EDGAR 10-K Filing

Company CIK: 1842022
Filing Year: 2025
Filename: 1842022_10-K_2025_0001842022-25-000003.json

---

ITEM 1. BUSINESS
Items 1. and 2. Business and Properties
General
DT Midstream was incorporated in the state of Delaware in 2021. Our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, proxy statements, and all amendments to such reports are available free of charge through the Investors Relations page of DT Midstream's website: www.dtmidstream.com, as soon as reasonably practicable after they are filed with or furnished to the SEC. Additionally, the public may read and copy any materials that we file electronically with the SEC at www.sec.gov.
The DT Midstream Code of Conduct, Board of Directors' Code of Business Conduct and Ethics, Board of Directors' Governance Guidelines, Board of Directors' Committee Charters, and Categorical Standards for Director Independence are also posted on DT Midstream's website. The information on DT Midstream's website is not part of this report or any other report that DT Midstream files with, or furnishes to, the SEC.
Business Overview
We are an owner, operator, and developer of an integrated portfolio of natural gas midstream assets. We provide multiple, integrated natural gas services to customers through our interstate pipelines, intrastate pipelines, storage systems, gathering lateral pipelines 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. On December 31, 2024, we closed on the Midwest Pipeline Acquisition of three FERC-regulated natural gas transmission pipelines. See Note 16, "Acquisitions" to the Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.
Our core assets strategically connect key demand centers in the Midwestern U.S., Eastern Canada and Northeastern U.S. regions to the premium production areas of the Marcellus/Utica natural gas formation in the Appalachian Basin and connect key demand centers and LNG export terminals in the Gulf Coast region to premium production areas of the Haynesville natural gas formation.
We have an established history of stable, long-term growth with contractual cash flows from customers that include natural gas producers, local distribution companies, electric power generators, industrials, and national marketers.
We believe that our properties are generally in good condition, well-maintained and suitable and adequate to carry on our business at capacity for the foreseeable future.
2024 Executive Summary
During the year ended December 31, 2024, DT Midstream's accomplishments and business developments included:
•Attained Net Income Attributable to DT Midstream of $354 million;
•Declared total cash dividends of $2.94 per common share;
•Closed on the Midwest Pipeline Acquisition of three FERC-regulated natural gas transmission pipelines, Guardian, Midwestern and Viking, from ONEOK for a purchase price of $1.2 billion on December 31, 2024. The pipelines have a total capacity of approximately 3.7 Bcf/d and 1,300 miles across seven states in the Midwest market region;
•To fund the Midwest Pipeline Acquisition, we:
◦Issued 4,168,750 common shares and received net proceeds of approximately $406 million;
◦Issued 5.800% senior secured notes due 2034 in aggregate principal amount of $650 million; and
◦Utilized our Revolving Credit Facility and cash on hand for the remaining purchase consideration;
•Placed the LEAP phase 3 expansion into service early and reached a final investment decision on the LEAP phase 4 expansion, which will increase the system capacity to 2.1 Bcf/d by the first half of 2026;
•Reached a final investment decision to construct an interconnect between Stonewall and the Mountain Valley Pipeline;
•Completed the Clean Fuels Acquisition and advanced the carbon capture and sequestration project in Louisiana through completion of the Class V test well;
•Credit rating was upgraded to investment-grade by Fitch Ratings and our outlook was upgraded to positive by both Moody's and S&P;
•Received a net distribution of $416 million from Millennium as a result of the issuance of senior unsecured notes;
•Repaid our remaining Term Loan Facility borrowings of $399 million;
•Amended the Credit Agreement to extend the Revolving Credit Facility maturity date to December 2029; and
•Published our third annual Corporate Sustainability Report. The information in our Corporate Sustainability Report is not incorporated by reference into this Form 10-K.
Our Strategy
Our principal business objective is to safely and reliably operate and develop 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 and acquisition opportunities that leverage our current asset footprint and strategic relationships with our customers.
•Grow cash flows supported by long-term firm service revenue contracts. We will continue pursuing opportunities that increase the demand-based component of our contract portfolio and will focus on obtaining additional long-term firm service commitments from customers, which may include fixed demand charges, MVCs and acreage dedications.
Our Operations and Business Segments
DT Midstream sets strategic goals, allocates resources, and evaluates performance based on the following two segments: Pipeline and Gathering. For financial information by segment for the last three years, see Note 14, "Segment and Related Information," to the Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.
Expand Energy accounted for approximately 56% of our operating revenues for the year ended December 31, 2024. Our operating revenues do not include revenues of unconsolidated joint ventures accounted for as equity method investments.
Pipeline Segment
Description
Our Pipeline segment includes our interstate pipelines, intrastate pipelines, storage systems, gathering 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 gathering lateral pipelines are assets that gather natural gas for our customers from multiple central delivery points within a basin and redeliver that natural gas to interstate pipelines, intrastate pipelines, and LNG export terminals for further downstream transportation and, accordingly, perform a gathering function not subject to FERC jurisdiction. Our storage systems provide natural gas storage services for customers, subject to FERC jurisdiction. On December 31, 2024, we closed on the Midwest Pipeline Acquisition of three FERC-regulated natural gas transmission pipelines. See Note 16, "Acquisitions" to the Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.
Revenues and Earnings from Equity Method Investees
DT Midstream primarily provides two types of pipeline and storage services: firm service and interruptible service. Firm service revenue contracts are typically long-term and structured using fixed demand charges or MVCs with fixed deficiency fee rates. This provides for fixed revenue commitments regardless of actual volumes of natural gas that flow, which leads to more stable operating performance, revenues and cash flows and limits our exposure to natural gas price fluctuations. For the year ended December 31, 2024, approximately 92% of our Pipeline revenue was generated under firm service revenue contracts and approximately 99% of the revenue of our unconsolidated joint ventures was generated under firm service revenue contracts. The earnings of our unconsolidated joint ventures are included in earnings from equity method investees in our Consolidated Statements of Operations. Interruptible service revenue contracts typically contain fixed rates, with total consideration dependent on actual natural gas volumes that flow.
For the year ended December 31, 2024, revenue from the Pipeline segment accounted for approximately 45% of our consolidated revenue. The cash flows from our Pipeline operations can be impacted in the short term by seasonality, weather fluctuations and the financial condition of our customers.
Competition
Our Pipeline operations compete for customers primarily based on geographic location, which determines connectivity and proximity to supply sources and end users, as well as price, operating reliability and flexibility, available capacity, and service offerings. Our primary competitors in the natural gas interstate pipelines and transmission market and in the gathering lateral pipelines market include major interstate pipelines and midstream companies that can transport and gather natural gas volumes between interstate systems and between central delivery points within a basin.
Properties
The following table presents certain information concerning our principal properties included in the Pipeline segment:
Property Classification % Owned Operator Approximate Capacity (Bcf/d)
Approximate Compression Horsepower
Description Location
Pipeline
FERC-Regulated Interstate Pipelines
Birdsboro 100% Yes 0.2 - A 14-mile interstate pipeline transporting gas supply to a gas-fired power plant in Pennsylvania
PA
Guardian (a)
100% Yes 1.3 100,300 A 263-mile interstate pipeline which connects to the Chicago Hub and serves key Wisconsin demand centers
IL and WI
Midwestern (a)
100% Yes 1.5 82,900 A 402-mile bi-directional interstate pipeline which connects Appalachia supply to the Midwest market region between Tennessee and the Chicago Hub
KY, IL, IN and TN
Millennium (b)
52.5% No 1.9 84,400 A joint venture that owns a 266-mile interstate transportation pipeline and compression facilities serving markets in the northeast and supply from the northeast Marcellus region
NY
NEXUS (b)
50% No 1.4 99,100 A joint venture that owns a 256-mile transportation pipeline and three compression facilities that transports Utica and Marcellus shale natural gas to Ohio, Michigan and Ontario market centers and Generation
OH and MI
Vector (b)
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
Canada, IL, IN and MI
Viking (a)
100% Yes 1.0 69,500 A 674-mile bi-directional interstate pipeline which serves key utility customers in Minnesota, Wisconsin and North Dakota
MN, ND and WI
Intrastate Pipelines
Generation 50% No 0.4 - A 29-mile intrastate pipeline in northern Ohio and owned by NEXUS
OH
FERC-Regulated Storage System
Washington 10 Storage Complex (c)
91% Yes N/A 26,200 An interstate storage system with 94 Bcf of storage capacity and associated compression facilities
MI
Gathering Lateral Pipelines
Bluestone 100% Yes 1.2 33,200 A 65-mile gathering lateral pipeline, and two compression facilities, that gathers Marcellus shale natural gas to Millennium and the Tennessee Pipeline
PA and NY
LEAP 100% Yes 1.9 27,000 A 211-mile gathering pipeline that gathers Haynesville shale natural gas to markets in the Gulf Coast region
LA
Michigan System 100% Yes 0.8 2,400 A 335-mile pipeline system in northern Michigan
MI
Stonewall 85% Yes 1.5 - A 68-mile gathering lateral pipeline that gathers Marcellus and Utica shale natural gas to the Columbia Pipeline
WV
__________________________________
(a)The Midwest Pipeline Acquisition closed on December 31, 2024. See Note 16, "Acquisitions" to the Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.
(b)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.
(c)The Washington 10 Storage Complex includes 16 Bcf of leased capacity from the Washington 28 Storage Complex, which is held by a joint venture, South Romeo, in which DT Midstream owns a 50% interest.
Business Updates
On December 31, 2024, we closed on the Midwest Pipeline Acquisition of three FERC-regulated natural gas transmission pipelines, Guardian, Midwestern and Viking, from ONEOK for a purchase price of $1.2 billion. The pipelines have a total capacity of approximately 3.7 Bcf/d and 1,300 miles across seven states in the Midwest market region. To fund the Midwest Pipeline Acquisition, we issued 4,168,750 common shares at a price to the public of $101.00 per share and received net proceeds of approximately $406 million and issued $650 million in aggregate principal amount of 5.800% senior secured notes due December 2034.
During the year ended December 31, 2024, we placed the LEAP phase 3 expansion into service and reached a final investment decision on the LEAP phase 4 expansion, which will increase the system capacity to 2.1 Bcf/d by the first half of 2026. We also reached a final investment decision to proceed on an interconnect between Stonewall and Mountain Valley Pipeline. Capital expenditure investments for our ongoing expansion projects are contemplated in our forecasted capital expenditures discussed under Part II, Item 7 "Management’s Discussion and Analysis of Financial Condition and Results of Operations-Capital Investments" of this Form 10-K.
In September 2024, Millennium closed on the sale of $800 million of senior unsecured notes with a weighted-average coupon rate of 5.88%. We received a distribution from Millennium of $416 million, net of fees and expenses, which reduced our investment balance under the equity method of accounting. We used the proceeds from the distribution to repay our existing indebtedness under our Term Loan Facility and for general corporate purposes. 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.
Gathering Segment
Description
Our Gathering segment includes gathering systems, related treatment plants, and compression and surface facilities. Our subsidiary companies own and operate these types of assets across multiple states.
Our natural gas gathering systems primarily consist of networks of pipelines that collect natural gas from points at or near our customers’ wells for delivery to plants for treating, to gathering pipelines for further gathering, or to pipelines for transportation. Natural gas is moved from the receipt points to the central delivery points on our gathering systems. We provide other ancillary services within our Gathering segment, including compression, dehydration, gas treatment, water impoundment, water transportation, water disposal, and sand mining. Our gathering systems provide a gathering function and are therefore not subject to FERC jurisdiction. Our gathering business has significant infrastructure within our customers' production acreage that is contractually dedicated to DT Midstream to provide gathering services. The Clean Fuels Gathering assets and results of operations after the July 1, 2024 acquisition date are presented in our Gathering segment. See Note 16, "Acquisitions" to the Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.
Revenues
Our Gathering segment typically has firm revenue contracts that are long-term and structured using fixed demand charges or MVCs with fixed deficiency fee rates. This provides for fixed revenue commitments regardless of actual volumes of natural gas that flow, which leads to more stable operating performance, revenues and cash flows and limits our exposure to natural gas price fluctuations. Additional revenues are generated from proved developed producing reserves connected to our assets, which we refer to as "flowing gas." For the year ended December 31, 2024, approximately 54% and 45% of our Gathering segment revenue was generated under firm revenue contracts and flowing gas, respectively.
For the years ended December 31, 2024 and 2023, average throughput from the Gathering segment was 2.9 Bcf/d and 3.0 Bcf/d, respectively. For the year ended December 31, 2024, revenue from the Gathering segment accounted for approximately 55% of our consolidated revenue.
Competition
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.
Properties
The following table presents certain information concerning our principal properties included in the Gathering segment:
Property Classification % Owned Operator Approximate Capacity (Bcf/d)
Approximate Compression Horsepower
Description Location
Gathering
Appalachia Gathering
100% Yes 1.0 81,300 A 152-mile gathering system that gathers Marcellus shale natural gas to the Texas Eastern Pipeline and Stonewall
PA and WV
Blue Union Gathering 100% Yes 2.6 81,600 A 427-mile gathering system that gathers shale natural gas from the Haynesville formation of Louisiana and Texas and delivers to markets in the Gulf Coast region; ancillary services include water impoundment, water transportation, water disposal, and sand
LA and TX
Clean Fuels Gathering 100% Yes 0.0 6,000 A 77-mile gathering system that gathers and treats coal mine methane into pipeline quality natural gas
IL
Ohio Utica Gathering 100% Yes 0.1 12,500 A 20-mile gathering system, including compression and dehydration facilities, that gathers Utica shale natural gas from producer wells to a nearby processing plant
OH
Susquehanna Gathering
100% Yes 1.3 88,700 A 198-mile gathering system that gathers Marcellus shale natural gas to Bluestone
PA
Tioga Gathering 100% Yes 0.1 - A 3-mile gathering system that gathers shale natural gas to the Eastern Gas Transmission system
PA
Business Updates
During the first half of 2024, we placed the new Ohio Utica Gathering system into service. Additionally, we completed the Clean Fuels Acquisition and advanced our carbon capture and sequestration project in Louisiana through completion of the Class V test well. The carbon capture and sequestration Class VI permit application was transferred to the Louisiana Department of Energy and Natural Resources in February 2024, and we are awaiting the completion of their review.
Capital expenditure investments for our ongoing expansion projects are contemplated in our forecasted capital expenditures discussed under Part II, Item 7 "Management’s Discussion and Analysis of Financial Condition and Results of Operations-Capital Investments" of this Form 10-K.
Pipeline and Gathering Rights-of-Way
We obtain satisfactory title to the properties we own and use in our businesses, subject to liens for current taxes, liens incident to minor encumbrances, and easements and restrictions, which do not materially detract from the value of such property, the interests in those properties or the use of such properties in our businesses. Our storage facilities, treating and processing plants, compressor stations, offices and related facilities are located on real property owned or leased by us. In some cases, the real property we lease is on federal, state or local government land.
We typically obtain and maintain rights to construct and operate the pipelines on other people’s land under agreements that are perpetual or provide for renewal rights. Our pipelines are constructed on rights-of-way granted by the current record owners of such property. In many instances, lands over which rights-of-way have been obtained are subject to prior liens that have not been subordinated to the rights-of-way grants. All record owners have joined in the rights-of-way grants and signatures have been obtained, except in unusual cases where title is unclear and requires additional investigation.
Human Capital Resources
DT Midstream recognizes that being innovative is necessary for our continued growth. We currently employ 556 employees, all of whom are employed full-time, exclusive of our student intern program. This includes approximately 150 employees who joined DT Midstream to support DTM Interstate Transportation as part of the Midwest Pipeline Acquisition. All of our employees are in the U.S., with our headquarters in Detroit, Michigan and locations in Illinois, Indiana, Kentucky, Louisiana, Minnesota, Ohio, Oklahoma, Pennsylvania, Tennessee, Texas, West Virginia, and Wisconsin. None of our employees are covered by collective bargaining agreements. We believe that our employee relations are good.
Know, Support and Respect Culture
Our human capital resources objectives center around employee engagement, fostering our culture, and leadership development, including training focused on our Know, Support and Respect Culture priorities discussed below. We maintain and grow our team using practices that help us identify, hire, incentivize, and retain our existing employees. Our employees have access to mentoring and educational development opportunities, including leadership development programs for emerging leaders identified at various levels within our corporate structure. Our executive leadership team meets annually with our Board of Directors' Organization and Compensation Committee to discuss executive leadership succession planning, including successor candidates and emerging leaders for management positions within the Company.
DT Midstream is committed to building an empowered and engaged team of the highest quality that delivers safe and reliable service to our customers. Rather than having stand-alone programs, we integrate these practices into our overall operating model and focus on the outcomes of Knowing, Supporting, and Respecting one another. We regularly review our representation demographics and engagement scores, and we evaluate our success based on our ability to advance our Know, Support and Respect Culture priorities:
•Know - Deliberately understanding the demographics and cultural norms of the communities where we live and operate;
•Support - Honestly understanding and listening to the perspectives and needs of all employees, regardless of location, position, or tenure - and developing strategic action plans based on annual engagement survey feedback; and
•Respect - Respect is required, so every employee will feel comfortable at work.
Health and Safety
The health and safety of people, including our employees, contractors, customers, and the communities we serve is our top priority. Our safety culture is maintained and strengthened by our safety team, which monitors events, compliance, and training activities.
We monitor our safety performance with leading and lagging indicators, such as safety observations, near-misses and the OSHA recordable injury metrics.
Compensation and Benefits Description
Our human capital resources objectives also include recruiting, incentivizing, fostering belonging, and retaining top talent. To achieve this, we offer all employees competitive compensation packages, annual and long-term incentive programs, defined contribution retirement savings plans and an employer contribution match, as well as paid time off, medical, dental, vision and other employee benefits. We review our compensation practices annually to ensure that pay is fair and internally equitable, and we believe our long-term incentive plan is important for our ability to attract, retain, motivate and reward employees. For additional information on the metrics used in our incentive plans, see Part III, Item 11 "Executive Compensation" of this Form 10-K.
For additional information on our approach to managing our human capital resources, see our 2024 Corporate Sustainability Report on our website. The information in our Corporate Sustainability Report is not incorporated by reference into this Form 10-K.
Regulatory Environment
Our operations and investments are subject to extensive regulation by United States federal, state and local authorities. In addition, NEXUS and Vector are subject to applicable laws, rules, and regulations in Canada. Failure to comply with federal, state or local regulations may result in the imposition of administrative, civil and/or criminal remedies. We cannot predict whether a regulatory complaint or proceeding will be filed against us in the future or how a regulator may rule on any such complaint. We are not aware of any pending proceedings or complaints at this time.
Additional rules and legislation pertaining to these matters are considered and adopted from time to time. In certain instances, existing rules and legislation may be repealed or substantially modified in a way that reduces our regulatory compliance obligations. We cannot predict whether any such additional rules or legislation will be promulgated or enacted, whether any existing rules or legislation will be repealed or substantially modified, or what effect, if any, such changes might have on our operations, or existing regulatory requirements. To the extent that any new rules or legislation increase our regulatory compliance obligations, the industry could be required to incur additional capital expenditures and increased costs depending on future legislative and regulatory changes.
Federal Interstate Transportation & Storage Regulation
Many of our business operations are subject to extensive regulation by FERC under the NGA, the NGPA and regulations, rules and policies promulgated under those and other statutes. Specifically, Birdsboro, Guardian, Midwestern, Millennium, NEXUS, Vector, Viking and the Washington 10 Storage Complex are subject to FERC's NGA authority and provide interstate natural gas transportation or storage services in accordance with their FERC-approved tariffs. Notwithstanding the regulatory discussion below, we believe the regulatory burden does not currently affect our competitive condition.
Generally, FERC’s authority with respect to natural gas extends to:
•rates and charges for interstate pipelines and storage facilities as well as intrastate pipelines and storage facilities providing service in interstate commerce;
•terms and conditions of services and service contracts with customers;
•certification and construction of new interstate pipelines and storage services and facilities and expansion of such facilities;
•abandonment of interstate pipelines and storage services and facilities;
•maintenance of accounts and records;
•relationships between pipelines and certain affiliates;
•depreciation and amortization rates and policies;
•facility replacements and upgrades; and
•acquisitions and dispositions of interstate pipelines and storage facilities.
Under the NGA, rates charged by interstate pipelines must be just, reasonable, and not unduly discriminatory or preferential. 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 $1,584,648 per violation per day (as adjusted for inflation for 2025), and violators may be subject to criminal penalties of up to $1 million per violation per day and five years in prison.
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 $1,584,648 per violation per day (as adjusted for inflation for 2025), and violators may be subject to criminal penalties of up to $1 million per violation and five years in prison.
State Intrastate Transportation Regulation
Many state agencies possess the authority to review and authorize natural gas transportation transactions and the construction, acquisition, abandonment and interconnection of physical facilities for intrastate pipelines. State agencies also may regulate transportation rates, service terms, and conditions and contract pricing. Other state regulations may not directly apply to our business but may nonetheless affect the availability of natural gas for purchase, compression and sale. Regulations within a particular state generally will affect all intrastate pipeline operators within the state on a comparable basis; thus, we believe that the regulation of intrastate transportation in any state in which we operate will not disproportionately affect our operations.
Gathering Pipeline Regulation
Section 1(b) of the NGA exempts natural gas gathering facilities from regulation by FERC. We believe that our gathering systems meet the traditional tests FERC has used to establish a pipeline’s status as an exempt gatherer not subject to regulation as a FERC-jurisdictional natural gas company. If FERC were to consider the status of an individual facility and determine that the facility is not a gathering pipeline and the pipeline provides interstate transmission service, the rates for, and terms and conditions of, services provided by such facility would become subject to regulation by FERC under the NGA or the NGPA. Such regulation could decrease revenue, increase operating costs and, depending upon the facility in question, adversely affect our business, financial condition and results of operations. In addition, if any of our facilities were found to have provided
services or otherwise operated in violation of the NGA or NGPA, this could result in the imposition of civil penalties as well as a requirement to disgorge charges collected for such service in excess of the rate established by FERC.
Our gathering assets may be subject to the rules and regulations of various state utility commissions. State regulation of gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements and complaint-based rate regulation. States in which we operate may adopt ratable take and common purchaser statutes, which would require our gathering pipelines to take natural gas without undue discrimination in favor of one producer over another producer or one supply source over another similarly situated supply source. The regulations under these statutes may impose some restrictions on our ability as an owner of gathering facilities to decide with whom we contract to gather natural gas. States in which we operate may also adopt a complaint-based regulation of natural gas gathering activities, which allows natural gas producers and shippers to file complaints with state regulators in an effort to resolve grievances relating to gathering access and rate discrimination.
Our gathering operations could be adversely affected should they be subject in the future to different application of state regulation of rates and services. Our gathering operations also may be, or become, subject to additional safety and operational regulations relating to the design, installation, testing, construction, operation, replacement, and management of gathering facilities.
FERC and CFTC Enforcement
The EPAct 2005 amended the NGA and NGPA to prohibit fraud and manipulation in natural gas markets, and FERC issued a final rule making it unlawful for any entity, in connection with the purchase or sale of natural gas or transportation service subject to FERC’s jurisdiction, to defraud, make an untrue statement or omit a material fact, or engage in any practice, act or course of business that operates or would operate as a fraud. FERC’s anti-manipulation rules apply to interstate gas pipeline and storage companies and intrastate gas pipeline and storage companies that provide interstate services, such as Section 311 service, as well as otherwise non-jurisdictional entities to the extent the activities are conducted "in connection with" gas sales, purchases or transportation subject to FERC jurisdiction. The anti-manipulation rules apply to intrastate sales and gathering activities only to the extent that there is a "nexus" to FERC-jurisdictional transactions. The EPAct 2005 also provided FERC with the authority to impose civil penalties, which, as adjusted for inflation for 2025, is currently up to a maximum of $1,584,648 per violation per day.
In addition, the CFTC is directed under the 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 $1.5 million (as adjusted for inflation for 2025) or triple the monetary gain to the violator for violations of the anti-market manipulation sections of the Commodities Exchange Act.
Pipeline Safety and Maintenance Regulation
Our natural gas pipeline assets are subject to the pipeline safety regulations implemented by PHMSA. PHMSA establishes and implements minimum federal safety standards and reporting requirements applicable to gas pipeline facilities, including associated underground natural gas storage. These standards include requirements that apply to the design, installation, testing, construction, operation and maintenance, 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 "Moderate Consequence Areas" for determining regulatory requirements for gas transmission pipeline segments outside of HCAs. The rule also establishes new requirements for conducting periodic integrity assessments outside of HCAs 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.
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.
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.
PHMSA is in the process of developing 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. The final rule was submitted for publication in the Federal Register in January 2025 but has since been withdrawn for further review by PHMSA with no timeframe for a final rule. PHMSA is also in the process of revising regulations applicable to requirements for operators in response to certain class location changes and developing a proposed rule to establish inspection and maintenance requirements for idled pipelines. Congress was due to reauthorize the Pipeline Safety Act in 2023, but that process has been delayed until 2025. 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 $272,926 per day for each violation and approximately $2.73 million for a related series of violations (as adjusted for inflation as prescribed in 2025). This maximum penalty authority established by statute will continue to be adjusted periodically to account for inflation.
Our operations are in substantial compliance with all existing U.S. federal, state and local pipeline safety laws and regulations. However, the adoption of new laws and regulations, such as those proposed by PHMSA, could result in significant added costs or delays in service or the termination of projects, which could have a material adverse effect on us in the future.
In the course of operating our pipeline facilities, we may experience a leak or a rupture on our system. These leaks and ruptures may cause explosions, fire, damage to the environment, damage to property, personal injury and/or death. Depending on the circumstances of the leak or rupture, PHMSA or the state agent may require that certain pipeline assets remain out of service and/or operate at a significantly reduced operating pressure until certain corrective measures are performed and a return to normal operation is approved by PHMSA or the state agent. In addition to any regulatory fines or corrective measures, we may be sued for any damages. Depending upon the facts and circumstances of a particular incident, state and federal regulatory authorities may also seek civil and/or criminal fines and penalties.
Natural Gas Storage Regulation
We operate natural gas storage facilities in Michigan as interstate facilities regulated by PHMSA and provide interstate storage and related services pursuant to a FERC-approved tariff. As such, our natural gas storage facilities are required to meet the federal safety standards as required by 49 C.F.R. §192.12, Underground natural gas storage facilities. New regulations that may expand requirements for underground natural gas storage facilities are still under development by PHMSA based on the May 2023 PHMSA Notice of Proposed Rulemaking entitled "Gas Pipeline Leak Detection and Repair." PHMSA submitted a final rule for publication in the Federal Register in January 2025, which was subsequently withdrawn for further review by PHMSA with no projected timeframe for finalizing the regulations.
Our operations are in substantial compliance with 49 C.F.R. §192.12, Underground natural gas storage facilities. However, the adoption of new laws and regulations could result in significant added costs or delays in service or the termination of projects, which could have a material adverse effect on us in the future.
Environmental and Occupational Health and Safety Regulations
General. Our operations are subject to U.S. federal, state and local environmental laws and regulations relating to air quality, water quality, waste management, wildlife conservation, natural resources and worker health and safety. These laws and regulations require the acquisition of and compliance with permits and the installation of pollution control equipment or replacement of aging pipelines and other facilities; limit or prohibit construction activities in sensitive areas such as wetlands, wilderness or areas that provide habitat for endangered or threatened species; require investigatory and remedial actions to mitigate or eliminate pollution conditions caused by our operations or attributable to former operations; and apply health and safety criteria addressing worker protections.
In addition, our operations and construction activities are subject to county and local ordinances that restrict the time, place or manner in which those activities may be conducted to reduce or mitigate nuisance-type conditions, such as, for example, excessive levels of dust or noise or increased traffic congestion.
Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties; the occurrence of delays or cancellations in the permitting or performance or expansion of projects; the denial or termination of project authorizations; the imposition of restrictions or limitations on project authorizations; the addition or removal of conditions or terms in project authorizations; the issuance of injunctions limiting or preventing some or all of our operations in a particular area; and, under certain environmental laws, citizen suits, in which individuals and environmental organizations act in the place of the government and sue operators for alleged violations of environmental law.
We have implemented programs and policies designed to keep our pipelines and other facilities in compliance with existing environmental laws and regulations, and we incur significant costs in connection with compliance. We also incur, and expect to continue to incur, additional costs with respect to construction as existing environmental laws and regulations impact the cost of planning, design, permitting, installation and start-up, and with respect to capital expenditures for pollution control equipment that is necessary to achieve emission and discharge standards included in our permits.
Moreover, we incur, and expect to continue to incur, additional costs in connection with spill response. Spills can result in significant costs associated with the investigation and remediation of contaminated facilities, and with injury and damage claims arising from releases and related contamination.
The timing and complete extent of future expenditures related to environmental matters is difficult to estimate accurately because, among other things, interpretation and enforcement of environmental laws and regulations are constantly changing, our pollution control and clean-up cost estimates may change, especially when our current estimates are based on preliminary site investigations or agreements, and new contaminated facilities and sites may be found, or what we know about existing sites and facilities could change.
We do not believe that our compliance with environmental legal requirements will materially adversely affect our business, financial condition and results of operations. Nonetheless, the trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment. Thus, there can be no assurance as to the amount or timing of future expenditures for environmental compliance or remediation, and actual future expenditures may be significantly in excess of the amounts we currently anticipate. For example, we try to anticipate future regulatory requirements that might be imposed and plan accordingly to remain in compliance with changing environmental laws and regulations and to minimize the costs of such compliance. While we are in substantial compliance with existing environmental laws and regulations, additional, unplanned measures and expenditures may be required to maintain compliance in the future.
The following is a discussion of several of the principal environmental laws and regulations, as amended from time to time, which relate to our business.
Hazardous Substances and Waste. CERCLA and comparable state laws impose liability, without regard to fault or the legality of the original conduct, on current and prior owners or operators of the sites where a release of hazardous substances occurred or extends and companies that transported, disposed or arranged for the transportation or disposal of the hazardous substances released. Under CERCLA, these "responsible parties" may be subject to strict and joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources, and for the costs of certain health studies. CERCLA also authorizes the EPA and, in some instances, third parties to act in response to threats to the public health or the environment and to seek to recover from the responsible parties the costs they incur. It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances or other pollutants released into the environment. We generate materials in the course of our ordinary operations that are regulated as "hazardous substances" under CERCLA or similar state laws and, as a result, may be jointly and severally liable under CERCLA, or such laws, for all or part of the costs required to clean up sites at which these hazardous substances have been released into the environment.
In the ordinary course of our operations, we generate solid wastes and in some instances hazardous wastes, which are subject to the requirements of RCRA and comparable state statutes. While RCRA regulates both solid and hazardous wastes, it imposes strict requirements on the generation, storage, treatment, transportation and disposal of hazardous wastes. While certain petroleum production wastes are excluded from RCRA’s hazardous waste regulations, it is possible that these wastes will in the future be designated as "hazardous wastes" and be subject to more rigorous and costly disposal requirements, which could have a material adverse effect on our maintenance capital expenditures and operating expenses.
We own, lease or operate properties where hydrocarbons are being or have been handled for many years, by us and by former owners or operators, and we send hydrocarbons and wastes to third-party sites for treatment or disposal. Under CERCLA, RCRA and analogous state laws, we could be required to remove or remediate previously disposed or released wastes (including wastes disposed of or released by prior owners or operators), to clean up contaminated property (including contaminated groundwater) or to perform remedial operations to prevent future contamination, as well as to reimburse for or contribute to the remediation of third-party disposal and treatment sites. We are not currently aware of any facts, events or conditions relating to the application of such requirements that could reasonably materially adversely affect our business, financial condition and results of operations.
