EDGAR 10-K Filing

Company CIK: 1842022
Filing Year: 2022
Filename: 1842022_10-K_2022_0001842022-22-000006.json

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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 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 the Registrant files electronically with the SEC at www.sec.gov.
The DT Midstream Code of Business Conduct and Ethics, Board of Directors’ Governance Guidelines, Board Committee Charters, and Categorical Standards for Director Independence are also posted on the DT Midstream 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, lateral pipelines and related treatment plants and compression and surface facilities, and gathering systems and related treatment plants and compression and surface facilities. We also own joint venture interests in equity method investees which own and operate interstate pipelines, many of which have connectivity to our wholly owned assets.
Our core assets strategically connect key demand centers in the Midwestern U.S., Eastern Canada, Northeastern U.S., and Gulf Coast regions to the premium production areas of the Haynesville and Marcellus/Utica dry natural gas formations in the Gulf Coast and Appalachian Basins, respectively. We have an established history of stable, long-term growth with contractual cash flows from a diversified portfolio of customers that include natural gas producers, LDCs, electric power generators, industrials, and national marketers.
The Separation
On July 1, 2021, DTE Energy completed the Separation through the distribution of 96,732,466 shares of DT Midstream common stock to DTE Energy shareholders. See Note 1, "Separation, Description of the Business, and Basis of Presentation" to the Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.
2021 Executive Summary
•Successfully completed the Separation from DTE Energy and transitioned into a fully independent public midstream company;
•Established an independent DT Midstream Board of Directors and created the following board committees: Audit, Finance, Corporate Governance, Organization and Compensation, and ESG;
•Net Income Attributable to DT Midstream was $307 million for the year ended December 31, 2021;
•Issued common shares and issued long-term debt in the form of $2.1 billion senior notes and a $1.0 billion term loan facility. Additional liquidity available through a $750 million 5-year secured revolving credit facility;
•Declared a cash dividend of $0.60 per common share for both the third and fourth quarters;
•Executed a commercial agreement in the fourth quarter 2021 for a Haynesville system expansion (Blue Union and LEAP);
•Connected three new customers to Blue Union in September 2021;
•Expanded one of our Blue Union treating plants to 150 MMcf/d, completed in October 2021;
•Executed a long-term transportation agreement supporting the conversion of our Michigan Gathering System to dry gas transmission service;
•Executed a long-term firm agreement in the third quarter on the Appalachia Gathering System representing approximately 25% of system capacity;
•Executed a long-term firm contract with a new customer on Stonewall Gas Gathering in the third quarter 2021, representing approximately 15% of total capacity;
•NEXUS open season for additional receipt point capacity and a new market connection to Generation Pipeline announced in the third quarter 2021;
•Continued our efforts to advance carbon capture projects across our geographic regions;
•Announced our "wellhead to water" expansion proposal of the Haynesville system which offers a carbon neutral pathway for supply to reach LNG markets;
•Announced our strategic joint development agreement with Mitsubishi Power Americas, Inc. to advance hydrogen development projects across the U.S.;
•Entered a new partnership with Project Canary to monitor methane emissions; and
•Developed a plan to publish our inaugural Sustainability Report in the second quarter 2022. The information in our 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 greenhouse gas reducing technologies as part of our goal of being leading environmental stewards in the midstream industry and have announced a net zero carbon emissions goal by 2050. Our strategy is premised on the following principles:
•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 dry natural gas basins in which we operate.
•Pursue economically attractive opportunities. We intend to pursue economically attractive expansion opportunities that leverage our current asset footprint and strategic relationships with our customers.
•Grow cash flows supported by long-term firm 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 commitments from customers, which may include reservation-based charges, MVCs and acreage dedications.
•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.
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 15, "Segment and Related Information," of the Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.
Southwestern and Antero accounted for approximately 67% and 10% of our operating revenues, respectively, for the year ended December 31, 2021. Our operating revenues do not include unconsolidated joint ventures accounted for as equity method investments.
Pipeline Segment
Description
Our Pipeline segment, formerly titled Pipeline and Other, includes our interstate pipelines, intrastate pipelines, storage systems, lateral pipelines and 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, many of which have connectivity to our wholly owned assets. We own and/or operate companies that own and/or 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, LDCs 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, LDCs and industrial end users. Our lateral pipelines are assets that gather natural gas for our customers from multiple central delivery points within a basin and redeliver that natural gas to interstate or intrastate pipelines for 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.
Properties
The following table presents certain information concerning our principal properties included in the Pipeline Segment:
Property Classification % Owned Description Location
Pipeline
FERC-Regulated Interstate Pipelines
NEXUS (a)
50% 256-mile pipeline and three compression facilities transporting Utica and Marcellus shale gas to Ohio, Michigan and Ontario market centers. NEXUS owns 100% of Generation Pipeline.
OH, MI, IL and Ontario
Vector Pipeline (a)
40% 348-mile pipeline and five compression facilities connecting Illinois, Michigan and Ontario market centers
IL, IN, MI and Ontario
Millennium Pipeline (a)
26% 263-mile pipeline and compression facilities serving markets in the northeast Marcellus region
NY
Birdsboro Pipeline 100% 14-mile pipeline delivering gas supply to a gas-fired power plant in Pennsylvania
PA
Intrastate Pipelines
Generation Pipeline 50% 25-mile pipeline located in northern Ohio and owned by NEXUS
OH
FERC-Regulated Storage System
Washington 10 Storage Complex (b)
91% 94 Bcf of storage capacity
MI
Lateral Pipelines
Bluestone 100% 65-mile pipeline gathering Marcellus shale gas to the Millennium Pipeline and the Tennessee Pipeline
PA and NY
LEAP 100% 155-mile pipeline gathering Haynesville shale gas to markets in the Gulf Coast region
LA
Stonewall Gas Gathering 85% 68-mile pipeline gathering gas from Appalachia Gathering System for delivery to the Columbia Pipeline
WV
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(a)We account for our ownership interest in these properties as equity method investments in accordance with GAAP. See Note 1 "Separation, Description of the Business, and Basis of Presentation" in Part II, Item 8 of this Form 10-K.
(b)The Washington 10 Storage Complex includes 16 Bcf of leased capacity from Washington 28 Storage which is held by a joint venture, South Romeo, in which DT Midstream owns a 50% interest and is the operator.
Revenues
DT Midstream primarily provides two types of pipeline and storage services: firm service and interruptible service. The cash flows from our Pipeline operations can be impacted in the short term by seasonality, weather fluctuations and the financial condition of our customers. Our election to enter primarily into firm service contracts with firm reservation charges provides us stable operating performance and cash flows. For the year ended December 31, 2021, revenue from the Pipeline segment accounted for approximately 37% of our consolidated revenues.
Competition
Natural gas pipeline, gathering lateral pipeline and storage operators compete for customers primarily based on geographic location, which determines connectivity and proximity to supply sources and end uses, 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 pipelines market include major interstate pipelines and midstream companies that can transport and gather natural gas volumes between interstate systems and between central delivery points within a basin, respectively.
Gathering Segment
Description
Our Gathering segment includes our gathering systems and related treatment plants and compression and surface facilities. We own and/or operate companies that own and/or 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 processing, 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 storage, water transportation and sand mining. Our gathering systems provide a gathering function and are therefore not subject to FERC jurisdiction.
Properties
The following table presents certain information concerning our principal properties included in the Gathering Segment:
Property Classification % Owned Description Location
Gathering
Susquehanna Gathering System 100% 198-mile pipeline delivering Marcellus shale gas production to Bluestone
PA
Blue Union 100% 358-mile gathering system delivering shale gas production from the Haynesville formation of Louisiana to markets in the Gulf Coast region
LA and TX
Appalachia Gathering System 100% 137-mile pipeline delivering Marcellus shale gas to the Texas Eastern Pipeline and Stonewall Gas Gathering
PA and WV
Tioga Gathering System 100% 3-mile pipeline delivering production gas to the Dominion Transmission interconnect
PA
Michigan Gathering System 100% 333-mile pipeline system in northern Michigan
MI
Revenues
The results of our Gathering operations are influenced by the volumes gathered through our systems. Our election to enter primarily into MVCs underpinned by long-term contracts provides our Gathering segments with stable operating performance and cash flows. For the year ended December 31, 2021, revenue from the Gathering segment accounted for approximately 63% 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 face competition in signing acreage dedications and MVCs, expanding treating capacity and expanding our system 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.
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 right-of-way grants. In some cases, not all of the record owners have joined in the right-of-way grants, but in substantially all such cases, signatures of the owners of a majority of the interests have been obtained.
Human Capital Resources
As a newly independent, publicly traded company, we recognize that being agile and innovative is necessary for our continued growth. We currently employ 280 employees, all of which are full-time. All of our employees are in the U.S., with our headquarters in Detroit and office locations in Pennsylvania, West Virginia, Louisiana, and Texas.
Diversity, Equity, and Inclusion (DEI)
DT Midstream is committed to building a diverse, empowered, and engaged team that delivers safe and reliable service to our customers. We measure DEI performance in several ways:
•Diversity of interviewees, hires, high potential talent, and leadership promotions;
•Workforce representation of women, minorities, veterans, and employees with disabilities based on voluntary self-identification information; and
•Employee engagement, including specific programs focused on a culture of belonging.
Health and Safety
The health and safety of people is our top priority for employees, contractors, customers, and the communities we serve. Our safety culture is maintained and strengthened by our safety team and culture, 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 Occupational Safety and Health Administration recordable injury metrics.
COVID-19 Response
During the first quarter 2020, the COVID-19 pandemic began impacting geographic areas throughout the United States in which we operate. We took quick action to ensure the safety and well-being of our employees.
We successfully implemented work from home for our employees and implemented new safety procedures to ensure employee safety, including the use of personal protective equipment, contact tracing and cleaning of our facilities. For the essential workers most critical to our continued operations, we used a pod-protocol to keep groups of employees together to protect their health and to ensure safe and reliable pipeline, gathering and storage service for our customers.
We continue to actively monitor risks related to COVID-19 and proper application of our safety protocol. We also provide consistent, transparent communications to employees around safe practices, quarantine and testing protocols, vaccine availability, and timing of safely returning to office work.
Compensation and Benefits Description
Our human capital resources objectives include recruiting, incentivizing, fostering belonging, and retaining top talent. To achieve this, we offer our employees competitive compensation packages, as well as medical, dental, vision and other benefits. We review our compensation practices annually to ensure that pay is fair and internally equitable. For additional information on metrics used in our incentive plans, please see "Annual Incentives" and "Long-term Incentives" sections of our Proxy Statement.
At the Separation, our human resource professionals worked with external compensation consultants to establish competitive, market-driven pay ranges by job classification, which enables us to recruit candidates based on objective factors like years of experience and strength of relevant skills.
Regulatory Environment
Our operations and investments are subject to extensive regulation by United States federal, state and local authorities. In addition, NEXUS and the Vector Pipeline are subject to applicable laws, rules, and regulations in Canada.
FERC Regulation
Many of our business operations are subject to extensive regulation by the FERC under the Natural Gas Act, the Natural Gas Policy Act and regulations, rules and policies promulgated under those and other statutes. Specifically, the Vector Pipeline, the Millennium Pipeline, the Birdsboro Pipeline, the NEXUS Gas Transmission Pipeline, and the Washington 10 Storage Complex are subject to the FERC's Natural Gas Act authority and provide interstate services in accordance with their FERC-approved tariffs. Generally, the 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;
•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;
•terms and conditions of services and service contracts with customers;
•depreciation and amortization rates and policies; and
•acquisitions and dispositions of interstate pipelines and storage facilities.
The FERC regulates the rates and charges for pipelines and storage in interstate commerce. Under the Natural Gas Act, 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 the FERC’s cost-of-service ratemaking process. Generally, the maximum filed recourse rates for interstate pipelines are based on the cost of providing that 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 or stored, 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 the 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. Changes to rates or terms and conditions of service and contracts can be proposed by a pipeline company under Section 4 of the Natural Gas Act. Rate increases proposed by a regulated interstate pipeline may be challenged and such increases may ultimately be rejected by the FERC. The existing interstate pipeline and storage rates or terms and conditions of service and contracts may be challenged by a complaint filed by interested persons including customers, state agencies or the FERC under Section 5 of the Natural Gas Act. 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 Natural Gas Act are subject only to prospective change by the 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 the 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.
FERC regulations also extend to the terms and conditions set forth in agreements for pipelines and storage services executed between interstate pipelines and their customers. These 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, the FERC. If the 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 Natural Gas Act could result in the imposition of civil and criminal penalties. Among other matters, the Energy Policy Act of 2005, which we refer to as the "EPAct 2005," amended the Natural Gas Act to give FERC authority to impose civil penalties for violations of the Natural Gas Act up to $1 million for any one violation, per day and violators may be subject to criminal penalties of up to $1 million per violation, per day and five years in prison. The $1 million civil penalty levels adjust annually based on inflation and have been set at $1,388,496 per violation, per day for 2022.
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 Natural Gas Policy Act, or "Section 311". Certain of our systems provide interstate transportation in accordance with an Operating Statement on file with the FERC. Under Section 311, rates charged for transportation must be fair and equitable, and amounts collected in excess of fair and equitable rates are subject to refund with interest. Rates for service pursuant to Section 311 are generally subject to review and approval by FERC at least once every five years. Additionally, the terms and conditions of service set forth in the intrastate pipeline’s Statement of Operating Conditions are subject to FERC approval. Non-compliance with FERC’s rules and regulations established under Section 311 could result in the imposition of civil and criminal penalties. Among other matters, the EPAct 2005 also amended the Natural Gas Policy Act to give FERC authority to impose civil penalties for violations of the Natural Gas Policy Act up to $1 million for any one violation and violators may be subject to criminal penalties of up to $1 million per violation and five years in prison. The $1 million civil penalty levels adjust annually based on inflation and have been set at $1,388,496 per violation, per day for 2022.
FERC regulations also extend to the terms and conditions set forth in agreements for pipelines and storage services executed between interstate pipelines and their customers. These 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, the FERC. If the 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. The Vector Pipeline, the Millennium Pipeline, the Birdsboro Pipeline, the NEXUS Gas Transmission Pipeline, and the Washington 10 Storage Complex provide interstate services in accordance with their FERC-approved tariffs. Notwithstanding the regulatory discussion above, we believe the regulatory burden does not currently affect our competitive condition.
State Regulation of Natural Gas Pipelines
In addition to FERC regulation of interstate services provided by intrastate pipelines pursuant to Natural Gas Policy Act Section 311, our intrastate natural gas pipeline operations are subject to regulation by various state agencies. 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 Natural Gas Act exempts natural gas gathering facilities from regulation by the FERC. We believe that our gathering systems meet the traditional tests the FERC has used to establish a pipeline’s status as an exempt gatherer not subject to regulation as a jurisdictional natural gas company. However, the distinction between FERC-regulated transmission services and federally unregulated gathering services is often the subject of litigation in the industry, so the classification and regulation of these systems are subject to change based on future determinations by the FERC, the courts or the U.S. Congress. If the 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 be subject to regulation by the FERC under the Natural Gas Act or the Natural Gas Policy Act. 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 Natural Gas Act or Natural Gas Policy Act, 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 the 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 source of supply over another similarly situated source of supply. The regulations under these statutes may have the effect of imposing 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. We cannot predict whether such a complaint will be filed against us in the future or how a regulator may rule on any such complaint. Failure to comply with state regulations can result in the imposition of administrative, civil and criminal remedies. We are not aware of any pending proceedings or complaints at this time.
Our gathering operations could be adversely affected should they be subject in the future to more stringent 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. Additional rules and legislation pertaining to these matters are considered or adopted from time to time. We cannot predict whether any such additional rules or legislation will be promulgated or enacted, or what effect, if any, such changes might have on our operations, but the industry could be required to incur additional capital expenditures and increased costs depending on future legislative and regulatory changes.
The price at which we buy and sell natural gas currently is not subject to U.S. federal regulation and, for the most part, is not subject to state regulation. The EPAct 2005 amended the Natural Gas Act and Natural Gas Policy Act to prohibit fraud and manipulation in natural gas markets. The FERC subsequently 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 the 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. The 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 the FERC with the authority to impose civil penalties of up to approximately $1 million (adjusted annually for inflation) per day per violation. On January 8, 2022, FERC issued an order (Order No. 875) increasing the maximum civil penalty amounts under the Natural Gas Act and Natural Gas Policy Act to adjust for inflation. FERC may now assess civil penalties under the Natural Gas Act and Natural Gas Policy Act of up to $1,307,164 per violation per day. In addition, the Commodity Futures Trading Commission, which we refer to as the "CFTC," is directed under the Commodities Exchange Act, which we refer to as the "CEA," 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 $1.2 million or triple the monetary gain to the violator for violations of the anti-market manipulation sections of the CEA.
Pipeline Safety and Maintenance
Our interstate natural gas pipeline system is subject to regulation by the Pipeline and Hazardous Materials Safety Administration, or PHMSA. PHMSA prescribes and enforces federal safety standards and reporting requirements that apply to interstate gas facilities. The safety standards include requirements for pipeline design, installation, testing, construction, operation and maintenance, as well as requirements for pipeline operator qualification and integrity management. The integrity management requirements apply to gas transmission line segments located in high consequence areas, or HCAs, and require operators to perform periodic 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 rule, which became effective July 1, 2020, requires operators of certain gas transmission pipelines to reconfirm maximum allowable operating pressure and establishes a new "Moderate Consequence Area" for determining regulatory requirements for gas transmission pipeline segments outside of HCAs. The rule also establishes new requirements for conducting baseline assessments and incorporates industry standards and guidelines as well as new requirements for integrity management programs. The rule also includes several requirements that allow operators to notify PHMSA of proposed alternative approaches to achieving the objectives of the minimum safety standards. We have revised our operating and inspection procedures to address these requirements and are in the process of implementing these changes. We do not expect our operations to be affected by this new rule any differently than other similarly situated midstream companies.
PHMSA recently issued another final rule, entitled "Safety of Gas Gathering Pipelines," that establishes new safety standards and reporting requirements for certain historically unregulated onshore gas gathering lines, effective as of May 16, 2022. The final rule creates 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. The final rule also creates a new Type R category of reporting-only onshore gas gathering that are subject to PHMSA’s incident and annual reporting requirements. We are revising our operating and inspection procedures to address these requirements and are in the process of implementing these changes. We may incur expenses related to compliance activities but do not expect our operations to be affected any differently than similarly situated midstream companies.
PHMSA is in the process of developing other regulations to address congressional mandates and for other purposes. For example, PHMSA is expected to issue a final rule establishing new requirements for the installation of valves and minimum rupture detection standards for certain gas pipelines, and to amend the requirements that apply to the repair, cathodic protection, and integrity management of gas transmission lines. PHMSA is also in the early stages of developing rules for gas pipeline leak detection and repair and implementing a parallel self-executing provision that requires gas pipeline operators to reduce methane emissions. The adoption of these new PHMSA rules and implementation of the methane emissions mandate 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. While we cannot predict the outcome of legislative or regulatory initiatives, such legislative and regulatory changes could materially adversely affect our business, financial condition and results of operations.
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 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 a result of the testing program, 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. This estimate does not include the impact of the Safety of Gas Gathering Pipelines rule or other final rules that PHMSA may issue in the near future. 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 $225,000 per day for each violation and approximately $2.25 million for a related series of violations. This maximum penalty authority established by statute will continue to be adjusted periodically to account for inflation.
We believe that our operations are in substantial compliance with all existing U.S. federal, state and local pipeline safety laws and regulations. However, the adoption of new laws and regulations, such as those proposed by PHMSA, could result in significant added costs or delays in service or the termination of projects, which could have a material adverse effect on us in the future.
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. The FERC certificate was received on April 15, 2021 and was effective on August 1, 2021. As such our natural gas storage facilities are required to meet the federal safety standards as required by §192.12, Underground natural gas storage facilities.
We believe that our operations are in substantial compliance with §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 stringent U.S. federal, state and local laws and regulations relating to the protection of the environment. These laws and regulations require the acquisition of and compliance with permits and the installation of pollution control equipment; limit or prohibit construction activities in sensitive areas, such as wetlands, coastal regions or areas inhabited by 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 workplace health and safety standards for the benefit of employees.
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.
Any failure to comply with these laws and regulations may result in the initiation of administrative, civil and criminal actions and the imposition of 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, which allow individuals and environmental organizations to 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. Remediation obligations can result in significant costs associated with the investigation and remediation of contaminated facilities, and with damage claims arising from the 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 such legal requirements will materially adversely affect our business, financial condition and results of operations. Nonetheless, the trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment. Thus, there can be no assurance as to the amount or timing of future expenditures for environmental compliance or remediation, and actual future expenditures may be significantly in excess of the amounts we currently anticipate. For example, we try to anticipate future regulatory requirements that might be imposed and plan accordingly to remain in compliance with changing environmental laws and regulations and to minimize the costs of such compliance. While we believe that we are in substantial compliance with existing environmental laws and regulations, there is no assurance that the current conditions will continue in the future.
The following is a discussion of several of the material environmental laws and regulations, as amended from time to time, which relate to our business.
Hazardous Substances and Waste. The Comprehensive Environmental Response, Compensation, and Liability Act, which we refer to as "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.
We also generate solid wastes, including hazardous wastes, which are subject to the requirements of the Resource Conservation and Recovery Act, which we refer to as "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. In the ordinary course of our operations, we generate wastes constituting solid waste and, in some instances, 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 operators, and we send hydrocarbons and wastes to third-party sites for treatment or disposal. Under CERLCA, 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 company.
Climate Change. Legislative and regulatory measures to address climate change and greenhouse gas, which we refer to as "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 reporting of GHGs from certain onshore oil and natural gas production sources on an annual basis. On November 15, 2021, the EPA published a proposed rule imposing standards of performance for GHG emissions (in the form of methane limitations) and for volatile organic compound emissions, applicable to new, modified, and reconstructed crude oil and natural gas sources, including the production, processing, transmission and storage segments. Additionally, the U.S. Congress, along with U.S. federal and state agencies, has considered measures to reduce the emissions of GHGs. Legislation or regulation 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; pay any taxes related to our GHG emissions and/or administer and manage a GHG emissions program, and otherwise increase the costs of our operations, including costs to operate and maintain our facilities.
The effect of climate change legislation or regulation on our business is currently uncertain. If we incur additional costs to comply with such legislation or regulations, we may not be able to pass on the higher costs to our customers or recover all the costs related to complying with such requirements and any such recovery may depend on events beyond our control, including the outcome of future rate proceedings before the 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 waters of the United States, 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, which we refer to as "the U.S. Army Corps," or an analogous state agency. In April 2020, the EPA and the U.S. Army Corps issued the Navigable Waters Protection Rule under the U.S. federal Clean Water Act, which we refer to as the "WOTUS Rule," narrowing the definition of "waters of the United States" relative to the definition under a prior 2015 rule. On August 30, 2021, the U.S. District Court for the District of Arizona vacated and remanded the WOTUS Rule. Based on this ruling, the EPA and the U.S. Army Corps halted implementation of the WOTUS Rule, and, on December 7, 2021, a rule replacing the WOTUS Rule was published which, if implemented, would in practice restore the pre-2015 definition of "waters of the United States." Agencies are interpreting the WOTUS Rule consistent with the pre-2015 definition in the interim period. To the extent that any future rules expand the scope of the Clean Water Act’s jurisdiction, we could face increased 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 Natural Gas Act requires authorization from the FERC. Certain FERC actions relating to such pipelines are subject to the National Environmental Policy Act, which we refer to as the "NEPA." NEPA requires U.S. federal agencies, such as the 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.
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 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 also focused on a possible connection between the operation of injection wells used for oil and gas wastewater disposal and seismic activity. Similar concerns have been raised that hydraulic fracturing may also contribute to seismic activity. When caused by human activity, such events are called induced seismicity. In light of these concerns, some state regulatory agencies have modified their regulations or issued orders to address induced seismicity through restrictions on disposal wells or enhanced well construction and monitoring requirements. Certain environmental and other groups have also suggested that additional U.S. federal, state and local laws and regulations may be needed to more closely regulate the wastewater disposal process.
If new laws or regulations that significantly restrict hydraulic fracturing or wastewater disposal wells are adopted, such laws could lead to greater opposition to, and litigation concerning, related oil and gas producing activities and to operational delays or increased operating costs for our customers, which in turn could reduce the demand for our services.
Endangered Species Act. The U.S. federal Endangered Species Act, which we refer to as the "ESA," restricts activities that may adversely affect endangered and threatened species or their habitats. 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 the U.S. federal Occupational Safety and Health Act, which we refer to as "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 EPA Risk Management Program regulations, which we refer to as the "RMP regulations." The RMP regulations were amended by the EPA under a final rule published December 19, 2019. The amendments were intended to better address potential security risks and ensure regulatory consistency, and we do not anticipate that they will significantly increase our cost of compliance. We have implemented internal programs and policies to comply with these health and safety requirements.
We believe that we are in substantial compliance with all applicable laws and regulations relating to worker health and safety. Historically, worker safety and health compliance costs have not materially adversely affected our business, financial condition and results of operations; however, there can be no assurance that such costs will not be material in the future or that such future compliance will not materially adversely affect our business, financial condition and results of operations. While we may increase expenditures in the future 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.
Physical and Cyber Security
Physical Security
Given the nature of the commodities we transport, treat, store, and sell, our assets and the assets of our customers and others in our industry may be targets of terrorist activities, theft or vandalism. A terrorist attack could create significant price volatility, disrupt our business, limit our access to capital markets, or cause significant harm to our operations, such as full or partial disruption to our ability to gather, process, or transport natural gas. The Transportation Security Administration published guidelines for the security of natural gas pipelines. We have implemented applicable practices from those guidelines. Acts of terrorism, as well as events occurring in response to or in connection with acts of terrorism, could cause environmental repercussions that could result in a significant decrease in revenues or significant reconstruction or remediation costs, which could materially adversely affect our business, financial condition and results of operations.
Cyber Security
We have become increasingly dependent on the systems, networks and technology that we use to conduct almost all aspects of our business, including the operation of our pipelines, storage and gathering assets, the recording of commercial transactions, and the reporting of financial information. We depend on both our own systems, networks and technology, as well as the systems, networks and technology of DTE Energy, our vendors, customers and other business partners, including our equity method investees. We have existing systems in place and continue to develop systems to monitor and address the risk of cyber security breaches in our business, operations and control environments. We routinely review and update those systems as the nature of that risk requires. Governmental standards and commonly accepted frameworks for the protection of computer-based systems and technology from cyber threats and attacks have been adopted. We monitor newly developed cyber security standards or legislation and consider adoption as appropriate for our business. Breaches in our information technology infrastructure or physical facilities, or other disruptions including those arising from theft, vandalism, fraud, or unethical conduct, could result in damage to or destruction of our assets, unnecessary waste, safety incidents, damage to the environment, reputational damage, potential liability, the loss of contracts, the imposition of significant costs associated with remediation and litigation, heightened regulatory scrutiny, increased insurance costs, which could materially adversely affect our business, financial condition and results of operations.

