We own interests in and/or operate NGL fractionation and storage assets in central Kansas near Conway. These assets include a 50 percent interest in an NGL fractionation facility with capacity of slightly more than 100 Mbbls/d and we own approximately 2023 million barrels of NGL storage capacity. We also own a 189-mile NGL pipeline from our fractionator near Conway, Kansas, to an interconnection with a third-party NGL pipeline system in Oklahoma.
We previously owned a non-operated 50 percent interest in the Delaware basin gas gathering system in the Permian basin, which was sold in February 2017. The system was comprised of more than 450milesof gathering pipeline, located in west Texas.
Other
Other includes our previously ownedupstream operations and minor business activities that are not operatingreportable segments, as well as corporate operations.
Geismar InterestUpstream Ventures
In July 2017,We acquired certain crude oil and natural gas properties in the Wamsutter basin in February 2021. These properties were conveyed to a venture in the third quarter of 2021 along with certain oil and gas properties conveyed by a third-party operator in the region. Under the terms of the agreement, the third party owns a 25 percent and we completed the sale of Williams Olefins, L.L.C,own a wholly owned subsidiary which owned our 88.575 percent undivided interest in each well’s working interest. We will retain ownership in the Geismar, Louisiana, olefins plant (Geismar Interest). Upon closingundeveloped acreage until certain acreage earning hurdles are met, at which time the sale, we entered into a long-term supply and transportation agreement with the purchaser to provide feedstock to the plant via our Bayou Ethane pipeline system.
Additional Business Segment Information
Revenues by service that exceeded 10third party will receive an additional 25 percent of consolidated revenues are presented in Note 2 – Revenue Recognitionany new wells and 50 percent of Notes to Consolidated Financial Statements.
We perform certain management, legal, financial, tax, consultation, information technology, administrative, and other services for our subsidiaries.
Our principal sources of cash are from dividends and advances from our subsidiaries, investments, payments by subsidiaries for services rendered, and, if needed, external financings, and net proceeds from asset sales and sales of partial interests of our subsidiaries. The terms of our credit agreement, which also govern certain subsidiaries’ borrowing arrangements, may limit the transfer of funds to us under certain conditions.
We believe that we have adequate sources and availability of raw materials and commodities for existing and anticipated business needs. Our interstate pipeline systems are all regulated in various waysremaining undeveloped acreage resulting in the financial return onthird party owning 50 percent and us owning 50 percent. The combined properties consist of over 1.2 million net acres and an interest in over 3,500 wells.
Certain natural gas properties in Louisiana were transferred to us in November 2020 as part of a bankruptcy resolution with one of our customers. In the investments madethird quarter of 2021, we sold 50 percent of the existing wells and wellbore rights in the systems being limited to standards permitted by the regulatory agencies. EachSouth Mansfield area of the pipeline systemsHaynesville Shale region to a third party operator, in a strategic effort to develop the acreage, thereby enhancing the value of our midstream natural gas infrastructure. Under the agreement, the third party operates the upstream position and develops the undeveloped acreage. When a certain drilling hurdle is met, the third party’s interest in new wells increases to 75 percent. The third party met this drilling hurdle in early 2023. We retain ownership in the undeveloped acreage until a separate acreage earning hurdle is met, at which time remaining undeveloped acreage will be conveyed to the third party resulting in the third party owning 75 percent and us owning 25 percent.
Operating Statistics
| | | | | | | | | | | |
| 2022 | | 2021 |
| (Annual Average Amounts) |
| Net Product Sales Volumes: | | | |
| Natural Gas (Bcf/d) | 0.22 | | | 0.13 | |
| NGLs (Mbbls/d) | 7 | | | 6 | |
| Crude Oil (Mbbls/d) | 2 | | | 2 | |
New Energy Ventures
Our Other segment also includes investments in new energy ventures related to hydrogen, solar, renewable natural gas, and NextGen Gas. NextGen Gas is natural gas that has ongoing capital requirements for efficiency and mandatory improvements, with expansion opportunities also necessitating periodic capital outlays.been independently certified as low emissions gas across all segments of the value chain.
REGULATORY MATTERS
FERC
Our gas pipeline interstate transmission and storage activities are subject to FERC regulation under the Natural Gas Act of 1938 (NGA) and under the Natural Gas Policy Act of 1978, and, as such, our rates and charges for the transportation of natural gas in interstate commerce, accounting, and the extension, enlargement, or abandonment of our jurisdictional facilities, among other things, are subject to regulation. Each of our gas pipeline companies holds certificates of public convenience and necessity issued by the FERC authorizing ownership and operation of all pipelines, facilities, and properties for which certificates are required under the NGA. FERC Standards of Conduct govern how our interstate pipelines communicate and do businessconduct transmission transactions with gasan affiliate that engages in marketing employees.functions. Among other things, the Standards of Conduct require that interstate gas pipelines treat all transmission customers, affiliated and non-affiliated, on a not operate their systems to preferentially benefit gas marketing functions.unduly discriminatory basis.
FERC regulation requires all terms and conditions of service, including the rates charged, to be filed with and approved by the FERC before any changes can go into effect. Our interstate gas pipeline companies establish rates through the FERC’s ratemaking process. In addition, our interstate gas pipelines may enter into negotiated rate agreements where cost-based recourse rates are made available. Key determinants in the FERC ratemaking process include:
•Costs of providing service, including depreciation expense;
•Allowed rate of return, including the equity component of the capital structure and related income taxes;
•Contract and volume throughput assumptions.
The allowed rate of return is determined in each rate case. Rate design and the allocation of costs between the reservation and commodity rates also impact profitability. As a result of these proceedings, certain revenues previously collected may be subject to refund.
We also own interests in and operate natural gas liquids pipelines that are regulated by various federal and state governmental agencies. Services provided on our interstate natural gas liquids pipelines are subject to regulation under the Interstate Commerce Act by the FERC, which has authority over the terms and conditions of service; rates, including depreciation and amortization policies; and initiation of service. Our intrastate natural gas liquids pipelines providing common carrier service are subject to regulation by various state regulatory agencies.
Updated Certificate Policy Statement and Interim Greenhouse Gas (GHG) Policy Statement
On February 18, 2022, the FERC issued two policy statements providing guidance for its pending and future consideration of interstate natural gas pipeline projects. The first policy statement is an Updated Certificate Policy Statement, which provides an analytical framework for how the FERC will consider whether a project is in the public convenience and necessity and explains that the FERC will consider all impacts of a proposed project, including economic and environmental impacts, together. The second policy statement is an Interim GHG Policy Statement, which sets forth how the FERC will assess the impacts of natural gas infrastructure projects on climate change in its reviews under the National Environmental Policy Act and the NGA. The FERC sought comment on all aspects of the policy statements, including the approach to assessing the significance of the proposed project’s contribution to climate change. On March 24, 2022, the FERC issued an order converting the Updated Certificate Policy Statement and the Interim GHG Policy Statement into draft policy statements and announcing that it will not apply either policy statement to pending applications or applications filed before the FERC issues any final guidance on the policy statements. The FERC has not yet issued final guidance on the policy statements.
Pipeline Safety
Our gas pipelines are subject to the Natural Gas Pipeline Safety Act of 1968, as amended, the Pipeline Safety Improvement Act of 2002, the Pipeline Safety, Regulatory Certainty, and Jobs Creation Act of 2011, (Pipeline Safety Act), and the Protecting Our Infrastructure of Pipelines and Enhancing Safety Act of 2016 and 2020, which regulate safety requirements in the design, construction, operation, and maintenance of interstate natural gas transmission facilities. The United States Department of Transportation Pipeline and Hazardous Materials Safety Administration (PHMSA) administers federal pipeline safety laws.
Federal pipeline safety laws authorize PHMSA to establish minimum safety standards for pipeline facilities and persons engaged in the transportation of gas or hazardous liquids by pipeline. These safety standards apply to the design, construction, testing, operation, and maintenance of gas and hazardous liquids pipeline facilities affecting interstate or foreign commerce. PHMSA has also established reporting requirements for operators of gas and hazardous liquid pipeline facilities, as well as provisions for establishing the qualification of pipeline personnel and requirements for managing the integrity of gas transmission and distribution lines and certain hazardous liquid pipelines. To ensure compliance with these provisions, PHMSA performs pipeline safety inspections and has the authority to initiate enforcement actions.
In October 2019, PHMSA published the first of three rules that would be a part of the Mega Rule. The Mega Rule was more than 10 years in the making and since October 2019, PHMSA has also published Rules 2 and 3 as a part of the Mega Rule implementation. At the end of 2021, PHMSA published Rule 3 of the Mega Rule with an implementation date in May 2022. Rule 3 was also called The Gas Gathering Rule and expanded Federal Pipeline Safety oversight to more than 400,000 miles of pipeline across all operators, including approximately 5,400 miles and 4,500 miles of our regulated and unregulated pipelines, respectively. The rule established Federal pipeline safety oversight on previously unregulated gas gathering pipelines. The rule limits the use of “incidental gathering pipelines” to 10 miles in length or less. The rule also creates a new category of regulated gas gathering pipelines that are located in rural locations and will be subject to certain reporting and safety standards. New regulations contain an exemptionin Rule 3 include requirements for public awareness, emergency response, damage prevention, incident notification, and annual reporting. As a result of the rule, we revised numerous procedures and are now reporting based on the expanded scope as required by regulation.
In August 2022, PHMSA published Rule 2, which is the last in the three part Mega Rule set of regulations. Certain portions of Rule 2 go into effect in May 2023 with the remaining portions taking effect in February 2024. Rule 2 contains new corrosion control requirements, new requirements for repair criteria outside of high consequence areas (HCAs), inspections to be performed after extreme weather events or natural disasters, management of change, and other integrity management related rule changes. We are evaluating procedures that will need to be updated to maintain compliance and are also analyzing anticipated cost impacts.
PHMSA’s new rule, Requirement of Valve Installation and Minimum Rupture Detection Standards, went into effect in October 2022. The rupture monitoring and emergency response standards are applicable to existing pipelines, but the installation of rupture mitigation valves (RMVs) is not retroactive and only applies to gathering lines in certain rural locations. A substantial portionnew pipelines and significant pipeline replacements. This new rule establishes criteria for how operators must monitor and respond to potential ruptures on their system. It also outlines requirements for the installation of our gathering lines qualifyRMVs or Alternative Equivalent Technology to allow for that exemptionquicker isolation after an incident has occurred. In response to the new regulation, Williams has updated all applicable procedures and are currently not regulated under federal law.
States are largely preempted by federal law from regulating pipeline safety for interstate pipelines but most are certified by PHMSA to assume responsibility for enforcing intrastate pipeline safety regulations and inspecting intrastate pipelines. In practice, because states can adopt stricter standards for intrastate pipelines than those imposed byis developing implementation plans as a result of the federal government for interstate lines, they vary considerably in their authority and capacity to address pipeline safety.rulemaking.
Pipeline Integrity Regulations
We have an enterprise-wide Gas Integrity Management Plan that we believe meets the PHMSA final rule that was issued pursuant to the requirements of the Pipeline Safety Improvement Act of 2002. The rule requiresrules require gas pipeline operators to develop an integrity management program for gas transmission pipelines that could affect high-consequence areasHCAs in the event of pipeline failure. The integrity management program includes a baseline assessment plan along with periodic reassessments to be completed within required time frames. In meeting the integrity regulations, we have identified high-consequence areasHCAs and developed baseline assessment plans. Ongoing periodic reassessments and initial assessments of any new high-consequence areasHCAs have been completed. Also, in response to the portion of the Mega Rule implemented in 2021, we have identified Moderate Consequence Areas, and Class 3 and 4 pipeline locations required by the rule and integrated those segments into our integrity program, and have begun scheduling required assessments and reassessments as needed to meet the regulatory timelines.We estimate that the cost to be incurred in 20202023 associated with this program to be approximately $133$126 million. Management considers costs associated with compliance with the rule to be prudent costs incurred in the ordinary course of business and, therefore, recoverable through Northwest Pipeline’s and Transco’s rates.
We have an enterprise-wide Liquid Integrity Management Plan that we believe meets the PHMSA final rule that was issued pursuant to the requirements of the Pipeline Safety Improvement Act of 2002. The rule requires liquid pipeline operators to develop an integrity management program for liquid transmission pipelines that could affect high-consequence areasHCAs in the event of pipeline failure. The integrity management program includes a baseline assessment plan along with periodic reassessments expected to be completed within required time frames. In meeting the integrity regulations, we utilized government defined high-consequence areasHCAs and developed baseline assessment plans. We completed assessments within the required time frames. We estimate that the cost to be incurred in 20202023 associated with this program will be approximately $2$10 million. Ongoing periodic reassessments and initial assessments of any new high-consequence areasHCAs are expected to be completed within the time frames required by the rule. Management considers the costs associated with compliance with the rule to be prudent costs incurred in the ordinary course of business.
Cybersecurity Matters
The Transportation Security Administration (TSA) issued Security Directive Pipeline-2021-01B (Security Directive 1B) on May 29, 2022, which requires that owners/operators of critical pipelines (1) report cybersecurity incidents to the Cybersecurity and Infrastructure Agency (CISA) within 24 hours; (2) appoint a cybersecurity coordinator to coordinate with TSA and CISA; and (3) conduct a self-assessment of cybersecurity practices, identify any gaps, and develop a plan and timeline for remediation. On July 27, 2022, the TSA issued Security Directive Pipeline-2021-02C (Security Directive 2C), which requires owners/operators of critical pipelines to (1) establish and implement a TSA-approved Cybersecurity Implementation Plan that describes the specific cybersecurity measures employed and the schedule for achieving the cybersecurity outcomes described in Security Directive 2C; (2) develop and maintain a Cybersecurity Incident Response Plan to reduce the risk of operational disruption or other significant impacts from a cybersecurity incident; and (3) establish a Cybersecurity Assessment Program and submit an annual plan describing how the effectiveness of cybersecurity measures will be assessed. We have established and received TSA approval for our Cybersecurity Implementation Plan and are compliant with the remaining requirements established in Security Directives 1B and 2C. New regulations or security directives issued by TSA may impose additional requirements applicable to our cybersecurity program, which could cause us to incur increased capital and operating costs and operational delays.
See Part I, Item 1A. “Risk Factors” — “A breach of our information technology infrastructure, including a breach caused by a cybersecurity attack on us or third parties with whom we are interconnected, may interfere with the safe operation of our assets, result in the disclosure of personal or proprietary information, and harm our reputation.”
State Gathering Regulations
Our onshore midstream gathering operations are subject to laws and regulations in the various states in which we operate. For example, the Texas Railroad Commission has the authority to regulate the terms of service for our intrastate natural gas gathering business in Texas. Although the applicable state regulations vary widely, they generally require that pipeline rates and practices be reasonable and nondiscriminatory, and may include provisions covering marketing, pricing, pollution, environment, and human health and safety. Some states, such as New York and Ohio, have specific regulations pertaining to the design, construction, and operations of gathering lines within such state.
Intrastate Liquids Pipelines in the Gulf Coast
Our intrastate liquids pipelines in the Gulf Coast are regulated by the Louisiana Public Service Commission,Department of Natural Resources, the Texas Railroad Commission, and various other state and federal agencies. These pipelines are also subject to the liquid pipeline safety and integrity regulations discussed above since both Louisiana and Texas have adopted the integrity management regulations defined in PHMSA.
OCSLA
Our offshore gas and liquids pipelines located on the outer continental shelf are subject to the Outer Continental Shelf Lands Act, which provides in part that outer continental shelf pipelines “must provide open and nondiscriminatory access to both owner and nonownernon-owner shippers.”
See Part II, Item 8. Financial Statements and Supplementary Data — Note 19 – Contingent Liabilities and Commitments of Notes to Consolidated Financial Statements for further details on our regulatory matters. For additional information regarding regulatory matters, please also refer to Part 1,I, Item 1A. “Risk Factors” — “The operation of our businesses might be adversely affected by regulatory proceedings, changes in government regulations or in their
interpretation or implementation, or the introduction of new laws or regulations applicable to our businesses or our customers,” and “The“The natural gas sales, transportation, and storage operations of our gas pipelines are subject to regulation by the FERC, which could have an adverse impact on their ability to establish transportation and storage rates that would allow them to recover the full cost of operating their respective pipelines and storage assets, including a reasonable rate of return.”
ENVIRONMENTAL MATTERS
Our operations are subject to federal environmental laws and regulations as well as the state, local, and tribal laws and regulations adopted by the jurisdictions in which we operate. We could incur liability to governments or third parties for any unlawful discharge of pollutants into the air, soil, or water, as well as liability for cleanup costs. Materials could be released into the environment in several ways including, but not limited to:
•Leakage from gathering systems, underground gas storage caverns, pipelines, processing or treating facilities, transportation facilities, and storage tanks;
•Damage to facilities resulting from accidents during normal operations;
•Damages to onshore and offshore equipment and facilities resulting from storm events or natural disasters;
•Blowouts, cratering, and explosions.
In addition, we may be liable for environmental damage caused by former owners or operators of our properties.
We believe compliance with current environmental laws and regulations will not have a material adverse effect on our capital expenditures, earnings, or current competitive position. However, environmental laws and regulations could affect our business in various ways from time to time, including incurring capital and maintenance expenditures, fines and penalties, and creating the need to seek relief from the FERC for rate increases to recover the costs of certain capital expenditures and operation and maintenance expenses.
For additional information regarding the potential impact of federal, state, tribal, or local regulatory measures on our business and specific environmental issues, please refer to Part 1, Item 1A. “Risk Factors” — “Our operations are subject to environmental laws and regulations, including laws and regulations relating to climate change and greenhouse gas emissions, which may expose us to significant costs, liabilities, and expenditures that could exceed our expectations,” and Part II, Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Environmental” and “Environmental Matters” in Part II, Item 8. Financial Statements and Supplementary Data — Note 1917 – Contingent Liabilities and Commitments of Notes to Consolidated Financial Statements.
COMPETITION
Gas Pipeline Business
The market for supplying natural gas is highly competitiveGathering and new pipelines, storage facilities, and other related services are expanding to service the growing demand for natural gas. Additionally, pipeline capacity in many growing natural gas supply basins is constrained causing competition to increase among pipeline companies as they strive to connect those basins to major natural gas demand centers.
In our business, we predominately compete with major intrastate and interstate natural gas pipelines. In the last few years, local distribution companies have also started entering into the long-haul transportation business through joint venture pipelines. The principle elements of competition in the interstate natural gas pipeline business are based on rates, reliability, quality of customer service, diversity of supply, and proximity to customers and market hubs.
Significant entrance barriers to build new pipelines exist, including federal and growing state regulations and public opposition against new pipeline builds, and these factors will continue to impact potential competition for the foreseeable future. However, we believe our past success in working with regulators and the public, the position of our existing infrastructure, established strategic long-term contracts, and the fact that our pipelines have numerous receipt and
delivery points along our systems provide us a competitive advantage, especially along the eastern seaboard and northwestern United States.
Midstream BusinessProcessing
Competition for natural gas gathering, processing, treating, transporting,transportation, and storing natural gasstorage, as well as NGLs transportation, fractionation, and storage continues to increase as production from shales and other resource areas continues to grow. Our midstream services compete with similar facilities that are in the same proximity as our assets.
We face competition from companies of varying size and financial capabilities, including major and independent natural gas midstream providers, private equity firms, and major integrated oil and natural gas companies that gather, transport, process, fractionate, store, and market natural gas and NGLs, as well as some larger exploration and production companies that are choosing to develop midstream services to handle their own natural gas.
Our gathering and processing agreements are generally long-term agreements that may include acreage dedication. Competition for natural gas volumes is primarily based on reputation, commercial terms (products retained or fees charged), array of services provided, efficiency and reliability of services, location of gathering facilities, available capacity, downstream interconnects, and latent capacity. We believe our significant presence in traditional prolific supply basins, our solid positions in growing shale plays, our expertise and reputation as a reliable operator, and our ability to offer integrated packages of services position us well against our competition.
Regulated Interstate Natural Gas Transportation and Storage
The market for supplying natural gas is highly competitive and new pipelines, storage facilities, and other related services are expanding to service the growing demand for natural gas. Additionally, pipeline capacity in many growing natural gas supply basins is constrained causing competition to increase among pipeline companies as they strive to connect those basins to major natural gas demand centers.
In our business, we predominately compete with major intrastate and interstate natural gas pipelines. In the last few years, local distribution companies have also started entering into the long-haul transportation business through joint venture pipelines.The principle elements of competition in the interstate natural gas pipeline business are based on capacity available, rates, reliability, quality of customer service, diversity of supply, and proximity to customers and market hubs.
We face competition in a number of our key markets and we compete with other interstate and intrastate pipelines for deliveries to customers who can take deliveries at multiple points. Natural gas delivered on our system competes with alternative energy sources used to generate electricity such as hydroelectric power, coal, fuel oil, and nuclear. Future demand for natural gas within the power sector could be increased by regulations limiting or discouraging coal use or could be adversely affected by laws mandating or encouraging renewable power sources.
Significant entrance barriers to build new pipelines exist, including federal and growing state regulations and public opposition against new pipeline builds, and these factors will continue to impact potential competition for the foreseeable future. However, we believe our past success in working with regulators and the public, the position of our existing infrastructure, established strategic long-term contracts, and the fact that our pipelines have numerous receipt and delivery points along our systems provide us a competitive advantage, especially along the eastern seaboard and northwestern United States.
Energy Management and Marketing Services
Our Gas & NGL Marketing Services segment competes with national and regional full-service energy providers, producers, and pipelines marketing affiliates or other marketing companies that aggregate commodities with transportation and storage capacity.
For additional information regarding competition for our services or otherwise affecting our business, please refer to Part 1, Item 1A. “Risk Factors” - “The financial condition of our natural gas transportation and midstream businesses is dependent on the continued availability of natural gas supplies in the supply basins that we access and demand for those supplies in the markets we serve,” “Our industry is highly competitive and increased competitive pressure could adversely affect our business and operating results,” and “We may not be able to replace, extend, or add additional customer contracts or contracted volumes on favorable terms, or at all, which could affect our financial condition, the amount of cash available to pay dividends, and our ability to grow.”
EMPLOYEESHUMAN CAPITAL RESOURCES
At
We are committed to maintaining a work environment that enables us to attract, develop, and retain a highly skilled and diverse group of talented employees who help promote long-term value creation.
Employees
As of February 1, 2020,2023, we had 4,8125,043 full-time employees.employees located throughout the United States. Of this total, approximately 22 percent are women and 17 percent are ethnically diverse. During 2022, our voluntary turnover rate was 7.7 percent.
We encourage you to review our 2021 Sustainability Report available on our website for more information about our human capital programs and initiatives. Nothing on our website shall be deemed incorporated by reference into this Annual Report on Form 10-K.
Workforce Safety
We continue to advance our safety-first culture by developing and empowering our employees to operate our assets in a safe, reliable, and customer-focused way.We strive to continuously improve safety and work towards zero safety incidents. When a safety hazard is recognized, every employee is empowered to stop work activities, make changes to enhance safety, and share the lessons learned with the organization on how we made it right.
For 2021, safety and environmental-focused goals and related metrics comprised 10 percent of our annual incentive program for employees, and included our Loss of Primary Containment Events Reduction and High Potential Near Miss to Incident Ratio.
For 2022, these goals included our Loss of Primary Containment Events Reduction, a new Behavioral Near Miss to Incident Ratio goal aimed to focus attention on behaviors that are the leading causes of incidents, as well as a new Methane Emissions Reduction goal focusing on our efforts to reduce greenhouse gas emissions. These three metrics comprise 15 percent of our annual incentive program for employees, and reinforce the importance of incident prevention and our commitment to environmental and safety-focused improvements.
For 2022, our Behavioral Near Miss to Incident Ratio and Methane Emissions Reduction goals outperformed the established targets, and while Loss of Primary Containment Events were reduced, they fell short of the overall reduction target.
Workforce Health, Engagement, and Development
Our employees are our most valued resource, are instrumental in our mission to safely deliver products that fuel the clean energy economy, and are the driving force behind our reputation as a safe, reliable company that does the right thing, every time. Cultivating a healthy work environment increases productivity and promotes long-term value creation.
We provide a comprehensive total rewards program that includes base salary, an all-employee annual incentive program, retirement benefits, and health benefits, including wellness and employee assistance programs. We provide employees with company-paid life insurance, disability coverage, and paid parental leave for both birth and non-birth parents, as well as adoption assistance. Our annual incentive program is a key component of our commitment to a performance culture focused on recognizing and rewarding high performance.
In order to attract and retain top talent, we create and are committed to maintaining a safe, inclusive workplace where employees feel valued, heard, respected, and supported in their personal and professional development. Our Employee Development Council is a cross-functional, cross-enterprise advisory board that works to understand the needs of the business by providing input on, and advocating for, employee development initiatives. Additionally, we support strong employee engagement by encouraging open dialogue regarding professional development and succession planning.