Air Emissions. The U.S. federal Clean Air Act and comparable state laws and regulations restrict the emission of air pollutants from various industrial sources, including our compressor stations, and also impose various pre-construction, operational, monitoring and reporting requirements. Such laws and regulations may require that we obtain pre-approval for the construction or modification of certain projects or facilities, obtain and strictly comply with air permits containing various emissions and operational limitations, and utilize specific emission control technologies to limit emissions. Our failure to comply with these requirements could subject us to monetary penalties, injunctions, conditions or restrictions on operations and, potentially, criminal enforcement actions. We may be required to incur certain capital expenditures in the future for air pollution control equipment in connection with obtaining and maintaining permits and approvals for air emissions. Compliance with these requirements may require modifications to certain of our operations, including the installation of new equipment to control emissions from our compressors that could result in significant costs, increased capital expenditures and operating costs, and could adversely affect our business. Further, the permitting, regulatory compliance and reporting programs, taken as a whole, increase the costs and complexity of oil and gas operations with potential to adversely affect the cost of doing business for our customers resulting in reduced demand for our gas processing and transportation services. Although we can give no assurances, we believe such requirements will not materially adversely affect our business, financial condition and results of operations, and the requirements are not expected to be more burdensome to us than to any similarly situated midstream company.
Climate Change. Legislative and regulatory measures to address climate change and GHG emissions are in various phases of discussion or implementation. The EPA regulates GHG emissions from new and modified facilities that are potential major sources of criteria pollutants under the Clean Air Act’s Prevention of Significant Deterioration and Title V programs and has adopted regulations that require, among other things, preconstruction and operating permits for certain large stationary sources and the monitoring and annual reporting of GHGs from certain onshore oil and natural gas production sources. On December 2, 2023, the EPA 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, pursuant to which EPA issued regulations (announced November 12, 2024) that impose a charge on methane emissions that exceed certain thresholds from offshore and onshore petroleum and natural gas production, onshore natural gas processing, onshore natural gas transmission compression, certain kinds of natural gas and LNG storage, and onshore petroleum and natural gas gathering and boosting. Legislation or regulation that levies a charge related to our GHG emissions or that restricts GHG emissions could increase our cost of environmental compliance by requiring us to install new equipment to reduce emissions from larger facilities; purchase emission allowances; administer and manage a GHG emissions program; and otherwise increase the costs of our operations, including costs to operate and maintain our facilities.
FERC does not directly regulate GHG emissions. However, on February 17, 2022, FERC issued two policy statements providing guidance on its consideration of GHG emissions and other factors when reviewing proposed projects under the NGA. These policy statements have been the subject of public comments. On January 24, 2025, FERC issued an order terminating the Consideration of Greenhouse Gas Emissions in Natural Gas Infrastructure Project Reviews proceeding. FERC instead said it will address GHG emissions issues on a case by case basis. It is unclear at this point the impacts that termination of this proceeding will have on FERC’s processing of certificate applications.
PHMSA is also working on a Congressionally-mandated rulemaking that is designed to impose leak detection and repair criteria in order to reduce GHG emissions associated with PHMSA-regulated gas pipeline facilities and underground natural gas storage facilities. PHMSA submitted a final rule for publication in the Federal Register in January 2025, which has since been withdrawn for further review by PHMSA with no timeframe for finalizing the regulations. This rulemaking process could undergo significant revisions and a final rule may not be issued in 2025. If this rulemaking is finalized, we may incur additional expenses related to the requirements imposed by this rule, but do not expect these expenses to be material.
The effect of climate change legislation or regulation on our business is currently uncertain. If we incur additional costs to comply with such legislation or regulations, we may not be able to pass on the higher costs to our customers or recover all the costs related to complying with such requirements, and any such recovery may depend on events beyond our control, including the outcome of future rate proceedings before FERC or state regulatory agencies and the provisions of any final legislation or implementing regulations. Our future business, financial condition and results of operations could be adversely affected if such costs are not recovered through regulated rates or otherwise passed on to our customers. Additionally, our customers or suppliers may also be affected by legislation or regulation, which may adversely impact their 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 uncertainty, costs and delays with respect to obtaining permits for activities in jurisdictional waters, including wetlands.
Spill prevention, control and countermeasure requirements of U.S. federal laws require appropriate containment berms and similar structures to help prevent the contamination of regulated waters in the event of a hydrocarbon spill, rupture or leak. In addition, the Clean Water Act and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities. These permits may require us to monitor and sample the storm water runoff from some of our facilities. The Clean Water Act and regulations implemented thereunder also prohibit discharges of dredged and fill material in wetlands and other waters of the U.S. unless authorized by an appropriately issued permit. Some states also maintain groundwater protection programs that require permits for discharges or operations that may impact groundwater conditions. U.S. federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws. We believe that compliance with existing permits and foreseeable new permit requirements will not materially adversely affect our business, financial condition and results of operations.
National Environmental Policy Act. The construction of interstate natural gas transportation pipelines pursuant to the NGA requires authorization from FERC. Certain FERC actions relating to such pipelines are subject to NEPA, which requires U.S. federal agencies, such as FERC, to evaluate major U.S. federal actions having the potential to significantly affect the environment. During such evaluations, an agency will prepare a detailed Environmental Impact Statement unless it has found on the basis of an environmental assessment that no significant effect is likely. Such NEPA analyses have the potential to significantly delay or limit, and significantly increase the cost of, development of midstream infrastructure. On April 20, 2022, the White House Council on Environmental Quality 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 May 1, 2024, the Council published a second rule, further amending its NEPA implementing regulations. This rule 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 generally require agencies to undertake more searching inquiries during their NEPA reviews of new projects that require federal permits. However, the scope and detail of NEPA requirements may change as pending court cases are resolved. For example, a challenge to the Council’s May 2024 rule is underway in federal court in North Dakota. In a separate case, the federal court of appeals in Washington D.C. ruled in November 2024 that the Council’s regulations exceed the Council’s authority and do not bind the federal agencies. Petitions for rehearing are pending before the appellate court, and the ultimate import of that decision is unclear. On December 10, 2024, the U.S. Supreme Court heard argument in Seven County Infrastructure Coalition v. Eagle County, Colorado, in which petitioners seek to reverse a recent trend in courts requiring more extensive NEPA reviews, particularly related to indirect and downstream impacts of new infrastructure projects. The outcomes of these cases are uncertain.
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 February 2024, the EPA issued a final rule amending the Risk Management Program’s implementing regulations. The amended regulations impose numerous new or heightened requirements concerning incident investigations, third-party compliance auditing, consideration of alternative chemicals and technologies, and evaluation of risks from natural hazards and climate change, among other issues.
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
Item 1A. Risk Factors
You should carefully consider the following risks and other information in this Form 10-K. Any of the following risks and uncertainties could materially adversely affect our business, financial condition and results of operations.
Risks Relating to Our Business
Operational Risks
Any significant decrease in production or in demand of natural gas in our asset footprint could materially adversely affect our business, financial condition and results of operations.
Our business is dependent on the continued availability of and demand for natural gas in our areas of operation, which include the Midwestern U.S., Canada, Northeastern U.S. and Gulf Coast regions.
To maintain or increase the contracted capacity or the volume of natural gas gathered, transported and stored on our systems and cash flows associated therewith, our customers must continually obtain adequate supplies of natural gas. If new supplies of natural gas are not obtained to replace the natural decline in volumes from existing supply basins in our areas of operation, or if natural gas supplies are diverted to serve other markets, the overall volume of natural gas gathered, transported and stored on our systems would decline. The primary factors affecting our ability to obtain sources of natural gas include (i) the level of successful drilling activity near our systems, (ii) our ability to compete for volumes from successful new wells and (iii) our ability to compete successfully for volumes from sources connected to other pipelines. A reduction in the natural gas volumes supplied by producers for any of the factors mentioned above as well as national, regional, local, economic and political factors, including tariffs and periods of changing inflation, could result in reduced throughput on our systems and corresponding service revenues, which could materially adversely affect our business, financial condition and results of operations.
In addition, demand for our services is dependent on the demand for gas in the markets we serve. Alternative fuel sources such as electricity, coal, fuel oils, or nuclear energy, as well as technological advances and renewable sources of energy, could reduce demand for natural gas in our markets and have an adverse effect on our business. Government imposed constraints, such as changes in regulatory policy and permitting and environmental limitations, could also artificially limit new demand for natural gas, which could materially adversely affect our business, financial condition and results of operations.
We have one key customer, Expand Energy. The loss of, or reduction in volumes from, this customer could result in a decline in demand for our services and materially adversely affect our business, financial condition and results of operations.
Expand Energy accounted for approximately 56% of our operating revenues for the year ended December 31, 2024. Our operating revenues do not include revenues of unconsolidated joint ventures accounted for as equity method investments. The loss of all or even a portion of the contracted volumes of this or other customers, the failure to extend or replace customer contracts, or the extension or replacement of customer contracts on less favorable terms, as a result of competition, creditworthiness, reduced natural gas production or otherwise, could materially adversely affect our business, financial condition and results of operations.
We may be unable to renew or replace expiring contracts at favorable rates or on a long-term basis.
One of our exposures to market risk occurs when our existing contracts, including both our contracts with customers and our contracts with suppliers and other counterparties, expire and are subject to renegotiation and renewal. The majority of our customer contracts are firm service revenue contracts. Firm service revenue contracts are typically long-term and structured using fixed demand charges or MVCs with fixed deficiency fee rates. This provides for fixed revenue commitments regardless of actual volumes of natural gas that flow, which leads to more stable operating performance, revenues and cash flows and limits our exposure to natural gas price fluctuations. We may be unable to renew or replace these contracts at expiration, and our efforts to negotiate for similar fixed revenue commitments may be unsuccessful, which could cause our exposure to natural gas price risk to change or adversely affect the stability of our cash flows.
If third-party pipelines and other facilities interconnected to our assets become unavailable to transport natural gas, it could materially adversely affect our business, financial condition and results of operations.
We depend upon third-party pipelines and other facilities that provide receipt and delivery options to and from our assets. For example, our pipelines interconnect with multiple interstate pipelines in the Midwestern U.S., Canada, Northeastern U.S.
and Gulf Coast regions and a significant number of intrastate pipelines. Because we do not own these third-party pipelines or facilities, their continuing operation is not within our control. If these pipeline connections become unavailable for current or future volumes of natural gas due to testing, turnarounds, repairs, maintenance, damage, reduced operating pressure, lack of capacity, regulatory requirements or any other reason, our ability to operate efficiently and continue shipping natural gas to end markets could be restricted, thereby reducing our revenues. Any temporary or permanent interruption at any key pipeline interconnect or other downstream facility utilized to move our customers’ product to their end destination that causes a material reduction in volumes transported on our pipelines could materially adversely affect our business, financial condition and results of operations.
In addition, the rates charged by treating plants, pipelines and other facilities interconnected to our assets affect the utilization and value of our services. Significant changes in the rates charged by these third parties, or the rates charged by the third parties that own "downstream" assets required to move commodities to their final destinations, could materially adversely affect our business, financial condition and results of operations.
Our operations are subject to operational hazards, unforeseen interruptions and damage caused by third parties and natural events. If a significant accident or event occurs that results in a business interruption or damage to our pipelines, storage and gathering systems, the facilities of our customers or other interconnected pipelines and facilities, it could materially adversely affect our business, financial condition and results of operations.
Our operations, our customers’ operations and other interconnected pipelines and facilities are subject to many operational hazards, including (i) damage to pipelines, facilities, equipment, environmental controls and surrounding properties, including damage resulting from landslide and ground movement slippage; (ii) leaks, migrations or losses of natural gas and other hydrocarbons, water, brine, other fluids and hazardous chemicals that we handle in our treating and other operations; (iii) inadvertent damage from third parties, including from construction, farm and utility equipment; (iv) uncontrolled releases of natural gas and other hydrocarbons; (v) ruptures, fires and explosions; (vi) product and waste spills and unauthorized discharges of products, wastes and other pollutants; (vii) pipeline freeze-offs due to cold weather; (viii) operator error; (ix) aging infrastructure, mechanical or other performance problems; (x) damages to and loss of availability of interconnecting third-party pipelines, railroads and terminals; (xi) disruption or failure of information technology systems and network infrastructure; (xii) floods; (xiii) severe weather; (xiv) lightning and (xv) terrorism.
These risks could result in loss of human life, personal injuries, significant property damage, environmental pollution, impairment of our operations, regulatory investigations and penalties and substantial financial losses. The location of certain segments of our systems in or near populated areas, including residential areas, commercial business centers and industrial sites, could increase the damages resulting from these risks. In spite of any precautions taken, the occurrence of an event such as those described above that is not fully covered by insurance could materially adversely affect our business, financial condition and results of operations. In addition, these risks could materially impact or completely prevent our customers’ from performing their respective obligations under our commercial agreements, which, in turn, could materially adversely affect our business, financial condition and results of operations.
Failure to successfully combine our business with the assets acquired in the Midwest Pipeline Acquisition, or an inaccurate estimate by us of the benefits to be realized from the Midwest Pipeline Acquisition, may adversely affect our future results.
On December 31, 2024, we closed our transaction with ONEOK pursuant to which DT Midstream acquired 100% of the equity interests of Guardian, Midwestern and Viking. The Midwest Pipeline Acquisition involves potential risks, including:
•failure to attract and retain skilled professional and technical employees could adversely affect operations;
•the failure to realize expected profitability, growth or accretion;
•environmental or regulatory compliance matters or liabilities;
•title or permit issues;
•uncertainty associated with future rate-making proceedings with FERC;
•the diversion of management’s attention;
•the incurrence of substantial maintenance capital or other expenses;
•the incurrence of significant charges, such as impairment of goodwill or other intangible assets, asset devaluation or restructuring charges; and
•the incurrence of unanticipated liabilities and costs for which indemnification is unavailable or inadequate.
The expected benefits from the Midwest Pipeline Acquisition may not be realized if our estimates of the potential revenues associated with the interests acquired by us in the Midwest Pipeline Acquisition are materially inaccurate or if we failed to identify operating problems or liabilities associated with the underlying pipeline systems prior to closing. The accuracy of our estimates of the potential cash flows generated by the acquired assets is inherently uncertain. Although we conducted due diligence in connection with the Midwest Pipeline Acquisition, DT Midstream cannot assure investors that this diligence surfaced all material issues that may arise as a result of the Midwest Pipeline Acquisition. Additionally, unexpected risks may arise, and previously known risks may materialize in a manner not consistent with our preliminary risk analysis. If problems are identified in the future, the purchase agreement for the Midwest Pipeline Acquisition provides for limited recourse against the seller. If any of these risks or unanticipated liabilities or costs were to materialize, any desired benefits of the Midwest Pipeline Acquisition may not be fully realized, if at all, and our future financial performance, results of operations and cash available for distribution could be negatively impacted.
Expansion projects or acquisitions that are expected to be accretive, including our Midwest Pipeline Acquisition, may nevertheless reduce our cash from operations and could materially adversely affect our business, financial condition and results of operations.
We regularly review our portfolio of businesses and pursue growth through expansions and acquisitions that we expect to be accretive, and we believe the Midwest Pipeline Acquisition will be accretive to our distributive cash flow, improve our business profile, and add to the backlog of future growth opportunities. However, even if we complete expansion projects 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 have entered into joint ventures, and may in the future enter into additional or modify existing joint ventures, which might restrict our operational and corporate flexibility. In addition, these joint ventures are subject to most of the same operational risks to which we are subject.
We conduct a meaningful portion of our operations through joint ventures with third parties, including through our interests in Vector, Millennium and NEXUS, and we may enter into additional joint venture arrangements in the future. Generally, we do not operate the assets owned by these joint ventures and our control over their operations is limited by the applicable governing provisions of such joint venture agreements. In certain cases, we could have limited ability to influence or control certain day-to-day activities affecting the operations, the amount of capital expenditures that we may be required to fund with respect to these operations and the amount of cash we will receive from the joint venture. We also could be dependent on our joint venture partners to fund their required share of capital expenditures and be exposed to third party credit risk through our contractual arrangements with our joint venture partners. Additionally, we may be subject to restrictions or limitations on our ability to sell or transfer our interests in the jointly owned assets, and we may be required to offer business opportunities to the joint venture, or rights of participation to other joint venture partners or participants in certain areas of mutual interest.
In addition, our joint venture arrangements may involve risks not otherwise present when operating assets directly. We may incur liabilities as a result of an action taken by our joint venture partners and may be required to devote significant management time to the requirements of and matters relating to the joint ventures. Our joint venture partners may be in a position to take actions contrary to our instructions or requests, or contrary to our policies or objectives. Any disputes between us and our joint venture partners may result in delays, litigation or operational impasses.
The risks described above or the failure to continue our joint ventures or to resolve disagreements with our joint venture partners could adversely affect our ability to conduct business that is the subject of a joint venture, which could in turn materially adversely affect our business, financial condition and results of operations. In addition, these joint ventures are subject to most of the same operational risks to which we are subject and the impact of any of these operational risks on our joint ventures’ respective business, financial condition or results of operations could in turn materially adversely affect our business, financial condition and results of operations.
We do not own the majority of the land on which our assets are located, which could disrupt our current and future operations.
We do not own the majority of the land on which our assets are located, and we are therefore subject to the possibility of more onerous terms and increased costs or delays to retain necessary land use rights required to conduct our operations if we do not have valid rights-of-way, if such rights-of-way lapse or terminate or if our facilities are not properly located within the boundaries of such rights-of-way. If we were to be unsuccessful in negotiating or renegotiating rights-of-way, we might have to institute condemnation proceedings on our FERC-regulated assets or relocate our facilities for non-regulated assets. Restrictions on our ability to use our rights-of-way, through our inability to renew right-of-way contracts or otherwise, or a relocation could materially adversely affect our business, financial condition and results of operations. Additionally, even when we own an interest in the land on which our assets are located, agreements with correlative rights owners may require us to relocate pipelines and facilities, shut in storage facilities to facilitate the development of the correlative rights owners’ estate or pay the correlative rights owners the lost value of their estate if they are not willing to accommodate development.
We face and will continue to face opposition to the development or operation of our assets from various groups.
We face and will continue to face opposition to the development or operation of our assets from environmental groups, landowners, local and national groups, activists and other advocates. Such opposition could take many forms, including organized protests, attempts to block, vandalize or sabotage our development or operations, intervention in regulatory or administrative proceedings involving our assets directly or indirectly, lawsuits, legislation or other actions designed to prevent, disrupt or delay the development or operation of our assets and business. Any such event that delays or interrupts the revenues generated, or expected to be generated, by our operations, or which causes us to make significant expenditures not covered by insurance, could materially adversely affect our business, financial condition and results of operations.
The expansion of our existing assets and construction of new assets is subject to economic, market, regulatory, environmental, political, and legal risks, which could materially adversely affect our business, financial condition and results of operations. If we are unable to complete expansion projects, our future growth may be limited.
We may be unable to complete successful, accretive expansion projects for many reasons, including economic and market risks such as an inability to identify attractive expansion projects; an inability to successfully integrate the infrastructure we build; an inability to raise financing for expansion projects on economically acceptable terms; and because some of our competitors may be better positioned to compete for certain expansion projects that we believe would be accretive. In addition, the construction of additions or modifications to our existing energy infrastructure assets, and the construction of other new energy infrastructure assets, involve numerous regulatory, environmental, political and legal uncertainties beyond our control. The development and construction of pipeline and gathering infrastructure and storage facilities expose us to construction risks such as: (i) the failure of third parties to meet their contractual requirements; (ii) environmental hazards; (iii) adverse weather conditions; (iv) the performance of third-party contractors; and (v) the lack of available skilled labor, equipment and materials.
Certain of our internal growth projects may require regulatory approval from U.S. federal and state authorities and Canadian authorities prior to construction. The approval process for storage and transportation projects located in the Northeast has become increasingly challenging, 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 could modify its policy governing the issuance of interstate natural gas pipeline authorizations, in part to address concerns about climate change. It is not clear at this time whether FERC will modify its policy governing the issuance of certificates and, if so, what those modifications will be. Policy and regulatory changes relating to the implementation of NEPA may increase scrutiny of environmental impacts associated with our projects. Authorizations required for our projects under existing or future agency policies may not be granted or, if granted, such authorization may include burdensome or expensive conditions.
Failure to retain and attract key executives and other skilled professional and technical employees could materially adversely affect our business, financial condition and results of operations.
Our business is dependent on our ability to attract, retain and motivate employees. We rely on our management team, which has significant experience in the midstream industry, to manage our day-to-day affairs and establish and execute our strategic and operational plans. The loss of any of our key executives or the failure to fill new positions created by expansion, turnover or retirement could adversely affect our ability to implement our business strategy. In addition, our operations require engineers, operational and field technicians and other highly skilled employees. The competition for talent has become increasingly intense, and we may experience increased employee turnover, increased wage inflation or an impediment of our ability to execute certain key strategic initiatives due to a tightening labor market and skilled labor shortages. Failure to
successfully attract and retain an appropriately qualified workforce could materially adversely affect our business, financial condition and results of operations.
The lack of diversification of our assets and geographic locations could materially adversely affect our business, financial condition and results of operations.
We rely primarily on revenues generated from our pipeline, storage and gathering systems, substantially all of which are located in the Midwestern U.S., Eastern Canada, Northeastern U.S. and Gulf Coast regions. Due to our lack of diversification in assets and geographic location, an adverse development in these businesses or our areas of operations, including adverse developments due to catastrophic events, weather, regulatory action, state and local political activities, availability of equipment and personnel, local prices, producer liquidity and decreases in demand for natural gas could have a more significant impact on our business, financial condition and results of operations than if we maintained more diverse assets and locations.
Liquidity, Credit and Financial Risks
We may not have access to additional financing sources on favorable terms, or at all, which could materially adversely affect our business, financial condition and results of operations, and independent third parties determine our credit ratings outside of our control.
The cost of capital for our business depends, in part, on our credit ratings; general market conditions; the market’s perception of our business risk and growth potential; our current debt levels; interest rate changes; our current and expected future earnings; our cash flow; and the market price per share of our common stock. In part based on our current credit ratings, potential lenders may be unwilling or unable to provide us with financing that is attractive to us, may increase collateral requirements or may charge us prohibitively high fees in order to obtain financing. Consequently, our ability to access the credit markets in order to attract financing on reasonable terms may be adversely affected. Depending on market conditions at the relevant time, we may have to rely more heavily on additional equity financings or on less efficient forms of debt financing that require a larger portion of our cash flow from operations, thereby reducing funds available for our operations, future business opportunities and other purposes. We may not have access to such equity or debt capital on favorable terms, at the desired times, or at all. In addition, declines in our credit ratings may influence our suppliers’ and customers’ willingness to transact with us, increase the cost of our debt capital, and we may be required to make prepayments or provide security to satisfy credit concerns.
Fluctuations in energy prices could materially adversely affect our business, financial condition and results of operations.
Fluctuations in energy prices can greatly affect the development of new natural gas reserves. Drilling and production activity generally decreases as commodity prices decrease. In general terms, the prices of natural gas, oil and other hydrocarbon products fluctuate in response to changes in supply and demand, market uncertainty and a variety of additional factors that are beyond our control. These factors include (i) worldwide political and economic conditions; (ii) weather conditions and seasonal trends; (iii) the levels of domestic production and consumer demand; (iv) the availability of imported and exported natural gas, LNG and other commodities; (v) the ability to export LNG; (vi) the availability of transportation systems with adequate capacity; (vii) the volatility and uncertainty of regional pricing differentials and premiums; (viii) the price and availability of alternative fuels; (ix) the effect of energy conservation measures; and (x) governmental regulation and taxation.
Prices of natural gas have been historically volatile, and we expect this volatility to continue. Consequently, even if new natural gas reserves are discovered in areas served by our assets, producers may choose not to develop those reserves. Sustained declines in natural gas prices could have a negative impact on exploration, development and production activity and could lead to a material decrease in such activity, which could result in reduced throughput on our systems and materially adversely affect our business, financial condition and results of operations. See also "Operational Risks-Any significant decrease in production or in demand of natural gas in our asset footprint could materially adversely affect our business, financial condition and results of operations."
We are exposed to our customers’ credit risk and our credit risk management and contractual terms may be inadequate to protect against such risk.
We are subject to the risk of loss resulting from nonpayment or nonperformance by our customers in the ordinary course of our business. While some of our customers are rated investment grade, others have sub-investment grade ratings. These customers are otherwise considered creditworthy or are required to make prepayments or provide security to satisfy credit concerns. However, our credit procedures and policies may not be adequate to fully eliminate customer credit risk. If we fail to adequately assess the creditworthiness of existing or future customers, the unanticipated deterioration in their creditworthiness
and any resulting increase in nonpayment or nonperformance by them could materially adversely affect our business, financial condition and results of operations.
Our existing and future level of debt may limit our flexibility to obtain additional financing and to pursue other business opportunities.
As of December 31, 2024, we had outstanding approximately $2.1 billion of senior notes, $1.25 billion of senior secured notes and $150 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 and other debt facilities with floating rate terms will depend on market interest rates, since we anticipate that the interest rates applicable to our borrowings will fluctuate with movements in interest rate markets. If our operating results are not sufficient to service our current or future indebtedness, we will be forced to take actions such as reducing dividends, reducing or delaying our business activities, acquisitions, investments or capital expenditures, selling assets, restructuring or refinancing our debt, or seeking additional equity capital. We may not be able to effect any of these actions on satisfactory terms, or at all.
Increases in interest rates could increase our interest expense and may adversely affect our cash flows, our ability to service our indebtedness and our ability to pay dividends to our shareholders.
Borrowings under our Revolving Credit Facility have, and we may in the future enter into debt instruments with, variable interest rates. From early 2022 through late 2023, in response to growing signs of inflation, the Federal Reserve increased interest rates rapidly. Although the Federal Reserve reduced the federal funds rate in late 2024, we are unable to predict changes in interest rates which are affected by factors beyond our control. Increases in interest rates on variable rate debt would increase our interest expense unless we make arrangements to hedge the risk of rising interest rates. In addition, interest rates under our Revolving Credit Facility will, and interest rates under future debt instruments we enter into may, increase depending on our leverage ratio levels or, under certain circumstances, our public debt ratings. These increased costs could reduce our profitability, reduce our credit availability, limit our ability to pursue growth opportunities, impair our ability to meet our debt obligations, increase the cost of financing, place us at a competitive disadvantage and materially adversely affect our business, financial condition, cash flows and results of operations. An increase in interest rates also could limit our ability to refinance existing debt upon maturity or cause us to pay higher rates upon refinancing.
Restrictions under our existing or any future credit facilities, indentures and senior notes could adversely affect our business, financial condition, results of operations and ability to pay dividends to our shareholders.
Our existing Revolving Credit Facility and the indenture governing our senior notes limit our ability to, and any future credit facility or indenture we may enter into might limit our ability to, among other things: (i) incur additional indebtedness or guarantee other indebtedness; (ii) grant liens or make certain negative pledges; (iii) make certain dividends or investments; (iv) engage in transactions with affiliates; (v) transfer, sell or otherwise dispose of all or substantially all of our assets; or (vi) enter into a merger, consolidate, liquidate, wind up or dissolve.
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. Additionally, we have recently entered into amendments to our Revolving Credit Facility that, among other things, permitted us to incur certain customary bridge loans, extended the maturity date and implemented customary "limited condition transactions provisions", enabling us to enter into future acquisitions and other transactions with the conditionality to the consummation thereof subject only to customary "SunGard" conditions, which provide additional financing certainty and reduce the number of conditions required. Any subsequent amendment to the terms of our Revolving Credit Facility, replacement of our Revolving Credit Facility or any new indebtedness could have similar or greater restrictions.
For more information, see the section entitled "Management’s Discussion and Analysis of Financial Condition and Results of Operations-Capital Resources and Liquidity".
Inflation and cost increases may impact our sales margins and profitability.
Inflationary pressure could adversely impact our profitability. Inflation in the United States has recently declined; however, we are unable to predict changes in inflation which is affected by factors beyond our control, including the recent imposition of tariffs by the U.S. and certain of its trading partners. Rising inflation in the future could have an adverse impact on our operating costs, which have historically increased with the market during inflationary periods and may continue to increase as a result of inflationary impacts on product costs, labor rates, and domestic transportation. We may not be able to fully offset these inflation increases by raising prices for our services, which could result in downward pressure on our results of operations.
If our intangible assets or goodwill become impaired, we may be required to record a charge to earnings.
We annually review the carrying value of goodwill associated with business combinations we have made for impairment. Our intangible assets 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.
Regulatory Risks
The adoption of legislation and introduction of regulations relating to hydraulic fracturing and the enactment of new or increased severance taxes and impact fees on natural gas production could cause our current and potential customers to reduce the number of future wells or curtail production of existing wells. If reductions are significant for those or other reasons, the reductions could materially adversely affect our business, financial condition and results of operations.