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ITEM 1A. RISK FACTORS
Item 1A. Risk Factors
You should carefully consider the following risks and other information in this Annual Report on 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 demand or in production of natural gas in our asset footprint could materially adversely affect our business, financial condition and results of operations.
Our business is dependent on the continued availability of and demand for natural gas in our areas of operation, which include the Midwestern U.S., Eastern Canada, Northeastern U.S. and Gulf Coast regions. A reduction in the natural gas volumes supplied by producers could result in reduced throughput on our systems and materially adversely affect our business, financial condition and results of operations. The primary factors affecting our ability to obtain sources of natural gas include (i) the level of successful drilling activity near our systems, (ii) our ability to compete for volumes from successful new wells and (iii) our ability to compete successfully for volumes from sources connected to other pipelines.
To maintain or increase the contracted capacity or the volume of natural gas transported, stored and gathered on our systems and cash flows associated therewith, our customers must continually obtain adequate supplies of natural gas. If new supplies of natural gas are not obtained to replace the natural decline in volumes from existing supply basins in our areas of operation, or if natural gas supplies are diverted to serve other markets, the overall volume of natural gas gathered, transported and stored on our systems would decline, which could materially adversely affect our business, financial condition and results of operations.
We have several customers with two being key customers, Southwestern and Antero. The loss of, or reduction in volumes from, either of these customers could result in a decline in demand for our services and materially adversely affect our business, financial condition and results of operations.
Southwestern and Antero accounted for approximately 67% and 10% of our operating revenues, respectively, for the year ended December 31, 2021. Our operating revenues do not include unconsolidated joint ventures accounted for as equity method investments. The loss of all or even a portion of the contracted volumes of these or other customers, the failure to extend or replace these contracts or the extension or replacement of these contracts on less favorable terms, as a result of competition, creditworthiness, reduced 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 at the time our existing contracts, including both our contracts with existing customers and our contracts with our suppliers and other counterparties, expire and are subject to renegotiation and renewal. Firm revenue contracts are typically long-term and can include MVCs and demand charges, which provide for fixed revenue commitments regardless of the market value or volumes of natural gas that flow on the system. We may not be able to renew or replace these contracts at expiration and our efforts to negotiate for similar fixed revenue commitments may not be successful, which could cause our exposure to commodity price risk to change or adversely affect the stability of our cash flows.
Any failure to extend or replace a significant portion of our existing contracts or extending or replacing them at unfavorable or lower rates or with lower or no associated fixed revenue commitments, could materially adversely affect our business, financial condition and results of operations.
If third-party pipelines and other facilities interconnected to our assets become unavailable to transport natural gas, our business, financial condition and results of operations could be materially adversely affected.
We depend upon third-party pipelines and other facilities that provide receipt and delivery options to and from our assets. For example, our pipelines interconnect with multiple interstate pipelines in the Midwestern U.S., Eastern Canada, Northeastern U.S. and Gulf Coast regions and a significant number of intrastate pipelines. Because we do not own these third-party pipelines or facilities, their continuing operation is not within our control. If these pipeline connections were to 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, our business, financial condition and results of operations could be materially adversely affected.
Our operations, our customers’ operations and other interconnected pipelines and facilities are subject to many hazards, including (i) damage to pipelines, facilities, equipment, environmental controls and surrounding properties, including damage resulting from 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 damage to property, environmental pollution, impairment of our operations, regulatory investigations and penalties and substantial losses to us. 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.
Expansion projects or acquisitions that are expected to be accretive may nevertheless reduce our cash from operations and could materially adversely affect our business, financial condition and results of operations.
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, including 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 product 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 the Stonewall Gas Gathering, Vector Pipeline, Millennium Pipeline, NEXUS, Generation Pipeline and South Romeo, 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 are 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 third parties 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 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 shale formations. In addition, the FERC is considering modifying its policy governing the issuance of interstate natural gas pipeline authorizations, in part to address concerns about climate change. 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. As macroeconomic conditions improved throughout 2021, the labor market tightened, resulting in increased employee turnover and skilled labor shortages. The challenge to attract and retain qualified talent could lead to increased wage inflation or impede our ability to execute certain key strategic initiatives as we respond to this labor shortage. In addition, our operations require engineers, operational and field technicians and other highly skilled employees. Competition for experienced executives and skilled employees in some areas is high and we may experience difficulty in recruiting and retaining employees. Our costs, including costs for contractors to replace employees, productivity costs and safety costs, may rise. Failure to hire and adequately train replacement employees, including the transfer of significant internal historical knowledge and expertise to new employees, or the future availability and cost of contract labor may adversely affect our ability to manage and operate our business. 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.
The physical risks associated with climate change may adversely affect our operations and financial results.
Climate change could create acute and/or chronic physical risks to our operations, which may adversely affect financial results. Acute physical risks include more frequent and severe weather events, which may result in adverse physical effects on portions of the country’s gas infrastructure, and could disrupt our supply chain and ultimately our operations. Disruption of transportation and distribution systems, including systems operated by us and systems that are operated by others but on which our operations or our customers’ operations rely, could result in reduced operational efficiency and customer service interruption. Severe weather events could also cause physical damage to facilities, all of which could lead to reduced revenues, increased insurance premiums or increased operational costs. To the extent we are unable to recover those costs, or if the recovery of those costs results in higher rates and reduced demand for our services, our future financial results could be adversely impacted. Chronic physical risks include long-term shifts in climate patterns resulting in new storm patterns or chronic increased temperatures, which could cause demand for gas as a heating fuel to decrease as a result of warmer weather and adversely impact our future financial results.
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 market in order to attract financing on reasonable terms may be adversely affected. Depending on market conditions at the relevant time, we may have to rely more heavily on additional equity financings or on less efficient forms of debt financing that require a larger portion of our cash flow from operations, thereby reducing funds available for our operations, future business opportunities and other purposes. We may not have access to such equity or debt capital on favorable terms, at the desired times, or at all. In addition, declines in our credit ratings may influence our suppliers’ and customers’ willingness to transact with us, and we may be required to make prepayments or provide security to satisfy credit concerns.
Fluctuations in energy prices 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.
Sustained declines in natural gas prices could have a negative impact on exploration, development and production activity and could lead to a material decrease in such activity, which could result in reduced throughput on our systems and materially adversely affect our business, financial condition and results of operations. See also "-Any significant decrease in demand or in production of natural gas in our asset footprint could materially adversely affect our business, financial condition and results of operations".
We are 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 (including two of our key customers, Southwestern and Antero). 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, 2021, we had outstanding approximately $2.1 billion of senior notes and $1.0 billion of indebtedness under our Term Loan Facility and $750 million of commitments under the 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 than competitors with less debt to competitive pressures or a downturn in our business or the economy generally.
Our ability to service our debt will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control. In addition, our ability to service debt under our Revolving Credit Facility, our Term Loan Facility and other debt facilities with floating rate terms will depend on market interest rates, since we anticipate that the interest rates applicable to our borrowings will fluctuate with movements in interest rate markets. If our operating results are not sufficient to service our current or future indebtedness, we will be forced to take actions such as reducing dividends, reducing or delaying our business activities, acquisitions, investments or capital expenditures, selling assets, restructuring or refinancing our debt, or seeking additional equity capital. We may not be able to effect any of these actions on satisfactory terms, or at all.
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.
Our term loan and borrowings under our Revolving Credit Facility have, and we may in the future enter into debt instruments with, variable interest rates. Increases in interest rates on variable rate debt will increase our interest expense unless we make arrangements to hedge the risk of rising interest rates. These increased costs could reduce our profitability, impair our ability to meet our debt obligations, increase the cost of financing and materially adversely affect our business, financial condition 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.
Continuing inflation and cost increases may impact our sales margins and profitability.
Inflationary pressure could adversely impact our profitability. Our operating costs may increase, and may continue to increase, due to the recent growth in inflation which has impacted product costs, labor rates, and domestic transportation. We may not be able to fully offset these inflation increases by raising prices for our services, which could result in downward pressure on our results of operations.
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 credit facilities 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 credit facilities contain, or any future credit facility or indenture we may enter into may also contain, covenants requiring us to maintain certain financial ratios and tests. If we violate any of the restrictions, covenants, ratios or tests in the applicable credit facility or indentures, the lenders thereunder will be able to accelerate the maturity of all borrowings under the credit facility and demand repayment of amounts outstanding, and our lenders’ commitment to make further loans to us may terminate. We might not have, or be able to obtain, sufficient funds to make these accelerated payments. Any subsequent replacement of our credit facilities 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".
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 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 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. States could elect to prohibit hydraulic fracturing altogether, as was announced in December 2014 with regard to hydraulic fracturing activities in New York. 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 have conducted or are conducting reviews and studies on the environmental aspects of hydraulic fracturing, including the Environmental Protection Agency, which we refer to as the "EPA." For example, in December 2016, the EPA issued its final report on a study it had conducted over several years regarding the effects of hydraulic fracturing on drinking water sources. The final report, contrary to several previously published draft reports issued by the EPA, found instances in which impacts to drinking water may occur. However, the report also noted significant data gaps that prevented the EPA from determining the extent or severity of these impacts. The report, or other reviews or studies on the environmental aspects of hydraulic fracturing, could spur initiatives to further regulate hydraulic fracturing.
Other governmental agencies, including the U.S. Department of Energy, have evaluated or are evaluating various other aspects of hydraulic fracturing. These completed, ongoing or proposed studies, 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 have 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. Such regulations and restrictions could cause delays and impose additional costs and restrictions on us and our customers. The adoption of new laws, regulations or ordinances at the U.S. federal, state or local levels imposing more stringent restrictions on hydraulic fracturing could make it more difficult for our customers to complete natural gas wells, increase customers’ costs of compliance and doing business, and otherwise adversely affect the hydraulic fracturing services they perform, which could negatively impact demand for our services.
Furthermore, the tax laws, rules and regulations that affect our customers are subject to change. For example, Pennsylvania’s governor has in recent legislative sessions proposed legislation to impose a state severance tax on the extraction of natural resources, including natural gas produced from the Marcellus/Utica shale formations, either in replacement of or in addition to the existing state impact fee. In late January 2021, Pennsylvania’s governor announced he was re-proposing legislation to enact a severance tax to fund COVID-19 relief measures. Pennsylvania’s legislature has not thus far advanced any of the governor’s severance tax proposals; however, severance tax legislation may continue to be proposed in future legislative sessions. Any such tax increase or change could adversely impact the earnings, cash flows and financial position of our customers and cause them to reduce their drilling in the areas in which we operate.
Our 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 business, including our capital costs to construct, maintain and upgrade pipelines and other facilities, or 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 refrain from construction activities in sensitive areas such as wetlands, wilderness or urban areas or areas inhabited by 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 greenhouse gas, which we refer to as "GHG," could be implemented that significantly increase our compliance costs, pollution mitigation costs, or the cost of any remediation of environmental contamination that may become necessary, and these costs could be material. For example, in April 2020 the U.S. federal district court for the district of Montana issued a broad order vacating the U.S. Army Corps of Engineers Clean Water Act Section 404 Nationwide Permit 12, which we refer to as "NWP 12," for alleged failure to comply with consultation requirements under the U.S. federal Endangered Species Act. Pipeline companies and other developers of linear infrastructure frequently rely upon NWP 12 for construction and maintenance projects in jurisdictional wetland areas. In May 2020, the U.S. Army Corps of Engineers, which we refer to as "the U.S. Army Corps," appealed the U.S. federal district court’s order to the U.S. Court of Appeals for the Ninth Circuit. In July 2020, the U.S. Supreme Court granted a stay of the district court’s order vacating NWP 12, pending the disposition of the appeal in the Ninth Circuit and any subsequent appeal to the Supreme Court. On January 5, 2021, the U.S. Army Corps announced that it reissued NWP 12. On August 11, 2021, the Ninth Circuit granted partial vacatur of the appeal, concluding that the U.S. Army Corps' reissuance of NWP 12 rendered the underlying claim of the appeal moot. Environmental groups have filed a complaint in the Montana federal court challenging the U.S. Army Corps reissuance of NWP 12. The litigation is ongoing. Moreover, the NWP 12 reissuance is among the agency actions listed for review in accordance with President Biden’s January 20, 2021 Executive Order ("Protecting Public Health and the Environment and Restoring Science to Tackle the Climate Crisis"). 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. 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, on January 27, 2021 President Biden issued an Executive Order ("Tackling the Climate Crisis at Home and Abroad") that included provisions directing the Secretary of the Interior to pause approval of new oil and natural gas leases on public lands pending completion of a comprehensive review and reconsideration of U.S. federal oil and gas permitting and leasing practices and directing the heads of U.S. federal agencies to take steps to ensure that, to the extent consistent with applicable law, federal funding is not directly subsidizing fossil fuels. In July 2021, however, a Federal Court in Louisiana granted a nationwide preliminary injunction against enforcement of the moratorium. The Biden Administration has appealed the injunction. Also, on November 26, 2021 the Department of the Interior issued a report calling for an increase in royalty payments for new oil and gas leases on federal lands. The report may pave the way for legislation the in fact increases such royalty rates. 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 greenhouse gases present a danger to public health and the environment, has adopted regulations under existing provisions of the U.S. federal Clean Air Act that, among other things, restrict emissions of GHGs and require the monitoring and reporting of GHG emissions from specified onshore and offshore
production sources and onshore treating sources in the U.S. on an annual basis. In addition, some communities and cities have banned new natural gas hook-ups or are expected to enact similar electrification measures in response to climate change concerns. Other actions that could be pursued by the Biden Administration may include the imposition of more restrictive requirements for the establishment of pipeline infrastructure or the permitting of LNG export facilities. Such regulations or any new U.S. federal laws restricting emissions of GHGs, such as a carbon tax, from customer operations, or that limit the growth of pipelines and LNG exports from the U.S., could delay or curtail their activities and, in turn, adversely affect our business, financial condition and results of operations.
There is inherent risk of the incurrence of environmental costs and liabilities in our business due to our handling of natural gas and hazardous substances, and historical industry operations and waste management and disposal practices. For example, an accidental release from one of our facilities could subject us to substantial liabilities arising from environmental cleanup and restoration costs, claims made by neighboring landowners and other third parties for personal injury and property damage, governmental claims for natural resource damages or imposing fines or penalties for related violations of environmental laws, permits or regulations. In addition, strict, joint and several liabilities may be imposed under certain environmental laws that govern the investigation and remediation of soil and groundwater contamination, which could cause us to become liable for the contamination caused by others, such as prior operators of our facilities, or for the consequences of our own actions that were in compliance with all applicable laws at the time those actions were taken, such as the historic disposal by us of hazardous substances or wastes at third party sites where contamination is subsequently discovered. Private parties, including the owners of the properties through which our assets pass and facilities where our wastes are taken for reclamation or disposal, may also have the right to pursue legal actions against us to enforce compliance, as well as to seek damages for non-compliance, with environmental laws and regulations or for personal injury or property damage that may result from environmental and other impacts of our operations. We may not be able to recover some or any of these costs through insurance or increased revenues, which could materially adversely affect our business, financial condition and results of operations. For more information, see the section entitled "Items 1. and 2. Business and Properties-Regulatory Environment-Environmental and Occupational Health and Safety Regulations".
Our natural gas transportation and storage operations are subject to extensive regulation by the 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 the FERC, and state regulatory authorities. Generally, the 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; 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; terms and conditions of services and service contracts with customers; depreciation and amortization rates and policies; facility replacements and upgrades; and acquisitions and dispositions of interstate pipelines and storage facilities or assets.
While the FERC may exercise jurisdiction over the rates and terms of service for certain of the services provided by our assets if our assets are intrastate pipelines providing service in interstate commerce, such assets may not be subject to the 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 the FERC authorizing the construction, either by filing a new certificate application or filing to amend its existing certificate.
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, the FERC. In the event that the 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. The Vector Pipeline, the Millennium Pipeline, the Birdsboro Pipeline, the NEXUS Gas Transmission Pipeline, 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 the FERC’s regulations. Furthermore, should the 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 the 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 the FERC or state regulatory authorities regarding the natural gas industry may have an impact on us, including the 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 the FERC's authorization of new or expanded pipeline and storage infrastructure. The 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.
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 run 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 our fuel usage and lost and unaccounted-for volumes pursuant to our contractual agreements. In addition, our gathering systems have contracts that provide for specified levels of fuel retainage. As such, we may find it necessary to purchase natural gas in the market to make up for any of these differences, which exposes us to commodity 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 "lateral pipelines," meet the traditional tests the FERC has used to establish a pipeline’s status as an exempt gathering facility not subject to FERC regulation as a jurisdictional natural gas company under the Natural Gas Act, although the 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. The 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 the 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 gathering services not regulated by FERC has regularly been 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 the 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, in turn, 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. For example, significant changes to the U.S. tax laws have been proposed, including, among others, an increase in the corporate tax rate and the imposition of a tax on the fair market value of stock that is repurchased by certain corporations. 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. It cannot be predicted whether or when tax laws, statutes, rules, regulations or ordinances may be enacted, issued, or amended that could materially and adversely impact our financial position, results of operations, or cash flows.
Some of our operations cross the U.S./Canada border and are subject to cross-border regulation.
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.
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.
The U.S. Department of Transportation, through the Pipeline and Hazardous Materials Safety Administration, referred to as "PHMSA," has adopted regulations requiring pipeline operators to develop integrity management programs for transportation pipelines located where a leak or rupture could do the most harm in a high consequence area, referred to as an "HCA." The regulations require operators to: (i) perform ongoing assessments of pipeline integrity; (ii) identify and characterize applicable threats to pipeline segments that could impact an HCA; (iii) improve data collection, integration and analysis; (iv) repair and remediate the pipeline as necessary; and (v) implement preventive and mitigating actions.
Additionally, while states are largely 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 the U.S. federal government for interstate lines, 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 increased costs of operation that, in some instances, may be significant.
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 associated with our compliance 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 for pipelines that are not currently subject to regulation by PHMSA 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 gathering assets in Northern Michigan and our storage assets, have been in operation for many years, with some portions being more than 40 years old. In some cases, certain portions may have been in service for many years prior to our purchase of the relevant systems or have been operated by third parties not under our control and consequently, there may be historical occurrences or latent issues regarding our pipeline systems that management may be unaware of and that could materially adversely affect our business, financial condition and results of operations. Certain portions of our pipeline systems are located in or near areas determined to be HCAs, which are areas where a release 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 cyber events. 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 risks 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 amounts of coverage. The occurrence of an event that is not fully covered by insurance could materially adversely affect our business, financial condition and results of operations. 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.
We are subject to cyber security and data privacy laws, regulations, litigation and directives relating to our processing of personal data.
Several jurisdictions in which we operate throughout the U.S. have laws governing how we must respond to a cyber incident that results in the unauthorized access, disclosure or loss of personal data. Our business involves collection, uses and other processing of personal data of our employees, contractors, suppliers and service providers. As legislation continues to develop and cyber incidents continue to evolve, we will likely be required to expend significant resources to continue to modify or enhance our protective measures to comply with such legislation and to detect, investigate and remediate vulnerabilities to cyber incidents. Any failure by us, or a company we acquire, to comply with such laws and regulations could result in reputational harm, loss of goodwill, penalties, liabilities and mandated changes in our business practices. Additionally, if we acquire a company that has violated or is not in compliance with applicable data protection laws, we may incur significant liabilities and penalties as a result.
A terrorist attack, armed conflict or cyber security event, or the threat of them, could harm our business.
In 2012, the U.S. Department of Homeland Security issued public warnings that indicated that pipelines and other assets might be specific targets of terrorist organizations or "cyber security" events. Potential targets might include our pipelines, storage and gathering systems or operating systems and may affect our ability to operate or control our assets or utilize our customer service systems. Also, 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 occurrence of any of these events, including an attack or threat targeted at our pipelines and other assets 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. These developments may subject our operations to increased risks, as well as increased costs, and, depending on their ultimate magnitude, could materially adversely affect our business, financial condition and results of operations.
Other Business Risks
Customers’, legislators’ and 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.
A number of factors can affect customers’, legislators’ or regulators’ perception 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; and our ability to safeguard sensitive customer information. Customers’, legislators’ and regulators’ opinions of us can also be affected by media coverage, including the proliferation of social media, which may include information, whether factual or not, that could damage the perception of our company and the midstream industry.
Other concerns about the use of natural gas include the potential for natural gas explosions and the effect of natural gas on indoor air quality and the environment generally. These shifts in public sentiment may not only impact further legislative initiatives, but behaviors and perceptions of customers, investors and regulators.
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 make it more difficult for us to achieve favorable legislative or regulatory outcomes. In addition, in recent years, increasing attention has been given to corporate activities related to environmental, social and governance, which we call "ESG," matters in public discourse and the investment community. A number of advocacy groups have campaigned for governmental and private action to promote change at public companies related to ESG matters, including increasing attention and demands for action related to climate change, promoting the use of substitutes for fossil fuel products and encouraging the divestment of companies in the fossil fuel industry, and some organizations that provide information to investors on corporate governance and related matters have developed ratings systems for evaluating companies on their approach to ESG matters. Unfavorable ESG ratings may lead to increased negative investor sentiment toward us and our industry and to the diversion of investment to other companies or industries, which could adversely affect our stock price and our access to and costs of capital and could adversely impact the demand for our services and, in turn, materially adversely affect our business, financial condition and results of operations.
We are currently preparing and expect to publish our first sustainability report in the second quarter 2022, which will detail how we seek to manage our operations responsibly and ethically, as well as strategies and goals associated with reducing our environmental impact. The sustainability report is expected to include 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 sustainability report increases our level of transparency to our stakeholders and complements the disclosures regarding our contributions to sustainable development in this Annual Report on 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 sustainability report could negatively impact our reputation, employee retention, and the willingness of our customers and suppliers to do business with us.
Negative opinions could also result in sales volumes reductions or increased use of other sources of energy, or additional difficulties in accessing capital markets or greater challenges in developing or operating our assets. Any of these consequences could materially adversely affect our business, financial condition and results of operations.
A pandemic, epidemic or outbreak of an infectious disease, such as the COVID-19 pandemic, could materially adversely affect our business, financial condition and results of operations and we face numerous risks related to the COVID-19 pandemic.
A global or national public health crisis, such as COVID-19, may cause disruptions to our business and operational plans. Since the beginning of 2020, the COVID-19 pandemic has spread across the globe and disrupted economies around the world, including the natural gas industry in which we operate. The rapid spread of the virus has led to the implementation of various responses, including U.S. federal, state and local government-imposed quarantines, shelter-in-place mandates, sweeping restrictions on travel and other public health and safety measures.
While we believe our business, financial conditions and results of operations have not been materially adversely affected by the COVID-19 pandemic to date, we believe that COVID-19 continues to present the potential for materially adverse risks. Some factors from the COVID-19 pandemic that could materially adversely affect our business, financial condition and results of operations include: third-party effects, including contractual and counterparty risk; litigation risk and possible loss contingencies related to COVID-19, employee matters and insurance arrangements; supply/demand market and macroeconomic forces; lower commodity prices; unavailable storage capacity and operational effects; decreased utilization and rates for our assets and services; impact on liquidity and access to capital markets; our ability to comply with our covenants and other restrictions in agreements governing our debt; workforce reductions and furloughs; cyber security threats; operational, health or safety-related incidents; and U.S. federal, state and local actions. As of December 31, 2021, there have not been meaningful impacts or disruptions to our business, financial condition and results of operations as a result of the COVID-19 pandemic. We continue to assess the impact of the COVID-19 pandemic on an ongoing basis.
COVID-19 and various governmental and private responses to the virus have led to widespread, global supply chain disruptions during the 2021 fiscal year and continuing into 2022. These supply chain disruptions may cause some of our suppliers to fail to deliver the quantities of supplies we need or fail to deliver such supplies in a timely manner. The failure to receive any such supplies could inhibit our ability to operate our business, which could materially adversely affect our business, financial condition and results of operations.
Risks Relating to the Separation
We could have an indemnification obligation to DTE Energy in accordance with the terms of the Tax Matters Agreement if the Distribution were determined not to qualify for non-recognition treatment for U.S. federal tax purposes, which could materially adversely affect our business, financial condition and results of operations
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 Code apply, we could, under certain circumstances, be required to indemnify DTE Energy for the resulting taxes and related expenses. Any such indemnification obligation could materially adversely affect our business, financial condition and results of operations.
In addition, Section 355(e) of the Code generally creates a presumption that the Distribution would be taxable to DTE Energy, but not to shareholders, if we or our shareholders were to engage in transactions that result in a 50% or greater change by vote or value in the ownership of our stock during the four-year period beginning on the date that begins two years before the date of the Distribution, unless it were established that such transactions and the Distribution were not part of a plan or series of related transactions giving effect to such a change in ownership. If the Distribution were taxable to DTE Energy due to such a 50% or greater change in ownership of our stock, DTE Energy would recognize gain equal to the excess of the fair market value of our common stock distributed to DTE Energy shareholders over DTE Energy’s tax basis in our common stock and we generally would be required to indemnify DTE Energy for the tax on such gain and related expenses. Any such indemnification obligation could materially adversely affect our business, financial condition and results of operations. For more information, see discussion of the referenced Separation agreements within Note 1, "Separation, Description of the Business, and Basis of Presentation" to the Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.
We agreed to numerous restrictions to preserve the non-recognition treatment of the Distribution, which may reduce our strategic and operating flexibility.
We agreed in the Tax Matters Agreement to covenants and indemnification obligations that address compliance with Section 355(e) of the Code. These covenants and indemnification obligations may limit our ability to pursue strategic transactions or engage in new businesses or other transactions that may otherwise maximize the value of our business and might discourage or delay a strategic transaction that our shareholders may consider favorable. For more information, see discussion of the referenced Separation agreements within Note 1, "Separation, Description of the Business, and Basis of Presentation" to the Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.
We have only operated as an independent, publicly traded company since July 1, 2021, and our historical financial data is not necessarily representative of the results we would have achieved if we had been an independent, publicly traded company and may not be a reliable indicator of our future results.
We derived the historical financial data included in this Annual Report on Form 10-K for the periods prior to July 1, 2021 from DTE Energy’s consolidated financial statements, and this data does not necessarily reflect the results of operations and financial position we would have achieved as an independent, publicly traded company during the periods presented, or those that we will achieve in the future. Prior to the Separation, we operated as part of DTE Energy’s broader corporate organization and DTE Energy or one of its affiliates performed various corporate and operational functions for us, such as accounting, auditing, communications, tax, legal and ethics and compliance program administration, human resources, information technology, insurance, investor relations, risk management, treasury, other shared facilities and other general, administrative and limited operational functions. As part of DTE Energy, we received certain benefits from DTE Energy’s operating diversity, size, purchasing power, credit rating, borrowing leverage and available capital for investments, and we lost these benefits after the Separation. As such, our historical financial data may not be indicative of our future performance as an independent, publicly traded company.
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 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.
After the Separation, certain members of management and directors may face actual or potential conflicts of interest.
Following the Separation, the management and directors of each of DTE Energy and DT Midstream own common stock in both companies and Robert Skaggs, Jr., who is a member of our Board, also serves on the board of directors of DTE Energy, which we refer to as the "DTE Energy Board," and may be required to recuse himself from deliberations relating to arrangements between us and DTE Energy. This ownership and directorship overlap could create, or appear to create, potential conflicts of interest when the management and directors of one company face decisions that could have different implications for themselves and the other company. For example, potential conflicts of interest could arise in connection with the resolution of any dispute regarding the terms of the agreements governing our relationship with DTE Energy. These agreements include the Separation and Distribution Agreement, the Transition Services Agreement, the Tax Matters Agreement, the Employee Matters Agreement and any commercial agreements between the parties or their affiliates. Potential conflicts of interest may also arise out of any commercial arrangements that we or DTE Energy may enter into in the future. For more information, see the referenced Separation agreements within Note 1, "Separation, Description of the Business, and Basis of Presentation" to the Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