We offer robust corporate and technical training programs to support the professional development of our employees and add long-term value to our business. Our Learning and Training Council defines and maintains an agile governance structure that ensures training plans are effective and aligned to business needs and employee development. Performance is measured considering both the achieved results associated with attaining annual goals and observable skills and behaviors based on our defined competencies that contribute to workplace effectiveness and career success. Including the defined competencies in our annual performance program illustrates our emphasis on, and commitment to, achieving results in the right way.
Additionally, we are committed to strengthening the communities where we operate through philanthropic giving and volunteerism. We support Science, Technology, Engineering, and Math education initiatives, environmental conservation and first responder efforts, and the work of United Way agencies across the United States.
The Compensation and Management Development Committee of our Board of Directors oversees the establishment and administration of our compensation programs, including incentive compensation and equity-based plans, as well as the oversight of human capital management, including diversity and inclusion, and development.
Diversity & Inclusion
We are committed to creating an inclusive culture, where differences are embraced and employees feel valued, welcomed, appreciated, and compelled to reach their full potential. We believe that inclusion fosters innovation, collaboration, and drives business growth and long-term success. To create a culture of inclusion, we embrace, appreciate, and fully leverage the diversity within our teams, including gender, race and ethnicity, life experiences, thoughts, perspectives, and anything that makes us different from one another. We believe that incorporating our many differences into a team of people who are working toward the same goal gives us a competitive advantage.
To create space for employees to share personal experiences and perspectives, and to appreciate and celebrate what makes people different, we offer Employee Resource Groups (ERGs). These groups are employee-led and based on similar interests and experiences, represent diverse communities and their allies, and are open to everyone. ERG members participate in community events, volunteer, lend professional and personal support to one another, and promote inclusion across the company. They also provide input to the leadership team.
We are committed to helping all employees develop and succeed. We strive for diverse representation at all levels of the organization through our talent management practices and employee development programs, including required baseline diversity and inclusion training for all leaders across the company. Diversity metrics are reported monthly to our management team to enhance transparency and opportunities for improvement.
Our Diversity and Inclusion Council, which includes members of the executive officer team, organizational and operational leaders, and individual employees, promotes policies, practices, and procedures that support the growth of a high-performing workforce where all individuals can achieve their full potential. The council serves as the governing body over enterprise diversity and inclusion initiatives, including a quarterly candid conversation meeting for all employees, 10 active ERGs, and annual awards that recognize an outstanding leader and an individual contributor who champion inclusion.
As of December 31, 2022, our Board of Directors includes 12 members, 11 of whom are independent members, and one-quarter of which are women. As part of the director selection and nominating process, the Governance and Sustainability Committee annually assesses the Board’s diversity in areas such as geography, gender, race and ethnicity, and age. We strive to maintain a board of directors with diverse occupational and personal backgrounds.
WEBSITE ACCESS TO REPORTS AND OTHER INFORMATION
We file our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, proxy statements, and other documents electronically with the SEC under the Exchange Act.
Our Internet website is www.williams.com. We make available, free of charge, through the Investors tab of our Internet website our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8‑K, and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC. Our Corporate Governance Guidelines, Sustainability Report, Code of Ethics for Senior Officers, Board committee charters, and the Williams Code of Business Conduct are also available on our Internet website. We will also provide, free of charge, a copy of any of our corporate documents listed above upon written request to our Corporate Secretary, One Williams Center, Suite 4700, Tulsa, Oklahoma 74172.
Item 1A. Risk Factors
FORWARD-LOOKING STATEMENTS AND CAUTIONARY STATEMENT
FOR PURPOSES OF THE “SAFE HARBOR” PROVISIONS OF
THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995
The reports, filings, and other public announcements of Williams may contain or incorporate by reference statements that do not directly or exclusively relate to historical facts. Such statements are “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (Securities Act) and Section 21E of the Securities Exchange Act of 1934, as amended.Act. These forward-looking statements relate to anticipated financial performance, management’s plans and objectives for future operations, business prospects, outcomeoutcomes of regulatory proceedings, market conditions, and other matters as discussed below.matters. We make these forward-looking statements in reliance on the safe harbor protections provided under the Private Securities Litigation Reform Act of 1995.
All statements, other than statements of historical facts, included in this report that address activities, events, or developments that we expect, believe, or anticipate will exist or may occur in the future, are forward-looking statements. Forward-looking statements can be identified by various forms of words such as “anticipates,” “believes,” “seeks,” “could,” “may,” “should,” “continues,” “estimates,” “expects,” “forecasts,” “intends,” “might,” “goals,” “objectives,” “targets,” “planned,” “potential,” “projects,” “scheduled,” “will,” “assumes,” “guidance,” “outlook,” “in-service date,” or other similar expressions. These forward-looking statements are based on management’s beliefs and assumptions and on information currently available to management and include, among others, statements regarding:
•Levels of dividends to Williams stockholders;
•Future credit ratings of Williams and its affiliates;
•Amounts and nature of future capital expenditures;
•Expansion and growth of our business and operations;
•Expected in-service dates for capital projects;
•Financial condition and liquidity;
•Business strategy;
•Cash flow from operations or results of operations;
•Seasonality of certain business components;
•Natural gas, and natural gas liquids, and crude oil prices, supply, and demand;
•Demand for our services.
Forward-looking statements are based on numerous assumptions, uncertainties, and risks that could cause future events or results to be materially different from those stated or implied in this report. Many of the factors that will determine these results are beyond our ability to control or predict. Specific factors that could cause actual results to differ from results contemplated by the forward-looking statements include, among others, the following:
•Availability of supplies, market demand, and volatility of prices;
•Development and rate of adoption of alternative energy sources;
•The impact of existing and future laws and regulations, the regulatory environment, environmental liabilities,matters, and litigation, as well as our ability to obtain necessary permits and approvals, and achieve favorable rate proceeding outcomes;
•Our exposure to the credit risk of our customers and counterparties;
•Our ability to acquire new businesses and assets and successfully integrate those operations and assets into existing businesses as well as successfully expand our facilities and to consummate asset sales on acceptable terms;
•Whether we are able to successfully identify, evaluate, and timely execute our capital projects and investment opportunities;
•The strength and financial resources of our competitors and the effects of competition;
•The amount of cash distributions from and capital requirements of our investments and joint ventures in which we participate;
•Whether we will be able to effectively execute our financing plan;
•Increasing scrutiny and changing expectations from stakeholders with respect to our environmental, social, and governance practices;
•The physical and financial risks associated with climate change;
•The impactimpacts of operational and developmental hazards and unforeseen interruptions;
•Risks associated with weather and natural phenomena, including climate conditions and physical damage to our facilities;
•Acts of terrorism, cybersecurity incidents, and related disruptions;
•Our costs and funding obligations for defined benefit pension plans and other postretirement benefit plans;
•Changes in maintenance and construction costs, as well as our ability to obtain sufficient constructionconstruction- related inputs, including skilled labor;
•Inflation, interest rates, and general economic conditions (including future disruptions and volatility in the global credit markets and the impact of these events on customers and suppliers);
•Risks related to financing, including restrictions stemming from debt agreements, future changes in credit ratings as determined by nationally recognized credit rating agencies, and the availability and cost of capital;
•Changes in the current geopolitical situation;situation, including the Russian invasion of Ukraine;
•Whether we are able to pay current and expected levels of dividends;
•Additional risks described in our filings with the Securities and Exchange Commission.
Given the uncertainties and risk factors that could cause our actual results to differ materially from those contained in any forward-looking statement, we caution investors not to unduly rely on our forward-looking statements. We disclaim any obligations to, and do not intend to, update the above list or announce publicly the result of any revisions to any of the forward-looking statements to reflect future events or developments.
In addition to causing our actual results to differ, the factors listed above and referred to below may cause our intentions to change from those statements of intention set forth in this report. Such changes in our intentions may also cause our results to differ. We may change our intentions, at any time and without notice, based upon changes in such factors, our assumptions, or otherwise.
Because forward-looking statements involve risks and uncertainties, we caution that there are important factors, in addition to those listed above, that may cause actual results to differ materially from those contained in the forward-looking statements. These factors are described in the following section.
RISK FACTORS
You should carefully consider the following risk factors in addition to the other information in this report. Each of these factors could adversely affect our business, prospects, financial condition, results of operations, cash flows, and, in some cases our reputation. The occurrence of any of such risks could also adversely affect the value of an investment in our securities.
Risks Related to Our Business
The financial condition of our natural gas transportation and midstream businesses is dependent on the continued availability of natural gas supplies in the supply basins that we access and demand for those supplies in the markets we serve.
Our ability to maintain and expand our natural gas transportation and midstream businesses depends on the level of drilling and production predominantly by third parties in our supply basins. Production from existing wells and natural gas supply basins with access to our pipeline and gathering systems will naturally decline over time. The amount of natural gas reserves underlying these existing wells may also be less than anticipated, and the rate at which production from these reserves declines may be greater than anticipated. We do not obtain independent evaluations of natural gas reserves connected to our systems and processing facilities. Accordingly, we do not have independent estimates of total reserves dedicated to our systems or the anticipated life of such reserves. In addition, low prices for natural gas, regulatory limitations, including permitting and environmental regulations, or the lack of available capital have, and may continue to, adversely affect the development and production of existing or additional natural gas reserves and the installation of gathering, storage, and pipeline transportation facilities. The import and export of natural gas supplies may also be affected by such conditions. Low natural gas prices in one or more of our existing supply basins, whether caused by a lack of infrastructure or otherwise, could also result in depressed natural gas production in such basins and limit the supply of natural gas made available to us. The competition for natural gas supplies to serve other markets could also reduce the amount of natural gas supply for our customers. A failure to obtain access to sufficient natural gas supplies will adversely impact our ability to maximize the capacities of our gathering, transportation, and processing facilities.
Demand for our services is dependent on the demand for gas in the markets we serve. Alternative fuel sources such as electricity, coal, fuel oils, or nuclear energy, as well as technological advances and renewable sources of energy, could reduce demand for natural gas in our markets and have an adverse effect on our business.
A failure to obtain access to sufficient natural gas supplies or a reduction in demand for our services in the markets we serve could result in impairments of our assets and have a material adverse effect on our business, financial condition, results of operations, and cash flows.
Prices for natural gas, NGLs, oil, and other commodities, are volatile and this volatility has and could continue to adversely affect our financial condition, results of operations, cash flows, access to capital, and ability to maintain or grow our existing businesses.
Our revenues, operating results, future rate of growth, and the value of certain components of our businesses depend primarily upon the prices of natural gas, NGLs, oil, or other commodities, and the differences between prices of these commodities and could be materially adversely affected by an extended period of low commodity prices, or a decline in commodity prices. Price volatility has and could continue to impact both the amount we receive for our products and services and the volume of products and services we sell. Prices affect the amount of cash flow available for capital expenditures and our ability to borrow money or raise additional capital. Price volatility has had and could continue to have an adverse effect on our business, results of operations, financial condition, and cash flows.
The markets for natural gas, NGLs, oil, and other commodities are likely to continue to be volatile. Wide fluctuations in prices might result from one or more factors beyond our control, including:
Worldwide•Imbalances in supply and demand whether rising from worldwide or domestic supplies of and demand for natural gas, NGLs, oil, and related commodities;
Turmoil•Geopolitical turmoil in the Middle East, Eastern Europe, and other producing regions;
•The activities of the OrganizationOPEC and other countries, whether acting independently of Petroleum Exporting Countries;or informally aligned with OPEC, which have significant oil, natural gas or other commodity production capabilities, including Russia;
•The level of consumer demand;
•The price and availability of other types of fuels or feedstocks;
•The availability of pipeline capacity;
•Supply disruptions, including plant outages and transportation disruptions;
•The price and quantity of foreign imports and domestic exports of natural gas and oil;
•Domestic and foreign governmental regulations and taxes;
•The credit of participants in the markets where products are bought and sold.
We are exposed to the credit risk of our customers and counterparties, and our credit risk management will not be able to completely eliminate such risk.
We are subject to the risk of loss resulting from nonpayment and/or nonperformance by our customers and counterparties in the ordinary course of our business. Generally, our customers are rated investment grade, are otherwise considered creditworthy, are required to make prepayments or provide security to satisfy credit concerns, or are dependent upon us, in some cases without a readily available alternative, to provide necessary services. However, our credit procedures and policies cannot completely eliminate customer and counterparty credit risk. Our customers and counterparties include industrial customers, local distribution companies, natural gas producers, and marketers whose creditworthiness may be suddenly and disparately impacted by, among other factors, commodity price volatility, deteriorating energy market conditions, and public and regulatory opposition to energy producing activities. In a low commodity price environment, certain of our customers have been or could be negatively impacted, causing them significant economic stress resulting, in some cases, in a customer bankruptcy filing or an effort to renegotiate our contracts. To the extent one or more of our key customers commences bankruptcy proceedings, our contracts with thesuch customers may be subject to rejection under applicable provisions of the United States Bankruptcy Code or, if we so agree, may be renegotiated. Further, during any such bankruptcy proceeding, prior to assumption, rejection, or renegotiation of such contracts, the bankruptcy court may temporarily authorize the payment of value for our services less than contractually required, which could have a material adverse effect on our business, financial condition, results
of operations, cash flows, and cash flows.financial condition. If we fail to adequately assess the creditworthiness of existing or future customers and counterparties or otherwise do not take or are unable to take sufficient mitigating actions, including obtaining sufficient collateral, deterioration in their creditworthiness and any resulting increase in nonpayment and/or nonperformance by them could cause us to write down or write off accounts receivable. Such write-downs or write-offs could negatively affect our operating results infor the periodsperiod in which they occur, and, if significant, could have a material adverse effect on our business, financial condition, results of operations, and cash flows.
We face opposition to operation and expansion of our pipelines and facilities from various individuals and groups.
We have experienced, and we anticipate that we will continue to face, opposition to the operation and expansion of our pipelines and facilities from governmental officials, environmental groups, landowners, tribal groups, local groups, and other advocates. In some instances, we encounter opposition whichthat disfavors hydrocarbon-based energy supplies regardless of practical implementation or financial considerations. Opposition to our operation and expansion can take many forms, including the delay or denial of required governmental permits, organized protests, attempts to block or sabotage our operations, intervention in regulatory or administrative proceedings involving our assets, or lawsuits or other actions designed to prevent, disrupt, or delay the operation or expansion of our assets and business. In addition, acts of sabotage or eco-terrorism could cause significant damage or injury to people, property, or the environment or lead to extended interruptions of our operations. Any such event that delays or prevents the expansion of our business, that interrupts the revenues generated by our operations, or which causes us to make
significant expenditures not covered by insurance, could adversely affect our financial condition and results of operations.
We may not be able to grow or effectively manage our growth.
As part of our growth strategy, we consider acquisition opportunities and engage in significant capital projects. We have both a project lifecycle process and an investment evaluation process. These are processes we use to identify, evaluate, and execute on acquisition opportunities and capital projects. We may not always have sufficient and accurate information to identify and value potential opportunities and risks or our investment evaluation process may be incomplete or flawed. Regarding potential acquisitions, suitable acquisition candidates or assets may not be available on terms and conditions we find acceptable or, where multiple parties are trying to acquire an acquisition candidate or assets, we may not be chosen as the acquirer. If we are able to acquire a targeted business, we may not be able to successfully integrate the acquired businesses and realize anticipated benefits in a timely manner.
Our growth may also be dependent upon the construction of new natural gas gathering, transportation, compression, processing, or treating pipelines and facilities, NGL transportation, or fractionation or storage facilities as well as the expansion of existing facilities. Additional risks associated with construction may include the inability to obtain rights-of-way, skilled labor, equipment, materials, permits, and other required inputs in a timely manner such that projects are completed, on time or at all, and the risk that construction cost overruns, including due to inflation, could cause total project costs to exceed budgeted costs. Additional risks associated with growing our business include, among others, that:
•Changing circumstances and deviations in variables could negatively impact our investment analysis, including our projections of revenues, earnings, and cash flow relating to potential investment targets, resulting in outcomes whichthat are materially different than anticipated;
•We could be required to contribute additional capital to support acquired businesses or assets;
Weassets, and we may assume liabilities that were not disclosed to us, that exceed our estimates and for which contractual protections are either unavailable or prove inadequate;
•Acquisitions could disrupt our ongoing business, distract management, divert financial and operational resources from existing operations, and make it difficult to maintain our current business standards, controls, and procedures;
•Acquisitions and capital projects may require substantial new capital, including proceeds from the issuance of debt or equity, and we may not be able to access credit or capital markets or obtain acceptable terms.
If realized, any of these risks could have an adverse impact on our financial condition, results of operations, including the possible impairment of our assets, or cash flows.
Our industry is highly competitive and increased competitive pressure could adversely affect our business and operating results.
We have numerous competitors in all aspects of our businesses, and additional competitors may enter our markets. Any current or future competitor that delivers natural gas, NGLs, or other commodities into the areas that we operate could offer transportation services that are more desirable to shippers than those we provide because of price, location, facilities, or other factors. In addition, current or potential competitors may make strategic acquisitions or have greater financial resources than we do, which could affect our ability to make strategic investments or acquisitions. Our competitors may be able to respond more quickly to new laws or regulations or emerging technologies or to devote greater resources to the construction, expansion, or refurbishment of their facilities than we can. Failure to successfully compete against current and future competitors could have a material adverse effect on our business, results of operations, financial condition, and cash flows.
We do not own 100 percent of the equity interests of certain subsidiaries, including the Partially OwnedNonconsolidated Entities, which may limit our ability to operate and control these subsidiaries. Certain operations, including the Partially OwnedNonconsolidated Entities, are conducted through arrangements that may limit our ability to operate and control these operations.
The operations of our current non-wholly-owned subsidiaries, including the Partially OwnedNonconsolidated Entities, are conducted in accordance with their organizational documents. We anticipate that we will enter into more such
arrangements, including through new joint venture structures or new Partially OwnedNonconsolidated Entities. We may have limited operational flexibility in such current and future arrangements, and we may not be able to control the timing or amount of cash distributions received. In certain cases:
•We cannot control the amount of cash reserves determined to be necessary to operate the business, which reduces cash available for distributions;
•We cannot control the amount of capital expenditures that we are required to fund and we are dependent on third parties to fund their required share of capital expenditures;
•We may be subject to restrictions or limitations on our ability to sell or transfer our interests in the jointly owned assets;
•We may be forced to offer rights of participation to other joint venture participants in the area of mutual interest;
•We have limited ability to influence or control certain day to day activities affecting the operations;
•We may have additional obligations, such as required capital contributions, that are important to the success of the operations.
In addition, conflicts of interest may arise between us, on the one hand, and other interest owners, on the other hand. If such conflicts of interest arise, we may not have the ability to control the outcome with respect to the matter in question. Disputes between us and other interest owners may also result in delays, litigation, or operational impasses.
The risks described above or the failure to continue such arrangements could adversely affect our ability to conduct the operations that are the subject of such arrangements which could, in turn, negatively affect our business, growth strategy, financial condition, and results of operations.
We may not be able to replace, extend, or add additional customer contracts or contracted volumes on favorable terms, or at all, which could affect our financial condition, the amount of cash available to pay dividends, and our ability to grow.
We rely on a limited number of customers and producers for a significant portion of our revenues and supply of natural gas and NGLs. Although many of our customers and suppliers are subject to long-term contracts, if we are unable to replace or extend such contracts, add additional customers, or otherwise increase the contracted volumes of natural gas provided to us by current producers, in each case on favorable terms, if at all, our financial condition, growth plans, and the amount of cash available to pay dividends could be adversely affected. Our ability to replace, extend, or add additional customer or supplier contracts, or increase contracted volumes of natural gas from current producers, on favorable terms, or at all, is subject to a number of factors, some of which are beyond our control, including:
•The level of existing and new competition in our businesses or from alternative sources, such as electricity, renewable resources, coal, fuel oils, or nuclear energy;
•Natural gas and NGL prices, demand, availability, and margins in our markets. Higher prices for energy commodities related to our businesses could result in a decline in the demand for those commodities and, therefore, in customer contracts or throughput on our pipeline systems. Also, lower energy commodity prices could negatively impact our ability to maintain or achieve favorable contractual terms, including pricing, and could also result in a decline in the production of energy commodities resulting in reduced customer contracts, supply contracts, and throughput on our pipeline systems;
•General economic, financial markets, and industry conditions;
•The effects of regulation on us, our customers, and our contracting practices;
•Our ability to understand our customers’ expectations, efficiently and reliably deliver high quality services, and effectively manage customer relationships. The results of these efforts will impact our reputation and positioning in the market.
Certain of our gas pipeline services are subject to long-term, fixed-price contracts that are not subject to adjustment, even if our cost to perform such services exceeds the revenues received from such contracts.
Our gas pipelines provide some services pursuant to long-term, fixed-price contracts. It is possible that costs to perform services under such contracts will exceed the revenues our pipelines collect for their services. Although most of theother services are priced at cost-based rates that are subject to adjustment in rate cases, under FERC policy, a regulated service provider and a customer may mutually agree to sign a contract for service at a “negotiated rate” that may be above or below the FERC regulated cost-based rate for that service. These “negotiated rate” contracts are not generally subject to adjustment for increased costs that could be produced by inflation or other factors relating to the specific facilities being used to perform the services.
Some of our businesses are exposed to supplier concentration risks arising from dependence on a single or a limited number of suppliers.
Some of our businesses may be dependent on a small number of suppliers for delivery of critical goods or services. If a supplier on which one of our businesses depends were to fail to timely supply required goods and services, such business may not be able to replace such goods and services in a timely manner or otherwise on favorable terms or at all. If our business is unable to adequately diversify or otherwise mitigate such supplier concentration risks and such
risks were realized, such businesses could be subject to reduced revenues and increased expenses, which could have a material adverse effect on our financial condition, results of operation, and cash flows.
Failure of our service providers or disruptions to our outsourcing relationships might negatively impact our ability to conduct our business.
Certain of our accounting and information technology services are currently provided by third-party vendors, and sometimes from service centers outside of the United States. Services provided pursuant to these agreementsarrangements could be disrupted. Similarly, the expiration of agreements associated with such agreementsarrangements or the transition of services between providers could lead to loss of institutional knowledge or service disruptions. Our reliance on others as service providers could have a material adverse effect on our business, financial condition, results of operations, and cash flows.
An impairment of our assets, including property, plant, and equipment, intangible assets, and/or equity-method investments, could reduce our earnings.
GAAP requires us to test certain assets for impairment on either an annual basis or when events or circumstances occur which indicate that the carrying value of such assets might be impaired. The outcome of such testing could result in impairments of our assets including our property, plant, and equipment, intangible assets, and/or equity-method investments. Additionally, any asset monetizations could result in impairments if any assets are sold or otherwise exchanged for amounts less than their carrying value. If we determine that an impairment has occurred, we would be required to take an immediate noncash charge to earnings.
Increasing scrutiny and changing expectations from stakeholders with respect to our environmental, social and governance practices may impose additional costs on us or expose us to new or additional risks.
Companies across all industries are facing increasing scrutiny from stakeholders related to their environmental, social and governance (“ESG”) practices. Investor advocacy groups, certain institutional investors, investment funds and other influential investors are also increasingly focused on ESG practices and in recent years have placed increasing importance on the implications and social cost of their investments. Regardless of the industry, investors’ increased focus and activism related to ESG (as proponents or opponents) and similar matters may hinder access to capital, as investors may decide to reallocate capital or to not commit capital as a result of their assessment of a company’s ESG practices. Companies whichthat do not adapt to or comply with investor or other stakeholder expectations and standards, which are evolving, or whichthat are perceived to have not responded appropriately to the growing concern for ESG issues, regardless of whether there is a legal requirement to do so, may suffer from reputational damage, and the business, financial condition, and/or stock price of such a company could be materially and adversely affected.
We face pressures from our stockholders, who are increasingly focused on climate change, to prioritize sustainable energy practices, reduce our carbon footprint, and promote sustainability. Our stockholders may require us to implement ESG procedures or standards in order to continue engaging with us, to remain invested in us or before they may make further investments in us. Additionally, we may face reputational challenges in the event our
ESG procedures or standards do not meet the standards set by certain constituencies. We have adopted certain practices as highlighted in our 20182021 Sustainability Report, including with respect to air emissions, biodiversity and land use, climate change, and environmental stewardship. It is possible, however, that our stockholders might not be satisfied with our sustainability efforts or the speed of their adoption. If we do not meet our stockholders’ expectations, our business, ability to access capital, and/or our stock price could be harmed.
