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

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

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 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, 2023, the aggregate market value of DT Midstream's voting common stock was approximately $4.8 billion (based on the New York Stock Exchange closing price on such date).

Number of shares of common stock outstanding at February 8, 2024:

Description						Shares
Common stock, par value $0.01						96,979,556

Certain information in DT Midstream's definitive Proxy Statement for our 2024 Annual Meeting of Common Shareholders to be held May 10, 2024, 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.

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:

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," 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;

•global supply chain disruptions;

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

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

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

•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;

•the price and availability of debt and equity financing;

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

•the effectiveness of the Company's 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 conflicts in 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;

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

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

•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.

Items 1. and 2. Business and Properties

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.

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, lateral pipelines including related treatment plants 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.

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.

During the year ended December 31, 2023, DT Midstream's accomplishments and business developments included:

•Attained Net Income Attributable to DT Midstream of $384 million;

•Declared total cash dividends of $2.76 per common share;

•Completed the conversion of the Michigan System from gathering to dry gas transmission service and began providing services under a new long-term dry gas transmission contract;

•Placed the LEAP phase 1 and phase 2 expansions into service early;

•Continued construction of the LEAP phase 3 expansion;

•Executed a commercial agreement and completed construction of a new gathering trunkline for Ohio Utica Gathering;

•Completed construction of 0.4 Bcf/d of new treating capacity for Blue Union Gathering;

•Continued construction of the Appalachia Gathering phase 2 expansion;

•Began construction of a new 1.0 Bcf/d LEAP interconnect with the Gillis Access Project, which will provide access to the Louisiana industrial and LNG corridor;

•Began construction on a new 0.4 Bcf/d supply interconnect with a third-party processing plant in Blue Union Gathering;

•Published our second annual Corporate Sustainability Report in the second quarter 2023. The information in our Corporate Sustainability Report is not incorporated by reference into this Form 10-K; and

•Advanced the carbon capture and sequestration project in Louisiana through filing the Class V test well permit application with the Louisiana Department of Natural Resources; the permit was received in January 2024.

Our principal business objective is to safely and reliably operate and develop 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 serving high quality, low cost resources with proximity to strong demand centers, 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 natural gas basins in which we operate.

•Pursue economically attractive opportunities. We intend to pursue economically attractive expansion 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.

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.

Southwestern Energy accounted for approximately 60% of our operating revenues for the year ended December 31, 2023. Our operating revenues do not include revenues of unconsolidated joint ventures accounted for as equity method investments.

Our Pipeline segment includes our interstate pipelines, intrastate pipelines, storage systems, lateral pipelines including related treatment plants 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 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.

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, 2023, approximately 84% of our Pipeline revenue was generated under firm service revenue contracts and approximately 95% 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, 2023, revenue from the Pipeline segment accounted for approximately 41% 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.

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 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, respectively.

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

Property Classification

% Owned

Operator

Capacity (Bcf/d)

Compression Horsepower

Description

Location

Pipeline

FERC-Regulated Interstate Pipelines

NEXUS (a)

50%

No

1.4

99,137

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

OH and MI

Vector (a)

40%

No

2.8

120,000

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

IL, IN, MI and Ontario

Millennium (a)

52.5%

No

1.9

84,389

A joint venture that owns a 263-mile pipeline and compression facilities serving markets in the northeast and supply from the northeast Marcellus region

NY

Birdsboro

100%

Yes

0.2

—

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

PA

Intrastate Pipelines

Generation

50%

No

0.4

—

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

OH

FERC-Regulated Storage System

Washington 10 Storage Complex (b)

91%

Yes

N/A

26,205

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

MI

Lateral Pipelines

Bluestone

100%

Yes

1.2

36,720

A 65-mile pipeline and two compression facilities delivering Marcellus shale natural gas to Millennium and the Tennessee Pipeline

PA and NY

LEAP

100%

Yes

1.7

18,000

A 209-mile pipeline delivering Haynesville shale natural gas to markets in the Gulf Coast region

LA

Stonewall

85%

Yes

1.5

—

A 68-mile pipeline delivering Marcellus and Utica shale natural gas to the Columbia Pipeline

WV

Michigan System

100%

Yes

0.8

2,400

A 335-mile pipeline system in northern Michigan

MI

__________________________________

(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 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.

During the three months ended March 31, 2023, DT Midstream completed the conversion of the Michigan System from gathering to dry gas transmission service and began providing services under a new long-term dry gas transmission contract. For the year ended December 31, 2023, the Michigan System financial results are presented in the Pipeline segment. The prior years' comparative activity was for gathering services and therefore was not revised from presentation in the Gathering segment.

In August 2023, we placed the LEAP phase 1 expansion into service early; and, in January 2024, we placed the LEAP phase 2 expansion into service early. During the year ended December 31, 2023, we continued the LEAP phase 3 expansion, which will increase the capacity to 1.9 Bcf/d and will provide additional access to LNG export terminals. Additionally, during the year ended December 31, 2023, we began construction of a new 1.0 Bcf/d LEAP interconnect with the Gillis Access Project, which will provide access to the Louisiana industrial and LNG corridor and is expected to be placed into service in the second quarter 2024.

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

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.

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, 2023, 58% and 25% of our Gathering segment revenue was generated under firm revenue contracts and flowing gas, respectively.

For the years ended December 31, 2023 and 2022, average throughput from the Gathering segment was 3.0 Bcf/d and 3.1 Bcf/d, respectively. For the year ended December 31, 2023, revenue from the Gathering segment accounted for approximately 59% of our consolidated revenue.