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

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ITEM 2. PROPERTIES

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ITEM 3. LEGAL PROCEEDINGS
Item 3. Legal Proceedings
For information on legal proceedings and matters related to DT Midstream, see Note 13, "Commitments and Contingencies" to the Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

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ITEM 4. MINE SAFETY DISCLOSURE
Item 4. Mine Safety Disclosures
Not applicable.
PART II

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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. At December 31, 2021, there were 96,734,010 shares of DT Midstream common stock issued and outstanding. These shares were held by a total of 42,903 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 consistent with cash flow growth and are targeting a payout ratio consistent with pure-play midstream companies. For information on DT Midstream's dividend restrictions, see Note 11, "Debt" to the Consolidated Financial Statements in 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 equity compensation plans that provide for the annual awarding of stock-based compensation have been approved by shareholders. For additional detail, see Note 14, "Stock-based Compensation and Defined Contribution Plans" to the Consolidated Financial Statements in Item 8 of this Form 10-K.
See the following table for information as of December 31, 2021:
Number of Securities to be Issued Upon Exercise of Outstanding Options, Warrants, and Rights Weighted-Average Exercise Price of Outstanding Options, Warrants, and Rights Number of Securities Remaining Available for Future Issuance Under Equity Compensation Plans
Equity compensation plans approved by shareholders 756,360 $ - 2,243,640
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, the date of the Separation, in our common stock, the Standard & Poor’s 500 (“S&P 500”) Index, and the Alerian Midstream Energy (“AMNA”) Index. We believe the AMNA Index is meaningful because it is an independent, objective view of the performance of similarly-sized midstream energy companies.
Quarterly Return Percentage
Quarter Ended
Company/Index September 30, 2021 December 31,
DT Midstream 11.51 17.18
S&P 500 Index 0.05 11.07
Alerian Midstream Energy Index (2.00) (2.37)
Indexed Returns
Base Period Quarter Ended
Company/Index July 1,
2021 September 30, 2021 December 31,
DT Midstream 100.00 111.51 117.18
S&P 500 Index 100.00 100.05 111.07
Alerian Midstream Energy Index 100.00 98.00 97.63

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ITEM 6. SELECTED FINANCIAL DATA