Additionally, adverse effects upon the oil and gas industry related to the worldwide social and political environment,environments, including uncertainty or instability resulting from climate change, changes in political leadership and environmental policies, changes in geopolitical-social views toward fossil fuels and renewable energy, concern about the environmental impact of climate change, and investors’ expectations regarding ESG matters, may also adversely affect demand for our services. Any long-term material adverse effect on the oil and gas industry could have a significant financial and operational adverse impact on our business.
The occurrence of any of the foregoing could have a material adverse effect on the price of our stock and our business and financial condition.
We may be subject to physical and financial risks associated with climate change.
The threat of global climate change may create physical and financial risks to our business. Energy needs vary with weather conditions. To the extent weather conditions may be affected by climate change, energy use could increase or decrease depending on the duration and magnitude of any changes. Increased energy use due to weather changes may require us to invest in more pipelines and other infrastructure to serve increased demand. A decrease in energy use due to weather changes may affect our financial condition through decreased revenues. Extreme weather conditions in general require more system backup, adding to costs, and can contribute to increased system stresses, including service interruptions. Weather conditions outside of our operating territory could also have an impact on our revenues. To the extent the frequency of extreme weather events increases, this could increase our cost of providing service. We may not be able to pass on the higher costs to our customers or recover all costs related to mitigating these physical risks.
Additionally, many climate models indicate that global warming is likely to result in rising sea levels and increased frequency and severity of weather events, which may lead to higher insurance costs, or a decrease in available coverage, for our assets in areas subject to severe weather. These climate-related changes could damage our physical assets, especially operations located in low-lying areas near coasts and river banks, and facilities situated in hurricane-prone and rain-susceptible regions.
To the extent financial markets view climate change and greenhouse gas (“GHG”) emissions as a financial risk, this could negatively impact our cost of and access to capital. Climate change and GHG regulation could also reduce demand for our services. Our business could also be affected by the potential for lawsuits against GHG emitters, based on links drawn between GHG emissions and climate change.
Our operations are subject to operational hazards and unforeseen interruptions.
There are operational risks associated with the gathering, transporting, storage, processing, and treating of natural gas, the fractionation, transportation, and storage of NGLs, and crude oil transportation and production handling, including:
•Aging infrastructure and mechanical problems;
•Damages to pipelines and pipeline blockages or other pipeline interruptions;
•Uncontrolled releases of natural gas (including sour gas), NGLs, crude oil, or other products;
•Collapse or failure of storage caverns;
•Operator error;
•Damage caused by third-party activity, such as operation of construction equipment;
•Pollution and other environmental risks;
•Fires, explosions, craterings, and blowouts;
•Security risks, including cybersecurity;
•Operating in a marine environment.
Any of these risks could result in loss of human life, personal injuries, significant damage to property, environmental pollution, impairment of our operations, loss of services to our customers, reputational damage, and substantial losses to us. The location of certain segments of our facilities in or near populated areas, including residential areas, commercial business centers, and industrial sites, could increase the level of damages resulting from these risks. An event such as those described above could have a material adverse effect on our financial condition and results of operations, particularly if the event is not fully covered by insurance.
We do not insure against all potential risks and losses and could be seriously harmed by unexpected liabilities or by the inability of our insurers to satisfy our claims.
In accordance with customary industry practice, we maintain insurance against some, but not all, risks and losses, and only at levels we believe to be appropriate. The occurrence of any risks not fully covered by our insurance could have a material adverse effect on our business, financial condition, results of operations, and cash flows and our ability to repay our debt.
Our assets and operations, as well as our customers’ assets and operations, can be adversely affected by weather and other natural phenomena.
Our assets and operations, especially those located offshore, and our customers’ assets and operations can be adversely affected by hurricanes, floods, earthquakes, landslides, tornadoes, fires, and other natural phenomena and weather conditions, including extreme or unseasonable temperatures, making it more difficult for us to realize the historic rates of return associated with our assets and operations. A significant disruption in our or our customers’ operations or the occurrence of a significant liability for which we are not fully insured could have a material adverse effect on our business, financial condition, results of operations, and cash flows.
Our business could be negatively impacted by acts of terrorism and related disruptions.
Given the volatile nature of the commodities we transport, process, store, and sell, our assets and the assets of our customers and others in our industry may be targets of terrorist activities. Uncertainty surrounding the Russian invasion of Ukraine, or other sustained military campaigns, may affect our operations in unpredictable ways, including the possibility that infrastructure facilities could be direct targets of, or indirect casualties of, an act of terrorism. 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 produce, process, transport, or distribute natural gas, NGLs, or other commodities. 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 have a material adverse effect on our business, financial condition, results of operations, and cash flows.
A breach of our information technology infrastructure, including a breach caused by a cybersecurity attack on us or third parties with whom we are interconnected, may interfere with the safe operation of our assets, result in the disclosure of personal or proprietary information, and harm our reputation.
We rely on our information technology infrastructure to process, transmit, and store electronic information, including information we use to safely operate our assets. Our Board of Directors has oversight responsibility with regard to assessment of the major risks inherent in our business, including cybersecurity risks, and reviews management’s efforts to address and mitigate such risks, including the establishment and implementation of policies to address cybersecurity threats. We have invested, and expect to continue to invest, significant time, manpower, and capital in our information technology infrastructure. However, the age, operating systems, or condition of our current information technology infrastructure and software assets and our ability to maintain and upgrade such assets could affect our ability to resist cybersecurity threats. While we believe that we maintain appropriate information security policies, practices, and protocols, we regularly face cybersecurity and other security threats to our information technology infrastructure, which could include threats to our operational industrial control systems and safety systems that are used to operate our pipelines, plants, and assets. We face unlawful attempts to gain access to our information technology infrastructure, including coordinated attacks from hackers, whether state-sponsored groups, “hacktivists”, or private individuals. We face the threat of theft and misuse of sensitive data and information, including customer and employee information. We also face attempts to
gain access to information related to our assets through attempts to obtain unauthorized access by targeting acts of deception against individuals with legitimate access to physical locations or information. We also are subject to cybersecurity risks arising from the fact that our business operations are interconnected with third parties, including third-party pipelines, other facilities and our contractors and vendors. In addition, the breach of certain business systems could affect our ability to correctly record, process, and report financial information. Breaches in our information technology infrastructure or physical
facilities, or other disruptions including those arising from theft, vandalism, fraud, or unethical conduct, which may increase as a result of the Russian invasion of Ukraine, 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, and have a material adverse effect on our operations, financial condition, results of operations, and cash flows.
If third-party pipelines and other facilities interconnected to our pipelines and facilities become unavailable to transport natural gas and NGLs or to treat natural gas, our revenues could be adversely affected.
We depend upon third-party pipelines and other facilities that provide delivery options to and from our pipelines and facilities for the benefit of our customers. Because we do not own these third-party pipelines or other facilities, their continuing operation is not within our control. If these pipelines or facilities were to become temporarily or permanently unavailable for any reason, or if throughput were reduced because of testing, line repair, damage to pipelines or facilities, reduced operating pressures, lack of capacity, increased credit requirements or rates charged by such pipelines or facilities or other causes, we and our customers would have reduced capacity to transport, store, or deliver natural gas or NGL products to end use markets or to receive deliveries of mixed NGLs, thereby reducing our revenues. Any temporary or permanent interruption at any key pipeline interconnectinterconnection or in operations on third-party pipelines or facilities that would cause a material reduction in volumes transported on our pipelines or our gathering systems or processed, fractionated, treated, or stored at our facilities could have a material adverse effect on our business, financial condition, results of operations, and cash flows.
Our operating results for certain components of our business might fluctuate on a seasonal basis.
Revenues from certain components of our business can have seasonal characteristics. In many parts of the country, demand for natural gas and other fuels peaks during the winter. As a result, our overall operating results in the future might fluctuate substantially on a seasonal basis. Demand for natural gas and other fuels could vary significantly from our expectations depending on the nature and location of our facilities and pipeline systems and the terms of our natural gas transportation arrangements relative to demand created by unusual weather patterns.
We do not own all of the land on which our pipelines and facilities are located, which could disrupt our operations.
We do not own all of the land on which our pipelines and facilities have been constructed. As such, we are subject to the possibility of increased costs to retain necessary land use. In those instances in which we do not own the land on which our facilities are located, we obtain the rights to construct and operate our pipelinesfacilities and gathering systems on land owned by third parties and governmental agencies for a specific period of time. In addition, some of our facilities cross Native American lands pursuant to rights-of-way of limited terms. We may not have the right of eminent domain over land owned by Native American tribes. Our loss of any of these rights, through our inability to renew right-of-way contracts or otherwise, could have a material adverse effect on our business, financial condition, results of operations, and cash flows.
Our business could be negatively impacted as a result of stockholder activism.
In recent years, stockholder activism, including threatened or actual proxy contests, has been directed against numerous public companies, including ours.
We were the target of a proxy contest from a stockholder activist, which resulted in our incurring significant costs. If stockholder activists were to again take or threaten to take actions against the Company or seek to involve themselves in the governance, strategic direction, or operations of the Company, we could incur significant costs as well as the distraction of management, which could have an adverse effect on our business or financial results. In addition, actions
of activist stockholders may cause significant fluctuations in our stock price based on temporary or speculative market perceptions or other factors that do not necessarily reflect the underlying fundamentals and prospects of our business.
Our costs and funding obligations for our defined benefit pension plans and costs for our other postretirement benefit plans are affected by factors beyond our control.
We have defined benefit pension plans and other postretirement benefit plans. The timing and amount of our funding requirements under the defined benefit pension plans depend upon a number of factors that we control, including changes to pension plan benefits, as well as factors outside of our control, such as asset returns, interest
rates, and changes in pension laws. Changes to these and other factors that can significantly increase our funding requirements could have a significant adverse effect on our financial condition and results of operations.
Failure to attract and retain an appropriately qualified workforce could negatively impact our results of operations.
Events such as an aging workforce without appropriate replacements, mismatch of skill sets to future needs, the challenges of attracting new, qualified workers to the midstream energy industry, or unavailability of contract labor may lead to operating challenges such as lack of resources, loss of knowledge, and a lengthy time period associated with skill development, including with the workforce needs associated with projects and ongoing operations. Failure to hire and adequately obtain replacement employees, including the ability to transfer significant internal historical knowledge and expertise to the new employees, or the future availability and cost of contract labor may adversely affect our ability to manage and operate the businesses. If we are unable to successfully attract and retain an appropriately qualified workforce, results of operations could be negatively impacted.
Holders of our common stock may not receive dividends in the amount expected or any dividends.
We may not have sufficient cash each quarter to pay dividends or maintain current or expected levels of dividends. The actual amount of cash we dividend may fluctuate from quarter to quarter and will depend on various factors, some of which are beyond our control, including:
The amount of cash that our subsidiaries distribute to us;
The amount of cash we generate from our operations, our working capital needs, our level of capital expenditures, and our ability to borrow;
The restrictions contained in our indentures and credit facility and our debt service requirements;
The cost of acquisitions, if any.
A failure either to pay dividends or to pay dividends at expected levels could result in a loss of investor confidence, reputational damage, and a decrease in the value of our stock price.
If there is a determination that the spin-off of WPX Energy, Inc. (WPX) stock to our stockholders is taxable for U.S. federal income tax purposes because the facts, representations or undertakings underlying a U.S. Internal Revenue Service private letter ruling or a tax opinion are incorrect or for any other reason, then we and our stockholders could incur significant income tax liabilities.
In connection with our original separation plan that called for an initial public offering (IPO) of stock of WPX and a subsequent spin-off of our remaining shares of WPX to our stockholders, we obtained a private letter ruling from the IRS and an opinion of our outside tax advisor, to the effect that the distribution by us of WPX shares to our stockholders, and any related restructuring transaction undertaken by us, would not result in recognition for U.S. federal income tax purposes, of income, gain or loss to us or our stockholders under section 355 and section 368(a)(1)(D) of the U.S. Internal Revenue Code of 1986, as amended (Code), except for cash payments made to our stockholders in lieu of fractional shares of WPX common stock. In addition, we received an opinion from our outside tax advisor to the effect
that the spin-off pursuant to our revised separation plan which was ultimately consummated on December 31, 2011, which did not involve an IPO of WPX shares, would not result in the recognition, for federal income tax purposes, of income, gain, or loss to us or our stockholders under section 355 and section 368(a)(1)(D) of the Code, except for cash payments made to our stockholders in lieu of fractional shares of WPX. The private letter ruling and opinion have relied on or will rely on certain facts, representations, and undertakings from us and WPX regarding the past and future conduct of the companies’ respective businesses and other matters. If any of these facts, representations, or undertakings are, or become, incorrect or are not otherwise satisfied, including as a result of certain significant changes in the stock ownership of us or WPX after the spin-off, or if the IRS disagrees with any such facts and representations upon audit, we and our stockholders may not be able to rely on the private letter ruling or the opinion of our tax advisor and could be subject to significant income tax liabilities.
Risks Related to Financing Our Business
DowngradesA downgrade of our credit ratings, which are determined outside of our control by independent third parties, could impact our liquidity, access to capital, and our costs of doing business.
Downgrades of our credit ratings increase our cost of borrowing and could require us to provide collateral to our counterparties, negatively impacting our available liquidity. In addition, our ability to access capital markets could continue to be limited by the downgrading of our credit ratings.
Credit rating agencies perform independent analysis when assigning credit ratings. ThisThe analysis includes a number of criteria such as, business composition, market and operational risks, as well as various financial tests. Credit rating agencies continue to review the criteria for industry sectors and various debt ratings and may make changes to those criteria from time to time. Credit ratings are subject to revision or withdrawal at any time by the ratings agencies. As of the date of the filing of this report, we have been assigned an investment-grade credit rating by each of the three credit ratings agencies.
Difficult conditions in the global financial markets and the economy in general could negatively affect our business and results of operations.
Our businesses may be negatively impacted by adverse economic conditions or future disruptions in the global financial markets. Included among these potential negative impacts are industrial or economic contraction (including as a result of the COVID-19 pandemic) leading to reduced energy demand and lower prices for our products and services and increased difficulty in collecting amounts owed to us by our customers. The ongoing Russian invasion of Ukraine and the actions undertaken by western nations in response to Russia’s actions has had, and may continue to have, adverse impacts on global financial markets. If financing is not available when needed, or is available only on unfavorable terms, we may be unable to implement our business plans or otherwise take advantage of business opportunities or respond to competitive pressures. In addition, financial markets have periodically been affected by concerns over U.S. fiscal and monetary policies. These concerns, as well as actions taken by the U.S. federal government in response to these concerns, could significantly and adversely impact the global and U.S. economies and financial markets, which could negatively impact us in the manner described above.
Restrictions in our debt agreements and the amount of our indebtedness may affect our future financial and operating flexibility.
Our total outstanding long-term debt (including current portion) as of December 31, 2019,2022, was $22.3$22.6 billion.
The agreements governing our indebtedness contain covenants that restrict our and our material subsidiaries’ ability to incur certain liens to support indebtedness and our ability to merge or consolidate or sell all or substantially all of our assets in certain circumstances. In addition, certain of our debt agreements contain various covenants that restrict or limit, among other things, our ability to make certain distributions during the continuation of an event of default, the ability of our subsidiaries to incur additional debt, and our, and our material subsidiaries’, ability to enter into certain affiliate transactions and certain restrictive agreements. Certain of our debt agreements also contain, and those we enter into in the future may contain, financial covenants, and other limitations with which we will need to comply.
Our debt service obligations and the covenants described above could have important consequences. For example, they could:
•Make it more difficult for us to satisfy our obligations with respect to our indebtedness, which could in turn result in an event of default on such indebtedness;
•Impair our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions, general corporate purposes, or other purposes;
•Diminish our ability to withstand a continued or future downturn in our business or the economy generally;
•Require us to dedicate a substantial portion of our cash flow from operations to debt service payments, thereby reducing the availability of cash for working capital, capital expenditures, acquisitions, the payments of dividends, general corporate purposes, or other purposes;
•Limit our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate, including limiting our ability to expand or pursue our business activities and preventing us from engaging in certain transactions that might otherwise be considered beneficial to us.
Our ability to comply with our debt covenants, to repay, extend, or refinance our existing debt obligations and to obtain future credit will depend primarily on our operating performance. Our ability to refinance existing debt obligations or obtain future credit will also depend upon the current conditions in the credit markets and the availability of credit generally. If we are unable to comply with these covenants, meet our debt service obligations, or obtain future credit on favorable terms, or at all, we could be forced to restructure or refinance our indebtedness, seek additional equity capital or sell assets. We may be unable to obtain financing or sell assets on satisfactory terms, or at all.
Our failure to comply with the covenants in the documents governing our indebtedness could result in events of default, which could render such indebtedness due and payable. We may not have sufficient liquidity to repay our indebtedness in such circumstances. In addition, cross-default or cross-acceleration provisions in our debt agreements could cause a default or acceleration to have a wider impact on our liquidity than might otherwise arise from a default or acceleration of a single debt instrument. For more information regarding our debt agreements, please read Note 1512 – Debt and Banking Arrangements of Notes to Consolidated Financial Statements.
Changes to interest rates or increases in interest rates could adversely impact our access to credit, share price, our ability to issue securities or incur debt for acquisitions or other purposes, and our ability to make cash dividends at our intended levels.
Interest rates may increase in the future. As a result, interest rates on future credit facilities and debt offerings could be higher than current levels, causing our financing costs to increase accordingly. As with other yield-oriented securities, our share price will be impacted by the level of our dividends and implied dividend yield. The dividend yield is often used by investors to compare and rank yield-oriented securities for investment decision-making purposes. Therefore, changes in interest rates, either positive or negative, may affect the yield requirements of investors who invest in our shares, and a rising interest rate environment could have an adverse impact on our share price and our ability to issue equity or incur debt for acquisitions or other purposes and to pay cash dividends at our intended levels.
Our hedging activities might not be effective and could increase the volatility of our results.
In an effort to manage our financial exposure related to commodity price and market fluctuations, we have entered, and may in the future enter into contracts to hedge certain risks associated with our assets and operations. In these hedging activities, we have used, and may in the future use, fixed-price, forward, physical purchase, and sales contracts, futures, financial swaps, and option contracts traded in the over-the-counter markets or on exchanges. Nevertheless, no single hedging arrangement can adequately address all risks present in a given contract. For example, a forward contract that would be effective in hedging commodity price volatility risks would not hedge the contract’s counterparty
credit or performance risk. Therefore, unhedged risks will always continue to exist. While we attempt to manage counterparty credit risk within guidelines established by our credit policy, we may not be able to successfully manage all credit risk and as such, future cash flows and results of operations could be impacted by counterparty default. The difference in accounting treatment for the underlying position and the financial instrument used to hedge the value of the contract can cause volatility in our reported net income while the positions are open due to mark-to-market accounting.
Our and our customers’ access to capital could be affected by financial institutions’ policies concerning fossil- fuel related businesses.
Public concern regarding the potential effects of climate change have directed increased attention towards the funding sources of fossil-fuel energy companies. As a result, certain financial institutions, funds, and other sources of capital have restricted or eliminated their investment in certain market segments of fossil-fuel related energy. Ultimately, limiting fossil-fuel related companies’ access to capital could make it more difficult for our customers to
secure funding for exploration and production activities or for us to secure funding for growth projects. Such a lack of capital could also both indirectly affect demand for our services and directly affect our ability to fund construction or other capital projects.
Risks Related to Regulations
The operation of our businesses might be adversely affected by regulatory proceedings, changes in government regulations or in their interpretation or implementation, or the introduction of new laws or regulations applicable to our businesses or our customers.
Public and regulatory scrutiny of the energy industry has resulted in the proposal and/or implementation of increased regulations. Such scrutiny has also resulted in various inquiries, investigations, and court proceedings, including litigation of energy industry matters. Both the shippers on our pipelines and regulators have rights to challenge the rates we charge under certain circumstances. Any successful challenge could materially affect our results of operations.
Certain inquiries, investigations, and court proceedings are ongoing. Adverse effects may continue as a result of the uncertainty of ongoing inquiries, investigations, and court proceedings, or additional inquiries and proceedings by federal or state regulatory agencies or private plaintiffs. In addition, we cannot predict the outcome of any of these inquiries or whether these inquiries will lead to additional legal proceedings against us, civil or criminal fines and/or penalties, or other regulatory action, including legislation, which might be materially adverse to the operation of our business and our results of operations or increase our operating costs in other ways. Current legal proceedings or other matters, including environmental matters, suits, regulatory appeals, and similar matters might result in adverse decisions against us which, among other outcomes, could result in the imposition of substantial penalties and fines and could damage our reputation. The result of such adverse decisions, either individually or in the aggregate, could be material and may not be covered fully or at all by insurance.
In addition, existing regulations, including those pertaining to financial assurances to be provided by our businesses in respect of potential asset decommissioning and abandonment activities, might be revised, reinterpreted, or otherwise enforced in a manner whichthat differs from prior regulatory action. New laws and regulations, including those pertaining to oil and gas hedging and cash collateral requirements, might also be adopted or become applicable to us, our customers, or our business activities. The change in the U.S. governmental administration and its policies may increase the likelihood of such legal and regulatory developments. If new laws or regulations are imposed relating to oil and gas extraction, or if additional or revised levels of reporting, regulation, or permitting moratoria are required or imposed, including those related to hydraulic fracturing, the volumes of natural gas and other products that we transport, gather, process, and treat could decline, our compliance costs could increase, and our results of operations could be adversely affected.
The natural gas sales, transportation, and storage operations of our gas pipelines are subject to regulation by the FERC, which could have an adverse impact on their ability to establish transportation and storage rates that would allow them to recover the full cost of operating their respective pipelines and storage assets, including a reasonable rate of return.
In addition to regulation by other federal, state, and local regulatory authorities, interstate pipeline transportation and storage service is subject to regulation by the FERC. Federal regulation extends to such matters as:
•Transportation and sale for resale of natural gas in interstate commerce;
•Rates, operating terms, types of services, and conditions of service;
•Certification and construction of new interstate pipelines and storage facilities;
•Acquisition, extension, disposition, or abandonment of existing interstate pipelines and storage facilities;
•Accounts and records;
•Depreciation and amortization policies;
•Relationships with affiliated companies whothat are involved in marketing functions of the natural gas business;
•Market manipulation in connection with interstate sales, purchases, or transportation of natural gas.
Regulatory or administrative actions in these areas, including successful complaints or protests against the rates of the gas pipelines, can affect our business in many ways, including decreasing tariff rates and revenues, decreasing volumes in our pipelines, increasing our costs, and otherwise altering the profitability of our pipeline business.
Our operations are subject to environmental laws and regulations, including laws and regulations relating to climate change and greenhouse gas emissions, which may expose us to significant costs, liabilities, and expenditures that could exceed our expectations.
Our operations are subject to extensive federal, state, tribal, and local laws and regulations governing environmental protection, endangered and threatened species, the discharge of materials into the environment, and the security of chemical and industrial facilities. Substantial costs, liabilities, delays, and other significant issues related to environmental laws and regulations are inherent in the gathering, transportation, storage, processing, and treating of natural gas, fractionation, transportation, and storage of NGLs, and crude oil transportation and production handling as well as waste disposal practices and construction activities. New or amended environmental laws and regulations can also result in significant increases in capital costs we incur to comply with such laws and regulations. Failure to comply with these laws, regulations, and permits may result in the assessment of administrative, civil and/or criminal penalties, the imposition of remedial obligations, the imposition of stricter conditions on or revocation of permits, the issuance of injunctions limiting or preventing some or all of our operations, and delays or denials in granting permits.
Joint and several strict liability may be incurred without regard to fault under certain environmental laws and regulations, for the remediation of contaminated areas and in connection with spills or releases of materials associated with natural gas, oil, and wastes on, under, or from our properties and facilities. Private parties, including the owners of properties through which our pipeline and gathering systems pass and facilities where our wastes are taken for reclamation or disposal, may have the right to pursue legal actions to enforce compliance as well as to seek damages for noncompliance with environmental laws and regulations or for personal injury or property damage arising from our operations. Some sites at which we operate are located near current or former third-party hydrocarbon storage and processing or oil and natural gas operations or facilities, and there is a risk that contamination has migrated from those sites to ours.
We are generally responsible for all liabilities associated with the environmental condition of our facilities and assets, whether acquired or developed, regardless of when the liabilities arose and whether they are known or unknown. In connection with certain acquisitions and divestitures, we could acquire, or be required to provide indemnification against, environmental liabilities that could expose us to material losses, which may not be covered by insurance. In addition, the steps we could be required to take to bring certain facilities into compliance could be prohibitively expensive, and we might be required to shut down, divest, or alter the operation of those facilities, which might cause us to incur losses.