Our Gathering operations compete for customers based on 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.

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

Property Classification

% Owned

Operator

Capacity (Bcf/d)

Compression Horsepower

Description

Location

Gathering

Susquehanna Gathering

100%

Yes

1.4

97,005

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

PA

Blue Union Gathering

100%

Yes

2.6

78,000

A 420-mile gathering system delivering shale natural gas from the Haynesville formation of Louisiana to markets in the Gulf Coast region; ancillary services include water impoundment, water transportation, water disposal, and sand mining

LA and TX

Appalachia Gathering

100%

Yes

1.0

81,305

A 149-mile gathering system delivering Marcellus shale natural gas to the Texas Eastern Pipeline and Stonewall

PA and WV

Tioga Gathering

100%

Yes

0.1

—

A 3-mile gathering system delivering shale natural gas to Eastern Gas Transmission and Storage

PA

Ohio Utica Gathering

100%

Yes

0.1

10,000

A 20-mile gathering system, including compression and dehydration facilities, to deliver Utica shale gas from producer wells to a nearby processing plant

OH

During the year ended December 31, 2023, DT Midstream executed a commercial agreement and completed construction of the trunkline of Ohio Utica Gathering. The initial portions of the system were placed into service in the fourth quarter 2023, and future facilities are expected to be placed into service in the first half of 2024. Additionally, we added 0.4 Bcf/d of new treating capacity to Blue Union Gathering. We also began construction on a new 0.4 Bcf/d supply interconnect with a third-party processing plant to Blue Union Gathering, which is expected to be placed into service in the second quarter 2024. During the year ended December 31, 2023, we also continued the expansion of Appalachia Gathering.

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.

DT Midstream recognizes that being innovative is necessary for our continued growth. We currently employ 402 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 and office locations in Michigan, Pennsylvania, Ohio, West Virginia, Louisiana, and Texas. None of our employees are covered by collective bargaining agreements. We believe that our employee relations are good.

DT Midstream is committed to building a diverse, empowered, and engaged team that delivers safe and reliable service to our customers. Rather than having DEI solely as a stand-alone program, we integrate these practices into our overall operating model. We review DEI performance in several ways:

•Diversity of interviewees, hires, high potential talent, and leadership promotions;

•Workforce representation of women, minorities, and employees with disabilities based on voluntary self-identification information; and

•Employee engagement, including specific programs focused on a culture of belonging.

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.

Our human capital resources objectives include recruiting, incentivizing, fostering belonging, and retaining top talent. To achieve this, we offer our 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, please see "Annual and Long-Term Incentives" in the Compensation Discussion and Analysis section of our Proxy Statement.

For additional information on our approach to managing our human capital resources, see our 2023 Corporate Sustainability Report on our website. The information in our Corporate Sustainability Report is not incorporated by reference into this Form 10-K.

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. We cannot predict whether any such additional rules or legislation will be promulgated or enacted, or what effect, if any, such changes might have on our operations, however the industry could be required to incur additional capital expenditures and increased costs depending on future legislative and regulatory changes.

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, Vector, Millennium, Birdsboro, NEXUS, 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. 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. Generally, such recourse rates are based on the cost of providing service, including recovery of and a return on the pipeline’s cost of capital. 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 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. 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 $1,544,521 per violation per day (as adjusted for inflation for 2024), and violators may be subject to criminal penalties of up to $1 million per violation per day and five years in prison.

To the extent that an intrastate pipeline system transports natural gas in interstate commerce, the rates, terms and conditions of such interstate transportation service are subject to FERC rules and regulations under Section 311 of the NGPA. Non-compliance with FERC’s rules and regulations established under Section 311 of the NGPA could result in the imposition of civil and criminal penalties. The EPAct 2005 also amended the NGPA to give FERC authority to impose civil penalties for violations of the NGPA up to $1,544,521 per violation per day (as adjusted for inflation for 2024), and violators may be subject to criminal penalties of up to $1 million per violation and five years in prison.

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.

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.

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 2024, is currently up to a maximum of $1,544,521 per violation per day.

In addition, the CFTC is directed under the Commodities Exchange Act to prevent price manipulations for 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 $1.4 million (as adjusted for inflation for 2024) or triple the monetary gain to the violator for violations of the anti-market manipulation sections of the Commodities Exchange Act.

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, operator qualification as well as requirements for integrity management on certain pipelines. The integrity management programs 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 maximum allowable operating pressure and establishes new "Moderate Consequence Areas" for determining regulatory requirements for gas transmission pipeline segments outside of HCAs. The rule also establishes new requirements for conducting baseline assessments and 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 or our operations to be affected any differently than other similarly situated midstream companies.

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 or our operations to be affected any differently than similarly situated midstream companies.

Additionally, 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 or our operations to be affected any differently than similarly situated midstream companies.

PHMSA is in the process of developing other regulations to address congressional mandates set forth in the 2020 PIPES Act and for other purposes. For example, 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. PHMSA is also in the process of developing inspection and maintenance requirements for idled pipelines and revising regulations applicable to requirements for operators in response to certain class location changes. Congress was due to reauthorize the Pipeline Safety Act in 2023, but that process has been delayed until 2024. Through reauthorization of the Pipeline Safety Act, Congress may pass a bill that mandates other statutory changes or directs PHMSA to develop additional rulemaking. The adoption of these new PHMSA rules could impact our pipeline assets and operations by requiring the installation of new or modified safety controls and the implementation of new capital projects or accelerated maintenance programs, all of which could require us to incur increased operational costs that could be significant. 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 regulations, 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 $266,000 per day for each violation and approximately $2.66 million for a related series of violations (as adjusted for inflation in 2024). This maximum penalty authority established by statute will continue to be adjusted periodically to account for inflation.