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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 interstate pipelines, intrastate pipelines, storage systems, lateral pipelines and related treatment plants and compression and surface facilities, and gathering systems and related treatment plants and compression and surface facilities. We also own joint venture interests in equity method investees which own and operate interstate pipelines, many of which have connectivity to our wholly owned assets.
Our core assets connect demand centers in the Midwestern U.S., Eastern Canada, Northeastern U.S. and Gulf Coast regions to production areas of the Haynesville and Marcellus/Utica dry natural gas formations in the Gulf Coast and Appalachian Basins, respectively.
The Separation
On October 27, 2020, DTE Energy announced that its Board of Directors had authorized the separation of the DTE midstream business, formerly known as DTE Gas Enterprises, LLC, and its consolidated subsidiaries ("DT Midstream", "we", "our", "us") from DTE Energy.
In June 2021, in order to facilitate the Separation and settle short-term borrowings due to DTE Energy, we issued long-term debt in the form of $2.1 billion senior notes and a $1.0 billion term loan facility. Using the debt proceeds, net of discount and issuance costs of $53 million, we made the following cash payments:
•Settled Short-term borrowings due to DTE Energy as of June 30, 2021 of $2,537 million;
•Settled Accounts Receivable due from DTE Energy and Accounts Payable due to DTE Energy as of June 30, 2021 for net cash of $9 million; and
•Provided a one-time special dividend to DTE Energy of $501 million.
On July 1, 2021, DTE Energy completed the Separation through the distribution of 96,732,466 shares of DT Midstream common stock to DTE Energy shareholders of record as of 5:00 p.m. ET on June 18, 2021 (the "record date"). DTE Energy shareholders received one share of DT Midstream common stock for every two shares of DTE Energy common stock held at the close of business on the record date, with certain shareholders receiving cash in lieu of fractional shares of DT Midstream common stock.
Following the Separation on July 1, 2021, we became an independent public company listed under the symbol "DTM" on the NYSE. DTE Energy no longer retains any ownership in our company.
See Note 1, "Separation, Description of the Business, and Basis of Presentation" to the Consolidated Financial Statements under Part II, Item 8 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 provide a detailed discussion of the operating performance and future outlook of our segments. Segment information, described below, 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, 2021 to the year ended December 31, 2020, or the year ended December 31, 2020 to the year ended December 31, 2019.
The following table summarizes our consolidated financial results:
Year Ended December 31,
2021 2020 2019
(millions, except per share amounts)
Operating revenues $ 840 $ 754 $ 504
Net Income Attributable to DT Midstream 307 312 204
Diluted Earnings per Common Share $ 3.16 $ 3.23 $ 2.11
Operating revenues increased in the years ended December 31, 2021 and December 31, 2020 in both our Pipeline and Gathering segments.
Year Ended December 31,
2021 2020 2019
(millions)
Net Income Attributable to DT Midstream by Segment
Pipeline $ 178 $ 155 $ 116
Gathering 129 157 88
Total $ 307 $ 312 $ 204
Net income attributable to DT Midstream decreased $5 million in the year ended December 31, 2021 due to lower earnings at our Gathering segment, partially offset by higher earnings at our Pipeline segment. Net income attributable to DT Midstream increased in the year ended December 31, 2020 primarily due to the first full year of operations of Blue Union and a partial year of operations for LEAP.
See Note 4, "Acquisitions" to the Consolidated Financial Statements under Part II, Item 8 of this Form 10-K, for discussion of the acquisition of Blue Union and LEAP in December 2019. See detailed explanations of segment performance in the sections below.
Pipeline
The Pipeline segment consists of our interstate pipelines, intrastate pipelines, storage systems, lateral pipelines and related treatment plants and compression and surface facilities. This segment also includes our equity method investments. Pipeline results and outlook are discussed below:
Year Ended December 31,
2021 2020 2019
(millions)
Operating revenues $ 307 $ 266 $ 234
Operation and maintenance 59 53 64
Depreciation and amortization 63 52 46
Taxes other than income 13 7 6
Asset (gains) losses and impairments, net - - 1
Operating Income 172 154 117
Interest expense 51 43 56
Interest income (1) (4) (11)
Earnings from equity method investees (126) (108) (98)
Other (income) and expense (3) (2) -
Income Tax Expense 62 58 38
Net Income 189 167 132
Less: Net Income Attributable to Noncontrolling Interests 11 12 16
Net Income Attributable to DT Midstream $ 178 $ 155 $ 116
Operating revenues increased $41 million in the year ended December 31, 2021 primarily due to higher LEAP revenues of $51 million as a result of a full year of LEAP operations in 2021. LEAP was placed into service in the third quarter 2020. This increase was partially offset by lower storage revenues at the Washington 10 Storage Complex of $8 million due to lower market rates. Operating revenues increased $32 million in the year ended December 31, 2020 primarily due to the LEAP partial year of operations and higher storage and Stonewall Gas Gathering revenues, partially offset by lower services provided to our equity method investees and lower Bluestone volumes.
Operation and maintenance expense increased $6 million in the year ended December 31, 2021 primarily due to higher Separation related transaction costs, higher public company costs, and higher LEAP operating costs after it was placed into service in the third quarter 2020, partially offset by cost savings initiatives. Operation and maintenance expense decreased $11 million in the year ended December 31, 2020 primarily due to lower reserves for uncollectible accounts and cost savings initiatives.
Depreciation and amortization expense increased $11 million in the year ended December 31, 2021 primarily due to higher depreciation related to LEAP of $12 million after it was placed into service in the third quarter 2020, partially offset by lower depreciation of storage assets. Depreciation and amortization expense increased $6 million in the year ended December 31, 2020 primarily due to depreciation related to LEAP after it was placed in service, partially offset by increased useful lives of certain storage assets.
Taxes other than income expense increased $6 million in the year ended December 31, 2021 primarily due to LEAP after it was placed into service in the third quarter 2020.
Interest expense increased $8 million in the year ended December 31, 2021 primarily due to higher capitalized interest during 2020 related to LEAP construction, partially offset by lower interest on borrowings from DTE Energy in 2021. Interest expense decreased $13 million in the year ended December 31, 2020 primarily due to lower interest on borrowings from DTE Energy in 2020.
Earnings from equity method investees increased $18 million in the year ended December 31, 2021 primarily due to higher operating earnings of $12 million from NEXUS, $3 million from the Vector Pipeline and $2 million from the Millennium Pipeline. Earnings from equity method investees increased $10 million in the year ended December 31, 2020 primarily due to higher NEXUS earnings, including the first full year of operations of the Generation Pipeline.
Income tax expense increased $4 million in the year ended December 31, 2021 primarily due to an increase in Income before income taxes. Income tax expense increased $20 million in the year ended December 31, 2020 primarily due to an increase in Income before income taxes.
Net income attributable to noncontrolling interests decreased $4 million in the year ended December 31, 2020 primarily due to the May 2019 purchase of an additional 30% ownership interest in Stonewall Gas Gathering.
Outlook
We believe our long-term agreements with customers and the location and connectivity of our pipeline assets soundly 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 future Haynesville system expansion (LEAP), completion of a new customer interconnection at Stonewall Gas Gathering, and additional growth related to our equity method investees.
Gathering
The Gathering segment consists of our gathering systems and related treatment plants and compression and surface facilities. Gathering results and outlook are discussed below:
Year Ended December 31,
2021 2020 2019
(millions)
Operating revenues $ 534 $ 489 $ 273
Operation and maintenance 173 123 80
Depreciation and amortization 103 100 47
Taxes other than income 11 8 2
Asset (gains) losses and impairments, net 17 (2) -
Operating Income 230 260 144
Interest expense 61 70 22
Interest income (3) (5) -
Other (income) and expense 1 (20) -
Income Tax Expense 42 58 34
Net Income Attributable to DT Midstream $ 129 $ 157 $ 88
Operating revenues increased $45 million in the year ended December 31, 2021 primarily due to higher gathering revenues on Blue Union of $33 million and the Appalachia Gathering System of $17 million, partially offset by lower volumes on Susquehanna Gathering System of $4 million. Operating revenues increased $216 million in the year ended December 31, 2020 primarily due to the first full year of Blue Union operations.
Operation and maintenance expense increased $50 million in the year ended December 31, 2021 primarily due to an increase of $30 million related to increased Blue Union operations, higher activity on the Appalachia Gathering System, higher Separation related transaction costs, and higher public company costs. Operation and maintenance expense increased $43 million in the year ended December 31, 2020 primarily due to the first full year of Blue Union operations, partially offset by no direct acquisition costs in 2020, cost savings initiatives and lower physical purchases of gas from Appalachia Gathering System customers.
Depreciation and amortization expense increased $53 million in the year ended December 31, 2020 primarily due to the first full year of Blue Union operations.
Taxes other than income expense increased $6 million in the year ended December 31, 2020 primarily due to placing the Blue Union assets in service.
Asset (gains) losses and impairments, net increased $19 million in the year ended December 31, 2021 primarily due to the 2021 loss on notes receivable for an investment in certain assets in the Utica shale region.
Interest expense decreased $9 million in the year ended December 31, 2021, primarily due to a lower interest rate on outstanding borrowings from DTE Energy. Interest expense increased $48 million in the year ended December 31, 2020 primarily due to the first full year of financing Blue Union.
Other (income) and expense increased $21 million in the year ended December 31, 2021 and decreased $20 million in the year ended December 31, 2020. The variances were primarily due to a post Blue Union acquisition income settlement of $20 million in 2020.
Income tax expense decreased $16 million in the year ended December 31, 2021 primarily due to a decrease in Income before income taxes. Income tax expense increased $24 million in the year ended December 31, 2020 primarily due to an increase in Income before income taxes.
Outlook
We believe our long-term agreements with producers and the quality of the natural gas reserves in the Marcellus/Utica and Haynesville shale regions soundly 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 future Haynesville system expansion (Blue Union) and expansion opportunities at the Appalachia Gathering System.
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 greenhouse gas reducing technologies as part of our goal of being leading environmental stewards in the midstream industry and have announced a net zero carbon emissions goal by 2050. Our strategy is premised on the following principles:
•disciplined capital deployment in assets supported by strong fundamentals;
•capitalize on asset integration and utilization opportunities;
•pursue economically attractive opportunities;
•grow cash flows supported by long-term firm revenue contracts; and
•provide exceptional service to our customers.
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. We anticipate total capital expenditures, inclusive of contributions to equity method investees, in 2022 of approximately $350 million to $400 million.
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 expenditures for environmental equipment, such as pollution control equipment, beyond what is currently planned, financing costs related to additional capital expenditures and the replacement costs of aging pipelines and other facilities.
For further discussion of environmental matters, see Note 13, "Commitments and Contingencies" to the Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.
CLIMATE CHANGE
We believe we have a responsibility to address climate change and have made consistent, effective environmental policies a priority. Our Board of Directors includes a committee focused on environmental, social and governance initiatives. Our strategy will focus on targeted growth from carbon-reducing technologies associated with our current platforms. We have announced our intent to employ carbon-reducing technologies as part of our goal of being leading environmental stewards in the midstream industry and have committed to a net zero carbon emissions goal by 2050. We expect to achieve a 30% reduction in the next decade.
During 2022, we will continue our exploration of early-stage development opportunities for energy transition advancements leveraging our existing assets, competencies and partnerships. These opportunities include the following:
•Our efforts to advance carbon capture projects across our geographic regions;
•Our "wellhead to water" expansion proposal of the Haynesville system which offers a carbon neutral pathway for supply to reach LNG markets;
•Our strategic joint development agreement with Mitsubishi Power Americas, Inc. to advance hydrogen development projects across the United States; and
•Our new partnership with Project Canary to monitor methane emissions.
Capital expenditure investments for these projects have been contemplated in our forecasted capital expenditures discussed in Capital Investments section.
DT Midstream plans to publish its inaugural Sustainability Report in the second quarter 2022. The information in our Sustainability Report is not incorporated by reference into this Form 10-K.
For discussion of various 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" of this Form 10-K. For discussion of recent climate change related laws and regulations, see Part I, Item 1. and 2. "Business and Properties - Regulatory Environment" of this Form 10-K.
COVID-19 PANDEMIC
During the first quarter 2020, the COVID-19 pandemic began impacting the states in which we operate. We are actively monitoring the impact of the COVID-19 pandemic on supply chains, markets, counterparties and customers and any related impacts on operating costs, customer demand and recoverability of assets that could materially impact our financial results. To date, impacts from the COVID-19 pandemic have not had a material effect on our financial results.
CAPITAL RESOURCES AND LIQUIDITY
Cash Requirements
Our principal liquidity requirements are to finance our operations, fund capital expenditures, satisfy our indebtedness obligations, and pay dividends, as deemed appropriate. We believe we will have sufficient internal and external capital resources to fund anticipated capital and operating requirements. We expect that cash from operations in 2022 will be approximately $605 million to $655 million.
Year Ended December 31,
2021 2020 2019
(millions)
Cash and Cash Equivalents at Beginning of Period $ 42 $ 46 $ 26
Net cash and cash equivalents from operating activities 572 597 390
Net cash and cash equivalents from (used for) investing activities 123 (714) (2,561)
Net cash and cash equivalents (used for) from financing activities (605) 113 2,191
Net Increase (Decrease) in Cash and Cash Equivalents 90 (4) 20
Cash and Cash Equivalents at End of Period $ 132 $ 42 $ 46
Operating Activities
Cash flows from our operations can be impacted in the short term by the volumes gathered or transported through our systems, changing commodity prices, seasonality, weather fluctuations, dividends from equity method investees and the financial condition of our customers. Our preference to enter into firm service contracts with firm reservation fees helps minimize our long-term exposure to commodity prices and its impact on the financial condition of our customers and provides us more stable operating performance and cash flows.
Net cash and cash equivalents from operating activities decreased $25 million in the year ended December 31, 2021 primarily due to net changes in working capital, and a decrease in other income driven by proceeds received from a nonrecurring settlement in 2020. These decreases were partially offset by an increase in operating income after adjustment for non-cash items including depreciation and amortization expense, amortization of operating lease right-of-use assets, and asset (gains) losses and impairments.
Net cash and cash equivalents from operating activities increased $207 million in the year ended December 31, 2020 primarily due to an increase in net income; adjusted for non-cash items, including depreciation and amortization expense and deferred income taxes; and a change in working capital items. The change in working capital items in 2020 compared to 2019 primarily related to other current and noncurrent assets and liabilities. These increases were partially offset by an increase in earnings from equity method investees and a decrease in dividends from equity method investees.
Investing Activities
Cash outflows associated with investing activities are primarily the result of plant and equipment expenditures, acquisitions, and contributions to equity method investees. Cash inflows from investing activities are generated from collection of notes receivable, distributions from equity method investees, and proceeds from asset sales.
Net cash and cash equivalents from investing activities increased $837 million in the year ended December 31, 2021 primarily due to the Separation related cash settlement of the Notes receivable due from DTE Energy, a decrease in cash used for plant and equipment expenditures, and a reduction in contributions to equity method investees.
Net cash and cash equivalents used for investing activities decreased $1.8 billion in the year ended December 31, 2020 primarily due to a decrease in acquisitions, net of cash acquired, which was driven by our acquisition of Blue Union and LEAP in 2019, and a reduction in contributions to equity method investees in 2020. These decreases were partially offset by an increase in cash used for plant and equipment expenditures and an increase in notes receivable due from DTE Energy.
Financing Activities
Prior to the Separation we relied on short-term borrowings and contributions from DTE Energy as a source of funding for capital requirements not satisfied by our operations. In June 2021, we issued senior notes in an aggregate principal amount of $2.1 billion and entered into a Credit Agreement providing for a $1.0 billion Term Loan Facility and a $750 million Revolving Credit Facility. See Note 11, "Debt" to the Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.
Net cash and cash equivalents used for financing activities increased $718 million in the year ended December 31, 2021 primarily due to the Separation related repayment of short-term borrowings due to DTE Energy and payment of a one-time special dividend to DTE Energy, a decrease in contributions from DTE Energy, and dividends paid on common stock in 2021. These increases were partially offset by net proceeds received from the issuance of long-term debt in June 2021 and decreased acquisition-related deferred payments.
Net cash and cash equivalents from financing activities decreased by $2.1 billion in the year ended December 31, 2020 primarily due to reduced contributions from DTE Energy, lower cash from short-term borrowings due to DTE Energy and the Blue Union and LEAP acquisition related deferred payment. The decrease was partially offset by the purchase of noncontrolling interests in 2019.
During 2021, DT Midstream paid cash dividends on common stock of $0.60 per share related to the quarter ended September 30, 2021. See Note 9, "Earnings per Share and Dividends" to the Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.
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 Separation on our debt and equity capitalization, described further below, we are not aware of any trends or other demands, commitments, events or uncertainties that will result in or that are reasonably likely to result in our liquidity increasing or decreasing materially.
Our working capital requirements will be primarily driven by changes in accounts receivable and accounts payable. We continue our efforts to identify opportunities to improve cash flows through working capital initiatives and obtaining additional long-term firm commitments from customers.
Historically, our sources of liquidity included cash generated from operations and, prior to the Separation, loans obtained through DTE Energy’s corporate-wide cash management program. After the Separation, our sources of liquidity include cash generated from operating activities and available borrowings under our Revolving Credit Facility. We began investing in money market cash equivalents in August 2021.
In June 2021, we issued long-term debt in the form of $2.1 billion Senior Notes and a $1.0 billion Term Loan Facility. Proceeds were used for the repayment of the Short-term borrowings due to DTE Energy as well as a one-time special dividend provided to DTE Energy. We also entered into a $750 million secured Revolving Credit Facility for general corporate purposes and letter of credit issuances to support our future operations and liquidity. The Credit Agreement covering the Term Loan Facility and Revolving Credit Facility includes financial covenants that DT Midstream must maintain. See Note 11, "Debt" to the Consolidated Financial Statements under Part II, Item 8 of this Form 10-K for additional discussion on the financial covenants.
As of December 31, 2021, we had $8 million of letters of credit outstanding and no borrowings outstanding under our Revolving Credit Facility. We have approximately $874 million of available liquidity as of December 31, 2021, consisting of cash and cash equivalents and amounts available 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 consistent with cash flow growth and are targeting a payout ratio consistent with pure-play midstream companies.
We believe we will have sufficient operating flexibility, cash resources and funding sources to maintain adequate amounts of liquidity and to meet future operating cash, capital expenditure and debt servicing needs. However, virtually all of our businesses are capital intensive, or require access to capital, and the inability to access adequate capital could adversely impact future earnings and cash flows.
See Note 1, "Separation, Description of the Business, and Basis of Presentation", Note 11, "Debt" and Note 13, "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. Our management believes 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.
Contractual Obligations
The following table details our contractual obligations due by year as of December 31, 2021:
2022 2023 2024 2025 2026 and Thereafter
(millions)
Long-Term Debt:
Term Loan Facility (a)
$ 10 $ 10 $ 10 $ 10 $ 955
Senior Notes (b)
- - - - 2,100
Letters of credit - - - - 8
Interest Expense (c)
114 114 114 114 459
Operating Leases 17 11 3 1 7
Other Purchase Obligations 4 4 2 1 1
Total Obligations $ 145 $ 139 $ 129 $ 126 $ 3,530
_____________________________
(a) Excludes $4 million of unamortized debt discount and $15 million of unamortized debt issuance costs
(b) Excludes $30 million of unamortized debt issuance costs
(c) Interest Expense calculation related to the Term Loan Facility assumes the variable rate of LIBOR is 0.50% plus 2.00%
OFF-BALANCE SHEET ARRANGEMENTS
We are party to off-balance sheet arrangements, which include our equity method investments. See the section entitled "Principles of Consolidation" in Note 1, "Separation, Description of the Business, and Basis of Presentation" 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 Pipeline Line of Credit and our guarantees, which are discussed further in Note 13, "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 the section titled "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, which could materially adversely affect our business, financial condition and results of operations" in Part I, Item 1A. "Risk Factors" of this Form 10-K.
CRITICAL ACCOUNTING ESTIMATES
The preparation of our Consolidated Financial Statements in conformity with GAAP requires that management applies accounting policies and makes estimates and assumptions that affect results of operations and the amounts of assets and liabilities reported in the Consolidated Financial Statements. Management believes that the areas described below require significant judgment in the application of the accounting policy or in making estimates and assumptions in matters that are inherently uncertain and that may change in subsequent periods. Additional discussion of our accounting policies can be found in the Notes to the Consolidated Financial Statements in Item 8 of this Form 10-K.
Goodwill
We have goodwill that resulted from business combinations. An impairment test for goodwill is performed annually as of October 1st, or whenever events or circumstances indicate that the value of goodwill may be impaired.
In performing the impairment test, we compare 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.
We estimate each reporting unit’s fair value using standard valuation techniques, including techniques which use estimates of projected future results and cash flows to be generated by the reporting unit. The fair values for the reporting units were calculated using a weighted combination of the income approach, which estimates fair value based on discounted cash flows, and the market approach, which estimates fair value based on market comparables within the Midstream industry.
The income approach includes a terminal value that utilizes an assumed long-term growth rate approach, which incorporates management’s assumptions regarding sustainable long-term growth of the reporting units. The income approach's cash flow valuations involve a number of estimates that require broad assumptions and significant judgment by management regarding future performance.
One of the most significant assumptions utilized in determining the fair value of reporting units under the market approach is implied market multiples for certain peer companies. Management selects comparable peers based on each peer’s primary business mix, operations, and market capitalization compared to the applicable reporting unit and calculates implied market multiples based on available projected earnings guidance and peer company market values as of the test date. Management also compared the fair value of the reporting units to DT Midstream's market capitalization including an estimated control premium.
In between annual impairment tests, we monitor our estimates and assumptions regarding estimated future cash flows, including the impact of movements in market indicators in future quarters, and will update the impairment analyses if a triggering event occurs. While we believe the assumptions are reasonable, 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.
We performed our annual impairment test as of October 1, 2021 and determined that the estimated fair value of each reporting unit exceeded its carrying value, and no impairment existed.
The results of the test and key estimates that were incorporated are as follows as of the October 1, 2021 valuation date:
Reporting Unit Goodwill Discount Rate Fair Value
Reduction % (a)
Valuation Methodology(b)
(millions)
Pipeline $ 53 6.3 % 53 % DCF and market multiples analysis
Gathering 420 7.5 % 23 % DCF and market multiples analysis
$ 473
__________________________________
(a) Percentage by which the fair value of equity of the reporting unit would need to decline to equal its carrying value, including goodwill. The fair value reduction percentage improved as compared to the October 1, 2020 annual impairment test, principally due to improvement in market multiples.
(b) Discounted cash flows (DCF) incorporated 2021-2025 projected cash flows plus a calculated terminal value. For each of the reporting units, DT Midstream capitalized the terminal year cash flows at the weighted average costs of capital (WACC) less an assumed long-term growth rate of 2.0%. Management applied equal weighting to the DCF and market multiples analysis to determine the fair value of the respective reporting units.
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 2021.
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 2021.
NEW ACCOUNTING PRONOUNCEMENTS
See Note 3, "New Accounting Pronouncements" to the Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Market Price Risk
Our business is dependent on the continued availability of natural gas production and reserves in our areas of operation. Low prices for natural gas, including those resulting from regional basis differentials, could adversely affect development of additional reserves and production that is accessible by our pipeline and storage assets. We manage our exposure through the use of short, medium, and long-term storage, gathering, and transportation contracts. Consequently, our existing operations and cash flows have limited direct exposure to commodity price risk.
Credit Risk
We are exposed to credit risk, which is the risk that we may incur a loss if a counterparty fails to perform 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 of our more recent long-term contracts associated with system expansions, we have entered into negotiated credit agreements that provide for enhanced forms of credit support if certain credit standards are not met.
We depend on key customers in the Haynesville shale formation in the Gulf Coast and in the Utica and Marcellus shale formation in the Northeast for a significant portion of our revenues. The loss of, or reduction in volumes from, any of these key customers could result in a decline in demand for our services and materially adversely affect our business, financial condition and results of operations.
We engage with customers that are non-investment grade, including two of our key customers, Southwestern and Antero. Southwestern announced that it closed on the merger with Indigo Minerals, LLC in the third quarter 2021. 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 counterparties. See Note 13, "Commitments and Contingencies" to the Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.
Interest Rate Risk
We are subject to interest rate risk in connection with the issuance of debt. Our exposure to interest rate risk arises primarily from changes in LIBOR. As of December 31, 2021, we had floating rate debt of $995 million and a floating rate debt-to-total debt ratio of 32% related to the variable rate term loan facility issued in June 2021. See Note 11, "Debt" to the Consolidated Financial Statements under Part II, Item 8 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 rates at December 31, 2021 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:
Assuming a
10% Increase in Rates Assuming a
10% Decrease in Rates Change in the Fair Value of
Activity As of December 31, 2021
(millions)
Interest rate risk $ (72) $ 74 Long-term debt