In addition, climate change regulations and the costs that may be associated with such regulations and with the regulation of emissions of greenhouse gasesGHGs have the potential to affect our business. Regulatory actions by the Environmental Protection Agency or the passage of new climate change laws or regulations could result in increased costs to operate and maintain our facilities, install new emission controls on our facilities, or administer and manage ourany GHG complianceemissions program. We believe it is possible that future governmental legislation and/or regulation may require us either to limit GHG emissions associated with our operations or to purchase allowances for such emissions. We could also be subjected to a carbon tax assessed on the basis of carbon dioxide emissions or otherwise. However, we cannot predict precisely what form these future regulations might take, the stringency of any such regulations or when they might become effective. Several legislative bills have been introduced in the United States Congress that would require carbon dioxide emission reductions. Previously considered proposals have included, among other things, limitations on the amount of GHGs that can be emitted (so called “caps”) together with systems of permitted emissions allowances. These proposals could require us to reduce emissions or to purchase allowances for such emissions.
In addition to activities on the federal level, state and regional initiatives could also lead to the regulation of GHG emissions sooner than and/or independent of federal regulation. These regulations could be more stringent than any federal legislation that may be adopted. Future legislation and/or regulation designed to reduce GHG emissions could make some of our activities uneconomic to maintain or operate. We continue to monitor legislative and regulatory developments in this area and otherwise take efforts to limit and reduce GHG emissions from our
facilities. Although the regulation of GHG emissions may have a material impact on our operations and rates, we believe it is premature to attempt to quantify the potential costs of the impacts.
If we are unable to recover or pass through a significant level of our costs related to complying with climate change regulatory requirements imposed on us, it could have a material adverse effect on our results of operations and financial condition.
We do not insure against all potential risks and losses and could be seriously harmed by unexpected liabilities or by the inability of our insurers to satisfy our claims.
In accordance with customary industry practice, we maintain insurance against some, but not all, risks and losses, and only at levels we believe to be appropriate. The occurrence of any risks not fully covered by our insurance could have a material adverse effect on our business, financial condition, results of operations, and cash flows and our ability to repay our debt.
Failure to attract and retain an appropriately qualified workforce could negatively impact our results of operations.
Events such as an aging workforce without appropriate replacements, mismatch of skill sets to future needs, the challenges of attracting new, qualified workers to the midstream energy industry, or unavailability of contract labor may lead to operating challenges such as lack of resources, loss of knowledge, and a lengthy time period associated with skill development, including with the workforce needs associated with projects and ongoing operations. Failure to hire and adequately obtain replacement employees, including the ability to transfer significant internal historical knowledge and expertise to the new employees, or the future availability and cost of contract labor may adversely affect our ability to manage and operate the businesses. If we are unable to successfully attract and retain an appropriately qualified workforce, including members of senior management, results of operations could be negatively impacted.
Holders of our common stock may not receive dividends in the amount expected or any dividends.
We may not have sufficient cash each quarter to pay dividends or maintain current or expected levels of dividends. The actual amount of cash we dividend may fluctuate from quarter to quarter and will depend on various factors, some of which are beyond our control, including:
•The amount of cash that our subsidiaries distribute to us;
•The amount of cash we generate from our operations, our working capital needs, our level of capital expenditures, and our ability to borrow;
•The restrictions contained in our indentures and credit facility and our debt service requirements;
•The cost of acquisitions, if any.
A failure either to pay dividends or to pay dividends at expected levels could result in a loss of investor confidence, reputational damage, and a decrease in the value of our stock price.
Item 1B. Unresolved Staff Comments
Not applicable.
Item 2. Properties
Please read “Business” for a description of the location and general character of our principal physical properties. We generally own our facilities, although a substantial portion of our pipeline and gathering facilities is constructed and maintained pursuant to rights-of-way, easements, permits, licenses, or consents on and across properties owned by others.
Item 3. Legal Proceedings
Environmental
Certain reportable legal proceedings involving governmental authorities under federal, state, and local laws regulating the discharge of materials into the environment are described below. While it is not possible for us to predict the final outcome of the proceedings whichthat are still pending, we do not anticipate a material effect on our consolidated financial position if we receive an unfavorable outcome in any one or more of such proceedings.
On June 13, 2013, an explosion and fire occurred at our formerly owned Geismar olefins plant and rendered the facility temporarily inoperable (Geismar Incident). On October 21, 2013, the EPA, Region 6, issued an Inspection Report pursuant to the Clean Air Act’s Risk Management Program following its inspection of the facility on June 24 through June 28, 2013. The report notes the EPA’s preliminary determinations about the facility’s documentation regarding process safety, process hazard analysis, as well as operating procedures, employee training, and other matters. On June 16, 2014, we received Our threshold for disclosing material environmental legal proceedings involving a request for information related to the Geismar Incident from the EPA under Section 114 of the Clean Air Act to which we responded on August 13, 2014. We have worked with the agency to resolve these matters and in the second half of 2019, entered into a Stipulation of Settlement, which includes a penalty of $750,000 that will be due within thirty days of the Court’s entry of the settlement. The Court set a fairness hearing on the settlement for December 11, 2019. Prior to the scheduled hearing, the Court continued the hearing without setting a new date.
On May 5, 2017, we entered into a Consent Order with the Georgia Department of Natural Resources, Environmental Protection Division (GADNR) pertaining to alleged violations of the Georgia Water Quality Control Act and associated rules arising from a permit issued by GADNR for construction of Transco’s Dalton expansion project. Pursuant to the Consent Order, we paid a fine of $168,750 and agreed to a Corrective Action Plan.governmental authority where potential monetary sanctions are involved is $1 million.
On January 19, 2016, we received a Notice of Noncompliance with certain Leak Detection and Repair (LDAR) regulations under the Clean Air Act at our Moundsville Fractionator Facility from the EPA, Region 3. Subsequently, the EPA alleged similar violations of certain LDAR regulations at our Oak Grove Gas Plant. On March 19, 2018, we received a Notice of Violation of certain LDAR regulations at our former Ignacio Gas Plant from the EPA, Region 8, following an on-site inspection of the facility. On March 20, 2018, we also received a Notice of Violation of certain LDAR regulations at our Parachute Creek Gas Plant from the EPA, Region 8. All Noticessuch notices were subsequently referred to a common attorney at the Department of Justice (DOJ). We are exploringhave reached an agreement in principle with the DOJ and other agencies regarding global resolution of the claims at these facilities, as well as alleged violations at certain other facilities, with the DOJ. Globalfacilities. The proposed global resolution would includeincludes both
payment of a civil penalty in the amount of $3.75 million and an injunctive relief component. We continue to work with the DOJ and the other agencies to resolve these claims, whether individually or globally, and negotiations are ongoing.towards finalization of the global resolution.
Other environmental matters called for by this Item are described under the caption “Environmental Matters” in Note 1917 – Contingent Liabilities and Commitments of Notes to Consolidated Financial Statements included under Part II, Item 8 Financial Statements of this report, which information is incorporated by reference into this Item.
Other litigation
The additional information called for by this Item is provided in Note 1917 – Contingent Liabilities and Commitments of Notes to Consolidated Financial Statements included under Part II, Item 8 Financial Statements of this report, which information is incorporated by reference into this Item.
Item 4. Mine Safety Disclosures
Not applicable.
38
Information About Our Executive Officers
The name, title, age, period of service, and recent business experience of each of our executive officers as of February 24, 2020,27, 2023, are listed below.
| | | | | | | | | | | | | | | | | | | | |
| Name and Position | | Age | | Business Experience in Past Five Years |
| | | | | | |
Name and Position | | Age | | Business Experience in Past Five Years |
| Alan S. Armstrong | | 5760 | | 2011 to present | | Director, Chief Executive Officer, and President, The Williams Companies, Inc. |
| Director, Chief Executive Officer, and President | | | | 2015 to 2018 | | Chairman of the Board, WPZWilliams Partners L.P. |
| | | | 2014 to 2018 | | Chief Executive Officer, WPZWilliams Partners L.P. |
| | | | 2012 to 2018 | | Director of the general partner, WPZWilliams Partners L.P. |
Walter J. BennettDebbie Cowan | | 5045 | | 20202018 to present | | Senior Vice President Gathering & Processing, The Williams Companies, Inc. |
Senior Vice President Gathering & Processing | | | | 2015 to 2019 | | Senior Vice President – West, The Williams Companies, Inc. |
| | | | 2013 to 2018 | | Senior Vice President – West of the general partner, WPZ |
| | | | 2017 | | Director of the general partner, WPZ |
John D. Chandler | | 50 | | 2017 to present | | Senior Vice President and Chief Financial Officer, The Williams Companies, Inc. |
Senior Vice President and Chief Financial Officer | | | | 2017 to 2018 | | Director of the general partner, WPZ |
| | | | 2009 to 2014 | | Senior Vice President and Chief Financial Officer, Magellan GP, LLC |
Debbie Cowan | | 42 | | 2018 to present | | Senior Vice President – Chief Human Resources Officer, The Williams Companies, Inc. |
Senior Vice President –and Chief Human Resources Officer | | | | 2013 to 2018 | | Global Vice President of Human Resources, Koch Chemical Technology Group, LLC |
| Micheal G. Dunn | | 5457 | | 2017 to present | | Executive Vice President and Chief Operating Officer, The Williams Companies, Inc. |
| Executive Vice President and Chief Operating Officer | | | | 2017 to 2018 | | Director of the general partner, WPZWilliams Partners L.P. |
| | | | 2015 to 2016 | | President / Executive Vice President, Questar Pipeline / Questar Corporation |
| | | | 2010 to 2015 | | President and Chief Executive Officer, PacifiCorp Energy |
| Scott A. Hallam | | 4346 | | 2020 to present | | Senior Vice President Transmission & Gulf of Mexico, The Williams Companies, Inc. |
| Senior Vice President Transmission & Gulf of Mexico | | | | 2019 | | Senior Vice President – Atlantic-Gulf, The Williams Companies, Inc. |
| | | | 2017 to 2019 | | Vice President GM Atlantic-Gulf, The Williams Companies, Inc. |
| | | | 2015 to 2017 | | Vice President Northeast OA, The Williams Companies, Inc. |
| Mary A. Hausman | | 51 | | 2013 to 2015 | | General Manager – Utica, ACMP |
John E. Poarch | | 54 | | 20202022 to present | | Senior Vice President, Project Execution,Chief Accounting Officer and Controller, The Williams Companies, Inc. |
| Vice President, Chief Accounting Officer and Controller | | | | 2019 to 2022 | | Staff Vice President of Internal Audit, The Williams Companies, Inc. |
| | | | 2019 | | Director Special Projects, The Williams Companies, Inc. |
| | | | 2013 to 2019 | | Vice President and Chief Accounting Officer, NV Energy (a Berkshire Hathaway Energy Company) |
Larry C. Larsen
| | 48 | | 2022 to present | | Senior Vice President Project ExecutionGathering & Processing, The Williams Companies, Inc. |
| | | 2017 to 2019 | | Senior Vice President – EngineeringGathering & Processing | | | | 2020 to 2021 | | Vice President Strategic Development, The Williams Companies, Inc. |
| | | | 2019 to 2020 | | Vice President Rocky Mountain Midstream, The Williams Companies, Inc. |
| | | | 2018 to 2019 | | Vice President GM Rocky Mountain Midstream, The Williams Companies, Inc. |
| | | | 2017 to 2018 | | Vice President Central Services, The Williams Companies, Inc. |
| | | | 2017 | | Vice President – Commercial - West, The Williams Companies, Inc. |
| | | | 2015 to 2017 | | Vice President – Commercial & Business Development, The Williams Companies, Inc. |
| | | | 2011 to 2015 | | General Manager – Eagle Ford, ACMP |
| | | | | | |
| | | | | | | | | | | | | | | | | | | | |
| Name and Position | | Age | | Business Experience in Past Five Years |
| | | | | | |
Name and Position | | Age | | Business Experience in Past Five Years |
| John D. Porter | | 5053 | | 20202022 to present | | Senior Vice President Controller, and Chief AccountingFinancial Officer, The Williams Companies, Inc. |
Senior Vice President Controller, and Chief Financial Officer | | | | 2020 to 2021 | | Vice President, Chief Accounting Officer, Controller and Financial Planning & Analysis, The Williams Companies, Inc. |
| | | | 2017 to 2019 | | Vice President Enterprise Financial Planning & Analysis and Investor Relations, The Williams Companies, Inc. |
| | | | 2013 to 2017 | | Director of Investor Relations & Enterprise Planning, The Williams Companies, Inc. |
| Chad A. Teply | | 51 | | 2020 to present | | Senior Vice President – Project Execution, The Williams Companies, Inc. |
| Senior Vice President – Project Execution | | | | 2017 to 2020 | | Senior Vice President – Business Policy and Development, PacifiCorp (a Berkshire Hathaway Energy Company) |
| | | | 2009 to 2017 | | Vice President – Resource Development and Construction, PacifiCorp (a Berkshire Hathaway Energy Company) |
T. Lane Wilson
| | 5356 | | 2017 to present | | Senior Vice President and General Counsel, The Williams Companies, Inc. |
| Senior Vice President and General Counsel | | | | 2009 to 2017 | | United States Magistrate Judge for the Northern District of Oklahoma |
| Chad J. Zamarin | | 4346 | | 2023 to present | | Executive Vice President of Corporate Strategic Development, The Williams Companies, Inc. |
| Executive Vice President of Corporate Strategic Development | | | | 2017 to present2023 | | Senior Vice President – Corporate Strategic Development, The Williams Companies, Inc. |
Senior Vice President – Corporate Strategic Development | | | | 2017 to 2018 | | Director of the general partner, WPZWilliams Partners L.P. |
| | | | 2014 to 2017 | | President – Pipeline and Midstream, Cheniere Energy |
| | | | | | |
PART II
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Our common stock is listed on the New York Stock Exchange under the symbol “WMB.” At the close of business on February 19, 2020,17, 2023, we had 6,5126,013 holders of record of our common stock.
Share Repurchase Program
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| ISSUER PURCHASES OF EQUITY SECURITIES |
| | | | | | | | |
| Period | | (a)
Total Number of Shares Purchased | | (b)
Average Price Paid Per Share | | (c) Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs(1) | | (d)
Maximum Number (or Approximate Dollar Value) of Shares that May Yet Be Purchased Under the Plans or Programs |
| October 1 - October 31, 2022 | | — | | | $ | — | | | — | | | $ | 1,491,248,057 | |
| November 1 - November 30, 2022 | | — | | | $ | — | | | — | | | $ | 1,491,248,057 | |
| December 1 - December 31, 2022 | | — | | | $ | — | | | — | | | $ | 1,491,248,057 | |
| Total | | — | | | | | — | | | |
(1)We announced a stock repurchase program on September 8, 2021. Our board of directors has authorized the repurchase of up to $1.5 billion of the company’s common stock. The stock repurchase program has no expiration date. We intend to purchase shares of our stock from time to time in open market transactions, block purchases, privately negotiated or structured transactions, or in such other manner as determined at our discretion, subject to market conditions and other factors.
Performance Graph
Set forth below is a line graph comparing our cumulative total stockholder return on our common stock (assuming reinvestment of dividends) with the cumulative total return of the S&P 500 Stock Index, the Bloomberg Americas Pipelines Index, and the Arca Natural Gas Index for the period of five fiscal years commencing January 1, 2015.2018. The Bloomberg Americas Pipelines Index is composed of Enbridge Inc., TC Energy Corporation, Kinder Morgan, Inc., TCONEOK, Inc., Cheniere Energy, Corporation, ONEOK, Inc., Pembina Pipeline Corporation, Cheniere Energy, Inc., Targa Resources Corp., Inter Pipeline Ltd.New Fortress Energy Inc., and Williams. The Arca Natural Gas Index is comprised of over 20 highly capitalized companies in the natural gas industry involved primarily in natural gas exploration and production and natural gas pipeline transportation and transmission. The graph below assumes an investment of $100 at the beginning of the period.
|
| | | | | | | | | | | |
| | 2014 | | 2015 | | 2016 | | 2017 | | 2018 | | 2019 |
| The Williams Companies, Inc. | 100.0 | | 60.8 | | 79.8 | | 81.5 | | 62.0 | | 70.8 |
| S&P 500 Index | 100.0 | | 101.4 | | 113.5 | | 138.3 | | 132.2 | | 173.8 |
| Bloomberg Americas Pipelines Index | 100.0 | | 55.0 | | 80.7 | | 80.5 | | 69.0 | | 93.4 |
| Arca Natural Gas Index | 100.0 | | 61.0 | | 89.7 | | 76.3 | | 52.1 | | 51.5 |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 2017 | | 2018 | | 2019 | | 2020 | | 2021 | | 2022 |
| The Williams Companies, Inc. | 100.0 | | 74.5 | | 85.1 | | 78.7 | | 108.9 | | 144.8 |
| S&P 500 Index | 100.0 | | 94.8 | | 124.7 | | 147.6 | | 189.9 | | 155.5 |
| Bloomberg Americas Pipelines Index | 100.0 | | 83.8 | | 113.4 | | 89.7 | | 120.3 | | 139.0 |
| Arca Natural Gas Index | 100.0 | | 66.4 | | 65.5 | | 56.7 | | 91.0 | | 116.5 |
Item 6. Selected Financial Data
The following financial data at December 31, 2019 and 2018, and for each of the three preceding years in the period ended December 31, 2019, should be read in conjunction with the other financial information included in Part II, Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations and Part II, Item 8, FinancialStatements and Supplementary Data of this Form 10-K. All other financial data has been prepared from our accounting records.
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| | | | | | | | | | | | | | | | | | | |
| | Year Ended December 31, |
| | 2019 | | 2018 | | 2017 | | 2016 | | 2015 |
| | (Millions, except per-share amounts) |
| Revenues | $ | 8,201 |
| | $ | 8,686 |
| | $ | 8,031 |
| | $ | 7,499 |
| | $ | 7,360 |
|
| Income (loss) from continuing operations (1) | 729 |
| | 193 |
| | 2,509 |
| | (350 | ) | | (1,314 | ) |
| Amounts attributable to The Williams Companies, Inc. available to common stockholders: | | | | | | | | | |
| Income (loss) from continuing operations (2) | 862 |
| | (156 | ) | | 2,174 |
| | (424 | ) | | (571 | ) |
| Diluted income (loss) from continuing operations per common share | .71 |
| | (.16 | ) | | 2.62 |
| | (.57 | ) | | (.76 | ) |
| Total assets at December 31 | 46,040 |
| | 45,302 |
| | 46,352 |
| | 46,835 |
| | 49,020 |
|
| Commercial paper, lease liabilities, and long-term debt (including current portions) at December 31 | 22,497 |
| | 22,414 |
| | 20,935 |
| | 23,502 |
| | 24,487 |
|
| Stockholders’ equity at December 31 (3) | 13,363 |
| | 14,660 |
| | 9,656 |
| | 4,643 |
| | 6,148 |
|
| Cash dividends declared per common share | 1.52 |
| | 1.36 |
| | 1.20 |
| | 1.68 |
| | 2.45 |
|
| Diluted weighted-average shares outstanding (thousands) | 1,214,011 |
| | 973,626 |
| | 828,518 |
| | 750,673 |
| | 749,271 |
|
45
_________ | |
(1) | Income (loss) from continuing operations: |
For 2019 includes $464 million of impairments of certain assets, including a $354 million impairment of Constitution’s capitalized project costs, and $186 million impairments of certain equity-method investments, partially offset by a $122 million gain on the sale of our Jackalope equity-method investment;
For 2018 includes a $1.849 billion impairment of certain assets located in the Barnett Shale region, partially offset by a $591 million gain on the sale of our Four Corners area assets, a $141 million gain on the deconsolidation of certain Permian assets, and a $101 million gain from the sale of our Gulf Coast pipeline system assets;
For 2017 includes a $1.923 billion benefit for income taxes resulting from Tax Reform rate change and a $1.095 billion pre-tax gain on the sale of our Geismar Interest, partially offset by $1.248 billion of pre-tax impairments of certain assets and $776 million of pre-tax regulatory charges resulting from Tax Reform;
For 2016 includes an $873 million impairment of certain assets and a $430 million impairment of certain equity-method investments;
For 2015 includes a $1.4 billion impairment of certain equity-method investments and a $1.1 billion impairment of goodwill.
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(2) | Income (loss) from continuing operations attributable to the Williams Companies, Inc. available to common stockholders: |
For 2019 includes benefit of $209 million reflecting the noncontrolling interests’ share of the impairment of Constitution’s capitalized project costs.
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(3) | Stockholders’ equity at December 31: |
For 2019 includes a decrease related to a sale of a partial interest in our Northeast JV business;
For 2018 includes an increase reflecting our issuance of common stock associated with our merger with WPZ in August 2018;
For 2017 includes increases reflecting our issuance of common stock as part of our Financial Repositioning and a significant increase in our ownership of WPZ.
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
General
We are an energy company committed to being the leader in providing infrastructure company focused on connecting North America’s significant hydrocarbon resource plays to growing markets forthat safely delivers natural gas and NGLs through our gas pipeline and midstream business.products to reliably fuel the clean energy economy. Our operations are located in the United States.
Our interstate natural gas pipeline strategy is to create value by maximizing the utilization of our pipeline capacity by providing high quality, low costhigh-quality, low-cost transportation of natural gas to large and growing markets. Our gas pipeline businesses’ interstate transmission and storage activities are subject to regulation by the FERC and as such, our rates and charges for the transportation of natural gas in interstate commerce, and the extension, expansion or abandonment of jurisdictional facilities and accounting, among other things, are subject to regulation. The rates are established primarily through the FERC’s ratemaking process.process, but we also may negotiate rates with our customers pursuant to the terms of our tariffs and FERC policy. Changes in commodity prices and volumes transported have limited near-term impact on these revenues because the majority of cost of service is recovered through firm capacity reservation charges in transportation rates.
The ongoing strategy of our midstream operations is to safely and reliably operate large-scale midstream infrastructure where our assets can be fully utilized and drive low per-unit costs. We focus on consistently attracting new business by providing highly reliable service to our customers. These services include natural gas gathering, processing, treating, compression, and compression,storage, NGL fractionation, transportation and transportation,storage, crude oil production handling and transportation, as well as marketing services for NGL, crude oil, and natural gas, as well as storage facilities.gas.
As of December 31, 2019, ourOur operations are conducted, managed, and presented within the following reportable segments: Atlantic-Gulf,Transmission & Gulf of Mexico, Northeast G&P, West, and West,Gas & NGL Marketing Services, consistent with the manner in which our chief operating decision maker evaluates performance and allocates resources. All remaining business activities, as well asincluding our upstream operations and corporate activities, are included in Other. Our reportable segments are comprised of the following businesses:business activities:
Atlantic-Gulf•Transmission & Gulf of Mexico is comprised of our interstate natural gas pipeline,pipelines, Transco and Northwest Pipeline, and their related natural gas storage facilities, as well as natural gas gathering and processing and crude oil production handling and transportation assets in the Gulf Coast region, including a 51 percent interest in Gulfstar One (a consolidated variable interest entity)entity, or VIE), which is a proprietary floating production system, as well as a 50 percent equity-method investment in Gulfstream, and a 60 percent equity-method investment in Discovery,Discovery. Transmission & Gulf of Mexico also includes natural gas storage facilities and a 41 percent equity-method investmentpipelines providing services in Constitution as of December 31, 2019.north Texas.
•Northeast G&P is comprised of our midstream gathering, processing, and fractionation businesses in the Marcellus Shale region primarily in Pennsylvania and New York, and the Utica Shale region of eastern Ohio, as well as a 65 percent interest in our Northeast JV (a consolidated variable interest entity)VIE) which operates in West Virginia, Ohio, and Pennsylvania, a 66 percent interest in Cardinal (a consolidated variable interest entity)VIE) which operates in Ohio, a 69 percent equity-method investment in Laurel Mountain, a 5850 percent equity-method investment in Caiman II,Blue Racer, and Appalachia Midstream Services, LLC, which owns equity-method investments with an approximate average 66 percent interest in multiple gas gathering systems in the Marcellus Shale (Appalachia Midstream Investments).Investments.
•West is comprised of our interstate natural gas pipeline, Northwest Pipeline, and our gas gathering, processing, and treating operations in the Rocky Mountain region of Colorado and Wyoming, the Barnett Shale region of north-central Texas, the Eagle Ford Shale region of south Texas, the Haynesville Shale region of east Texas and northwest Louisiana, and the Mid-Continent region which includes the Anadarko Arkoma, Delaware, and Permian basins. This segment also includes our NGL and natural gas marketing business, storage facilities, an undivided 50 percent interest in an NGL fractionator near Conway, Kansas, a 50 percent equity-method investment in OPPL, a 50 percent equity-method investment in RMM, a 20 percent equity-method investment in Targa Train 7, and a 15 percent equity-method investment in Brazos Permian II. West also included
•Gas & NGL Marketing Services is comprised of our formerNGL and natural gas gatheringmarketing and processing assets intrading operations which includes risk management and transactions related to the Four Corners areastorage and transportation of New Mexiconatural gas and Colorado, which were sold during the fourth quarter of 2018 (see Note 3 – Acquisitions and Divestitures of Notes to Consolidated Financial Statements), and our former 50 percent interest in Jackalope (an equity-method investment following deconsolidation as of June 30, 2018), which was sold in April 2019,
and our previously owned 50 percent equity-method investment in the Delaware basin gas gathering system (DBJV) (see Note 6 – Investing Activities of Notes to Consolidated Financial Statements).
