the Credit Facility requires maintenance of (i) only the maximum consolidated net leverage ratio. The maximum consolidated net leverage ratio is set at 5 to 1 (except, that the Company may elect to temporarily step up the maximum consolidated net leverage ratio to 5.5 to 1 for a period of up to three fiscal quarters after the consummation of an acquisition or investment involving consideration exceeding $50 million). The consolidated net leverage ratio means the ratio of net debt determined in accordance with GAAP to annual consolidated EBITDA, as defined in the Credit Agreement. The Credit Agreement definition of annual consolidated EBITDA excludes EBITDA from equity method investees, but includes dividends and distributions from equity method investees. As of December 31, 2025, the consolidated net leverage ratio was 2.9 to 1 and we were in compliance with the financial covenant.

Dividend Restrictions

Upon the occurrence of the Investment Grade Event, the dividend restrictions under the indentures governing our Senior Notes were terminated and the negative covenants under the Credit Agreement related to dividends were amended automatically to provide for additional flexibility.

NOTE 11 — LEASES

Lessee

Our leases are primarily comprised of equipment and buildings with terms ranging from approximately 3 to 11 years.

A lease exists when we have the right to control the use of identified property, plant or equipment, as conveyed through a contract, for a certain time period and consideration paid. The right to control is deemed to occur when we have the right to obtain substantially all of the economic benefits of the identified assets and the right to direct the use of such assets.

Significant Accounting Policy – Lessee Accounting

Lease liabilities are calculated utilizing a discount rate to determine the present values of lease payments. GAAP requires the use of the rate implicit in the lease if it is readily determinable. When the rate implicit in the lease is not readily determinable, the incremental borrowing rate is used. The incremental borrowing rate is based upon the rate of interest that would have been paid on a collateralized basis over similar contract terms to that of the leases. The incremental borrowing rates have been determined utilizing an implied secured borrowing rate based upon an unsecured rate for a similar time period of remaining lease terms, which is then adjusted for the estimated impact of collateral. We have leases with non-index-based escalation clauses for fixed dollar or percentage increases over the contract term.

We have certain leases which contain purchase options. Based upon the nature of the leased property and terms of the purchase options, we have determined it is not reasonably certain that such purchase options will be exercised. Thus, the impact of the purchase options has not been included in the determination of right-of-use assets and lease liabilities for the subject leases.

We have certain leases which contain renewal options. Where the renewal options were deemed reasonably certain to occur, the impacts of such options were included in the determination of the right-of-use assets and lease liabilities for the subject leases.

We have agreements with lease and non-lease components, which are generally accounted for separately. Consideration in a lease is allocated between lease and non-lease components based upon the estimated relative standalone prices.

DT Midstream, Inc.

Notes to Consolidated Financial Statements

The components of lease cost for the following years includes:


	Year Ended December 31,
	2025		2024		2023
	(millions)
Operating lease cost	$	20	$	21	$	20
Short-term lease cost	3		3		3
	$	23	$	24	$	23

Operating lease cost includes amortization of operating lease right-of-use assets and other related costs. We have elected not to apply the lease balance sheet recognition requirements to short-term leases with a term of 12 months or less. Operating and short-term lease costs are recorded to operation and maintenance in our Consolidated Statements of Operations.

Other relevant information related to leases for the following years includes:


	Year Ended December 31,
	2025			2024			2023
Supplemental Cash Flows Information	(millions, except years and percentages)
Cash paid for amounts included in the measurement of these liabilities:
Operating cash flows for operating leases	$	20		$	21		$	21
Right-of-use assets obtained in exchange for lease obligations:
Operating leases	$	19		$	29		$	25
Weighted Average Remaining Lease Term
Operating leases	3.8 years			3.9 years			4.4 years
Weighted Average Discount Rate
Operating leases	5.1		%	5.3		%	4.8		%

Future minimum lease payments under leases for remaining periods as of December 31, 2025 are as follows:


	Operating Leases
	(millions)
2026	$	18
2027	17
2028	7
2029	3
2030	3
2031 and thereafter	5
Total future minimum lease payments	53
Imputed interest	(5)
Lease liabilities	$	48

Lessor

A lease exists when we have provided other parties with the right to control the use of identified property, plant or equipment, as conveyed through a contract, for a certain time period and consideration received. The right to control is deemed to occur when we have provided other parties with the right to obtain substantially all of the economic benefits of the identified assets and the right to direct the use of such assets.

We lease certain assets under an operating lease for a pipeline which commenced in December 2018. The lease is comprised of fixed payments with a remaining term of 13 years. The operating lease does not have renewal provisions or options to purchase the assets at the end of the lease and does not have termination for convenience provisions. The lease term extends to the end of the estimated economic life of the leased assets, thereby resulting in no residual value.

Guardian has agreements with various subsidiaries of a single parent company that results in the use of substantially all the pipeline's capacity through 2029 and represents an operating lease.

DT Midstream, Inc.

Notes to Consolidated Financial Statements

Fixed lease income associated with the operating leases was $78 million, $9 million, and $7 million for the years ended December 31, 2025, 2024 and 2023, respectively. Fixed lease income is reported in Operating revenues in our Consolidated Statements of Operations. Depreciation expense associated with the property under the operating leases was $17 million, $3 million, and $3 million for the years ended December 31, 2025, 2024 and 2023, respectively.

Future minimum rental revenues for remaining periods as of December 31, 2025 are as follows:


	Operating Lease
	(millions)
2026	$	73
2027	72
2028	72
2029	61
2030	9
2031 and thereafter	70
Total future minimum rental revenues	$	357

Property under the operating leases is as follows:


	December 31,
	2025		2024
	(millions)
Gross property under operating leases	$	512	$	484
Accumulated amortization of property under operating leases	$	34	$	17

DT Midstream, Inc.