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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/Member's Equity
Notes to Consolidated Financial Statements
Note 1 - Separation, Description of the Business, and Basis of Presentation
Note 2 - Significant Accounting Policies
Note 3 - New Accounting Pronouncements
Note 4 - Acquisitions
Note 5 - Revenue
Note 6 - Goodwill
Note 7 - Property, Plant, and Equipment and Intangible Assets
Note 8 - Income Taxes
Note 9 - Earnings Per Share and Dividends
Note 10 - Fair Value
Note 11 - Debt
Note 12 - Leases
Note 13 - Commitments and Contingencies
Note 14 - Stock-Based Compensation and Defined Contribution Plans
Note 15 - Segment and Related Information
Note 16 - Related Party Transactions
Note 17 - Subsequent Event
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Stockholders of DT Midstream, Inc.
Opinion on the Financial Statements
We have audited the accompanying consolidated statements of financial position of DT Midstream, Inc. and its subsidiaries (the “Company”) as of December 31, 2021 and 2020, and the related consolidated statements of operations, of comprehensive income, of changes in stockholders' equity/member's equity and of cash flows for each of the three years in the period ended December 31, 2021, including the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2021 and 2020, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2021 in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s consolidated financial statements 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 of these consolidated financial statements 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.
Our audits 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. We believe that our audits provide a reasonable basis for our opinion.
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.
Accounting for Equity Method Investment in NEXUS Gas Transmission, LLC
As described in Note 1 to the consolidated financial statements, the Company has investments in non-consolidated affiliates that are accounted for using the equity method. Under the equity method, investments are recorded at historical cost as an asset and adjusted for capital contributions, dividends received, and the Company’s share of the investee’s earnings or losses, which is 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, 2021, the Company’s equity method investment balance in NEXUS Gas Transmission, LLC (“NEXUS”) was $1,348 million. For the year ended December 31, 2021, earnings from equity method investees were $126 million, of which earnings from NEXUS were a portion.
The principal considerations for our determination that performing procedures relating to the accounting for the equity method investment in NEXUS is a critical audit matter are a high degree of audit subjectivity and effort in performing procedures and evaluating the audit evidence obtained related to the recognition of the NEXUS investment balance and earnings.
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, among others, (i) testing the completeness and accuracy of the NEXUS investment balance and earnings by reconciling to investee financial information and testing investment activity, including contributions and distributions; (ii) performing inquiries with management and investee auditors and inspecting information to understand and evaluate management’s consideration of NEXUS accounting matters, including management’s assertion that there were no indicators of other-than-temporary impairment; and (iii) performing procedures to evaluate subsequent events impacting NEXUS.
/s/ PricewaterhouseCoopers LLP
Detroit, Michigan
February 25, 2022
We have served as the Company’s auditor since 2020.
DT Midstream, Inc.
Consolidated Statements of Operations
Year Ended December 31,
2021 2020 2019
(millions, except per share amounts)
Revenues
Operating revenues $ 840 $ 754 $ 504
Operating Expenses
Operation and maintenance 231 175 141
Depreciation and amortization 166 152 93
Taxes other than income 24 15 8
Asset (gains) losses and impairments, net 17 (2) 1
Operating Income 402 414 261
Other (Income) and Deductions
Interest expense 112 113 75
Interest income (4) (9) (8)
Earnings from equity method investees (126) (108) (98)
Other (income) and expense (2) (22) -
Income Before Income Taxes 422 440 292
Income Tax Expense 104 116 72
Net Income 318 324 220
Less: Net Income Attributable to Noncontrolling Interests 11 12 16
Net Income Attributable to DT Midstream $ 307 $ 312 $ 204
Basic Earnings per Common Share
Net Income Attributable to DT Midstream $ 3.17 $ 3.23 $ 2.11
Diluted Earnings per Common Share
Net Income Attributable to DT Midstream $ 3.16 $ 3.23 $ 2.11
Weighted Average Common Shares Outstanding
Basic 96.7 96.7 96.7
Diluted 96.9 96.7 96.7
See Notes to Consolidated Financial Statements
DT Midstream, Inc.
Consolidated Statements of Comprehensive Income
Year Ended December 31,
2021 2020 2019
(millions)
Net Income $ 318 $ 324 $ 220
Foreign currency translation and unrealized gain on derivatives, net of tax 1 2 -
Other Comprehensive Income 1 2 -
Comprehensive Income 319 326 220
Less: Comprehensive Income Attributable to Noncontrolling Interests 11 12 16
Comprehensive Income Attributable to DT Midstream $ 308 $ 314 $ 204
See Notes to Consolidated Financial Statements
DT Midstream, Inc.
Consolidated Statements of Financial Position
December 31,
2021 2020
(millions)
ASSETS
Current Assets
Cash and cash equivalents $ 132 $ 42
Accounts receivable (net of no allowance for expected credit loss for each period end)
Third party 169 123
DTE Energy - 3
Notes receivable
Due from DTE Energy - 263
Third party 5 11
Related party 4 -
Deferred property taxes 25 24
Other 25 17
360 483
Investments
Investments in equity method investees 1,691 1,691
Property
Property, plant, and equipment 4,109 3,981
Accumulated depreciation (619) (511)
3,490 3,470
Other Assets
Goodwill 473 473
Long-term notes receivable
Third party 2 15
Related party - 4
Operating lease right-of-use assets 36 45
Intangible assets, net 2,082 2,140
Other 32 21
2,625 2,698
Total Assets $ 8,166 $ 8,342
See Notes to Consolidated Financial Statements
DT Midstream, Inc.
Consolidated Statements of Financial Position
December 31,
2021 2020
(millions, except shares)
LIABILITIES AND EQUITY
Current Liabilities
Accounts payable
Third party $ 22 $ 29
DTE Energy - 10
Current portion of long-term debt 10 -
Operating lease liabilities 16 17
Short-term borrowings due to DTE Energy - 3,175
Dividends payable 58 -
Property taxes payable 24 24
Other 47 33
177 3,288
Long-Term Debt (net of current portion) 3,036 -
Other Liabilities
Deferred income taxes 856 743
Operating lease liabilities 21 28
Other 55 55
932 826
Total Liabilities 4,145 4,114
Commitments and Contingencies (Note 13)
Stockholders' Equity/Member's Equity
Preferred stock ($0.01 par value, 50,000,000 shares authorized and no shares issued or outstanding at December 31, 2021, and no shares authorized, issued or outstanding at December 31, 2020)
- -
Common stock ($0.01 par value, 550,000,000 shares authorized and 96,734,010 shares issued and outstanding at December 31, 2021, and no shares authorized, issued or outstanding at December 31, 2020)
1 -
Additional paid in capital 3,450 3,333
Retained earnings 431 751
Accumulated other comprehensive income (loss) (10) (11)
Total DT Midstream Equity 3,872 4,073
Noncontrolling interests 149 155
Total Equity 4,021 4,228
Total Liabilities and Equity $ 8,166 $ 8,342
See Notes to Consolidated Financial Statements
DT Midstream, Inc.
Consolidated Statements of Cash Flows
Year Ended December 31,
2021 2020 2019
(millions)
Operating Activities
Net Income $ 318 $ 324 $ 220
Adjustments to reconcile Net Income to Net cash from operating activities:
Depreciation and amortization 166 152 93
Amortization of operating lease right-of-use assets 18 17 17
Deferred income taxes 104 111 68
Earnings from equity method investees (126) (108) (98)
Dividends from equity method investees 129 134 140
Asset (gains) losses and impairments, net 17 (2) 1
Changes in assets and liabilities:
Accounts receivable, net (43) (16) (20)
Accounts payable - Third party 4 (2) (3)
Accounts payable - Related party (10) 1 3
Other current and noncurrent assets and liabilities (5) (14) (31)
Net cash and cash equivalents from operating activities 572 597 390
Investing Activities
Plant and equipment expenditures (140) (518) (211)
Acquisitions, net of cash acquired - - (2,296)
Distributions from equity method investees 9 5 6
Contributions to equity method investees (11) (35) (145)
Notes receivable (due from) repaid by DTE Energy 263 (146) 91
Notes receivable - Third party and Related party - (20) (6)
Other investing activities 2 - -
Net cash and cash equivalents from (used for) investing activities 123 (714) (2,561)
Financing Activities
Issuance of long-term debt, net of discount and issuance costs 3,047 - -
Repayment of long-term debt (5) - -
Short-term borrowings (repayment of borrowings) from DTE Energy (3,175) 253 1,235
Borrowings under the Revolving Credit Facility 25 - -
Repayment of borrowings under the Revolving Credit Facility (25) - -
Payment of Revolving Credit Facility issuance fees (7) - -
Acquisition-related deferred payment - (380) -
Distributions to noncontrolling interests (16) (12) (22)
Purchase of noncontrolling interests - - (296)
Dividends paid on common stock (58) - -
Dividend to DTE Energy (501) - -
Contributions from DTE Energy 110 252 1,274
Net cash and cash equivalents (used for) from financing activities (605) 113 2,191
Net Increase (Decrease) in Cash and Cash Equivalents 90 (4) 20
Cash and Cash Equivalents at Beginning of Period 42 46 26
Cash and Cash Equivalents at End of Period $ 132 $ 42 $ 46
Supplemental disclosure of cash information
Cash paid for:
Interest, net of interest capitalized 103 113 75
Income taxes 3 3 8
Supplemental disclosure of non-cash investing and financing activities
Plant and equipment expenditures in accounts payable and other accruals $ 10 $ 21 $ 29
See Notes to Consolidated Financial Statements
DT Midstream, Inc.
Consolidated Statements of Changes in Stockholders' Equity/Member's Equity
Additional Paid In Capital Retained Earnings Accumulated Other Comprehensive Income (Loss) Noncontrolling Interests
Common Stock
Shares Amount Total
(millions, except shares)
Balance, December 31, 2018 - $ - $ 1,807 $ 361 $ (13) $ 457 $ 2,612
Net Income - - - 204 - 16 220
Contributions from DTE Energy - - 1,150 - - - 1,150
Distributions to noncontrolling interests - - - - - (22) (22)
Purchase of noncontrolling interests - - - - - (296) (296)
Taxes and other adjustments - - 124 (64) - - 60
Balance, December 31, 2019 - $ - $ 3,081 $ 501 $ (13) $ 155 $ 3,724
Net Income - - - 312 - 12 324
Distributions to noncontrolling interests - - - - - (12) (12)
Taxes and other adjustments - - 252 (62) - - 190
Other comprehensive income, net of tax - - - - 2 - 2
Balance, December 31, 2020 - $ - $ 3,333 $ 751 $ (11) $ 155 $ 4,228
Net Income - - - 307 - 11 318
Reorganization to C Corporation(a)
1,000 - - - - - -
Issuance of common shares to DTE Energy(b)
96,731,466 1 - - - - 1
Dividend to DTE Energy - - - (501) - - (501)
Dividends declared on common stock ($1.20 per common share)
- - - (116) - - (116)
Distributions to noncontrolling interests - - - - - (16) (16)
Stock-based compensation 1,544 - 8 - - - 8
Taxes and other adjustments - - 109 (10) - (1) 98
Other comprehensive income, net of tax - - - - 1 - 1
Balance, December 31, 2021 96,734,010 $ 1 $ 3,450 $ 431 $ (10) $ 149 $ 4,021
_____________________________________
(a)Issuance of common shares at $0.01 par value upon conversion to C Corporation from a single member LLC.
(b)Issuance of common shares to DTE Energy in anticipation of the Separation.
See Notes to Consolidated Financial Statements
DT Midstream, Inc.
Notes to Consolidated Financial Statements
NOTE 1 - SEPARATION, DESCRIPTION OF THE BUSINESS, AND BASIS OF PRESENTATION
The Separation
On October 27, 2020, DTE Energy announced that its Board of Directors had authorized the separation of the DTE midstream business, formerly known as DTE Gas Enterprises, LLC, and its consolidated subsidiaries ("DT Midstream") from DTE Energy.
In connection with the Separation, on January 13, 2021, DTE Gas Enterprises, LLC converted into a Delaware corporation pursuant to a statutory conversion and changed its name to DT Midstream, Inc. At the conversion, DT Midstream issued 1,000 shares of common stock at $0.01 par value to its parent, a subsidiary of DTE Energy. As DT Midstream was a single member LLC as of December 31, 2020 and a corporation with stockholders' equity as of December 31, 2021, Consolidated Statements of Changes in Stockholders' Equity/Member's Equity are presented as of December 31, 2021 and 2020. In June 2021, the DT Midstream Board of Directors authorized the issuance of an additional 96,731,466 common shares to DTE Energy in anticipation of the Separation, for a total of 96,732,466 common shares issued and outstanding. DT Midstream is authorized to issue 50,000,000 shares of preferred stock at $0.01 par value. No preferred stock was issued or outstanding at December 31, 2021.
In June 2021, in order to facilitate the Separation and settle short-term borrowings due to DTE Energy, DT Midstream issued long-term debt in the form of $2.1 billion senior notes and a $1.0 billion term loan facility. Using the debt proceeds, net of discount and issuance costs of $53 million, DT Midstream made the following cash payments:
•Settled Short-term borrowings due to DTE Energy as of June 30, 2021 of $2,537 million;
•Settled Accounts receivable due from DTE Energy and Accounts payable due to DTE Energy as of June 30, 2021 for net cash of $9 million; and
•Provided a one-time special dividend to DTE Energy of $501 million.
On July 1, 2021, DTE Energy completed the Separation through the distribution of 96,732,466 shares of DT Midstream common stock to DTE Energy shareholders of record as of 5:00 p.m. ET on June 18, 2021 (the "record date"). DTE Energy shareholders received one share of DT Midstream common stock for every two shares of DTE Energy common stock held at the close of business on the record date, with certain shareholders receiving cash in lieu of fractional shares of DT Midstream common stock.
Following the Separation on July 1, 2021, DT Midstream became an independent public company listed under the symbol "DTM" on the NYSE. DTE Energy no longer retains any ownership in DT Midstream.
In order to govern the ongoing relationships between DT Midstream and DTE Energy after the Separation and to facilitate an orderly transition, the parties entered into a series of agreements including the following:
•Separation and Distribution Agreement - sets forth the principal actions to be taken in connection with the Separation, including the transfer of assets and assumption of liabilities, among others, and sets forth other agreements governing aspects of the relationship between DTE Energy and DT Midstream.
•Transition Services Agreement ("TSA") - allows for DTE Energy to provide DT Midstream with specified services for a limited time and no longer than 24 months following the Separation, including support for accounting, tax, legal, human resources, informational technology, and various other administrative and operational services. Prior to the termination of the TSA, DT Midstream will establish standalone functions to provide services received from DTE Energy or will obtain such services from unaffiliated third parties.
•Tax Matters Agreement - governs the respective rights, responsibilities and obligations of DTE Energy and DT Midstream after the Separation with respect to all tax matters.
•Employee Matters Agreement - addresses certain employment, compensation and benefits matters, including the allocation and treatment of certain assets and liabilities relating to DT Midstream employees.
DT Midstream, Inc.
Notes to Consolidated Financial Statements
In addition, DT Midstream has various commercial agreements with DTE Energy and its subsidiaries. These agreements include certain pipeline, gathering, and storage services and operating and maintenance agreements.
Operation and maintenance for the years ended December 31, 2021 and 2020 include approximately $20 million and $6 million, respectively, of Separation related transaction costs for legal, accounting, auditing and other professional services.
Description of the Business
DT Midstream is an owner, operator, and developer of an integrated portfolio of natural gas midstream assets. The Company provides multiple, integrated natural gas services to customers through two primary segments: (i) Pipeline, which includes interstate pipelines, intrastate pipelines, storage systems, lateral pipelines and related treatment plants and compression and surface facilities, and (ii) Gathering, which includes gathering systems and related treatment plants and compression and surface facilities. DT Midstream's pipeline segment also includes interests in equity method investees which own and operate interstate pipelines, many of which have connectivity to DT Midstream’s assets.
DT Midstream’s core assets connect demand centers in the Midwestern U.S., Eastern Canada, Northeastern U.S. and Gulf Coast regions to production areas of the Haynesville and Marcellus/Utica dry natural gas formations in the Gulf Coast and Appalachian Basins, respectively.
Basis of Presentation
The Consolidated Financial Statements and Notes to Consolidated Financial Statements as of and for periods subsequent to July 1, 2021, the date of the Separation, reflect the consolidated financial position, results of operations and cash flows for DT Midstream as an independent company. Prior to the Separation, DT Midstream operated as a consolidated entity of DTE Energy and not as a standalone company. For the periods prior to the Separation, the Consolidated Financial Statements and Notes to Consolidated Financial Statements were prepared on a carve-out basis using the consolidated financial statements and accounting records of DTE Energy. The carve-out basis financial statements represent the historical financial position, results of operations, and cash flows of DT Midstream as they were historically managed in accordance with GAAP and reflect significant assumptions and allocations. The carve-out financial statements may not include all expenses that would have been incurred had DT Midstream existed as a standalone entity. Certain prior-period amounts have been reclassified to conform to current-year presentation.
GAAP requires 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 DT Midstream’s estimates. DT Midstream believes the assumptions underlying these financial statements are reasonable.
Cost Allocations
Prior to the Separation DT Midstream received monthly allocations of general corporate expenses of DTE Energy which were classified within the appropriate Consolidated Statements of Operations line item. Corporate allocations from DTE Energy included expenses related to labor and benefits, professional fees, shared assets and other expenses related to DTE Energy's corporate functions that provided support to DT Midstream. The allocation methodology utilized was consistent with the legacy allocation process, which allocates costs based on cost drivers. Cost drivers represent units of work that best reflect the consumption of resources within a specific corporate support function for a business group, and include time studies, activity-based metrics, headcount, and other allocation methods. DT Midstream believes this combination of cost drivers appropriately allocated costs attributable to its business. Effective July 1, 2021, with the completion of the Separation, DT Midstream no longer receives corporate allocations from DTE Energy. DTE Energy support services are provided through the TSA.
Corporate allocation amounts from DTE Energy are as follows:
Year Ended December 31,
2021 2020 2019
(millions)
Operation and maintenance $ 32 $ 29 $ 23
Other expense - 1 1
Total DTE Energy corporate allocations $ 32 $ 30 $ 24
DT Midstream, Inc.
Notes to Consolidated Financial Statements
Cash Management
DT Midstream's sources of liquidity include cash generated from operations and available borrowings under our Revolving Credit Facility. DT Midstream began investing in money market cash equivalents in August 2021.
Prior to the Separation, DT Midstream’s sources of liquidity included cash generated from operations and loans obtained through DTE Energy’s corporate-wide cash management program ("cash management program"), including a working capital loan agreement. Cash was managed centrally, with certain net earnings reinvested in, and working capital requirements met from, existing liquid funds. As a subsidiary of DTE Energy, DT Midstream’s bank accounts were set up as zero balance accounts held by DTE Energy. Cash was swept in and out of the bank’s accounts daily in order to achieve a zero balance at the close of each workday. Net DT Midstream cash inflows or outflows were settled daily against the notes receivable or borrowings, as applicable, with DTE Energy.
Cash and cash equivalents held by DTE Energy at the corporate level were not attributed to DT Midstream for any of the periods presented. Only cash amounts specifically attributable to DT Midstream are reflected in the accompanying Consolidated Statements of Financial Position. For the periods presented, these amounts included cash held by consolidated entities with noncontrolling interests, which were not managed as part of the cash management program.
Notes receivable and borrowings with DTE Energy arising from the working capital loan agreement have been presented as assets and liabilities, respectively, on the Consolidated Statements of Financial Position. The classification of these items as current or noncurrent is dependent on the due date of the asset or obligation.
DT Midstream had $3,175 million in Short-term borrowings due to DTE Energy and $263 million in Notes receivable due from DTE Energy at December 31, 2020. In the second quarter 2021, DTE Energy and DT Midstream amended the working capital loan agreements to combine all outstanding notes receivable and borrowings with DTE Energy into a single agreement with a net Short-term borrowing due to DTE Energy. Upon issuance of the senior notes and Term Loan Facility in June 2021, DT Midstream repaid the Short-term borrowing due to DTE Energy. See Note 11, "Debt" to the Consolidated Financial Statements for further information regarding the external debt issuances. Effective July 1, 2021, DT Midstream no longer participates in the cash management program and the working capital loan agreement was terminated.
Principles of Consolidation
DT Midstream consolidates all majority-owned subsidiaries and investments in entities in which we have a controlling influence. Non-majority owned investments are accounted for using the equity method of accounting when DT Midstream is able to significantly influence the operating policies of the investee. When DT Midstream does 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. DT Midstream eliminates all intercompany balances and transactions.
DT Midstream evaluates whether an entity is a VIE whenever reconsideration events occur. DT Midstream consolidates VIEs for which we are the primary beneficiary. If DT Midstream is not the primary beneficiary and an ownership interest is held, the VIE is accounted for under the equity method of accounting. When assessing the determination of the primary beneficiary, DT Midstream considers 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. DT Midstream performs ongoing reassessments of all VIEs to determine if the primary beneficiary status has changed.
The maximum risk exposure for consolidated VIEs is reflected on DT Midstream’s Consolidated Statements of Financial Position. For non-consolidated VIEs, the maximum risk exposure of DT Midstream is generally limited to its investment, notes receivable, future funding commitments, and amounts which it has guaranteed.
DT Midstream owns an 85% interest in the Stonewall Gas Gathering VIE, which owns and operates midstream natural gas assets. Stonewall Gas Gathering has contracts in which certain construction risk was designed to pass-through to customers, with DT Midstream retaining operational and customer default risk. DT Midstream is the primary beneficiary of Stonewall Gas Gathering, therefore Stonewall Gas Gathering is consolidated. DT Midstream owns a 50% interest in the South Romeo VIE and is the primary beneficiary, therefore South Romeo is consolidated.
DT Midstream, Inc.
Notes to Consolidated Financial Statements
The following table summarizes the major items in the Consolidated Statements of Financial Position for consolidated VIEs as of December 31, 2021 and 2020. All assets and liabilities of a consolidated VIE are presented where 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. VIEs, in which DT Midstream holds a majority voting interest and is the primary beneficiary, that meet the definition of a business and whose assets can be used for purposes other than the settlement of the VIE's obligations have been excluded from the table below.
Amounts for consolidated VIEs are as follows:
December 31,
2021 2020
(millions)
ASSETS (a)
Cash $ 23 $ 34
Accounts receivable - third party 8 8
Other current assets 3 2
Intangible assets, net 513 527
Property, plant and equipment, net 408 411
Goodwill 25 25
$ 980 $ 1,007
LIABILITIES (a)
Accounts payable and other current liabilities $ 5 $ 2
Other noncurrent liabilities 4 5
$ 9 $ 7
_____________________________________
(a)Amounts shown are 100% of the consolidated VIEs' assets and liabilities.
Prior to the third quarter 2021, NEXUS was classified as a VIE. NEXUS was not consolidated as DT Midstream was not the primary beneficiary, and DT Midstream accounted for its ownership interest in NEXUS under the equity method of accounting. In the third quarter 2021, it was determined NEXUS is capable of financing its own operations without additional subordinated financial support. As a result, it was concluded that NEXUS was no longer a VIE due to sufficient equity at risk to finance its activities. DT Midstream will continue to account for its ownership interest in NEXUS under the equity method of accounting.
DT Midstream has a variable interest in an investment in certain assets in the Utica shale region that is accounted for as a Note receivable - Third party. DT Midstream does not have an ownership interest in the entity and is not the primary beneficiary. The maximum risk exposure is limited to amounts DT Midstream has funded, which are accounted for as a note receivable, or committed to fund for joint development activities. See Note 2, "Significant Accounting Policies - Financing Receivables" to the Consolidated Financial Statements for additional discussion.
Amounts for non-consolidated VIEs are as follows:
December 31,
2021 2020
(millions)
Investments in equity method investees $ - $ 1,349
Notes receivable - current 5 11
Notes receivable - noncurrent 2 15
Future funding commitments $ - $ 21
Related Parties
Transactions between DT Midstream and DTE Energy prior to the Separation, as well as all transactions between DT Midstream and its equity method investees, have been presented as related party transactions in the accompanying Consolidated Financial Statements. See Note 16, "Related Party Transactions" to the Consolidated Financial Statements.
DT Midstream, Inc.
Notes to Consolidated Financial Statements
Equity Method Investments
Investments in non-consolidated affiliates that are not controlled by DT Midstream, but over which we have significant influence, are accounted for using the equity method of accounting. Under the equity method, 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 on the Consolidated Statements of Operations. DT Midstream's equity method investments are periodically evaluated for certain factors that may be indicative of other-than-temporary impairment. As of December 31, 2021 and 2020, DT Midstream’s share of the underlying equity in the net assets of the investees exceeded the carrying amounts of investments in equity method investees by $32 million and $13 million, respectively. The difference will be amortized over the life of the underlying assets. As of December 31, 2021 and December 31, 2020, DT Midstream's consolidated retained earnings balance includes undistributed earnings from equity method investments of $84 million and $94 million, respectively.
Equity method investees are described below:
Investments As of % Owned As of
December 31, December 31,
Equity Method Investee 2021 2020 2021 2020
(millions)
NEXUS $ 1,348 $ 1,349 50% 50%
Vector Pipeline 136 134 40% 40%
Millennium Pipeline 207 208 26% 26%
Total investments in equity method investees $ 1,691 $ 1,691
For further information by segment, see Note 15, "Segment and Related Information" to the Consolidated Financial Statements.
The following table presents summarized financial information of non-consolidated equity method investees in which DT Midstream owns 50% or less. The amounts included below represent 100% of the results of continuing operations of such entities.
Summarized balance sheet data is as follows:
December 31,
2021 2020
(millions)
Current assets $ 201 $ 213
Non-current assets 4,300 4,394
Current liabilities 225 201
Non-current liabilities $ 521 $ 603
Summarized income statement data is as follows:
Year Ended December 31,
2021 2020 2019
(millions)
Operating revenues $ 738 $ 708 $ 677
Operating expenses 371 381 369
Net Income $ 333 $ 294 $ 276
Property taxes
In February 2022, an equity method investee signed an agreement to settle a property tax appeal (subject to customary approvals). DT Midstream's portion of the revised estimate has been recorded in earnings from equity method investees of the Consolidated Statement of Operations for the year ended December 31, 2021. The agreement did not result in a material adjustment.
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, notes receivable, and unbilled revenue. DT Midstream's financing receivables are stated at net realizable value.