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• | Other includes minor business activities that are not operating segments, as well as corporate operations. Other also includes our previously owned operations, including an 88.5 percent undivided interest in an olefins production facility in Geismar, Louisiana, which was sold in July 2017 (see Note 3 – Acquisitions and Divestitures of Notes to Consolidated Financial Statements),anda refinery grade propylene splitter in the Gulf region, which was sold in June 2017.
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Unless indicated otherwise, the following discussion and analysis of results of operations and financial condition and liquidity relates to our current continuing operations and should be read in conjunction with the consolidated financial statements and notes thereto included in Part II, Item 8 of this report. Effective January 1, 2020, the composition of our reportable segments changed (see Part I, Item I Business Segments for further discussion).
Dividends
In December 2019,2022, we paid a regular quarterly dividend of $0.38$0.425 per share. On January 28, 2020,31, 2023, our board of directors approved a regular quarterly dividend of $0.40$0.4475 per share payable on March 30, 2020.27, 2023.
Overview of the Results of Operations
Net income (loss) attributable to The Williams Companies, Inc., for the year ended December 31, 2019,2022, increased $1.005 billioncompared toby $532 million over the year ended December 31, 2018, reflecting:prior year. Further discussion of our results is found in this report in the Results of Operations.
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• | A $1.451 billion decrease in Impairment of certain assets;
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• | A $431 million increase in Service revenues primarily associated with Transco expansion projects, the consolidation of UEOM beginning March 2019, and growth in Northeast G&P volumes, partially offset by lower revenues from our Barnett Shale operations primarily associated with the reduced recognition of deferred revenue and the end of a contractual MVC period, as well as the absence of revenues from operations sold or deconsolidated during 2018;
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• | A $484 million decrease to Net income (loss) attributable to noncontrolling interests primarily due to the WPZ Merger in the third quarter of 2018, as well as the noncontrolling interests’ share of the 2019 Constitution impairment.
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These favorable changes were partially offset by:
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• | A $694 million decrease in the Gain on sale of certain assets and businesses primarily related to the sale of the Four Corners area business in the fourth quarter of 2018;
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• | A $266 million decrease in Other investing income (loss) – net primarily due to the absence of 2018 gains on deconsolidations and 2019 impairments of equity-method investments, partially offset by a 2019 gain on the sale of our interest in Jackalope;
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$138 million of lower commodity margins;Recent Developments
$74 million of higher net interest expense;MountainWest Acquisition
$58 million lower allowance for equity funds used during construction (AFUDC);
A $197 million increase in provision for income taxes driven by higher pre-tax income, partially offset by the absence of a 2018 charge to establish a valuation allowanceOn February 14, 2023, we closed on deferred tax assets that may not be realized following the WPZ merger.
Acquisition of UEOM
As of December 31, 2018, we owned a 62 percent interest in UEOM which we accounted for as an equity-method investment. On March 18, 2019, we signed and closed the acquisition of the remaining 38100 percent interestof MountainWest Pipelines Holding Company (MountainWest) which includes FERC-regulated interstate natural gas pipeline systems and natural gas storage capacity, for $1.08 billion of cash and assumption of $430 million outstanding principal amount of long-term debt, subject to working capital and post-closing adjustments. The MountainWest Acquisition expands our existing transmission and storage infrastructure footprint into major markets in UEOM. Total consideration paid, including post-closing adjustments, was $741 million in cash funded through credit facility borrowingsUtah, Wyoming, and cash on hand. As a result of acquiring this additional interest, we obtained control of and now consolidate UEOM. (See Note 3 – Acquisitions and Divestitures of Notes to Consolidated Financial Statements.)Colorado.
Northeast JVNorthwest Pipeline FERC Rate Case Settlement
Concurrent with the UEOM acquisition, we executed an agreement whereby we contributed our consolidated interests in UEOM and our Ohio Valley midstream business to a newly formed partnership. In June 2019, our partner invested approximately $1.33 billion for a 35 percent ownership interest, and we retained 65 percent ownership of, as well as operate and consolidate, the Northeast JV business. (See Note 3 – Acquisitions and Divestitures of Notes to Consolidated Financial Statements.)
Sale of Jackalope
In April 2019, we sold our 50 percent equity-method interest in Jackalope for $485 million in cash, resulting in a gain on the disposition of $122 million. (See Note 6 – Investing Activities of Notes to Consolidated Financial Statements.)
Constitution
Although Constitution received a certificate of public convenience and necessity from the FERC to construct and operate the proposed pipeline and obtained, among other approvals, a waiver of the water quality certification under Section 401 of the Clean Water Act for the New York portion of the project, the members of Constitution, following extensive evaluation and discussion, recently determined that the underlying risk-adjusted return for this greenfield pipeline project has diminished in such a way that further development is no longer supported. (See Note 4 – Variable Interest Entities of Notes to Consolidated Financial Statements for further discussion.)
Expansion Project Updates
Significant expansion project updates for the period, including projects placed into service are described below. Ongoing major expansion projects are discussed later in Company Outlook.
Northeast G&P
Ohio River Supply Hub Expansion
We agreed to expand our services for certain customers to provide additional rich gas processing capacity in the Marcellus and Upper Devonian Shale in West Virginia and Pennsylvania. Associated with these agreements, we have expanded the inlet processing capacity of our Oak Grove facility to 400 MMcf/d. We have also constructed a new NGL pipeline from Moundsville to the Harrison Hub fractionation facility to provide an additional outlet for NGLs. These expansions are supported by long-term, fee-based agreements and volumetric commitments.
Susquehanna Supply Hub Expansion
InOn November 2019, we completed a 500 MMcf/d expansion of the gathering systems in the Susquehanna Supply Hub to bring the capacity to approximately 4.3 Bcf/d.
Atlantic-Gulf
Rivervale South to Market
In August 2018, we15, 2022, Northwest Pipeline received approval from the FERC to expand Transco’s existing natural gas transmission system to provide incremental firm transportation capacity from the existing Rivervale interconnection with Tennessee Gas Pipeline on Transco’s North New Jersey Extension tofor a stipulation and settlement agreement which generally reduces rates effective January 1, 2023, resolves other existing Transco locations within New
Jersey. The project was placed into partial service in July 2019. The remaining portion of the project was placed into service in September 2019. The full project increased capacity by 190 Mdth/d.
Norphlet Project
In March 2016, we announced that we reached an agreement to provide deepwater gas gathering services to the Appomattox developmentrate issues, establishes a Modernization and Emission Reduction Program, and satisfies its rate case filing obligation. Provisions were included in the Gulf of Mexico. We completed modificationssettlement that establishes a moratorium on any proceedings that would seek to install an alternate delivery routeplace new rates in effect any earlier than January 1, 2026, and that a general rate case filing will be made for rates to our Main Pass 261 Platform, as well as modificationsbecome effective not later than April 1, 2028, unless we have entered into a pre-filing settlement prior to our onshore Mobile Bay processing facility. The project went in service early in July 2019, at which time we also purchased a 54-mile-long, 16-inch-diameter pipeline (the Norphlet Pipeline) for $200 million. This pipeline transports gas from the Appomattox development to our Main Pass 261 Platform.that date.
Gateway
In December 2018, we received approval from the FERC to expand Transco’s existing natural gas transmission system to provide incremental firm transportation capacity from PennEast Pipeline Company’s proposed interconnection with Transco’s mainline south of Station 205 in New Jersey to other existing Transco meter stations within New Jersey. The project was placed into service in December 2019 and increased capacity by 65 Mdth/d.
Gulf Connector
In January 2019, the Gulf Connector project was placed into service. This project expanded Transco’s existing natural gas transmission system to provide incremental firm transportation capacity from Station 65 in Louisiana to delivery points in Wharton and San Patricio Counties, Texas. The project increased capacity by 475 Mdth/d.
West
North Seattle Lateral Upgrade
In July 2018, we received approval from the FERC to expand delivery capabilities on Northwest Pipeline’s North Seattle Lateral. The project consists of the removal and replacement of approximately 5.9 miles of 8-inch diameter pipeline with new 20-inch diameter pipeline. The project was placed into service in November 2019. The project increased delivery capacity by approximately 159 Mdth/d.
Wamsutter Expansion
We have expanded our gathering and processing infrastructure in the Wamsutter region of Wyoming in order to meet our customers’ production plans. We have completed construction of new compressor stations and modifications to our processing facilities, which were placed into service throughout 2019. The expansion added approximately 20 miles of gathering pipelines and approximately 15,000 horsepower of compression.
Filing of Rate CaseNorTex Asset Purchase
On August 31, 2018, Transco filed2022, we purchased a general rate case with the FERCgroup of assets in north Texas, primarily natural gas storage facilities and pipelines, from NorTex Midstream Holdings, LLC for an overall increase in rates. In September 2018, with the exception of certain rates that reflected a rate decrease, the FERC accepted and suspended our general rate filing to be effective March 1, 2019, subject to refund and the outcome of a hearing. The specific rates that reflected a rate decrease were accepted, without suspension, to be effective October 1, 2018, as requested by Transco, and were not subject to refund. In March 2019, the FERC accepted our motion to place the rates that were suspended by the September 2018 order into effect on March 1, 2019, subject to refund. In October 2019,$424 million.
Trace Acquisition
On April 29, 2022, we reached an agreementclosed on the termsacquisition of a settlement with100 percent of Gemini Arklatex, LLC through which we acquired the participants that would resolve all issuesHaynesville Shale region gas gathering and related assets of Trace Midstream for $972 million. The purpose of the Trace Acquisition was to expand our footprint into the east Texas area of the Haynesville Shale region, increasing in-basin scale in one of the largest growth basins in the rate case without the need for a hearing, and on December 31, 2019, we filed a formal stipulation and agreement with the FERC setting forth such terms of settlement. We anticipate FERC approval of the stipulation and agreement in the second quarter of 2020. As of December 31, 2019, we have provided a $189 million reserve for rate refunds related to increased rates collected since March 2019, which we believe is adequate for any refunds that may be required.country.
Commodity Prices
NGL per-unit margins were approximately 44 percent lower in 2019 compared to 2018 primarily due to a 31 percent and a 44 percent decrease in per-unit non-ethane and ethane sales prices, respectively, slightly offset by an approximate 10 percent decrease in per-unit natural gas feedstock prices.
NGL margins are defined as NGL revenues less any applicable Btu replacement cost, plant fuel, and third-party transportation and fractionation. Per-unit NGL margins are calculated based on sales of our own equity volumes at the processing plants. Our equity volumes include NGLs where we own the rights to the value from NGLs recovered at our plants under both “keep-whole” processing agreements, where we have the obligation to replace the lost heating value with natural gas, and “percent-of-liquids” agreements whereby we receive a portion of the extracted liquids with no obligation to replace the lost heating value.
The potential impact of commodity prices on our business is further discussed in the following Company Outlook.
Company Outlook
Our strategy is to provide a large-scale, reliable, and clean energy infrastructure designed to maximize the opportunities created by the vast supply of natural gas and natural gas products that exists in the United States. We accomplish this by connecting the growing demand for cleaner fuels and feedstocks with our major positions in the premier natural gas and natural gas products supply basins. We continue to maintain a strong commitment to safety, environmental stewardship including seeking opportunities for renewable energy ventures, operational excellence, and customer satisfaction. We believe that accomplishing these goals will position us to deliver safe, and reliable, serviceclean energy services to our customers and an attractive return to our shareholders.
Our business plan for 20202023 includes a continued focus on earnings and cash flow growth, while continuing to improve leverage metrics and control operating costs. Many of our producer customers are being impacted by extremely low natural gas and NGL prices, which are driving decreased drilling. We are responding by reducing the pace of our capital growth spending in our gathering and processing business and remaining committed to operating cost discipline.growth.
In 2020,2023, our operating results are expected to includebenefit from the MountainWest Acquisition, volume growth in the Haynesville and Northeast G&P areas, and annual inflation-based rate increases from Transco’s recent expansion projects placed in-serviceacross our gathering and general rate settlement as previously discussed.processing business. We also expect an increaseanticipate increases resulting from the development of our upstream oil and gas properties and a full year of contribution from the Norphlet project,recently acquired Trace and NorTex assets. These increases are partially offset by a lower deferred revenue amortization from Gulfstar, bothexpected commodity price environment.
We seek to maintain a strong financial position and liquidity, as well as manage a diversified portfolio of safe, clean, and reliable energy infrastructure assets that continue to serve key growth markets and supply basins in the Eastern Gulf region. Northeast results are expected to increase from higher gathering and processing volumes.We expect decreases in the West primarily due to lower deferred revenue amortization in the Barnett Shale and lower revenues from our Haynesville operations, partially offset by increased results from our DJ Basin and Eagle Ford operations. Additionally, we expect our recently implemented organizational realignment will benefit our expenses.
United States. Our growth capital and investment expenditures in 20202023 are expected to be in a range from $1.1$1.40 billion to $1.3 billion.$1.70 billion, excluding the MountainWest Acquisition. Growth capital spending in 20202023 primarily includes Transco expansions, all of which are fully contracted with firm transportation agreements, projects supporting the Northeast G&P business and our Bluestem NGL pipeline projectprojects supporting growth in the Mid-Continent region.Haynesville basin, including the Louisiana Energy Gateway project. We also expect to invest capital in the development of our upstream oil and gas properties. In addition to growth capital and investment expenditures, we also remain committed to projects that maintain our assets for safe and reliable operations, as well as projects that reduce emissions, and meet legal, regulatory, and/or contractual commitments.
Potential risks and obstacles that could impact the execution of our plan include:
•A global recession, which could result in downturns in financial markets and commodity prices, as well as impact demand for natural gas and related products;
•Opposition to, and legal regulations affecting, our infrastructure projects, including the risk of delay or denial in permits and approvals needed for our projects;
•Counterparty credit and performance risk;
•Unexpected significant increases in capital expenditures or delays in capital project execution;execution, including increases from inflation or delays caused by supply chain disruptions;
•Unexpected changes in customer drilling and production activities, which could negatively impact gathering and processing volumes;
•Lower than anticipated demand for natural gas and natural gas products which could result in lower than expectedlower-than-expected volumes, energy commodity prices, and margins;
•General economic, financial markets, or further industry downturns, including increased inflation and interest rates;
•Physical damages to facilities, including damage to offshore facilities by named windstorms;weather-related events;
•Other risks set forth under Part I, Item 1A. Risk Factors in this report.
We seek to maintain a strong financial position and liquidity, as well as manage a diversified portfolio of energy infrastructure assets which continue to serve key growth markets and supply basins in the United States.
Expansion Projects
Our ongoing major expansion projects include the following:
Atlantic-GulfTransmission & Gulf of Mexico
HillabeeDeepwater Shenandoah Project
In February 2016, the FERC issued a certificate order for the initial phases of Transco’s Hillabee Expansion Project.June 2021, we reached an agreement with two third-parties to provide offshore natural gas gathering and transportation services as well as onshore natural gas processing services. The project involves an expansionexpands our existing Gulf of Transco’sMexico offshore infrastructure via a 5-mile offshore lateral pipeline from the Shenandoah platform to Discovery’s existing Keathley Canyon Connector pipeline, adds onshore processing facilities at Larose, Louisiana to handle the expected rich Shenandoah production, and the natural gas transmission systemliquids will be fractionated and marketed at Discovery’s Paradis plant in Louisiana. We plan to place the project into service in the fourth quarter of 2024.
Deepwater Whale Project
In August 2021, we reached an agreement with two third-parties to provide offshore natural gas gathering and crude oil transportation services as well as onshore natural gas processing services. The project expands our existing Western Gulf of Mexico offshore infrastructure via a 26-mile gas lateral pipeline from Station 85 in west central Alabamathe Whale platform to the existing Perdido gas pipeline and adds a new interconnection with125-mile oil pipeline from the Sabal Trail pipeline in Alabama. The project is being constructed in phases, and all ofWhale platform to our existing junction platform. We plan to place the project expansion capacity is dedicated to Sabal Trail pursuant to a capacity lease agreement. Phase I was completedinto service in 2017 and it increased capacity by 818 Mdth/d. The in-service date of Phase II is planned for the secondfourth quarter of 2020, and together Phases I and II are expected to increase capacity by 1,025 Mdth/d.2024.
Northeast Supply EnhancementRegional Energy Access
In May 2019,January 2023, we received approval from the FERC for the project to expand Transco’s existing natural gas transmission system to provide incremental firm transportation capacity from Station 195receipt points in northeastern Pennsylvania to multiple delivery points in Pennsylvania, to the Rockaway Delivery Lateral transfer point in New York. Approvals required for the project from the New York State Department of Environmental Conservation and the New Jersey, Department of Environmental Protection remain pending, with each such agency having denied, without prejudice, Transco’s applications for such approvals. We have refiled our applications for those approvals and have addressed the technical issues identified by the agencies.Maryland. We plan to place the project into service in the fall of 2021, assuming timely receipt of these remaining approvals. The project is expected to increase capacity by 400 Mdth/d.
Southeastern Trail
In October 2019, we received approval from the FERC to expand Transco’s existing natural gas transmission system to provide incremental firm transportation capacity from the Pleasant Valley interconnect with Dominion’s Cove Point Pipeline in Virginia to the Station 65 pooling point in Louisiana. We plan to place the project into service in late 2020. The project is expected to increase capacity by 296 Mdth/d.
Leidy South
In July 2019, we filed an application with the FERC for approval of the project to expand Transco’s existing natural gas transmission system and also extend its system through a capacity lease with National Fuel Gas Supply Corporation that will enable us to provide incremental firm transportation from Clermont, Pennsylvania and from the Zick interconnection on Transco’s Leidy Line to the River Road regulating station in Lancaster County, Pennsylvania. We plan to place thefull project into service as early as the fourth quarter of 2021,2024, assuming timely receipt of all necessary regulatory approvals. The project is expected to increase capacity by 582829 Mdth/d.
West
Project Bluestem
We are expanding our presence inIn May 2022, we filed an application with the Mid-Continent region through building a 188-mile NGL pipeline from our fractionator near Conway, Kansas to an interconnect with a third-party NGL pipeline system in Oklahoma, providing us with firm access to Mt. Belvieu pricing. As part ofFERC for the project, which is an expansion of Transco’s existing natural gas transmission system to provide incremental firm transportation capacity from receipt points in Virginia and North Carolina to delivery points in North Carolina. We plan to place the third-party intendsproject into service as early as the 2024/2025 winter heating season assuming timely receipt of all necessary regulatory approvals. The project is expected to construct a 110-mile pipeline extensionincrease capacity by 423 Mdth/d.
Texas to Louisiana Energy Pathway
In August 2022, we filed an application with the FERC for the project, which involves an expansion of theirTransco’s existing NGL pipelinenatural gas transmission system that will have an initialto provide firm transportation capacity of 120 Mbbls/d. Further, duringfrom receipt points in south Texas to delivery points in Texas and Louisiana. We plan to place the project into service as early as the first quarter of 2019,2025, assuming timely receipt of all necessary regulatory approvals. The project is expected to provide 364 Mdth/d of new firm transportation service through a combination of increasing capacity, converting interruptible capacity to firm, and utilizing existing capacity.
Southeast Energy Connector
In August 2022, we exercisedfiled an optionapplication with the FERC for the project, which is an expansion of Transco’s existing natural gas transmission system to purchaseprovide incremental firm transportation capacity from receipt points in Mississippi and Alabama to a 20 percent equity interestdelivery point in Alabama. We plan to place the project into service in the first quarter of 2025, assuming timely receipt of all necessary regulatory approvals. The project is expected to increase capacity by 150 Mdth/d.
Commonwealth Energy Connector
In August 2022, we filed an application with the FERC for the project, which involves an expansion of Transco’s existing natural gas transmission system to provide incremental firm transportation capacity in Virginia. We plan to place the project into service as early as the fourth quarter of 2025, assuming timely receipt of all necessary regulatory approvals. The project is expected to increase capacity by 105 Mdth/d.
West
Louisiana Energy Gateway
In June 2022, we announced our intention to construct new natural gas gathering assets which are expected to gather 1.8 Bcf/d of natural gas produced in the Haynesville Shale basin for delivery to premium markets, including Transco, industrial markets, and growing LNG export demand along the Gulf Coast. This project is expected to go into service in the fourth quarter of 2024.
Haynesville Gathering Expansion
In February 2023, we announced our agreement with a Mt. Belvieu fractionation train developed bythird party to facilitate natural gas production growth in the Haynesville basin. We plan to construct a greenfield gathering system in support the third party’s 26,000 acre dedication. The system, once constructed, will provide natural gas gathering services to the third party. The pipeline and extension projects are expectedthird party has also agreed to be placed into service during the first quarter of 2021.a long-term capacity commitment on our Louisiana Energy Gateway project.
Critical Accounting Estimates
The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions. We believe that the nature of these estimates and assumptions is material due to the subjectivity and judgment necessary, or the susceptibility of such matters to change, and the impact of these on our financial condition or results of operations.
Pension and Postretirement Obligations
We have employee benefit plans that include pension and other postretirement benefits. Net periodic benefit costplans that require the use of assumptions and estimates to determine the benefit obligations for these plans are impacted by various estimates and assumptions.costs. These estimates and assumptions involve significant judgement and actual results will likely be different than anticipated. Estimates and assumptions utilized include the expected long-term rates of return on plan assets, discount rates, cash balance interest crediting rate, and employee demographics, including retirement age and mortality. These assumptions are reviewed annually and adjustments are made as needed. The assumptions utilized to compute cost and the benefit obligations and costs are shown in Note 107 – Employee Benefit Plans of Notes to Consolidated Financial Statements.
The following table presents the estimated increase (decrease) in net periodic benefit cost and obligations resulting from a one-percentage-point change in the specific assumption.
| | | | Benefit Cost | | Benefit Obligation | | Benefit Cost | | Benefit Obligation |
| | One- Percentage- Point Increase | | One- Percentage- Point Decrease | | One- Percentage- Point Increase | | One- Percentage- Point Decrease | | One-
Percentage-
Point
Increase | | One-
Percentage-
Point
Decrease | | One-
Percentage-
Point
Increase | | One-
Percentage-
Point
Decrease |
| | (Millions) | | (Millions) |
| Pension benefits: | | | | | | | | Pension benefits: | |
| Discount rate | $ | (2 | ) | | $ | 4 |
| | $ | (102 | ) | | $ | 120 |
| Discount rate | $ | (21) | | | $ | (1) | | | $ | (69) | | | $ | 80 | |
| Expected long-term rate of return on plan assets | (12 | ) | | 12 |
| | — |
| | — |
| Expected long-term rate of return on plan assets | (11) | | | 11 | | | — | | | — | |
| Cash balance interest crediting rate | 12 |
| | (10 | ) | | 71 |
| | (60 | ) | Cash balance interest crediting rate | 5 | | | (25) | | | 50 | | | (43) | |
| Other postretirement benefits: | | | | | | | | Other postretirement benefits: | |
| Discount rate | 1 |
| | 2 |
| | (23 | ) | | 28 |
| Discount rate | (3) | | | 2 | | | (14) | | | 16 | |
| Expected long-term rate of return on plan assets | (2 | ) | | 2 |
| | — |
| | — |
| Expected long-term rate of return on plan assets | (2) | | | 2 | | | — | | | — | |
Our expected long-term rates of return on plan assets, as determined at the beginning of each fiscal year, are based on the average rate of return expected on the funds invested in the plans. We determine our long-term expected rates of return on plan assets using our expectations ofhistorical returns, forward-looking capital market results, which include an analysis of historical results as well as forward-looking projections. These capital market expectations are based on a period of at least 10 years and take into account our investment strategy and mix of assets. We develop our expectations using input from our third-party independent investment consultant. The forward-looking capital market projections start with current conditions of interest rates, equity pricing, economic growth, and inflation and those are overlaid with forward looking projections of normal inflation, growth, and interest rates to determine expected returns. The capital market return projections for specific asset classes inadvisor, as well as the investment portfolio are then applied to thestrategy and relative weightings of the asset classes inwithin the investment portfolio. The resulting rates are an estimate of future results and, thus, likely to be different than actual results.