Notes to Consolidated Financial Statements

NOTE 12 — COMMITMENTS AND CONTINGENCIES

From time to time, we are subject to legal, administrative and environmental proceedings before various courts, arbitration panels and governmental agencies concerning claims arising in the ordinary course of business. These proceedings include certain contract disputes, additional environmental reviews and investigations, audits and pending judicial matters. We cannot predict the final disposition of such proceedings. We regularly review legal matters and record provisions for claims that we can estimate and are considered probable of loss. The amount or range of reasonably possible losses is not anticipated to, either individually or in the aggregate, materially adversely affect our business, financial condition and results of operations.

Guarantees

In certain limited circumstances, we enter into contractual guarantees. We may guarantee another entity's obligation in the event it fails to perform and may provide guarantees in certain indemnification agreements. We did not have any guarantees of other parties' obligations as of December 31, 2025.

Purchase Commitments

As of December 31, 2025, we were party to long-term purchase commitments relating to a variety of goods and services required for our business. We estimate lifetime purchase commitments of approximately $90 million, due in the periods shown below.


	(millions)
2026	$	16
2027	15
2028	13
2029	13
2030	11
2031 and thereafter	22
Total	$	90

Surety Bonds

In certain limited circumstances, we enter into contracts that require us to obtain external surety bonds to secure our payment and performance. We agree to indemnify the issuers of these surety bonds for amounts, if any, paid by them under these agreements. In the event that any surety bonds are called for non-performance, we would be obligated to reimburse the issuer of the surety bond. In February 2025, certain surety bonds valued at $21 million were terminated. The maximum potential indemnification under our surety bond agreements as of December 31, 2025 is $11 million.

Vector Line of Credit

We are the lender under a revolving term credit facility to Vector, the borrower, in the amount of CAD $70 million. The credit facility was executed in response to the passage of Canadian regulations requiring oil and gas pipelines to demonstrate their financial ability to respond to a catastrophic event and exists for the sole purpose of satisfying these regulations. Vector may only draw upon the facility if the funds are required to respond to a catastrophic event. The maximum potential payout as of December 31, 2025 is USD $51 million. The funding of a loan under the terms of the revolving term credit facility is considered remote.

Clean Fuels Gathering Contingent Payments

A gas supply agreement at Clean Fuels Gathering requires contingent payments from DT Midstream of up to $34 million upon the completion of certain milestones, including cumulative production and income tax credits, and variable payments under a sharing mechanism. As of December 31, 2025, one milestone had been achieved related to verification of gas production volumes and $10 million was paid and recorded as a prepaid asset. The remaining unamortized prepaid asset is $1 million and $8 million in current and long-term other assets, respectively, in DT Midstream's Consolidated Statements of Financial Position as of December 31, 2025.

DT Midstream, Inc.

Notes to Consolidated Financial Statements

Contingent Liability

In order to comply with certain state environmental regulations, we have an obligation to restore pipeline right-of-way slope failures that may arise in the ordinary course of business in the Utica and Marcellus formations. We completed evaluations of all locations, which were prioritized based on the severity and proximity of the slope failures, and used updated cost information to assess the adequacy of the estimate for the contingent liability accrual. As of December 31, 2025 and December 31, 2024, we had accrued contingent liabilities of $2 million and $3 million, respectively, for future slope restoration expenditures. The accrual is included in other current liabilities and other liabilities in the Consolidated Statements of Financial Position. While restoration is ongoing, we believe the accrued amounts are sufficient to cover estimated future expenditures.

Stonewall Litigation

On November 27, 2024, Antero Resources Corporation ("Antero") filed a lawsuit against Stonewall regarding the application of certain rate provisions under the Agreement between the parties dated June 20, 2014. On December 12, 2025, the Third Division of the Business Court of Texas issued an Order granting Antero’s Motion for Summary Judgment related to one aspect of the dispute. On January 12-16, 2026, trial was held on the remaining issues. The Company is awaiting a verdict and has the right to appeal.

Stonewall intends to continue to defend against Antero’s claim. The Company estimates the range of loss to be $0 to $55 million, and could result in a material impact to the rates charged to Antero going forward. No accrual has been recorded in the accompanying consolidated financial statements related to this matter, as a loss is deemed not probable. While the ultimate outcome of this matter cannot be predicted with certainty, an unfavorable resolution could have a material adverse effect on the Company’s financial position, results of operations, or cash flows.

NOTE 13 — STOCK-BASED COMPENSATION AND DEFINED CONTRIBUTION PLANS

The DT Midstream, Inc. Long-Term Incentive Plan permits the grant of incentive and nonqualified stock options, stock appreciation rights, restricted stock awards and restricted stock units, performance share awards, and performance units to employees, consultants and members of DT Midstream's Board of Directors. As a result of a restricted stock award grant, restricted stock unit or performance share award settlement, or by exercise of a stock option, we may issue common stock from our authorized but unissued common stock and/or from outstanding common stock acquired by or on behalf of DT Midstream in the participant's name. Key provisions of the DT Midstream Plan are:

•Authorized limit as of December 31, 2025 was 10,000,000 shares of common stock. The authorized limit increases annually on January 1 by the lesser of 1,750,000 shares of common stock or the amount determined by the DT Midstream Board of Directors.

•Prohibits the grant of a stock option with an exercise price that is less than the fair market value of DT Midstream's stock on the grant date.