The U.S. Congress has from time to time considered the adoption of legislation to provide for U.S. federal regulation of hydraulic fracturing, while a growing number of states, including some of those in which we operate, have adopted, and other states are considering adopting, regulations that could impose more stringent disclosure and/or well construction requirements on hydraulic fracturing operations. Some states, such as Pennsylvania, have imposed fees on the drilling of new unconventional oil and gas wells. Also, certain local governments have adopted, and additional local governments may further adopt, ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular. Further, several U.S. federal governmental agencies, including the EPA and the U.S. Department of Energy, have conducted or are conducting reviews and studies on the environmental aspects of hydraulic fracturing. These completed, ongoing or proposed studies on the environmental aspects of hydraulic fracturing, depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing or other regulatory mechanisms.
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.
Risks related to climate change could materially adversely affect our business, financial condition, results of operations, cash flow, access to and cost of capital or insurance, reputation, and business strategies.
Our business is subject to physical risks and transition risks related to climate change. Physical risks may arise from more frequent or severe weather events such as floods, landslides, storms, rising water levels, and changes in established weather patterns that cause damage to our assets or to portions of the country’s natural gas infrastructure upon which we or our customers rely. Physical risks from climate change may reduce our ability to operate reliably, safely, and economically and may cause significant insured or uninsured losses that affect our cash flows. In addition to physical risks, our business is subject to
transition risks arising from efforts to address climate change through legislation and policies and through market preferences that disfavor fossil fuels and related businesses. State and federal governments, as well as foreign governments and international governing bodies such as the United Nations, continue to develop laws, policies, and goals to reduce carbon emissions, foster a lower-carbon economy, and transition away from fossil fuels. While these efforts are diverse and subject to change, they may impose additional compliance costs and may reduce market interest in our business. Changing customer behaviors may lead to less demand for our services, less favorable pricing for our services, inefficient utilization of our assets, and diminished reputation. Our ability to comply with laws and avoid or mitigate physical and transition risks related to climate change may be limited, insufficient, or dependent on technological developments (such as lower-emission equipment) that we do not control or that require substantial additional investments and increase our cost of doing business. If we are unable to implement business strategies that address the physical risks of climate change and that meet the changing expectations of regulators or investors concerning climate change, we may experience a material adverse effect on our business.
Our operations are subject to environmental laws and regulations that may expose us to significant costs and liabilities, and changes in these laws and regulations could materially adversely affect our business, financial condition and results of operations.
Our natural gas transmission, storage and gathering activities are subject to stringent and complex U.S. federal, state and local environmental laws and regulations relating to air quality, water quality, waste management, wildlife conservation, natural resources and worker health and safety. As with the industry generally, compliance with current and anticipated environmental laws and regulations increases our overall cost of conducting business, including our capital costs to construct, maintain and upgrade pipelines and other facilities, or may even cause us not to pursue a project. For instance, we may be required to obtain and maintain permits and other approvals issued by various U.S. federal, state and local governmental authorities; monitor for, limit or prevent releases of materials from our operations in accordance with these permits and approvals; install pollution control equipment or replace aging pipelines and other facilities; limit or prohibit construction activities in sensitive areas such as wetlands, wilderness or areas that provide habitat for endangered or threatened species; incur potentially substantial new obligations or liabilities for any pollution or contamination that may result from our operations; and apply health and safety criteria addressing worker protections. Failure to comply with environmental laws and regulations, or the permits issued under them, may result in the assessment of administrative, civil and criminal penalties, the imposition of investigatory, remedial or corrective action obligations or the incurrence of capital expenditures, the occurrence of delays in the permitting or performance or expansion of projects, the issuance of injunctions limiting or preventing some or all of our operations in a particular area, and private party claims for personal injuries or property damage.
Moreover, environmental laws, regulations and enforcement policies tend to become more stringent over time. New, modified or stricter environmental laws, regulations or enforcement policies, including climate change laws and regulations restricting emissions of GHGs, could be implemented that significantly increase our compliance costs, pollution mitigation costs, or the cost of any necessary remediation of environmental contamination. For example, in April 2020 the U.S. District Court for the District of Montana issued a broad order vacating NWP 12, a general permit issued by the U.S. Army Corps of Engineers relied upon by industry for expedited permitting of oil and gas pipelines, for alleged failure to comply with consultation requirements under the ESA. While the U.S. Supreme Court ultimately stayed the vacatur of NWP 12, the District Court’s action temporarily caused uncertainty and disruption in the industry. A challenge to the 2021 reissuance of NWP 12 (re-issued on a five-year schedule) is pending in the federal district court in Washington, D.C. after the case was transferred from federal court in Montana. The NWP 12 reissuance was among the agency actions listed for review in accordance with the January 20, 2021 Executive Order ("Protecting Public Health and the Environment and Restoring Science to Tackle the Climate Crisis"); and, in 2022 the U.S. Army Corps of Engineers sought public comment on the potential to revise NWP 12 in response to objections to the use of NWP 12 related, primarily, to environmental justice, public participation, and climate change. The prior presidential administration did not take final action to modify the current version of NWP 12 before its expiration and reissuance in March 2026. While a new version might be proposed in early 2025, the position of the new presidential administration is not yet clear. 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. During the course of the prior presidential administration, litigation over the “pause” ensued. While lease sales ultimately continued, they have been scaled back and are subject to challenge by environmental groups. Over the past four years, the Department of the Interior has issued various regulations, with portions implementing the provisions of the Inflation Reduction Act pertaining to oil and gas leasing. These regulations include the so-called Waste Prevention Rule, which 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. The new presidential administration may return to a robust oil and gas leasing program and re-visit the Waste Prevention Rule as well as a number of other rules that may impact our customers. While the prior presidential administration had placed a temporary pause on the authorization of new LNG terminals, impacting LNG projects in various stages of planning and review, the new presidential administration has lifted this pause and the Department of Energy has been directed to review LNG export applications as expeditiously as possible. Moreover, a number of state and regional legal initiatives, including climate change laws, have emerged in recent years that seek to reduce GHGs emissions and the EPA, based on its findings that emissions of GHGs 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. Any new U.S. federal laws restricting emissions of GHGs, such as a carbon tax, from customer operations, or that limit the growth of pipelines and LNG exports from the U.S., could delay or curtail their activities and, in turn, adversely affect our business, financial condition and results of operations.
There is inherent risk of the incurrence of environmental costs and liabilities in our business due to our handling of natural gas and hazardous substances, and historical industry operations and waste management and disposal practices. For example, an accidental release from one of our facilities could subject us to substantial liabilities arising from environmental cleanup and restoration costs, claims made by neighboring landowners and other third parties for personal injury and property damage, or governmental claims for natural resource damages or imposing fines or penalties for related violations of environmental laws, permits or regulations. In addition, strict, joint and several liabilities may be imposed under certain environmental laws that govern the investigation and remediation of soil and groundwater contamination, which could cause us to become liable for the contamination caused by others, such as prior operators of our facilities, or for the consequences of our own actions that were in compliance with all applicable laws at the time those actions were taken, such as the historic disposal by us of hazardous substances or wastes at third party sites where contamination is subsequently discovered. Private parties, including the owners of the properties through which our assets pass and facilities where our wastes are taken for reclamation or disposal, may also have the right to pursue legal actions against us to enforce compliance, as well as to seek damages for non-compliance, with environmental laws and regulations or for personal injury or property damage that may result from environmental and other impacts of our operations. We may not be able to recover some or any of these costs through insurance or increased revenues, which could materially adversely affect our business, financial condition and results of operations. For more information, see the section entitled "Items 1. and 2. Business and Properties-Regulatory Environment-Environmental and Occupational Health and Safety Regulations".
Our natural gas transportation and storage operations are subject to extensive regulation by FERC and state regulatory authorities, and changes in FERC or state regulation could materially adversely affect our business, financial condition and results of operations.
Our business operations are subject to extensive regulation by FERC, and state regulatory authorities. Generally, FERC’s authority extends to rates and charges for interstate pipelines and storage facilities as well as intrastate pipelines and storage facilities providing service in interstate commerce; terms and conditions of services and service contracts with customers; certification and construction of new interstate pipelines and storage services and facilities and expansion of such facilities; abandonment of interstate pipelines and storage services and facilities; maintenance of accounts and records; relationships between pipelines and certain affiliates; depreciation and amortization rates and policies; facility replacements and upgrades; and acquisitions and dispositions of interstate pipelines and storage facilities.
While FERC may exercise jurisdiction over the rates and terms of service for certain of the services provided by our intrastate pipelines providing service in interstate commerce, such assets are not subject to FERC’s certification and construction authority. Prior to commencing construction of new or expanded existing interstate pipelines and storage facilities, an interstate pipeline must obtain a certificate from FERC authorizing the construction, either by filing a new certificate application or filing to amend its existing certificate. In reviewing certificate applications or amendments, FERC applies its Certificate Policy Statement, which FERC is considering revising, in part to address the consideration of climate change when
acting on such applications. A revised Certificate Policy Statement could result in more stringent review of future projects within FERC’s jurisdiction.
FERC regulations also extend to the terms and conditions set forth in agreements for our transportation and storage services executed between interstate transportation and storage service providers and their customers. These service agreements are required to conform, in all material respects, with the forms of service agreements set forth in the interstate company's FERC-approved tariff. Non-conforming agreements must be filed with, and accepted by, FERC. In the event that FERC finds that an agreement is materially non-conforming, in whole or in part, it could reject or require us to seek modification of the agreement, or alternatively require us to modify our tariff so that the non-conforming provisions are generally available to all customers or similarly-situated customers. Birdsboro, Guardian, Midwestern, Millennium, NEXUS, Vector, Viking and the Washington 10 Storage Complex provide interstate services in accordance with their FERC-approved tariffs.
Compliance with these requirements can be time-consuming, costly and burdensome and FERC action in any of these areas could adversely affect our ability to compete for business, construct new facilities, offer new services or recover the full cost of operating our pipelines. This regulatory oversight can result in longer lead times to develop and complete any future project than competitors that are not subject to FERC’s regulations. Furthermore, should FERC or state regulatory authorities find that we have failed to comply with all applicable FERC or state-administered statutes, rules, regulations and orders, or the terms of our tariffs on file with FERC, we could be subject to administrative and criminal remedies and substantial civil penalties and fines. We cannot give any assurance regarding the likely future regulations under which we will operate our assets or the effect such regulation could have on our business, financial condition and results of operations.
Any changes to the policies of FERC or state regulatory authorities regarding the natural gas industry may have an impact on us, including FERC’s approach as it considers policies affecting the establishment and modification of interstate pipeline rates and terms and conditions of service, policies that may affect rights of access to natural gas transmission capacity and policies that govern FERC's authorization of new or expanded pipeline and storage infrastructure. 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. Guardian, Midwestern and Viking are subject to rate regulation and accounting requirements of the FERC. The regulated operations of each of these subsidiaries have rates that are (i) established by independent, third-party regulators, (ii) set at levels that will recover our costs when considering the demand and competition for our services and (iii) collectible from our customers. Accordingly, we follow the accounting for regulated operations as defined in ASC 980, Regulated Operations for these pipelines, which results in differences in the application of GAAP between our regulated and non-regulated businesses. Under ASC 980, our regulated operations are required to record regulatory assets and liabilities for certain transactions that would have been treated as revenue or expense in non-regulated businesses. Future regulatory changes could result in changes in the amounts of regulatory assets and liabilities or the discontinuance of this accounting treatment for regulatory assets and liabilities and may require the write-off of the portion of any regulatory asset or liability that is no longer probable of recovery through regulated rates. Actions by regulatory authorities could also have an effect on the amounts we charge to and collect from our customers. Any changes to ASC 980 or on the determination of whether Guardian, Midwestern or Viking will continue to meet the criteria of ASC 980 could materially adversely affect our business, financial condition and results of operations.
We are exposed to costs associated with lost and unaccounted-for volumes.
A certain amount of natural gas is inherently lost and unaccounted-for in connection with meter differences and movement across a pipeline or storage system, and under our contractual arrangements with our customers we are entitled to retain a specified volume of natural gas in order to compensate us for such volumes as well as the natural gas used to operate our compressor stations, which we refer to as "fuel usage." The level of fuel usage and lost and unaccounted-for volumes on our transportation, storage and gathering systems may exceed the natural gas volumes retained from our customers as compensation for such volumes. In addition, our gathering systems have contracts that provide for specified levels of fuel retainage. As such, we need to purchase natural gas in the market to make up for any of these differences, which exposes us to natural gas price risk. Future exposure to the volatility of natural gas prices as a result of gas imbalances on our transportation, storage and gathering systems could materially adversely affect our business, financial condition and results of operations.
A change in the jurisdictional characterization of our gathering assets may result in increased regulation by FERC, which could cause our revenues to decline and operating expenses to increase and could materially adversely affect our business, financial condition and results of operations.
We believe that our non-jurisdictional natural gas gathering facilities, including those which we refer to as "gathering lateral pipelines," meet the traditional tests FERC has used to establish a pipeline’s status as an exempt gatherer not subject to regulation as a FERC-jurisdictional natural gas company under the NGA, although FERC has not made a formal determination with respect to the jurisdictional status of those facilities. FERC regulation nonetheless affects our businesses and the markets for products derived from our gathering businesses. FERC’s policies and practices across the range of its gas regulatory activities, including, for example, its policies on certification of new interstate natural gas facilities, open access transportation, rate making, terms and conditions of service, capacity release and market center promotion, indirectly affect intrastate markets. We have no assurance that FERC will continue its current policies as it considers matters such as certification of new interstate natural gas facilities, pipeline rates and rules and policies that may affect rights of access to natural gas transportation capacity. In addition, the distinction between FERC-regulated transmission services and federally unregulated gathering services is regularly the subject of substantial litigation in the industry. Consequently, the classification and regulation of some of our gathering operations could change based on future determinations by FERC, the courts or the U.S. Congress. If our gathering operations become subject to FERC jurisdiction, the result may adversely affect the rates we are able to charge and the services we currently provide and may include the potential for a termination of certain gathering agreements, which could materially adversely affect our business, financial condition and results of operations.
State and local legislative and regulatory initiatives relating to gas operations could adversely affect our services and customers’ production and therefore, materially adversely affect our business, financial condition and results of operations.
State and municipal regulations also impact our business. Common purchaser statutes generally require gatherers to gather or provide services without undue discrimination as to source of supply or producer; as a result, these statutes restrict our right to decide whose production we gather or transport. U.S. federal law leaves any economic regulation of natural gas gathering to the states. Some of the states in which we currently operate have adopted complaint-based regulation of gathering activities, which allows gas producers and shippers to file complaints with state regulators in an effort to resolve access and rate grievances. Other state and municipal regulations may not directly regulate our gathering business but may nonetheless affect the availability of natural gas for purchase, treating and sale, including state regulation of production rates and maximum daily production allowable from gas wells. While our gathering lines currently are subject to limited state regulation, there is a risk that state laws will be changed, which may give producers a stronger basis to challenge the rates, terms and conditions of their gathering lines.
Certain states in which we operate have adopted or are considering adopting measures that could impose new or more stringent requirements on gas exploration and production activities. For example, the potential for adverse impacts to our business is present where state or local governments have enacted ordinances directly regulating production rates and maximum daily production allowable from gas wells, and private individuals have sponsored and may in the future sponsor citizen initiatives to limit hydraulic fracturing, increase mandatory setbacks of oil and gas operations from occupied structures and achieve more restrictive state or local control over such activities.
In the event state or local restrictions or prohibitions are adopted in our areas of operations, our customers may incur significant compliance costs or may experience delays or curtailment in the pursuit of their exploration, development or production activities, and possibly be limited or precluded in the drilling of certain wells altogether. Any adverse impact on our customers’ activities would have a corresponding negative impact on our throughput volumes. In addition, while the general focus of debate is on upstream development activities, certain proposals may, if adopted, directly impact our ability to competitively locate, construct, maintain and operate our own assets. Accordingly, such restrictions or prohibitions could materially adversely affect our business, financial condition and results of operations.
Changes in tax laws or regulations may have a material adverse effect on our business, cash flow, financial condition or results of operations.
New income, sales, use or other tax laws, statutes, rules, regulations or ordinances could be enacted at any time, which could adversely affect our business operations and financial performance. Further, existing tax laws, statutes, rules, regulations or ordinances could be interpreted, changed, modified or applied adversely to us. It cannot be predicted whether or when tax laws, statutes, rules, regulations or ordinances may be enacted, issued, or amended. Changes to existing tax laws or the
enactment of future reform legislation could have a material impact on our financial condition, results of operations and ability to pay dividends to our shareholders.
Some of our operations cross the U.S./Canada border and are subject to cross-border regulation and potential tariffs which may have a material impact on our business, cash flow, financial condition or results of operations.
Our cross-border activities subject us to regulatory matters, including import and export licenses, tariffs, Canadian and U.S. customs and tax issues, and toxic substance certifications. Such regulations include the "Short Supply Controls" of the Export Administration Act, the United States-Mexico-Canada Agreement and the Toxic Substances Control Act. Violations of these licensing, tariff and tax-reporting requirements could result in the imposition of significant administrative, civil and criminal penalties, which could, in turn, materially adversely affect our business, financial condition and results of operations.
For example, tariffs or other restrictions placed on the import and export of natural gas with Canada and any related counter-measures that are taken by Canada could have an adverse effect on our financial condition or results of operations. Even in the absence of further tariffs, the related uncertainty could have a material adverse effect on our business, liquidity, financial condition or results of operations.
Pipeline Safety and Maintenance Risks
We may incur significant costs and liabilities to maintain our pipeline integrity management program and related testing, pipeline repair, and preventative or remedial measures, as well as other operational and maintenance requirements and assessments.
The U.S. Department of Transportation, through PHMSA, has adopted regulations requiring pipeline operators to comply with a number of operational and maintenance requirements, including to continuously survey their assets, conduct leakage surveys, and repair certain conditions. Additionally, these requirements require operators to develop integrity management programs for transportation pipelines located where a leak or rupture could do the most harm in 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 pipelines, storage and gathering infrastructure are aging, which could materially adversely affect our business, financial condition and results of operations.
Certain portions of our systems, particularly our Northern Michigan assets and our storage assets, have been in operation for many years, with some portions being more than 50 years old. In some cases, certain portions may have been in service for many years prior to our purchase of the relevant systems or have been operated by third parties not under our control and consequently, there may be historical occurrences or latent issues regarding our pipeline systems that management may be unaware of and that could materially adversely affect our business, financial condition and results of operations. Certain portions of our pipeline systems are located in or near areas determined to be HCAs, which are areas where a leak or rupture could have the most significant adverse consequences. The age and condition of these systems could result in increased maintenance or repair expenditures, and any downtime associated with increased maintenance and repair activities could
materially reduce our revenue. If, due to their age, certain pipeline sections were to become unexpectedly unavailable for current or future volumes of natural gas because of repairs, maintenance, damage, spills or leaks, or any other reason, it could materially adversely affect our business, financial condition and results of operation.
Our insurance policies do not cover all losses, costs or liabilities that we may experience, and there is no assurance that we will be able to purchase cost effective insurance in the future.
We are not fully insured against all risks inherent in our business, including environmental accidents that might occur as well as cyberattacks. In addition, we do not maintain business interruption insurance of the types and in amounts necessary to cover all possible risks of loss, like project delays caused by governmental action or inaction. The occurrence of any operating risk events not fully covered by insurance could materially adversely affect our business, financial condition and results of operations.
As a result of market conditions, premiums and deductibles for certain of our insurance policies may substantially increase. In some instances, certain insurance could become unavailable or available only for reduced coverage amounts. If significant changes in the number or financial solvency of insurance underwriters for the energy industry occur, we may be unable to obtain and maintain adequate insurance at a reasonable cost. The unavailability of full insurance coverage or our inability to maintain or obtain insurance of the type and amount we desire at reasonable rates to cover events in which we suffer significant losses could materially adversely affect our business, financial condition and results of operations.
A terrorist attack or armed conflict event, or the threat of them, could harm our business.
The U.S. Department of Homeland Security (DHS) has continued to issue public warnings that indicated that pipelines and other energy assets might be specific targets of terrorist organizations. Potential targets include our pipelines, storage and gathering systems and may affect our ability to operate or control our assets or utilize our customer service systems. Destructive forms of protests and opposition by extremists, and other disruptions, including acts of sabotage or eco-terrorism, against oil and natural gas development and production or midstream treating or transportation activities could potentially result in damage or injury to persons, property or the environment or lead to extended interruptions of our or our customers’ operations. The threat or occurrence of any of these events could cause a substantial decrease in revenues; increased costs or other financial losses; exposure or loss of customer information; damage to our reputation or business relationships; increased regulation or litigation; disruption of our operations; and inaccurate information reported from our operations.
Other Business Risks
Customers’, legislators’ or regulators’ perceptions of us are affected by many factors, including environmental and safety concerns, pipeline reliability, protection of customer information, media coverage, and public sentiment. Customers’, legislators’ or regulators’ negative opinion of us could materially adversely affect our business, financial condition and results of operations.
Many factors can affect customers’, legislators’ or regulators’ perceptions of us, including: safety concerns due to potential natural disasters, the rupture of pipelines, or other causes and our ability to promptly respond to such issues; our ability to safeguard sensitive customer information; media coverage, including the proliferation of social media, which may include factual and nonfactual information that could damage the public sentiment and perception of our company and the midstream industry.
If customers, legislators or regulators have or develop a negative opinion of us and our services, or of fossil fuels as an energy source generally, this could hinder our ability to achieve favorable legislative or regulatory outcomes. Negative opinions could also result in sales volumes reductions, increased use of alternative forms of energy, reduced access to capital markets, or greater challenges in developing or operating our assets.
In addition, in recent years, attention has been given to corporate activities related to ESG matters in public discourse and the investment community. Investor advocacy groups, proxy advisory firms, certain institutional investors and lenders, investment funds and other influential investors and rating agencies have been focused on climate change, societal expectations on companies to address climate change, investor and societal expectations regarding voluntary ESG disclosures, and consumer demand for alternative forms of energy. Attention to climate change and environmental conservation could result in increased costs, reduced access to insurance at reasonable rates, reduced demand for our services, reduced profits, negative impacts on our stock price, reduced access to capital markets, and governmental investigations and private litigation against us or our customers. To the extent that societal pressures or political or other factors are involved, it is possible that a liability could be imposed without regard to our causation of or contribution to the asserted damage, or to other mitigating factors. While we may
participate in various voluntary frameworks and certification programs to improve the ESG profile of our operations and products, we cannot guarantee that such participation or certification will have the intended results on our ESG profile.
A number of advocacy groups have campaigned for governmental and private action to promote change at public companies related to ESG matters, including demands for action related to climate change, promoting the use of alternative forms of energy, and encouraging the divestment of companies in the fossil fuel industry. Some organizations that provide corporate governance and related information to investors have ratings systems for evaluating companies on their approach to ESG matters. Unfavorable ESG ratings could lead to negative investor and bank financing sentiment toward us and our industry and to the diversion of investment to other companies or industries, which could adversely affect the demand for our services, our stock price, our access to and costs of capital and, in turn, materially adversely affect our business, financial condition and results of operations.
We published our third annual Corporate Sustainability Report in 2024, 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.
We are subject to cybersecurity and data privacy laws, regulations, litigation and directives relating to our processing of personal data.
Our business involves collection, uses and other processing of personal data of our employees, contractors, suppliers and service providers. Governmental standards and commonly accepted frameworks for the protection of computer-based systems and technology from cyber threats and attacks have been adopted. On November 7, 2024, the DHS's Transportation Security Administration issued a notice of proposed rulemaking seeking to imposes cybersecurity requirements on certain pipeline facilities entitled "Enhancing Surface Cyber Risk Management." New data privacy and cybersecurity laws add additional complexity, requirements, restrictions and potential legal risk, and compliance programs may require additional investment in resources, and could impact strategies and availability of previously useful data. Any failure by us or one of our technology service providers to comply with such laws and regulations could result in reputational harm, penalties, regulatory scrutiny, liabilities, legal claims, and/or mandated changes in our business practices.
We will report any confirmed cybersecurity incidents to the Cybersecurity and Infrastructure Security Agency. As legislation continues to develop and cyber incidents continue to evolve, we may be required to expend significant additional resources to respond to cyberattacks, to continue to modify or enhance our protective measures, or to detect, assess, investigate and remediate any security vulnerabilities and report any cyber incidents to the applicable regulatory authorities. Any failure to maintain compliance with these evolving government regulations may result in enforcement actions which may then result in significant time, support and cost and have a material adverse effect on our business and operations.
A cyberattack or threat could harm our business.
We have become increasingly dependent on digital information technologies, including computer-based systems, infrastructure, and cloud applications, to conduct almost all aspects of our business. These include operating our pipeline, storage and gathering assets, recording commercial transactions, communicating with employees supporting our operations and our customers or other business partners, and reporting financial information. We also collect and store sensitive data in the ordinary course of our business, including personally identifiable information of our employees, as well as our proprietary business information and that of our vendors, customers and other business partners. We depend on both our own systems, networks and technology, as well as the systems, networks and technology of our vendors, customers, and other business partners, including our joint venture partners. The secure processing, maintenance and transmission of this information is critical to our operations.
Our increasing reliance on digital technologies puts us at risk for system failures, disruptions, incidents, data breaches and cyberattacks, which could significantly impair our ability to conduct our business. Cyberattacks are becoming more sophisticated and include, but are not limited to, ransomware, credential stuffing, spear phishing, social engineering and other attempts to gain unauthorized access to data for purposes of extortion or malfeasance. The methodologies used by attackers change frequently and may not be recognized until such attack is underway. In April 2022, the cybersecurity authorities of the United States, Australia, Canada, New Zealand, and the United Kingdom issued a joint cybersecurity advisory warning of the increased risks of Russian state-sponsored cyberattacks following the international response to Russia’s invasion of Ukraine. We expect to continue to be targeted by cyberattacks as a critical infrastructure company.
We may not be able to anticipate, detect or prevent all cyberattacks, and the threat or occurrence of a cyberattack affecting our information technology systems or the information technology systems of our counterparties, depending on the extent or duration of the event, could materially adversely affect us, including by leading to corruption, misappropriation or loss of our proprietary and sensitive data, delays (which could be significant) in the performance of services for our customers, difficulty in completing and settling transactions, challenges in maintaining our books and records, communication interruptions, environmental damage, regulatory scrutiny, personal injury or death, property damage and other operational disruptions, as well as damage to our reputation, financial condition and cash flows and potential legal claims and liabilities.
Treated gas produced by Clean Fuels Gathering may not qualify for federal income tax credits for clean fuel production as had been projected.
The economic proceeds from Clean Fuels Gathering are expected to come from sales of treated gas, carbon offsets, and federal income tax credits. Clean Fuels Gathering produced gas may not qualify for federal income tax credits. The income tax credit value could be lower and/or uncertain compared to economic expectations. A change in tax law could lower or eliminate Clean Fuels Gathering from qualifying or receiving federal income tax credits, which would impact its projected economic return.
Risks Related to the Separation
We agreed to numerous restrictions to preserve the non-recognition treatment of the Distribution, and we could have an indemnification obligation to DTE Energy in accordance with the terms of the Tax Matters Agreement if the Distribution were determined not to qualify for non-recognition treatment for U.S. federal tax purposes.
We agreed in the Tax Matters Agreement to covenants and indemnification obligations that address compliance with Section 355(e) of the Internal Revenue Code. These covenants and indemnification obligations may limit our ability to pursue strategic transactions or engage in new businesses that may otherwise maximize the value of our Company and might discourage or delay a strategic transaction that our shareholders may consider favorable. Additionally, if it were determined that the Distribution did not qualify as a distribution to which Section 355(a), Section 355(c) and Section 361 of the Internal Revenue Code apply, we could, under certain circumstances, be required to indemnify DTE Energy for the resulting taxes and related expenses.
The Separation may expose us to potential liabilities arising out of state and U.S. federal fraudulent conveyance laws and legal dividend requirements.
If DTE Energy files for bankruptcy or is otherwise determined or deemed to be insolvent under U.S. federal bankruptcy laws, a court could deem the Separation or certain internal restructuring transactions undertaken by DTE Energy in connection with the Separation to be a fraudulent conveyance or transfer. Fraudulent conveyances or transfers are defined to include transfers made or obligations incurred with the actual intent to hinder, delay or defraud current or future creditors, or transfers made or obligations incurred for less than a reasonably equivalent value when the debtor was insolvent, or that rendered the debtor insolvent, inadequately capitalized or unable to pay its debts as they become due. A court could void the transactions or impose substantial liabilities upon us, which could materially adversely affect our business, financial condition and results of operations. Among other things, a court could require our shareholders to return to DTE Energy some or all of the shares of our common stock issued in the Separation or require us to fund liabilities of other companies involved in the restructuring transactions for the benefit of creditors. The distribution of our common stock is also subject to review under state corporate distribution statutes. Although DTE Energy intended to make a lawful distribution of our common stock, we cannot assure you that a court will not later determine that some or all of the Distribution to DTE Energy shareholders was unlawful.