We believe that 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.

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.

We believe that 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.

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 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 believe that 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 published 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. 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. Beginning in calendar year 2024, the statute authorizes the EPA to impose and collect 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. 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 and remain under consideration by FERC. If the policy statements come into effect as written, GHG emissions and climate-related considerations could play a more significant role in FERC’s analysis of projects under its jurisdiction, including projects that do or would supply gas to the Company’s facilities.

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 drilling schedules and production volumes and reduce the volumes delivered to us and 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. Despite these recent changes, the definition remains subject to litigation, with opponents arguing it is not sufficiently narrow. While recent changes to the definition may ease permitting in certain circumstances, continued controversy over the WOTUS definition may result in 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. On April 20, 2022, the White House Council on Environmental Quality (the "Council") published a final rule amending its existing regulations governing the implementation of NEPA by federal agencies. The amendments principally address definitions relating to environmental effects and alternatives that require agency consideration. On January 9, 2023, the Council published interim guidance, effective immediately, that addresses how federal agencies should consider GHG emissions and climate change when conducting reviews under NEPA. The interim guidance recommends that agencies quantify GHG emissions and then use an algorithm to translate the emissions into an expected social cost. On June 3, 2023, the federal government enacted the Fiscal Responsibility Act of 2023, which includes amendments to NEPA concerning the scope and scientific basis of impact analysis, the duration of impact reviews, and other matters. On July 31, 2023, the Council published a second proposed rule, further amending its NEPA implementing regulations. This regulatory proposal addresses a wide range of topics, including the implementation of the statutory amendments passed in 2023 and the replacement of numerous regulatory measures adopted during the prior presidential administration. The Council’s rulemaking and policy efforts, including the 2023 proposed rule if finalized, could permit or require agencies to undertake more searching inquiries during their NEPA reviews of new projects that require federal permits.

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. For example, the EPA finalized regulations under the Clean Water Act in June 2016 prohibiting wastewater discharges from hydraulic fracturing and certain other natural gas operations to publicly owned wastewater treatment plants. 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 August 2022, the EPA issued a proposed rule to amend the Risk Management Program's implementing regulations. The final rule, if issued, may impose new requirements that increase our cost of compliance or require changes to our internal programs and policies to comply with the Risk Management Program.

We believe that 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

Any significant decrease in demand or in production 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., Eastern Canada, Northeastern U.S. and Gulf Coast regions. A reduction in the natural gas volumes supplied by producers could result in reduced throughput on our systems and corresponding service revenues. 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.

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, which could materially adversely affect our business, financial condition and results of operations.

Southwestern Energy accounted for approximately 60% of our operating revenues for the year ended December 31, 2023. 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.

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.

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., Eastern 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, 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 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.

Even if we complete expansion projects or acquisitions that we believe will be accretive, these expansion projects or acquisitions may nevertheless reduce our cash from operations and could materially adversely affect our business, financial condition and results of operations. Any expansion project or acquisition 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 or acquisitions on schedule or within the budgeted cost; (iv) the assumption of unknown liabilities when making acquisitions 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 or acquire; (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 conduct a meaningful portion of our operations through joint ventures with third parties, including through our interests in Vector, Millennium, NEXUS and Generation, 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, 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 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.

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, due in part to state and local concerns related to unregulated exploration and production and gathering activities in new production areas, including the Marcellus/Utica formations. In addition, FERC is considering modifying its policy governing the issuance of interstate natural gas pipeline authorizations, in part to address concerns about climate change. 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.

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.

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.

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 market 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, and we may be required to make prepayments or provide security to satisfy credit concerns.

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

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 (including our key customer, Southwestern Energy). 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.

As of December 31, 2023, we had outstanding approximately $2.1 billion of senior notes, $600 million of senior secured notes, $399 million of indebtedness under our Term Loan Facility and $165 million of 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, our Term Loan 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.

Our Term Loan Facility and borrowings under our Revolving Credit Facility have, and we may in the future enter into debt instruments with, variable interest rates. Beginning early in 2022, in response to growing signs of inflation, the Federal Reserve has increased interest rates rapidly. Increases in interest rates on variable rate debt will increase our interest expense unless we make arrangements to hedge the risk of rising interest rates. 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.

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.

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 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".

Inflationary pressure could adversely impact our profitability. Our operating costs have increased with the market and may continue to increase, due to the recent growth in inflation which has impacted 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 result in downward pressure on our results of operations.

We annually review the carrying value of goodwill associated with business combinations we have made for impairment. Our intangible assets and goodwill 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 or goodwill 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.

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.

Certain state and U.S. federal regulatory agencies are also 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.

Furthermore, the tax laws, rules and regulations that affect our customers are subject to change. For example, Pennsylvania’s former governor has historically proposed legislation to impose a state severance tax on the extraction of natural resources, including natural gas produced from the Marcellus/Utica formations, either in replacement of or in addition to the existing state impact fee. Pennsylvania’s legislature has not thus far advanced any of the governor’s severance tax proposals; however, severance tax legislation may continue to be proposed in future legislative sessions. Any such tax increase or change could adversely impact the earnings, cash flows and financial position of our customers and cause them to reduce their drilling in the areas in which we operate.