The following table summarizes our stock-based compensation expense and the related income tax benefit:


	Year Ended December 31,
	2025		2024		2023
	(millions)
Stock-based compensation expense	$	26	$	23	$	20
Tax benefit	$	6	$	5	$	5

Restricted Stock Units

Restricted stock units granted under the DT Midstream Plan are for a specified number of shares of DT Midstream common stock that entitle the holder to receive common stock, a cash payment, or a combination thereof at the end of the specified vesting period, which is generally three or four years. Restricted stock units are deemed to be equity awards. The fair value of restricted stock units is based on DT Midstream's closing common stock price on the grant date. The fair value is amortized to stock-based compensation expense using a graded vesting schedule over the vesting period. Restricted stock units are settled with DT Midstream common stock and fractional shares are settled in cash.

DT Midstream, Inc.

Notes to Consolidated Financial Statements

During the vesting period, the number of restricted stock units granted will increase, assuming full dividend reinvestment on each dividend payment date. The recipient of a restricted stock unit has no shareholder rights during the vesting period. Restricted stock units are nontransferable and subject to risk of forfeiture during the vesting period. Forfeitures are recognized in the period they occur.

The following table summarizes restricted stock unit activity for the year ended December 31, 2025:


	Restricted Stock Units	Weighted- Average Grant Date Fair Value
	(thousands)	(per share)
Nonvested as of December 31, 2024	461	$	51.37
Granted (a)	105	92.35
Forfeited	(10)	81.04
Vested	(237)	45.89
Nonvested as of December 31, 2025	319	$	68.20

____________________________________

(a)Includes initial grants and dividends reinvested.

The weighted-average grant date fair value of restricted stock units granted, excluding dividends reinvested, during the years ended December 31, 2025, 2024 and 2023 was $99.05, $62.63 and $52.66, respectively. The intrinsic value of restricted stock units vested and issued during the years ended December 31, 2025, 2024 and 2023 was $25 million, $7 million, and $8 million, respectively.

Performance Share Awards

Performance share awards granted under the DT Midstream Plan are for a specified number of shares of DT Midstream common stock that entitle the holder to receive common stock, a cash payment, or a combination thereof at the end of the specified vesting period, which is generally three years. Performance share awards are deemed to be equity awards. Performance share stock-based compensation expense is accrued over the vesting period based on the grant date fair value calculated using: (i) DT Midstream's closing common stock price on the grant date; (ii) the grant date fair value of the market condition; and (iii) the probable achievement of performance objectives. The number of shares issued at settlement is determined based on market conditions and the achievement of certain DT Midstream performance objectives. Performance share awards are settled with DT Midstream common stock and fractional shares are settled in cash.

During the vesting period, the number of performance share awards granted will increase, assuming full dividend reinvestment on each dividend payment date. The recipient of a performance share award has no shareholder rights during the vesting period. Performance share awards are nontransferable and are subject to risk of forfeiture during the vesting period. Forfeitures are recognized in the period they occur.

The following table summarizes performance share award activity for the year ended December 31, 2025:


	Performance Share Awards	Weighted- Average Grant Date Fair Value
	(thousands)	(per share)
Nonvested as of December 31, 2024	701	$	64.38
Granted (a)	376	83.42
Forfeited	(18)	72.90
Settled	(364)	72.97
Nonvested as of December 31, 2025	695	$	69.95

_____________________________________

(a)Includes initial grants, dividends reinvested and shares added for achievement of final performance objectives on settled awards.

The weighted-average grant date fair value of performance share awards granted, excluding dividends reinvested, during the years ended December 31, 2025, 2024 and 2023 was $99.79, $52.05 and $53.74, respectively. The intrinsic value of performance share awards settled during the years ended December 31, 2025, 2024 and 2023 was $35 million, $10 million and $9 million, respectively.

DT Midstream, Inc.

Notes to Consolidated Financial Statements

Unrecognized Compensation Costs

As of December 31, 2025, we had $28 million of total unrecognized compensation costs related to non-vested stock incentive plan arrangements. The unrecognized compensation cost is expected to be recognized over a weighted-average period of 1.68 years.

Defined Contribution Plans

We sponsor defined contribution retirement savings plans, and participation in one of these plans is available to substantially all employees. We match employee contributions up to certain predefined and Internal Revenue Service limits based on eligible compensation and each employee's contribution rate, and contribute additional amounts in lieu of traditional pension and post-employment healthcare benefits. DT Midstream's cost for these plans was $10 million, $7 million and $7 million for the years ended December 31, 2025, 2024 and 2023, respectively.

NOTE 14 — SEGMENT AND RELATED INFORMATION

We set strategic goals, allocate resources, and evaluate performance based on the following two segments: Pipeline and Gathering. Our Chief Operating Decision Maker (CODM) has been identified as our Chief Executive Officer. Our CODM regularly evaluates financial information regarding these segments in deciding how to allocate resources and in assessing our operating and financial performance. We manage and report our operations primarily according to the nature of our products and services. Our plants, pipelines and other fixed assets are located in the U.S. and Canada.

The Pipeline segment owns and operates interstate and intrastate natural gas pipelines, storage systems, and natural gas gathering lateral pipelines. The Pipeline segment also has interests in equity method investees that own and operate interstate natural gas pipelines. The segment is engaged in the transportation and storage of natural gas for intermediate and end user customers. The DTM Interstate Transportation assets and results of operations after the December 31, 2024 acquisition date are presented in our Pipeline segment.

The Gathering segment owns and operates gas gathering systems. The segment is engaged in collecting natural gas from points at or near customers’ wells for delivery to plants for treating, to gathering pipelines for further gathering, or to pipelines for transportation, as well as associated ancillary services. The Clean Fuels Gathering assets and results of operations after the July 1, 2024 acquisition date are presented in our Gathering segment.

