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What changed in Williams Companies's 10-K — 2022 vs 2023

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Paragraph-level year-over-year comparison of Williams Companies's 2022 and 2023 10-K annual filings, covering the Business, Risk Factors, Legal Proceedings, Cybersecurity, MD&A and Market Risk sections. Every new, removed and edited paragraph is highlighted side-by-side so you can see exactly what management changed in the 2023 report.

+343 added−322 removedSource: 10-K (2024-02-21) vs 10-K (2023-02-27)

Top changes in Williams Companies's 2023 10-K

343 paragraphs added · 322 removed · 257 edited across 8 sections

Item 1. Business

Business — how the company describes what it does

101 edited+22 added−23 removed79 unchanged
Biggest changeWest Gas Gathering, Processing, and Treating Assets The following tables summarize the significant operated assets of this segment: Natural Gas Gathering Assets Location Pipeline Miles Inlet Capacity (Bcf/d) Ownership Interest Supply Basins/Shale Formations Consolidated: Wamsutter Wyoming 2,265 0.7 100% Wamsutter Southwest Wyoming Wyoming 1,614 0.5 100% Southwest Wyoming Piceance Colorado 352 1.8 100% Piceance Barnett Shale Texas 839 0.5 100% Barnett Shale Eagle Ford Shale Texas 1,251 0.5 100% Eagle Ford Shale Haynesville Shale (1) Louisiana & Texas 929 4.7 100% Haynesville Shale, Bossier Shale Permian Texas 112 0.1 100% Permian Mid-Continent Oklahoma & Texas 1,752 0.2 100% Miss-Lime, Granite Wash, Colony Wash Non-consolidated: (2) Rocky Mountain Midstream Colorado 208 0.6 50% Denver-Julesburg 15 Natural Gas Processing Facilities Location Inlet Capacity (Bcf/d) NGL Production Capacity (Mbbls/d) Ownership Interest Supply Basins Consolidated: Echo Springs Echo Springs, WY 0.6 48 100% Wamsutter Opal Opal, WY 1.1 47 100% Southwest Wyoming Willow Creek Rio Blanco Co., CO 0.5 30 100% Piceance Parachute Garfield Co., CO 1.0 5 100% Piceance Non-consolidated: (2) Fort Lupton Weld Co., CO 0.3 50 50% Denver-Julesburg Keenesburg I Weld Co., CO 0.2 40 50% Denver-Julesburg _______________ (1) Includes statistics for assets acquired in the Trace Acquisition.
Biggest changeNortheast G&P Operating Statistics 2023 2022 2021 (Annual Average Amounts) Consolidated: Gathering volumes (Bcf/d) 4.45 4.19 4.24 Plant inlet natural gas volumes (Bcf/d) 1.89 1.65 1.57 NGL production (Mbbls/d) 139 120 115 NGL equity sales (Mbbls/d) 1 1 1 Non-consolidated: (1) Gathering volumes (Bcf/d) 6.92 6.61 6.79 Plant inlet natural gas volumes (Bcf/d) 0.93 0.71 0.82 NGL production (Mbbls/d) 65 51 56 NGL equity sales (Mbbls/d) 4 3 6 __________ (1) Includes 100 percent of the volumes associated with operated equity-method investments, including Laurel Mountain and Blue Racer; as well as the Bradford Supply Hub and Marcellus South within Appalachia Midstream Investments. 16 West Gas Gathering, Processing, and Treating Assets The following tables summarize the significant operated assets of this segment: Natural Gas Gathering Assets Location Pipeline Miles Inlet Capacity (Bcf/d) Ownership Interest Supply Basins/Shale Formations Consolidated: Wamsutter Wyoming 2,273 0.7 100% Wamsutter Southwest Wyoming Wyoming 1,614 0.5 100% Southwest Wyoming Piceance Colorado 352 1.8 100% Piceance Barnett Shale Texas 815 0.5 100% Barnett Shale Eagle Ford Shale Texas 1,258 0.5 100% Eagle Ford Shale Haynesville Shale Louisiana & Texas 987 5.2 100% Haynesville Shale, Bossier Shale Permian Texas 113 0.1 100% Permian Mid-Continent Oklahoma & Texas 1,697 0.2 100% Miss-Lime, Granite Wash, Colony Wash DJ Basin Colorado 472 0.8 100% Denver-Julesburg Natural Gas Processing Facilities Location Inlet Capacity (Bcf/d) NGL Production Capacity (Mbbls/d) Ownership Interest Supply Basins Consolidated: Echo Springs Echo Springs, WY 0.6 48 100% Wamsutter Opal Opal, WY 0.7 39 100% Southwest Wyoming Willow Creek Rio Blanco Co., CO 0.5 30 100% Piceance Parachute Garfield Co., CO 1.0 5 100% Piceance Fort Lupton (1) Weld Co., CO 0.3 50 100% Denver-Julesburg Keenesburg I (1) Weld Co., CO 0.2 40 100% Denver-Julesburg Front Range (2) Weld Co., CO 0.1 12 100% Denver-Julesburg _______________ (1) Fort Lupton and Keenesburg I are a part of RMM which became a wholly owned subsidiary during 2023.
We share operating responsibilities for Gulfstream with the other 50 percent owner. Discovery We own a 60 percent interest in and operate the facilities of Discovery.
We share operating responsibilities for Gulfstream with the other 50 percent owner. Discovery We operate and own a 60 percent interest in the facilities of Discovery.
Northwest Pipeline Northwest Pipeline is an interstate natural gas transmission company that owns and operates a 3,900-mile natural gas pipeline system, which is regulated by the FERC, extending from the San Juan basin in northwestern New Mexico and southwestern Colorado through Colorado, Utah, Wyoming, Idaho, Oregon, and Washington to a point on the Canadian border near Sumas, Washington.
Northwest Pipeline Northwest Pipeline is an interstate natural gas transmission company that owns and operates an approximately 3,900-mile natural gas pipeline system, which is regulated by the FERC, extending from the San Juan basin in northwestern New Mexico and southwestern Colorado through Colorado, Utah, Wyoming, Idaho, Oregon, and Washington to a point on the Canadian border near Sumas, Washington.
Among other things, the Standards of Conduct require that interstate gas pipelines treat all transmission customers, affiliated and non-affiliated, on a not unduly discriminatory basis. 18 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.
Among other things, the Standards of Conduct require that interstate gas pipelines treat all transmission customers, affiliated and non-affiliated, on a not 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 natural gas pipelines transport and store natural gas for a broad mix of customers, including local natural gas distribution companies, public utilities, municipalities, direct industrial users, electric power generators, and natural gas marketers and producers. Most of our interstate natural gas transmission businesses are fully contracted under long-term firm reservation contracts with high credit quality customers.
Our interstate natural gas pipelines transport and store natural gas for a broad mix of customers, including local natural gas distribution companies, public utilities, municipalities, direct industrial users, electric power generators, and natural gas marketers and producers. Most of our interstate natural gas transmission businesses are fully 6 contracted under long-term firm reservation contracts with high credit quality customers.
Generally, fixed-monthly fees associated with production handling and export revenues are recognized on a units-of-production basis utilizing either contractually determined maximum daily quantities or expected remaining production. CIAC arrangements are recognized based on a units of production basis, utilizing expected remaining production. Our crude oil transportation business is supported mostly by major oil producers with long-cycle perspectives.
Generally, fixed-monthly fees associated with production handling and export revenues are recognized on a units-of-production basis utilizing either contractually determined maximum daily quantities or expected remaining production. CIAC arrangements are recognized on a units of production basis, utilizing expected remaining production. Our crude oil transportation business is supported mostly by major oil producers with long-cycle perspectives.
Ethane produced at our de-ethanizer is transported to markets via our 50-mile ethane pipeline from Oak Grove to Houston, Pennsylvania. The remaining mixed NGL stream from the de-ethanizer is then transported via our 50-mile NGL pipeline and fractionated at either our Moundsville or Harrison County, Ohio, fractionation facility. The resulting products are then transported on truck, rail, or pipeline.
Ethane produced at our de-ethanizer is transported to markets via our 50-mile ethane pipeline from Oak Grove to Houston, Pennsylvania. The remaining mixed NGL stream from the de-ethanizer is then transported via our 50-mile NGL pipeline and fractionated at either our Moundsville or Harrison County, Ohio, fractionation facility. The 15 resulting products are then transported on truck, rail, or pipeline.
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.
We provide a comprehensive total rewards program that includes base salary, an 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.
The Sequent Acquisition in July 2021 significantly increased the scope of our natural gas marketing operations. Our NGL marketing business transports and markets our equity NGLs from the production at our processing plants, NGLs from the production at our upstream properties, and also NGLs on behalf of third-party NGL producers, including some of our fee-based processing customers.
The Sequent Acquisition in July 2021 significantly increased the scope of our natural gas marketing operations. Our NGL marketing business transports and markets our equity NGLs from the production at our processing plants, NGLs 18 from the production at our upstream properties, and also NGLs on behalf of third-party NGL producers, including some of our fee-based processing customers.
“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 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. ” 21 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.
“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 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. ” 22 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.
Northwest Pipeline’s system includes 42 transmission compressor stations having a combined sea level-rated capacity of approximately 476,000 horsepower. Northwest Pipeline owns a one-third undivided interest in the Jackson Prairie underground storage facility in Washington. Northwest Pipeline also owns and operates a LNG storage facility in Washington.
Northwest Pipeline’s system includes 42 transmission compressor stations having a combined sea level-rated capacity of approximately 476,000 horsepower. Northwest Pipeline owns a one-third undivided interest in the Jackson Prairie underground storage facility in Washington. Northwest Pipeline also owns and operates an LNG storage facility in Washington.
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 non-owner shippers.” See Part I, Item 1A.
Outer Continental Shelf Lands Act 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 non-owner shippers.” See Part I, Item 1A.
Management considers the costs associated with compliance with the rule to be prudent costs incurred in the ordinary course of business. 20 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.
Management considers the costs associated with compliance with the rule to be prudent costs incurred in the ordinary course of business. 21 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.
These storage facilities have an aggregate working natural gas storage capacity of 10.4 Bcf, which is substantially utilized for third-party natural gas. These natural gas storage facilities enable Northwest Pipeline to balance daily receipts and deliveries and provide storage services to customers.
These storage facilities have an aggregate working natural gas storage capacity of approximately 10.4 Bcf, which is substantially utilized for third-party natural gas. These natural gas storage facilities enable Northwest Pipeline to balance daily receipts and deliveries and provide storage services to customers.
Our offshore floating production platforms provide centralized services to deepwater producers such as compression, separation, production handling, water removal, and pipeline landings. 11 The following tables summarize the significant crude oil transportation pipelines and production handling platforms of this segment: Crude Oil Pipelines Pipeline Miles Capacity (Mbbls/d) Ownership Interest Supply Basins Consolidated: Mountaineer, including Blind Faith and Gulfstar extensions 155 150 100% Eastern Gulf of Mexico BANJO 57 90 100% Western Gulf of Mexico Alpine 96 85 100% Western Gulf of Mexico Perdido Norte 74 150 100% Western Gulf of Mexico Production Handling Platforms Gas Inlet Capacity (MMcf/d) Crude/NGL Handling Capacity (Mbbls/d) Ownership Interest Supply Basins Consolidated: Devils Tower 110 60 100% Eastern Gulf of Mexico Gulfstar I FPS (1) 172 80 51% Eastern Gulf of Mexico Non-consolidated: (2) Discovery 75 10 60% Central Gulf of Mexico __________ (1) Statistics reflect 100 percent of the assets from our 51 percent interest in Gulfstar One.
Our offshore floating production platforms provide centralized services to deepwater producers such as compression, separation, production handling, water removal, and pipeline landings. 12 The following tables summarize the significant crude oil transportation pipelines and production handling platforms of this segment: Crude Oil Pipelines Pipeline Miles Capacity (Mbbls/d) Ownership Interest Supply Basins Consolidated: Mountaineer, including Blind Faith and Gulfstar extensions 155 150 100% Eastern Gulf of Mexico BANJO 57 90 100% Western Gulf of Mexico Alpine 96 85 100% Western Gulf of Mexico Perdido Norte 74 150 100% Western Gulf of Mexico Production Handling Platforms Gas Inlet Capacity (MMcf/d) Crude/NGL Handling Capacity (Mbbls/d) Ownership Interest Supply Basins Consolidated: Devils Tower 110 60 100% Eastern Gulf of Mexico Gulfstar I FPS (1) 172 80 51% Eastern Gulf of Mexico Non-consolidated: (2) Discovery 75 10 60% Central Gulf of Mexico __________ (1) Statistics reflect 100 percent of the assets from our 51 percent interest in Gulfstar One floating production system (FPS).