Our expected long-term rate of return on plan assets used for our pension plans was 5.263.81 percent in 2019.2022. The 20192022 actual return on plan assets for our pension plans was a loss of approximately 19.09.7 percent. The 10-year average rate of return on pension plan assets through December 20192022 was approximately 8.16.8 percent. The expected rates of return on plan assets are long-term in nature and are not significantly impacted by short-term market performance. Changes to our asset allocation also impact the expected rates of return.
The discount rates are used to measure the benefit obligations of our pension and other postretirement benefit plans. The objective of the discount rates is to determine the amount, if invested at the December 31 measurement date in a portfolio of high-quality debt securities, that will provide the necessary cash flows when benefit payments are due. Increases in the discount rates decrease the obligation and, generally, decrease the related cost. The discount rates for our pension and other postretirement benefit plans are determined separately based on an approach specific to our plans, which considers a yield curve of high-quality corporate bonds and their respectivethe duration of the expected benefit cash flows as described in Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies and Note 10 – Employee Benefit Plans of Notes to Consolidated Financial Statements. Our discount rate assumptions are impacted by changes in general economic and market conditions that affect interest rates on long-term, high-quality debt securities as well as by the duration of our plans’ liabilities.each plan.
The cash balance interest crediting rate assumption represents the average long-term rate by which the pension plans’ cash balance accounts are expected to grow. Interest on the cash balance accounts is based on the 30-year U.S. Treasury securities rate and is credited to the accounts quarterly. An increase in this rate causes the pension obligation and cost to increase.rate.
Equity-Method Investments
We continue to monitor our equity-method investments for any indications that the carrying value may have experienced an other-than-temporary decline in value. When evidence of a loss in value has occurred, we compare our estimate of the fair value of the investment to the carrying value of the investment to determine whether an impairment has occurred. We generally estimate the fair value of our investments using an income approach where significant judgments and assumptions include expected future cash flows and the appropriate discount rate. We also utilize a form of market approach to estimate the fair value of our investments. During 2019, we recognized impairments totaling $186 million related to our equity-method investments. (See Note 18 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk of Notes to Consolidated Financial Statements.)
50
Results of Operations
Consolidated Overview
The following table and discussion is a summary of our consolidated results of operations for the three years ended December 31, 2019.2022. The results of operations by segment are discussed in further detail following this consolidated overview discussion.
| | | | Year Ended December 31, | | Year Ended December 31, |
| | 2019 | | $ Change from 2018* | | % Change from 2018* | | 2018 | | $ Change
from
2017* | | % Change
from
2017* | | 2017 | | 2022 | | $ Change
from
2021* | | % Change
from
2021* | | 2021 | | $ Change
from
2020* | | % Change
from
2020* | | 2020 |
| | (Millions) | | (Millions) |
| Revenues: | | | | | | | | | | | | | | Revenues: | |
| Service revenues | $ | 5,933 |
| | +431 |
| | +8 | % | | $ | 5,502 |
| | +190 |
| | +4 | % | | $ | 5,312 |
| Service revenues | $ | 6,536 | | | +535 | | | +9 | % | | $ | 6,001 | | | +77 | | | +1 | % | | $ | 5,924 | |
| Service revenues – commodity consideration | 203 |
| | -197 |
| | -49 | % | | 400 |
| | +400 |
| | NM |
| | — |
| Service revenues – commodity consideration | 260 | | | +22 | | | +9 | % | | 238 | | | +109 | | | +84 | % | | 129 | |
| Product sales | 2,065 |
| | -719 |
| | -26 | % | | 2,784 |
| | +65 |
| | +2 | % | | 2,719 |
| Product sales | 4,556 | | | +20 | | | — | % | | 4,536 | | | +2,865 | | | +171 | % | | 1,671 | |
| Net gain (loss) on commodity derivatives | | Net gain (loss) on commodity derivatives | (387) | | | -239 | | | -161 | % | | (148) | | | -143 | | | NM | | (5) | |
| Total revenues | 8,201 |
| | | | | | 8,686 |
| | | | | | 8,031 |
| Total revenues | 10,965 | | | 10,627 | | | 7,719 | |
| Costs and expenses: | | | | | | | | | | | | | | Costs and expenses: | |
| Product costs | 1,961 |
| | +746 |
| | +28 | % | | 2,707 |
| | -407 |
| | -18 | % | | 2,300 |
| Product costs | 3,369 | | | +562 | | | +14 | % | | 3,931 | | | -2,386 | | | -154 | % | | 1,545 | |
| Processing commodity expenses | 105 |
| | +32 |
| | +23 | % | | 137 |
| | -137 |
| | NM |
| | — |
| |
| Net processing commodity expenses | | Net processing commodity expenses | 88 | | | +13 | | | +13 | % | | 101 | | | -33 | | | -49 | % | | 68 | |
| Operating and maintenance expenses | 1,468 |
| | +39 |
| | +3 | % | | 1,507 |
| | +69 |
| | +4 | % | | 1,576 |
| Operating and maintenance expenses | 1,817 | | | -269 | | | -17 | % | | 1,548 | | | -222 | | | -17 | % | | 1,326 | |
| Depreciation and amortization expenses | 1,714 |
| | +11 |
| | +1 | % | | 1,725 |
| | +11 |
| | +1 | % | | 1,736 |
| Depreciation and amortization expenses | 2,009 | | | -167 | | | -9 | % | | 1,842 | | | -121 | | | -7 | % | | 1,721 | |
| Selling, general, and administrative expenses | 558 |
| | +11 |
| | +2 | % | | 569 |
| | +25 |
| | +4 | % | | 594 |
| Selling, general, and administrative expenses | 636 | | | -78 | | | -14 | % | | 558 | | | -92 | | | -20 | % | | 466 | |
| | Impairment of certain assets | 464 |
| | +1,451 |
| | +76 | % | | 1,915 |
| | -667 |
| | -53 | % | | 1,248 |
| Impairment of certain assets | — | | | +2 | | | +100 | % | | 2 | | | +180 | | | +99 | % | | 182 | |
| Gain on sale of certain assets and businesses | 2 |
| | -694 |
| | NM |
| | (692 | ) | | -403 |
| | -37 | % | | (1,095 | ) | |
| Regulatory charges resulting from Tax Reform | — |
| | -17 |
| | -100 | % | | (17 | ) | | +691 |
| | NM |
| | 674 |
| |
| Impairment of goodwill | | Impairment of goodwill | — | | | — | | | — | % | | — | | | +187 | | | +100 | % | | 187 | |
| | Other (income) expense – net | 8 |
| | +59 |
| | +88 | % | | 67 |
| | +4 |
| | +6 | % | | 71 |
| Other (income) expense – net | 28 | | | -14 | | | -100 | % | | 14 | | | +8 | | | +36 | % | | 22 | |
| Total costs and expenses | 6,280 |
| | | | | | 7,918 |
| | | | | | 7,104 |
| Total costs and expenses | 7,947 | | | 7,996 | | | 5,517 | |
| Operating income (loss) | 1,921 |
| | | | | | 768 |
| | | | | | 927 |
| Operating income (loss) | 3,018 | | | 2,631 | | | 2,202 | |
| Equity earnings (losses) | 375 |
| | -21 |
| | -5 | % | | 396 |
| | -38 |
| | -9 | % | | 434 |
| Equity earnings (losses) | 637 | | | +29 | | | +5 | % | | 608 | | | +280 | | | +85 | % | | 328 | |
| Impairment of equity-method investments | | Impairment of equity-method investments | — | | | — | | | — | % | | — | | | +1,046 | | | +100 | % | | (1,046) | |
| Other investing income (loss) – net | (79 | ) | | -266 |
| | NM |
| | 187 |
| | -95 |
| | -34 | % | | 282 |
| Other investing income (loss) – net | 16 | | | +9 | | | +129 | % | | 7 | | | -1 | | | -13 | % | | 8 | |
| Interest expense | (1,186 | ) | | -74 |
| | -7 | % | | (1,112 | ) | | -29 |
| | -3 | % | | (1,083 | ) | Interest expense | (1,147) | | | +32 | | | +3 | % | | (1,179) | | | -7 | | | -1 | % | | (1,172) | |
| Other income (expense) – net | 33 |
| | -59 |
| | -64 | % | | 92 |
| | +117 |
| | NM |
| | (25 | ) | Other income (expense) – net | 18 | | | +12 | | | +200 | % | | 6 | | | +49 | | | NM | | (43) | |
| Income (loss) from continuing operations before income taxes | 1,064 |
| | | | | | 331 |
| | | | | | 535 |
| |
| Provision (benefit) for income taxes | 335 |
| | -197 |
| | -143 | % | | 138 |
| | -2,112 |
| | NM |
| | (1,974 | ) | |
| Income (loss) from continuing operations | 729 |
| | | | | | 193 |
| | | | | | 2,509 |
| |
| Income (loss) from discontinued operations | (15 | ) | | -15 |
| | NM |
| | — |
| | — |
| | — | % | | — |
| |
| Income (loss) before income taxes | | Income (loss) before income taxes | 2,542 | | | 2,073 | | | 277 | |
| Less: Provision (benefit) for income taxes | | Less: Provision (benefit) for income taxes | 425 | | | +86 | | | +17 | % | | 511 | | | -432 | | | NM | | 79 | |
| | Net income (loss) | 714 |
| | | | | | 193 |
| | | | | | 2,509 |
| Net income (loss) | 2,117 | | | 1,562 | | | 198 | |
| Less: Net income (loss) attributable to noncontrolling interests | (136 | ) | | +484 |
| | NM |
| | 348 |
| | -13 |
| | -4 | % | | 335 |
| Less: Net income (loss) attributable to noncontrolling interests | 68 | | | -23 | | | -51 | % | | 45 | | | -58 | | | NM | | (13) | |
| Net income (loss) attributable to The Williams Companies, Inc. | $ | 850 |
| | | | | | $ | (155 | ) | | | | | | $ | 2,174 |
| Net income (loss) attributable to The Williams Companies, Inc. | $ | 2,049 | | | +532 | | | +35 | % | | $ | 1,517 | | | +1,306 | | | NM | | $ | 211 | |
_______
| |
* | * + = Favorable change; - = Unfavorable change; NM = A percentage calculation is not meaningful due to a change in signs, a zero-value denominator, or a percentage change greater than 200. |
20192022 vs. 20182021
Service revenuesincreased primarily due to higher gathering and processing rates driven by favorable commodity prices and annual contractual rate escalations for certain of our West and Northeast G&P operations, higher volumes including from the Trace Acquisition and NorTex Asset Purchase, higher transportation fee revenues at Transco associated with expansion projects placed in service in 2019 and 2018, as well as the impact of the consolidation of UEOM, higher Northeast volumes at the Susquehanna Supply Hub and Ohio Valley Midstream regions, and higher gathering rates and volumes at the Utica Shale region. These increases are partially offset by the absence of revenues associated with asset divestitures and deconsolidations during 2018, including our former Four Corners area operations, as well as lower revenue in the Barnett Shale associated with the end of a contractual MVC period Leidy South expansion project placed fully in service at Transco in December 2021,
and lower revenue at Gulfstar primarily associated with producer operational issues.higher reimbursable electric power costs and storage rates which are substantially offset in Operating and maintenance expenses.
Service revenues – commodity consideration decreased due to lower NGL prices and lower volumesincreased primarily due to the absence of our former Four Corners area operations.higher NGL prices, partially offset by lower NGL volumes. These revenues represent consideration we receive in the form of commodities as full or partial payment for processing services provided. Most of these NGL volumes are sold withinduring the month processed and therefore are offset in Product costs below.
Product sales decreased primarily due to lower NGL and natural gas prices associated with our marketing and equity NGL sales activities, lower volumes from our equity NGL sales primarily reflecting the absence of our former Four Corners area operations, and lower system management gas sales, partially offset by higher marketing volumes. Marketing sales and system management gas sales are substantially offset in Product costs.
Product costs decreased primarily due to lower NGL and natural gas prices associated with our marketing and equity NGL production activities. This decrease also includes lower volumes acquired as commodity consideration for NGL processing services reflecting the absence of our former Four Corners area operations and lower system management gas purchases, partially offset by higher volumes for marketing activities.
Processing commodity expenses decreased primarily due to lower production of equity NGLs primarily related to ethane rejection and the absence of our former Four Corners area operations, and lower prices for natural gas purchases associated with our NGL production.
Operating and maintenance expenses decreased primarily due to the absence of our former Four Corners area operations and lower contracted services at Transco primarily due to the timing of required engine overhauls and integrity testing. These decreases are partially offset by the impact of the consolidation of UEOM and by a $32 million charge for severance and related costs primarily associated with a voluntary separation program (VSP) in 2019.
Depreciation and amortization expenses decreased primarily due to the 2018 impairment of certain assets in the Barnett Shale region and the absence of assets disposed including our former Four Corners area operations, partially offset by new assets placed in service and by the impact of the consolidation of UEOM.
Selling, general, and administrative expenses decreased primarily due to the absences of a charitable contribution of preferred stock to the Williams Foundation, Inc. (see Note 16 – Stockholders' Equity of Notes to Consolidated Financial Statements) and fees associated with the WPZ Merger, partially offset by a $25 million charge for severance and related costs primarily associated with our 2019 VSP, and transaction expenses associated with the acquisition of UEOM and the formation of the Northeast JV.
Impairment of certain assets includes 2019 impairments of our Constitution development project, certain Eagle Ford Shale gathering assets, and certain assets that may no longer be in use or are surplus in nature. Asset impairments in 2018 included certain assets in the Barnett Shale region and certain idle pipelines (see Note 18 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk of Notes to Consolidated Financial Statements).
Gain on sale of certain assets and businesses includes gains recognized on the sales of our Four Corners area and our Gulf Coast pipeline systems in 2018 (see Note 3 – Acquisitions and Divestitures of Notes to Consolidated Financial Statements).
The favorable change in Other (income) expense – netwithinOperating income (loss) includes net favorable changes to charges and credits to regulatory assets and liabilities, partially offset by the absence of a 2018 gain on asset retirement (see Note 7 – Other Income and Expenses of Notes to Consolidated Financial Statements).
The favorable change in Operating income (loss) includes lower impairments of assets, an increase in Service revenues primarily associated with Transco projects placed in-service and higher volumes in the Northeast region, the favorable impact of acquiring the additional interest of UEOM, and higher Transco rates and favorable changes in the amortization of regulatory assets and liabilities. The change is also impacted favorably by the absence of a charitable contribution of preferred stock to the Williams Foundation, Inc., and the absence of fees associated with the WPZ Merger. These favorable changes were partially offset by the impact of asset divestitures and deconsolidations during 2018, including the related gains on sales. They were also partially offset by lower margins associated with our equity NGL production primarily associated with lower prices, higher depreciation expense associated with new assets placed in service, and charges for severance and related costs primarily associated with our VSP.
The unfavorable change in Equity earnings (losses) is primarily due to 2019 losses from our Brazos Permian II investment acquired in December 2018 of $14 million, the impact of the consolidation of UEOM during the first quarter of 2019 which reduced equity earnings by $9 million, and a $7 million unfavorable impact related to the April 2019 sale of our Jackalope investment. Additionally, equity earnings at Aux Sable decreased $9 million related to lower rates reflecting lower NGL prices. These decreases are partially offset by improved results at our Appalachia Midstream Investments of $20 million.
The unfavorable change in Other investing income (loss) – net includes higher impairments of equity-method investments, the absence of 2018 gains on the deconsolidations of our Delaware basin assets and Jackalope, and a 2019 loss on the deconsolidation of Constitution. These were partially offset by a 2019 gain on the disposition of Jackalope (see Note 6 – Investing Activities of Notes to Consolidated Financial Statements).
Interest expense increased primarily due to an increase in financing obligations associated with Transco’s Atlantic Sunrise project and lower Interest capitalized related to construction projects that have been placed into service. (See Note 15 – Debt and Banking Arrangements of Notes to Consolidated Financial Statements.)
The unfavorable change in Other income (expense) – net below Operating income (loss) is primarily due to a decrease in equity AFUDC associated with reduced capital expenditures on projects, partially offset by the absence of 2018 unfavorable settlement charges from our pension early payout program (see Note 7 – Other Income and Expenses of Notes to Consolidated Financial Statements).
Provision (benefit) for income taxes changed unfavorably primarily due to higher pre-tax income attributable to The Williams Companies, Inc, partially offset by the absence of a charge to establish a $105 million valuation allowance, recorded in 2018, on certain deferred tax assets that may not be realized following the WPZ merger. See Note 8 – Provision (Benefit) for Income Taxes of Notes to Consolidated Financial Statements for a discussion of the effective tax rate compared to the federal statutory rate for both periods.
The favorable change in Net income (loss) attributable to noncontrolling interests is primarily due to our third- quarter 2018 acquisition of the publicly held interests in WPZ associated with the WPZ Merger, the impairment of Constitution project costs, and lower results at Gulfstar.
2018 vs. 2017
Service revenues increased primarily due to higher transportation fee revenues at Transco associated with expansion projects placed in-service in 2017 and 2018, as well as higher gathering volumes at the Susquehanna Supply Hub and Ohio River Supply Hub. These increases were partially offset by an unfavorable change in the rate of deferred revenue recognition resulting from implementing Accounting Standards Update 2014-09 “Revenue from Contracts with Customers” (ASC 606), reduced revenues from our Four Corners area operations that were sold in October 2018, a reduction of rates resulting from a Northwest Pipeline rate case settlement, and a decrease following the Jackalope deconsolidation.
Service revenues – commodity considerationincreased as the result of implementing ASC 606 using a modified retrospective approach, effective January 1, 2018. Therefore, prior periods were not recast. These revenues represent consideration we receive in the form of commodities as full or partial payment for gathering and processing services provided. (See Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting
Policies of Notes to Consolidated Financial Statements.) Most of these NGL volumes are sold within the month processed and therefore are offset in Product costs below.
Product sales increased primarily due to higher marketing sales prices and volumes, including increased volumes associated with the Sequent Acquisition in third-quarter 2021 and the Trace Acquisition in second-quarter 2022. Product sales also increased due to higher sales volumes and prices associated with our upstream operations and system management gas sales, which are offset in Product costs, as well as higher prices and higher sales from the production oflower volumes related to our equity NGLs, reflecting higher NGL prices.sales activities. These increases arewere partially offset by the absence of $269 millionan unfavorable change in olefinsnatural gas marketing sales associated with our former olefins operations in 2017.
The increase in Product costs is primarily due to the impact of ASC 606netting the 2022 legacy natural gas marketing revenues with the associated costs (see Note 1 – General, Description of Business, and Basis of Presentation of Notes to Consolidated Financial Statements). As we are acting as agent for natural gas marketing customers of our Gas & NGL Marketing Services segment, our natural gas marketing product sales are presented net of the related costs of those activities, including significant 2022 lower of cost or net realizable value adjustments to our natural gas inventory.
The unfavorable change in Net gain (loss) on commodity derivatives primarily reflects higher net unrealized losses in our Gas & NGL Marketing Services segment, and higher net realized losses related to derivative contracts in our Other segment. Lower net realized losses at our West segment and a net unrealized gain at our Other segment in 2022 partially offset these impacts. We experience significant earnings volatility from the fair value accounting required for the derivatives used to hedge a portion of the economic value of the underlying transportation and storage portfolio as well as upstream related production. However, the unrealized fair value measurement gains and losses are generally offset by valuation changes in the economic value of the underlying production or transportation and storage contracts, which is not recognized until the underlying transaction occurs.
Product costs decreased primarily due to the impact of netting the 2022 legacy natural gas marketing revenues with the associated costs. This decrease was partially offset by higher prices and volumes associated with our NGL marketing activities, including the increase in volumes associated with the Trace Acquisition in second-quarter 2022, as well as significant 2022 lower of cost or net realizable value adjustments to our NGL inventory. Product costs reflected in this line item for 2018 includealso increased due to higher system management gas purchases and higher NGL prices associated with volumes acquired as commodity consideration forrelated to our equity NGL production activities.
Net processing services, as well as higher marketing and system management gas purchases. This increase is partially offset by the absence of $147 million of olefin feedstock purchasescommodity expenses decreased primarily due to the saleimpact of our former olefins operations, as well as the absence ofa 2022 net unrealized gain on derivatives for processing plant shrink gas purchases and lower volumes for natural gas purchases associated with theour equity NGL production of equity NGLs, which are reported in Processing commodity expenses in conjunction with the 2018 implementation of ASC 606.activities, partially offset by higher net realized prices.
ProcessingThe net sum of Service revenues – commodity expensesconsideration, Product sales, Product costs, presents the naturalnet realized gains and losses on commodity derivatives related to sales of product, and net realized processing commodity expenses comprise our Commodity margins. However, Product sales and net realized gains and losses on commodity derivatives at our Other segment reflecting sales related to our oil and gas purchases associated with the productionproducing properties comprise Net realized product sales and are excluded from our Commodity margins. See Results of equity NGLs as previously described in conjunction with the implementationOperations— Year-Over-Year Operating Results - Segments for additional discussion of ASC 606.Commodity margins and Net realized product sales on a segment basis.
Operating and maintenance expenses decreasedincreased primarily due to the absencehigher operating and maintenance costs, including $63 million of $80 millionhigher reimbursable electric power and storage costs which are substantially offset in Service revenues. The increase was also a result of higher expenses associated with our upstream operations, increased costs associated with our former olefinsTransco's Leidy South expansion project placed in service in December 2021, higher employee-related expenses, and Four Corners area operations.higher expenses associated with the 2022 Trace Acquisition and NorTex Asset Purchase.
Depreciation and amortization expenses decreasedincreased primarily due to amortization of intangibles acquired in the Sequent and Trace Acquisitions and an increase in depreciation at Transco related to ARO revisions (offset in Other (income) expense – net within Operating income (loss) resulting in no net impact on our results of operations), partially offset by the absence of 2021 depreciation on certain decommissioned facilities in our former olefins and Four Corners area operations, partially offset by new assets placed in-service.West segment.
Selling, general, and administrative expenses decreasedincreased primarily due to higher employee-related expenses driven by the absence of severance-related, organizational realignment,Sequent Acquisition in July 2021 and Financial Repositioninghigher expenses for various corporate costs, incurred in 2017, $25 million in reducedincluding technology costs to support efforts to track and quantify emissions associated with our former olefinsnatural gas procurement, transmission, and Four Corners area operations, and cost containment efforts. These decreases are partially offset by a charitable contribution of preferred stock to The Williams Companies Foundation, Inc. and fees associated with the WPZ Merger.delivery.
Impairment of certain assetsincludes 2018 impairments on certain assets in the Barnett Shale region and certain idle pipelines and 2017 impairments associated with certain assets in the Mid-Continent, Marcellus South, and Houston Ship Channel areas (see Note 18 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk of Notes to Consolidated Financial Statements).
Gain on sale of certain assets and businesses includes gains recognized on the sales of our Four Corners area in October 2018, our Gulf Coast pipeline systems in December 2018 and our Geismar Interest in July 2017 (see Note 3 – Acquisitions and Divestitures of Notes to Consolidated Financial Statements).
Regulatory charges resulting from Tax Reform relates to the 2017 establishment of regulatory liabilities for the probable return to customers through future rates of the future decrease in income taxes payable associated with Tax Reform. (See Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies of Notes to Consolidated Financial Statements).
The favorable change in Other (income) expense – net within Operating income (loss) includes the benefit of establishing achanged unfavorably primarily due to charges related to Eminence storage cavern abandonments and monitoring, as well as regulatory assetcharges associated with an increasea decrease in Transco’s estimated deferred state income tax rate, following the WPZ Merger in 2018, substantially offset by the absencedeferral of gains from certain contract settlementsARO depreciation (offset in Depreciation and terminationsamortization expenses resulting in 2017, the absenceno net impact on our results of a gain on the sale of our RGP Splitter in 2017, and 2018 charges establishing a regulatory liability associated with a decrease in Northwest Pipeline's estimated deferred state income tax rate following the WPZ Merger (see Note 7 – Other Income and Expenses of Notes to Consolidated Financial Statements)operations).
Operating income (loss) changed unfavorably primarily due to higher impairments of assets, lower gains on sales of assets and businesses, and the absence of operating income associated with our former olefins and Four Corners area operations, partially offset by the absence of regulatory charges resulting from Tax Reform, higher Service revenues primarily from expansion projects, and higher NGL margins.
The unfavorable change in Equity earnings (losses) is primarily due to a decrease in volumes at Discovery, partially offset by improved results at our Appalachia Midstream Investments and the deconsolidation of our Jackalope interest, which is accounted for as an equity-method investment beginning in the second quarter of 2018.