Our CODM uses Net Income Attributable to DT Midstream to allocate resources, including employees, property, and financial or capital resources, for each segment predominantly in the annual budget and forecasting process. Our CODM considers budget-to-actual variances on a monthly basis when making decisions about allocating capital and personnel to the segments. The CODM also uses Net Income Attributable to DT Midstream to assess the performance for each segment by comparing the results of each segment. Net Income Attributable to DT Midstream is an important performance measure of the core profitability of our operations and forms the basis of our internal and external financial reporting. We believe that investors benefit from having access to the same financial measures that our management uses in evaluating segment results.

Inter-segment billing for goods and services exchanged between segments is based upon contracted prices of the provider. Inter-segment billings were not significant for the years ended December 31, 2025, 2024 and 2023.

DT Midstream, Inc.

Notes to Consolidated Financial Statements

Financial data for our business segments follows:


	Year Ended December 31, 2025
	Pipeline		Gathering		Total Reportable Segments		Eliminations		Total Consolidated
	(millions)
Revenues
Operating revenues	$	687	$	556	$	1,243	$	—	$	1,243
Operating Expenses
Operation and maintenance	134		195		329		—		329
Depreciation and amortization	111		147		258		—		258
Taxes other than income	27		15		42		—		42

Other (Income) and Deductions
Interest expense	51		110		161		—		161
Interest income	(1)		(1)		(2)		—		(2)
Earnings from equity method investees	(138)		—		(138)		—		(138)

Other income	(1)		(4)		(5)		—		(5)
Income Tax Expense	121		23		144		—		144
Less: Net Income Attributable to Noncontrolling Interests	13		—		13		—		13
Net Income Attributable to DT Midstream	$	370	$	71	$	441	$	—	$	441

Capital expenditures	$	176	$	250	$	426	$	—	$	426

	December 31, 2025
Investments in equity method investees	$	1,253	$	—	$	1,253	$	—	$	1,253
Total Assets	$	5,297	$	4,783	$	10,080	$	—	$	10,080

DT Midstream, Inc.

Notes to Consolidated Financial Statements


	Year Ended December 31, 2024
	Pipeline		Gathering		Total Reportable Segments		Eliminations		Total Consolidated
	(millions)
Revenues
Operating revenues	$	443	$	538	$	981	$	—	$	981
Operating Expenses
Operation and maintenance	68		176		244		—		244
Depreciation and amortization	74		135		209		—		209
Taxes other than income	22		17		39		—		39

Other (Income) and Deductions
Interest expense	47		106		153		—		153
Interest income	(4)		(3)		(7)		—		(7)
Earnings from equity method investees	(162)		—		(162)		—		(162)
Loss from financing activities	3		2		5		—		5
Other income	(1)		(3)		(4)		—		(4)
Income Tax Expense	107		30		137		—		137
Less: Net Income Attributable to Noncontrolling Interests	13		—		13		—		13
Net Income Attributable to DT Midstream	$	276	$	78	$	354	$	—	$	354

Capital expenditures	73		$	277	$	350	$	—	$	350
Acquisition accounted for as a business combination	$	1,198	$	—	$	1,198	$	—	$	1,198

	December 31, 2024
Investments in equity method investees	$	1,297	$	—	$	1,297	$	—	$	1,297
Total Assets	$	5,274	$	4,661	$	9,935	$	—	$	9,935


	Year Ended December 31, 2023
	Pipeline		Gathering		Total Reportable Segments		Eliminations		Total Consolidated
	(millions)
Revenues
Operating revenues	$	377	$	545	$	922	$	—	$	922
Operating Expenses
Operation and maintenance	55		190		245		—		245
Depreciation and amortization	69		113		182		—		182
Taxes other than income	15		13		28		—		28
Asset (gains) losses and impairments, net	(4)		—		(4)		—		(4)
Other (Income) and Deductions
Interest expense	55		95		150		—		150
Interest income	(1)		—		(1)		—		(1)
Earnings from equity method investees	(177)		—		(177)		—		(177)

Other income	—		(1)		(1)		—		(1)
Income Tax Expense	75		29		104		—		104
Less: Net Income Attributable to Noncontrolling Interests	12		—		12		—		12
Net Income Attributable to DT Midstream	$	278	$	106	$	384	$	—	$	384

Capital expenditures and acquisitions	$	255	$	517	$	772	$	—	$	772

	December 31, 2023
Investments in equity method investees	$	1,762	$	—	$	1,762	$	—	$	1,762
Total Assets	$	4,439	$	4,543	$	8,982	$	—	$	8,982

DT Midstream, Inc.

Notes to Consolidated Financial Statements

NOTE 15 — RELATED PARTY TRANSACTIONS

Transactions between DT Midstream and our equity method investees have been presented as related party transactions in the accompanying Consolidated Financial Statements.

The following is a summary of our balances with related parties:


	December 31,
	2025		2024
	(millions)

Notes receivable from Vector — long-term	$	4	$	4
Current Liabilities — Other	$	1	$	1

DT Midstream had related party transactions presented in Operation and maintenance and Other expense in our Consolidated Statements of Operations during the years ended December 31, 2025, 2024 and 2023 of $2 million, $2 million and $1 million, respectively.

NOTE 16 — ACQUISITION

Midwest Pipeline Acquisition

On December 31, 2024, we closed on the Midwest Pipeline Acquisition of three FERC-regulated interstate natural gas transmission pipelines from ONEOK for a preliminary purchase price of $1.2 billion, which was subject to certain customary purchase price adjustments. Under the terms of the agreement, DT Midstream acquired 100% operating ownership in Guardian, Midwestern and Viking.