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 frequently 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 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. federal 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. 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. For example, an Executive Order was issued on January 27, 2021 ("Tackling the Climate Crisis at Home and Abroad") that included provisions directing the Secretary of the Interior to pause approval of new oil and natural gas leases on public lands pending completion of a comprehensive review and reconsideration of U.S. federal oil and gas permitting and leasing practices and directing the heads of U.S. federal agencies to take steps to ensure that, to the extent consistent with applicable law, federal funding is not directly subsidizing fossil fuels. In July 2021, however, a Federal Court in Louisiana granted a nationwide preliminary injunction against enforcement of the moratorium. On appeal, the injunction was overturned. However, a short time later, the Federal Court in Louisiana issued a nationwide permanent injunction against enforcement of the moratorium. Litigation related to the moratorium continues in various courts. While lease sales continue to some extent, they have been scaled back and are subject to challenge by environmental groups. On November 26, 2021 the Department of the Interior issued a report calling for an increase in royalty payments for new oil and gas leases on federal lands and other measures. Royalty rates have been increased for new leases. In November 2022, the Department of the Interior issued a proposed rule that would strictly limit releases of methane from oil and gas drilling on public lands. This 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. On January 26, 2024, the federal government announced a temporary pause on the authorization of new LNG terminals. During this pause, the U.S. Department of Energy will update the underlying analyses for LNG export authorizations. The pause could delay approximately a dozen LNG projects that are pending or in various stages of planning.

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 present a danger to public health and the environment, 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. Other actions that could be pursued by the current Administration may include the imposition of more restrictive requirements for the establishment of pipeline infrastructure, or the extension of the current pause on new LNG terminals or the current pause leading to a ban. Such regulations or 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, 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 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. Vector, Millennium, Birdsboro, NEXUS, 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. FERC is currently considering modifications to its long-standing Certificate Policy Statement that currently governs its granting of certificate authority for the construction of proposed interstate natural gas infrastructure, whether new or expanded. 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.

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.

We believe that our non-jurisdictional natural gas gathering facilities, including those which we refer to as "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 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.

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. For example, significant changes to the U.S. tax laws have been proposed, including, among others, an increase in the corporate tax rate and the imposition of a tax on the fair market value of stock that is repurchased by certain corporations. 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.

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.

The U.S. Department of Transportation, through PHMSA, has adopted regulations requiring pipeline operators to develop integrity management programs for transportation pipelines located where a leak or rupture could do the most harm in a high consequence area, referred to as 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 what are referred to as moderate consequence areas or 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 systems, particularly our Northern Michigan assets and our storage assets, have been in operation for many years, with some portions being more than 40 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.

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 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.

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, increasing 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 are increasingly 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. Increasing attention to climate change and environmental conservation may 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 increasing attention and 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 developed ratings systems for evaluating companies on their approach to ESG matters. Unfavorable ESG ratings may lead to increased 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 second annual Corporate Sustainability Report in the second quarter 2023, 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 more expansive 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.

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. 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 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 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.

A global or national public health crisis may cause disruptions to our business and operational plans. Some factors from a health crisis that could materially adversely affect our business, financial condition and results of operations include: third-party effects, including contractual and counterparty risk; litigation risk and possible loss contingencies; employee matters and insurance arrangements; supply/demand market and macroeconomic forces; lower commodity prices; unavailable storage capacity and operational effects; decreased utilization and rates for our assets and services; impact on liquidity and access to capital markets; our ability to comply with our covenants and other restrictions in agreements governing our debt; workforce reductions and furloughs; cybersecurity threats; operational, health or safety-related incidents; global supply chain disruptions; and U.S. federal, state and local actions.

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.

In addition, Section 355(e) of the Internal Revenue Code generally creates a presumption that the Distribution would be taxable to DTE Energy, but not to shareholders, if we or our shareholders were to engage in transactions that result in a 50% or greater change by vote or value in the ownership of our common stock during the four-year period beginning on the date that begins two years before the date of the Distribution, unless it were established that such transactions and the Distribution were not part of a plan or series of related transactions giving effect to such a change in ownership. If the Distribution were taxable to DTE Energy due to such a 50% or greater change in ownership of our stock, DTE Energy would recognize a gain equal to the excess of the fair market value of our common stock distributed to DTE Energy shareholders over DTE Energy’s tax basis in our common stock, and we generally would be required to indemnify DTE Energy for the tax on such gain and related expenses. Any such indemnification obligation could materially adversely affect our business, financial condition and results of operations.

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.

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.

Following the Separation, the management and directors of each of DTE Energy and DT Midstream own common stock in both companies. Robert Skaggs, Jr., who is the chairman of the Board of Directors for DT Midstream, also serves on the board of directors of DTE Energy and may be required to recuse himself from deliberations relating to arrangements between us and DTE Energy. This ownership and directorship overlap could create, or appear to create, potential conflicts of interest when the management and directors of one company face decisions that could have different implications for themselves and the other company. For example, potential conflicts of interest could arise in connection with the resolution of any dispute regarding the terms of the agreements governing our relationship with DTE Energy. These agreements include the Separation and Distribution Agreement, the Transition Services Agreement, the Tax Matters Agreement, the Employee Matters Agreement and any commercial agreements between the parties or their affiliates. Potential conflicts of interest may also arise out of any commercial arrangements that we or DTE Energy may enter into in the future.

For more information on the Separation and Distribution, 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.

Item 1B. Unresolved Staff Comments

None.

Item 1C. Cybersecurity

To identify 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 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. 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. 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, 2023. For more information on how material cybersecurity incidents may impact our business, see Part I, Item 1A. "Risk Factors— Other Business Risks—"A cyberattack or threat could harm our business" of this Form 10-K.