Other investing income (loss) – net includes a 2017 gain on disposition of our investments in DBJV and Ranch Westex JV LLC, a 2018 impairment related to our investment in UEOM, and 2018 gains on the deconsolidations of certain Permian basin assets and of our interest in Jackalope. (See Note 6 – Investing Activities of Notes to Consolidated Financial Statements.)
Interest expense increased primarily due to an increase in other financing obligations associated with Transco's Dalton and Atlantic Sunrise projects, as well as expense related to the deemed financing component of certain contract liabilities resulting from our implementation of ASC 606 in 2018. This increase is partially offset by lower interest rates on our outstanding debt in 2018 and lower borrowings on our credit facilities in 2018.
Other income (expense) – net below Operating income (loss) changed favorably primarily due to a decrease in charges reducing regulatory assets related to deferred taxes on equity AFUDC resulting from Tax Reform, an increase in equity AFUDC,increases at investments across our West segment, including RMM, and a lower settlement charge from the pension early payout program. These favorable changes wereat Laurel Mountain, partially offset by a decrease due to the absence of a net gain on early retirement of debt in 2017 and a loss on early retirement of debt in 2018. (See Note 7 – Other Income and Expensesof Notes to Consolidated Financial Statements.)at Appalachia Midstream Investments.
Provision (benefit) for income taxes changed unfavorablyfavorably primarily due to the absence of a $1.923 billion tax provision benefit associated with Tax Reform and releasing a $127 milliondecrease in our estimate of the state deferred income tax rate, a benefit related to the release of a valuation allowance, in 2017. The unfavorable change also reflects a $105 million valuation allowance in 2018 associated with certain foreign tax credits.and federal settlements, partially offset by higher pre-tax income. See Note 86 – Provision (Benefit) for Income Taxes of Notes to Consolidated Financial Statements for a discussion of the effective tax rate compared to the federal statutory rate for both periods.
The unfavorable change in Net income (loss) attributable to noncontrolling interests is primarily relateddue to WPZ, reflective of both our acquisition ofhigher results at the publicly held interests in WPZNortheast JV.
2021 vs. 2020
Service revenues increased primarily due to higher transportation fee revenues associated with the WPZ Mergerexpansion projects placed in service at Transco in 2020 and a fourth quarter 2017 net loss incurred by WPZ,2021, higher revenue associated with reimbursable electricity expenses, and higher processing and fractionation revenues in our Northeast G&P segment. This increase was partially offset by lower operating resultsvolume deficiency fee revenues, lower gathering volumes, and lower deferred revenue amortization.
Service revenues – commodity consideration increased primarily due to higher NGL prices. These revenues represent consideration we receive in the form of commodities as full or partial payment for processing services provided. Most of these NGL volumes are sold during the month processed and therefore are offset within Product costs below.
Product sales increased primarily due to higher prices and volumes associated with our natural gas and NGL marketing activities, as well as the inclusion of our recently acquired upstream operations. This increase also includes higher prices related to our equity NGL sales activities. These increases were partially offset by negative product marketing sales from operations acquired in the Sequent Acquisition in 2021 (which does not reflect commodity derivative net realized gains discussed below).
Net gain (loss) on commodity derivatives includes realized and unrealized gains and losses from derivative instruments. The unfavorable change primarily reflects net unrealized losses in our Gas & NGL Marketing Services segment, and net realized losses related to derivative contracts in our West and Other segments. Net realized gains at Gulfstar.our Gas & NGL Marketing Services segment partially offset these impacts.
Product costs increased primarily due to higher prices and volumes associated with our natural gas and NGL marketing activities, as well as higher NGL prices associated with volumes acquired as commodity consideration related to our equity NGL production activities.
Net processing commodity expenses increased primarily due to higher prices for natural gas purchases associated with our equity NGL production activities, partially offset by lower volumes.
Operating and maintenance expenses increased primarily due to the inclusion of our recently acquired upstream operations and higher employee-related expenses, which reflect the absence of a 2020 favorable impact of a change in an employee benefit policy and increased incentive compensation costs associated with improved company performance, as well as higher reimbursable electricity expenses.
Depreciation and amortization expenses increased primarily due to the inclusion of our recently acquired upstream operations, reduced estimated useful lives for certain facilities in our West segment decommissioned during 2021, new assets placed in-service at Transco, and the amortization of intangible assets resulting from the Sequent Acquisition.
Selling, general, and administrative expenses increased primarily due to higher employee-related expenses, which reflect increased incentive compensation costs associated with improved company performance, Sequent Acquisition employee-related costs, and the absence of a 2020 favorable impact of a change in an employee benefit policy, partially offset by lower expenses for various corporate costs.
Impairment of certain assets reflects the 2020 impairment of our Northeast Supply Enhancement development project and certain gathering assets in the Marcellus Shale region (see Note 15 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk of Notes to Consolidated Financial Statements).
Impairment of goodwill reflects the goodwill impairment charge at the Northeast reporting unit in 2020 (see Note 15 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk of Notes to Consolidated Financial Statements).
Equity earnings (losses) changed favorably primarily due to the absence of the 2020 impairment of goodwill at RMM, increases at Appalachia Midstream Investments, Laurel Mountain, Blue Racer, Aux Sable, and Discovery, partially offset by a decrease at OPPL.
Impairment of equity-method investments reflects the absence of 2020 impairments to various equity-method investments (see Note 15 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk of Notes to Consolidated Financial Statements).
The favorable change in Other income (expense) – net below Operating income (loss) reflects the absence of a 2020 charge for a legal settlement associated with former olefins operations and the absence of 2020 write-offs of certain regulatory assets related to cancelled projects, partially offset by the unfavorable impact of a 2021 accrual for a loss contingency.
Provision (benefit) for income taxes changed unfavorably primarily due to higher pre-tax income. See Note 6 – Provision (Benefit) for Income Taxes of Notes to Consolidated Financial Statements for a discussion of the effective tax rate compared to the federal statutory rate for both periods.
The unfavorable change in Net income (loss) attributable to noncontrolling interests is primarily due to the absence of our partner’s share of the 2020 goodwill impairment at the Northeast reporting unit.
Year-Over-Year Operating Results – Segments
We evaluate segment operating performance based upon Modified EBITDA. Note 2018 – Segment Disclosures of Notes to Consolidated Financial Statements includes a reconciliation of this non-GAAP measure to Net income (loss). Management uses Modified EBITDA because it is an accepted financial indicator used by investors to compare company performance. In addition, management believes that this measure provides investors an enhanced perspective of the operating performance of our assets. Modified EBITDA should not be considered in isolation or as a substitute for a measure of performance prepared in accordance with GAAP.
Atlantic-Gulf | | | | | | | | | | | | | | | | | |
| Year Ended December 31, |
| 2022 | | 2021 | | 2020 |
| (Millions) |
| Service revenues | $ | 3,579 | | | $ | 3,385 | | | $ | 3,257 | |
| Service revenues – commodity consideration (1) | 64 | | | 52 | | | 21 | |
| Product sales (1) | 404 | | | 349 | | | 191 | |
| | | | | |
| Segment revenues | 4,047 | | | 3,786 | | | 3,469 | |
| | | | | |
| Product costs (1) | (399) | | | (349) | | | (193) | |
| Net processing commodity expenses (1) | (26) | | | (17) | | | (7) | |
| Other segment costs and expenses | (1,141) | | | (980) | | | (886) | |
| Impairment of certain assets | — | | | (2) | | | (170) | |
| | | | | |
| | | | | |
| Proportional Modified EBITDA of equity-method investments | 193 | | | 183 | | | 166 | |
| Transmission & Gulf of Mexico Modified EBITDA | $ | 2,674 | | | $ | 2,621 | | | $ | 2,379 | |
| | | | | |
| Commodity margins | $ | 43 | | | $ | 35 | | | $ | 12 | |
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2019 | | 2018 | | 2017 |
| | (Millions) |
| Service revenues | $ | 2,861 |
| | $ | 2,509 |
| | $ | 2,239 |
|
| Service revenues – commodity consideration | 41 |
| | 59 |
| | — |
|
| Product sales | 288 |
| | 435 |
| | 484 |
|
| Segment revenues | 3,190 |
| | 3,003 |
| | 2,723 |
|
| | | | | | |
| Product costs | (288 | ) | | (438 | ) | | (437 | ) |
| Processing commodity expenses | (16 | ) | | (16 | ) | | — |
|
| Other segment costs and expenses | (814 | ) | | (799 | ) | | (819 | ) |
| Impairment of certain assets | (354 | ) | | — |
| | — |
|
| Gain on sale of certain assets and businesses | — |
| | 81 |
| | — |
|
| Regulatory charges resulting from Tax Reform | — |
| | 9 |
| | (493 | ) |
| Proportional Modified EBITDA of equity-method investments | 177 |
| | 183 |
| | 264 |
|
| Atlantic-Gulf Modified EBITDA | $ | 1,895 |
| | $ | 2,023 |
| | $ | 1,238 |
|
| | | | | | |
| Commodity margins | $ | 25 |
| | $ | 40 |
| | $ | 47 |
|
2019(1)Included as a component of Commodity margins.
2022 vs. 20182021
Atlantic-GulfTransmission & Gulf of Mexico Modified EBITDA decreasedincreased primarily due to the impairment of Constitution, the absence of a 2018higher Gain on sale of certain assets and businesses Service revenues, andpartially offset by higher Other segment costs and expenses, partially offset by increased Service revenues related to expansion projects placed into service during 2018 and 2019.expenses.
Service revenues increased primarily due to a $403to:
•A $163 million increase in Transco’s natural gas transportationservice revenues primarily driven by a $358 million increase related toassociated with the Leidy South expansion projectsproject placed fully in service in 2018December 2021, park and 2019, as well asloan services, short-term firm transportation, overall demand, and commodity fee revenues. Additionally, 2022 benefited from higher revenue associated with Transco’s general rate case settlement and increased amounts for reimbursable electric power costs and storage expenses. Partially offsetting these increases wererates effective since the second quarter of 2022, partially offset by lower fee revenuescash out surcharges, all of $62which are offset by similar changes in electricity, storage and cash out charges reflected in Other segment costs and expenses;
•A $21 million increase in the Eastern Gulf Coast region primarily due to higher production handling and gathering volumes from the absence of temporary shut-ins due to producer operational issues and lower deferred revenue amortizationweather-related events in 2021, partially offset by a decrease at Gulfstar as well asOne for the saleTubular Bells field primarily due to lower production handling, gathering and transportation volumes from natural decline;
•A $16 million increase primarily related to storage and transportation revenues due to the acquisition of certainNorTex in August 2022; partially offset by
•A $13 million decrease in the Western Gulf Coast pipeline assetsregion primarily at Perdido due to lower transportation and gathering volumes from temporary downtime from producer operational issues in fourth-quarter 2018.2022.
The net sum of Commodity marginsService revenues – commodity consideration, Product sales, Product costs, and Processing commodity expenses comprise our commodity margins. Our commodity margins associated with our equity NGLs decreased $16increased $5 million consisting of a $26 million decrease associated with unfavorable net realizedprimarily driven by favorable NGL sales prices, partially offset by a $10 million increasehigher prices for natural gas purchases associated with higher sales volumes. The higherour equity NGL volumes were primarily related to the absence of 2018 downtime to modify the Mobile Bay processing plant for the Norphlet project. Additionally, the decrease in Product sales includes a $93 million decrease in commodity marketing sales due to lower NGL prices and volumes and a $39 million decrease in system management gas sales. Marketing sales and system management gas sales are substantially offset in Product costs and therefore have little impact to Modified EBITDA.production activities.
Other segment costs and expenses increased primarily due to higher operating costs including higher reimbursable electric power costs and storage costs, partially offset by favorable cash out charges, all of which are offset by similar changes in electricity reimbursements, cash out charges, and storage revenues reflected in Service revenues. Additionally, 2022 was impacted by higher costs associated with the Leidy South expansion project;
maintenance costs primarily related to general maintenance at Transco, Gulf Coast region, and Northwest Pipeline; charges related to Eminence storage cavern abandonments and monitoring; and regulatory charges associated with a $56 million unfavorabledecrease in Transco’s estimated deferred state income tax rate, higher employee-related costs, corporate allocations, and operations acquired in the NorTex Asset Purchase. These increases are partially offset by a favorable change in equity AFUDCthe deferral of ARO related depreciation at Transco.
2021 vs. 2020
Transmission & Gulf of Mexico Modified EBITDA increased primarily due to favorable changes to Impairment of certain assets and Service revenues, partially offset by higher Other segment costs and expenses.
Service revenues increased primarily due to:
•A $135 million increase in Transco’s and Northwest Pipeline’s natural gas transportation and storage revenues primarily associated with expansion projects placed in service in 2020 and 2021, higher reimbursable electric power costs and a cash out surcharge, which are offset by similar changes in electricity and cash out charges, reflected in Other segment costs and expenses;
•A $21 million increase from the Norphlet pipeline associated primarily with higher deferred revenue amortization and higher volumes;
•An $18 million increase at Perdido primarily driven by higher volumes due to the absence of temporary shut-ins in 2020 related to scheduled maintenance and fewer Western Gulf of Mexico weather-related events; partially offset by
•A $25 million decrease at Gulfstar One for the Tubular Bells field primarily associated with lower deferred revenue amortization from lower contractually determined maximum daily quantities;
•A $17 million decrease due to lower construction activity, a $32 million chargevolumes at Gulfstar One in 2019 for severance andthe Gunflint field due to ongoing producer operational issues, partially offset by the lower temporary shut-ins related costs primarilyto pricing in 2020.
Commodity margins associated with our 2019 VSP, aequity NGLs increased $21 million increaseprimarily driven by favorable NGL sales prices.
Other segment costs and expenses increased primarily due to higher incentive and benefit employee-related costs as previously discussed; higher operating costs, including higher reimbursable electric power costs; and a cash out surcharge reserve, which are offset by similar changes in reimbursable powerelectricity and storage expenses, $16 million of expensecash out reimbursements, reflected in 2019 related to the reversal of expenditures previously capitalized, Service revenues; and the absence of a $12 million 2018 gain on asset retirements. These unfavorable changes werehigher operating taxes, partially offset by $77 million of neta favorable changes to charges and creditschange associated with regulatory assets and liabilities, which were significantly driven by the previously mentioned settlement in Transco’s general rate case, and a $46 million decrease in Transco’s contracted services compared to 2018 mainly due to the timingdeferral of required engine overhauls and integrity testing.asset retirement obligation-related depreciation at Transco.
Impairment of certain assets includesreflects the 2019absence of the impairment of our ConstitutionNortheast Supply Enhancement development project in 2020 (see Note 1815 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk of Notes to Consolidated Financial Statements).
Gain on sale of certain assets and businesses reflects an $81 million gain from the sale of our Gulf Coast pipeline system assets in fourth-quarter 2018 (see Note 3 – Acquisitions and Divestitures of Notes to Consolidated Financial Statements).
2018 vs. 2017
Atlantic-Gulf Modified EBITDA increased primarily due to the absence of regulatory charges associated with the impact of Tax Reform at Transco, higher Service revenues, and a 2018 gain on the sale of certain assets;partially offset by lower Proportional Modified EBITDA of equity-method investments.
Service revenues increased primarily due to a $253 million increase in Transco’s natural gas transportation fee revenues primarily due to a $241 million increase associated with expansion projects placed in-service in 2017 and 2018.
Service revenues – commodity consideration increased as a result of implementing ASC 606 using a modified retrospective approach. These revenues represent consideration we received in the form of commodities as full or partial payment for gathering and processing services provided. Most of these NGL volumes are sold within the month processed and therefore are offset in Product costs below.
The decrease in Product sales includes:
| |
• | A $90 million decrease in commodity marketing sales driven by a $149 million decrease in crude oil sales as this activity is now presented on a net basis within Product costs in conjunction with the adoption of ASC 606, partially offset by a $59 million increase in NGL marketing sales primarily reflecting 20 percent higher non-ethane prices;
|
A $14 million decrease in sales associated with the production of our equity NGLs, as further described below as part of our commodity margins;
| |
• | A $57 million increase in system management gas sales. System management gas sales are offset in Product costs and therefore have little impact to Modified EBITDA.
|
Product costs slightly increased primarily due to a $59 million increase in system management gas purchases (substantially offset in Product sales) and the impact of ASC 606 in which costs reflected in this line item for 2018 include volumes acquired as commodity consideration for NGL processing services. This increase was partially offset by an $87 million decrease in marketing purchases (more than offset in Product sales) and the absence of natural gas purchases associated with the production of equity NGLs, which are now reported in Processing commodity expenses in conjunction with the implementation of ASC 606.
Processing commodity expenses presents the natural gas purchases associated with the production of equity NGLs as previously described in conjunction with the implementation of ASC 606.
The net sum of Service revenues – commodity consideration, Product sales, Product costs, and Processing commodity expenses comprise our commodity margins.
Other segment costs and expenses decreased primarily due to a $17 million increase in Transco’s equity AFUDC as a result of higher construction activity in 2018.
Gain on sale of certain assets reflects an $81 million gain from the sale of our Gulf Coast pipeline system assets in fourth-quarter 2018, as previously mentioned.
The decrease in Regulatory charges resulting from Tax Reform reflects the absence of $493 million of regulatory charges in 2017 associated with the impact of Tax Reform at Transco (See Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies of Notes to Consolidated Financial Statements).
The decrease in Proportional Modified EBITDA of equity-method investments isincreased at Discovery driven by higher NGL sales prices and higher volumes due to an $89 million decrease at Discovery, primarily related to a $76 million decrease associated with production ending on certain wells.the absence of prior year scheduled maintenance.
Northeast G&P
| | | | | | | | | | | | | | | | | |
| Year Ended December 31, |
| 2022 | | 2021 | | 2020 |
| (Millions) |
| Service revenues | $ | 1,654 | | | $ | 1,528 | | | $ | 1,465 | |
| Service revenues – commodity consideration (1) | 14 | | | 7 | | | 7 | |
| Product sales (1) | 134 | | | 99 | | | 57 | |
| Segment revenues | 1,802 | | | 1,634 | | | 1,529 | |
| | | | | |
| Product costs (1) | (135) | | | (99) | | | (57) | |
| Net processing commodity expenses (1) | (3) | | | (2) | | | (3) | |
| Other segment costs and expenses | (522) | | | (503) | | | (441) | |
| Impairment of certain assets | — | | | — | | | (12) | |
| Proportional Modified EBITDA of equity-method investments | 654 | | | 682 | | | 473 | |
| Northeast G&P Modified EBITDA | $ | 1,796 | | | $ | 1,712 | | | $ | 1,489 | |
| | | | | |
| Commodity margins | $ | 10 | | | $ | 5 | | | $ | 4 | |
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2019 | | 2018 | | 2017 |
| | (Millions) |
| Service revenues | $ | 1,338 |
| | $ | 976 |
| | $ | 872 |
|
| Service revenues – commodity consideration | 12 |
| | 20 |
| | — |
|
| Product sales | 150 |
| | 287 |
| | 291 |
|
| Segment revenues | 1,500 |
| | 1,283 |
| | 1,163 |
|
| | | | | | |
| Product costs | (152 | ) | | (289 | ) | | (286 | ) |
| Processing commodity expenses | (8 | ) | | (9 | ) | | — |
|
| Other segment costs and expenses | (470 | ) | | (392 | ) | | (386 | ) |
| Impairment of certain assets | (10 | ) | | — |
| | (124 | ) |
| Proportional Modified EBITDA of equity-method investments | 454 |
| | 493 |
| | 452 |
|
| Northeast G&P Modified EBITDA | $ | 1,314 |
| | $ | 1,086 |
| | $ | 819 |
|
| | | | | | |
| Commodity margins | $ | 2 |
| | $ | 9 |
| | $ | 5 |
|
2019(1)Included as a component of Commodity margins.
2022 vs. 20182021
Northeast G&P Modified EBITDA increased primarily due to higher Service revenues due to increased gathering volumes, as well as the $38 million favorable impact of acquiring the additional interest of UEOM,, partially offset by 2019 impairments.lower Proportional Modified EBITDA of equity-method investments and higher Other segment costs and expenses.
Service revenues increased primarily due to:
•A $158$64 million increase associated with the consolidation of UEOM, as previously discussed;
A $102 million increase associated with higher gatheringin revenues at Susquehanna Supply Hub reflecting 18 percent higher gathering volumes due to increased production from customers and higher rates;
A $49 million increase at Ohio Valley Midstreamthe Northeast JV primarily duerelated to higher gathering, processing, and transportation volumes;fractionation volumes as well as higher processing rates;
•A $36$43 million increase in gathering revenues in the Utica Shale region dueprimarily related to higher gathering rates and volumesresulting from new wells;annual cost of service contract redeterminations, as well as proceeds from the release of an acreage dedication;
•A $14 million increase in compression revenues for services charged to an affiliate driven by higher volumes.
Product sales decreased primarily due to lower non-ethane volumes and prices within our marketing activities. The changes in marketing revenues areassociated with reimbursable expenses, which is offset by similar changes in marketing purchases,the charges reflected above asin ProductOther segment costs. and expenses;
Other segment costs and expenses increased primarily due to:
A $53 million increase associated with the consolidation of UEOM;
A $10 million increase related to transactionhigher operating expenses, associated with the acquisition of UEOMincluding higher electricity and the formation of the Northeast JV;
A $7 million chargefuel, which is partially offset in 2019 for severance and related costs primarily associated with our VSP.
Impairment of certain assets increased due to a $10 million write-down of other certain assets that may no longer be in use or are surplus in nature in 2019 (see Service revenuesNote 18 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk of Notes to Consolidated Financial Statements).
Proportional Modified EBITDA of equity-method investments decreased $59 millionat Appalachia Midstream Investments primarily driven by lower gathering rates resulting from annual cost of service contract redeterminations as well as lower volumes. Additionally, there was a result of the consolidation of UEOM and $10 milliondecrease at Blue Racer primarily due to unfavorable rates reflecting lower NGL prices at Aux Sable. Thisvolumes. The decrease was partially offset by a $29 millionan increase at Appalachia Midstream Investments, reflecting higher volumesLaurel Mountain primarily due to increased customer production.higher commodity-based gathering rates.
2021 vs. 20172020
Northeast G&P Modified EBITDA increased primarily due to the absence of Impairment of certain assets in 2017, and higher Service revenues andincreased Proportional Modified EBITDA of equity-method investments and higher Service revenues, partially offset by increased Other segment costs and expenses.
Service revenues increased primarily due to:
•A $65$27 million increase in revenues associated with reimbursable electricity expenses, which is offset by similar changes in electricity charges, reflected in Other segment costs and expenses;
•A $23 million increase in revenues at the Northeast JV primarily related to higher processing and fractionation volumes, partially offset by lower gathering feevolumes;
•A $6 million increase in revenues at Susquehanna Supply Hub dueprimarily related to 13 percent higher gathering volumes reflecting increased customer production;
A $24 million increase at Ohio River Supply Hub reflecting higherrates, partially offset by lower gathering volumes due to increased customer production;
An $11 million increase in Utica gathering fee revenues reflecting higher rates and volumes.
Service revenues – commodity considerationOther segment costs and expenses increased as a result of implementing ASC 606 using a modified retrospective approach. These revenues represent consideration we receive in the form of commodities as full or partial payment for gathering and processing services provided. Most of these NGL volumes are sold within the month processed and therefore are offset in Processing commodity expenses.
Product sales decreased primarily due to $31 million lower marketing sales, driven by lower non-ethane volumeshigher maintenance and prices. The changes in marketing sales are offset by similar changes in marketing purchases, reflected aboveoperating expenses, including higher electricity charges, as Productwell as higher incentive and benefit employee-related costs. The decrease in Product sales is partially offset by $21 million in higher system management gas sales. System management gas sales are offset in Product costs and therefore have no impact on Modified EBITDA. as previously discussed.
Impairment of certain assets reflects the absence of a $115$12 million impairment of certain gathering operationsassets in the Marcellus SouthShale region in 2017.
Proportional Modified EBITDA of equity-method investments increased primarily due to a $33 million increase at Appalachia Midstream Investments reflecting our increased ownership acquired in late first-quarter 2017 and higher volumes. Improvements at Aux Sable and Caiman II also contributed to the increase.