The cash consideration provided for the assets acquired was approximately $1.2 billion. The acquisition was accounted for using the acquisition method of accounting for business combinations. Assets acquired and liabilities assumed were measured at estimated fair value at the acquisition date. The FERC-regulated pipelines are subject to rate making and cost recovery provisions and are accounted for under ASC 980 guidance as discussed in Note 17, "Regulatory Matters" to the Consolidated Financial Statements. As such, the fair value of assets acquired and liabilities assumed subject to these provisions approximates their regulated basis, and therefore no fair value adjustments were reflected related to these amounts.

The intangible assets recorded as a result of the acquisition pertain to existing customer relationships, which were valued at approximately $11 million as of the acquisition date. The excess purchase price over the fair value of net assets acquired and liabilities assumed was classified as goodwill.

The preliminary allocation of the purchase price was based on estimated fair values of the assets acquired and liabilities assumed at the date of acquisition, December 31, 2024, and as such, the values assigned were subject to adjustment as additional information became available. During the three months ended June 30, 2025, we received a $10 million working capital adjustment in accordance with the Purchase and Sale Agreement, which reduced the preliminary purchase price by $10 million. During the three months ended June 30, 2025, we recorded other measurement period adjustments resulting in a net increase to goodwill of $5 million due to additional information received during the measurement period. The allocation of the purchase price was finalized during the three months ended September 30, 2025, following the issuance of the acquired entities’ audited 2024 FERC financial statements. No further measurement period adjustments were made.

DT Midstream, Inc.

Notes to Consolidated Financial Statements

The components of the final purchase price allocation as of the acquisition date, reflecting measurement period-adjustments, are as follows:


		December 31,
		2024
		(millions)
Assets
	Accounts receivable	$	19
	Other current assets	10
	Property, plant, and equipment, net	933
	Goodwill	308
	Customer relationship intangible assets	11
	Regulatory assets	10
	Other assets	17
		$	1,308

Liabilities
	Accounts payable	$	12
	Property taxes payable	5
	Other current liabilities	3
	Regulatory liabilities	90
	Other liabilities	10
		$	120
Total cash consideration		$	1,188

NOTE 17 — REGULATORY MATTERS

Significant Accounting Policy – Regulation

Guardian, Midwestern and Viking are subject to rate regulation and accounting requirements of FERC. The regulated operations of each of these subsidiaries have rates that are (i) established by independent, third-party regulators, (ii) set at levels that will recover our costs when considering the demand and competition for our services and (iii) charged to and collectible from our customers. Accordingly, we follow the accounting for regulated operations as defined in ASC 980 for these pipelines, which results in differences in the application of GAAP between our regulated and non-regulated businesses. During the rate-making process, FERC sets the framework for what we can charge to and collect from our customers for our services and establish the manner that our costs are accounted for, including allowing us to defer recognition of certain costs and permitting cost recovery through rates over time as opposed to expensing such costs as incurred. Examples include costs for fuel and losses, contributions in aid of construction, charges for depreciation, gains or losses on disposition of assets and deferral of tax benefits related to changes in tax rates.

Regulatory Assets and Liabilities

Under ASC 980, our regulated operations are required to record regulatory assets and liabilities for certain transactions that would have been treated as revenue or expense in non-regulated businesses. Future regulatory changes could result in changes in the amounts of regulatory assets and liabilities or the discontinuance of this accounting treatment for regulatory assets and liabilities and may require the write-off of the portion of any regulatory asset or liability that is no longer probable of recovery through regulated rates. Actions by regulatory authorities could also have an effect on the amounts we charge to and collect from our customers. Any difference in the amounts recoverable or deferred is recorded as income or expense at the time of regulatory action.

Continued applicability of regulatory accounting treatment requires that rates be designed to recover specific costs of providing regulated services and be charged to and collected from customers. We believe that currently available facts support the continued use of regulatory accounting and that all regulatory assets and liabilities are recoverable or refundable in the current regulatory environment. Regulatory assets are included in Other Assets – Other on our Consolidated Statements of Financial Position.

DT Midstream, Inc.

Notes to Consolidated Financial Statements

The following includes balances and descriptions of our regulatory assets and liabilities:


	December 31,
	2025		2024
			(millions)
Regulatory Assets
Recoverable income taxes related to AFUDC equity	$	9	$	7
Load Management Services Cost Recovery Mechanism	3		2
Electric Cost Tracker	3		—
Other regulatory assets	—		1
	$	15	$	10

Regulatory Liabilities
Refundable federal income taxes	$	77	$	79
Removal costs liability	13		11

	$	90	$	90

As noted below, certain Regulatory assets for which costs have been incurred were included (or are expected to be included, for costs incurred subsequent to the most recently approved rate case) in the rate base, thereby providing a return on invested costs (except as noted). Certain other Regulatory assets are not included in the rate base but accrue recoverable carrying charges until tariff rates adjusted to collect the assets are billed. Certain Regulatory assets do not result from cash expenditures and therefore do not represent investments included in rate base or have offsetting liabilities that reduce rate base.

Regulatory Assets

•Recoverable income taxes related to AFUDC equity - Accounting standards for income taxes require recognition of a deferred tax liability for the equity component of AFUDC. A Regulatory asset is required for the future increase in taxes payable related to the equity component of AFUDC that will be recovered from customers through future rates over the remaining life of the related property, plant and equipment.

•Load Management Services Cost Recovery Mechanism - The mechanism reconciles the differences between the cost to our pipelines to maintain their line pack gas and the amounts our pipelines receive or pay for such gas to resolve imbalances with customers and pipeline interconnects and as may be otherwise necessary to maintain an appropriate level of line pack for system management purposes. The balance is recovered through an annual update to the LMS tariff rate applied to daily imbalance volumes with counterparties. The recoverable amount is not earning a return or accruing carrying charges.