DT Midstream regularly monitors the credit quality of its financing receivables by reviewing credit quality indicators and monitoring for triggering events, such as a credit rating downgrade or bankruptcy. Credit quality indicators include, but are not limited to, credit agency ratings where available, collection history, collateral, counterparty financial statements and other internal metrics. Utilizing such data, DT Midstream has determined three internal grades of credit quality. Internal grade 1 includes financing receivables for counterparties where credit rating agencies have rated the counterparty as investment grade. If credit ratings are not available, DT Midstream utilizes other credit quality indicators to determine the risk level associated with the financing receivable. Internal grade 1 may include financing receivables for counterparties for which credit rating agencies have rated the counterparty as below investment grade if, due to favorable information on other credit quality indicators, DT Midstream has determined the risk level to be similar to that of an investment grade counterparty. Internal grade 2 includes financing receivables for counterparties with limited credit information and those with a higher risk profile based upon credit quality indicators. Internal grade 3 reflects financing receivables for which the counterparties have the greatest level of risk, including those in bankruptcy status.
The following table presents DT Midstream's third party and related party notes receivable by year of origination, classified by internal grade of credit quality. The related credit quality indicators and risk ratings utilized to develop the internal grades have been updated through December 31, 2021.
Year of Origination
2021 2020 2019 and prior Total
(millions)
Notes receivable
Internal grade 1 (a)
$ - $ - $ 4 $ 4
Internal grade 2 - - - -
Internal grade 3 - - 7 7
Total Notes receivable - Third party and Related party $ - $ - $ 11 $ 11
__________________________________
(a)Related party
Notes receivable are typically considered delinquent (past due) when payment is not received for periods ranging from 60 to 120 days. DT Midstream ceases accruing interest income (nonaccrual status) and may either write off or establish an allowance for credit loss for the note receivable when it is expected that all principal or interest amounts due will not be collected in accordance with the note's contractual terms. In determining an allowance for credit losses for or the write off of notes receivable, DT Midstream considers the historical payment experience and other factors that are expected to have a specific impact on collection from the counterparty, including existing and future economic conditions.
Cash payments received 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.
DT Midstream, Inc.
Notes to Consolidated Financial Statements
DT Midstream has an investment in certain assets in the Utica shale region which is accounted for as a Note receivable - Third party. In the second quarter 2021, we assessed the note receivable for expected loss due to lower than expected actual volumes and proceeds received, and reduced forecasted volumes based on data made available in the second quarter 2021. As a result of the discounted cash flow analysis, in the second quarter 2021, we recorded a $19 million loss on the note receivable to Asset (gains) losses and impairments, net on the Consolidated Statement of Operations. Additionally, DT Midstream ceased accruing interest on the note receivable balance and reclassified the note to an Internal grade 3 receivable. Subsequently, as cash payments were received, a portion was recognized as interest income. It is possible that significant decreases in forecasted production volumes or commodity prices could result in additional losses on the Note receivable - Third party. There are no notes receivable on nonaccrual status as of December 31, 2021.
There are no past due financing receivables for DT Midstream as of December 31, 2021.
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 specific circumstances of the associated receivable. Uncollectible expense (recovery) was zero, $(2) million and $5 million for the years ended December 31, 2021, 2020 and 2019, respectively.
The following table presents a roll-forward of the activity for DT Midstream's financing receivables' (accounts receivable and notes receivable) allowance for expected credit loss. The balance is shown as a deduction from the respective financing receivable's balance in the Consolidated Statements of Financial Position.
2021 2020 2019
Allowance for expected credit loss- Accounts Receivable (millions)
Balance at January 1 $ - $ 8 $ -
Additions: Charged to costs, expenses, and other accounts - - 8
Deductions: Current period provision and write-offs charged against allowance - (8) -
Balance at December 31 $ - $ - $ 8
Allowance for expected credit loss- Notes Receivable
Balance at January 1 $ - $ - $ -
Additions: Charged to costs, expenses, and other accounts 19 - -
Deductions: Current period provision and write-offs charged against allowance (19) - -
Balance at December 31 $ - $ - $ -
DT Midstream has been monitoring the impacts from the COVID-19 pandemic on our customers and various counterparties. As of December 31, 2021, the impact on collectability of DT Midstream’s receivables has not been material.
Property, Plant, and Equipment
Property is stated at cost and includes construction-related labor, materials, and overhead. Expenditures for maintenance and repairs are charged to expense when incurred. DT Midstream's property, plant and equipment is depreciated over its estimated useful life using the straight-line method. See Note 7, "Property, Plant, and Equipment and Intangible Assets" to the Consolidated Financial Statements.
Intangible Assets
Intangible assets with finite useful lives are amortized generally on a straight-line basis over the periods benefited. See Note 7, "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.
DT Midstream, Inc.
Notes to Consolidated Financial Statements
Operation and maintenance
Operation and maintenance is primarily comprised of costs for labor, outside services, materials, compression, purchased natural gas, operating lease costs, and other operating and maintenance costs. Corporate allocations from DTE Energy, including Separation related transaction costs for legal, accounting, auditing and other professional services DTE Energy incurred for the benefit of DT Midstream, are also included in Operation and maintenance.
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 Income - Blue Union/LEAP Settlement
In the third quarter 2020, DT Midstream reached a post-acquisition settlement with M5 Louisiana Holdings, LLC. The settlement did not relate to the Blue Union/LEAP acquisition price. The proceeds of $20 million are included in Other (income) and expense on the Consolidated Statement of Operations for the year ended December 31, 2020.
Other Accounting Policies
Footnote Title
Note 5 Revenue
Note 8 Income Taxes
Note 10 Fair Value
Note 12 Leases
NOTE 3 - NEW ACCOUNTING PRONOUNCEMENTS
Recently Adopted Pronouncements
In July 2021, the FASB issued ASU No. 2021-05, Leases (Topic 842): Lessors - Certain Leases with Variable Lease Payments. The amendments in this update modify lease classification requirements for lessors, providing that lease contracts with variable lease payments that do not depend on a reference index or a rate should be classified as operating leases if they would have been classified as a sales-type or direct financing lease and resulted in the recognition of a selling loss at lease commencement. The ASU is effective for DT Midstream for fiscal years beginning after December 15, 2021, and interim periods therein. DT Midstream adopted this standard which did not have a material impact on the Consolidated Financial Statements.
Recently Issued Pronouncements
In March 2020, the FASB issued ASU No. 2020-04, Reference Rate Reform (Topic 848) - Facilitation of the Effects of Reference Rate Reform on Financial Reporting, as amended. Subsequently, in January 2021, the FASB issued ASU No. 2021-01, Reference Rate Reform (Topic 848) - Scope, as amended. The amendments in these updates provide optional expedients and exceptions for applying GAAP to contract modifications and hedging relationships, subject to meeting certain criteria, that reference LIBOR or another reference rate expected to be discontinued. The guidance can be applied prospectively from any date beginning March 12, 2020 through December 31, 2022. The optional relief is temporary and cannot be applied to contract modifications and hedging relationships entered into or evaluated after December 31, 2022. DT Midstream presently has various contracts that reference LIBOR and is assessing how this standard may be applied to specific contract modifications.
DT Midstream, Inc.
Notes to Consolidated Financial Statements
In October 2021, the FASB issued ASU 2021-08, Accounting for Contract Assets and Contract Liabilities from Contracts with Customers. The amendments in this update require that an entity (acquirer) recognize and measure contract assets and contract liabilities acquired in a business combination in accordance with Topic 606. At the acquisition date, an acquirer should account for the related revenue contracts as if it had originated the contracts. This ASU is effective for DT Midstream for fiscal years beginning after December 15, 2022, including interim periods within those fiscal years. The amendments should be applied prospectively to business combinations occurring on or after the effective date of the amendments. Early adoption is permitted. DT Midstream will adopt the update for business combinations occurring after the effective date.
NOTE 4 - ACQUISITIONS
Generation Pipeline Acquisition
Effective September 30, 2019, NEXUS closed on the purchase of Generation Pipeline, a pipeline system regulated by the Public Utilities Commission of Ohio. The 25-mile pipeline system supplies gas to industrial customers in the Toledo, OH area, has existing interconnects with ANR Pipeline Company and Panhandle Eastern Pipeline Company, and is located four miles from NEXUS. Total consideration paid for the acquired entity was approximately $163 million, of which DT Midstream's portion was 50%. DT Midstream accounts for its ownership interest in NEXUS under the equity method, which now includes equity in earnings related to Generation Pipeline.
Blue Union and LEAP Acquisition
On December 4, 2019, DT Midstream closed on the purchase of midstream natural gas assets in support of its strategy to continue to grow and earn competitive returns for DT Midstream shareholders. DT Midstream purchased 100% of M5 Louisiana Gathering, LLC and its wholly owned subsidiaries from Momentum Midstream and Indigo Natural Resources. The acquisition includes Blue Union and LEAP assets located in the Haynesville shale formation of Louisiana which provide natural gas gathering and other midstream services to producers primarily in Louisiana.
The fair value of the consideration provided for the entities acquired was $2.74 billion and includes $2.36 billion paid in cash and an estimated $380 million of contingent consideration to be paid upon the completion of the LEAP gathering pipeline. A liability for the contingent consideration payment was recorded upon acquisition and adjusted each period for accretion. Accretion expense of $5 million and $1 million was recorded for the years ended December 31, 2020 and 2019, respectively. In July 2020, the LEAP gathering pipeline achieved the final milestone of its construction, and consideration of $385 million was paid on July 27, 2020.
The acquisition was financed by DTE Energy. The financing by DTE Energy was attributed to DT Midstream and is included in the Short-term borrowings due to DTE Energy on the Consolidated Statement of Financial Position as of December 31, 2020. Short-term borrowings due to DTE Energy were repaid in connection with the Separation as described in Note 1, "Separation, Description of the Business, and Basis of Presentation" to the Consolidation Financial Statements.
The acquisition was accounted for using the acquisition method of accounting for business combinations. The excess purchase price over the fair value of net assets acquired 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 Blue Union and LEAP acquisition. The acquisition provides DT Midstream with a platform for midstream growth and access to further investment opportunities in the Haynesville Basin. The goodwill is being deducted for income tax purposes. December 3, 2020 marked the expiration of the one-year period from the acquisition to revise the fair value of assets acquired and liabilities assumed. As a result of purchase accounting adjustments through December 3, 2020, approximately $2 million of additional goodwill was recognized. The purchase price is no longer subject to resolution of any indemnification claims and all cash consideration held in escrow has been released.
DT Midstream, Inc.
Notes to Consolidated Financial Statements
The final allocation of the purchase price is based on estimated fair values of the Blue Union and LEAP assets acquired and liabilities assumed at the date of acquisition, December 4, 2019. The components of the purchase price allocation, inclusive of purchase accounting adjustments, are as follows:
(millions)
Assets
Cash $ 62
Accounts receivable 31
Property, plant, and equipment, net 1,034
Goodwill 174
Customer relationship intangibles 1,473
Other current assets 1
$ 2,775
Liabilities
Accounts payable $ 26
Acquisition related deferred payment 380
Other current liabilities 3
Asset retirement obligations 9
$ 418
Total cash consideration $ 2,357
The intangible assets recorded as a result of the acquisition pertain to existing customer relationships, which were valued at approximately $1.47 billion as of the acquisition date. The fair value of the intangible assets acquired was estimated by applying the income approach. The income approach is based upon discounted projected future cash flows attributable to the existing contracts and agreements. The fair value measurement is based on significant unobservable inputs, including management estimates and assumptions, and thus represents a 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 entities. The intangible assets are amortized on a straight-line basis over a period of 40 years, which is based on the number of years the assets are expected to economically contribute to the business. The expected economic benefit incorporates existing customer contracts with weighted-average amortization life of 13 years and expected renewal rates, based on the estimated volume and production lives of gas resources in the region. See Note 2, "Significant Accounting Policies" to the Consolidated Financial Statements for more information.
DT Midstream incurred $18 million of direct transaction costs for the acquisition during the year ended December 31, 2019. These costs were primarily related to advisory fees and included in Operation and maintenance in DT Midstream's Consolidated Statements of Operations.
DT Midstream's Consolidated Statement of Operations include Operating Revenues of $15 million and Net Income of $3 million associated with the acquired entities for the one-month period following the acquisition date, excluding the $18 million of transaction costs described above.
DT Midstream, Inc.
Notes to Consolidated Financial Statements
The following represents the unaudited pro forma consolidated income statement as if Blue Union and LEAP had been included in the results of DT Midstream for the year ended December 31, 2019:
Unaudited Pro Forma Consolidated Income Statement
For the year ended December 31, 2019
(millions)
Revenue $ 645
Net Income $ 256
The pro forma amounts include adjustments to reflect the additional depreciation and amortization that would have been charged assuming the fair value adjustments to property, plant, and equipment and intangible assets had been applied as of January 1, 2019. Pro forma amounts are not presented for the years ending December 31, 2021 and 2020 since Blue Union and LEAP results are included in the Consolidated Financial Statements for the entire year.
NOTE 5 - REVENUE
Significant Accounting Policy
Revenue is measured based upon the consideration specified in a contract with a customer at the time when performance obligations are satisfied. A performance obligation is a promise in a contract to transfer a distinct good or service or a series of distinct goods or services to the customer. DT Midstream's revenues generally consist of services related to the gathering, transportation, and storage of natural gas. Revenue is recognized when performance obligations are satisfied by transferring control over a service to a customer, which occurs when the service is provided to the customer. When a customer simultaneously receives and consumes the product or 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.
Disaggregation of Revenue
The following is a summary of revenues disaggregated by segment:
Year Ended December 31,
2021 2020 2019
(millions)
Pipeline (a)
$ 307 $ 266 $ 234
Gathering 534 489 273
Elimination of Inter-segment Revenue (1) (1) (3)
Total operating revenues $ 840 $ 754 $ 504
__________________________________
(a)Includes revenues outside the scope of Topic 606 primarily related to contracts accounted for as leases of $9 million for the years ended December 31, 2021, 2020 and 2019.
DT Midstream, Inc.
Notes to Consolidated Financial Statements
Nature of Goods and Services
The following is a description of principal activities, separated by reportable segments, from which DT Midstream generates revenue. For more detailed information about reportable segments, see Note 15, "Segment and Related Information" to the Consolidated Financial Statements.
DT Midstream has contracts with customers which generally contain a single performance obligation. When more than one performance obligation exists in a contract, the consideration under the contract is allocated to the performance obligations based on the relative standalone selling price. DT Midstream generally determines standalone selling prices based on the prices charged to customers or the use of the adjusted market assessment approach. The adjusted market assessment approach involves the evaluation of the market in which DT Midstream sells goods or services and estimating the price that a customer in that market would be willing to pay.
When a customer simultaneously receives and consumes the product or 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.
Pipeline and Gathering
Pipeline revenues consist of services related to the transportation and storage of natural gas. Gathering revenues generally consist of services related to the gathering, transportation, and processing of natural gas. Contracts are primarily long-term in nature. Revenues, including estimated unbilled amounts, are generally recognized over time based upon services provided or through the passage of time ratably based upon providing a stand-ready service. Unbilled amounts are generally determined using estimated volumes based on preliminary meter data and contracted rates and typically result in minor adjustments in the following reporting period. DT Midstream has determined that the above methods represent a faithful depiction of the transfer of control to the customer. Revenues are typically billed and received monthly. Pricing for such revenues may consist of demand rates, commodity rates, transportation rates, and other associated fees. Consideration may consist of both fixed and variable components and may be subject to MVCs. Generally, uncertainties in the variable consideration components are resolved and revenues are known at the time of recognition.
Contract Liabilities
The following is a summary of contract liability activity:
2021 2020
(millions)
Balance at January 1 $ 23 $ 22
Increases due to cash received or receivable, excluding amounts recognized as revenue during the period 8 3
Revenue recognized that was included in the balance at the beginning of the period (3) (2)
Balance at December 31 $ 28 $ 23
The contract liabilities at DT Midstream generally represent amounts paid by or receivable from customers for which the associated performance obligation has not yet been satisfied. Performance obligations associated with contract liabilities include providing services related to customer prepayments. Contract liabilities associated with these services are recognized when control has transferred to the customer.
The following table presents contract liability amounts as of December 31, 2021 that are expected to be recognized as revenue in future periods:
(millions)
2022 $ 9
2023 3
2024 3
2025 3
2026 3
2027 and thereafter 7
Total $ 28
DT Midstream, Inc.
Notes to Consolidated Financial Statements
Transaction Price Allocated to the Remaining Performance Obligations
In accordance with optional exemptions available under Topic 606, DT Midstream does 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 DT Midstream's invoices for actual goods provided and services performed, and (3) contracts for which variable consideration relates entirely to an unsatisfied performance obligation.
Such contracts consist of various types of performance obligations, including the delivery of 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 consideration under the contract 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, 2021 that are expected to be recognized as revenue in future periods:
(millions)
2022 $ 84
2023 80
2024 69
2025 64
2026 45
2027 and thereafter 81
Total $ 423
Major Customers
The following table summarizes customers which represent 10% or more of our total revenue for the years ended December 31, 2021, 2020 and 2019. Both Pipeline and Gathering segments provide services to these customers.
2021 2020 2019
Customer Percentage Customer Percentage Customer Percentage
Revenue of Total Revenue of Total Revenue of Total
Customers: (millions, except percentages)
Customer A $ 563 67 % $ 227 31 % $ 235 47 %
Customer B $ 84 10 % $ 84 11 % $ 80 16 %
Customer C * * $ 278 37 % * *
*Represents less than 10%
NOTE 6 - GOODWILL
DT Midstream has 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, 2021 and determined that the estimated fair value of each reporting unit exceeded its carrying value, and no impairment existed.
The following is the summary of the change in the carrying amount of goodwill:
2021 2020
(millions)
Balance at January 1 $ 473 $ 471
Goodwill attributable to 2019 acquisition of Blue Union and LEAP - 2
Balance at December 31 $ 473 $ 473
DT Midstream, Inc.
Notes to Consolidated Financial Statements
NOTE 7 - 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,
2021 2020
(years) (millions)
Property, plant, and equipment
Gathering systems 34 $ 2,206 $ 2,111
Pipeline and related assets 41 1,595 1,593
Land, structures, and other equipment 21 308 277
$ 4,109 $ 3,981
Accumulated depreciation
Gathering systems $ (362) $ (301)
Pipeline and related assets (213) (174)
Land, structure, and other equipment (44) (36)
(619) (511)
Net Property, plant, and equipment $ 3,490 $ 3,470
Pipeline includes base natural gas of $50 million at December 31, 2021 and 2020. Base natural gas is not subject to depreciation.
Intangible Assets
DT Midstream has intangible assets as shown below:
December 31, 2021 December 31, 2020
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 25 - 40 years (a)
$ 2,252 $ (177) $ 2,075 $ 2,252 $ (120) $ 2,132
Contract intangibles 14 - 26 years
18 (11) 7 18 (10) 8
Total $ 2,270 $ (188) $ 2,082 $ 2,270 $ (130) $ 2,140
_____________________________________
(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 gas resources in the region.
The following table summarizes DT Midstream’s estimated customer relationships and contract intangibles amortization expense to be recognized during each year through 2026:
2022 2023 2024 2025 2026
(millions)
Estimated amortization expense $ 57 $ 57 $ 57 $ 57 $ 57
DT Midstream, Inc.
Notes to Consolidated Financial Statements
Depreciation and Amortization
The following is a summary of Depreciation and amortization expense by asset type:
Year Ended December 31,
2021 2020 2019
(millions)
Property, plant, and equipment $ 108 $ 97 $ 69
Customer relationships and other intangible assets, net 58 55 24
Total Depreciation and amortization $ 166 $ 152 $ 93
NOTE 8 - INCOME TAXES
Significant Accounting Policy - Accounting for Income Taxes
The Company records 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 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 50% likely 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.
The Separation - Tax Considerations
As discussed at Note 1, "Separation, Description of the Business, and Basis of Presentation", DT Midstream completed the Separation from DTE Energy on July 1, 2021. For periods prior to the Separation, the results of DT Midstream’s operations were included in the consolidated federal and state income tax returns filed (and to be filed) by DTE Energy. After DTE Energy files its consolidated income tax returns for 2021, we anticipate there to be a settlement or adjustments to allocated tax attributes (if any) between DT Midstream and DTE Energy in accordance with the terms of the Tax Matters Agreement for the first half of 2021 prior to the Separation.
For periods prior to the Separation, the income tax provision has been presented on a stand-alone basis as if DT Midstream filed separate federal, state, local, and foreign income tax returns, referred to as the separate return method. Consequently, certain income taxes currently payable or receivable are deemed to have been contributed to or distributed from DT Midstream, through Stockholders' Equity/Member's Equity, in the period that the liability or asset arose. Differences (if any) between the carrying value of assets and liabilities (including deferred taxes) prior to the Separation versus post Separation were recorded as contributed capital. DT Midstream’s income taxes, as presented in the comparative financial statements, may not be indicative of the income taxes that DT Midstream will generate in the future.
DT Midstream, Inc.
Notes to Consolidated Financial Statements
DT Midstream’s total Income Tax Expense varied from the statutory federal income tax rate for the following reasons:
Year Ended December 31,
2021 2020 2019
(millions)
Income Before Income Taxes $ 422 $ 440 $ 292
Income tax expense at statutory rate 89 92 61
State and local income taxes, net of federal benefit 17 25 13
State legislative rate change (3) - -
Other, net 1 (1) (2)
Income Tax Expense $ 104 $ 116 $ 72
Effective income tax rate 24.7 % 26.5 % 24.6 %
Components of DT Midstream’s Income Tax Expense were as follows:
Year Ended December 31,
2021 2020 2019
(millions)
Current income tax expense
Federal $ 1 $ - $ -
State and other income tax (1) 5 4
Total current income taxes - 5 4
Deferred income tax expense
Federal 85 84 55
State and other income tax 19 27 13
Total deferred income tax 104 111 68
$ 104 $ 116 $ 72
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 DT Midstream's 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’s deferred tax assets (liabilities) were comprised of the following:
December 31,
2021 2020
(millions)
Deferred income tax balance components
Property, plant, and equipment $ (363) $ (330)
Federal net operating loss carry-forward 175 194
State and local net operating loss carry-forward, net of Federal 97 92
Investment in equity method investees and partnerships (774) (711)
Other 9 13
(856) (742)
Less valuation allowance - (1)
Net deferred income tax asset / (liability) $ (856) $ (743)
Total deferred income tax assets and liabilities
Deferred income tax assets $ 288 $ 262
Deferred income tax liabilities (1,144) (1,005)
$ (856) $ (743)
DT Midstream, Inc.
Notes to Consolidated Financial Statements
DT Midstream has a deferred tax asset related to a federal net operating loss carry-forward of $175 million as of December 31, 2021. The US federal pre-2018 net operating loss carry-forwards were all utilized. All remaining US federal net operating losses will be available to be carried forward indefinitely and available to offset 80% of taxable income in future years.
DT Midstream has state and local deferred tax assets related to net operating loss carry-forwards of $97 million at December 31, 2021. The state and local net operating loss carry-forwards expire from 2033 through 2040.
The deferred income tax attributes described above and included in our consolidated balance sheet, have been allocated from DTE Energy in accordance with the terms of our Tax Matters Agreement and applicable tax law. As described above, any differences between these amounts (or amounts previously reported) and amounts actually allocated once the 2021 income tax returns have been filed will be recorded as an adjustment through contributed capital.
Uncertain Tax Positions
As of December 31, 2021 and 2020, DT Midstream does not have any unrecognized tax benefits.
For periods prior to the Separation, DT Midstream was a member of the consolidated tax return of DTE Energy. During 2021, DTE Energy settled a federal tax audit for the 2019 tax year. As of the balance sheet date, DTE Energy’s federal income tax returns for 2020 and subsequent years remains subject to examination by the Internal Revenue Service (IRS).
DT Midstream also files income tax returns in numerous state and local jurisdictions with varying statute limitations.
DT Midstream, Inc.
Notes to Consolidated Financial Statements
NOTE 9 - 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. Restricted stock units and performance shares that are dilutive are included in the determination of weighted average shares outstanding. Restricted stock units and performance shares do not receive cash dividends, as such, these awards are not considered participating securities.