---

ITEM 1B. UNRESOLVED STAFF COMMENTS
Item 1B. Unresolved Staff Comments
None.

---

ITEM 2. PROPERTIES

---

ITEM 3. LEGAL PROCEEDINGS
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 DISCLOSURE
Item 4. Mine Safety Disclosures
Our sand mining facility in Louisiana is subject to regulation by the Federal Mine Safety and Health Administration under the Federal Mine Safety and Health Act of 1977. Information concerning mine safety violations or other regulatory matters required by section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act and Item 104 of Regulation S-K is filed as Exhibit 95.1 to this Annual Report on Form 10-K.
PART II

---

ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY
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, 2024, there were 101,324,894 shares of DT Midstream common stock issued and outstanding. These shares were held by a total of 37,147 shareholders of record.
We expect to pay regular cash dividends to DT Midstream common stockholders in the future. Any payment of future dividends is subject to approval by the Board of Directors and may depend on our future earnings, cash flows, capital requirements, financial condition, and the effect a dividend payment would have on our compliance with relevant financial covenants. Over the long-term, we expect to grow our dividend with cash flow growth. For information on DT Midstream's historical dividends and dividend restrictions, see Note 8, "Earnings Per Share and Dividends" and Note 10, "Debt" to the Consolidated Financial Statements under Part II, Item 8 of this Form 10-K. There were no sales of unregistered equity securities during the past three years.
Securities Authorized for Issuance Under Equity Compensation Plans
DT Midstream's Long-Term Incentive Plan was approved by shareholders as an equity compensation plan that provides for the annual awarding of stock-based compensation to all employees. See Note 13, "Stock-Based Compensation and Defined Contribution Plans" to the Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.
See the following table for information as of December 31, 2024:
Number of Securities to be Issued Upon Exercise of Outstanding Options, Warrants, and Rights (a)
Weighted-Average Exercise Price of Outstanding Options, Warrants, and Rights
Number of Securities Remaining Available for Future Issuance Under Equity Compensation Plans
DT Midstream, Inc. Long-Term Incentive Plan 1,163,847 $ - 6,605,030
_____________________________________
(a)Includes 463,033 Restricted Stock Units and 700,814 Performance Share Awards.
COMPARISON OF CUMULATIVE TOTAL RETURN
Total Return to DT Midstream Investors
The graph below shows the cumulative total shareholder return assuming the investment of $100, including the reinvestment of dividends, on July 1, 2021 in our common stock, the Standard & Poor’s 500 Index, or S&P 500 Index, and the Alerian Midstream Energy Index. We believe the Alerian Midstream Energy Index is meaningful because it is an independent, objective view of the performance of similarly-sized midstream energy companies.
Base Period Indexed Returns
Company/Index July 1,
2021 December 31,
2021 December 31,
2022 December 31,
2023 December 31,
DT Midstream 100.00 117.18 141.56 148.29 280.16
S&P 500 Index 100.00 111.07 90.94 114.82 143.52
Alerian Midstream Energy Index 100.00 97.63 118.56 136.19 196.66

---

ITEM 6. SELECTED FINANCIAL DATA

---

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
This discussion contains forward-looking statements that involve risks and uncertainties. The forward-looking statements are not historical facts, but rather are based on current expectations, estimates, assumptions and projections about the midstream industry and our business and financial results. Our actual results could differ materially from the results contemplated by these forward-looking statements due to a number of factors, including those discussed in the sections entitled "Forward-Looking Statements" and "Risk Factors."
OVERVIEW
Our Business
We are an owner, operator, and developer of an integrated portfolio of natural gas midstream assets. We provide multiple, integrated natural gas services to customers through our Pipeline segment, which includes interstate pipelines, intrastate pipelines, storage systems, and gathering lateral pipelines, and through our Gathering segment. We also own joint venture interests in equity method investees which own and operate interstate pipelines that connect to our wholly owned assets. On December 31, 2024, we closed on the Midwest Pipeline Acquisition of three FERC-regulated natural gas transmission pipelines. See Note 16, "Acquisitions" to the Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.
Our core assets strategically connect key demand centers in the Midwestern U.S., Eastern Canada and Northeastern U.S. regions to the premium production areas of the Marcellus/Utica natural gas formation in the Appalachian Basin and connect key demand centers and LNG export terminals in the Gulf Coast region to premium production areas of the Haynesville natural gas formation.
We have an established history of stable, long-term growth with contractual cash flows from customers that include natural gas producers, local distribution companies, electric power generators, industrials, and national marketers.
Our Strategy
See discussion of our strategy under Part I, Items 1. and 2. "Business and Properties-Our Strategy" of this Form 10-K.
RESULTS OF OPERATIONS
Management’s Discussion and Analysis of Financial Condition and Results of Operations includes financial information prepared in accordance with GAAP. The following sections discuss the operating performance and future outlook of our segments. Segment information includes intercompany revenues and expenses, as well as other income and deductions that are eliminated in the Consolidated Financial Statements.
For purposes of the following discussion, any increases or decreases refer to the comparison of the year ended December 31, 2024 to the year ended December 31, 2023, or the year ended December 31, 2023 to the year ended December 31, 2022, as applicable. The following table summarizes our consolidated financial results:
Year Ended December 31,
2024 2023 2022
(millions, except per share amounts)
Operating revenues $ 981 $ 922 $ 920
Net Income Attributable to DT Midstream $ 354 $ 384 $ 370
Diluted Earnings per Common Share $ 3.60 $ 3.94 $ 3.81
Year Ended December 31,
2024 2023 2022
(millions)
Net Income Attributable to DT Midstream
Pipeline $ 276 $ 278 $ 228
Gathering 78 106 142
Total $ 354 $ 384 $ 370
Pipeline
The Pipeline segment consists of our interstate pipelines, intrastate pipelines, storage systems, gathering 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 years ended December 31, 2024 and 2023, the Michigan System financial results are presented in the Pipeline segment. The activity for the year ended December 31, 2022 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,
2024 2023 2022
(millions)
Operating revenues $ 443 $ 377 $ 339
Operation and maintenance 68 55 54
Depreciation and amortization 74 69 63
Taxes other than income 22 15 14
Asset (gains) losses and impairments, net - (4) (6)
Operating Income 279 242 214
Interest expense 47 55 57
Interest income (4) (1) (1)
Earnings from equity method investees (162) (177) (150)
Loss from financing activities 3 - 6
Other income (1) - -
Income tax expense 107 75 62
Net Income 289 290 240
Less: Net Income Attributable to Noncontrolling Interests 13 12 12
Net Income Attributable to DT Midstream $ 276 $ 278 $ 228
Operating revenues increased $66 million for the year ended December 31, 2024 primarily due to new LEAP long-term firm service revenue contracts of $55 million, higher long-term contracting rates and volumes at the Washington 10 Storage Complex of $9 million and higher volumes at Stonewall of $9 million, partially offset by lower volumes at Bluestone of $8 million. 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.
Operation and maintenance expense increased $13 million for the year ended December 31, 2024 primarily due to higher production-related operating expenses from the expansion of LEAP and acquisition related costs for the Midwest Pipeline Acquisition. 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.
Depreciation and amortization expense increased $5 million for the year ended December 31, 2024 primarily due to new LEAP assets placed into service. 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 LEAP assets placed into service.
Taxes other than income increased $7 million for the year ended December 31, 2024 primarily due to LEAP assets placed into service.
Asset (gains) losses and impairments, net decreased $4 million for the year ended December 31, 2024 due to a one-time gain realized from an insurance settlement that occurred in the prior year.
Interest expense decreased $8 million for the year ended December 31, 2024 primarily due to lower outstanding borrowings under the Revolving Credit Facility and the repayment of the Term Loan Facility during 2024, partially offset by lower capitalized interest driven by lower construction in progress during 2024 and higher interest related to the Bridge Facility and 2034 Notes. 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.
Earnings from equity method investees decreased $15 million for the year ended December 31, 2024 primarily due to higher interest expense from new senior unsecured notes at Millennium and a full year of interest expense from senior unsecured notes at NEXUS. 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. 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 increased $3 million for the year ended December 31, 2024 primarily due to the repayment of our remaining Term Loan Facility that occurred during the current year. Loss from financing activities decreased $6 million for the year ended December 31, 2023 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 $32 million for the year ended December 31, 2024 primarily due to higher income before income taxes and deferred tax remeasurement adjustments for changes in state tax rates and apportionment factors due to the Midwest Pipeline Acquisition and enacted state legislation. Income tax expense increased $13 million for the year ended December 31, 2023 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. See Note 7, "Income Taxes" to the Consolidated Financial Statements under Part II, Item 8 of this Form 10-K for further details.
Pipeline Outlook
We believe our long-term agreements with customers and the location and connectivity of our pipeline assets position the business for future growth. We will continue to pursue economically attractive expansion opportunities that leverage our current asset footprint and strategic relationships. These growth opportunities include DTM Interstate Transportation assets, further expansion at LEAP and Stonewall, new contracts at the Washington 10 Storage Complex and additional growth related to our equity method investments.
Gathering
The Gathering segment includes gathering systems, related treatment plants and compression and surface facilities. Gathering results and outlook are discussed below:
Year Ended December 31,
2024 2023 2022
(millions)
Operating revenues $ 538 $ 545 $ 581
Operation and maintenance 176 190 213
Depreciation and amortization 135 113 107
Taxes other than income 17 13 14
Asset (gains) losses and impairments, net - - (17)
Operating Income 210 229 264
Interest expense 106 95 80
Interest income (3) - (2)
Loss from financing activities 2 - 7
Other income (3) (1) (1)
Income tax expense 30 29 38
Net Income Attributable to DT Midstream $ 78 $ 106 $ 142
Operating revenues decreased $7 million for the year ended December 31, 2024 primarily due to lower volumes and recovery of production-related operating expenses on Blue Union Gathering of $19 million and lower Susquehanna Gathering volumes of $16 million, partially offset by a full year of operations at Ohio Utica Gathering of $18 million and higher Appalachia Gathering volumes of $12 million. Operating revenues decreased $36 million for the year ended December 31, 2023 primarily due to lower 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.
Operation and maintenance expense decreased $14 million for the year ended December 31, 2024 primarily due to lower planned maintenance and production-related operating expenses on Blue Union Gathering of $18 million, partially offset by a full year of operations at Ohio Utica Gathering. Operation and maintenance expense decreased $23 million for the year ended December 31, 2023 primarily due to lower 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.
Depreciation and amortization expense increased $22 million for the year ended December 31, 2024 primarily due to assets placed into service at Ohio Utica Gathering, Blue Union Gathering, and Appalachia Gathering. 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.
Taxes other than income increased $4 million for the year ended December 31, 2024 primarily due to assets placed into service at Blue Union Gathering.
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. See Note 2, "Significant Accounting Policies" to the Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.
Interest expense increased $11 million for the year ended December 31, 2024 primarily due to lower capitalized interest driven by lower construction in progress during 2024 and higher interest related to the Bridge Facility and 2034 Notes issued in 2024. This increase was partially offset by lower outstanding borrowings under the Revolving Credit Facility and the repayment of the Term Loan Facility during 2024. 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.
Loss from financing activities increased $2 million for the year ended December 31, 2024 primarily due to the repayment of our remaining Term Loan Facility that occurred during the current year. Loss from financing activities decreased $7 million for the year ended December 31, 2023 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.
Income tax expense increased $1 million for the year ended December 31, 2024 primarily due to deferred tax remeasurement adjustments for changes in state tax rates and apportionment factors due to the Midwest Pipeline Acquisition and enacted state legislation, partially offset by lower income before income taxes. 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. See Note 7, "Income Taxes" to the Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.
Gathering Outlook
We believe our long-term agreements with producers and the quality of the natural gas reserves in the Marcellus/Utica and Haynesville formations position the business for future growth. We will continue to pursue economically attractive expansion opportunities that leverage our current asset footprint and strategic relationships. These growth opportunities include further expansions at Blue Union Gathering, Appalachia Gathering, Ohio Utica Gathering, Tioga Gathering and Clean Fuels Gathering.
ENVIRONMENTAL MATTERS
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.
CLIMATE CHANGE
We believe we have an opportunity to address climate change and have made strategically aligned environmental investment decisions a priority. Our Board of Directors includes a committee focused on environmental, social and governance initiatives, and our strategy will focus on targeted growth from carbon-reducing technologies associated with our current platforms. We have announced our intent to employ carbon-reducing technologies as part of our goal of being leading environmental stewards in the midstream industry, and we are executing on a plan to achieve net zero carbon emissions by 2050. We established our baseline Scope 1 carbon emissions in 2021 and are targeting a 30% reduction from this baseline by 2030.
In 2024, we completed the Clean Fuels Acquisition and advanced our carbon capture and sequestration project in Louisiana through completion of the Class V test well. The carbon capture and sequestration Class VI permit application was transferred to the Louisiana Department of Energy and Natural Resources in February 2024, and we are awaiting the completion of their review.
In future years, we plan to continue to make progress on opportunities for energy transition advancements leveraging our existing assets, competencies and partnerships. These opportunities include the following:
•Our efforts to advance our Louisiana carbon capture project, as well as other potential carbon capture projects across our geographic regions;
•Our Clean Fuels Gathering project to capture fugitive methane emissions; and
•Our strategic joint development agreement with Mitsubishi Power Americas, Inc. to advance hydrogen development projects across the United States.
Capital project investments have been contemplated in our forecasted capital expenditures discussed in the Capital Investments section below. DT Midstream published our third annual Corporate Sustainability Report in 2024. The information in our Corporate Sustainability Report is not incorporated by reference into this Form 10-K.
For discussion of various risks including transitional risks associated with climate change related laws and regulations, reputational risks of climate change, and the physical risks of climate change, see Part I, Item 1A. "Risk Factors-Risks Relating to Our Business-Regulatory Risks-Risks related to climate change could materially adversely affect our business, financial condition, results of operations, cash flow, access to and cost of capital or insurance, reputation, and business strategies." of this Form 10-K. For discussion of recent climate change related laws and regulations, see Part I, Items 1. and 2. "Business and Properties-Regulatory Environment-Environmental and Occupational Health and Safety Regulations-Climate Change" of this Form 10-K.
CAPITAL RESOURCES AND LIQUIDITY
Cash Requirements
Our principal liquidity requirements are to finance our operations, fund capital expenditures, satisfy our indebtedness obligations, and pay approved dividends. We believe we will have sufficient internal and external capital resources to fund anticipated capital and operating requirements.
Year Ended December 31,
2024 2023 2022
(millions)
Cash and Cash Equivalents at Beginning of Period $ 56 $ 61 $ 132
Net cash and cash equivalents from operating activities 763 798 725
Net cash and cash equivalents used for investing activities (1,081) (351) (854)
Net cash and cash equivalents from (used for) financing activities 330 (452) 58
Net Increase (Decrease) in Cash and Cash Equivalents 12 (5) (71)
Cash and Cash Equivalents at End of Period $ 68 $ 56 $ 61
For purposes of the following discussion, any increases or decreases refer to the comparison of the year ended December 31, 2024 to the year ended December 31, 2023 and the year ended December 31, 2023 to the year ended December 31, 2022.
Operating Activities
Cash flows from our operating activities can be impacted in the short term by the natural gas volumes gathered or transported through our systems under interruptible service revenue contracts, changing natural gas prices, seasonality, weather fluctuations, dividends received from equity method investees, working capital changes and the financial condition of our customers. Our preference to enter into firm service revenue contracts leads to more stable operating performance, revenues and cash flows and limits our exposure to natural gas price fluctuations.
Net cash and cash equivalents from operating activities decreased $35 million for the year ended December 31, 2024 primarily due to a decrease in working capital changes and a decrease in dividends received from equity method investees, partially offset by a decrease in cash paid for income taxes and an increase in operating income after adjustment for non-cash items including depreciation and amortization expense, stock-based compensation, and amortization of operating lease right-of-use assets.
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.
Investing Activities
Cash outflows associated with our investing activities are primarily the result of plant and equipment expenditures, acquisitions, and contributions to equity method investees. Cash inflows from our investing activities are generated from proceeds from sale or collection of Notes receivable, distributions received from equity method investees, and proceeds from asset sales.
On December 31, 2024, we closed on the Midwest Pipeline Acquisition of three FERC-regulated natural gas transmission pipelines for $1.2 billion. See Note 16, "Acquisitions" to the Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.
As a result of the sales of senior unsecured notes at our equity method investees, we received net distributions from Millennium of $416 million and NEXUS of $371 million during the years ended December 31, 2024 and 2023, respectively. See Note 1, "Description of the Business and Basis of Presentation" to the Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.
Net cash and cash equivalents used for investing activities increased $730 million for the year ended December 31, 2024 primarily due to cash consideration for the Midwest Pipeline Acquisition, partially offset by a decrease in cash used for plant and equipment expenditures and higher distributions received from equity method investees, including those noted above.
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.
Financing Activities
In December 2024, we issued the 2034 Notes in aggregate principal amount of $650 million, and we amended the Credit Agreement to, among other things, extend the Revolving Credit Facility maturity date to 2029. In November 2024, we amended our Credit Agreement to permit the Company to incur certain customary bridge loans, including the Bridge Facility. In September 2024, we repaid the remaining indebtedness under the Term Loan Facility of $399 million. See Note 10, "Debt" to the Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.
In November 2024, we issued 4,168,750 common shares for net proceeds of approximately $406 million. DT Midstream paid cash dividends on common stock of $280 million, $263 million, and $244 million during the years ended December 31, 2024, 2023 and 2022, respectively. See Note 8, "Earnings Per Share and Dividends" to the Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.
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.
Net cash and cash equivalents from financing activities of $330 million for the year ended December 31, 2024 increased as compared to net cash and cash equivalents used for financing activities of $452 million for the year ended December 31, 2023. The increase was primarily due to proceeds received from the issuance of common shares, proceeds received from the issuance of the 2034 Notes, and lower net repayments of borrowings under the Revolving Credit Facility, partially offset by the repayment of the Term Loan Facility and higher dividends paid on common stock.
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.
Outlook
We expect to continue executing on our natural gas-centric business strategy focused on disciplined capital deployment and supported by a flexible, well capitalized balance sheet. Other than the impact of the items discussed below on our debt and equity capitalization, we are not aware of any trends, other demands, commitments, events or uncertainties that are reasonably likely to materially impact our liquidity position.
Our working capital requirements will be primarily driven by changes in accounts receivable, accounts payable and taxes payable. We continue our efforts to identify opportunities to improve cash flows through working capital initiatives and obtaining long-term firm service revenue contracts from customers.
Our sources of liquidity include cash and cash equivalents generated from operating activities and available borrowings under our Revolving Credit Facility. As of December 31, 2024, we had $16 million of letters of credit outstanding and $150 million borrowings outstanding under our Revolving Credit Facility. We had approximately $902 million of available liquidity as of December 31, 2024, 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 with cash flow growth.
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 Revolving Credit Facility includes financial covenants that DT Midstream must maintain. See Note 10, "Debt" to the Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.
See also Note 12, "Commitments and Contingencies" to the Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.
Credit Ratings
Credit ratings are intended to provide banks and capital market participants with a framework for comparing the credit quality of securities and are not a recommendation to buy, sell, or hold securities. Our credit ratings affect our cost of capital and other terms of financing, as well as our ability to access the credit and commercial paper markets. We believe that the current credit ratings provide sufficient access to capital markets. However, disruptions in the banking and capital markets not specifically related to us may affect our ability to access these funding sources or cause an increase in the return required by investors. During the year ended December 31, 2024, our credit rating was upgraded to investment-grade by Fitch Ratings and our outlook was upgraded to positive by both Moody's and S&P.
Contractual Obligations
The following table details our contractual obligations due by year as of December 31, 2024:
2025 2026 2027 2028 2029 and Thereafter
(millions)
Short-term borrowings (a)
$ 150 $ - $ - $ - $ -
Long-term debt:
Senior notes (b)
- - - - 2,100
Senior secured notes (c)
- - - - 1,250
Letters of credit - - - - 16
Interest expense (d)
156 153 153 153 446
Operating lease payments 17 15 14 6 5
Purchase commitments 14 13 12 12 44
Total Contractual Obligations $ 337 $ 181 $ 179 $ 171 $ 3,861
_____________________________
(a) Short-term borrowings under our Revolving Credit Facility can be extended up to the October 2027 expiration date.
(b) Excludes $19 million of unamortized debt issuance costs.
(c) Excludes $1 million of unamortized debt discount and $11 million of unamortized debt issuance costs.
(d) Represents interest expense related to all Long-term debt.
CAPITAL INVESTMENTS
Capital spending within our Company is primarily for ongoing maintenance and expansion of our existing assets, and if identified, attractive growth opportunities. We have been disciplined in our capital deployment and make growth investments that meet our criteria in terms of strategy, management skills, and identified risks and expected returns. All potential investments are analyzed for their rates of return and cash payback on a risk-adjusted basis. Our total capital expenditures, inclusive of $5 million in contributions to equity method investees, were $355 million for the year ended December 31, 2024 primarily for expansions on Blue Union Gathering, Ohio Utica Gathering, LEAP and Appalachia Gathering. On December 31, 2024, we closed on the Midwest Pipeline Acquisition of three FERC-regulated natural gas transmission pipelines for $1.2 billion. See Note 16, "Acquisitions" to the Consolidated Financial Statements under Part II, Item 8 of this Form 10-K. We anticipate total capital expenditures, inclusive of contributions to equity method investees, for the year ended December 31, 2025 of approximately $470 million to $550 million.
OFF-BALANCE SHEET ARRANGEMENTS
We are party to off-balance sheet arrangements, which include our equity method investments. See Note 1, "Description of the Business and Basis of Presentation-Principles of Consolidation" to the Consolidated Financial Statements under Part II, Item 8 of this Form 10-K for further discussion of the nature, purpose and other details of such agreements.
Other off-balance sheet arrangements include the Vector line of credit and our surety bonds, which are discussed in Note 12, "Commitments and Contingencies" to the Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.
INDEMNIFICATION OBLIGATIONS
We could have an indemnification obligation to DTE Energy pursuant to the Tax Matters Agreement and the Separation and Distribution Agreement. See Part I, Item 1A. "Risk Factors-Risks Related to the Separation-We agreed to numerous restrictions to preserve the non-recognition treatment of the Distribution, and we could have an indemnification obligation to DTE Energy in accordance with the terms of the Tax Matters Agreement if the Distribution were determined not to qualify for non-recognition treatment for U.S. federal tax purposes." of this Form 10-K for further details.
CRITICAL ACCOUNTING ESTIMATES
The preparation of our Consolidated Financial Statements in conformity with GAAP requires that management apply accounting policies and make estimates and assumptions that affect results of operations and the amounts of assets and liabilities reported in the Consolidated Financial Statements. Management believes that the areas described below require significant judgment in the application of the accounting policy or in making estimates and assumptions in matters that are inherently uncertain and that may change in subsequent periods. See additional discussion of our accounting policies in the Notes to Consolidated Financial Statements in Item 8 of this Form 10-K.
Purchase Accounting
In accordance with business combination accounting guidance, the assets acquired and liabilities assumed in an acquired business are measured at their estimated fair values at the acquisition date. As discussed in the Regulation paragraph below, these acquired FERC-regulated pipelines are accounted for under ASC 980, and thus, the fair value of assets acquired and liabilities assumed subject to these provisions approximate their regulated basis, and therefore no fair value adjustments have been reflected related to these amounts. Customer relationship intangible assets are not subject to rate making and cost recovery provisions, and therefore do include fair value adjustments. Determining the fair value of these items required management's judgment and involved the use of significant estimates and assumptions with respect to the timing and amounts of future cash inflows and outflows, discount rates, market prices and asset lives, among other items. Changes to these estimates and assumptions could result in material changes to the fair value of assets and liabilities as of the acquisition date. For income tax purposes, the transaction is treated as a taxable deemed asset acquisition. Accordingly, the majority of deferred income tax assets and liabilities of the acquired entities are eliminated as the tax bases were increased to fair market value which equals net book value.
See Note 7, "Income Taxes" and Note 16, "Acquisitions" to the Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.
Goodwill
We have goodwill that resulted from business combinations. Annually as of October 1st, an impairment test for goodwill is performed which compares the fair value of each reporting unit to its carrying value including goodwill. If the carrying value including goodwill exceeds the fair value of a reporting unit, an impairment loss would be recognized. A goodwill impairment loss is measured as the amount by which a reporting unit’s carrying value exceeds its fair value, not to exceed the carrying amount of goodwill.
The October 1, 2024 fair values for the reporting units were calculated using an income approach. The estimated fair value in our annual goodwill impairment analysis utilizes significant assumptions that require judgment by management. One such significant assumption is the weighted average cost of capital (WACC) which is used to discount estimates of projected future results and cash flows to be generated by each reporting unit. The WACC is based on our cost of debt, which includes U.S. industrial bond spreads, and cost of equity, which consists of U.S. Treasury Rates plus an equity risk premium. Another significant assumption is the terminal value that utilizes an assumed long-term growth rate, which incorporates management’s judgment regarding sustainable long-term growth of the reporting units.
Our annual goodwill impairment analysis included a comparison of the estimated fair value of the Company as a whole to our market capitalization. Management also compared the implied market multiple of the estimated fair value of each reporting unit to midstream industry transaction multiples and considered other market indicators to support the appropriateness of the fair value estimates.
We performed our annual impairment test as of October 1, 2024 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, 2024 valuation date:
Reporting Unit Goodwill Weighted Average Costs of Capital
Fair Value Reduction % (a)
Valuation Methodology (b)
(millions)
Pipeline $ 53 7.5 % 65 % DCF
Gathering 420 8.6 % 22 % 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.
(b) Discounted cash flows (DCF) incorporated 2024 (fourth quarter) through 2028 projected cash flows plus a calculated terminal value. We calculated the terminal-year cash flows using an estimated long-term growth rate of 2.5%, discounted at the WACC for each of the reporting units.
In between annual impairment tests, we monitor our estimates and assumptions regarding estimated future cash flows, including the impact of movements in market indicators, and will update the impairment analysis if a triggering event occurs. While we believe the estimates and assumptions in the fair value are reasonable, the actual results may differ from projections. To the extent projected results or cash flows are revised downward, the reporting unit may be required to write down all or a portion of its goodwill, which would adversely impact our earnings. If current expectations of future long-term growth are not met or market factors outside of our control change, such as U.S. Treasury Rates or a decline in midstream industry transaction multiples, this may lead to a goodwill impairment in the future. See Part II, Item 7A., "Quantitative and Qualitative Disclosures About Market Risk", in this Form 10-K for more information on our exposure to market risk.
On December 31, 2024, we completed the Midwest Pipeline Acquisition, which resulted in an addition of $303 million to goodwill under the Pipeline reporting unit. This addition occurred after the completion of our annual impairment test as of October 1, 2024. As part of our year-end procedures, we performed a qualitative assessment of the goodwill balance, including the newly added goodwill from the acquisition, and determined there were no indicators of impairment as of December 31, 2024. See Note 16, "Acquisitions" to the Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.
Assessment of Long-Lived Assets for Impairment
We evaluate the carrying value of long-lived assets, excluding goodwill, when circumstances indicate that the carrying value of those assets may not be recoverable. Conditions that could have an adverse impact on the cash flows and fair value of the long-lived assets are a deteriorating business climate, condition of the asset, or plans to dispose of or abandon the asset before the end of its useful life, which could result from the loss of or reduction in volume from our customers. The review of long-lived assets for impairment requires significant assumptions about operating strategies and estimates of future cash flows, which require assessments of current and projected market conditions and anticipated customer revenues. An impairment evaluation is based on an undiscounted cash flow analysis at the lowest level for which independent cash flows of long-lived assets can be identified from other groups of assets and liabilities. Impairment may occur when the carrying value of the asset exceeds the future undiscounted cash flows. When the undiscounted cash flow analysis indicates a long-lived asset is not recoverable, the amount of the impairment loss is determined by measuring the excess of the long-lived asset over its fair value. An impairment would require us to reduce both the long-lived asset and current period earnings by the amount of the impairment, which would adversely impact our earnings. As part of our ongoing reviews of business operations and associated long-lived assets, we did not identify any indicators of impairment that existed during 2024.
Depreciation and Amortization of Long-Lived Assets
We compute depreciation and amortization based on estimated useful lives. These estimates are based on various factors including condition, manufacturing specifications, technological advances and historical data concerning useful lives of similar assets. Uncertainties that impact these estimates include economic conditions and supply and demand in the area. When assets are put into service, we make estimates with respect to useful lives and salvage values that we believe are reasonable. However, subsequent events could cause us to change our estimates, thus impacting the future calculation of depreciation and amortization. For our regulated assets, depreciation studies to assess the estimated useful lives of the asset are typically conducted as part of rate proceedings or tariff filings, which can result in changes in economic lives. Changes in economic lives, if applicable, are implemented prospectively as of the tariff approved effective date.
Assessment of Equity Method Investments for Impairment
We assess at each balance sheet date whether there is objective evidence that the equity method investment is impaired by completing a quantitative or qualitative analysis of factors impacting the investment. If there is objective evidence of impairment, we determine whether the decline below carrying value is other than temporary. If the decline is determined to be other than temporary, an impairment charge is recorded in earnings with an offsetting reduction to the carrying value of the investment. As part of our ongoing reviews of equity method investment operations, we did not identify any indicators of impairment that existed during 2024.
Regulation
Guardian, Midwestern and Viking are subject to rate regulation and accounting requirements of the FERC. The regulated operations of each of these subsidiaries have rates that are (i) established by independent, third-party regulators, (ii) set at levels that will recover our costs when considering the demand and competition for our services and (iii) collectible from our customers. Accordingly, we follow the accounting for regulated operations as defined in ASC 980, Regulated Operations for these pipelines, which results in differences in the application of GAAP between our regulated and non-regulated businesses. These entities are required to record regulatory assets and liabilities for certain transactions that would have been treated as revenue or expense in non-regulated businesses. Future regulatory changes could result in changes in the amounts of regulatory assets and liabilities or the discontinuance of this accounting treatment for regulatory assets and liabilities for some or all of our regulated businesses. We believe that currently available facts support the continued use of regulatory accounting and that all regulatory assets and liabilities are recoverable or refundable in the current regulatory environment.
See Note 17, "Regulatory Matters" to the Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.
NEW ACCOUNTING PRONOUNCEMENTS
See Note 3, "New Accounting Pronouncements" to the Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