•Electric Cost Tracker - The mechanism provides for the recovery of electric power costs incurred to operate our electric-driven compressor stations. Under the provisions of the applicable tariff, the tracker balance is reset annually or semi‑annually through adjustments to the Electric Cost Tracker rate, as required, to reflect updated electric cost levels. As the Electric Cost Tracker functions as a pass‑through of actual electric expenditures to customers, the associated regulatory asset is not included in rate base and does not earn a return or accrue carrying charges.

Liabilities

•Refundable federal income taxes - In December 2017, the Tax Cuts and Jobs Acts ("TCJA") was enacted and reduced the corporate income tax rate, effective January 1, 2018. Guardian, Midwestern and Viking remeasured deferred taxes, resulting in a reduction to deferred tax liabilities, to reflect the impact of the TCJA on the cumulative temporary differences expected to reverse after the effective date. Regulatory liabilities were established for the anticipated return to ratepayers of deferred income taxes through reductions in future rates. The current amount of amortization and method for amortization of each pipeline’s Regulatory liability related to the TCJA tax rate change has been determined in each pipeline’s most recent rate proceedings.

•Removal costs liability - The amounts collected from customers to fund future asset removal activities in excess of removal costs incurred. The annual amount accumulated in this liability is based on rates established in the most recent rate proceedings for each pipeline. The rate is multiplied by the depreciable base for each applicable asset category to calculate the annual amount accumulated in this liability.

DT Midstream, Inc.

Notes to Consolidated Financial Statements

Rate Case Settlements

The FERC approval dates for the most recent FERC rate proceedings for Guardian, Midwestern and Viking were February 15, 2023, May 3, 2022 and July 31, 2024, respectively. As of December 31, 2025, there were no open FERC rate proceedings for these pipelines. The most recent approved rate proceeding for Guardian included a max tariff rate reduction of approximately 13%, effective April 1, 2025.

NOTE 18 — SUBSEQUENT EVENT

Dividend Declaration

On February 19, 2026, we announced that our Board of Directors declared a quarterly dividend of $0.88 per share of common stock. The dividend is payable to our stockholders of record as of March 16, 2026 and is expected to be paid on April 15, 2026.

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

None.

Item 9A. Controls and Procedures

(a) Evaluation of disclosure controls and procedures

Management of DT Midstream carried out an evaluation, under the supervision and with the participation of DT Midstream's Chief Executive Officer (CEO) and Chief Financial Officer (CFO), of the effectiveness of the design and operation of DT Midstream's disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) as of December 31, 2025, which is the end of the period covered by this report. Based on this evaluation, DT Midstream's CEO and CFO have concluded that such disclosure controls and procedures are effective in providing reasonable assurance that information required to be disclosed by DT Midstream in reports that it files or submits under the Exchange Act (i) is recorded, processed, summarized, and reported within the time periods specified in the SEC's rules and forms and (ii) is accumulated and communicated to DT Midstream's management, including our CEO and CFO, as appropriate to allow timely decisions regarding required disclosure. Due to the inherent limitations in the effectiveness of any disclosure controls and procedures, management cannot provide absolute assurance that the objectives of our disclosure controls and procedures will be attained.

(b) Management's report on internal control over financial reporting

Management of DT Midstream is responsible for establishing and maintaining adequate internal control over financial reporting as such term is defined in Exchange Act Rules 13a-15(f) and 15d-15(f). Internal control over financial reporting is a process designed by, or under the supervision of, DT Midstream's CEO and CFO, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.

On December 31, 2024, DT Midstream completed the acquisition of three FERC-regulated natural gas transmission pipelines (the "Midwest Pipeline Acquisition"). The operations and related processes of the wholly-owned subsidiaries acquired in the Midwest Pipeline Acquisition were integrated into DT Midstream's internal control over financial reporting framework during 2025 and were included in management's assessment of internal control over financial reporting as of December 31, 2025.

Management of DT Midstream has assessed the effectiveness of DT Midstream’s internal control over financial reporting as of December 31, 2025. In making this assessment, management used the criteria issued by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control - Integrated Framework (2013). Based on this assessment, DT Midstream's management concluded that, as of December 31, 2025, DT Midstream’s internal control over financial reporting was effective.

The effectiveness of DT Midstream's internal control over financial reporting as of December 31, 2025 has been audited by PricewaterhouseCoopers, LLP, an independent registered public accounting firm, as stated in their report which appears herein.

There have been no changes in our internal control over financial reporting during the quarter ended December 31, 2025 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Item 9B. Other Information

During the three months ended December 31, 2025, none of the Company’s directors or executive officers adopted, modified or terminated any contract, instruction or written plan for the purchase or sale of the Company’s common stock that was intended to satisfy the affirmative defense conditions of Exchange Act Rule 10b5-1(c) or any "non-Rule 10b5-1 trading arrangement."

Item 9C. Disclosure Regarding Foreign Jurisdictions that Prevent Inspections

Not applicable.

PART III

Information required of DT Midstream by Part III (Items 10, 11, 12, 13 and 14) of this Form 10-K is incorporated by reference from DT Midstream's definitive Proxy Statement for our 2026 Annual Meeting of Common Shareholders to be held May 5, 2026. The Proxy Statement will be filed with the SEC pursuant to Regulation 14A not later than 120 days after the end of DT Midstream's fiscal year covered by this report on Form 10-K. The sections of the Proxy Statement from which such information is incorporated by reference are identified below.