Per-unit NGL margins are calculated based on sales of our own equity volumes at the processing plants. For the year ended December 31, 2022, approximately 10 percent of our NGL production volumes were under noncash commodity-based contracts. Generally, our gathering and processing agreements are long-term agreements, with terms ranging from month-to-month to the life of the producing lease.
Per-unit NGL margins are calculated based on sales of our own equity volumes at the processing plants. For the year ended December 31, 2023, approximately 10 percent of our NGL production volumes were under noncash commodity-based contracts. Generally, our gathering and processing agreements are long-term agreements, with terms ranging from month-to-month to the life of the producing lease.
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.
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, solar, wind, coal, fuel oil, and nuclear.
In addition, all of our natural gas marketing derivative activities qualify as held for trading purposes, which requires net presentation in the Consolidated Statement of Income.
In addition, all of our natural gas marketing derivative activities qualify as held for trading purposes, which requires net presentation in our Consolidated Statement of Income.
Blue Racer is a joint venture to own, operate, develop, and acquire midstream assets in the Utica Shale and certain adjacent areas in the Marcellus Shale. Blue Racer’s assets include 741 miles of gathering pipelines, and the Natrium complex in Marshall County, West Virginia, with a cryogenic processing capacity of 800 MMcf/d and fractionation capacity of approximately 134 Mbbls/d.
Blue Racer is a joint venture to own, operate, develop, and acquire midstream assets in the Utica Shale and certain adjacent areas in the Marcellus Shale. Blue Racer’s assets include 616 miles of gathering pipelines and the Natrium complex in Marshall County, West Virginia, with a cryogenic processing capacity of 800 MMcf/d and fractionation capacity of approximately 134 Mbbls/d.
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.
Energy Management and Marketing Services Our Gas & NGL Marketing Services segment competes with national and regional full-service energy providers, producers, and pipeline 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.
For the year ended December 31, 2022, approximately 90 percent of our NGL production volumes were under fee-based contracts. • Noncash commodity-based: We also process gas under two types of commodity-based contracts, keep-whole and percent-of-liquids, where we receive consideration for our services in the form of NGLs.
For the year ended December 31, 2023, approximately 90 percent of our NGL production volumes were under fee-based contracts. • Noncash commodity-based: We also process gas under two types of commodity-based contracts, keep-whole and percent-of-liquids, where we receive consideration for our services in the form of NGLs.
Blue Racer also owns the Berne complex in Monroe County, Ohio, with a cryogenic processing capacity of 400 MMcf/d, and NGL and condensate pipelines connecting Natrium to Berne. Blue Racer provides gathering, processing, and marketing services primarily under percent-of-liquids and fixed-fee agreements.
Blue Racer also owns the Berne complex in Monroe County, Ohio, with a cryogenic processing capacity of 400 MMcf/d, and 101 miles of NGL and condensate pipelines connecting Natrium to Berne. Blue Racer provides gathering, processing, and marketing services primarily under percent-of-liquids and fixed-fee agreements.
“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. ” HUMAN CAPITAL RESOURCES 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.
“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. ” HUMAN CAPITAL RESOURCES 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 now and into the clean energy future.
Discovery’s assets include a 600 MMcf/d cryogenic natural gas processing plant near Larose, Louisiana, a 32 Mbbls/d NGL fractionator plant near Paradis, Louisiana, and a 594-mile offshore natural gas gathering and transportation system in the Gulf of Mexico. Discovery’s mainline has a gathering inlet capacity of 600 MMcf/d.
Discovery’s assets include a 600 MMcf/d cryogenic natural gas processing plant near Larose, Louisiana, a 35 Mbbls/d NGL fractionator plant near Paradis, Louisiana, and a 594-mile offshore natural gas gathering and transportation system in the Gulf of Mexico. Discovery’s mainline has a gathering inlet capacity of 600 MMcf/d.
Transco Transco is an interstate natural gas transmission company that owns and operates a 9,700-mile natural gas pipeline system, which is regulated by the FERC, extending from Texas, Louisiana, Mississippi, and the Gulf of Mexico through Alabama, Georgia, South Carolina, North Carolina, Virginia, Maryland, Delaware, Pennsylvania, and New Jersey to the New York City metropolitan area.
Transmission & Gulf of Mexico Interstate Natural Gas Pipeline Assets Transco Transco is an interstate natural gas transmission company that owns and operates an approximately 9,700-mile natural gas pipeline system, which is regulated by the FERC, extending from Texas, Louisiana, Mississippi, and the Gulf of Mexico through Alabama, Georgia, South Carolina, North Carolina, Virginia, Maryland, Delaware, Pennsylvania, and New Jersey to the New York City metropolitan area.
OPPL is capable of transporting 255 Mbbls/d of NGLs and includes approximately 1,035 miles of NGL pipeline extending from Opal, Wyoming, to the Mid-Continent NGL market center near Conway, Kansas, along with extensions into the Piceance and Denver-Julesberg basins in Colorado and the Bakken Shale in the Williston basin in North Dakota.
OPPL is capable of transporting 255 Mbbls/d of NGLs and includes approximately 1,035 miles of NGL pipeline extending from Opal, Wyoming, to the Mid-Continent NGL market center near Conway, Kansas, along with extensions into the Piceance and DJ basins in Colorado and the Bakken Shale in the Williston basin in North Dakota.
Northwest Pipeline provides services for markets in Washington, Oregon, Idaho, Wyoming, Nevada, Utah, Colorado, New Mexico, California, and Arizona, either directly or indirectly through interconnections with other pipelines. At December 31, 2022, Northwest Pipeline’s system had a design capacity totaling approximately 3.8 MMdth/d.
Northwest Pipeline provides services for 10 markets in Washington, Oregon, Idaho, Wyoming, Nevada, Utah, Colorado, New Mexico, California, and Arizona, either directly or indirectly through interconnections with other pipelines. At December 31, 2023, Northwest Pipeline’s system had a design capacity totaling approximately 3.8 MMdth/d.
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.
Operating Statistics 2023 2022 2021 (Annual Average Amounts) Net Product Sales Volumes: Natural Gas (Bcf/d) 0.29 0.22 0.13 NGLs (Mbbls/d) 7 7 6 Crude Oil (Mbbls/d) 4 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.
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. 25
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. 26
We have operations in 14 supply areas that provide natural gas gathering, processing, and transmission services, NGLs fractionation, transportation, and storage services, and marketing services to more than 700 customers.
We have operations in 12 supply areas that provide natural gas gathering, processing, and transmission services, NGLs fractionation, transportation, and storage services, and marketing services to more than 700 customers.
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.
ERG members participate in community events, volunteer, lend professional and personal support to one another, and promote inclusion across the company. They also have executive sponsors and provide input to the leadership team. We are committed to helping all employees develop and succeed.
We encourage you to review our 2021 Sustainability Report available on our website for more information about our human capital programs and initiatives.
We encourage you to review our 2022 Sustainability Report available on our website for more information about our human capital programs and initiatives.
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.
Significant entrance barriers to build new pipelines exist, including increased federal and state regulations and elevated public opposition against new pipeline builds, and these factors will continue to impact potential competition for the foreseeable future.
Certain Equity-Method Investments Appalachia Midstream Investments Through our Appalachia Midstream Investments, we operate 100 percent of and own an approximate average 66 percent interest in the Bradford Supply Hub gathering system and own an approximate average 68 percent interest in the Marcellus South gathering system, together which consist of approximately 1,040 miles of gathering 14 pipeline in the Marcellus Shale region with the capacity to gather 5,330 MMcf/d of natural gas.
Certain Equity-Method Investments Appalachia Midstream Investments Through our Appalachia Midstream Investments, we operate 100 percent of and own an approximate average 66 percent interest in the Bradford Supply Hub gathering system and own an approximate average 68 percent interest in the Marcellus South gathering system, together which consist of approximately 1,049 miles of gathering pipeline in the Marcellus Shale region with the capacity to gather 5,700 MMcf/d of natural gas.
We estimate that the cost to be incurred in 2023 associated with this program will be approximately $10 million. Ongoing periodic reassessments and initial assessments of any new HCAs are expected to be completed within the time frames required by the rule.
We estimate that the cost to be incurred in 2024 associated with this program will be approximately $4 million. Ongoing periodic reassessments and initial assessments of any new HCAs are expected to be completed within the time frames required by the rule.
The system serves customers in Texas and 12 southeast and Atlantic seaboard states, including major metropolitan areas in Georgia, North Carolina, Washington, D.C., Maryland, New York, New Jersey, and Pennsylvania. At December 31, 2022, Transco’s system had a design capacity totaling approximately 18.6 MMdth/d. Transco’s system includes 59 compressor stations, four underground storage fields, and one LNG storage facility.
The system serves customers in Texas and 12 southeast and Atlantic seaboard states, including major metropolitan areas in Georgia, North Carolina, Washington, D.C., Maryland, New York, New Jersey, and Pennsylvania. At December 31, 2023, Transco’s system had a design capacity totaling approximately 19.1 MMdth/d. Transco’s system includes 59 compressor stations, four underground storage fields, and one LNG storage facility.
We own an interest in and operate over 33,000 miles of pipelines in 25 states, 29 natural gas processing facilities, 7 NGL fractionation facilities, approximately 24 million barrels of NGL storage capacity, and 290.4 Bcf of natural gas storage capacity, and deliver natural gas that is used every day for clean-power generation, heating, and industrial use.
We own an interest in and operate over 33,000 miles of pipelines in 24 states, 35 natural gas processing facilities, 9 NGL fractionation facilities, approximately 25 million barrels of NGL storage capacity, and 405.4 Bcf of natural gas storage capacity, and deliver natural gas that is used every day for clean-power generation, heating, and industrial use.
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.
Additionally, pipeline capacity in many natural gas supply basins is constrained and facing more regulation and opposition 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.
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.
When a safety hazard is recognized, every employee has the authority and responsibility to stop work activities, make changes to enhance safety, and share the lessons learned with the organization on how we made it right.
Our NGL marketing business transports and markets our equity NGLs from the production at our processing plants, NGLs from the production at our upstream properties, and also NGLs on behalf of third-party NGL producers, including some of our fee-based processing customers, as well as the NGL volumes owned by RMM and Discovery.
Our NGL marketing business transports and markets our equity NGLs from the production at our processing plants, NGLs from the production at our upstream properties, and also NGLs on behalf of third-party NGL producers, including some of our fee-based processing customers, as well as the NGL volumes owned by certain of our equity-method investments.