---

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Market Price Risk
Our gathering business is dependent on the continued availability of natural gas production and reserves in our geographical areas of operation. Low prices for natural gas, including those resulting from regional basis differentials, could adversely affect development of additional reserves and future natural gas production that is accessible by our pipeline and storage assets. We manage our exposure through the use of short, medium, and long-term transportation, gathering, and storage contracts. Consequently, our existing operations and cash flows have limited direct exposure to natural gas price risk.
Credit Risk
We are exposed to credit risk, which is the risk of loss resulting from nonpayment or nonperformance under a contract. We manage our exposure to credit risk associated with customers through credit analysis, credit approval, credit limits and monitoring procedures. For certain transactions, we may request letters of credit, cash collateral, prepayments or guarantees as forms of credit support. Our FERC tariffs require tariff customers that do not meet specified credit standards to provide three months of credit support, however, we are exposed to credit risk beyond this three-month period when our tariffs do not require our customers to provide additional credit support. For some long-term contracts with associated system construction or expansion, we have entered into negotiated credit agreements that provide for enhanced forms of credit support if certain customer credit standards are not met.
We depend on a key customer, Expand Energy, in the Haynesville formation in the Gulf Coast and in the Marcellus formation in the Northeastern U.S. for a significant portion of our revenues. The loss of, or reduction in volumes from, this key customer could result in a decline in demand for our services and materially adversely affect our business, financial condition and results of operations.
Our key customer, Expand Energy, is investment grade. We engage with other customers that are sub-investment grade. These customers are otherwise considered creditworthy or are required to make prepayments or provide security to satisfy credit concerns. We regularly monitor for bankruptcy proceedings that may impact our customers and had no bankruptcy proceedings during the year ended December 31, 2024.
Interest Rate Risk
We are subject to interest rate risk in connection with floating rate debt borrowings under our Revolving Credit Facility. Our exposure to interest rate risk arises primarily from changes in SOFR. As of December 31, 2024, we had floating rate debt of $150 million related to borrowings outstanding under our Revolving Credit Facility, and a floating rate debt-to-total debt ratio of 4.29%. 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.
Summary of Sensitivity Analysis
A sensitivity analysis was performed on the fair values of our long-term debt obligations. The sensitivity analysis involved increasing and decreasing interest rates as of December 31, 2024 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, 2024
(millions)
Interest rate risk $ (100) $ 104 Long-term debt