Item 10. Directors, Executive Officers, and Corporate Governance

The information required by this item is incorporated by reference from the following sections of the Proxy Statement:

•"Board of Directors"

•"Corporate Governance"

•"Management"

Item 11. Executive Compensation

The information required by this item is incorporated by reference from the section titled "Executive Compensation."

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

The information required by this item with respect to security ownership of certain beneficial owners and management is incorporated by reference from the section titled "Security Ownership of Certain Beneficial Owners and Management."

Information regarding securities authorized for issuance under equity compensation plans is included in Part II, Item 5 of this Form 10‑K under the caption “Securities Authorized for Issuance Under Equity Compensation Plans."

Item 13. Certain Relationships and Related Transactions, and Director Independence

The information required by this item is incorporated by reference from the following sections of the Proxy Statement:

•"Certain Relationships and Related Party Transactions"

•"Director Independence and Categorical Standards"

Item 14. Principal Accountant Fees and Services

The information required by this item is incorporated by reference from the following sections of the Proxy Statement:

•"Proposal 2 — Ratification of Appointment of Independent Registered Public Accounting Firm"

•"Audit Committee Report"

PART IV

Item 15. Exhibits and Financial Statement Schedules

A.The following documents are filed as part of this Annual Report on Form 10-K.

(a)Consolidated Financial Statements. See "Item 8—Financial Statements."

(b)Financial Statement Schedules. Financial statement schedules listed under the SEC rules are omitted because they are not applicable, or the required information is provided in the Notes to Consolidated Financial Statements in Item 8 of this Form 10-K.

(c)Exhibits.


Exhibit Number						Description
						(i) Exhibits filed herewith:

21.1						Subsidiaries of DT Midstream, Inc.

23.1						Consent of PricewaterhouseCoopers LLP

31.1						Chief Executive Officer Section 302 Form 10-K Certification of Periodic Report

31.2						Chief Financial Officer Section 302 Form 10-K Certification of Periodic Report

95.1						Mine Safety Disclosure

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101.CAL						XBRL Taxonomy Extension Calculation Linkbase

101.DEF						XBRL Taxonomy Extension Definition Database

101.LAB						XBRL Taxonomy Extension Label Linkbase

101.PRE						XBRL Taxonomy Extension Presentation Linkbase

104						Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)

						(ii) Exhibits furnished herewith:

32.1						Chief Executive Officer Section 906 Form 10-K Certification of Periodic Report

32.2						Chief Financial Officer Section 906 Form 10-K Certification of Periodic Report

						(iii) Exhibits incorporated by reference:

2.1						Separation and Distribution Agreement, dated June 25, 2021, between DTE Energy Company and DT Midstream, Inc. (incorporated by reference to Exhibit 2.1 to DT Midstream’s Current Report on Form 8-K filed on July 1, 2021)

3.1						Amended and Restated Certificate of Incorporation of DT Midstream, Inc., effective July 1, 2021 (incorporated by reference to Exhibit 3.1 to DT Midstream's Current Report on Form 8-K filed on July 1, 2021)

3.2						Amended and Restated Bylaws of DT Midstream, Inc., effective July 1, 2021 (incorporated by reference to Exhibit 3.2 to DT Midstream's Current Report on Form 8-K filed on July 1, 2021)

4.1						First Supplemental Indenture, dated as of January 30, 2025, among DT Midstream, Inc., the Guaranteeing Subsidiaries and U.S. Bank Trust Company, National Association, as trustee (incorporated by reference to Exhibit 4.1 to DT Midstream's Annual Report on Form 10-K filed on February 26, 2025)

4.2						Second Supplemental Indenture, dated as of January 30, 2025, among DT Midstream, Inc., the Guaranteeing Subsidiaries and U.S. Bank Trust Company, National Association, as trustee and Notes Collateral Agent (incorporated by reference to Exhibit 4.2 to DT Midstream's Annual Report on Form 10-K filed on February 26, 2025)


Exhibit Number						Description

						(iii) Exhibits incorporated by reference:


4.3						First Supplemental Indenture, dated as of January 30, 2025, among DT Midstream, Inc., the Guaranteeing Subsidiaries and U.S. Bank Trust Company, National Association, as trustee and Notes Collateral Agent (incorporated by reference to Exhibit 4.3 to DT Midstream's Annual Report on Form 10-K filed on February 26, 2025)

4.4						Description of Securities (incorporated by reference to Exhibit 4.1 to DT Midstream's Annual Report on Form 10-K filed on February 16, 2024)

4.5						Indenture dated as of June 9, 2021 among DT Midstream, the Guarantors and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to DT Midstream's Current Report on Form 8-K filed on June 10, 2021)

4.6						Indenture, dated as of April 11, 2022, among DT Midstream, Inc., the Guarantors and U.S. Bank Trust Company, National Association, as trustee (incorporated by reference to Exhibit 4.1 to DT Midstream's Current Report on Form 8-K filed April 11, 2022)

4.7						Pari Passu Intercreditor Agreement, dated as of April 11, 2022, among DT Midstream, Inc., the Guarantors, Barclays Bank PLC, as Credit Agreement Agent, and U.S. Bank Trust Company, National Association, as Notes Collateral Agent (incorporated by reference to Exhibit 4.2 to DT Midstream's Current Report on Form 8-K filed April 11, 2022)

4.8						First Supplemental Indenture, dated as of August 12, 2024, among DT Midstream, Inc., the Guarantors and U.S. Bank Trust Company, National Association, as Trustee and Notes Collateral Agent (incorporated by reference to Exhibit 4.4 to DT Midstream's Quarterly Report on Form 10-Q filed on October 29, 2024)