On July 26, 2023, the SEC adopted a final rule requiring, among other things, registrants to disclose certain information regarding cybersecurity risk management, strategy and governance annually and certain information about material cybersecurity incidents within four business days of the incident. The final rule became effective on September 5, 2023.

The Director of Cybersecurity has over 20 years of relevant experience and is responsible for managing our cybersecurity program and team, which monitors the day-to-day risks using the approach described above. 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.

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 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.

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, 2023, there were 96,971,021 shares of DT Midstream common stock issued and outstanding. These shares were held by a total of 39,293 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 5% to 7% annually. For information on DT Midstream's dividend restrictions, see 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.

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. For additional detail, 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, 2023:

			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			974,733						$	—					5,229,267

_____________________________________

(a)Includes 417,294 Restricted Stock Units and 557,439 Performance Share Awards

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 (“S&P 500”) Index, and the Alerian Midstream Energy (“AMNA”) Index. We believe the AMNA Index is meaningful because it is an independent, objective view of the performance of similarly-sized midstream energy companies.

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

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 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.

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

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, 2023 to the year ended December 31, 2022, or the year ended December 31, 2022 to the year ended December 31, 2021, as applicable. The following table summarizes our consolidated financial results:

																														Year Ended December 31,
																														2023						2022						2021
						(millions, except per share amounts)
Operating revenues																														$	922					$	920					$	840
Net Income Attributable to DT Midstream																														384						370						307
Diluted Earnings per Common Share																														$	3.94					$	3.81					$	3.16

The Pipeline segment consists of our interstate pipelines, intrastate pipelines, storage systems, lateral pipelines including related treatment plants and compression and surface facilities. This segment also includes our equity method investments. During the three months ended March 31, 2023, we completed the conversion of the Michigan System from gathering to dry gas transmission service and began providing services under a new long-term dry gas transmission contract. For the year ended December 31, 2023, the Michigan System financial results are presented in the Pipeline segment. The prior years' comparative activity was for gathering services and therefore was not revised from presentation in the Gathering segment.

Pipeline results and outlook are discussed below:

																														Year Ended December 31,
																														2023						2022						2021
						(millions)
Operating revenues																														$	377					$	339					$	307
Operation and maintenance																														55						54						59
Depreciation and amortization																														69						63						63
Taxes other than income																														15						14						13
Asset (gains) losses and impairments, net																														(4)						(6)						—
Operating Income																														242						214						172
Interest expense																														55						57						51
Interest income																														(1)						(1)						(1)
Earnings from equity method investees																														(177)						(150)						(126)
Loss from financing activities																														—						6						—
Other (income) and expense																														—						—						(3)
Income Tax Expense																														75						62						62
Net Income																														290						240						189
Less: Net Income Attributable to Noncontrolling Interests																														12						12						11
Net Income Attributable to DT Midstream																														$	278					$	228					$	178

Operating revenues increased $38 million for the year ended December 31, 2023 primarily due to higher long-term and short-term storage contracting rates at the Washington 10 Storage Complex of $18 million, new transmission service contracts at the Michigan System of $16 million, and new LEAP long-term firm service revenue contracts of $10 million, partially offset by lower volumes at Bluestone of $2 million. Operating revenues increased $32 million for the year ended December 31, 2022 primarily due to higher volumes and rates on LEAP of $21 million, a new customer on Stonewall of $7 million, and higher volumes and rates at the Washington 10 Storage Complex of $4 million.

Operation and maintenance expense increased $1 million for the year ended December 31, 2023 primarily due to new transmission service contracts at the Michigan System, partially offset by increased capitalized labor and overhead. Operation and maintenance expense decreased $5 million for the year ended December 31, 2022 primarily due to lower Separation-related transaction costs of $10 million, partially offset by increased maintenance and labor costs at the Washington 10 Storage Complex of $3 million.

Depreciation and amortization expense increased $6 million for the year ended December 31, 2023 primarily due to new transmission service assets at the Michigan System and new Haynesville System (LEAP) assets placed into service.

Asset (gains) losses and impairments, net increased $6 million for the year ended December 31, 2022 due to a one-time gain realized from a legal settlement with a supplier that occurred in 2022.

Interest expense decreased $2 million for the year ended December 31, 2023 primarily due to higher capitalized interest on higher construction in progress during 2023, partially offset by higher borrowings and rates under the Revolving Credit Facility, higher interest rates on the Term Loan Facility, and a full year of interest expense related to our 2032 Notes. Interest expense increased $6 million for the year ended December 31, 2022 primarily due to higher outstanding borrowings and higher interest rates on our external debt as compared to interest rates on borrowings from DTE Energy prior to the Separation.

Earnings from equity method investees increased $27 million for the year ended December 31, 2023 primarily due to higher earnings from Millennium of $19 million from our higher ownership percentage and a goodwill impairment at Generation of $7 million in 2022. Additionally, NEXUS had increased contract rates and additional customers offset by higher interest expense from new senior unsecured notes. Earnings from equity method investees increased $24 million for the year ended December 31, 2022 primarily due to the Millennium acquisition of $9 million, higher revenues from increased contract rates and additional customers at NEXUS of $15 million and higher westbound contracted volumes at Vector of $4 million, partially offset by a goodwill impairment at Generation of $7 million. On October 7, 2022, DT Midstream closed on the $552 million purchase of an additional 26.25% ownership interest in Millennium from National Grid. 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.