Nothing on our website shall be deemed incorporated by reference into this Annual Report on Form 10-K. 23 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.
Nothing on our website shall be deemed incorporated by reference into this Annual Report on Form 10-K. 24 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 implement best practices to progress towards zero safety incidents.
During 2022, our facilities gathered and processed gas and crude oil for approximately 240 customers. Our top ten customers accounted for approximately 70 percent of our gathering and processing fee revenues and NGL margins from our noncash commodity-based agreements.
During 2023, our facilities gathered and processed gas and crude oil for approximately 230 customers. Our top ten customers accounted for approximately 70 percent of our gathering and processing fee revenues and NGL 7 margins from our noncash commodity-based agreements.
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.
Under the agreement, the third party operates the upstream position and develops the undeveloped acreage. The third party’s interest in new wells increased to 75 percent in early 2023 when a certain drilling hurdle was met.
North Texas Assets (NorTex) On August 31, 2022, we purchased a group of assets in north Texas from NorTex Midstream Holdings, LLC. The NorTex assets include approximately 80 miles of natural gas transmission pipelines and 36 Bcf of natural gas storage in the Dallas-Fort Worth market.
These assets expand our natural gas storage footprint in the Gulf Coast region. North Texas Assets (NorTex) On August 31, 2022, we purchased a group of assets in north Texas from NorTex Midstream Holdings, LLC. The NorTex assets include approximately 80 miles of natural gas transmission pipelines and 36 Bcf of natural gas storage in the Dallas-Fort Worth market.
Our reportable segments are comprised of the following business activities: • Transmission & Gulf of Mexico is comprised of our interstate natural gas pipelines, Transco, Northwest Pipeline, and MountainWest, 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 50 percent equity-method investment in Gulfstream, and a 60 percent equity-method investment in Discovery.
Our reportable segments are comprised of the following business activities: • Transmission & Gulf of Mexico is comprised of our interstate natural gas pipelines, Transcontinental Gas Pipe Line Company, LLC (Transco) , Northwest Pipeline LLC (Northwest Pipeline), and MountainWest Pipelines Holding Company (MountainWest), 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 LLC (Gulfstar One), a 50 percent equity-method investment in Gulfstream Natural Gas System, L.L.C.
Gas & NGL Marketing Services Operating Statistics 2022 2021 2020 (Annual Average Amounts) Sales Volumes: Natural Gas (Bcf/d) (1) (2) 7.20 7.70 0.62 NGLs (Mbbls/d) (2) 250 227 220 ________________ (1) Includes 100% of the volumes associated with the Sequent Acquisition after the purchase on July 1, 2021.
Gas & NGL Marketing Services Operating Statistics 2023 2022 2021 (Annual Average Amounts) Sales Volumes: Natural Gas (Bcf/d) (1) 7.05 7.20 7.70 NGLs (Mbbls/d) 223 250 227 ________________ (1) Includes 100% of the volumes associated with the Sequent Acquisition after the purchase on July 1, 2021.
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.
For 2022 and 2023, these goals included our Loss of Primary Containment Events Reduction, a Behavioral Near Miss to Incident Ratio goal aimed to focus attention on behaviors that are the leading causes of incidents, as well as a Methane Emissions Reduction goal focusing on our efforts to reduce greenhouse gas emissions by safely and reliably operating and maintaining assets.
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. 22 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.
We believe our significant presence in key supply basins, our expertise and reputation as a reliable and safe operator, our commitment to sustainability, and our ability to offer integrated packages of services position us well against our competition. 23 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.
Laurel Mountain has a long-term, dedicated, volumetric-based fee agreement, with exposure to natural gas prices, to gather the anchor customer’s production in the western Pennsylvania area of the Marcellus Shale. Additionally, certain Laurel Mountain agreements have MVCs. Blue Racer We own a 50 percent interest in Blue Racer which is operated by Blue Racer Midstream Holdings, LLC (BRMH).
Laurel Mountain has a long-term, dedicated, volumetric-based fee agreement, with exposure to natural gas prices, to gather the anchor customer’s production in the western Pennsylvania area of the Marcellus Shale. Additionally, certain Laurel Mountain agreements have MVCs. Blue Racer We operate and own a 50 percent interest in Blue Racer.
Compression facilities at sea level-rated capacity total approximately 2.4 million horsepower. Transco has natural gas storage capacity in four underground storage fields located on or near its pipeline system or market areas and operates two of these storage fields. Transco also has storage capacity in an LNG storage facility that it owns and operates.
Compression facilities at sea level-rated capacity total approximately 2.5 million horsepower. Transco has natural gas storage capacity in four underground storage fields located on or near its pipeline system or market areas and operates two of these storage fields.
We believe counterparty credit concerns in our gathering and processing businesses are significantly mitigated by the physical nature of our services, where we gather at the wellhead and are therefore critical to a producer’s ability to move product to market. 7 Gas and NGL Marketing Our NGL and natural gas marketing services are presented primarily within our Gas & NGL Marketing Services segment.
We believe counterparty credit concerns in our gathering and processing businesses are significantly mitigated by the physical nature of our services, where we gather at the wellhead and are therefore critical to a producer’s ability to move product to market.
Employees As of February 1, 2023, we had 5,043 full-time 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.
Employees As of February 1, 2024, we had 5,601 full-time employees located throughout the United States. Of this total, approximately 21 percent are women and 16 percent are ethnically diverse. During 2023, our voluntary turnover rate was 7.2 percent.
Gas Transportation, Processing, and Treating Assets The following tables summarize the significant operated assets of this segment: Offshore Natural Gas Pipelines Location Pipeline Miles Inlet Capacity (Bcf/d) Ownership Interest Supply Basins Consolidated: Canyon Chief, including Blind Faith and Gulfstar extensions Deepwater Gulf of Mexico 156 0.5 100% Eastern Gulf of Mexico Norphlet Deepwater Gulf of Mexico 58 0.3 100% Eastern Gulf of Mexico Other Eastern Gulf Offshore shelf and other 46 0.2 100% Eastern Gulf of Mexico Seahawk Deepwater Gulf of Mexico 115 0.4 100% Western Gulf of Mexico Perdido Norte Deepwater Gulf of Mexico 105 0.3 100% Western Gulf of Mexico Other Western Gulf Offshore shelf and other 65 0.3 100% Western Gulf of Mexico Non-consolidated: (1) Discovery Central Gulf of Mexico 594 0.6 60% Central Gulf of Mexico Natural Gas Processing Facilities Location Inlet Capacity (Bcf/d) NGL Production Capacity (Mbbls/d) Ownership Interest Supply Basins Consolidated: Markham Markham, TX 0.5 45 100% Western Gulf of Mexico Mobile Bay Coden, AL 0.7 35 100% Eastern Gulf of Mexico NorTex Jack Co., TX 0.1 13 100% Barnett Shale Non-consolidated: (1) Discovery Larose, LA 0.6 32 60% Central Gulf of Mexico _____________ (1) Includes 100 percent of the statistics associated with operated equity-method investments.
In addition to providing gas supply to power generation in north Texas, these assets also provide storage services for Permian gas directed toward growing Gulf Coast LNG demand. 11 Gas Gathering, Transportation, Processing, and Treating Assets The following tables summarize the significant operated assets of this segment: Offshore Natural Gas Pipelines Location Pipeline Miles Inlet Capacity (Bcf/d) Ownership Interest Supply Basins Consolidated: Canyon Chief, including Blind Faith and Gulfstar extensions Deepwater Gulf of Mexico 156 0.5 100% Eastern Gulf of Mexico Norphlet Deepwater Gulf of Mexico 58 0.3 100% Eastern Gulf of Mexico Other Eastern Gulf Offshore shelf and other 46 0.2 100% Eastern Gulf of Mexico Seahawk Deepwater Gulf of Mexico 115 0.4 100% Western Gulf of Mexico Perdido Norte Deepwater Gulf of Mexico 105 0.3 100% Western Gulf of Mexico Other Western Gulf Offshore shelf and other 65 0.3 100% Western Gulf of Mexico Non-consolidated: (1) Discovery Central Gulf of Mexico 594 0.6 60% Central Gulf of Mexico Natural Gas Processing Facilities Location Inlet Capacity (Bcf/d) NGL Production Capacity (Mbbls/d) Ownership Interest Supply Basins Consolidated: Markham Markham, TX 0.5 45 100% Western Gulf of Mexico Mobile Bay Coden, AL 0.7 35 100% Eastern Gulf of Mexico NorTex Jack Co., TX 0.1 13 100% Barnett Shale Non-consolidated: (1) Discovery Larose, LA 0.6 35 60% Central Gulf of Mexico _____________ (1) Includes 100 percent of the statistics associated with our operated equity-method investment Discovery.
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 .
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 estimate that the cost to be incurred in 2023 associated with this program to be approximately $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 estimate that the cost to be incurred in 2024 associated with this program to be approximately $163 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 Transco, Northwest Pipeline, and MountainWest’s rates.
West Operating Statistics 2022 2021 2020 (Annual Average Amounts) Consolidated: Gathering volumes (Bcf/d) (1) 5.19 3.25 3.33 Plant inlet natural gas volumes (Bcf/d) 1.15 1.23 1.25 NGL production (Mbbls/d) 43 41 49 NGL equity sales (Mbbls/d) 14 16 22 Non-Consolidated: (2) Gathering volumes (Bcf/d) 0.29 0.29 0.25 Plant inlet natural gas volumes (Bcf/d) 0.28 0.28 0.25 NGL production (Mbbls/d) 33 29 23 ________________ (1) Includes volumes for gathering assets acquired in the Trace Acquisition after the purchase on April 29, 2022.
West Operating Statistics 2023 2022 2021 (Annual Average Amounts) Consolidated: Gathering volumes (Bcf/d) (1) 6.02 5.19 3.25 Plant inlet natural gas volumes (Bcf/d) 1.54 1.15 1.23 NGL production (Mbbls/d) 91 43 41 NGL equity sales (Mbbls/d) 14 14 16 Non-Consolidated: (2) Gathering volumes (Bcf/d) — 0.29 0.29 Plant inlet natural gas volumes (Bcf/d) — 0.28 0.28 NGL production (Mbbls/d) — 33 29 ________________ (1) Includes volumes for gathering assets acquired in the Trace Acquisition after the purchase on April 29, 2022 as well as volumes for gathering assets acquired in the DJ Basin Acquisitions after the purchase on November 30, 2023.
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.
Some local distribution companies are also involved in the long-haul transportation business through joint venture pipelines. The principle elements of competition in the interstate natural gas pipeline business are based on available capacity, rates, reliability, quality of customer service, diversity and flexibility of supply, and proximity or access to customers and market hubs.
The following tables summarize the significant operated assets of this segment and non-operated Blue Racer: Natural Gas Gathering Assets Location Pipeline Miles Inlet Capacity (Bcf/d) Ownership Interest Supply Basins Consolidated: Ohio Valley Midstream (1) Ohio, West Virginia, & Pennsylvania 216 0.8 65% Appalachian Utica East Ohio Midstream (1) (2) Ohio 53 0.6 65% Appalachian Susquehanna Supply Hub Pennsylvania & New York 479 4.3 100% Appalachian Cardinal (1) Ohio 395 0.7 66% Appalachian Flint Ohio 100 0.5 100% Appalachian Non-consolidated: (3) Bradford Supply Hub Pennsylvania 750 4.0 66% Appalachian Marcellus South Pennsylvania & West Virginia 290 1.3 68% Appalachian Laurel Mountain Pennsylvania 1,145 0.9 69% Appalachian Blue Racer Ohio & West Virginia 741 1.5 50% Appalachian Natural Gas Processing Facilities Location Inlet Capacity (Bcf/d) NGL Production Capacity (Mbbls/d) Ownership Interest Supply Basins Consolidated: (1) Fort Beeler Marshall Co., WV 0.5 62 65% Appalachian Oak Grove Marshall Co., WV 0.6 75 65% Appalachian Kensington Columbiana Co., OH 0.6 68 65% Appalachian Leesville Carroll Co., OH 0.2 18 65% Appalachian Non-consolidated: (3) (4) Berne Monroe Co., OH 0.4 60 50% Appalachian Natrium Marshall Co., WV 0.8 120 50% Appalachian _____________ (1) Statistics reflect 100 percent of the assets from our 65 percent ownership in our Northeast JV and 66 percent ownership of Cardinal gathering system. 13 (2) Utica East Ohio Midstream inlet capacity consists of 1.3 Bcf/d of a high-pressure gathering pipeline that delivers Cardinal gathering volumes to Utica East Ohio Midstream processing facilities.