4.9						Indenture, dated as of December 6, 2024, among DT Midstream, Inc., the Guarantors and U.S. Bank Trust Company, National Association, as Trustee and Notes Collateral Agent (incorporated by reference to Exhibit 4.1 to DT Midstream's Current Report on Form 8-K filed on December 6, 2024)

10.1*						Form of Amended and Restated Change-In-Control Severance Agreement (incorporated by reference to Exhibit 10.1 to DT Midstream's Annual Report on Form 10-K filed on February 16, 2024)

10.2						Credit Agreement, dated as of June 10, 2021 by and among DT Midstream, as borrower, the Lenders party thereto, the L/C Issuers party thereto, and Barclays Bank PLC, as Administrative Agent and Collateral Agent (incorporated by reference to Exhibit 10.1 to DT Midstream's Current Report on Form 8-K filed on June 10, 2021)

10.3						Tax Matters Agreement, dated June 25, 2021, between DTE Energy Company and DT Midstream, Inc. (incorporated by reference to Exhibit 10.2 to DT Midstream’s Current Report on Form 8-K filed on July 1, 2021)

10.4						DT Midstream, Inc. Long-Term Incentive Plan (incorporated by reference to Exhibit 10.4 to DT Midstream’s Registration Statement on Form 10-12B (File No. 001-40392), filed on May 7, 2021)

10.5						DT Midstream, Inc. Supplemental Savings Plan (incorporated by reference to Exhibit 10.1 to DT Midstream’s Annual Report on Form 10-K filed on February 16, 2023)

10.6						Form of Severance Agreement (incorporated by reference to Exhibit 10.5 to DT Midstream’s Current Report on Form 8-K filed on July 1, 2021)

10.7						DT Midstream, Inc. Annual Incentive Plan (incorporated by reference to Exhibit 10.6 to DT Midstream’s Current Report on Form 8-K filed on July 1, 2021)


10.8						First Incremental Revolving Facility Amendment and Amendment No. 1 to Credit Agreement and Collateral Agreement, by and among DT Midstream, Inc., the lenders and letter of credit issuers party thereto and Barclays Bank PLC, as administrative agent and collateral agent, dated as of October 19, 2022 (incorporated by reference to Exhibit 10.1 to DT Midstream's Current Report on Form 8-K filed on October 20, 2022)
Exhibit Number						Description

						(iii) Exhibits incorporated by reference:

10.9						Amendment No. 2 to Credit Agreement, by and between DT Midstream, Inc., and Barclays Bank PLC, as administrative agent and collateral agent, dated as of June 27, 2023 (incorporated by reference to Exhibit 10.1 to DT Midstream's Current Report on Form 8-K filed on June 29, 2023)

10.10						Amendment No. 3 to Credit Agreement, by and between DT Midstream, Inc., and Barclays Bank PLC, as administrative agent and collateral agent, and the lenders party thereto, dated as of November 25, 2024 (incorporated by reference to Exhibit 10.1 to DT Midstream's Current Report on Form 8-K filed on November 27, 2024)

10.11						Amendment No. 4 to Credit Agreement, by and between DT Midstream, Inc., the guarantors party thereto and Barclays Bank PLC, as administrative agent and collateral agent, dated as of December 12, 2024 (incorporated by reference to Exhibit 10.1 to DT Midstream's Current Report on Form 8-K filed on December 12, 2024)

10.12						Purchase and Sale Agreement, dated November 19, 2024, by and among DT Midstream, Inc., DTM Interstate Transportation, LLC, ONEOK Partners Intermediate Limited Partnership and Border Midwestern Company (incorporated by reference to Exhibit 10.1 to DT Midstream’s Current Report on Form 8-K filed on November 19, 2024)

19.1						DT Midstream, Inc. Insider Trading Policy, dated June 1, 2023 (incorporated by reference to Exhibit 19.1 to DT Midstream’s Annual Report on Form 10-K filed on February 16, 2024)

97.1						DT Midstream, Inc. Clawback Policy, dated September 19, 2023 (incorporated by reference to Exhibit 97.1 to DT Midstream’s Annual Report on Form 10-K filed on February 16, 2024)

* Certain portions of this exhibit have been redacted pursuant to Item 601(b)(10)(iv) of Regulation S-K. The registrant agrees to furnish supplementally an unredacted copy of the exhibit to the Securities and Exchange Commission upon its request

Item 16. Form 10-K Summary

None.

Signatures

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, DT Midstream, Inc. has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.


Date:	February 19, 2026
			DT MIDSTREAM, INC.
			(Registrant)

		By:	/S/ DAVID J. SLATER
			David J. Slater Chief Executive Officer, and Executive Chairman of DT Midstream, Inc.

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of DT Midstream, Inc. and in the capacities and on the date indicated.

By:

/S/ DAVID J. SLATER

By:

/S/ JEFFREY A. JEWELL

David J. Slater
Chief Executive Officer,
and Executive Chairman
(Principal Executive Officer)

Jeffrey A. Jewell
Executive Vice President,
and Chief Financial Officer
(Principal Financial Officer)

By:

/S/ JOSEPH P. FINLAND

By:

/S/ ANGELA ARCHON

Joseph P. Finland
Chief Accounting Officer
(Principal Accounting Officer)

Angela Archon, Director

By:

/S/ STEPHEN BAKER

By:

/S/ ELAINE PICKLE

Stephen Baker, Director

Elaine Pickle, Director

By:

/S/ ROBERT C. SKAGGS, JR.

By:

/S/ PETER TUMMINELLO

Robert C. Skaggs, Jr., Director

Peter Tumminello, Director

By:

/S/ DWAYNE WILSON

By:

Dwayne Wilson, Director

Date: February 19, 2026

DT Midstream - 10-K annual report 2025

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