Loss from financing activities decreased $6 million for the year ended December 31, 2023 and increased $6 million for the year ended December 31, 2022 due to the partial repayment of our Term Loan Facility that occurred during the three months ended June 30, 2022. See Note 10, "Debt" to the Consolidated Financial Statements under Part II, Item 8 of this Form 10-K for further details.

Income tax expense increased $13 million for the year ended December 31, 2023 primarily due to higher income before income taxes in 2023. Income tax expense for the years ended December 31, 2023 and 2022 include the impacts of net tax benefits related to state tax rate changes. Income tax expense was unchanged for the year ended December 31, 2022 due to increased Income before income taxes, fully offset by state tax rate changes. See Note 7, "Income Taxes" to the Consolidated Financial Statements under Part II, Item 8 of this Form 10-K for further details.

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 further expansion at the Haynesville System (LEAP) and Stonewall, new contracts at the Washington 10 Storage Complex, and additional growth related to our equity method investments.

The Gathering segment includes gathering systems, related treatment plants and compression and surface facilities. Gathering results and outlook are discussed below:

																														Year Ended December 31,
																														2023						2022						2021
						(millions)
Operating revenues																														$	545					$	581					$	534
Operation and maintenance																														190						213						173
Depreciation and amortization																														113						107						103
Taxes other than income																														13						14						11
Asset (gains) losses and impairments, net																														—						(17)						17
Operating Income																														229						264						230
Interest expense																														95						80						61
Interest income																														—						(2)						(3)
Loss from financing activities																														—						7						—
Other (income) and expense																														(1)						(1)						1
Income Tax Expense																														29						38						42
Net Income Attributable to DT Midstream																														$	106					$	142					$	129

Operating revenues decreased $36 million for the year ended December 31, 2023 primarily due to lower Haynesville System (Blue Union Gathering) revenues of $50 million, lower Michigan System gathering services of $6 million, and lower Susquehanna Gathering volumes of $3 million, partially offset by higher Appalachia Gathering volumes of $21 million driven primarily by new contracts resulting from the expansion in 2023. Lower Blue Union Gathering revenues were driven primarily by lower deficiency fees of $23 million, lower recovery of production-related operating expenses of $12 million, lower rates of $9 million and lower production volumes of $5 million. Operating revenues increased $47 million for the year ended December 31, 2022 primarily due to higher Blue Union Gathering revenues of $42 million and higher volumes on Appalachia Gathering of $5 million. Higher Blue Union Gathering revenues were driven by recovery of production-related operating expenses of $25 million and increased gathering volumes primarily from new contracts of $17 million.

Operation and maintenance expense decreased $23 million for the year ended December 31, 2023 primarily due to lower Haynesville System (Blue Union Gathering) expenses of $14 million driven by lower production-related operating expenses, a reduction in Appalachia Gathering environmental contingent liabilities of $6 million, and increased capitalized labor and overhead of $3 million. Operation and maintenance expense increased $40 million for the year ended December 31, 2022 primarily due to higher Blue Union Gathering and Susquehanna Gathering expenses of $46 million and $2 million, respectively, partially offset by lower Appalachia Gathering expenses of $7 million. Higher Blue Union Gathering expenses were driven by planned maintenance and increased production-related operating expenses recovered from customers. Higher public company costs were mostly offset by lower Separation-related transaction costs of $10 million.

Depreciation and amortization expense increased $6 million for the year ended December 31, 2023 primarily due to new Blue Union Gathering and Appalachia Gathering assets placed into service. Depreciation and amortization expense increased $4 million for the year ended December 31, 2022 primarily due to new Blue Union Gathering and Susquehanna Gathering assets placed into service.

Asset (gains) losses and impairments, net decreased $17 million for the year ended December 31, 2023 due to the 2022 one-time gain on sale of certain assets in the Utica Shale region. Asset gains of $17 million for the year ended December 31, 2022 increased as compared to Asset losses and impairments, net of $17 million for the year ended December 31, 2021. The increase was due to the 2022 one-time gain on sale of certain assets in the Utica Shale region of $17 million as compared to the 2021 one-time loss on notes receivable for an investment in certain assets in the Utica Shale region of $19 million, partially offset by a $2 million gain on sale of Michigan System assets. See Note 2, "Significant Accounting Policies" to the Consolidated Financial Statements under Part II, Item 8 of this Form 10-K for further details.

Interest expense increased $15 million for the year ended December 31, 2023 primarily due to higher borrowings and interest rates under the Revolving Credit Facility, higher interest rates on the Term Loan Facility, and a full year of interest expense related to our 2032 Notes, partially offset by higher capitalized interest due to higher construction in progress during 2023. Interest expense increased $19 million for the year ended December 31, 2022 primarily due to higher outstanding borrowings and higher interest rates on our external debt as compared to interest rates on borrowings from DTE Energy prior to the Separation.

Loss from financing activities decreased $7 million for the year ended December 31, 2023 and increased $7 million for the year ended December 31, 2022 due to the partial repayment of our Term Loan Facility that occurred during the three months ended June 30, 2022. See Note 10, "Debt" to the Consolidated Financial Statements under Part II, Item 8 of this Form 10-K for further details.

Income tax expense decreased $9 million for the year ended December 31, 2023 primarily due to lower income before income taxes in 2023. Income tax expense for the years ended December 31, 2023 and 2022 include the impacts of net tax benefits related to state tax rate changes. Income tax expense decreased $4 million for the year ended December 31, 2022 primarily due to state tax rate changes. The decrease was partially offset by an increase in Income before income taxes. See Note 7, "Income Taxes" to the Consolidated Financial Statements under Part II, Item 8 of this Form 10-K for further details.