Northeast G&P Gas Gathering, Processing, and Treating Assets This segment includes our natural gas gathering, compression, processing, and NGL fractionation businesses in the Marcellus and Utica Shale regions in Pennsylvania, West Virginia, New York, and Ohio. 14 The following tables summarize the significant operated assets of this segment: Natural Gas Gathering Assets Location Pipeline Miles Inlet Capacity (Bcf/d) Ownership Interest Supply Basins Consolidated: Ohio Valley Midstream (1) Ohio, West Virginia, & Pennsylvania 216 0.8 65% Appalachian Utica East Ohio Midstream (1) (2) Ohio 53 0.6 65% Appalachian Susquehanna Supply Hub Pennsylvania & New York 504 4.6 100% Appalachian Cardinal (1) Ohio 429 0.7 66% Appalachian Flint Ohio 100 0.5 100% Appalachian Non-consolidated: (3) Bradford Supply Hub Pennsylvania 753 4.4 66% Appalachian Marcellus South Pennsylvania & West Virginia 296 1.3 68% Appalachian Laurel Mountain Pennsylvania 1,147 0.9 69% Appalachian Blue Racer Ohio & West Virginia 616 2.0 50% Appalachian Natural Gas Processing Facilities Location Inlet Capacity (Bcf/d) NGL Production Capacity (Mbbls/d) Ownership Interest Supply Basins Consolidated: (1) Fort Beeler Marshall Co., WV 0.5 62 65% Appalachian Oak Grove Marshall Co., WV 0.6 75 65% Appalachian Kensington Columbiana Co., OH 0.6 68 65% Appalachian Leesville Carroll Co., OH 0.2 18 65% Appalachian Non-consolidated: (3) Berne Monroe Co., OH 0.4 60 50% Appalachian Natrium Marshall Co., WV 0.8 120 50% Appalachian _____________ (1) Statistics reflect 100 percent of the assets from our 65 percent ownership in our Northeast JV and 66 percent ownership of Cardinal gathering system.
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, 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.
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, 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. 20 The United States Department of Transportation Pipeline and Hazardous Materials Safety Administration (PHMSA) administers federal pipeline safety laws.
The majority of our volumes in the region are gathered from northern Pennsylvania, southwestern Pennsylvania, and the northwestern panhandle of West Virginia in core areas of the Marcellus Shale. We operate the assets under long-term, 100 percent fixed-fee gathering agreements that include significant acreage dedications and, in the Bradford Supply Hub, a cost of service mechanism.
The majority of our volumes in the region are gathered from northern Pennsylvania, southwestern Pennsylvania, and the northwestern panhandle of West Virginia in core areas of the Marcellus Shale. We operate the assets primarily under long-term, 100 percent fixed-fee gathering agreements that include significant acreage dedications. Additionally, some Marcellus South agreements have MVCs.
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.
NextGen Gas is natural gas that has been independently certified as low emissions gas across all segments of the value chain. 19 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.
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.
We retained ownership in the undeveloped acreage until a separate acreage earning hurdle was met in the fourth quarter of 2023, at which time remaining undeveloped acreage was conveyed to the third party resulting in the third party owning 75 percent and us owning 25 percent.
Additionally, some Marcellus South agreements have MVCs. Laurel Mountain We own a 69 percent interest in a joint venture, Laurel Mountain, that includes a 1,145-mile gathering system that we operate in western Pennsylvania with the capacity to gather 0.9 Bcf/d of natural gas.
Laurel Mountain We operate and own a 69 percent interest in a joint venture, Laurel Mountain, which includes a 1,147-mile gathering system in western Pennsylvania with the capacity to gather 0.9 Bcf/d of natural gas.
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.
Future demand for natural gas within the power sector could be increased by growing power demand and by regulations limiting or discouraging coal use in power generation. Conversely, natural gas demand could be adversely affected by laws mandating or encouraging solar and wind power sources or restricting the use of natural gas.
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.
For 2023, our Behavioral Near Miss to Incident Ratio and Methane Emissions Reduction goals outperformed the established targets, however, our Loss of Primary Containment Events goal fell short of the reduction targets.
Our equity NGL volumes from our Wyoming plants and our Willow Creek facility in Colorado are dedicated for transport on OPPL under a long-term transportation agreement. NGL volumes from our RMM equity-method investment are also transported on OPPL. Rocky Mountain Midstream We operate and own a 50 percent interest in RMM.
Our equity NGL volumes from our Wyoming plants and our Willow Creek facility in Colorado are dedicated for transport on OPPL under a long-term transportation agreement. NGL volumes from RMM are also transported on OPPL. Brazos Permian II We own a 15 percent interest in Brazos Permian II, a privately held Permian basin midstream company.
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.
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, flexibility of commercial terms (including but not limited to fees charged, products retained, volume commitments), available capacity, array and quality of services provided, as well as efficiency, reliability, and safety of services.
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. 8 Crude Oil Transportation and Production Handling Assets Our crude oil transportation operations, which are primarily presented in our Transmission & Gulf of Mexico segment as described under the heading “Business Segments,” earn revenues primarily from a combination of fixed-monthly fees, contractual fixed or variable fees applied to production volumes, and contributions in aid of construction (CIAC) arrangements.
Crude Oil Transportation and Production Handling Assets Our crude oil transportation operations, which are primarily presented in our Transmission & Gulf of Mexico segment as described under the heading “Business Segments,” earn revenues primarily from a combination of fixed-monthly fees, contractual fixed or variable fees applied to production volumes, and contributions in aid of construction (CIAC) arrangements.
Our gas marketing business markets natural gas from the production at our upstream properties and provides asset management and the wholesale marketing, trading, storage, and transportation of natural gas for a diverse set of natural gas and electric utilities, municipalities, power generators, and producers, and moves gas to markets through transportation and storage agreements on strategically positioned assets.
Our gas marketing business markets natural gas and provides natural gas asset management and wholesale marketing, trading, storage, and transportation for a diverse set of natural gas and electric utilities, municipalities, power generators, and producers, including for our own upstream properties.
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.
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. These metrics align the focus of the organization, from entry level to executives, and create a connection to annual compensation on environmental and safety performance.
These safety standards apply to the design, construction, testing, operation, and maintenance of gas and hazardous liquids pipeline facilities affecting interstate or foreign commerce.
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.
These contracts have various expiration dates and account for the major portion of our regulated businesses. Additionally, we offer storage services and interruptible transportation services under shorter-term agreements. Transco’s and Northwest 6 Pipeline’s three largest customers in 2022 accounted for approximately 23 percent and 51 percent, respectively, of their total operating revenues.
The contracts have various expiration dates and account for the major portion of the entities’ businesses. Additionally, we offer storage services and interruptible transportation services under shorter-term agreements. The three largest customers of this business in 2023 accounted for approximately 32 percent of its total operating revenues.
(2) Includes 100 percent of the volumes associated with operated equity-method investments. 16 Trace Acquisition On April 29, 2022, we closed on the acquisition of 100 percent of Gemini Arklatex, LLC through which we acquired the Haynesville Shale region gas gathering and related assets of Trace Midstream.
It also includes crude oil storage and compression assets. Trace Acquisition On April 29, 2022, we closed on the acquisition of 100 percent of Gemini Arklatex, LLC through which we acquired the Haynesville Shale region gas gathering and related assets of Trace Midstream.
(2) Tbtu converted to MMdth at one trillion British thermal units = one million dekatherms. 12 Certain Equity-Method Investments Gulfstream Gulfstream is a 745-mile interstate natural gas pipeline system extending from the Mobile Bay area in Alabama to markets in Florida, which has a capacity to transport 1.4 Bcf/d. We own a 50 percent equity-method investment in Gulfstream.
(2) Includes 100 percent of the statistics associated with our operated equity-method investment Discovery. Certain Equity-Method Investments Gulfstream Gulfstream is a 745-mile interstate natural gas pipeline system extending from the Mobile Bay area in Alabama to markets in Florida, which has a capacity to transport 1.4 Bcf/d. We own a 50 percent equity-method investment in Gulfstream.
This segment also includes our NGL 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. • Gas & NGL Marketing Services includes our NGL and natural gas marketing and trading operations.
This segment also includes our NGL storage facilities, an undivided 50 percent interest in an NGL fractionator near Conway, Kansas, a 50 percent equity-method investment in Overland Pass Pipeline Company LLC (OPPL), a 20 percent equity-method investment in Targa Train 7 LLC (Targa Train 7), and a 15 percent equity-method investment in Brazos Permian II, LLC (Brazos Permian II). • Gas & NGL Marketing Services is comprised of our NGL and natural gas marketing and trading operations, which includes risk management and transactions related to the storage and transportation of natural gas and NGLs on strategically positioned assets.
The total usable gas storage capacity available to Transco and its customers in such underground storage fields and LNG storage facility and through storage service contracts is approximately 188 Bcf of natural gas. At December 31, 2022, Transco’s customers had stored in its facilities approximately 127 Bcf of natural gas.
Transco also has storage capacity in an LNG storage facility that it owns and operates. The total usable gas storage capacity available to Transco and its customers in such underground storage fields and LNG storage facility and through storage service contracts is approximately 188 Bcf of natural gas.
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.
The council serves as the governing body over enterprise diversity and inclusion initiatives, including enterprise diversity and inclusion events, organized and hosted by one of our 10 ERGs, and our annual awards that recognize an outstanding leader and an individual contributor who champion inclusion.
Transmission & Gulf of Mexico also includes natural gas storage facilities and pipelines providing services in 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 which operates in West Virginia, Ohio, and Pennsylvania, a 66 percent interest in Cardinal which operates in Ohio, a 69 percent equity-method investment in Laurel Mountain, a 50 percent equity-method investment in Blue Racer, and Appalachia Midstream Investments. • West is comprised of 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 and Permian basins.
Transmission & Gulf of Mexico also includes natural gas storage facilities and pipelines providing services in north Texas, Louisiana, and Mississippi. • 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 Ohio Valley Midstream LLC (Northeast JV) which operates in West Virginia, Ohio, and Pennsylvania, a 66 percent interest in Cardinal Gas Services, L.L.C.
To ensure compliance with these provisions, PHMSA performs pipeline safety inspections and has the authority to initiate enforcement actions. 19 In October 2019, PHMSA published the first of three rules that would be a part of the Mega Rule.
To ensure compliance with these provisions, PHMSA performs pipeline safety inspections and has the authority to initiate enforcement actions. In August 2022, PHMSA published Rule 2, which is the last in the three part Mega Rule set of regulations.
This segment includes risk management and transactions related to the storage and transportation of natural gas and NGLs on strategically positioned assets. Detailed discussion of each of our reportable segments follows. For a discussion of our ongoing expansion projects, see Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.
Detailed discussion of each of our reportable segments follows. For a discussion of our ongoing expansion projects, see Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