---

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Item 8. Financial Statements
The following Consolidated Financial Statements are included herein:
Page
Report of Independent Registered Public Accounting Firm (PCAOB ID 238)
Consolidated Statements of Operations
Consolidated Statements of Comprehensive Income
Consolidated Statements of Financial Position
Consolidated Statements of Cash Flows
Consolidated Statements of Changes in Stockholders' Equity
Notes to Consolidated Financial Statements
Note 1 - Description of the Business and Basis of Presentation
Note 2 - Significant Accounting Policies
Note 3 - New Accounting Pronouncements
Note 4 - Revenue
Note 5 - Goodwill
Note 6 - Property, Plant, and Equipment and Intangible Assets
Note 7 - Income Taxes
Note 8 - Earnings Per Share and Dividends
Note 9 - Fair Value
Note 10 - Debt
Note 11 - Leases
Note 12 - Commitments and Contingencies
Note 13 - Stock-Based Compensation and Defined Contribution Plans
Note 14 - Segment and Related Information
Note 15 - Related Party Transactions
Note 16 - Acquisitions
Note 17 - Regulatory Matters
Note 18 - Subsequent Event
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Stockholders of DT Midstream, Inc.
Opinions on the Financial Statements and Internal Control over Financial Reporting
We have audited the accompanying consolidated statements of financial position of DT Midstream, Inc. and its subsidiaries (the “Company”) as of December 31, 2024 and 2023, and the related consolidated statements of operations, of comprehensive income, of changes in stockholders' equity and of cash flows for each of the three years in the period ended December 31, 2024, 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, 2024, 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, 2024 and 2023, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2024 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, 2024, based on criteria established in Internal Control - Integrated Framework (2013) issued by the COSO.
Basis for Opinions
The Company's management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in Management’s Report on Internal Control over Financial Reporting appearing under Item 9A. Our responsibility is to express opinions on the Company’s consolidated financial statements and on the Company's internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.
Our audits of the consolidated financial statements included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
As described in Management’s Report on Internal Control over Financial Reporting, management has excluded three FERC-regulated natural gas transmission pipelines (“Midwest Pipeline Acquisition”) from its assessment of internal control over financial reporting as of December 31, 2024 because they were acquired by the Company in a purchase business combination on December 31, 2024. We have also excluded the Midwest Pipeline Acquisition from our audit of internal control over financial reporting. The three FERC-regulated natural gas transmission pipelines are wholly-owned subsidiaries whose total revenues and total assets excluded from management’s assessment and our audit of internal control over financial reporting represent less than 1 percent and approximately 10 percent, respectively, of the related consolidated financial statement amounts as of and for the year ended December 31, 2024 (the 10 percent calculation excludes assets related to acquired goodwill and other intangible assets, as they were included in management’s assessment).
Definition and Limitations of Internal Control over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Critical Audit Matters
The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that (i) relates to accounts or disclosures that are material to the consolidated financial statements and (ii) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Equity Method Investments in NEXUS Gas Transmission, LLC and Millennium Pipeline Intermediate Holdings, LLC
As described in Note 1 to the consolidated financial statements, non-controlled investments are accounted for using the equity method of accounting when the Company is able to significantly influence the operating policies of the investee. Under the equity method of accounting, investments are recorded at historical cost as an asset and adjusted for capital contributions, dividends and distributions received, and the Company’s share of the investee’s earnings or losses, which are recorded as earnings from equity method investees. The Company’s equity method investments are periodically evaluated for certain factors that may be indicative of other-than-temporary impairment. As of December 31, 2024, the Company’s equity method investment balance in NEXUS Gas Transmission, LLC (“NEXUS”) and Millennium Pipeline Intermediate Holdings, LLC (“Millennium”) was $880 million and $283 million, respectively. For the year ended December 31, 2024, earnings from equity method investees for NEXUS and Millennium were $62 million and $59 million, respectively.
The principal consideration for our determination that performing procedures relating to the equity method investments in NEXUS and Millennium is a critical audit matter is a high degree of auditor effort in performing procedures related to these equity method investments.
Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to equity method investments. These procedures also included, among others, the following, which were performed as of and for the year ended December 31, 2024 for NEXUS and Millennium (collectively “the investees”): (i) vouching capital contributions, dividends and distributions to source documents, (ii) confirming specific unaudited financial information with the investees, (iii) reconciling the investee financial information per Company records to the investees’ independently audited financial statements, (iv) recalculating the Company’s carrying amount of its investments in the investees that exceeded the Company’s share of the underlying equity in the net assets and the related amortization of such differences, (v) performing inquiries with management, and inspecting supporting evidence and documentation, to understand and evaluate management’s consideration of accounting matters, including management’s assertion that there were no indicators of other-than-temporary impairment, and (vi) performing procedures to evaluate subsequent events impacting the investees.
/s/ PricewaterhouseCoopers LLP
Detroit, Michigan
February 26, 2025
We have served as the Company’s auditor since 2020.
DT Midstream, Inc.
Consolidated Statements of Operations
Year Ended December 31,
2024 2023 2022
(millions, except per share amounts)
Revenues
Operating revenues $ 981 $ 922 $ 920
Operating Expenses
Operation and maintenance 244 245 267
Depreciation and amortization 209 182 170
Taxes other than income 39 28 28
Asset (gains) losses and impairments, net - (4) (23)
Operating Income 489 471 478
Other (Income) and Deductions
Interest expense 153 150 137
Interest income (7) (1) (3)
Earnings from equity method investees (162) (177) (150)
Loss from financing activities 5 - 13
Other income (4) (1) (1)
Income Before Income Taxes 504 500 482
Income Tax Expense 137 104 100
Net Income 367 396 382
Less: Net Income Attributable to Noncontrolling Interests 13 12 12
Net Income Attributable to DT Midstream $ 354 $ 384 $ 370
Basic Earnings per Common Share
Net Income Attributable to DT Midstream $ 3.63 $ 3.97 $ 3.83
Diluted Earnings per Common Share
Net Income Attributable to DT Midstream $ 3.60 $ 3.94 $ 3.81
Weighted Average Common Shares Outstanding
Basic 97.6 96.9 96.7
Diluted 98.4 97.5 97.2
See Notes to Consolidated Financial Statements
DT Midstream, Inc.
Consolidated Statements of Comprehensive Income
Year Ended December 31,
2024 2023 2022
(millions)
Net Income $ 367 $ 396 $ 382
Foreign currency translation and unrealized gain on derivatives, net of tax - 2 -
Other comprehensive income - 2 -
Comprehensive income 367 398 382
Less: Comprehensive income attributable to noncontrolling interests 13 12 12
Comprehensive Income Attributable to DT Midstream $ 354 $ 386 $ 370
See Notes to Consolidated Financial Statements
DT Midstream, Inc.
Consolidated Statements of Financial Position
December 31,
2024 2023
(millions)
ASSETS
Current Assets
Cash and cash equivalents $ 68 $ 56
Accounts receivable (net of $- allowance for expected credit loss for each period end)
172 154
Deferred property taxes 33 31
Taxes receivable 8 15
Prepaid expenses and other 29 16
310 272
Investments
Investments in equity method investees 1,297 1,762
Property
Property, plant, and equipment 6,525 5,282
Accumulated depreciation (998) (848)
5,527 4,434
Other Assets
Goodwill 776 473
Long-term notes receivable - related party 4 4
Operating lease right-of-use assets 49 38
Intangible assets, net 1,921 1,968
Other 51 31
2,801 2,514
Total Assets $ 9,935 $ 8,982
See Notes to Consolidated Financial Statements
DT Midstream, Inc.
Consolidated Statements of Financial Position
December 31,
2024 2023
(millions, except shares)
LIABILITIES AND EQUITY
Current Liabilities
Accounts payable $ 77 $ 94
Short-term borrowings 150 165
Operating lease liabilities 16 13
Dividends payable 75 67
Interest payable 12 10
Property taxes payable 42 34
Accrued compensation 19 18
Contract liabilities 18 18
Other 17 15
426 434
Long-Term Debt, net 3,319 3,065
Other Liabilities
Deferred income taxes 1,129 1,031
Operating lease liabilities 36 27
Contract liabilities 135 111
Regulatory liabilities 90 -
Other 34 34
1,424 1,203
Total Liabilities 5,169 4,702
Commitments and Contingencies (Note 12)
Stockholders' Equity
Preferred stock ($0.01 par value, 50,000,000 shares authorized, and no shares issued or outstanding as of December 31, 2024 and 2023)
- -
Common stock ($0.01 par value, 550,000,000 shares authorized, and 101,324,894 and 96,971,021 shares issued and outstanding as of December 31, 2024 and 2023, respectively)
1 1
Additional paid-in capital 3,911 3,485
Retained earnings 723 661
Accumulated other comprehensive income (loss) (8) (8)
Total DT Midstream Equity 4,627 4,139
Noncontrolling interests 139 141
Total Equity 4,766 4,280
Total Liabilities and Equity $ 9,935 $ 8,982
See Notes to Consolidated Financial Statements
DT Midstream, Inc.
Consolidated Statements of Cash Flows
Year Ended December 31,
2024 2023 2022
(millions)
Operating Activities
Net Income $ 367 $ 396 $ 382
Adjustments to reconcile Net Income to Net cash and cash equivalents from operating activities:
Depreciation and amortization 209 182 170
Stock-based compensation 23 20 17
Amortization of operating lease right-of-use assets 18 18 19
Deferred income taxes 120 110 70
Earnings from equity method investees (162) (177) (150)
Dividends from equity method investees 161 196 181
Asset (gains) losses and impairments, net - - (17)
Loss from financing activities 5 - 13
Changes in assets and liabilities:
Accounts receivable, net 11 7 8
Accounts payable 11 (5) 7
Contract liabilities 23 97 3
Other current and noncurrent assets and liabilities (23) (46) 22
Net cash and cash equivalents from operating activities 763 798 725
Investing Activities
Plant and equipment expenditures (350) (772) (338)
Acquisition accounted for as a business combination (1,198) - -
Proceeds from sale of notes receivable - - 22
Distributions from equity method investees 472 427 17
Contributions to equity method investees (5) (7) (5)
Acquisition of additional interest in equity method investee - - (552)
Other investing activities - 1 2
Net cash and cash equivalents used for investing activities (1,081) (351) (854)
Financing Activities
Issuance of long-term debt, net of discount and issuance costs 644 - 591
Repayment of long-term debt (399) - (596)
Borrowings under the Revolving Credit Facility 385 540 370
Repayment of borrowings under the Revolving Credit Facility (400) (705) (40)
Payment of Revolving Credit Facility issuance costs (3) - (3)
Issuance of common stock, net of issuance costs 406 - -
Distributions to noncontrolling interests (17) (18) (14)
Dividends paid on common stock (280) (263) (244)
Other financing activities (6) (6) (6)
Net cash and cash equivalents from (used for) financing activities 330 (452) 58
Net Increase (Decrease) in Cash and Cash Equivalents 12 (5) (71)
Cash and Cash Equivalents at Beginning of Period 56 61 132
Cash and Cash Equivalents at End of Period $ 68 $ 56 $ 61
Supplemental disclosure of cash information
Cash paid for:
Interest, net of interest capitalized $ 140 $ 140 $ 125
Income taxes 12 22 24
Supplemental disclosure of non-cash investing and financing activities
Plant and equipment expenditures in accounts payable and other accrued liabilities $ 44 $ 80 $ 99
See Notes to Consolidated Financial Statements
DT Midstream, Inc.
Consolidated Statements of Changes in Stockholders' Equity
Additional Paid-In Capital Retained Earnings Accumulated Other Comprehensive Income (Loss) Noncontrolling Interests
Common Stock
Shares Amount Total
(dollars in millions, shares in thousands)
Balance, December 31, 2021 96,734 $ 1 $ 3,450 $ 431 $ (10) $ 149 $ 4,021
Net Income - - - 370 - 12 382
Dividends declared on common stock ($2.56 per common share)
- - - (248) - - (248)
Distributions to noncontrolling interests - - - - - (14) (14)
Stock-based compensation 78 - 17 (2) - - 15
Repurchase of common stock (57) - - (3) - - (3)
Taxes and other adjustments - - 2 (1) - - 1
Balance, December 31, 2022 96,755 $ 1 $ 3,469 $ 547 $ (10) $ 147 $ 4,154
Net Income - - - 384 - 12 396
Dividends declared on common stock ($2.76 per common share)
- - - (268) - - (268)
Distributions to noncontrolling interests - - - - - (18) (18)
Stock-based compensation and other 216 - 16 (2) - - 14
Other comprehensive income, net of tax - - - - 2 - 2
Balance, December 31, 2023 96,971 $ 1 $ 3,485 $ 661 $ (8) $ 141 $ 4,280
Net Income - - - 354 - 13 367
Issuance of common stock, net of issuance costs (a)
4,169 - 406 - - - 406
Dividends declared on common stock ($2.94 per common share)
- - - (288) - - (288)
Contributions from noncontrolling interests - - - - - 2 2
Distributions to noncontrolling interests - - - - - (17) (17)
Stock-based compensation and other 185 - 20 (4) - - 16
Balance, December 31, 2024 101,325 $ 1 $ 3,911 $ 723 $ (8) $ 139 $ 4,766
_____________________________________
(a)Issuance of common shares at $0.01 par value. See Note 8, "Earnings Per Share and Dividends," to the Consolidated Financial Statements.
See Notes to Consolidated Financial Statements
DT Midstream, Inc.
Notes to Consolidated Financial Statements
NOTE 1 - DESCRIPTION OF THE BUSINESS AND BASIS OF PRESENTATION
Description of the Business
DT Midstream is an owner, operator, and developer of an integrated portfolio of natural gas midstream assets. We provide multiple, integrated natural gas services to customers through two segments: (i) Pipeline, which includes interstate pipelines, intrastate pipelines, storage systems, gathering lateral pipelines including related treatment plants and compression and surface facilities, and (ii) Gathering, which includes gathering systems, related treatment plants, and compression and surface facilities. Our Pipeline segment also includes joint venture interests in equity method investees which own and operate interstate pipelines that connect to our wholly owned assets. On December 31, 2024, we closed on the Midwest Pipeline Acquisition of three FERC-regulated natural gas transmission pipelines. See Note 16, "Acquisitions" to the Consolidated Financial Statements.
Our core assets strategically connect key demand centers in the Midwestern U.S., Eastern Canada and Northeastern U.S. regions to the premium production areas of the Marcellus/Utica natural gas formation in the Appalachian Basin, and connect key demand centers and LNG export terminals in the Gulf Coast region to premium production areas of the Haynesville natural gas formation.
Basis of Presentation`
The Consolidated Financial Statements and Notes to Consolidated Financial Statements are prepared under GAAP.
These accounting principles require management to use estimates and assumptions that impact reported amounts of assets, liabilities, revenues and expenses, and the disclosure of contingent assets and liabilities. Actual results may differ from our estimates. We believe the assumptions underlying these financial statements are reasonable.
In our opinion, the accompanying Consolidated Financial Statements include all adjustments, consisting of normal recurring adjustments, necessary to present a fair statement of our financial position as of December 31, 2024, results of operations for the years ended December 31, 2024, 2023 and 2022, statement of changes in stockholders' equity for the years ended December 31, 2024, 2023 and 2022, and cash flows for the years ended December 31, 2024, 2023 and 2022.
Cash Management
Our sources of liquidity include cash generated from operations and available borrowings under our Revolving Credit Facility.
Principles of Consolidation
We consolidate all majority-owned subsidiaries and investments in entities in which we have a controlling influence. Non-controlled investments are accounted for using the equity method of accounting when we are able to significantly influence the operating policies of the investee. When we do not influence the operating policies of an investee, the equity investment is measured at fair value, if readily determinable, or if not readily determinable, at cost less impairment, if applicable. We eliminate all intercompany balances and transactions.
We evaluate whether an entity is a VIE whenever reconsideration events occur. We consolidate VIEs for which we are the primary beneficiary. When assessing the determination of the primary beneficiary, we consider all relevant facts and circumstances, including: the power, through voting or similar rights, to direct the activities of the VIE that most significantly impact the VIE's economic performance and the obligation to absorb the expected losses and/or the right to receive the expected returns of the VIE. We perform ongoing reassessments of all VIEs to determine if the primary beneficiary status has changed.
We own an 85% interest in the Stonewall VIE and are the primary beneficiary, therefore Stonewall is consolidated. We own a 50% interest in the South Romeo VIE and are the primary beneficiary, therefore South Romeo is consolidated.
DT Midstream, Inc.
Notes to Consolidated Financial Statements
The following table summarizes the major line items in the Consolidated Statements of Financial Position for consolidated VIEs as of December 31, 2024 and 2023. All assets and liabilities of a consolidated VIE are included in the table when it has been determined that a consolidated VIE has either (1) assets that can be used only to settle obligations of the VIE or (2) liabilities for which creditors do not have recourse to the general credit of the primary beneficiary. The assets and liabilities of consolidated VIEs that meet the definition of a business and whose assets can be used for purposes other than the settlement of the VIEs' obligations have been excluded from the table below.
December 31,
2024 2023
(millions)
ASSETS (a)
Cash $ 17 $ 13
Accounts receivable 11 10
Other current assets 2 2
Intangible assets, net 468 483
Property, plant and equipment, net 391 391
Goodwill 25 25
$ 914 $ 924
LIABILITIES (a)
Accounts payable and other current liabilities $ 5 $ 4
Other noncurrent liabilities 3 3
$ 8 $ 7
_____________________________________
(a)Amounts shown are 100% of the consolidated VIEs' assets and liabilities.
Related Parties
Transactions between DT Midstream and our equity method investees have been presented as related party transactions in the accompanying Consolidated Financial Statements. See Note 15, "Related Party Transactions" to the Consolidated Financial Statements.
Equity Method Investments
Non-controlled investments are accounted for using the equity method of accounting when we are able to significantly influence the operating policies of the investee. Under the equity method of accounting, investments are recorded at historical cost as an asset and adjusted for capital contributions, dividends and distributions received, and our share of the investee's earnings or losses, which are recorded as earnings from equity method investees on the Consolidated Statements of Operations. Equity method investments and related activity are included in the Pipeline segment.
Our equity method investments are periodically evaluated for certain factors that may be indicative of other-than-temporary impairment. As of December 31, 2024 and 2023, our carrying amounts of investments in equity method investees exceeded our share of the underlying equity in the net assets of the investees by $336 million and $352 million, respectively. The difference will be amortized over the life of the underlying assets. As of both December 31, 2024 and 2023, our consolidated retained earnings balance did not have undistributed earnings from equity method investments. We use the cumulative earnings approach to classify proceeds received from equity method investees as dividends or distributions on the Consolidated Statements of Cash Flows.
Earnings from equity method investees include:
Year Ended December 31,
2024 2023 2022
(millions)
NEXUS $ 62 $ 68 $ 61
Vector 41 38 36
Millennium 59 71 53
Total earnings from equity method investees $ 162 $ 177 $ 150
DT Midstream, Inc.
Notes to Consolidated Financial Statements
Equity method investees are described below:
Investments As of % Owned As of
December 31, December 31,
Equity Method Investee 2024 2023 2024 2023
(millions)
NEXUS $ 880 $ 900 50% 50%
Vector 134 135 40% 40%
Millennium 283 727 52.5% 52.5%
Total investments in equity method investees $ 1,297 $ 1,762
In September 2024, Millennium closed on the sale of $800 million of senior unsecured notes with a weighted-average coupon rate of 5.88%. We received a distribution from Millennium of $416 million, net of fees and expenses, which reduced our investment balance. We used the proceeds from the distribution to repay our existing indebtedness under our Term Loan Facility and for general corporate purposes.
In May 2023, NEXUS closed on the sale of $750 million of senior unsecured notes with a weighted-average coupon rate of 5.52%. We received a distribution from NEXUS of $371 million, net of fees and expenses, which reduced our investment balance. We used the proceeds from the distribution to repay borrowings outstanding under our Revolving Credit Facility.
In October 2022, DT Midstream closed on the $552 million purchase of an additional 26.25% ownership interest in Millennium from National Grid. The transaction was financed with cash on hand and available capacity under the Company's Revolving Credit Facility. The purchase constituted National Grid's full ownership interest in Millennium and brought our total ownership interest in Millennium to 52.5%. We account for our ownership interest in Millennium under the equity method of accounting. Millennium is not a VIE and we do not have a controlling interest due to shared control with our partner over all of Millennium's significant business activities. Our carrying amount of our Millennium investment exceeded our share of the underlying equity in the net assets of Millennium by $343 million on the acquisition date.
The following tables present summarized financial information of our non-consolidated equity method investees. The amounts included below represent 100% of the results of continuing operations of such entities, including the portion owned by other parties.
Summarized balance sheet data is as follows:
December 31,
2024 2023
(millions)
Current assets $ 170 $ 159
Noncurrent assets 3,939 4,057
Current liabilities 209 208
Noncurrent liabilities $ 1,930 $ 1,177
Summarized income statement data is as follows:
Year Ended December 31,
2024 2023 2022
(millions)
Operating revenues $ 818 $ 823 $ 800
Operating expenses 376 377 396
Net Income $ 364 $ 392 $ 372
DT Midstream, Inc.
Notes to Consolidated Financial Statements
NOTE 2 - SIGNIFICANT ACCOUNTING POLICIES
Cash and Cash Equivalents
Cash and cash equivalents include cash in banks and highly liquid money market investments with remaining maturities of three months or less, when purchased. Cash equivalents are stated at cost, which approximates fair value.
Financing Receivables
Financing receivables are primarily composed of trade accounts receivable and notes receivable, which are stated at net realizable value.
We regularly monitor the credit quality of our financing receivables by reviewing counterparty credit quality indicators and monitoring for triggering events, such as a credit rating downgrade or bankruptcy. We have three internal grades of credit quality, with internal grade 1 as the lowest risk and internal grade 3 as the highest risk. The related credit quality indicators and risk ratings utilized to develop the internal grades have been updated through December 31, 2024. As of December 31, 2024, the notes receivable - related party of $4 million, which originated prior to 2021, was classified as internal grade 1. There are no notes receivable on nonaccrual status and no past due financing receivables as of December 31, 2024.
Notes receivable are typically considered delinquent (past due) when payment is not received for periods ranging from 60 to 120 days. We cease accruing interest income (nonaccrual status) and may either write off or establish an allowance for expected credit loss for the note receivable when it is expected that all contractual principal or interest amounts due will not be collected. In determining an allowance for expected credit losses for or the write off of notes receivable, we consider the historical payment experience and other factors that are expected to have a specific impact on collection, including existing and future economic conditions. Cash receipts for notes receivable on nonaccrual status that do not bring the account contractually current are first applied to contractually owed past due interest, with any remainder applied to principal. Recognition of interest income is generally resumed when the note receivable becomes contractually current.
We had an investment in certain assets in the Utica Shale region which was accounted for as a note receivable - third party. A third party purchased our investment in certain assets in the Utica Shale region based on significantly improved commodity pricing during the second quarter 2022 for proceeds of $22 million. This resulted in a gain of $17 million recorded in Asset (gains) losses and impairments, net on the Consolidated Statement of Operations. We maintain no continuing involvement with the note receivable.
For trade accounts receivable, the customer allowance for expected credit loss is calculated based on specific review of future collections based on receivable balances generally in excess of 30 days. Existing and future economic conditions, historical loss rates, customer trends and other relevant factors that may affect our ability to collect are also considered. Receivables are written off on a specific identification basis and determined based on the particular circumstances of the associated receivable. Uncollectible expense (recovery) was zero for each of the years ended December 31, 2024, 2023 and 2022.
Our collections on accounts receivable from customers are current, and no material rate of historical loss was noted, which resulted in no allowance for expected credit loss as of December 31, 2024 or 2023. Any balance would be shown as a deduction from the respective financing receivable's balance in the Consolidated Statements of Financial Position.
Property, Plant, and Equipment
Property is stated at cost and includes construction-related labor, materials, overhead and capitalized interest. Property for FERC-Regulated entities includes equity AFUDC. Equity AFUDC represents the capitalization of the estimated average cost of equity during construction projects and is recorded as a credit to allowance for funds used during construction in our Consolidated Statements of Operations. Expenditures for maintenance and repairs are charged to expense when incurred. Property, plant and equipment is depreciated over its estimated useful life using the straight-line method. See Note 6, "Property, Plant, and Equipment and Intangible Assets" to the Consolidated Financial Statements.
DT Midstream, Inc.
Notes to Consolidated Financial Statements
On December 31, 2024, DT Midstream closed on the Midwest Pipeline Acquisition of three FERC-regulated natural gas transmission pipelines. These assets are accounted for under ASC 980, which in some cases requires that the cost of regulated property retired or sold, plus removal costs, less salvage, be charged to accumulated depreciation. For regulated assets, depreciation studies to assess the estimated useful lives of the asset are typically conducted as part of rate proceedings or tariff filings. Changes in economic lives, if applicable, are implemented prospectively as of the approved effective date. See Note 16, "Acquisitions" and Note 17, "Regulatory Matters" to the Consolidated Financial Statements.
Intangible Assets
Intangible assets with finite useful lives are amortized on a straight-line basis over the periods benefited. See Note 6, "Property, Plant, and Equipment and Intangible Assets" to the Consolidated Financial Statements.
Long-Lived Assets
Long-lived assets are reviewed for impairment whenever events or changes in circumstances indicate the carrying amount of an asset may not be recoverable. If the carrying amount of the asset exceeds the expected undiscounted future cash flows generated by the asset, an impairment loss is recognized resulting in the asset being written down to its estimated fair value. Assets to be disposed of are reported at the lower of the carrying amount or fair value, less costs to sell.
Purchase Accounting
In accordance with the business combination acquisition method of accounting, the assets acquired and liabilities assumed in an acquired business are measured at their estimated fair values at the acquisition date.
Goodwill
DT Midstream has goodwill resulting from business combinations. For each reporting unit with goodwill, we perform an impairment test annually or whenever events or circumstances indicate that the value of goodwill may be impaired.
Operation and Maintenance
Operation and maintenance is primarily comprised of costs for labor and employee benefits, outside services, materials, compression, purchased natural gas, operating lease costs, office costs, and other operating and maintenance costs.
Depreciation and Amortization
Depreciation and amortization is related to Property, plant and equipment and Customer relationships and other intangible assets, net, used in our transportation, storage and gathering businesses.
Other Significant Accounting Policies
Footnote Title
Note 1 Equity Method Investments
Note 4 Revenue
Note 7 Income Taxes
Note 9 Fair Value
Note 11 Leases
Note 14 Reportable Segments
Note 16 Acquisitions
Note 17 Regulation
DT Midstream, Inc.
Notes to Consolidated Financial Statements
NOTE 3 - NEW ACCOUNTING PRONOUNCEMENTS
Recently Adopted Pronouncements
In November 2023, the FASB issued ASU No. 2023-07, Segment Reporting (Topic 280) - Improvements to Reportable Segment Disclosures. The amendments improve reportable segment disclosure requirements, primarily through enhanced disclosures about significant segment expenses and interim disclosure requirements. The amendments are effective for fiscal years beginning after December 15, 2023 and interim periods within fiscal years beginning after December 15, 2024. Early adoption is permitted. We adopted this ASU on December 31, 2024, and applied the amendments retrospectively to all prior periods presented in our Consolidated Financial Statements. See Note 14, "Segment and Related Information," to the Consolidated Financial Statements.
Recently Issued Pronouncements
In December 2023, the FASB issued ASU No. 2023-09, Income Taxes (Topic 740) - Improvements to Income Tax Disclosures. The amendments improve transparency of income tax disclosure requirements, primarily through enhanced disclosures of rate reconciliation and income taxes paid. The amendments are effective for annual periods beginning after December 15, 2024. Early adoption is permitted. We continue to evaluate the impact of this standard's adoption on our Consolidated Financial Statements.
In November 2024, the FASB issued ASU No. 2024-03, Income Statement-Reporting Comprehensive Income-Expense Disaggregation Disclosures (Subtopic 220-40) - Disaggregation of Income Statement Expenses. The amendments require enhanced disclosures of specified costs and expenses included in significant expense captions in the income statement, including purchases of inventory, employee compensation, depreciation, amortization, and other key amounts. The FASB subsequently issued ASU No. 2025-01 in January 2025 to clarify the effective date of ASU No. 2024-03. The amendments are effective for fiscal years beginning after December 15, 2026 and interim reporting periods within annual reporting periods beginning after December 15, 2027. Early adoption is permitted. We are currently evaluating the impact of this standard's adoption on our Consolidated Financial Statements.
NOTE 4 - REVENUE
Significant Accounting Policy - Revenue
Pipeline revenues consist of services related to the gathering, transportation and/or storage of natural gas. Gathering revenues consist of services related to the gathering, processing, and/or treating of natural gas. Revenue is measured based upon the pricing or consideration for such services specified in the contract with a customer. Consideration may consist of both fixed components including fixed demand charges and fixed deficiency fee rates for MVCs, and variable components including fixed rates for the actual volumes flowed under interruptible services and other associated fees.
Our contracts with customers generally contain a single performance obligation, which is a promise to deliver either a distinct service or a series of distinct services to the customer. When multiple performance obligations exist, the contract consideration is allocated between the performance obligations based on the relative standalone selling price, which is determined by prices charged to customers or the adjusted market assessment approach. The adjusted market assessment approach involves evaluating the market in which we sell services and estimating the price that a customer in that market would be willing to pay.
Revenue is recognized when performance obligations are satisfied by delivering a service to a customer, which occurs when the service is provided to the customer. When a customer simultaneously receives and consumes the service provided, revenue is recognized over time. Alternatively, if it is determined that the criteria for recognition of revenue over time is not met, the revenue is considered to be recognized at a point in time. Our revenues, including estimated unbilled amounts, are generally recognized over time as actual services are provided, or ratably over time when providing a stand-ready service. Unbilled amounts are generally determined using preliminary meter data volumes and contracted pricing, and typically result in minor adjustments. Generally, uncertainties in the variable consideration components are resolved and revenue amounts are known at the time of recognition. We have determined that the above methods represent a faithful depiction of delivering a service to the customer. Revenues are typically billed and consideration received monthly, however, certain deficiency fees related to MVCs are billed quarterly or annually.
DT Midstream, Inc.
Notes to Consolidated Financial Statements
Disaggregation of Revenue
The following is a summary of revenues disaggregated by segment:
Year Ended December 31,
2024 2023 2022
(millions)
Pipeline (a)
$ 443 $ 377 $ 339
Gathering 538 545 581
Total operating revenues $ 981 $ 922 $ 920
__________________________________
(a) Includes revenues outside the scope of ASC 606 primarily related to contracts accounted for as leases of $9 million, $7 million and $10 million for the years ended December 31, 2024, 2023 and 2022, respectively.
Nature of Services
We primarily provide two types of revenue services: firm service and interruptible service. Firm service revenue contracts provide for fixed revenue commitments regardless of actual volumes of natural gas that flow, which leads to more stable operating performance, revenues and cash flows and limits our exposure to natural gas price fluctuations. Firm service revenue contracts are typically long-term and structured using fixed demand charges or MVCs with fixed deficiency fee rates. Contracts structured using fixed demand charges contain a performance obligation of a stand-ready series of distinct services that are substantially the same with the same pattern of transfer to the customer, therefore revenue is recognized ratably over time. Contracts structured using MVCs with fixed deficiency fee rates require customers to transport or store a minimum volume of natural gas over a specified time period. If a customer fails to meet its MVCs for the specified time period, the contract consideration includes a fixed rate for the actual volumes gathered, transported or stored, and a deficiency fee for the shortfall between the MVCs and the actual volumes gathered, transported, or stored. If a customer exceeds its MVC for the specified time period, the contract consideration is based on fixed rates for the actual volumes gathered, transported, or stored. The contract consideration is allocated to each distinct monthly performance obligation, consistent with the allocation objective and based upon the level of effort required to satisfy the service obligation. Revenues are generally recognized over time based on the output measure of natural gas volumes gathered, transported, or stored, with the recognition of the deficiency fee revenue in the period when it is known the customer cannot make up the deficient volumes in the specified time period. Interruptible service revenue contracts typically contain fixed rates, with total consideration dependent on actual natural gas volumes that flow. Interruptible service revenues are recognized over time based on the output measure of natural gas volumes gathered, transported, or stored. Certain of our gathering contracts allow for the recovery of production-related operating expenses, which are offsetting in revenue and operating expense. Recovery of production-related operating expenses were $51 million, $53 million and $65 million for the years ended December 31, 2024, 2023 and 2022, respectively.
Contract Liabilities
The following is a summary of contract liability activity:
2024 2023
(millions)
Balance as of January 1 $ 129 $ 32
Increases due to cash received or receivable, excluding amounts recognized as revenue during the period (a)
47 101
Revenue recognized that was included in the balance at the beginning of the period (23) (4)
Balance as of December 31
$ 153 $ 129
__________________________________
(a) During the year ended December 31, 2024 and 2023, we collected prepayment amounts from customers under various long-term revenue contracts on Ohio Utica Gathering, Appalachia Gathering, Blue Union Gathering and LEAP.
DT Midstream, Inc.
Notes to Consolidated Financial Statements
Contract liabilities generally represent amounts paid by or receivable from customers for which the associated performance obligation has not yet been satisfied. Contract liabilities associated with these services are recognized upon delivery of the service to the customer.
The following table presents contract liability amounts as of December 31, 2024 that are expected to be recognized as revenue in future periods:
(millions)
2025 $ 18
2026 18
2027 18
2028 16
2029 16
2030 and thereafter 67
Total $ 153
Transaction Price Allocated to the Remaining Performance Obligations
In accordance with optional exemptions available under ASC 606, we do not disclose the value of unsatisfied performance obligations for (1) contracts with an original expected length of one year or less, (2) with the exception of fixed consideration, contracts for which the amount of revenue recognized depends upon our invoices for actual volumes gathered, transported, or stored, and (3) contracts for which variable consideration relates entirely to an unsatisfied performance obligation.
Such contracts consist of various types of performance obligations, including providing midstream services. Contracts with variable volumes and/or variable pricing, including those with pricing provisions tied to a consumer price or other index, have also been excluded as the related contract consideration is variable at the contract inception. Contract lengths vary from cancellable to multi-year.
The following table presents revenue amounts related to fixed consideration associated with unsatisfied performance obligations as of December 31, 2024 that are expected to be recognized as revenue in future periods:
(millions)
2025 $ 265
2026 223
2027 226
2028 181
2029 149
2030 and thereafter 268
Total $ 1,312
Costs to Obtain or Fulfill a Contract
We recognize an asset from the costs incurred to obtain a revenue contract only if we expect to recover those costs. In addition, the costs to fulfill a revenue contract are capitalized if the costs are specifically identifiable to a revenue contract, would result in enhancing resources that will be used in satisfying performance obligations in the future, and are expected to be recovered. These capitalized costs are amortized on a systematic basis consistent with the pattern of transfer of the services to which such costs relate.
As of December 31, 2024 and 2023, we had capitalized costs to obtain or fulfill a contract of $18 million, which are included in other current assets and other noncurrent assets in the accompanying Consolidated Statements of Financial Position. During the years ended December 31, 2024, 2023 and 2022 we recognized $1 million of amortization expense related to such capitalized costs.
DT Midstream, Inc.
Notes to Consolidated Financial Statements
Major Customers
The following table summarizes the customer which represents 10% or more of our total revenue for the years ended December 31, 2024, 2023 and 2022. Both Pipeline and Gathering segments provided services to this customer.
2024 2023 2022
Customer Percentage Customer Percentage Customer Percentage
Revenue of Total Revenue of Total Revenue of Total
Customer: (millions, except percentages)
Expand Energy $ 555 56 % $ 560 60 % $ 596 65 %
NOTE 5 - GOODWILL
We have goodwill that resulted from business combinations. The carrying value of goodwill is evaluated for impairment on an annual basis or whenever events or circumstances indicate that the value of goodwill may be impaired. We performed our annual impairment test as of October 1, 2024 and determined that the estimated fair value of each reporting unit exceeded its carrying value, and no impairment existed. We recognized goodwill as of December 31, 2024 as part of the Midwest Pipeline Acquisition in the Pipeline reporting unit. See Note 16, "Acquisitions" to the Consolidated Financial Statements.
The following is the summary of the change in the carrying amount of goodwill:
2024 2023
(millions)
Balance at January 1 $ 473 $ 473
Goodwill attributable to the Midwest Pipeline Acquisition 303 -
Balance at December 31 $ 776 $ 473
The following is a summary of the carrying value of goodwill by reporting unit:
December 31,
2024 2023
(millions)
Pipeline $ 356 $ 53
Gathering 420 420
Total goodwill $ 776 $ 473
While we believe the estimates and assumptions in the estimated fair value are reasonable, the actual results may differ from projections. To the extent projected results or cash flows are revised downward, the reporting unit may be required to write down all or a portion of its goodwill, which would adversely impact our earnings.
DT Midstream, Inc.
Notes to Consolidated Financial Statements
NOTE 6 - PROPERTY, PLANT, AND EQUIPMENT AND INTANGIBLE ASSETS
Property, Plant, and Equipment
The following is a summary of Property, plant, and equipment by classification:
Average Estimated Useful Life
December 31,
2024 2023
(years) (millions)
Property, plant, and equipment
Land and other non-depreciable assets N/A $ 105 $ 96
Rights of way and easements 25 to 53
168 103
Pipelines and interconnects 10 to 95
4,437 3,460
Facilities and processing plants 7 to 50
1,364 1,234
Wells and well equipment 40 to 70
70 70
General plant 3 to 40
60 40
Construction in progress N/A 321 279
Total Property, plant, and equipment $ 6,525 $ 5,282
Less accumulated depreciation (998) (848)
Net Property, plant, and equipment $ 5,527 $ 4,434
Intangible Assets
The following is a summary of Intangible Assets by classification:
December 31, 2024 December 31, 2023
Useful Lives
Gross Carrying Value
Accumulated Amortization
Net Carrying Value
Gross Carrying Value
Accumulated Amortization
Net Carrying Value
(millions)
Intangible assets subject to amortization
Customer relationships
3 - 40 years (a)
$ 2,262 $ (345) $ 1,917 $ 2,252 $ (289) $ 1,963
Contract intangibles 14 - 26 years
18 (14) 4 18 (13) 5
Total $ 2,280 $ (359) $ 1,921 $ 2,270 $ (302) $ 1,968
_____________________________________
(a) The useful lives of the customer relationship intangible assets are based on the number of years in which the assets are expected to economically contribute to the business. The expected economic benefit incorporates existing customer contracts and expected renewal rates based on the estimated volume and production lives of natural gas resources in each region.
The following table summarizes estimated customer relationships and contract intangibles amortization expense to be recognized during each year through 2029:
2025 2026 2027 2028 2029
(millions)
Estimated amortization expense $ 60 $ 60 $ 60 $ 59 $ 59
Depreciation and Amortization
The following is a summary of depreciation and amortization expense by asset type:
Year Ended December 31,
2024 2023 2022
(millions)
Property, plant, and equipment $ 152 $ 125 $ 113
Customer relationships and other intangible assets, net 57 57 57
Total Depreciation and amortization $ 209 $ 182 $ 170
DT Midstream, Inc.
Notes to Consolidated Financial Statements
NOTE 7 - INCOME TAXES
Significant Accounting Policy - Accounting for Income Taxes
We record the effect of income taxes in accordance with GAAP, which provides for the use of an asset and liability approach. Deferred income tax assets and liabilities are recognized for temporary differences between the basis of assets and liabilities for financial reporting and tax purposes and measured using enacted tax rates in effect for the year in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities as a result of changes in the enacted tax rates is recognized in earnings in the period of enactment. Our recognition of deferred tax assets is based upon a more-likely-than-not criterion. We routinely assess realizability based on objectively-weighted, available positive and negative evidence.
We account for uncertainties in income taxes using a benefit recognition model with a two-step approach: a more-likely-than-not recognition criterion, and a measurement attribute that measures the position as the largest amount of tax benefit that is greater than a 50% likelihood of being realized upon ultimate settlement. If the benefit does not meet the more likely than not criteria for being sustained on its technical merits, no benefit will be recorded. Uncertain tax positions that relate only to timing of when an item is included on a tax return are considered to have met the recognition threshold.
Midwest Pipeline Acquisition
The Midwest Pipeline Acquisition was treated as a deemed asset acquisition which was taxable for federal and state income tax purposes as a result of 1) making tax elections promulgated under Internal Revenue Code §338(h)(10) for the acquired entities which were treated as corporations under Subchapter C of the Internal Revenue Code, and 2) all single member Limited Liability Companies ("LLC") being treated as disregarded entities for income tax purposes. Accordingly, the majority of deferred income tax assets and liabilities of the acquired entities are eliminated as the tax bases were increased to fair market value which equals net book value. The election resulted in tax-deductible goodwill which is subject to revision during the one-year period as additional information is obtained about facts and circumstances that existed at closing and purchase price allocations are completed/reported on income tax returns.
As a result of changes to the expected state apportionment factors and rates due to the Midwest Pipeline Acquisition, the Company recorded a remeasurement to increase the existing deferred income tax liabilities of DT Midstream (acquiring entity) by $22 million which was charged to income tax expense. See Note 16, "Acquisitions" to the Consolidated Financial Statements.
Tax Legislation
On December 4, 2024, the State of Louisiana enacted a series of tax bills aimed at overall tax reform across multiple state tax regimes including income, franchise, and sales and use. House Bill 2 imposes a flat 5.5% (previously tiered from 3.5% to 7.5%) corporate income tax rate beginning January 1, 2025. In accordance with tax accounting guidance, DT Midstream recorded the remeasurement as a deferred income tax benefit of $4 million. Other enacted law changes include the repeal of the Louisiana franchise tax and increased state sales and use tax rates, which will take effect in future years and are not expected to have a material impact on the financial statements.
On July 8, 2022, the Commonwealth of Pennsylvania enacted House Bill 1342 which includes a corporate income tax rate reduction from 9.99% to 4.99% that will phase-in over a nine-year period.
DT Midstream, Inc.
Notes to Consolidated Financial Statements
Our total Income Tax Expense varied from the statutory federal income tax rate for the following reasons:
Year Ended December 31,
2024 2023 2022
(millions)
Income Before Income Taxes $ 504 $ 500 $ 482
Income tax expense at statutory rate 106 105 101
State and local income taxes, net of federal benefit 18 18 24
State tax rate changes 15 (18) (25)
Other, net (2) (1) -
Income Tax Expense $ 137 $ 104 $ 100
Effective income tax rate 27.3 % 20.9 % 20.7 %
The State tax rate changes line in the table above includes state deferred remeasurements recorded in each of the respective years discussed below.
Our 2024 effective tax rate includes a $15 million expense driven by updates to state rates and apportionment factors, primarily related to the Midwest Pipeline Acquisition and tax legislation, as discussed above.
Our 2023 effective tax rate includes the impact of state tax rate changes of an $18 million benefit driven by changes in tax status and updates to state apportionment which were completed in 2023 as a part of ongoing corporate tax structuring, simplification initiatives, and initial post-separation full-year tax return filings.
Our 2022 effective tax rate includes the impact of state tax rate changes of a $25 million benefit driven by the Pennsylvania legislative changes.
Components of Income tax expense were as follows:
Year Ended December 31,
2024 2023 2022
(millions)
Current income tax expense
Federal $ 13 $ (4) $ 16
State and other income tax 4 (2) 14
Total current income tax expense 17 (6) 30
Deferred income tax expense
Federal 84 109 86
State and other income tax 36 1 (16)
Total deferred income tax expense 120 110 70
Total Income Tax Expense $ 137 $ 104 $ 100
Deferred tax assets and liabilities are recognized for the estimated future tax effect of temporary differences between the tax basis of assets or liabilities and the reported amounts in our Consolidated Financial Statements. We believe it is more likely than not that we will generate sufficient taxable income in future periods to realize our deferred tax assets.
DT Midstream, Inc.
Notes to Consolidated Financial Statements
Deferred tax assets (liabilities) were comprised of the following:
December 31,
2024 2023
(millions)
Deferred income tax balance components
Property, plant, and equipment $ (369) $ (369)
Federal net operating loss carry-forward 117 184
State and local net operating loss carry-forward, net of federal 75 102
Investment in equity method investees and partnerships (970) (979)
Other 18 31
Net deferred income tax asset / (liability) $ (1,129) $ (1,031)
Total deferred income tax assets and liabilities
Deferred income tax assets $ 266 $ 319
Deferred income tax liabilities (1,395) (1,350)
Net deferred income tax asset / (liability) $ (1,129) $ (1,031)
We have recorded a deferred tax asset related to a federal net operating loss carry-forward of $117 million as of December 31, 2024. U.S. federal net operating losses will be available to be carried forward indefinitely and available to offset 80% of taxable income in future years.