The DT Midstream Board of Directors authorized the issuance of an additional 96,731,466 common shares to DTE Energy on June 30, 2021 for a total of 96,732,466 common shares issued and outstanding at the date of the Separation. This share amount is utilized for the calculation of basic and diluted earnings per share for all periods prior to the Separation presented based on Net Income attributable to DT Midstream. For the years ended December 31, 2021, 2020 and 2019, these shares are treated as issued and outstanding for purposes of calculating historical earnings per share.
The following is a reconciliation of DT Midstream's basic and diluted earnings per share calculation:
Year Ended December 31,
2021 2020 2019
(millions, except per share amounts)
Basic and Diluted Earnings per Common Share
Net Income Attributable to DT Midstream $ 307 $ 312 $ 204
Average number of common shares outstanding - basic 96.7 96.7 96.7
Incremental shares attributable to:
Average dilutive restricted stock units and performance share awards 0.2 - -
Average number of common shares outstanding - diluted 96.9 96.7 96.7
Basic Earnings per Common Share $ 3.17 $ 3.23 $ 2.11
Diluted Earnings per Common Share $ 3.16 $ 3.23 $ 2.11
DT Midstream declared the following cash dividends:
Quarters Ended Quarterly Dividend Dividend Payment Date
(per-share) (millions)
September 30 $ 0.60 $ 58 October 2021
December 31 $ 0.60 $ 58 January 2022
NOTE 10 - 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. DT Midstream makes certain assumptions it believes that market participants would use in pricing assets or liabilities, including assumptions about risk, and the risks inherent in the inputs to valuation techniques. DT Midstream believes it uses valuation techniques that maximize the use of observable market-based inputs and minimize the use of unobservable inputs.
DT Midstream, Inc.
Notes to Consolidated Financial Statements
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. DT Midstream classifies 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 DT Midstream has 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, 2021 December 31, 2020
Carrying Fair Value Carrying Fair Value
Amount Level 1 Level 2 Level 3 Amount Level 1 Level 2 Level 3
(millions)
Cash equivalents (a)
$ 50 $ - $ 50 $ - $ - $ - $ - $ -
Short-term notes receivable
Due from DTE Energy - - - - 263 - - 292
Third party 5 - - 5 11 - - 11
Related party 4 - - 4 - - - -
Long-term notes receivable
Third party 2 - - 2 15 - - 15
Related party - - - - 4 - - 4
Short-term borrowings due to DTE Energy - - - - 3,175 - - 3,517
Long-term debt (b)
$ 3,046 $ - $ 3,163 $ - $ - $ - $ - $ -
______________________________________
(a)Money market cash equivalents are measured and recorded at fair value on a recurring basis.
(b)Includes debt due within one year. Carrying value represents principal of $3,095 million, net of unamortized debt discounts and issuance costs.
The fair values of DT Midstream’s non-publicly traded notes receivable due from DTE Energy and short-term borrowings due to DTE Energy were based on an internally developed model and are classified as Level 3 within the fair value hierarchy. As described in Note 2, "Significant Accounting Policies", the carrying amount and fair value of the Notes receivable - third party was reduced in the second quarter 2021 based on a discounted cash flow analysis performed.
DT Midstream, Inc.
Notes to Consolidated Financial Statements
NOTE 11 - DEBT
Debt Issuances
On June 9, 2021, DT Midstream issued senior unsecured notes of $1.1 billion in aggregate principal amount due June 15, 2029 (the "2029 Notes") and $1.0 billion in aggregate principal amount due June 15, 2031 (the "2031 Notes"). On June 10, 2021, DT Midstream entered into a Credit Agreement (the "Credit Agreement") that provides for a $1.0 billion 7-year term loan facility (the "Term Loan Facility") and a $750 million 5-year secured revolving credit facility (the "Revolving Credit Facility").
Long-Term Debt
DT Midstream's long-term debt outstanding included:
December 31,
Title Type Interest Rate Maturity Date 2021
(millions)
2029 Notes Senior Notes (a) (c)
4.125% 2029 $ 1,100
2031 Notes Senior Notes (a) (c)
4.375% 2031 1,000
Term Loan Facility Term Loan Facility (a)
Variable (b)
2028 995
3,095
Unamortized debt discount (4)
Unamortized debt issuance costs (45)
Long-term debt due within one year (10)
Long-term debt (net of current portion) $ 3,036
______________________________
(a) Debt proceeds were used for the repayment of short-term borrowings due to DTE Energy to facilitate the Separation of DT Midstream, as well as a one-time special dividend provided to DTE Energy. See Note 1, "Separation, Description of the Business, and Basis of Presentation" to the Consolidated Financial Statements for additional information.
(b) Variable rate is LIBOR plus 2.00%, where LIBOR will not be less than 0.50%. The Term Loan Facility includes $98 million with a six-month LIBOR interest period ending March 31, 2022 and $897 million with a six-month LIBOR interest period ending June 30, 2022.
(c) Interest payable semi-annually in arrears each June 15 and December 15, commencing December 15, 2021.
The following table presents the scheduled debt maturities, excluding any unamortized discount on debt:
2022 2023 2024 2025 2026 and Thereafter Total
(millions)
Debt maturities $ 10 10 10 10 3,055 $ 3,095
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 June 2026 $ 750
Amounts outstanding
Revolving Credit Facility borrowings -
Letters of credit 8
Net availability $ 742
DT Midstream, Inc.
Notes to Consolidated Financial Statements
Borrowings under the Revolving Credit Facility are used for general corporate purposes and letter of credit issuances to support DT Midstream's future operations and liquidity. The Revolving Credit Facility incurred issuance fees of $7 million, net of amortization, which are included in Other noncurrent assets on DT Midstream's Consolidated Statements of Financial Position as of December 31, 2021. These fees are being amortized over the term of the Revolving Credit Facility. On July 1, 2021, DT Midstream borrowed $25 million under the Revolving Credit Facility which was repaid on August 2, 2021.
The Credit Agreement covering the Term Loan Facility and Revolving Credit Facility includes financial covenants that DT Midstream must maintain. These covenants restrict the ability of DT Midstream and its 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 its restricted subsidiaries to incur liens on assets and enter into certain transactions with affiliates. The Term Loan Facility requires the maintenance of a minimum debt service coverage ratio of 1.1 to 1, and the Revolving Credit Facility requires maintenance of (i) a maximum consolidated net leverage ratio of 5 to 1, and (ii) a minimum interest coverage ratio of no less than 2.5 to 1. The debt service coverage ratio means the ratio of annual consolidated EBITDA to debt service, as defined in the Credit Agreement. The consolidated net leverage ratio means the ratio of net debt determined in accordance with GAAP to annual consolidated EBITDA. The interest coverage ratio means the ratio of annual consolidated EBITDA to annual interest expense, as defined in the Credit Agreement. At December 31, 2021, the debt service coverage ratio, the consolidated net leverage ratio and the interest coverage ratio was 5.9 to 1, 3.9 to 1 and 6.0 to 1, respectively, and DT Midstream was in compliance with these financial covenants.
Dividend Restrictions
2029 and 2031 Senior Notes
The indenture governing the Senior Notes restricts, subject to certain exceptions, DT Midstream’s ability to pay dividends on capital stock. The indenture generally permits, subject to certain conditions, the payment of dividends during the quarter that do not exceed 50% of consolidated net income (as defined in the indenture) for the period beginning on April 1, 2021, to the end of the most recently ended fiscal quarter for which internal financial statements are available. One exception in the indenture specifically permits, subject to certain conditions, the payment of quarterly dividends on common stock in each fiscal year up to the greater of $240 million and 30% of consolidated cash flow (as defined in the indenture). For 2021, the dividend capacity remaining at year end was $240 million less dividends declared of $116 million or approximately $124 million.
Credit Agreement
The Credit Agreement also restricts, subject to certain exceptions, DT Midstream’s ability to pay dividends on capital stock. However, the Credit Agreement permits the payment of dividends so long as, giving pro forma effect thereto, the first lien net leverage ratio does not exceed 3.25 to 1. As of December 31, 2021, the dividend capacity under such test exceeded the dividend capacity under the indenture governing the Senior Notes.
NOTE 12 - LEASES
Lessee
Leases at DT Midstream are primarily comprised of equipment and buildings with terms ranging from approximately 2 to 11 years.
A lease is deemed to exist when DT Midstream has 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 DT Midstream has 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
Lease liabilities are determined utilizing a discount rate to determine the present values of lease payments. GAAP requires the use of the rate implicit in the lease when 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.
DT Midstream has leases with non-index-based escalation clauses for fixed dollar or percentage increases.
DT Midstream has certain leases which contain purchase options. Based upon the nature of the leased property and terms of the purchase options, DT Midstream has 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 has 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.
DT Midstream has 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 following years includes:
Year Ended December 31,
2021 2020 2019
(millions)
Operating lease cost $ 19 $ 18 $ 18
Short-term lease cost - 1 1
$ 19 $ 19 $ 19
DT Midstream has elected not to apply the lease recognition requirements to leases with a term of 12 months or less. Operating lease cost includes amortization of operating lease right-of-use assets and other related costs. Operating and short-term lease costs are recorded to Operation and Maintenance within Operating Expenses in the Consolidated Statement of Operations.
Other relevant information related to leases for the following years includes:
Year Ended December 31,
2021 2020 2019
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 $ 19 $ 18 $ 18
Right-of-use assets obtained in exchange for lease obligations:
Operating leases $ 9 $ 16 $ 26
Weighted Average Remaining Lease Term
Operating leases 4.4 years 3.2 years 3.6 years
Weighted Average Discount Rate
Operating leases 2.6 % 2.8 % 3.2 %
DT Midstream, Inc.
Notes to Consolidated Financial Statements
DT Midstream's future minimum lease payments under leases for remaining periods as of December 31, 2021 are as follows:
Operating Leases
(millions)
2022 $ 17
2023 11
2024 3
2025 1
2026 1
2027 and thereafter 6
Total future minimum lease payments 39
Imputed interest (2)
Lease liabilities $ 37
Lessor
DT Midstream leases 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 18 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.
A lease is deemed to exist when DT Midstream has 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 DT Midstream has 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's fixed lease income associated with the operating lease was $9 million for each of the years ended December 31, 2021, 2020 and 2019. Fixed lease income is reported in Operating Revenues on DT Midstream's Consolidated Statement of Operations. Depreciation expense associated with the property under the operating lease was $3 million for each of the years ended December 31, 2021, 2020 and 2019.
DT Midstream's future minimum rental revenues for remaining periods as of December 31, 2021 are as follows:
Operating Lease
(millions)
2022 $ 9
2023 9
2024 9
2025 9
2026 9
2027 and thereafter 104
$ 149
Property under the operating lease for DT Midstream is as follows:
December 31,
2021 2020
(millions)
Gross property under operating leases $ 58 $ 58
Accumulated amortization of property under operating leases $ 9 $ 6
DT Midstream, Inc.
Notes to Consolidated Financial Statements
NOTE 13 - COMMITMENTS AND CONTINGENCIES
From time to time, DT Midstream is 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. DT Midstream cannot predict the final disposition of such proceedings. DT Midstream regularly reviews legal matters and records 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 DT Midstream’s business, financial condition and results of operations.
Guarantees
In certain limited circumstances, DT Midstream enters into contractual guarantees. DT Midstream may guarantee another entity's obligation in the event it fails to perform and may provide guarantees in certain indemnification agreements. Additionally, DT Midstream may provide indirect guarantees for the indebtedness of others. In connection with the Separation, DT Midstream assumed guarantees valued at $7 million as of December 31, 2021. Payment under these guarantees are considered remote. DT Midstream did not have any guarantees of other parties' obligations as of December 31, 2021.
Purchase Commitments
As of December 31, 2021, DT Midstream was party to long-term purchase commitments relating to a variety of goods and services required for their business. DT Midstream estimates lifetime purchase commitments of approximately $12 million.
(millions)
2022 $ 4
2023 4
2024 2
2025 1
2026 1
2027 and thereafter -
Total $ 12
Vector Pipeline Line of Credit
In July 2021 and in conjunction with the Separation, DT Midstream assumed the Vector Pipeline line of credit from DTE Energy. DT Midstream became the lender under the revolving term credit facility to Vector Pipeline, the borrower, in the amount of Canadian $70 million. The credit facility was initially 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 Pipeline may only draw upon the facility if the funds are required to respond to a catastrophic event. The maximum potential payout at December 31, 2021 is USD $55 million. The funding of a loan under the terms of the credit facility is considered remote.
Bankruptcies
DT Midstream’s Gathering segment provides gas gathering services under customer contracts with gas shippers in the Utica and Marcellus regions in Pennsylvania and West Virginia. In December 2019, one of these customers, Arsenal Resources, entered into bankruptcy. The Bankruptcy Court issued an order approving a plan to be followed in connection with the bankruptcy with an effective date of January 7, 2020. As of December 31, 2019, DT Midstream recorded an allowance for expected credit loss of approximately $8 million against a portion of its accounts receivable from Arsenal Resources.
In 2020, DT Midstream received payments of approximately $4 million from Arsenal Resources under the terms of a cure agreement. There was no allowance for expected credit loss remaining at December 31, 2020.
DT Midstream, Inc.
Notes to Consolidated Financial Statements
Environmental Contingencies
In order to comply with certain state environmental regulations, DT Midstream has an obligation to restore pipeline right-of-way slope failures that may arise in the ordinary course of business in the Utica and Marcellus shale region. Slope restoration expenditures are typically capital in nature. As of December 31, 2021 and 2020, DT Midstream had accrued contingent liabilities of $20 million and $23 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. DT Midstream believes the accrued amounts are sufficient to cover estimated future expenditures.
COVID-19 Pandemic
DT Midstream is actively monitoring the impact of the COVID-19 pandemic on supply chains, markets, counterparties, and customers, and any related impacts on operating costs, customer demand, and recoverability of assets that could materially impact DT Midstream’s financial results.
There have been no material adjustments or reserves deemed necessary to the financial statements as of December 31, 2021 as a result of COVID-19. DT Midstream cannot predict the future impacts of the COVID-19 pandemic on the Consolidated Financial Statements, as developments involving COVID-19 and its related effects on economic and operating conditions remain highly uncertain.
NOTE 14 - STOCK-BASED COMPENSATION AND DEFINED CONTRIBUTION PLANS
Prior to the Separation, DT Midstream employees participated in DTE Energy's Long-Term Incentive Plan. At the Separation, outstanding DT Midstream employee restricted stock awards and performance share awards were modified or settled as follows:
•DTE Energy restricted stock awards were converted into DT Midstream restricted stock units;
•DTE Energy settled two-thirds of the 2019 performance share awards and one-third of the 2020 performance share awards; and
•Remaining unsettled DTE Energy performance share awards were converted into DT Midstream performance share awards.
The restricted stock and performance awards were converted using a formula designed to preserve the fair value of the awards immediately prior to the Separation. All converted awards retained the vesting schedule of the original awards. The conversion of the restricted stock and performance awards qualified as an accounting modification under GAAP. The pre- and post- Separation fair value of the awards was compared, and any incremental fair value was added to the original grant date fair value of the awards. The Separation modification gave rise to incremental fair value of approximately $1 million for the performance share awards granted in January 2021 and is reflected in the compensation cost charged to income and the unrecognized compensation cost described below. The Separation modification did not give rise to incremental fair value for any other converted restricted stock or performance share awards.
The DT Midstream, Inc. Long-Term Incentive Plan ("DT Midstream Plan") began on the Separation date. The DT Midstream Plan permits the grant of incentive and nonqualified stock options, stock appreciation rights, restricted stock and restricted stock units, performance shares, and performance units to employees and members of its Board of Directors. As a result of a grant of a restricted stock award, a settlement of restricted stock units or performance shares, or by exercise of a participant's stock option, DT Midstream may deliver common stock from its authorized but unissued common stock and/or from outstanding common stock acquired by or on behalf of DT Midstream in the name of the participant. Key provisions of the DT Midstream Plan are:
•Authorized limit is 3,000,000 shares of common stock. The authorized limit increases annually on January 1 by the lesser of 1,750,000 shares of common stock or the amount determined by the DT Midstream Board of Directors; and
•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.
DT Midstream, Inc.
Notes to Consolidated Financial Statements
The following table summarizes the components of stock-based compensation for DT Midstream. Prior to the Separation, DT Midstream received an allocation of costs from DTE Energy associated with stock-based compensation. Allocated costs for the years ended December 31, 2020 and 2019 and the first six months of 2021 are included in the table below. No costs were allocated after July 1, 2021.
The following table presents allocated costs through June 30, 2021 and costs incurred directly by DT Midstream subsequent to June 30, 2021:
Year Ended December 31,
2021 2020 2019
(millions)
Stock-based compensation expense $ 12 $ 6 $ 6
Tax benefit $ 3 $ 2 $ 1
Restricted Stock Units
Restricted stock units awarded under the DT Midstream Plan are for a specified number of shares of DT Midstream common stock that entitle the holder to receive shares of DT Midstream common stock, a cash payment, or any combination of cash and common stock at the end of the vesting period, which is generally three or four years. Restricted stock units are deemed to be equity awards. During the vesting period, the recipient of the restricted stock unit has no shareholder rights. During the period beginning on the grant date and ending on the vesting date, the number of restricted stock units will be increased, assuming full dividend reinvestment at the fair market value on the dividend payment date.
The restricted stock units are recorded at cost that approximates fair value on the grant date. The cost is amortized to compensation expense on a graded vesting schedule over the vesting period.
The following table summarizes DT Midstream's restricted stock unit activity for the year ended December 31, 2021:
Restricted
Stock Units Weighted Average
Grant Date
Fair Value
Balance at December 31, 2020 - $ -
Converted at Separation 106,455 35.68
Grants 362,045 43.32
Vested and issued (2,200) 39.20
Balance at December 31, 2021 466,300 $ 41.60
Performance Share Awards
Performance shares awarded under the DT Midstream Plan are for a specified number of shares of DT Midstream common stock that entitle the holder to receive a cash payment, shares of common stock or a combination thereof. The final value of the award is determined by the achievement of certain performance objectives and market conditions. The awards vest at the end of a specified period, usually three years. The DT Midstream stock price and number of probable shares attributable to market conditions for such equity awards are fair valued only at the grant date. For the awards converted at the Separation, the grant date fair value was based on DTE Energy stock price and market conditions at grant date.
During the vesting period, the recipient of a performance share award has no shareholder rights. During the period beginning on the date the performance shares are awarded and ending on the certification date of the performance objectives, the number of performance shares awarded will be increased, assuming full dividend reinvestment at the fair market value on the dividend payment date. The cumulative number of performance shares will be adjusted to determine the final payment based on the performance objectives achieved. Performance share awards are nontransferable and are subject to risk of forfeiture.
DT Midstream, Inc.
Notes to Consolidated Financial Statements
The following table summarizes DT Midstream's performance share activity for the year ended December 31, 2021:
Performance
Shares Weighted Average
Grant Date
Fair Value
Balance at December 31, 2020 - $ -
Converted at Separation 290,544 40.52
Grants 3,453 49.92
Forfeitures (3,937) 41.17
Balance at December 31, 2021 290,060 $ 40.63
Unrecognized Compensation Costs
As of December 31, 2021, DT Midstream had $23 million of total unrecognized compensation cost related to non-vested stock incentive plan arrangements. The cost is expected to be recognized over a weighted-average period of 1.98 years.
Defined Contribution Plans
DT Midstream sponsors defined contribution retirement savings plans, and participation in one of these plans is available to substantially all employees. DT Midstream matches employee contributions up to certain predefined limits based on eligible compensation and the employee's contribution rate and contributes additional amounts in lieu of traditional pension and post-employment healthcare benefits. Prior to the Separation, DT Midstream participated in the defined contribution retirement plans of DTE Energy. DT Midstream's cost for these plans was $3 million, $2 million and $2 million for the years ended December 31, 2021, 2020 and 2019, respectively.
DT Midstream, Inc.
Notes to Consolidated Financial Statements
NOTE 15 - SEGMENT AND RELATED INFORMATION
DT Midstream sets strategic goals, allocates resources, and evaluates performance based on the following structure:
Pipeline segment, formerly titled Pipeline and Other, owns and operates interstate and intrastate natural gas pipelines, storage systems, and natural gas gathering lateral pipelines. The 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 definition and composition of the segment was not impacted by the segment title change and remains consistent with prior periods.
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 processing, 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 storage, water transportation and sand mining.
Inter-segment billing for goods and services exchanged between segments is based upon contracted prices of the provider and primarily consists of:
Year Ended December 31,
2021 2020 2019
(millions)
Pipeline $ - $ - $ -
Gathering 1 1 3
Total $ 1 $ 1 $ 3
Financial data for DT Midstream's business segments follows:
Year Ended December 31, 2021
Pipeline Gathering Eliminations Total
(millions)
Operating revenues $ 307 $ 534 $ (1) $ 840
Operation and maintenance 59 173 (1) 231
Depreciation and amortization 63 103 - 166
Taxes other than income 13 11 - 24
Asset (gains) losses and impairments, net - 17 - 17
Operating Income 172 230 - 402
Interest expense 51 61 - 112
Interest income (1) (3) - (4)
Earnings from equity method investees (126) - - (126)
Other (income) and expense (3) 1 - (2)
Income Tax Expense 62 42 - 104
Net Income 189 129 - 318
Less: Net Income Attributable to Noncontrolling Interests 11 - - 11
Net Income Attributable to DT Midstream $ 178 $ 129 $ - $ 307
Capital expenditures and acquisitions $ 20 $ 120 $ - $ 140
December 31, 2021
Investments in equity method investees $ 1,691 $ - $ - $ 1,691
Goodwill 53 420 - 473
Total assets $ 4,165 $ 4,001 $ - $ 8,166
DT Midstream, Inc.
Notes to Consolidated Financial Statements
Year Ended December 31, 2020
Pipeline Gathering Eliminations Total
(millions)
Operating revenues $ 266 $ 489 $ (1) $ 754
Operation and maintenance 53 123 (1) 175
Depreciation and amortization 52 100 - 152
Taxes other than income 7 8 - 15
Asset (gains) losses and impairments, net - (2) - (2)
Operating Income 154 260 - 414
Interest expense 43 70 - 113
Interest income (4) (5) - (9)
Earnings from equity method investees (108) - - (108)
Other (income) and expense (2) (20) - (22)
Income Tax Expense 58 58 - 116
Net Income 167 157 - 324
Less: Net Income Attributable to Noncontrolling Interests 12 - - 12
Net Income Attributable to DT Midstream $ 155 $ 157 $ - $ 312
Capital expenditures and acquisitions $ 350 $ 168 $ - $ 518
December 31, 2020
Investments in equity method investees $ 1,691 $ - $ - $ 1,691
Goodwill 53 420 - 473
Total assets $ 4,343 $ 3,999 $ - $ 8,342
Year Ended December 31, 2019
Pipeline Gathering Eliminations Total
(millions)
Operating revenues $ 234 $ 273 $ (3) $ 504
Operation and maintenance 64 80 (3) 141
Depreciation and amortization 46 47 - 93
Taxes other than income 6 2 - 8
Asset (gains) losses and impairments, net 1 - - 1
Operating Income 117 144 - 261
Interest expense 56 22 (3) 75
Interest income (11) - 3 (8)
Earnings from equity method investees (98) - - (98)
Other (income) and expense - - - -
Income Tax Expense 38 34 - 72
Net Income 132 88 - 220
Less: Net Income Attributable to Noncontrolling Interests 16 - - 16
Net Income Attributable to DT Midstream $ 116 $ 88 $ - $ 204
Capital expenditures and acquisitions $ 401 $ 2,106 $ - $ 2,507
December 31, 2019
Investments in equity method investees $ 1,684 $ - $ - $ 1,684
Goodwill 53 418 - 471
Total assets $ 3,852 $ 3,935 $ - $ 7,787
DT Midstream, Inc.
Notes to Consolidated Financial Statements
NOTE 16 - RELATED PARTY TRANSACTIONS
Transactions between DT Midstream and DTE Energy prior to the Separation, as well as all transactions between DT Midstream and its equity method investees, have been presented as related party transactions in the accompanying Consolidated Financial Statements.
Prior to the Separation, DTE Energy and its subsidiaries provided physical operations, maintenance, and technical support pursuant to an operating agreement for DT Midstream’s facilities. DT Midstream also utilized various services performed by DTE Energy and its subsidiaries, including marketing and capacity optimization services.
Prior to the Separation, interest expense recorded in the Consolidated Statements of Operations was primarily related to interest on the Short-term borrowings due to DTE Energy, amounts of which are shown in the table below. The working capital loan agreement had interest rates of 3.3% for 2021 and 3.9% for 2020 and 2019 and a term of one year. No interest expense on Short-term borrowings due to DTE Energy was incurred after the Separation.
In June 2021, DT Midstream made the following cash payments:
•Settled Short-term borrowings due to DTE Energy as of June 30, 2021 of $2,537 million
•Settled Accounts receivable due from DTE Energy and Accounts payable due to DTE Energy as of June 30, 2021 for net cash of $9 million
•Provided a one-time special dividend to DTE Energy
On July 1, 2021, DTE Energy completed the Separation through the distribution of 96,732,466 shares of DT Midstream common stock to DTE Energy shareholders. After the Separation, DTE Energy is not considered a related party of DT Midstream.
The following is a summary of DT Midstream's balances with related parties:
December 31,
2021 2020
(millions)
Accounts receivable from DTE Energy $ - $ 3
Notes receivable from DTE Energy - 263
Notes receivable from Vector - current 4 -
Notes receivable from Vector - long-term - 4
Accounts payable to DTE Energy - 10
Short-term borrowings due to DTE Energy - 3,175
DT Midstream, Inc.
Notes to Consolidated Financial Statements
The following is a summary of DT Midstream’s transactions with related parties:
Year Ended December 31,
2021 2020 2019
(millions)
Revenues
Pipeline $ 5 $ 16 $ 12
Gathering 10 10 21
Other Costs
Interest income (5) (6) (8)
Interest expense 43 110 75
Operation and maintenance and Other expense 43 54 33
Other
Notes receivable (due from) repaid by DTE Energy 263 (146) 91
Short-term borrowings (repayment of borrowings) from DTE Energy (3,175) 253 1,235
Dividend to DTE Energy (501) - -
Contributions from DTE Energy 110 252 1,274
Non-cash distributions to DTE Energy (10) (62) (64)
NOTE 17 - SUBSEQUENT EVENT
On February 25, 2022, DT Midstream announced that DT Midstream's Board of Directors declared a quarterly dividend of $0.64 per share of common stock. The dividend is payable to DT Midstream's stockholders of record as of March 21, 2022 and is expected to be paid on April 15, 2022.