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Item 1A. Risk Factors

Risk Factors — what could go wrong, per management

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Biggest changeFederal 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 that are involved in marketing functions of the natural gas business; • Market manipulation in connection with interstate sales, purchases, or transportation of natural gas. 38 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.
Biggest changeFederal regulation extends to such matters as: • Transportation and sale for resale of natural gas in interstate commerce; 39 • 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 that are involved in marketing functions of the natural gas business; • Market manipulation in connection with interstate sales, purchases, or transportation of natural gas.
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; 36 • 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.
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.
Wide fluctuations in prices might result from one or more factors beyond our control, including: • Imbalances in supply and demand whether rising from worldwide or domestic supplies of and demand for natural gas, NGLs, oil, and related commodities; 28 • Geopolitical turmoil in the Middle East, Eastern Europe, and other producing regions; • The activities of OPEC and other countries, whether acting independently of 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.
Wide fluctuations in prices might result from one or more factors beyond our control, including: • Imbalances in supply and demand whether rising from worldwide or domestic supplies of and demand for natural gas, NGLs, oil, and related commodities; • Geopolitical turmoil in the Middle East, Eastern Europe, and other producing regions; • The activities of OPEC and other countries, whether acting independently of 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.
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.
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; 32 • 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.
Companies that do not adapt to or comply with investor or other stakeholder expectations and standards, which are evolving, or that 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.
Companies that do not adapt to or comply with investor or other stakeholder expectations and standards, which are evolving, or that are perceived to have not responded appropriately to the growing concern for 33 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 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.
We may change our intentions, at any time and without notice, based upon changes in such factors, our assumptions, or otherwise. 28 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.
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 .
The difference in accounting treatment for the underlying position and the financial instrument 38 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 .
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 29 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.
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.
Ultimately, limiting fossil-fuel related companies’ access to capital could make it more difficult for our customers to 37 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.
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.
The results of these efforts will impact our reputation and positioning in the market. 31 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.
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.
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.
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 30 assets, or lawsuits or other actions designed to prevent, disrupt, or delay the operation or expansion of our assets and business.
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.
However, we cannot predict precisely what form these future regulations might take, the stringency of 40 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.
These factors are described in the following section. 27 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.
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 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 35 rates, and changes in pension laws.
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.
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.
Price volatility has had and could continue to have an adverse effect on our business, results of operations, financial condition, and cash flows. 29 The markets for natural gas, NGLs, oil, and other commodities are likely to continue to be volatile.
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; 33 • Security risks, including cybersecurity; • Operating in a marine environment.
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; 34 • 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.
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 face unlawful attempts to gain access to our information technology infrastructure, including coordinated attacks from hackers, whether state-sponsored groups, 35 “hacktivists”, or private individuals. We face the threat of theft and misuse of sensitive data and information, including customer and employee information.
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.
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. 37 Our debt service obligations and the covenants described above could have important consequences.
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 39 facilities.
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.
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.
In addition, actions of activist stockholders may cause significant 36 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.
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.
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. 41 Item 1B. Unresolved Staff Comments Not applicable.
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.
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 operations, and cash flows.
Breaches in our information technology infrastructure or physical 34 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.
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 or other geopolitical tensions and conflicts, 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.
Additionally, we may face reputational challenges in the event our 32 ESG procedures or standards do not meet the standards set by certain constituencies. We adopted certain practices as highlighted in our 2021 Sustainability Report, including with respect to air emissions, biodiversity and land use, climate change, and environmental stewardship.
Additionally, we may face reputational challenges in the event our ESG procedures or standards do not meet the standards set by certain constituencies. We adopted certain practices as highlighted in our 2022 Sustainability Report, including with respect to air emissions, biodiversity and land use, climate change, and environmental stewardship.
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 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; 26 • 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 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 impacts of operational and developmental hazards and unforeseen interruptions; • The risks resulting from outbreaks or other public health crises, including COVID-19; • 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 construction- 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; • The ability of the members of the Organization of Petroleum Exporting Countries (OPEC) and other oil exporting nations to agree to and maintain oil price and production controls and the impact on domestic production; • Changes in the current geopolitical situation, including the Russian invasion of Ukraine; • Changes in U.S. governmental administration and policies; • Whether we are able to pay current and expected levels of dividends; • Additional risks described in our filings with the SEC.
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 matters, and litigation, as well as our ability and the ability of other energy companies with whom we conduct or seek to conduct business, to obtain necessary permits and approvals, and our ability to achieve favorable rate proceeding outcomes; • Our exposure to the credit risk of our customers and counterparties; 27 • 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 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 impacts of operational and developmental hazards and unforeseen interruptions; • The risks resulting from outbreaks or other public health crises; • 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 construction- 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; • The ability of the members of the Organization of Petroleum Exporting Countries (OPEC) and other oil exporting nations to agree to and maintain oil price and production controls and the impact on domestic production; • Changes in the current geopolitical situation, including the Russian invasion of Ukraine and conflicts in the Middle East including between Israel and Hamas and conflicts involving Iran and its proxy forces; • Changes in U.S. governmental administration and policies; • Whether we are able to pay current and expected levels of dividends; • Additional risks described in our filings with the SEC.
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 12 – Debt and Banking Arrangements of Notes to Consolidated Financial Statements.
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 12 – Debt and Banking Arrangements.
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.
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 have risen in recent years and may increase in the future.
Our total outstanding long-term debt (including current portion) as of December 31, 2022, was $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.
Our total outstanding long-term debt (including current portion and commercial paper) as of December 31, 2023, was $26.4 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.
The operations of our current non-wholly-owned subsidiaries, including the Nonconsolidated Entities, are conducted in accordance with their organizational documents. We anticipate that we will enter into more such 30 arrangements, including through new joint venture structures or new Nonconsolidated Entities.
Certain operations, including the Nonconsolidated 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 Nonconsolidated 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 Nonconsolidated Entities.
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.
Uncertainty surrounding the Russian invasion of Ukraine, conflicts in the Middle East including between Israel and Hamas and conflicts involving Iran and its proxy forces, 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.
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.
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 current U.S. governmental administration and its policies, which often oppose the development or expansion of fossil fuel energy, have increased the likelihood of such legal and regulatory developments.
Governmentally imposed constraints, such as prohibitions on natural gas hookups in newly constructed buildings, could also artificially limit new demand for natural gas.
Governmentally imposed constraints, such as prohibitions on natural gas hookups in newly constructed buildings and the recently announced permit freeze for new LNG export projects, could also artificially limit new demand for natural gas.
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.
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 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.
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.
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.
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.
Geopolitical tensions and conflicts including those in the Middle East between Israel and Hamas and Iran or its proxy forces, as well as the ongoing Russian invasion of Ukraine and the actions undertaken by western nations in response to these conflicts have had, and may continue to have, adverse impacts on global financial markets.
We do not own 100 percent of the equity interests of certain subsidiaries, including the Nonconsolidated Entities, which may limit our ability to operate and control these subsidiaries. Certain operations, including the Nonconsolidated Entities, are conducted through arrangements that may limit our ability to operate and control these operations.
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. 31 We do not own 100 percent of the equity interests of certain subsidiaries, including the Nonconsolidated Entities, which may limit our ability to operate and control these subsidiaries.
Removed
Our businesses may be negatively impacted by adverse economic conditions or future disruptions in the global financial markets.
Added
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.

Item 2. Properties

Properties — owned and leased real estate

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Biggest changeItem 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. 40
Biggest changeItem 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

Legal Proceedings — active lawsuits and investigations

3 edited+0 added−1 removed5 unchanged
Biggest changeOther environmental matters called for by this Item are described under the caption “ Environmental Matters ” in Note 17 – 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.
Biggest changeThe consent decree, which became effective on December 26, 2023, imposes both payment of a civil penalty in the amount of $3.75 million and an injunctive relief component. 43 Other environmental matters called for by this Item are described under the caption “ Environmental Matters ” in Note 17 – Contingencies and Commitments 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 17 – 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 17 – Contingencies and Commitments included under Part II, Item 8 Financial Statements of this report, which information is incorporated by reference into this Item.
We have 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. The proposed global resolution includes both payment of a civil penalty in the amount of $3.75 million and an injunctive relief component.
We have entered into a consent decree with the DOJ and other agencies regarding global resolution of the claims at these facilities, as well as alleged violations at certain other facilities.
Removed
We continue to work with the DOJ and the other agencies towards finalization of the global resolution.

Item 4. Mine Safety Disclosures

Mine Safety Disclosures — required of mining issuers

10 edited+1 added−1 removed2 unchanged
Biggest changeDebbie Cowan 45 2018 to present Senior Vice President and 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 57 2017 to present Executive Vice President and Chief Operating Officer, The Williams Companies, Inc.
Biggest changeSenior Vice President and Chief Human Resources Officer 2013 to 2018 Global Vice President of Human Resources, Koch Chemical Technology Group, LLC 45 Name and Position Age Business Experience in Past Five Years (or Relevant Business Experience) John D. Porter 54 2022 to present Senior Vice President and Chief Financial Officer, The Williams Companies, Inc.
Executive Vice President of Corporate Strategic Development 2017 to 2023 Senior Vice President – Corporate Strategic Development, The Williams Companies, Inc. 2017 to 2018 Director of the general partner, Williams Partners L.P. 2014 to 2017 President – Pipeline and Midstream, Cheniere Energy 43 PART II
Executive Vice President of Corporate Strategic Development 2017 to 2023 Senior Vice President – Corporate Strategic Development, The Williams Companies, Inc. 2017 to 2018 Director of the general partner, Williams Partners L.P. 2014 to 2017 President – Pipeline and Midstream, Cheniere Energy, Inc. 46 PART II
Armstrong 60 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, Williams Partners L.P. 2014 to 2018 Chief Executive Officer, Williams Partners L.P. 2012 to 2018 Director of the general partner, Williams Partners L.P.
Armstrong 61 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, Williams Partners L.P. 2014 to 2018 Chief Executive Officer, Williams Partners L.P. 2012 to 2018 Director of the general partner, Williams Partners L.P. Micheal G.
Larsen 48 2022 to present Senior Vice President Gathering & Processing, The Williams Companies, Inc.
Larsen 49 2022 to present Senior Vice President Gathering & Processing, The Williams Companies, Inc.
Item 4. Mine Safety Disclosures Not applicable. 41 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 27, 2023, are listed below. Name and Position Age Business Experience in Past Five Years Alan S.
Item 4. Mine Safety Disclosures Not applicable. 44 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 21, 2024, are listed below. Name and Position Age Business Experience in Past Five Years (or Relevant Business Experience) Alan S.
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.
Teply 52 2023 to present Senior Vice President – Transmission & Gulf of Mexico, The Williams Companies, Inc. Senior Vice President – Transmission & Gulf of Mexico 2020 to 2023 Senior Vice President – Project Execution, The Williams Companies, Inc. 2017 to 2020 Senior Vice President – Business Policy and Development, PacifiCorp (a Berkshire Hathaway Energy Company) T.
Lane Wilson 56 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 46 2023 to present Executive Vice President of Corporate Strategic Development, The Williams Companies, Inc.
Lane Wilson 57 2017 to present Senior Vice President and General Counsel, The Williams Companies, Inc. Senior Vice President and General Counsel Chad J. Zamarin 47 2023 to present Executive Vice President of Corporate Strategic Development, The Williams Companies, Inc.
Senior Vice President Gathering & 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. 42 Name and Position Age Business Experience in Past Five Years John D.
Senior Vice President Gathering & 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. Eric J.
Executive Vice President and Chief Operating Officer 2017 to 2018 Director of the general partner, Williams Partners L.P. Scott A. Hallam 46 2020 to present Senior Vice President Transmission & Gulf of Mexico, The Williams Companies, Inc.
Dunn 58 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, Williams Partners L.P. Mary A. Hausman 52 2022 to present Vice President, Chief Accounting Officer and Controller, The Williams Companies, Inc.
Porter 53 2022 to present Senior Vice President and Chief Financial Officer, The Williams Companies, Inc.
Ormond 37 2023 to present Senior Vice President Project Execution, The Williams Companies, Inc.
Removed
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 2022 to present Vice President, Chief Accounting Officer and Controller, The Williams Companies, Inc.
Added
Senior Vice President Project Execution 2023 Senior Vice President Commercial Operations, Engineering & Project Management, Crestwood Midstream Partners LP 2020 to 2023 Senior Vice President Engineering & Project Management, Crestwood Midstream Partners LP 2017 to 2020 Vice President Strategic Development & New Ventures, Crestwood Midstream Partners LP Debbie (Cowan) Pickle 46 2018 to present Senior Vice President and Chief Human Resources Officer, The Williams Companies, Inc.