We have recorded state and local deferred tax assets related to net operating loss carry-forwards of $75 million as of December 31, 2024. Of the state and local net operating loss carry-forwards, $70 million can be carried indefinitely and $5 million will expire from 2033 through 2042 and are available to offset varying amounts of taxable income in future years.
Uncertain Tax Positions
As of December 31, 2024 and 2023, we did not have any unrecognized tax benefits. Our income tax returns remain subject to examination by federal, state, and local taxing jurisdictions.
DT Midstream, Inc.
Notes to Consolidated Financial Statements
NOTE 8 - EARNINGS PER SHARE AND DIVIDENDS
Basic earnings per share is calculated by dividing Net Income attributable to DT Midstream by the weighted-average number of common shares outstanding during the period. Diluted earnings per share reflect the dilution that would occur if any potentially dilutive instruments were exercised or converted into common shares, using the treasury stock method. Restricted stock units and performance share awards, including dividend equivalents on those grants, are potentially dilutive and, if dilutive, are included in the determination of weighted-average shares outstanding. Restricted stock units and performance share awards do not receive cash dividends, as such, these awards are not considered participating securities.
In November 2024, we issued 4,168,750 common shares at a price to the public of $101.00 per share and received net proceeds of approximately $406 million in anticipation of the Midwest Pipeline Acquisition. See Note 16, "Acquisitions" to the Consolidated Financial Statements.
The following is a reconciliation of basic and diluted earnings per share:
Year Ended December 31,
2024 2023 2022
(millions, except per share amounts)
Basic and Diluted Earnings per Common Share
Net Income Attributable to DT Midstream $ 354 $ 384 $ 370
Average number of common shares outstanding - basic 97.6 96.9 96.7
Incremental shares attributable to:
Average dilutive restricted stock units and performance share awards 0.8 0.6 0.5
Average number of common shares outstanding - diluted 98.4 97.5 97.2
Basic Earnings per Common Share $ 3.63 $ 3.97 $ 3.83
Diluted Earnings per Common Share $ 3.60 $ 3.94 $ 3.81
We declared the following cash dividends:
Dividends Declared Dividend Amount Dividend Payment Date
(quarter ended) (per-share) (millions)
March 31 $ 0.64 $ 62 April 2022
June 30 $ 0.64 $ 62 July 2022
September 30 $ 0.64 $ 62 October 2022
December 31 $ 0.64 $ 62 January 2023
March 31 $ 0.69 $ 67 April 2023
June 30 $ 0.69 $ 67 July 2023
September 30 $ 0.69 $ 67 October 2023
December 31 $ 0.69 $ 67 January 2024
March 31 $ 0.735 $ 71 April 2024
June 30 $ 0.735 $ 71 July 2024
September 30 $ 0.735 $ 71 October 2024
December 31 $ 0.735 $ 75 January 2025
DT Midstream, Inc.
Notes to Consolidated Financial Statements
NOTE 9 - FAIR VALUE
Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date in a principal or most advantageous market. Fair value is a market-based measurement that is determined based on inputs, which refer broadly to assumptions that market participants use in pricing assets or liabilities. These inputs can be readily observable, market corroborated, or generally unobservable inputs. We make certain assumptions we believe that market participants would use in pricing assets or liabilities, including assumptions about risk, and the risks inherent in the inputs to valuation techniques. We believe we use valuation techniques that maximize the use of observable market-based inputs and minimize the use of unobservable inputs.
Significant Accounting Policy - Fair Value
A fair value hierarchy has been established that prioritizes the inputs to valuation techniques used to measure fair value in three broad levels. The fair value hierarchy gives the highest priority to quoted prices (unadjusted) in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). In some cases, the inputs used to measure fair value might fall in different levels of the fair value hierarchy. All assets and liabilities are required to be classified in their entirety based on the lowest level of input that is significant to the fair value measurement in its entirety. Assessing the significance of a particular input may require judgment considering factors specific to the asset or liability and may affect the valuation of the asset or liability and its placement within the fair value hierarchy. We classify fair value balances based on the fair value hierarchy defined as follows:
•Level 1 - Consists of unadjusted quoted prices in active markets for identical assets or liabilities that we have the ability to access as of the reporting date.
•Level 2 - Consists of inputs other than quoted prices included within Level 1 that are directly observable for the assets or liabilities or indirectly observable through corroboration with observable market data.
•Level 3 - Consists of unobservable inputs for assets or liabilities whose fair value is estimated based on internally developed models or methodologies using inputs that are generally less readily observable and supported by little, if any, market activity at the measurement date. Unobservable inputs are developed based on the best available information and subject to cost-benefit constraints.
Fair Value of Financial Instruments
The following table presents the carrying amount and fair value of financial instruments:
December 31, 2024 December 31, 2023
Carrying Fair Value Carrying Fair Value
Amount Level 1 Level 2 Level 3 Amount Level 1 Level 2 Level 3
(millions)
Cash equivalents (a)
$ - $ - $ - $ - $ 36 $ - $ 36 $ -
Long-term notes receivable - related party 4 - - 4 4 - - 4
Short-term borrowings (a)
150 - 150 - 165 - 165 -
Long-term debt (b)
$ 3,319 $ - $ 3,136 $ - $ 3,065 $ - $ 2,850 $ -
______________________________________
(a)Short-term borrowings and money market cash equivalents are stated at cost, which approximates fair value.
(b)Carrying value as of December 31, 2024 and 2023 represents principal of $3.4 billion and $3.1 billion, respectively, net of unamortized debt discounts and issuance costs.
On December 31, 2024, we closed on the Midwest Pipeline Acquisition, and assets acquired and liabilities assumed were measured at estimated fair value. See Note 16, "Acquisitions" to the Consolidated Financial Statements.
DT Midstream, Inc.
Notes to Consolidated Financial Statements
NOTE 10 - DEBT
Amendments to Credit Agreement
In December 2024, we amended our Credit Agreement to, among other things, extend the Revolving Credit Facility maturity date to December 2029 and implement customary "limited condition transaction provisions", enabling us to enter into future acquisitions and other transactions with the conditionality to the consummation thereof subject only to customary "SunGard" conditions, which provide additional financing certainty and reduce the number of conditions required. In November 2024, we amended our Credit Agreement to permit the Company to incur certain customary bridge loans, including the Bridge Facility, a $700 million 364-day bridge loan facility committed by Barclays Bank PLC, which provided certain backstop funding for our Midwest Pipeline Acquisition. Bridge Facility issuance fees of $4 million were incurred during the year ended December 31, 2024 and recorded as interest expense on our Consolidated Statements of Operations.
In June 2023, we amended our Credit Agreement which modified certain of the terms, including, among other things, the replacement of the interest rate provisions related to the Term Loan Facility from Eurodollar Rate to Term SOFR (as defined in the Credit Agreement).
In October 2022, we amended the Credit Agreement to increase the Revolving Credit Facility commitments by $250 million to aggregate commitments of $1.0 billion. The amendment also extended the Revolving Credit Facility maturity date to October 2027, replaced the Revolving Credit Facility's LIBOR interest rate references with Term SOFR, and incorporated various amendments, including amendments to pricing, guarantee and collateral provisions, that will become effective if we receive an investment-grade rating from two of the three credit rating agencies.
Debt Issuances
In November 2024, we issued $650 million in aggregate principal amount of 5.800% senior secured notes due December 2034. The 2034 Notes are guaranteed by certain of our subsidiaries and secured by a first priority lien on certain assets of DT Midstream and our subsidiary guarantors that secure our existing credit facilities. As part of the issuance of the 2034 Notes, we capitalized debt issuance costs and discount costs of approximately $5 million and $1 million, respectively.
In April 2022, we issued $600 million in aggregate principal amount of 4.300% senior secured notes due April 2032. The 2032 Notes are guaranteed by certain of our subsidiaries and secured by a first priority lien on certain assets of DT Midstream and our subsidiary guarantors that secure our existing credit facilities. The 2032 Notes have a security fall away provision where the collateral securing the notes will be released if we receive an investment-grade rating from two of the three credit rating agencies.
Debt Redemptions
In September 2024, we repaid the remaining indebtedness under the Term Loan Facility of $399 million. The early redemption resulted in a loss on extinguishment of debt of $4 million related to the write-off of unamortized discount and issuance costs, which was recorded as a loss from financing activities on our Consolidated Statements of Operations for the year ended December 31, 2024. There were no prepayment costs in conjunction with the early redemption of the Term Loan Facility.
In April 2022, we used $593 million of the net proceeds from the sale of the 2032 Notes to make a partial repayment on the existing indebtedness under the Term Loan Facility. The early redemption resulted in a loss on extinguishment of debt of $9 million and loss on modification of debt of $4 million related to the write-off of unamortized discount and issuance costs, which was recorded as a loss from financing activities in our Consolidated Statements of Operations for the year ended December 31, 2022. There were no prepayment costs in conjunction with the partial redemption of the Term Loan Facility.
DT Midstream, Inc.
Notes to Consolidated Financial Statements
Interest Expense
The following table summarizes our interest expense:
Year Ended December 31,
2024 2023 2022
(millions)
Interest expense $ 163 $ 170 $ 142
Capitalized interest (10) (20) (5)
Total interest expense, net $ 153 $ 150 $ 137
Long-Term Debt
The following is a summary of long-term debt:
Maturity December 31, December 31,
Title Type Interest Rate Date 2024 2023
(millions)
2029 Notes Senior Notes (a)
4.125% 2029 $ 1,100 $ 1,100
2031 Notes Senior Notes (a)
4.375% 2031 1,000 1,000
2032 Notes Senior Secured Notes (b)
4.300% 2032 600 600
2034 Notes Senior Secured Notes (a)
5.800% 2034 650 -
Term Loan Facility Term Loan Facility Variable 2028 - 399
Long-term debt principal 3,350 3,099
Unamortized debt discount (1) (2)
Unamortized debt issuance costs (30) (32)
Long-term debt, net $ 3,319 $ 3,065
______________________________
(a) Interest payable semi-annually in arrears each June 15 and December 15. The first interest payment due on the 2034 Notes is June 15, 2025.
(b) Interest payable semi-annually in arrears each April 15 and October 15.
The following table presents scheduled debt maturities, excluding any unamortized discount on debt:
2025 2026 2027 2028 2029 and Thereafter Total
(millions)
Debt maturities $ - - - - 3,350 $ 3,350
Short-Term Credit Arrangements and Borrowings
The following table presents the availability under the Revolving Credit Facility:
December 31,
(millions)
Total availability
Revolving Credit Facility, expiring December 2029
$ 1,000
Amounts outstanding
Revolving Credit Facility borrowings (a)
Letters of credit 16
Net availability $ 834
______________________________
(a) The weighted average interest rate for Revolving Credit Facility borrowings outstanding was 4.34% as of December 31, 2024.
DT Midstream, Inc.
Notes to Consolidated Financial Statements
Borrowings under the Revolving Credit Facility, if any, are used for general corporate purposes, acquisitions, and letter of credit issuances to support our operations and liquidity. The 2024 amendment costs of the Revolving Credit Facility of $3 million were capitalized during the year ended December 31, 2024. Revolving Credit Facility issuance and amendment costs, net of amortization, of $7 million and $6 million as of December 31, 2024 and 2023, respectively, are included in other noncurrent assets in our Consolidated Statements of Financial Position and are being amortized over the remaining term of the Revolving Credit Facility.
The Credit Agreement covering the Revolving Credit Facility includes financial covenants that we must maintain. These covenants restrict the ability of DT Midstream and our subsidiaries to incur additional indebtedness and guarantee indebtedness, create or incur liens, engage in mergers, consolidations, liquidations or dissolutions, sell, transfer or otherwise dispose of assets, make investments, acquisitions, loans or advances, pay dividends and distributions or repurchase capital stock, prepay, redeem or repurchase certain junior indebtedness, enter into agreements that limit the ability of the restricted subsidiaries to make distributions to DT Midstream or the ability of DT Midstream and our restricted subsidiaries to incur liens on assets and enter into certain transactions with affiliates. The Revolving Credit Facility requires maintenance of (i) a maximum consolidated net leverage ratio of 5 to 1 (except, that the Company may elect to temporarily step up the maximum consolidated net leverage ratio to 5.5 to 1 for a period of up to three fiscal quarters after the consummation of an acquisition or investment involving consideration exceeding $50 million), and (ii) a minimum interest coverage ratio of no less than 2.5 to 1. The consolidated net leverage ratio means the ratio of net debt determined in accordance with GAAP to annual consolidated EBITDA, as defined in the Credit Agreement. The interest coverage ratio means the ratio of annual consolidated EBITDA to annual interest expense, as defined in the Credit Agreement. The Credit Agreement definition of annual consolidated EBITDA excludes EBITDA from equity method investees, but includes dividends and distributions from equity method investees. As of December 31, 2024, the consolidated net leverage ratio and the interest coverage ratio were 2.3 to 1 and 9.3 to 1, respectively, and we were in compliance with these financial covenants.
Dividend Restrictions
The indentures governing our Senior and Senior Secured Notes permit the payment of quarterly dividends on common stock in each fiscal year up to a dividend capacity calculated as defined in the indentures. For 2024, the dividend capacity remaining at year end was $537 million.
The Credit Agreement permits the payment of quarterly dividends on common stock in each fiscal year as long as giving pro forma effect thereto, we maintain a first lien net leverage ratio that does not exceed 3.25 to 1. We maintained such first lien net leverage ratio as of December 31, 2024.
NOTE 11 - LEASES
Lessee
Our leases are primarily comprised of equipment and buildings with terms ranging from approximately 1 to 11 years.
A lease exists when we have the right to control the use of identified property, plant or equipment, as conveyed through a contract, for a certain time period and consideration paid. The right to control is deemed to occur when we have the right to obtain substantially all of the economic benefits of the identified assets and the right to direct the use of such assets.
Significant Accounting Policy - Lessee Accounting
Lease liabilities are calculated utilizing a discount rate to determine the present values of lease payments. GAAP requires the use of the rate implicit in the lease if it is readily determinable. When the rate implicit in the lease is not readily determinable, the incremental borrowing rate is used. The incremental borrowing rate is based upon the rate of interest that would have been paid on a collateralized basis over similar contract terms to that of the leases. The incremental borrowing rates have been determined utilizing an implied secured borrowing rate based upon an unsecured rate for a similar time period of remaining lease terms, which is then adjusted for the estimated impact of collateral. We have leases with non-index-based escalation clauses for fixed dollar or percentage increases over the contract term.
We have certain leases which contain purchase options. Based upon the nature of the leased property and terms of the purchase options, we have determined it is not reasonably certain that such purchase options will be exercised. Thus, the impact of the purchase options has not been included in the determination of right-of-use assets and lease liabilities for the subject leases.
DT Midstream, Inc.
Notes to Consolidated Financial Statements
We have certain leases which contain renewal options. Where the renewal options were deemed reasonably certain to occur, the impacts of such options were included in the determination of the right-of-use assets and lease liabilities for the subject leases.
We have agreements with lease and non-lease components, which are generally accounted for separately. Consideration in a lease is allocated between lease and non-lease components based upon the estimated relative standalone prices.
The components of lease cost for the following years includes:
Year Ended December 31,
2024 2023 2022
(millions)
Operating lease cost $ 21 $ 20 $ 20
Short-term lease cost 3 3 3
$ 24 $ 23 $ 23
Operating lease cost includes amortization of operating lease right-of-use assets and other related costs. We have elected not to apply the lease balance sheet recognition requirements to short-term leases with a term of 12 months or less. Operating and short-term lease costs are recorded to operation and maintenance in our Consolidated Statements of Operations.
Other relevant information related to leases for the following years includes:
Year Ended December 31,
2024 2023 2022
Supplemental Cash Flows Information (millions, except years and percentages)
Cash paid for amounts included in the measurement of these liabilities:
Operating cash flows for operating leases $ 21 $ 21 $ 18
Right-of-use assets obtained in exchange for lease obligations:
Operating leases $ 29 $ 25 $ 14
Weighted Average Remaining Lease Term
Operating leases 3.9 years 4.4 years 4.0 years
Weighted Average Discount Rate
Operating leases 5.3 % 4.8 % 3.5 %
Future minimum lease payments under leases for remaining periods as of December 31, 2024 are as follows:
Operating Leases
(millions)
2025 $ 17
2026 15
2027 14
2028 6
2029 2
2030 and thereafter 3
Total future minimum lease payments 57
Imputed interest (5)
Lease liabilities $ 52
Lessor
A lease exists when we have provided other parties with the right to control the use of identified property, plant or equipment, as conveyed through a contract, for a certain time period and consideration received. The right to control is deemed to occur when we have provided other parties with the right to obtain substantially all of the economic benefits of the identified assets and the right to direct the use of such assets.
DT Midstream, Inc.
Notes to Consolidated Financial Statements
We lease certain assets under an operating lease for a pipeline which commenced in December 2018. The lease is comprised of fixed payments with a remaining term of 14 years. The operating lease does not have renewal provisions or options to purchase the assets at the end of the lease and does not have termination for convenience provisions. The lease term extends to the end of the estimated economic life of the leased assets, thereby resulting in no residual value.
As part of the Midwest Pipeline Acquisition, one pipeline has agreements with a customer and its subsidiaries that results in the use of substantially all the pipeline's capacity through 2026 and represents an operating lease.
Fixed lease income associated with the operating lease was $9 million, $7 million, and $10 million for the years ended December 31, 2024, 2023 and 2022, respectively. Fixed lease income is reported in Operating revenues in our Consolidated Statements of Operations. Depreciation expense associated with the property under the operating lease was $3 million for each of the years ended December 31, 2024, 2023 and 2022.
Future minimum rental revenues for remaining periods as of December 31, 2024 are as follows:
Operating Lease
(millions)
2025 $ 77
2026 62
2027 9
2028 9
2029 9
2030 and thereafter 79
Total future minimum rental revenues $ 245
Property under the operating lease is as follows:
December 31,
2024 2023
(millions)
Gross property under operating leases $ 484 $ 58
Accumulated amortization of property under operating leases $ 17 $ 15
NOTE 12 - COMMITMENTS AND CONTINGENCIES
From time to time, we are subject to legal, administrative and environmental proceedings before various courts, arbitration panels and governmental agencies concerning claims arising in the ordinary course of business. These proceedings include certain contract disputes, additional environmental reviews and investigations, audits and pending judicial matters. We cannot predict the final disposition of such proceedings. We regularly review legal matters and record provisions for claims that we can estimate and are considered probable of loss. The amount or range of reasonably possible losses is not anticipated to, either individually or in the aggregate, materially adversely affect our business, financial condition and results of operations.
Guarantees
In certain limited circumstances, we enter into contractual guarantees. We may guarantee another entity's obligation in the event it fails to perform and may provide guarantees in certain indemnification agreements. We did not have any guarantees of other parties' obligations as of December 31, 2024.
DT Midstream, Inc.
Notes to Consolidated Financial Statements
Purchase Commitments
As of December 31, 2024, we were party to long-term purchase commitments relating to a variety of goods and services required for our business. We estimate lifetime purchase commitments of approximately $95 million, due in the periods shown below.
(millions)
2025 $ 14
2026 13
2027 12
2028 12
2029 12
2030 and thereafter 32
Total $ 95
Surety Bonds
In certain limited circumstances, we enter into contracts that require us to obtain external surety bonds to secure our payment and performance. We agree to indemnify the issuers of these surety bonds for amounts, if any, paid by them under these agreements. In the event that any surety bonds are called for non-performance, we would be obligated to reimburse the issuer of the surety bond. The maximum potential indemnification under our surety bond agreements as of December 31, 2024 is $30 million.
Vector Line of Credit
We are the lender under a revolving term credit facility to Vector, the borrower, in the amount of CAD $70 million. The credit facility was executed in response to the passage of Canadian regulations requiring oil and gas pipelines to demonstrate their financial ability to respond to a catastrophic event and exists for the sole purpose of satisfying these regulations. Vector may only draw upon the facility if the funds are required to respond to a catastrophic event. The maximum potential payout as of December 31, 2024 is USD $49 million. The funding of a loan under the terms of the revolving term credit facility is considered remote.
Contingent Liability
In order to comply with certain state environmental regulations, we have an obligation to restore pipeline right-of-way slope failures that may arise in the ordinary course of business in the Utica and Marcellus formations. We completed evaluations of all locations, which were prioritized based on the severity and proximity of the slope failures, and used updated cost information to assess the adequacy of the estimate for the contingent liability accrual. Based on these evaluations, we recorded a reduction to the contingent liability accrual and decrease to operation and maintenance expense of $9 million and $6 million during the years ended December 31, 2024 and 2023, respectively. As of December 31, 2024 and 2023, we had accrued contingent liabilities of $3 million and $13 million, respectively, for future slope restoration expenditures. The accrual is included in other current liabilities and other liabilities in the Consolidated Statements of Financial Position. While restoration is ongoing, we believe the accrued amounts are sufficient to cover estimated future expenditures.
NOTE 13 - STOCK-BASED COMPENSATION AND DEFINED CONTRIBUTION PLANS
The DT Midstream, Inc. Long-Term Incentive Plan permits the grant of incentive and nonqualified stock options, stock appreciation rights, restricted stock awards and restricted stock units, performance share awards, and performance units to employees, consultants and members of DT Midstream's Board of Directors. As a result of a restricted stock award grant, restricted stock unit or performance share award settlement, or by exercise of a stock option, we may issue common stock from our authorized but unissued common stock and/or from outstanding common stock acquired by or on behalf of DT Midstream in the participant's name. Key provisions of the DT Midstream Plan are:
•Authorized limit as of December 31, 2024 was 8,250,000 shares of common stock. The authorized limit increases annually on January 1 by the lesser of 1,750,000 shares of common stock or the amount determined by the DT Midstream Board of Directors.
DT Midstream, Inc.
Notes to Consolidated Financial Statements
•Prohibits the grant of a stock option with an exercise price that is less than the fair market value of DT Midstream's stock on the grant date.
The following table summarizes our stock-based compensation expense and the related income tax benefit:
Year Ended December 31,
2024 2023 2022
(millions)
Stock-based compensation expense $ 23 $ 20 $ 17
Tax benefit $ 5 $ 5 $ 4
Restricted Stock Units
Restricted stock units granted under the DT Midstream Plan are for a specified number of shares of DT Midstream common stock that entitle the holder to receive common stock, a cash payment, or a combination thereof at the end of the specified vesting period, which is generally three or four years. Restricted stock units are deemed to be equity awards. The fair value of restricted stock units is based on DT Midstream's closing common stock price on the grant date. The fair value is amortized to stock-based compensation expense using a graded vesting schedule over the vesting period. Restricted stock units are settled with DT Midstream common stock and fractional shares are settled in cash.
During the vesting period, the number of restricted stock units granted will increase, assuming full dividend reinvestment on each dividend payment date. The recipient of a restricted stock unit has no shareholder rights during the vesting period. Restricted stock units are nontransferable and subject to risk of forfeiture during the vesting period. Forfeitures are recognized in the period they occur.
The following table summarizes restricted stock unit activity for the year ended December 31, 2024:
Restricted
Stock Units Weighted- Average
Grant Date
Fair Value
(thousands) (per share)
Nonvested as of December 31, 2023 417 $ 45.82
Granted (a)
152 60.37
Forfeited (4) 49.35
Vested (b)
(104) 42.40
Nonvested as of December 31, 2024 461 $ 51.37
____________________________________
(a)Includes initial grants and dividends reinvested.
(b)Includes vested, not issued shares of two thousand at December 31, 2024. Shares will be issued in first quarter 2025.
The weighted-average grant date fair value of restricted stock units granted, excluding dividends reinvested, during the years ended December 31, 2024, 2023 and 2022 was $62.63, $52.66 and $52.25, respectively. The intrinsic value of restricted stock units vested and issued during the years ended December 31, 2024, 2023 and 2022 was $7 million, $8 million, and $3 million, respectively.
Performance Share Awards
Performance share awards granted under the DT Midstream Plan are for a specified number of shares of DT Midstream common stock that entitle the holder to receive common stock, a cash payment, or a combination thereof at the end of the specified vesting period, which is generally three years. Performance share awards are deemed to be equity awards. Performance share stock-based compensation expense is accrued over the vesting period based on the grant date fair value calculated using: (i) DT Midstream's closing common stock price on the grant date; (ii) the grant date fair value of the market condition; and (iii) the probable achievement of performance objectives. The number of shares issued at settlement is determined based on market conditions and the achievement of certain DT Midstream performance objectives. Performance share awards are settled with DT Midstream common stock and fractional shares are settled in cash.
DT Midstream, Inc.
Notes to Consolidated Financial Statements
During the vesting period, the number of performance share awards granted will increase, assuming full dividend reinvestment on each dividend payment date. The recipient of a performance share award has no shareholder rights during the vesting period. Performance share awards are nontransferable and are subject to risk of forfeiture during the vesting period. Forfeitures are recognized in the period they occur.
The following table summarizes performance share award activity for the year ended December 31, 2024:
Performance Share Awards
Weighted- Average
Grant Date
Fair Value
(thousands) (per share)
Nonvested as of December 31, 2023 557 $ 64.36
Granted (a)
372 55.32
Forfeited (29) 59.66
Settled (199) 48.12
Nonvested as of December 31, 2024 701 $ 64.38
_____________________________________
(a)Includes initial grants, dividends reinvested and shares added for achievement of final performance objectives on settled awards.
The weighted-average grant date fair value of performance share awards granted, excluding dividends reinvested, during the years ended December 31, 2024, 2023 and 2022 was $52.05, $53.74 and $72.91, respectively. The intrinsic value of performance share awards settled during the years ended December 31, 2024, 2023 and 2022 was $10 million, $9 million and $4 million, respectively.
Unrecognized Compensation Costs
As of December 31, 2024, we had $27 million of total unrecognized compensation costs related to non-vested stock incentive plan arrangements. The unrecognized compensation cost is expected to be recognized over a weighted-average period of 1.77 years.
Defined Contribution Plans
We sponsor defined contribution retirement savings plans, and participation in one of these plans is available to substantially all employees. We match employee contributions up to certain predefined and Internal Revenue Service limits based on eligible compensation and each employee's contribution rate, and contribute additional amounts in lieu of traditional pension and post-employment healthcare benefits. DT Midstream's cost for these plans was $7 million, $7 million and $5 million for the years ended December 31, 2024, 2023 and 2022, respectively.
NOTE 14 - SEGMENT AND RELATED INFORMATION
We set strategic goals, allocate resources, and evaluate performance based on the following two segments: Pipeline and Gathering. Our Chief Operating Decision Maker (CODM) has been identified as our Chief Executive Officer. Our CODM regularly evaluates financial information regarding these segments in deciding how to allocate resources and in assessing our operating and financial performance. We manage and report our operations primarily according to the nature of our products and services. Our plants, pipelines and other fixed assets are located in the U.S. and Canada.
The Pipeline segment owns and operates interstate and intrastate natural gas pipelines, storage systems, and natural gas gathering lateral pipelines. The Pipeline segment also has interests in equity method investees that own and operate interstate natural gas pipelines. The segment is engaged in the transportation and storage of natural gas for intermediate and end user customers. The Midwest Pipeline Acquisition assets are presented in our Pipeline segment as of December 31, 2024. 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 years ended December 31, 2024 and 2023, the Michigan System financial results are presented in the Pipeline segment. The 2022 comparative activity was for gathering services and therefore was not revised from presentation in the Gathering segment.
DT Midstream, Inc.
Notes to Consolidated Financial Statements
The Gathering segment owns and operates gas gathering systems. The segment is engaged in collecting natural gas from points at or near customers’ wells for delivery to plants for treating, to gathering pipelines for further gathering, or to pipelines for transportation, as well as associated ancillary services, including compression, dehydration, gas treatment, water impoundment, water transportation, water disposal, and sand mining. The Clean Fuels Gathering assets and results of operations after the July 1, 2024 acquisition date are presented in our Gathering segment.
Our CODM uses Net Income Attributable to DT Midstream to allocate resources, including employees, property, and financial or capital resources, for each segment predominantly in the annual budget and forecasting process. Our CODM considers budget-to-actual variances on a monthly basis when making decisions about allocating capital and personnel to the segments. The CODM also uses Net Income Attributable to DT Midstream to assess the performance for each segment by comparing the results of each segment. Net Income Attributable to DT Midstream is an important performance measure of the core profitability of our operations and forms the basis of our internal and external financial reporting. We believe that investors benefit from having access to the same financial measures that our management uses in evaluating segment results.
Inter-segment billing for goods and services exchanged between segments is based upon contracted prices of the provider. Inter-segment billings were not significant for the years ended December 31, 2024, 2023 and 2022.
Financial data for our business segments follows:
Year Ended December 31, 2024
Pipeline Gathering Total Reportable Segments
Eliminations Total Consolidated
(millions)
Revenues
Operating revenues $ 443 $ 538 $ 981 $ - $ 981
Operating Expenses
Operation and maintenance 68 176 244 - 244
Depreciation and amortization 74 135 209 - 209
Taxes other than income 22 17 39 - 39
Other (Income) and Deductions
Interest expense 47 106 153 - 153
Interest income (4) (3) (7) - (7)
Earnings from equity method investees (162) - (162) - (162)
Loss from financing activities 3 2 5 - 5
Other income (1) (3) (4) - (4)
Income Tax Expense 107 30 137 - 137
Less: Net Income Attributable to Noncontrolling Interests
13 - 13 - 13
Net Income Attributable to DT Midstream $ 276 $ 78 $ 354 $ - $ 354
Capital expenditures $ 73 $ 277 $ 350 $ - $ 350
Acquisition accounted for as a business combination
$ 1,198 $ - $ 1,198 $ - $ 1,198
December 31, 2024
Investments in equity method investees $ 1,297 $ - $ 1,297 $ - $ 1,297
Goodwill 356 420 776 - 776
Total Assets $ 5,274 $ 4,661 $ 9,935 $ - $ 9,935
DT Midstream, Inc.
Notes to Consolidated Financial Statements
Year Ended December 31, 2023
Pipeline Gathering Total Reportable Segments
Eliminations Total Consolidated
(millions)
Revenues
Operating revenues $ 377 $ 545 $ 922 $ - $ 922
Operating Expenses
Operation and maintenance 55 190 245 - 245
Depreciation and amortization 69 113 182 - 182
Taxes other than income 15 13 28 - 28
Asset (gains) losses and impairments, net (4) - (4) - (4)
Other (Income) and Deductions
Interest expense 55 95 150 - 150
Interest income (1) - (1) - (1)
Earnings from equity method investees (177) - (177) - (177)
Other income - (1) (1) - (1)
Income Tax Expense 75 29 104 - 104
Less: Net Income Attributable to Noncontrolling Interests
12 - 12 - 12
Net Income Attributable to DT Midstream $ 278 $ 106 $ 384 $ - $ 384
Capital expenditures $ 255 $ 517 $ 772 $ - $ 772
December 31, 2023
Investments in equity method investees $ 1,762 $ - $ 1,762 $ - $ 1,762
Goodwill 53 420 473 - 473
Total Assets $ 4,439 $ 4,543 $ 8,982 $ - $ 8,982
Year Ended December 31, 2022
Pipeline Gathering Total Reportable Segments
Eliminations Total Consolidated
(millions)
Revenues
Operating revenues $ 339 $ 581 $ 920 $ - $ 920
Operating Expenses
Operation and maintenance 54 213 267 - 267
Depreciation and amortization 63 107 170 - 170
Taxes other than income 14 14 28 - 28
Asset (gains) losses and impairments, net (6) (17) (23) - (23)
Other (Income) and Deductions
Interest expense 57 80 137 - 137
Interest income (1) (2) (3) - (3)
Earnings from equity method investees (150) - (150) - (150)
Loss from financing activities 6 7 13 - 13
Other income - (1) (1) - (1)
Income Tax Expense 62 38 100 - 100
Less: Net Income Attributable to Noncontrolling Interests
12 - 12 - 12
Net Income Attributable to DT Midstream $ 228 $ 142 $ 370 $ - $ 370
Capital expenditures and acquisitions $ 638 $ 252 $ 890 $ - $ 890
December 31, 2022
Investments in equity method investees $ 2,200 $ - $ 2,200 $ - $ 2,200
Goodwill 53 420 473 - 473
Total Assets $ 4,625 $ 4,208 $ 8,833 $ - $ 8,833
DT Midstream, Inc.
Notes to Consolidated Financial Statements
NOTE 15 - RELATED PARTY TRANSACTIONS
Transactions between DT Midstream and our equity method investees have been presented as related party transactions in the accompanying Consolidated Financial Statements.
The following is a summary of our balances with related parties:
December 31,
2024 2023
(millions)
Notes receivable from Vector - long-term $ 4 $ 4
Current Liabilities - Other $ 1 $ 1
DT Midstream had related party transactions presented in Operation and maintenance and Other expense in our Consolidated Statements of Operations during the years ended December 31, 2024, 2023 and 2022 of $2 million, $1 million and $1 million, respectively.
NOTE 16 - ACQUISITIONS
Clean Fuels Acquisition
On July 1, 2024, DT Midstream closed on the purchase of Clean Fuels Gathering from a privately held coal mine methane producer for purchase consideration of $12 million plus immaterial transaction costs, which was accounted for as an asset acquisition. The Clean Fuels Acquisition was primarily comprised of gathering and treating assets that process coal mine methane into pipeline quality gas which was capitalized as property, plant and equipment. The Clean Fuels Acquisition aligns with our strategy to pursue economically attractive opportunities and deploy GHG reducing technologies and is expected to generate carbon offsets and federal income tax credits. A concurrent gas supply agreement was executed which requires contingent payments from DT Midstream of up to $34 million upon the completion of certain milestones, including cumulative production and income tax credits, and variable payments under a sharing mechanism that could be material. As of December 31, 2024, one milestone had been achieved and $10 million was recorded as a long-term prepaid asset in Other assets and Accounts payable in DT Midstream's Consolidated Statements of Financial Position. The Clean Fuels Gathering assets and results of operations after the July 1, 2024 acquisition date are presented in our Gathering segment.
Midwest Pipeline Acquisition
On December 31, 2024, we closed on the Midwest Pipeline Acquisition of three FERC-regulated natural gas transmission pipelines from ONEOK for a purchase price of $1.2 billion, which is subject to certain customary purchase price adjustments. Under the terms of the agreement, DT Midstream acquired 100% operating ownership in Guardian, Midwestern and Viking. The pipelines have a total capacity of approximately 3.7 Bcf/d and 1,300 miles across seven states in the Midwest market region.
•Guardian Pipeline, L.L.C. is a 263-mile interstate pipeline which connects to the Chicago Hub and serves key Wisconsin demand centers;
•Midwestern Gas Transmission Company is a 402-mile bi-directional interstate pipeline which connects Appalachia supply to the Midwest market region between Tennessee and the Chicago Hub; and
•Viking Gas Transmission Company is a 674-mile bi-directional interstate pipeline which serves key utility customers in Minnesota, Wisconsin and North Dakota.
The Midwest Pipeline Acquisition has potential commercial synergies and it directly aligns with DT Midstream's strategy of owning natural gas assets serving key demand centers and market regions, and with revenues supported by take-or-pay contracts with creditworthy and diverse customers.
DT Midstream, Inc.
Notes to Consolidated Financial Statements
The cash consideration provided for the assets acquired was approximately $1.2 billion. The acquisition was accounted for using the acquisition method of accounting for business combinations. Assets acquired and liabilities assumed were measured at estimated fair value at the acquisition date. The FERC-regulated pipelines are subject to rate making and cost recovery provisions and are accounted for under ASC 980 guidance as discussed in Note 17, "Regulatory Matters" to the Consolidated Financial Statements. As such, the fair value of assets acquired and liabilities assumed subject to these provisions approximates their regulated basis, and therefore no fair value adjustments have been reflected related to these amounts.
The intangible assets recorded as a result of the acquisition pertain to existing customer relationships, which were valued at approximately $11 million as of the acquisition date. This fair value was estimated by applying the multi-period excess earnings method, which estimates the value of the intangible asset based upon the present value of the incremental after-tax cash flows solely attributable to the existing customer relationships. The fair value measurement uses significant unobservable inputs, including management estimates and assumptions, and thus represents a fair value Level 3 measurement, pursuant to the applicable accounting guidance. Key estimates and inputs include revenue and expense projections and discount rates based on the risks associated with the intangible assets, and contributory asset charges. The intangible assets are amortized on a straight-line basis over a period of 5 years, which is the number of years the assets are expected to generate incremental after-tax cash flows.
The excess purchase price over the fair value of net assets acquired and liabilities assumed was classified as goodwill. The factors contributing to the recognition of goodwill were based on various strategic benefits that are expected to be realized from the acquisition. The acquisition provides us with a platform for growth and access to further investment opportunities.
For income tax purposes, the transaction is treated as a taxable deemed asset acquisition. Accordingly, the majority of deferred income tax assets and liabilities of the acquired entities are eliminated as the tax bases were increased to fair market value which equals net book value. See Note 7, "Income Taxes" to the Consolidated Financial Statements.
The preliminary allocation of the purchase price is based on estimated fair values of the assets acquired and liabilities assumed at the date of acquisition, December 31, 2024. The purchase price is subject to final working capital settlement adjustments and other potential valuation adjustments during the one year measurement period per the business combination guidance. The components of the preliminary purchase price allocation are as follows:
December 31,
(millions)
Assets
Accounts receivable $ 29
Other current assets 10
Property, plant, and equipment, net 933
Goodwill 303
Customer relationship intangible assets 11
Regulatory assets 10
Other assets 22
$ 1,318
Liabilities
Accounts payable $ 12
Property taxes payable 5
Other current liabilities 3
Regulatory liabilities 90
Other liabilities 10
$ 120
Total cash consideration $ 1,198
DT Midstream, Inc.
Notes to Consolidated Financial Statements
DT Midstream incurred approximately $5 million of direct transaction costs for the acquisition during the year ended December 31, 2024. These costs were primarily related to legal and advisory fees and are included in operation and maintenance in DT Midstream's Consolidated Statements of Operations. The Midwest Pipeline Acquisition assets are presented in our Pipeline segment as of December 31, 2024.
Pro forma Financial Information
The Midwest Pipeline Acquisition was completed on December 31, 2024, therefore the acquisition had no impact on our consolidated revenues and earnings for the twelve months ended December 31, 2024. The following unaudited pro forma summary presents our consolidated information as if the acquisition had occurred on January 1, 2023 using our records and seller provided information. The unaudited pro forma financial information does not purport to be indicative of the combined results of operations which would have actually been obtained had the acquisition taken place on January 1, 2023, nor should it be taken as indicative of future consolidated results of operations. The pro forma earnings for the years ended December 31, 2024 and 2023 were adjusted to include net interest expense, after tax, of $11 million and $23 million, respectively, related to the 2034 Senior Notes issued to fund the acquisition offset by the elimination of interest expense on debt held by the acquired pipelines, which was paid off at the acquisition date. Income tax expense of $22 million related to the remeasurement of state deferred income taxes as a result of the acquisition were excluded from the year ended December 31, 2024 and included in the year ended December 31, 2023. Transaction costs, after tax, of $7 million, which includes Bridge Financing fees and legal and professional expenses, were excluded from the year ended December 31, 2024 and included in the year ended December 31, 2023. Other adjustments, after tax, of $1 million and $4 million were included for the years ended December 31, 2024 and 2023, respectively.
Pro forma (Unaudited)
Years Ended December 31,
2024 2023
(in millions)
Revenue $ 1,182 $ 1,091
Net Income attributable to DT Midstream $ 430 $ 377
NOTE 17 - REGULATORY MATTERS
Significant Accounting Policy - Regulation
Guardian, Midwestern and Viking are subject to rate regulation and accounting requirements of the FERC. The regulated operations of each of these subsidiaries have rates that are (i) established by independent, third-party regulators, (ii) set at levels that will recover our costs when considering the demand and competition for our services and (iii) collectible from our customers. Accordingly, we follow the accounting for regulated operations as defined in ASC 980, Regulated Operations for these pipelines, which results in differences in the application of GAAP between our regulated and non-regulated businesses. During the rate-making process, FERC sets the framework for what we can charge to and collect from our customers for our services and establish the manner that our costs are accounted for, including allowing us to defer recognition of certain costs and permitting recovery of the amounts through rates over time as opposed to expensing such costs as incurred. Examples include costs for fuel and losses, contributions in aid of construction, charges for depreciation, gains or losses on disposition of assets and deferral of tax benefits related to changes in tax rates.
Regulatory Assets and Liabilities
Under ASC 980, our regulated operations are required to record regulatory assets and liabilities for certain transactions that would have been treated as revenue or expense in non-regulated businesses. Future regulatory changes could result in changes in the amounts of regulatory assets and liabilities or the discontinuance of this accounting treatment for regulatory assets and liabilities and may require the write-off of the portion of any regulatory asset or liability that is no longer probable of recovery through regulated rates. Actions by regulatory authorities could also have an effect on the amounts we charge to and collect from our customers. Any difference in the amounts recoverable or deferred is recorded as income or expense at the time of regulatory action.
DT Midstream, Inc.
Notes to Consolidated Financial Statements
Continued applicability of regulatory accounting treatment requires that rates be designed to recover specific costs of providing regulated services and be charged to and collected from customers. We believe that currently available facts support the continued use of regulatory accounting and that all regulatory assets and liabilities are recoverable or refundable in the current regulatory environment. Regulatory assets are included in Other Assets - Other on our Consolidated Statement of Financial Position.
The following includes balances and descriptions of our regulatory assets and liabilities.
December 31,
(millions)
Regulatory Assets
Recoverable income taxes related to AFUDC equity $ 7
Load Management Services Cost Recovery Mechanism 2
Other regulatory assets 1
$ 10
Regulatory Liabilities
Refundable federal income taxes $ 79
Removal costs liability 11
$ 90
As noted below, certain Regulatory assets for which costs have been incurred were included (or are expected to be included, for costs incurred subsequent to the most recently approved rate case) in the rate base, thereby providing a return on invested costs (except as noted). Certain other Regulatory assets are not included in the rate base but accrue recoverable carrying charges until tariff rates adjusted to collect the assets are billed. Certain Regulatory assets do not result from cash expenditures and therefore do not represent investments included in rate base or have offsetting liabilities that reduce rate base.
Regulatory Assets
•Recoverable income taxes related to AFUDC equity - Accounting standards for income taxes require recognition of a deferred tax liability for the equity component of AFUDC. A Regulatory asset is required for the future increase in taxes payable related to the equity component of AFUDC that will be recovered from customers through future rates over the remaining life of the related property, plant and equipment.
•Load Management Services Cost Recovery Mechanism - The mechanism reconciles the differences between the cost to our pipelines to maintain their line pack gas and the amounts our pipelines receive or pay for such gas to resolve imbalances with customers and pipeline interconnects and as may be otherwise necessary to maintain an appropriate level of line pack for system management purposes. The balance is recovered through an annual update to the LMS tariff rate applied to daily imbalance volumes with counterparties. The recoverable amount is not earning a return or accruing carrying charges.
Liabilities
•Refundable federal income taxes - In December 2017, the Tax Cuts and Jobs Acts ("TCJA") was enacted and reduced the corporate income tax rate, effective January 1, 2018. Guardian, Midwestern and Viking remeasured deferred taxes, resulting in a reduction to deferred tax liabilities, to reflect the impact of the TCJA on the cumulative temporary differences expected to reverse after the effective date. Regulatory liabilities were established for the anticipated return to ratepayers of deferred income taxes through reductions in future rates. The current amount of amortization and method for amortization of each pipeline’s Regulatory liability related to the TCJA tax rate change has been determined in each pipeline’s most recent rate proceedings.
•Removal costs liability - The amounts collected from customers to fund future asset removal activities in excess of removal costs incurred. The annual amount accumulated in this liability is based on rates established in the most recent rate proceedings for each pipeline. The rate is multiplied by the depreciable base for each applicable asset category to calculate the annual amount accumulated in this liability.
DT Midstream, Inc.
Notes to Consolidated Financial Statements
Rate Case Settlements
The settlement dates for the most recent FERC rate proceedings for Guardian, Midwestern and Viking were February 15, 2023, May 3, 2022 and July 31, 2024, respectively. As of December 31, 2024, there were no open FERC proceedings for these pipelines.
NOTE 18 - SUBSEQUENT EVENT
Dividend Declaration
On February 26, 2025, we announced that our Board of Directors declared a quarterly dividend of $0.82 per share of common stock. The dividend is payable to our stockholders of record as of March 17, 2025 and is expected to be paid on April 15, 2025.