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

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ITEM 9A. CONTROLS AND PROCEDURES
Item 9A. Controls and Procedures
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, 2021, 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 its 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 its disclosure controls and procedures will be attained.
(b) Management's report on internal control over financial reporting
This annual report does not include a report of management’s assessment regarding internal control over financial reporting or an attestation report of the company’s registered public accounting firm due to a transition period established by rules of the Securities and Exchange Commission for newly public companies.
(c) Changes in internal control over financial reporting
Prior to the Separation, DT Midstream relied on certain material processes and internal controls over financial reporting performed by DTE Energy. No changes in our internal controls over financial reporting during the quarter ended December 31, 2021 have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.

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ITEM 9B. OTHER INFORMATION
Item 9B. Other Information
None.

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

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ITEM 11. EXECUTIVE COMPENSATION
Item 11. Executive Compensation

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

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

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

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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 under Item 8 of this Form 10-K.
(c)Exhibits.
Exhibit Number Description
(i) Exhibits filed herewith:
21.1
Subsidiaries of DT Midstream, Inc.
23.1
Consent of PricewaterhouseCoopers LLP
31.1
Chief Executive Officer Section 302 Form 10-K Certification of Periodic Report
31.2
Chief Financial Officer Section 302 Form 10-K Certification of Periodic Report
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)
4.1
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)
Exhibit Number Description
(iii) Exhibits incorporated by reference:
10.1
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)
10.2
Transition Services Agreement, dated June 25, 2021, between DTE Energy Company and DT Midstream, Inc. (incorporated by reference to Exhibit 10.1 to DT Midstream’s Current Report on Form 8-K filed on July 1, 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
Employee Matters Agreement, dated June 25, 2021, between DTE Energy Company and DT Midstream, Inc (incorporated by reference to Exhibit 10.3 to DT Midstream’s Current Report on Form 8-K filed on July 1, 2021)
10.5
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)
10.6
Change-In-Control Agreement (incorporated by reference to Exhibit 10.4 to DT Midstream’s Current Report on Form 8-K filed on July 1, 2021)
10.7
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)
10.8
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)
10.9
Purchase Agreement, dated as of May 25, 2021, among DT Midstream, Inc., Barclays Capital Inc., as representative of the initial purchasers named therein, and the guarantors party thereto (incorporated by reference to Exhibit 10.5 to Amendment No. 2 to DT Midstream’s Registration Statement on Form 10-12B (File No. 001-40392), filed on May 26, 2021)
99.1
NEXUS Gas Transmission, LLC Consolidated Financial Statements for the years ended December 31, 2020 and 2019 (incorporated by reference to Exhibit 99.3 to DT Midstream’s Registration Statement on Form 10-12B (File No. 001-40392), filed on May 7, 2021)