Item 5. Market for Registrant's Common Equity

Market for Common Equity — stock, dividends, buybacks

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Biggest changeWe 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.
Biggest changeRepurchases may be made from time to time in the open market, by block purchases, in privately negotiated transactions, or in such other manner as determined by our management. Our management will also determine the timing and amount of any repurchases based on 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, 2018.
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, 2019.
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 17, 2023, we had 6,013 holders of record of our common stock.
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 16, 2024, we had 5,803 holders of record of our common stock.
The Bloomberg Americas Pipelines Index is composed of Enbridge Inc., TC Energy Corporation, Kinder Morgan, Inc., ONEOK, Inc., Cheniere Energy, Inc., Pembina Pipeline Corporation, Targa Resources Corp., New Fortress Energy Inc., and Williams.
The Bloomberg Americas Pipelines Index is composed of Enbridge Inc., TC Energy Corporation, Kinder Morgan, Inc., ONEOK, Inc., Cheniere Energy, Inc., Pembina Pipeline Corporation, Targa Resources Corp., Hess Midstream LP, and Williams.
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.
Share Repurchase Program ISSUER PURCHASES OF EQUITY SECURITIES Period Total Number of Shares Purchased Average Price Paid Per Share Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs (1) Maximum Number (or Approximate Dollar Value) of Shares that May Yet Be Purchased Under the Plans or Programs October 1 - October 31, 2023 — $ — — $ 1,360,938,325 November 1 - November 30, 2023 — $ — — $ 1,360,938,325 December 1 - December 31, 2023 — $ — — $ 1,360,938,325 Total — — (1) In September 2021, our Board of Directors authorized a share repurchase program with a maximum dollar limit of $1.5 billion.
The graph below assumes an investment of $100 at the beginning of the period. 44 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 45
The graph below assumes an investment of $100 at the beginning of the period. 47 2018 2019 2020 2021 2022 2023 The Williams Companies, Inc. 100.0 114.2 105.5 146.1 194.2 217.4 S&P 500 Index 100.0 131.5 155.6 200.3 164.0 207.0 Bloomberg Americas Pipelines Index 100.0 135.3 107.0 143.5 165.8 177.3 Arca Natural Gas Index 100.0 98.8 85.5 137.1 175.5 189.1 48
Removed
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.
Added
The share repurchase program does not obligate us to acquire any particular amount of common stock, and it may be suspended or discontinued at any time. This share repurchase program does not have an expiration date.