---

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None.

---

ITEM 9A. CONTROLS AND PROCEDURES
Item 9A. Controls and Procedures
(a) Evaluation of disclosure controls and procedures
Management of DT Midstream carried out an evaluation, under the supervision and with the participation of DT Midstream's Chief Executive Officer (CEO) and Chief Financial Officer (CFO), of the effectiveness of the design and operation of DT Midstream's disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) as of December 31, 2024, which is the end of the period covered by this report. Based on this evaluation, DT Midstream's CEO and CFO have concluded that such disclosure controls and procedures are effective in providing reasonable assurance that information required to be disclosed by DT Midstream in reports that it files or submits under the Exchange Act (i) is recorded, processed, summarized, and reported within the time periods specified in the SEC's rules and forms and (ii) is accumulated and communicated to DT Midstream's management, including our CEO and CFO, as appropriate to allow timely decisions regarding required disclosure. Due to the inherent limitations in the effectiveness of any disclosure controls and procedures, management cannot provide absolute assurance that the objectives of our disclosure controls and procedures will be attained.
(b) Management's report on internal control over financial reporting
Management of DT Midstream is responsible for establishing and maintaining adequate internal control over financial reporting as such term is defined in Exchange Act Rules 13a-15(f) and 15d-15(f). Internal control over financial reporting is a process designed by, or under the supervision of, DT Midstream's CEO and CFO, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Management of DT Midstream has assessed the effectiveness of DT Midstream’s internal control over financial reporting as of December 31, 2024. In making this assessment, management used the criteria issued by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control - Integrated Framework (2013). Based on this assessment, DT Midstream's management concluded that, as of December 31, 2024, DT Midstream’s internal control over financial reporting was effective.
Management has excluded the Midwest Pipeline Acquisition of three FERC-regulated natural gas transmission pipelines from its assessment of internal control over financial reporting as of December 31, 2024 because they were acquired by DT Midstream in a purchase business combination on December 31, 2024. The acquired wholly-owned subsidiaries from the Midwest Pipeline Acquisition represent less than 1 percent of DT Midstream's consolidated total revenue for the year ended December 31, 2024 and approximately 10 percent of DT Midstream's consolidated total assets (the 10 percent calculation excludes assets related to acquired goodwill and other intangible assets, as they were included in management’s assessment), as of December 31, 2024.
The effectiveness of DT Midstream's internal control over financial reporting as of December 31, 2024 has been audited by PricewaterhouseCoopers, LLP, an independent registered public accounting firm, as stated in their report which appears herein.
(c) Changes in internal control over financial reporting
There have been no changes in our internal control over financial reporting during the quarter ended December 31, 2024 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

---

ITEM 9B. OTHER INFORMATION
Item 9B. Other Information
During the three months ended December 31, 2024, none of the Company’s directors or executive officers adopted, modified or terminated any contract, instruction or written plan for the purchase or sale of the Company’s common stock that was intended to satisfy the affirmative defense conditions of Exchange Act Rule 10b5-1(c) or any "non-Rule 10b5-1 trading arrangement."

---

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Item 10. Directors, Executive Officers, and Corporate Governance

---

ITEM 11. EXECUTIVE COMPENSATION
Item 11. Executive Compensation

---

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

---

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Item 13. Certain Relationships and Related Transactions, and Director Independence

---

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
Item 14. Principal Accountant Fees and Services
PART IV

---

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
Item 15. Exhibits and Financial Statement Schedules
A.The following documents are filed as part of this Annual Report on Form 10-K.
(a)Consolidated Financial Statements. See "Item 8 - Financial Statements."
(b)Financial Statement Schedules. Financial statement schedules listed under the SEC rules are omitted because they are not applicable, or the required information is provided in the Notes to Consolidated Financial Statements in Item 8 of this Form 10-K.
(c)Exhibits.
Exhibit Number
Description
(i) Exhibits filed herewith:
4.1
First Supplemental Indenture, dated as of January 30, 2025, among DT Midstream, Inc., the Guaranteeing Subsidiaries and U.S. Bank Trust Company, National Association, as trustee
4.2
Second Supplemental Indenture, dated as of January 30, 2025, among DT Midstream, Inc., the Guaranteeing Subsidiaries and U.S. Bank Trust Company, National Association, as trustee and Notes Collateral Agent
4.3
First Supplemental Indenture, dated as of January 30, 2025, among DT Midstream, Inc., the Guaranteeing Subsidiaries and U.S. Bank Trust Company, National Association, as trustee and Notes Collateral Agent
21.1
Subsidiaries of DT Midstream, Inc.
23.1
Consent of PricewaterhouseCoopers LLP
31.1
Chief Executive Officer Section 302 Form 10-K Certification of Periodic Report
31.2
Chief Financial Officer Section 302 Form 10-K Certification of Periodic Report
95.1
Mine Safety Disclosure
101.INS XBRL Instance Document - The instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document
101.SCH XBRL Taxonomy Extension Schema
101.CAL XBRL Taxonomy Extension Calculation Linkbase
101.DEF XBRL Taxonomy Extension Definition Database
101.LAB XBRL Taxonomy Extension Label Linkbase
101.PRE XBRL Taxonomy Extension Presentation Linkbase
104 Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)
(ii) Exhibits furnished herewith:
32.1
Chief Executive Officer Section 906 Form 10-K Certification of Periodic Report
32.2
Chief Financial Officer Section 906 Form 10-K Certification of Periodic Report
(iii) Exhibits incorporated by reference:
2.1
Separation and Distribution Agreement, dated June 25, 2021, between DTE Energy Company and DT Midstream, Inc. (incorporated by reference to Exhibit 2.1 to DT Midstream’s Current Report on Form 8-K filed on July 1, 2021)
3.1
Amended and Restated Certificate of Incorporation of DT Midstream, Inc., effective July 1, 2021 (incorporated by reference to Exhibit 3.1 to DT Midstream's Current Report on Form 8-K filed on July 1, 2021)
3.2
Amended and Restated Bylaws of DT Midstream, Inc., effective July 1, 2021 (incorporated by reference to Exhibit 3.2 to DT Midstream's Current Report on Form 8-K filed on July 1, 2021)
Exhibit Number
Description
(iii) Exhibits incorporated by reference:
4.4
Description of Securities (incorporated by reference to Exhibit 4.1 to DT Midstream's Annual Report on Form 10-K filed on February 16, 2024)
4.5
Indenture dated as of June 9, 2021 among DT Midstream, the Guarantors and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to DT Midstream's Current Report on Form 8-K filed on June 10, 2021)
4.6
Indenture, dated as of April 11, 2022, among DT Midstream, Inc., the Guarantors and U.S. Bank Trust Company, National Association, as trustee (incorporated by reference to Exhibit 4.1 to DT Midstream's Current Report on Form 8-K filed April 11, 2022)
4.7
Pari Passu Intercreditor Agreement, dated as of April 11, 2022, among DT Midstream, Inc., the Guarantors, Barclays Bank PLC, as Credit Agreement Agent, and U.S. Bank Trust Company, National Association, as Notes Collateral Agent (incorporated by reference to Exhibit 4.2 to DT Midstream's Current Report on Form 8-K filed April 11, 2022)
4.8
First Supplemental Indenture, dated as of August 12, 2024, among DT Midstream, Inc., the Guarantors and U.S. Bank Trust Company, National Association, as Trustee and Notes Collateral Agent (incorporated by reference to Exhibit 4.4 to DT Midstream's Quarterly Report on Form 10-Q filed on October 29, 2024)
4.9
Indenture, dated as of December 6, 2024, among DT Midstream, Inc., the Guarantors and U.S. Bank Trust Company, National Association, as Trustee and Notes Collateral Agent (incorporated by reference to Exhibit 4.1 to DT Midstream's Current Report on Form 8-K filed on December 6, 2024)
10.1*
Form of Amended and Restated Change-In-Control Severance Agreement (incorporated by reference to Exhibit 10.1 to DT Midstream's Annual Report on Form 10-K filed on February 16, 2024)
10.2
Credit Agreement, dated as of June 10, 2021 by and among DT Midstream, as borrower, the Lenders party thereto, the L/C Issuers party thereto, and Barclays Bank PLC, as Administrative Agent and Collateral Agent (incorporated by reference to Exhibit 10.1 to DT Midstream's Current Report on Form 8-K filed on June 10, 2021)
10.3
Tax Matters Agreement, dated June 25, 2021, between DTE Energy Company and DT Midstream, Inc. (incorporated by reference to Exhibit 10.2 to DT Midstream’s Current Report on Form 8-K filed on July 1, 2021)
10.4
DT Midstream, Inc. Long-Term Incentive Plan (incorporated by reference to Exhibit 10.4 to DT Midstream’s Registration Statement on Form 10-12B (File No. 001-40392), filed on May 7, 2021)
10.5
DT Midstream, Inc. Supplemental Savings Plan (incorporated by reference to Exhibit 10.1 to DT Midstream’s Annual Report on Form 10-K filed on February 16, 2023)
10.6
Form of Severance Agreement (incorporated by reference to Exhibit 10.5 to DT Midstream’s Current Report on Form 8-K filed on July 1, 2021)
10.7
DT Midstream, Inc. Annual Incentive Plan (incorporated by reference to Exhibit 10.6 to DT Midstream’s Current Report on Form 8-K filed on July 1, 2021)
10.8
First Incremental Revolving Facility Amendment and Amendment No. 1 to Credit Agreement and Collateral Agreement, by and among DT Midstream, Inc., the lenders and letter of credit issuers party thereto and Barclays Bank PLC, as administrative agent and collateral agent, dated as of October 19, 2022 (incorporated by reference to Exhibit 10.1 to DT Midstream's Current Report on Form 8-K filed on October 20, 2022)
10.9
Amendment No. 2 to Credit Agreement, by and between DT Midstream, Inc., and Barclays Bank PLC, as administrative agent and collateral agent, dated as of June 27, 2023 (incorporated by reference to Exhibit 10.1 to DT Midstream's Current Report on Form 8-K filed on June 29, 2023)
Exhibit Number
Description
(iii) Exhibits incorporated by reference:
10.10
Amendment No. 3 to Credit Agreement, by and between DT Midstream, Inc., and Barclays Bank PLC, as administrative agent and collateral agent, and the lenders party thereto, dated as of November 25, 2024 (incorporated by reference to Exhibit 10.1 to DT Midstream's Current Report on Form 8-K filed on November 27, 2024)
10.11
Amendment No. 4 to Credit Agreement, by and between DT Midstream, Inc., the guarantors party thereto and Barclays Bank PLC, as administrative agent and collateral agent, dated as of December 12, 2024 (incorporated by reference to Exhibit 10.1 to DT Midstream's Current Report on Form 8-K filed on December 12, 2024)
10.12
Purchase and Sale Agreement, dated November 19, 2024, by and among DT Midstream, Inc., DTM Interstate Transportation, LLC, ONEOK Partners Intermediate Limited Partnership and Border Midwestern Company (incorporated by reference to Exhibit 10.1 to DT Midstream’s Current Report on Form 8-K filed on November 19, 2024)
19.1
DT Midstream, Inc. Insider Trading Policy, dated June 1, 2023 (incorporated by reference to Exhibit 19.1 to DT Midstream’s Annual Report on Form 10-K filed on February 16, 2024)
97.1
DT Midstream, Inc. Clawback Policy, dated September 19, 2023 (incorporated by reference to Exhibit 97.1 to DT Midstream’s Annual Report on Form 10-K filed on February 16, 2024)
* Certain portions of this exhibit have been redacted pursuant to Item 601(b)(10)(iv) of Regulation S-K. The registrant agrees to furnish supplementally an unredacted copy of the exhibit to the Securities and Exchange Commission upon its request