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 expansion at the Haynesville System (Blue Union Gathering), Appalachia Gathering, Tioga Gathering, and Ohio Utica Gathering.

We are subject to extensive U.S. federal, state, and local environmental regulations. Additional compliance costs may result as the effects of various substances on the environment are studied and governmental regulations are developed and implemented. Actual costs to comply with such regulation 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.

We believe we have a responsibility to address climate change and have made consistent, effective environmental policies a priority. Our Board of Directors includes a committee focused on environmental, social and governance initiatives. 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 expect to achieve a 30% reduction from this baseline by 2030.

During 2024, 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;

•Our "wellhead to water" expansion proposal of the Haynesville System which offers a carbon neutral pathway for supply to reach LNG markets; and

•Our strategic joint development agreement with Mitsubishi Power Americas, Inc. to advance hydrogen development projects across the United States.

Capital expenditure investments for these projects have been contemplated in our forecasted capital expenditures discussed in the Capital Investments section below.

DT Midstream published our second annual Corporate Sustainability Report in the second quarter 2023. 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—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.

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,
															2023						2022						2021
									(millions)
Cash and Cash Equivalents at Beginning of Period															$	61					$	132					$	42
Net cash and cash equivalents from operating activities															798						725						572
Net cash and cash equivalents from (used for) investing activities															(351)						(854)						123
Net cash and cash equivalents from (used for) financing activities															(452)						58						(605)
Net Increase (Decrease) in Cash and Cash Equivalents															(5)						(71)						90
Cash and Cash Equivalents at End of Period															$	56					$	61					$	132

For purposes of the following discussion, any increases or decreases refer to the comparison of the year ended December 31, 2023 to the year ended December 31, 2022 and the year ended December 31, 2022 to the year ended December 31, 2021.

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 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 $73 million for the year ended December 31, 2023 primarily due to a decrease in cash paid for taxes, net changes in working capital, an increase in operating income after adjustment for non-cash items including depreciation and amortization expense, stock-based compensation, amortization of operating lease right-of-use assets, and assets (gains) losses and impairments, and an increase in dividends received from equity method investees. These increases were partially offset by an increase in interest expense.

Net cash and cash equivalents from operating activities increased $153 million for the year ended December 31, 2022 primarily due to net changes in working capital, an increase in operating income after adjustment for non-cash items including depreciation and amortization expense, amortization of operating lease right-of-use assets, and assets (gains) losses and impairments, and an increase in dividends received from equity method investees. These increases were partially offset by an increase in interest expense and an increase in cash paid for income taxes.

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.

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.

Net cash and cash equivalents used for investing activities decreased $503 million for the year ended December 31, 2023 primarily due to the acquisition of an additional 26.25% ownership interest in the Millennium from National Grid in 2022 and higher distributions received from equity method investees in 2023, including the NEXUS distribution noted above. This change was partially offset by an increase in cash used for plant and equipment expenditures for expansions on LEAP, Blue Union Gathering, Appalachia Gathering, and Ohio Utica Gathering, and a decrease in proceeds from the sale of notes receivable.

Net cash and cash equivalents used for investing activities of $854 million for the year ended December 31, 2022 increased as compared to net cash and cash equivalents from investing activities of $123 million for the year ended December 31, 2021. The increase was primarily due to the acquisition of an additional 26.25% ownership interest in the Millennium from National Grid in 2022, cash collection of the Notes receivable from DTE Energy in 2021, and an increase in cash used for plant and equipment expenditures in 2022, partially offset by proceeds from the sale of notes receivable in 2022.

In April 2022, we issued the 2032 Notes in aggregate principal amount of $600 million. We used the net proceeds from the sale of the 2032 Notes of $593 million to partially repay indebtedness under our Term Loan Facility. See Note 10, "Debt" to the Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

DT Midstream paid cash dividends on common stock of $263 million, $244 million, and $58 million during the years ended December 31, 2023, 2022 and 2021, 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 $452 million for the year ended December 31, 2023 increased as compared to net cash and cash equivalents from financing activities of $58 million for the year ended December 31, 2022. The increase was primarily due to higher net repayments of borrowings under the Revolving Credit Facility, higher dividends paid on common stock, and lower proceeds from the issuance of long-term debt. The increase was partially offset by lower repayments of long-term debt.

Prior to the Separation, we relied on short-term borrowings and contributions from DTE Energy. In June 2021, we issued the 2029 Notes and 2031 Notes in aggregate principal amount of $2.1 billion and entered into a $1.0 billion Term Loan Facility. Proceeds were used for the repayment of the short-term borrowings due to DTE Energy, as well as a one-time special dividend provided to DTE Energy.

Net cash and cash equivalents from financing activities of $58 million for the year ended December 31, 2022 increased as compared to net cash and cash equivalents used for financing activities of $605 million for the year ended December 31, 2021. The increase was primarily due to the 2021 Separation-related repayment of short-term borrowings and special dividend to DTE Energy, partially offset by contributions from DTE Energy that did not recur in 2022. Additionally, the increase was driven by higher borrowings under the revolving credit facility in 2022. The increase was partially offset by lower proceeds from the issuance of long-term debt, higher repayment of long-term debt, and higher dividends paid on common stock in 2022.

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 and accounts 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, 2023, we had $16 million of letters of credit outstanding and $165 million of borrowings outstanding under our Revolving Credit Facility. We had approximately $875 million of available liquidity as of December 31, 2023, consisting of cash and cash equivalents and available borrowings under our Revolving Credit Facility.

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 5% to 7% annually.