Item 7. Management's Discussion & Analysis

Management's Discussion & Analysis (MD&A) — revenue / margin commentary

91 edited+60 added−36 removed43 unchanged
Biggest changeYear Ended December 31, 2022 $ Change from 2021* % Change from 2021* 2021 $ Change from 2020* % Change from 2020* 2020 (Millions) Revenues: Service revenues $ 6,536 +535 +9 % $ 6,001 +77 +1 % $ 5,924 Service revenues – commodity consideration 260 +22 +9 % 238 +109 +84 % 129 Product sales 4,556 +20 — % 4,536 +2,865 +171 % 1,671 Net gain (loss) on commodity derivatives (387) -239 -161 % (148) -143 NM (5) Total revenues 10,965 10,627 7,719 Costs and expenses: Product costs 3,369 +562 +14 % 3,931 -2,386 -154 % 1,545 Net processing commodity expenses 88 +13 +13 % 101 -33 -49 % 68 Operating and maintenance expenses 1,817 -269 -17 % 1,548 -222 -17 % 1,326 Depreciation and amortization expenses 2,009 -167 -9 % 1,842 -121 -7 % 1,721 Selling, general, and administrative expenses 636 -78 -14 % 558 -92 -20 % 466 Impairment of certain assets — +2 +100 % 2 +180 +99 % 182 Impairment of goodwill — — — % — +187 +100 % 187 Other (income) expense – net 28 -14 -100 % 14 +8 +36 % 22 Total costs and expenses 7,947 7,996 5,517 Operating income (loss) 3,018 2,631 2,202 Equity earnings (losses) 637 +29 +5 % 608 +280 +85 % 328 Impairment of equity-method investments — — — % — +1,046 +100 % (1,046) Other investing income (loss) – net 16 +9 +129 % 7 -1 -13 % 8 Interest expense (1,147) +32 +3 % (1,179) -7 -1 % (1,172) Other income (expense) – net 18 +12 +200 % 6 +49 NM (43) Income (loss) before income taxes 2,542 2,073 277 Less: Provision (benefit) for income taxes 425 +86 +17 % 511 -432 NM 79 Net income (loss) 2,117 1,562 198 Less: Net income (loss) attributable to noncontrolling interests 68 -23 -51 % 45 -58 NM (13) 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. 2022 vs. 2021 Service revenues increased 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 associated with the Leidy South expansion project placed fully in service at Transco in December 2021, 52 and higher reimbursable electric power costs and storage rates which are substantially offset in Operating and maintenance expenses .
Biggest changeYear Ended December 31, 2023 $ Change from 2022* % Change from 2022* 2022 $ Change from 2021* % Change from 2021* 2021 (Millions) Revenues: Service revenues $ 7,026 +490 +7 % $ 6,536 +535 +9 % $ 6,001 Service revenues – commodity consideration 146 -114 -44 % 260 +22 +9 % 238 Product sales 2,779 -1,777 -39 % 4,556 +20 — % 4,536 Net gain (loss) from commodity derivatives 956 +1,343 NM (387) -239 -161 % (148) Total revenues 10,907 10,965 10,627 Costs and expenses: Product costs 1,884 +1,485 +44 % 3,369 +562 +14 % 3,931 Net processing commodity expenses 151 -63 -72 % 88 +13 +13 % 101 Operating and maintenance expenses 1,984 -167 -9 % 1,817 -269 -17 % 1,548 Depreciation and amortization expenses 2,071 -62 -3 % 2,009 -167 -9 % 1,842 Selling, general, and administrative expenses 665 -29 -5 % 636 -78 -14 % 558 Gain on sale of business (129) +129 NM — — — % — Other (income) expense – net (30) +58 NM 28 -12 -75 % 16 Total costs and expenses 6,596 7,947 7,996 Operating income (loss) 4,311 3,018 2,631 Equity earnings (losses) 589 -48 -8 % 637 +29 +5 % 608 Other investing income (loss) – net 108 +92 NM 16 +9 +129 % 7 Interest expense (1,236) -89 -8 % (1,147) +32 +3 % (1,179) Net gain from Energy Transfer litigation judgment 534 +534 NM — — — % — Other income (expense) – net 99 +81 NM 18 +12 +200 % 6 Income (loss) before income taxes 4,405 2,542 2,073 Less: Provision (benefit) for income taxes 1,005 -580 -136 % 425 +86 +17 % 511 Income (loss) from continuing operations 3,400 2,117 1,562 Income (loss) from discontinued operations (97) -97 NM — — — % — Net income (loss) 3,303 2,117 1,562 Less: Net income (loss) attributable to noncontrolling interests 124 -56 -82 % 68 -23 -51 % 45 Net income (loss) attributable to The Williams Companies, Inc. $ 3,179 +1,130 +55 % $ 2,049 +532 +35 % $ 1,517 _______ * + = 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. 56 2023 vs. 2022 Service revenues increased primarily due to: • Higher volumes from acquisitions at our Transmission & Gulf of Mexico segment; • Higher volumes and rates at our Northeast G&P segment; partially offset by • Lower rates, partially offset by higher volumes at our West segment.
Our operations are conducted, managed, and presented within the following reportable segments: Transmission & Gulf of Mexico, Northeast G&P, West, and Gas & NGL Marketing Services, consistent with the manner in which our chief operating decision maker evaluates performance and allocates resources. All remaining business activities, including our upstream operations and corporate activities, are included in Other.
Consistent with the manner in which our chief operating decision maker evaluates performance and allocates resources, our operations are conducted, managed, and presented within the following reportable segments: Transmission & Gulf of Mexico, Northeast G&P, West, and Gas & NGL Marketing Services. All remaining business activities, including our upstream operations and corporate activities, are included in Other.
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.
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 Shale 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 product sales also increased due to higher production from new wells and higher volumes associated with acquisitions of additional ownership interests in 2021; • 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 production hedged in 2022 compared to 2021; partially offset by • A $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.
Net realized product sales also increased due to higher production from new wells and higher volumes associated with acquisitions of additional ownership interests in 2021; • A $25 million favorable change in Net unrealized gain (loss) from commodity derivative instruments due to a change in forward commodity prices relative to our hedge positions and an increase in the volume of production hedged in 2022 compared to 2021; partially offset by • A $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.
Additionally, 2022 was impacted by higher costs associated with the Leidy South expansion project; 56 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 decrease in Transco’s estimated deferred state income tax rate, higher employee-related costs, corporate allocations, and operations acquired in the NorTex Asset Purchase.
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 decrease in Transco’s estimated deferred state income tax rate, higher employee-related costs, corporate allocations, and operations acquired in the NorTex Asset Purchase.
Risk Factors in this report. Expansion Projects Our ongoing major expansion projects include the following: Transmission & Gulf of Mexico Deepwater Shenandoah Project In 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.
Risk Factors in this report. 52 Expansion Projects Our ongoing major expansion projects include the following: Transmission & Gulf of Mexico Deepwater Shenandoah Project In 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.
We plan to place the project into service in the fourth quarter of 2024. 48 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.
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.
Additionally, volumes of equity NGL sold and natural gas purchased associated with our 60 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.
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.
This segment also includes our NGL 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. • Gas & NGL Marketing Services is comprised of our NGL and natural gas marketing and trading operations which includes risk management and transactions related to the storage and transportation of natural gas and NGLs on strategically positioned assets. 46 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.
This segment also includes our NGL storage facilities, an undivided 50 percent interest in an NGL fractionator near Conway, Kansas, a 50 percent equity-method investment in OPPL, a 20 percent equity-method investment in Targa Train 7, and a 15 percent equity-method investment in Brazos Permian II. • Gas & NGL Marketing Services is comprised of our NGL and natural gas marketing and trading operations, which includes risk management and transactions related to the storage and transportation of natural gas and NGLs on strategically positioned assets. 49 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.
At December 31, 2022, certain assessment studies were still in process for which the ultimate outcome may yield different estimates of most likely costs. Therefore, the actual costs incurred will depend on the final amount, type, and extent of contamination discovered at these sites, the final cleanup standards mandated by the EPA or other governmental authorities, and other factors.
At December 31, 2023, certain assessment studies were still in process for which the ultimate outcome may yield different estimates of most likely costs. Therefore, the actual costs incurred will depend on the final amount, type, and extent of contamination discovered at these sites, the final cleanup standards mandated by the EPA or other governmental authorities, and other factors.
We consider prudently incurred environmental assessment and remediation costs and the costs associated with compliance with environmental standards to be recoverable through rates for our interstate natural gas transmission pipelines. Historically, with limited exceptions, we have been permitted recovery of these environmental costs, and it is our intent to continue seeking recovery of such costs through future rate filings. 68
We consider prudently incurred environmental assessment and remediation costs and the costs associated with compliance with environmental standards to be recoverable through rates for our interstate natural gas transmission pipelines. Historically, with limited exceptions, we have been permitted recovery of these environmental costs, and it is our intent to continue seeking recovery of such costs through future rate filings. 73
Other segment costs and expenses increased primarily due to higher operating expenses related to timing and scope of activities 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 changes in pricing.
Other segment costs and expenses increased primarily due to higher operating expenses related to timing and scope of activities including from operations acquired in the Trace Acquisition, the absence of gains on asset sales in 66 2021, higher corporate allocations, acquisition-related costs associated with the Trace Acquisition, and an unfavorable change in our net imbalance liability due to changes in pricing.
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, meet legal, regulatory, and/or contractual commitments. We intend to fund substantially all planned 2023 capital spending with cash available after paying dividends.
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. We intend to fund substantially all planned 2024 capital spending with cash available after paying dividends.
Net processing commodity expenses decreased primarily due to the impact of a 2022 net unrealized gain on derivatives for processing plant shrink gas purchases and lower volumes for natural gas purchases associated with our equity NGL production activities, partially offset by higher net realized prices.
Net processing commodity expenses decreased primarily due to the impact of a 2022 net unrealized gain from derivatives for processing plant shrink gas purchases and lower volumes for natural gas purchases associated with our equity NGL production activities, partially offset by higher net realized prices.
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.
The unfavorable change in Net gain (loss) from 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.
Pension and Postretirement Obligations We have pension and other postretirement benefit plans that require the use of assumptions and estimates to determine the benefit obligations and costs. These estimates and assumptions involve significant judgement and actual results will likely be different than anticipated.
Pension and Postretirement Obligations We have pension and other postretirement benefit plans that require the use of assumptions and estimates to determine the benefit obligations and costs. These estimates and assumptions involve significant judgment and actual results will likely be different than anticipated.
No assurance can be given that 66 the credit rating agencies will continue to assign us investment-grade ratings even if we meet or exceed their current criteria for investment-grade ratios.
No assurance can be given that the credit rating agencies will continue to assign us investment-grade ratings even if we meet or exceed their current 71 criteria for investment-grade ratios.
Liquidity Based on our forecasted levels of cash flow from operations and other sources of liquidity, we expect to have sufficient liquidity to manage our businesses in 2023.
Liquidity Based on our forecasted levels of cash flow from operations and other sources of liquidity, we expect to have sufficient liquidity to manage our businesses in 2024.
Our potential material internal and external sources and uses of liquidity are as follows: Sources: Cash and cash equivalents on hand Cash generated from operations Distributions from our equity-method investees Utilization of our credit facility and/or commercial paper program Cash proceeds from issuance of debt and/or equity securities Proceeds from asset monetizations Uses: Working capital requirements Capital and investment expenditures Product costs Gas & NGL Marketing Services payments for transportation and storage capacity and gas supply Other operating costs including human capital expenses Quarterly dividends to our shareholders Repayments of borrowings under our credit facility and/or commercial paper program Debt service payments, including payments of long-term debt Distributions to noncontrolling interests Share repurchase program 65 At December 31, 2022, we have approximately $21.927 billion of long-term debt due after one year.
Our potential material internal and external sources and uses of liquidity are as follows: Sources: Cash and cash equivalents on hand Cash generated from operations Distributions from our equity-method investees Utilization of our credit facility and/or commercial paper program Cash proceeds from issuance of debt and/or equity securities Proceeds from asset monetizations Uses: Working capital requirements Capital and investment expenditures Product costs Gas & NGL Marketing Services payments for transportation and storage capacity and gas supply Other operating costs including human capital expenses Quarterly dividends to our shareholders Repayments of borrowings under our credit facility and/or commercial paper program Debt service payments, including payments of long-term debt Distributions to noncontrolling interests Share repurchase program 70 At December 31, 2023, we have approximately $23.376 billion of long-term debt due after one year.
See Note 12 – Debt and Banking Arrangements of Notes to Consolidated Financial Statements for the aggregate maturities over the next five years. Our potential sources of liquidity available to address these maturities include cash generated from operations, proceeds from refinancing, our credit facility, or our commercial paper program, as well as proceeds from asset monetizations.
See Note 12 – Debt and Banking Arrangements for the aggregate maturities over the next five years. Our potential sources of liquidity available to address these maturities include cash generated from operations, proceeds from refinancing, our credit facility, or our commercial paper program, as well as proceeds from asset monetizations.
Potential risks associated with our planned levels of liquidity discussed above include those previously discussed in Company Outlook . At December 31, 2022, we had a working capital deficit of $1.093 billion, including cash and cash equivalents and long-term debt due within one year.
Potential risks associated with our planned levels of liquidity discussed above include those previously discussed in Company Outlook . At December 31, 2023, we had a working capital deficit of $1.317 billion, including cash and cash equivalents and long-term debt due within one year.
We plan to place the full project into service as early as the fourth quarter of 2024, assuming timely receipt of all necessary regulatory approvals. The project is expected to increase capacity by 829 Mdth/d.
We plan to place the project into service as early as the fourth quarter of 2024, assuming timely receipt of all necessary regulatory approvals. The project is expected to increase capacity by 423 Mdth/d.
Our reportable segments are comprised of the following business activities: • Transmission & Gulf of Mexico is comprised of our interstate natural gas 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, or VIE), a 50 percent equity-method investment in Gulfstream, and a 60 percent equity-method investment in Discovery.
Our reportable segments are comprised of the following business activities: • Transmission & Gulf of Mexico is comprised of our interstate natural gas pipelines, Transco, Northwest Pipeline, and MountainWest, 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 50 percent equity-method investment in Gulfstream, and a 60 percent equity-method investment in Discovery.
We expect to pay approximately $11 million in 2023 for these activities. Estimates of the most likely costs of cleanup are generally based on completed assessment studies, preliminary results of studies, or our experience with other similar cleanup operations.
We expect to pay approximately $9 million in 2024 for these activities. Estimates of the most likely costs of cleanup are generally based on completed assessment studies, preliminary results of studies, or our experience with other similar cleanup operations.
Current estimates of the most likely costs of such activities are approximately $40 million, all of which are included in Accrued and other current liabilities and Regulatory liabilities, deferred income, and other in the Consolidated Balance Sheet at December 31, 2022.
Current estimates of the most likely costs of such activities are approximately $48 million, all of which are included in Accrued and other current liabilities and Regulatory liabilities, deferred income, and other in the Consolidated Balance Sheet at December 31, 2023.
Net realized gain (loss) on commodity derivatives – service revenues changed favorably due to a change in settled commodity prices relative to our hedge positions.
Net realized gain (loss) from commodity derivatives relating to service revenues changed favorably due to a change in settled commodity prices relative to our hedge positions.
Transmission & Gulf of Mexico also includes natural gas storage facilities and pipelines providing services in 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 VIE) which operates in West Virginia, Ohio, and Pennsylvania, a 66 percent interest in Cardinal (a consolidated VIE) which operates in Ohio, a 69 percent equity-method investment in Laurel Mountain, a 50 percent equity-method investment in Blue Racer, and Appalachia Midstream Investments. • West is comprised of 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 and Permian basins.
Transmission & Gulf of Mexico also includes natural gas storage facilities and pipelines providing services in 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 Northeast JV which operates in West Virginia, Ohio, and Pennsylvania, a 66 percent interest in Cardinal which operates in Ohio, a 69 percent equity-method investment in Laurel Mountain, a 50 percent equity-method investment in Blue Racer, and Appalachia Midstream Investments. • West is comprised of 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, the Mid-Continent region which includes the Anadarko and Permian basins, and the DJ Basin of Colorado which includes RMM, a former 50 percent equity-method investment in which we acquired the remaining ownership interest in November 2023.