West
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2019 | | 2018 | | 2017 |
| | (Millions) |
| Service revenues | $ | 1,813 |
| | $ | 2,085 |
| | $ | 2,246 |
|
Service revenues – commodity consideration | 150 |
| | 321 |
| | — |
|
| Product sales | 1,797 |
| | 2,448 |
| | 2,013 |
|
| Segment revenues | 3,760 |
| | 4,854 |
| | 4,259 |
|
| | | | | | |
| Product costs | (1,774 | ) | | (2,448 | ) | | (1,842 | ) |
| Processing commodity expenses | (79 | ) | | (116 | ) | | — |
|
| Other segment costs and expenses | (688 | ) | | (825 | ) | | (832 | ) |
| Impairment of certain assets | (100 | ) | | (1,849 | ) | | (1,032 | ) |
| Gain on sale of certain assets and businesses | (2 | ) | | 591 |
| | — |
|
| Regulatory charges resulting from Tax Reform | — |
| | 7 |
| | (220 | ) |
| Proportional Modified EBITDA of equity-method investments | 115 |
| | 94 |
| | 79 |
|
| West Modified EBITDA | $ | 1,232 |
| | $ | 308 |
| | $ | 412 |
|
| | | | | | |
| Commodity margins | $ | 94 |
| | $ | 205 |
| | $ | 171 |
|
2019 vs. 2018
West Modified EBITDA increased primarily due to lower Impairment of certain assets and lower Other segment costs and expenses, partially offset by a lower gain on sale of certain assets in 2019, lower Service revenues, and lower commodity margins.
Service revenues decreased primarily due to:
A $218 million decrease associated with asset divestitures and deconsolidations during 2018 and 2019, including our former Four Corners area assets, certain Delaware basin assets that were contributed to our Brazos Permian II equity-method investment, and our Jackalope assets which were deconsolidated in second-quarter 2018 and subsequently sold in second-quarter 2019;
A $57 million decrease driven by lower deferred revenue amortization and MVC deficiency fee revenues in the Barnett Shale region primarily associated with the expiration of a certain MVC agreement;
A $17 million decrease driven by lower gathering volumes primarily in the Mid-Continent, Barnett Shale, and Wamsutter regions, partially offset by higher gathering volumes primarily in the Haynesville Shale and Eagle Ford regions;
A $15 million decrease associated with lower processing rates primarily driven by lower commodity pricing in the Piceance region;
A $15 million decrease associated with lower gathering rates primarily in the Mid-Continent and Haynesville Shale regions;
A $17 million increase related to other MVC deficiency fee revenues;
A $13 million increase related to higher fractionation and storage fees;
An $8 million increase associated with the resolution of a prior period performance obligation.
The net sum of Service revenues – commodity consideration, Product sales, Product costs, and Processing commodity expenses comprise our commodity margins. Our commodity margins associated with our equity NGLs decreased $127 million primarily due to:
A $98 million decrease associated with lower sales volumes, consisting of $54 million related to the absence of our former Four Corners area assets and $44 million due to 12 percent lower non-ethane volumes and 33 percent lower ethane sales volumes primarily due to higher ethane rejection in 2019, natural declines, less producer drilling activity, and more severe weather conditions in first-quarter 2019;
A $66 million decrease associated with lower sales prices primarily due to 29 percent and 48 percent lower average net realized per-unit non-ethane and ethane sales prices, respectively;
A $37 million increase related to lower natural gas purchases associated with lower equity NGL production volumes and lower natural gas prices, including $9 million related to the absence of our former Four Corners area assets.
Additionally, the decrease in Product sales includes a $447 million decrease in marketing sales, which is due to lower sales prices, partially offset by higher sales volumes, and a $36 million decrease related to the sale of other products. These decreases are substantially offset in Product costs. Marketing margins increased by $27 million primarily due to favorable changes in prices.
Other segment costs and expenses decreased primarily due to a $127 million reduction associated with the absences of our former Four Corners area assets and from the Jackalope deconsolidation in second-quarter 2018, the absence of a 2018 unfavorable charge of $12 million for a regulatory liability associated with a decrease in Northwest Pipeline’s estimated deferred state income tax rate following the WPZ Merger, $12 million favorable settlements in 2019, as well as $10 million lower ad valorem taxes. These decreases were partially offset by an unfavorable charge in 2019 for severance and related costs primarily associated with our VSP of $17 million.
Impairment of certain assets decreased primarily due to the absence of the $1,849 million Barnett impairment in 2018, partially offset by various 2019 impairments2020 (see Note 1815 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk of Notes to Consolidated Financial Statements).
The decrease in Proportional Modified EBITDA of equity-method investmentsGain on sale increased at Appalachia Midstream Investments primarily driven by higher volumes as well as the absence of our $26 million share of an impairment of certain assets in 2020 that were subsequently sold. Additionally, there was an increase at Blue Racer primarily due to the favorable impact of increased ownership as well as the absence of our $10 million share of an impairment of certain assets in 2020. There was also an increase at Laurel Mountain due to higher commodity-based gathering rates as well as the absence of our $11 million share of an impairment of certain assets in 2020 that were subsequently sold and businesseshigher MVC revenue, partially offset by lower volumes, and an increase at Aux Sable.
West
| | | | | | | | | | | | | | | | | |
| Year Ended December 31, |
| 2022 | | 2021 | | 2020 |
| (Millions) |
| Service revenues | $ | 1,542 | | | $ | 1,248 | | | $ | 1,272 | |
Service revenues – commodity consideration (1) | 182 | | | 179 | | | 101 | |
| Product sales (1) | 841 | | | 643 | | | 152 | |
| | | | | |
Net realized gain (loss) on commodity derivatives – service revenues | (1) | | | (15) | | | — | |
Net realized gain (loss) on commodity derivatives – product sales (1) | (3) | | | (29) | | | (2) | |
| Net realized gain (loss) on commodity derivatives | (4) | | | (44) | | | (2) | |
| | | | | |
| Segment revenues | 2,561 | | | 2,026 | | | 1,523 | |
| | | | | |
| Product costs (1) | (813) | | | (608) | | | (154) | |
| Net processing commodity expenses (1) | (105) | | | (85) | | | (58) | |
| Other segment costs and expenses | (564) | | | (477) | | | (474) | |
| | | | | |
| | | | | |
| Proportional Modified EBITDA of equity-method investments | 132 | | | 105 | | | 110 | |
| West Modified EBITDA | $ | 1,211 | | | $ | 961 | | | $ | 947 | |
| | | | | |
| Commodity margins | $ | 102 | | | $ | 100 | | | $ | 39 | |
| | | | | |
________________
(1) Included as a component of Commodity margins.
2022 vs. 2021
West Modified EBITDA reflectsincreased primarily due to higher Service revenues and a favorable change in Net realized gain (loss) on commodity derivatives, partially offset by higher Other segment costs and expenses.
Service revenues increased primarily due to:
•A $186 million increase in the Haynesville Shale region primarily due to higher gathering volumes including volumes from the Trace Acquisition as well as higher gathering rates driven by favorable commodity pricing;
•A $96 million increase in the Barnett Shale region primarily due to higher gathering rates driven by favorable commodity pricing;
•A $14 million increase associated with higher fractionation fees primarily due to higher fractionation volumes from a new contract;
•A $4 million increase in the Eagle Ford region primarily due to higher MVC revenues, escalated gathering rates, and higher deferred revenue amortization, substantially offset by lower volumes due to decreased producer activity; partially offset by
•A $10 million decrease in the Wamsutter region primarily due to lower MVC revenue.
Net realized gain (loss) on commodity derivatives – service revenues changed favorably due to a change in settled commodity prices relative to our hedge positions.
Product margins from our equity NGLs increased $6 million primarily due to higher net realized NGL sales prices, partially offset by higher net realized prices for natural gas purchases associated with our equity NGL production activities. Additionally, volumes of equity NGL sold and natural gas purchased associated with our
equity NGL production activities were lower primarily due to a customer contract change. Margins from other sales activities increased $16 million primarily due to higher condensate sales and favorable pricing. Marketing margins decreased $20 million primarily due to the absence of the gain from the salefavorable impact of our Four Corners area assets recordedWinter Storm Uri in the fourthfirst quarter of 2018 (see Note 3 – Acquisitions2021.
Other segment costs and Divestituresexpenses increased primarily due to higher operating expenses related to timing and scope of Notesactivities including from operations acquired in the Trace Acquisition, the absence of gains on asset sales in 2021, higher corporate allocations, acquisition-related costs associated with the Trace Acquisition in 2022, and an unfavorable change in our net imbalance liability due to Consolidated Financial Statements).changes in pricing.
Proportional Modified EBITDA of equity-method investments increased primarily due to the additions of the RMMhigher volumes at OPPL and Brazos Permian II equity-method investments in the second half of 2018, partially offset by the sale of our Jackalope investment in second-quarter 2019.higher commodity prices and volumes at RMM.
20182021 vs. 20172020
West Modified EBITDA decreasedincreased primarily due to the increase inhigher Impairment of certain assetsCommodity margins, and lower Service revenues. These decreases were partially offset by the Gain on sale of certain assets and businesses in 2018, the absence of regulatory charges associated with the impact of Tax Reform, and higher NGL margins driven by higher NGL prices and lower realized natural gas prices, partially offset by lower NGL volumes.Service revenues.
Service revenues decreased primarily due to:
•A $64 million decrease primarily associated with implementing the new revenue guidance under ASC 606 including a $118 million decrease related to lower amortization of deferred revenue associated with the up-front cash payments received in conjunction with the fourth quarter 2016 Barnett Shale and Mid-Continent contract restructurings, partially offset by a $54 million increase related to other deferred revenue amortization primarily in the Permian basin;
A $42$63 million decrease associated with the sale of our Four Corners area assets in October 2018;
A $30 million decrease at Northwest Pipelinelower volumes, primarily due to production declines in the reductionEagle Ford Shale region which impact is substantially offset by recognition of its rates as a result of a rate case settlement that became effective January 1, 2018;higher MVC revenue (see below);
•A $29 million decrease following the Jackalope deconsolidation in second-quarter 2018;
A $15$22 million decrease driven by lower gathering volumesdeferred revenue amortization, primary in the Barnett Shale region; partially offset by
•A $37 million increase associated with higher MVC revenue primarily in the Eagle Ford Shale region, partially offset by lower MVC revenue in the Wamsutter region;
•A $17 million increase in revenues associated primarily with reimbursable compressor power and fuel purchases due to higher prices related to the impact of Winter Storm Uri in the first quarter of 2021, which are offset by similar changes in Other segment costs and expenses;
•A $10 million increase associated with higher net realized gathering and processing rates, primarily in the Barnett Shale and Mid-ContinentPiceance regions due to higher commodity pricing, along with escalated gathering rates in the Eagle Ford Shale region, partially offset by a decrease in gathering rates in the Haynesville Shale region due to a customer contract change.
Marketing margins increased by $36 million primarily due to favorable changes in net realized natural gas and NGL prices, including the impact of Winter Storm Uri in the first quarter of 2021. Product margins from our equity NGLs increased by $13 million, primarily due to favorable net realized commodity price changes, partially offset by lower sales volumes. Margins on other sales of products increased $12 million primarily due to higher commodity prices.
Other segment costs and expenses increased primarily due to higher incentive and benefit employee-related expenses as previously discussed, higher reimbursable compressor power and fuel purchases which are offset in Service revenues, and higher compressor and plant fuel expenses which are not reimbursable, partially offset by gains on asset sales in 2021, lower leased compressor expenses, favorable changes in system gains and losses, lower legal and consulting expenses, and favorable settlements.
Proportional Modified EBITDA of equity-method investments decreased primarily due to lower volumes at OPPL, partially offset by higher volumes in the Niobrara (prior to the Jackalope deconsolidation), Piceance, and commodity prices at Brazos Permian regions;II.
A $21 million increase associated with higher gathering and processing rates in the Piceance region driven by higher
Gas & NGL prices as well as higher average gathering and processing rates across most other areas, partially offset by lower contract rates primarily in the Haynesville Shale region.Marketing Services
| | | | | | | | | | | | | | | | | | | | | |
| Year Ended December 31, |
| 2022 | | 2021 | | 2020 | | | | |
| (Millions) |
| Service revenues | $ | 3 | | | $ | 3 | | | $ | 32 | | | | | |
| Product sales (1) | 3,534 | | | 4,292 | | | 1,602 | | | | | |
| | | | | | | | | |
| Net realized gain (loss) from derivative instruments (1) | 17 | | | 25 | | | (3) | | | | | |
| Net unrealized gain (loss) from derivative instruments | (321) | | | (109) | | | — | | | | | |
| Net gain (loss) on commodity derivatives | (304) | | | (84) | | | (3) | | | | | |
| | | | | | | | | |
| Segment revenues | 3,233 | | | 4,211 | | | 1,631 | | | | | |
| Net unrealized gain (loss) from derivative instruments within Net processing commodity expenses | 47 | | | — | | | — | | | | | |
| Product costs (1) | (3,228) | | | (4,152) | | | (1,569) | | | | | |
| Other segment costs and expenses | (92) | | | (37) | | | (11) | | | | | |
| Gas & NGL Marketing Services Modified EBITDA | $ | (40) | | | $ | 22 | | | $ | 51 | | | | | |
| | | | | | | | | |
| Commodity margins | $ | 323 | | | $ | 165 | | | $ | 30 | | | | | |
________________Service revenues – commodity consideration increased(1) Included as a resultcomponent of implementing ASC 606 using a modified retrospective approach. These revenues represent consideration we receive in the form of commodities as full or partial payment for gatheringCommodity margins.
2022 vs. 2021
Gas & NGL Marketing Services Modified EBITDA decreased primarily due to higher net unrealized loss from derivative instruments and processing services provided. Most of these NGL volumes are sold within the month processedhigher Other segment costs and therefore are offset in expensesProduct costs below.
The increase in Product sales includes:
| |
• | A $373 million increase in marketing sales primarily due to increases in realized NGL prices including a 14 percent increase in average non-ethane per-unit sales prices and a 25 percent increase in ethane prices, in addition to a 15 percent increase in ethane volumes (more than offset by higher Product costs);
|
A $47 million increase in sales associated with the production of our equity NGLs, as further described below as part of our commodity margins;
| |
• | An $18 million increase in system management gas sales due to a change in presentation in accordance with ASC 606, which are more than offset in Product costs and, therefore, have little impact on Modified EBITDA.
|
The increase in Product costs includes the impact of ASC 606 in which costs reflected in this line item for 2018 include volumes acquired as commodity consideration for NGL processing services, a $381 million increase in marketing purchases (substantially offset in Product sales), a $19 million increase in system management gas purchases (substantially offset in Product sales), partially offset by the absence of natural gas purchases associated with the production of equity NGLs, which are now reported inhigher Processing commodity expenses in conjunction with the implementation of ASC 606.
Processing commodity expenses presents the natural gas purchases associated with the production of equity NGLs as previously described in conjunction with the implementation of ASC 606Commodity margins.
The net sum of Service revenues –Commodity margins commodity consideration, Product sales, Product costs, and Processing commodity expenses comprise our commodity margins. Our commodity margins increased $158 million primarily due to a $40to:
•A $188 million increase in NGL productnatural gas marketing margins which included the following:
◦A $301 million increase in natural gas transportation capacity marketing margins primarily resulting from the Sequent Acquisition in the third quarter of 2021 and an increase in favorable pricing spreads in 2022 compared to 2021; partially offset by an $8
◦A $58 million decrease inassociated with our legacy natural gas marketing margins. NGL margins are driven by $56 million in higher ethane and non-ethane per-unit prices, reflecting 19 percent higher realized non-ethane per-unit sales prices and 50 percent higher realized ethane per-unit sales prices. These increases were partially offset by $18 million in lower volumesoperations primarily due to the saleabsence of the favorable impact of Winter Storm Uri in the first quarter of 2021;
◦A $55 million decrease in natural gas storage marketing margins due primarily to an increase in lower of cost or net realizable value inventory adjustments of $115 million and higher storage fees, partially offset by higher storage withdrawals in 2022 compared to 2021.
•A $30 million decrease in our Four Corners area assetsNGL marketing margins primarily due to lower of cost or net realizable value inventory adjustments in October 2018.2022.
Net unrealized gain (loss) from derivative instruments changed primarily due to the Sequent Acquisition in July 2021, and a change in forward commodity prices relative to our hedge positions in 2022 compared to 2021.
Other segment costs and expenses increased primarily due to higher employee-related costs related to the Sequent Acquisition and higher corporate allocations.
2021 vs. 2020
Gas & NGL Marketing Services Modified EBITDAdecreased primarily due to $57 millionhigher net unrealized losses from derivative instruments, lower operatingService revenues, and maintenancehigher segment costs and general and administrative costs. This reduction in costs isexpenses, partially offset by higher Commodity margins.
Service revenues decreased due primarily to the Four Corners area saleabsence of a temporary volume deficiency fee associated with reduced volumes from a shipper on OPPL in October 2018, ongoing cost containment efforts,2020.
Commodity margins increased $135 million primarily due to:
•A $112 million increase associated with our legacy natural gas and NGL marketing operations primarily due to favorable changes in net realized natural gas prices, including the deconsolidationimpact of our Jackalope interestWinter Storm Uri in second-quarter 2018. These reductions arethe first quarter of 2021;
•A $23 million increase associated with the operations acquired in the Sequent Acquisition in 2021 including $35 million primarily related to favorable pricing spreads on transportation capacity reflecting losses on physical transaction settlements more than offset by net realized gains on derivatives. The transportation related margin was partially offset by a $24$12 million regulatory charge associated with Northwest Pipeline’s approved ratesunfavorable margin related to Tax Reform,storage activity. The unfavorable storage margin reflects gains on physical transaction settlements offset by an $18 million charge related to the absencepartial recognition of a $15purchase accounting inventory fair value adjustment which increased the weighted-average cost of inventory and $13 million related to a lower of cost or net realizable value inventory adjustment.
The Net unrealized gain (loss) from contract settlements and terminationsderivative instruments changed primarily due to the Sequent Acquisition in 2017,July 2021, and a $12change in forward commodity prices relative to our hedge positions.
million charge for a regulatory liability associated with a decrease in Northwest Pipeline’s estimated deferred state income tax rate following the WPZ Merger.
Impairment of certain assetsOther segment costs and expenses increased primarily due to employee-related costs associated with the $1.849 billion impairment of certain assetsoperations acquired in the Barnett Shale regionSequent Acquisition in 2018,2021.
Other
| | | | | | | | | | | | | | | | | |
| | Year Ended December 31, |
| | 2022 | | 2021 | | 2020 |
| | (Millions) |
| Service revenues | $ | 24 | | | $ | 32 | | | $ | 34 | |
| Product sales (1) | 706 | | | 333 | | | — | |
| | | | | |
| Net realized gain (loss) from derivative instruments (1) | (104) | | | (20) | | | — | |
| Net unrealized gain (loss) from derivative instruments | 25 | | | — | | | — | |
| Net gain (loss) on commodity derivatives | (79) | | | (20) | | | — | |
| | | | | |
| Segment revenues | 651 | | | 345 | | | 34 | |
| | | | | |
| Other segment costs and expenses | (217) | | | (167) | | | (49) | |
| Other Modified EBITDA | $ | 434 | | | $ | 178 | | | $ | (15) | |
| | | | | |
| Net realized product sales | $ | 602 | | | $ | 313 | | | $ | — | |
________________(1) Included as a component of Net realized product sales.
2022 vs. 2021
Other Modified EBITDA increased primarily due to $248 million higher results from our upstream operations which included the following:
•A $289 million increase in Net realized product sales primarily due to higher commodity prices in 2022, partially offset by the absence of a $1.019 billion impairmentthe favorable impact of certain gathering operationsWinter Storm Uri in 2021 and an unfavorable change in Net realized gain (loss) from derivative instruments due to an increase in commodity prices relative to our hedge positions and an increase in the Mid-Continent regionvolume of production hedged in 2017 (see Note 18 – Fair Value Measurements, Guarantees,2022 compared to 2021. Net realized product sales also increased due to higher production from new wells and Concentrationhigher volumes associated with acquisitions of Credit Risk of Notes to Consolidated Financial Statements).additional ownership interests in 2021;
Gain on sale•A $25 million favorable change in Net unrealized gain (loss) from derivative instruments due to a change in forward commodity prices relative to our hedge positions and an increase in the volume of certain assets and businesses reflects a gain from the sale of our Four Corners area assetsproduction hedged in fourth quarter 2018.2022 compared to 2021; partially offset by
Regulatory charges resulting from Tax Reform• decreasedA $66 million increase in Other segment costs and expenses primarily due to the increased scale of our upstream operations and higher associated production taxes which were also impacted by higher commodity prices and higher volumes as well as higher tax rates.
Other segment costs and expenses also includes an $11 million charge related to an accrual for loss contingency in 2022, substantially offset by the absence of the $220a $10 million initial regulatory charge associated with the impact of Tax Reform at Northwest Pipelinerelated to an accrual for loss contingency in 2017 (see Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies of Notes to Consolidated Financial Statements).2021.
Proportional Modified EBITDA of equity-method investments 2021 vs. 2020increased primarily due to the deconsolidation of our Jackalope interest, which is accounted for as an equity-method investment beginning in the second quarter of 2018.
Other
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2019 | | 2018 | | 2017 |
| | (Millions) |
| Other Modified EBITDA | $ | 6 |
| | $ | (29 | ) | | $ | 997 |
|
2019 vs. 2018
Other Modified EBITDA increased primarily due to:
The absence of the $66 million impairment of certain idle pipelines in the second quarter of 2018 (see Note 18 – Fair Value Measurements and Guarantees of Notes to Consolidated Financial Statements);
The absence of a $35 million charge in 2018 associated with a charitable contribution of preferred stock to The Williams Companies Foundation, Inc. (a not-for-profit corporation) (See Note 16 – Stockholders’ Equity of Notes to Consolidated Financial Statements);
The absence of $20 million in costs in 2018 associated with the WPZ Merger (See Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies of Notes to Consolidated Financial Statements);
An $8•A $168 million increase related to our upstream operations, including the absencefavorable commodity price impact of 2018 unfavorable Modified EBITDA associated with the results of certain of our former Gulf Coast area operations sold in 2018;
The absence of a $7 million loss on early retirement of debt in 2018 (see Note 7 – Other Income and Expenses of Notes to Consolidated Financial Statements).
These increases were partially offset by:
The absence of a $37 million benefit of establishing a regulatory asset associated with an increase in Transco’s estimated deferred state income tax rate following the WPZ Merger in 2018 and a subsequent unfavorable $12 million adjustmentWinter Storm Uri in the first quarter of 2019;
A $26 million decrease in income associated with a regulatory asset related to deferred taxes on equity funds used during construction;
The absence of a $20 million gain on the sale of certain assets and operations located in the Gulf Coast area in 2018 (see Note 3 – Acquisitions and Divestitures of Notes to Consolidated Financial Statements).
2018 vs. 20172021;
Modified EBITDA• changed unfavorably primarily due to:
The absence of a $1.095 billion gain on the sale of our Geismar Interest in 2017 (see Note 3 – Acquisitions and Divestitures of Notes to Consolidated Financial Statements);
| |
• | The absence of $54 million of Modified EBITDA associated with the results of our former Geismar Olefins and RGP Splitter plants subsequent to their sale in July 2017;
|
A $35$24 million charge in 2018 associated with a charitable contribution of preferred stock to The Williams Companies Foundation, Inc. (a not-for-profit corporation), as previously mentioned;
A $34 million decreaseincrease due to the absence of a net gain on early retirement2020 charge related to a legal settlement associated with our former olefins operations;
•A $15 million increase due to the absence of debt in 2017 and a loss on early retirement2020 charges related to write-offs of debt in 2018 (see Note 7 – Other Income and Expenses of Notes to Consolidated Financial Statements);certain regulatory assets associated with cancelled projects; partially offset by
•A $26$10 million decrease in income associated with a regulatory asset2021 charge related to deferred taxes on equity funds used during construction;
$20 million in costs in 2018 associated with the WPZ Merger, as previously mentioned;
The absence of a $12 million gain on the sale of the Refinery Grade Propylene Splitter in 2017 (see Note 7 – Other Income and Expenses of Notes to Consolidated Financial Statements).
These decreases were partially offset by:
The absence of a $68 million impairment for a certain NGL pipeline asset in the third quarter of 2017 and a$23 million impairment of an olefins pipeline project in the Gulf Coast region in the second quarter of 2017, partially offset by a $66 million impairment of certain idle pipelines in the second quarter of 2018 (see Note 18 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk of Notes to Consolidated Financial Statements);
A $62 million favorable change for lower charges to reduce regulatory assets related to deferred taxes on AFUDC resulting from Tax Reform (see Note 7 – Other Income and Expenses of Notes to Consolidated Financial Statements);
$40 million of lower costs, driven by the absence of expenses associated with severance and related costs, Financial Repositioning, and strategic alternative costs;
A $37 million increase associated with the benefit of establishing a regulatory asset associated with an increase in Transco’s estimated deferred state income tax rate following the WPZ Merger, as previously mentioned;
A $30 million favorable change in the settlement charge expense related to the program to pay out certain deferred vested pension benefits of employees associated with former operations (see Note 10 – Employee Benefit Plans of Notes to Consolidated Financial Statements);
A $20 million gain on the sale of certain assets and operations located in the Gulf Coast area, as previously mentioned.