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 the inability to access adequate capital could adversely impact future earnings and cash flows.

The Credit Agreement covering the Term Loan Facility and Revolving Credit Facility includes financial covenants that DT Midstream must maintain. See Note 10, "Debt" and Note 12, "Commitments and Contingencies" to the Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

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.

The following table details our contractual obligations due by year as of December 31, 2023:

			2024						2025						2026						2027						2028 and Thereafter
			(millions)
Short-term borrowings (a)			$	165					$	—					$	—					$	—					$	—
Long-Term Debt:
Senior Notes (b)			—						—						—						—						2,100
Senior Secured Notes (c)			—						—						—						—						600
Term Loan Facility (d)			—						—						—						—						399
Letters of credit			—						—						—						—						16
Interest expense (e)			127						125						125						126						342
Operating lease payments			15						9						7						7						6
Purchase commitments			14						13						12						11						53
Total Contractual Obligations			$	321					$	147					$	144					$	144					$	3,516

_____________________________

(a) Short-term borrowings under our Revolving Credit Facility can be extended up to the October 2027 expiration date.

(b) Excludes $23 million of unamortized debt issuance costs.

(c) Excludes $1 million of unamortized debt discount and $5 million of unamortized debt issuance costs.

(d) Excludes $1 million of unamortized debt discount and $4 million of unamortized debt issuance costs.

(e) Represents interest expense related to all Long-Term Debt. The interest expense related to the Term Loan Facility assumes the variable rate is 2.614%.

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 expenditures, inclusive of $7 million in contributions to equity method investees, were $779 million for the year ended December 31, 2023. We anticipate total capital expenditures, inclusive of contributions to equity method investees, for the year ended December 31, 2024 of approximately $350 million to $435 million.

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

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 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.

The preparation of our Consolidated Financial Statements in conformity with GAAP requires that management applies accounting policies and makes 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.

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, 2023 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 judgement 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, 2023 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, 2023 valuation date:

Reporting Unit						Goodwill						Weighted Average Costs of Capital						Fair Value Reduction % (a)						Valuation Methodology (b)
						(millions)
Pipeline						$	53					9.4		%				42		%				DCF
Gathering						420						9.6		%				9		%				DCF
						$	473

_________________________________

(a) Percentage by which the estimated fair value of the reporting unit would need to decline to equal its carrying value including goodwill. The fair value reduction percentage for the Gathering reporting unit increased 1% as compared to the October 1, 2022 annual impairment test, principally due to a slight reduction in the Gathering reporting unit net book value, partially offset by an increased WACC. The WACC increase was driven by the increased U.S. Treasury Rates during 2023.

(b) Discounted cash flows (DCF) incorporated 2023 (fourth quarter) through 2027 projected cash flows plus a calculated terminal value. We calculated the terminal-year cash flows using an estimated long-term growth rate of 2.0%, 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.

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 2023.

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 2023.

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

Our 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.

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 associated with gathering 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, Southwestern Energy, in the Haynesville formation in the Gulf Coast and in the Utica and Marcellus formations 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.

We engage with customers that are sub-investment grade, including our key customer, Southwestern Energy. 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, 2023.

We are subject to interest rate risk in connection with the issuance of debt. Our exposure to interest rate risk arises primarily from changes in SOFR. As of December 31, 2023, we had floating rate debt of $564 million related to the variable rate Term Loan Facility and borrowings outstanding under our Revolving Credit Facility, and a floating rate debt-to-total debt ratio of 17%. 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.

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, 2023 by a hypothetical 10% and calculating the resulting change in the fair values. 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, 2023

(millions)

Interest rate risk

$

(82)

$

85

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)			53
Consolidated Statements of Operations			55
Consolidated Statements of Comprehensive Income			56
Consolidated Statements of Financial Position			57
Consolidated Statements of Cash Flows			59
Consolidated Statements of Changes in Stockholders' Equity/Member's Equity			60
Notes to Consolidated Financial Statements			61
Note 1 — Description of the Business and Basis of Presentation			61
Note 2 — Significant Accounting Policies			64
Note 3 — New Accounting Pronouncements			66
Note 4 — Revenue			66
Note 5 — Goodwill			69
Note 6 — Property, Plant, and Equipment and Intangible Assets			69
Note 7 — Income Taxes			70
Note 8 — Earnings Per Share and Dividends			73
Note 9 — Fair Value			74
Note 10 — Debt			75
Note 11 — Leases			77
Note 12 — Commitments and Contingencies			79
Note 13 — Stock-Based Compensation and Defined Contribution Plans			80
Note 14 — Segment and Related Information			83
Note 15 — Related Party Transactions			85
Note 16 — Subsequent Event			86

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

We have audited the accompanying consolidated statements of financial position of DT Midstream, Inc. and its subsidiaries (the “Company”) as of December 31, 2023 and 2022, and the related consolidated statements of operations, of comprehensive income, of changes in stockholders' equity/member's equity and of cash flows for each of the three years in the period ended December 31, 2023, 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, 2023, 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, 2023 and 2022, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2023 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, 2023, based on criteria established in Internal Control - Integrated Framework (2013) issued by the COSO.

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.

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.

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.

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, 2023, the Company’s equity method investment balance in NEXUS Gas Transmission, LLC (“NEXUS”) and Millennium Pipeline Company, LLC (“Millennium”) was $900 million and $727 million, respectively. For the year ended December 31, 2023, earnings from equity method investees were $177 million, of which earnings from NEXUS and Millennium were the majority.

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, 2023 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 investee auditors, 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.

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