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.
We also expect to invest capital in our Other segment ventures. 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.
We will seek to recover approximately $4 million of accrued costs related to remediation activities by our interstate gas pipelines through future natural gas transmission rates. The remainder of these costs will be funded from operations. During 2022, we paid approximately $5 million for cleanup and/or remediation and monitoring activities.
We will seek to recover approximately $3 million of accrued costs related to remediation activities by our interstate gas pipelines through future natural gas transmission rates. The remainder of these costs will be funded from operations. During 2023, we paid approximately $7 million for cleanup and/or remediation and monitoring activities.
This project is expected to go into service in the fourth quarter of 2024. 49 Haynesville Gathering Expansion In February 2023, we announced our agreement with a third 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.
This project is expected to go into service in the second half of 2025. Haynesville Gathering Expansion In February 2023, we announced our agreement with a third party to facilitate natural gas production growth in the Haynesville basin. We plan to construct a greenfield gathering system in support of the third party’s 26,000-acre dedication.
As of December 31, 2022, we have approximately $627 million of long-term debt due within one year. Our potential sources of liquidity available to address these maturities include cash on hand, proceeds from refinancing, our credit facility, or our commercial paper program, as well as proceeds from asset monetizations.
As of December 31, 2023, we have approximately $2.337 billion of long-term debt due within one year. Our potential sources of liquidity available to address these maturities include cash on hand, proceeds from refinancing, our credit facility, or our commercial paper program, as well as proceeds from asset monetizations.
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.
See Note 6 – Provision (Benefit) for Income Taxes for a discussion of the effective tax rate compared to the federal statutory rate for both periods.
The net sum of Service revenues – commodity consideration , Product sales , Product costs, net realized gains and losses on commodity derivatives related to sales of product, and net realized processing commodity expenses comprise our Commodity margins .
The net sum of Service revenues – commodity consideration , Product sales , Product costs, net realized gains and losses on commodity derivatives related to sales of product, and net realized processing commodity expenses for our reportable segments (excludes Other) comprise our Commodity margins .
Our available liquidity is as follows: Available Liquidity December 31, 2022 (Millions) Cash and cash equivalents $ 152 Capacity available under our $3.75 billion credit facility, less amounts outstanding under our $3.5 billion commercial paper program (1) 3,400 $ 3,552 __________ (1) In managing our available liquidity, we do not expect a maximum outstanding amount in excess of the capacity of our credit facility inclusive of any outstanding amounts under our commercial paper program.
Our available liquidity is as follows: Available Liquidity December 31, 2023 (Millions) Cash and cash equivalents $ 2,150 Capacity available under our $3.75 billion credit facility, less amounts outstanding under our $3.5 billion commercial paper program (1) 3,025 $ 5,175 __________ (1) In managing our available liquidity, we do not expect a maximum outstanding amount in excess of the capacity of our credit facility inclusive of any outstanding amounts under our commercial paper program.
Benefit Cost Benefit Obligation One- Percentage- Point Increase One- Percentage- Point Decrease One- Percentage- Point Increase One- Percentage- Point Decrease (Millions) Pension benefits: Discount rate $ (21) $ (1) $ (69) $ 80 Expected long-term rate of return on plan assets (11) 11 — — Cash balance interest crediting rate 5 (25) 50 (43) Other postretirement benefits: Discount rate (3) 2 (14) 16 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 historical returns, forward-looking capital market expectations of at least 10 years from our third-party independent investment advisor, as well as the investment strategy and relative weightings of the asset classes within the investment portfolio.
Benefit Cost Benefit Obligation One- Percentage- Point Increase One- Percentage- Point Decrease One- Percentage- Point Increase One- Percentage- Point Decrease (Millions) Pension benefits: Discount rate $ 3 $ (4) $ (73) $ 85 Expected long-term rate of return on plan assets (11) 11 — — Cash balance interest crediting rate 5 (4) 54 (47) Other postretirement benefits: Discount rate (3) 4 (13) 16 Expected long-term rate of return on plan assets (3) 3 — — Our expected long-term rates of return on plan assets, as determined at the beginning of each fiscal year, are based on historical returns, forward-looking capital market expectations of at least 10 years from our third-party independent investment advisor, as well as the investment strategy and relative weightings of the asset classes within the investment portfolio.
These increases were partially offset by an unfavorable change in natural gas marketing sales primarily due to the impact of netting 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).
These increases were partially offset by an unfavorable change in natural gas marketing sales primarily due to the impact of netting the 2022 legacy natural gas marketing revenues with the associated costs (see Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies).
Overview of the Results of Operations Net income (loss) attributable to The Williams Companies, Inc. for the year ended December 31, 2022, increased by $532 million over the prior year. Further discussion of our results is found in this report in the Results of Operations.
Overview of the Results of Operations Net income (loss) attributable to The Williams Companies, Inc. for the year ended December 31, 2023, increased by $1.13 billion over the prior year. Further discussion of our results is found in this report in the Results of Operations.
The 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. Other segment costs and expenses increased primarily due to employee-related costs associated with the operations acquired in the Sequent Acquisition in 2021.
Net unrealized gain (loss) from commodity 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.
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.
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.
Texas to Louisiana Energy Pathway 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 firm transportation capacity from receipt points in south Texas to delivery points in Texas and Louisiana.
Texas to Louisiana Energy Pathway In January 2024, we received approval from the FERC for the project, which involves an expansion of Transco’s existing natural gas transmission system to provide firm transportation capacity from receipt points in south Texas to delivery points in Texas and Louisiana.
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.
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 the benefit obligations and costs are shown in Note 7 – Employee Benefit Plans.
We had $350 million of commercial paper outstanding at December 31, 2022. The highest amount outstanding under our commercial paper program and credit facility during 2022 was $1.219 billion. At December 31, 2022, we were in compliance with the financial covenants associated with our credit facility.
We had $725 million of commercial paper outstanding at December 31, 2023. The highest amount outstanding under our commercial paper program and credit facility during 2023 was $730 million. At December 31, 2023, we were in compliance with the financial covenants associated with our credit facility.
We plan to place the project into service as early as the 2024/2025 winter heating season assuming timely receipt of all necessary regulatory approvals. The project is expected to increase capacity by 423 Mdth/d.
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 64 Mdth/d.
Southeast Energy Connector In August 2022, we filed an application with the FERC 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 Mississippi and Alabama to a delivery point in Alabama.
Southeast Energy Connector In November 2023, we received approval from the FERC for the project, which involves an expansion of Transco’s existing natural gas transmission system to provide incremental firm transportation capacity from receipt points in Mississippi and Alabama to a delivery point in Alabama.
Southside Reliability Enhancement In May 2022, we filed an application with the FERC 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.
Southside Reliability Enhancement In July 2023, we received approval from the FERC for the project, which involves 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.
Dividends In December 2022, we paid a regular quarterly dividend of $0.425 per share. On January 31, 2023, our board of directors approved a regular quarterly dividend of $0.4475 per share payable on March 27, 2023.
Dividends In December 2023, we paid a regular quarterly dividend of $0.4475 per share. On January 30, 2024, our board of directors approved a regular quarterly dividend of $0.4750 per share payable on March 25, 2024.
On February 14, 2023, we acquired 100 percent of 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 acquisition was funded with available sources of short-term liquidity.
MountainWest Acquisition On February 14, 2023, we closed on the acquisition of 100 percent of MountainWest Pipelines Holding Company which includes FERC-regulated interstate natural gas pipeline systems and natural gas storage capacity, for $1.08 billion of cash, funded with available sources of short-term liquidity, and retaining $430 million outstanding principal amount of MountainWest long-term debt.
Sources (Uses) of Cash The following table summarizes the sources (uses) of cash and cash equivalents for each of the periods presented (see Notes to Consolidated Financial Statements for the Notes referenced in the table): Cash Flow Year Ended December 31, Category 2022 2021 2020 (Millions) Sources of cash and cash equivalents: Operating activities – net Operating $ 4,889 $ 3,945 $ 3,496 Proceeds from long-term debt (see Note 12) Financing 1,755 2,155 2,199 Proceeds from credit-facility borrowings Financing — — 1,700 Proceeds from commercial paper - net Financing 345 — — Contributions in aid of construction Investing 12 52 37 Uses of cash and cash equivalents: Payments of long-term debt (see Note 12) Financing (2,876) (894) (2,141) Common dividends paid Financing (2,071) (1,992) (1,941) Payments on credit-facility borrowings Financing — — (1,700) Capital expenditures Investing (2,253) (1,239) (1,239) Purchases of businesses, net of cash acquired (see Note 3) Investing (933) (151) — Dividends and distributions paid to noncontrolling interests Financing (204) (187) (185) Purchases of and contributions to equity-method investments (see Note 8) Investing (166) (115) (325) Other sources / (uses) – net Financing and Investing (26) (36) (48) Increase (decrease) in cash and cash equivalents $ (1,528) $ 1,538 $ (147) Operating activities The factors that determine operating activities are largely the same as those that affect Net income (loss) , with the exception of noncash items such as Depreciation and amortization , Provision (benefit) for deferred income taxes , Equity (earnings) losses , Impairment of goodwill , Impairment of equity-method investments , Impairment of certain assets , Net unrealized (gain) loss from derivative instruments , and Inventory write-downs.
Sources (Uses) of Cash The following table summarizes the sources (uses) of cash and cash equivalents for each of the periods presented (see Notes to Consolidated Financial Statements for the Notes referenced in the table): Cash Flow Year Ended December 31, Category 2023 2022 2021 (Millions) Sources of cash and cash equivalents: Net cash provided (used) by operating activities Operating $ 5,938 $ 4,889 $ 3,945 Proceeds from long-term debt (see Note 12) Financing 2,755 1,755 2,155 Proceeds from (payments of) commercial paper - net Financing 372 345 — Proceeds from sale of business (see Note 3) Investing 346 — — Uses of cash and cash equivalents: Capital expenditures Investing (2,516) (2,253) (1,239) Common dividends paid Financing (2,179) (2,071) (1,992) Purchases of businesses, net of cash acquired (see Note 3) Investing (1,568) (933) (151) Payments of long-term debt (see Note 12) Financing (634) (2,876) (894) Dividends and distributions paid to noncontrolling interests Financing (213) (204) (187) Purchases of and contributions to equity-method investments (see Note 8) Investing (141) (166) (115) Purchases of treasury stock Financing (130) (9) — Other sources / (uses) – net Financing and Investing (32) (5) 16 Increase (decrease) in cash and cash equivalents $ 1,998 $ (1,528) $ 1,538 Operating activities The factors that determine operating activities are largely the same as those that affect Net income (loss) , with the exception of noncash items such as Depreciation and amortization , Provision (benefit) for deferred income taxes , Equity (earnings) losses , Net unrealized (gain) loss from commodity derivative instruments , Gain on sale of business, Inventory write-downs, and Amortization of stock-based awards.
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 the duration of the expected benefit cash flows of each plan. 50 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.
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 the duration of the expected benefit cash flows of each plan.
Growth capital spending in 2023 primarily includes Transco expansions, all of which are fully contracted with firm transportation agreements, projects supporting the Northeast G&P business and projects supporting growth in the Haynesville basin, including the Louisiana Energy Gateway project. We also expect to invest capital in the development of our upstream oil and gas properties.
Growth capital spending in 2024 primarily includes Transco expansions, all of which are fully contracted with firm transportation agreements, projects supporting growth in the Haynesville Basin, and projects supporting the Northeast G&P business. We also expect to invest capital in our Other segment ventures.
Our expected long-term rate of return on plan assets used for our pension plans was 3.81 percent in 2022. The 2022 actual return on plan assets for our pension plans was a loss of approximately 9.7 percent. The 10-year average rate of return on pension plan assets through December 2022 was approximately 6.8 percent.
Our expected long-term rate of return on plan assets used for our pension plans was 5.17 percent in 2023. The 2023 actual return on plan assets for our pension plans was approximately 11.4 percent. The 10-year average rate of return on pension plan assets through December 2023 was approximately 6.4 percent.
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.
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.
Proportional Modified EBITDA of equity-method investments increased primarily due to higher volumes at OPPL and higher commodity prices and volumes at RMM. 2021 vs. 2020 West Modified EBITDA increased primarily due to higher Commodity margins, partially offset by lower Service revenues .
Proportional Modified EBITDA of equity-method investments increased primarily due to higher volumes at OPPL and higher commodity prices and volumes at RMM.
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 higher MVC revenue, partially offset by lower volumes, and an increase at Aux Sable. 59 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 increased 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.
The decrease was partially offset by an increase at Laurel Mountain primarily due to higher commodity-based gathering rates. 64 West Year Ended December 31, 2023 2022 2021 (Millions) Service revenues $ 1,502 $ 1,542 $ 1,248 Service revenues – commodity consideration (1) 103 182 179 Product sales (1) 441 841 643 Net realized gain (loss) from commodity derivatives relating to service revenues 82 (1) (15) Net realized gain (loss) from commodity derivatives relating to product sales (1) 7 (3) (29) Net realized gain (loss) from commodity derivatives 89 (4) (44) Segment revenues 2,135 2,561 2,026 Product costs (1) (425) (813) (608) Net processing commodity expenses (1) (92) (105) (85) Other segment costs and expenses (542) (564) (477) Proportional Modified EBITDA of equity-method investments 162 132 105 West Modified EBITDA $ 1,238 $ 1,211 $ 961 Commodity margins $ 34 $ 102 $ 100 ________________ (1) Included as a component of Commodity margins . 2023 vs. 2022 West Modified EBITDA increased primarily due to a favorable change in Net realized gain (loss) from commodity derivatives relating to service revenues, higher Proportional Modified EBITDA of equity-method investments, and lower Other segment costs and expenses, partially offset by lower Commodity margins and Service revenues.
Proportional Modified EBITDA of equity-method investments decreased primarily due to lower volumes at OPPL, partially offset by higher volumes and commodity prices at Brazos Permian II. 61 Gas & NGL 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 ________________ (1) Included as a component of Commodity margins . 2022 vs. 2021 Gas & NGL Marketing Services Modified EBITDA decreased primarily due to higher net unrealized loss from derivative instruments and higher Other segment costs and expenses , partially offset by higher Commodity margins .
Gas & NGL Marketing Services Year Ended December 31, 2023 2022 2021 (Millions) Service revenues $ 1 $ 3 $ 3 Product sales (1) 2,060 3,534 4,292 Net realized gain (loss) from commodity derivative instruments (1) 115 17 25 Net unrealized gain (loss) from commodity derivative instruments 702 (321) (109) Net gain (loss) from commodity derivatives 817 (304) (84) Segment revenues 2,878 3,233 4,211 Net unrealized gain (loss) from commodity derivative instruments within Net processing commodity expenses (43) 47 — Product costs (1) (1,786) (3,228) (4,152) Other segment costs and expenses (99) (92) (37) Gas & NGL Marketing Services Modified EBITDA $ 950 $ (40) $ 22 Commodity margins $ 389 $ 323 $ 165 ________________ (1) Included as a component of Commodity margins . 2023 vs. 2022 Gas & NGL Marketing Services Modified EBITDA increased primarily due to a favorable change in Net unrealized gain (loss) from commodity derivative instruments within Segment revenues and higher Commodity margins , partially offset by an unfavorable change in Net unrealized gain (loss) from commodity derivative instruments within Net processing commodity expenses .
We retain the flexibility to adjust planned levels of growth capital and investment expenditures in response to changes in economic conditions or business opportunities including the repurchase of our common stock.
We retain the flexibility to adjust planned levels of growth capital and investment expenditures in response to changes in economic conditions or business opportunities including the repurchase of our common stock. On January 5, 2024, we issued $2.1 billion in long-term debt (see Note 12 – Debt and Banking Arrangements).
Proportional Modified EBITDA of equity-method investments increased at Discovery driven by higher NGL sales prices and higher volumes due to the absence of prior year scheduled maintenance. 57 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 (1) Included as a component of Commodity margins . 2022 vs. 2021 Northeast G&P Modified EBITDA increased primarily due to higher Service revenues , partially offset by lower Proportional Modified EBITDA of equity-method investments and higher Other segment costs and expenses .
These increases are partially offset by a favorable change in the deferral of ARO related depreciation at Transco. 62 Northeast G&P Year Ended December 31, 2023 2022 2021 (Millions) Service revenues $ 1,896 $ 1,654 $ 1,528 Service revenues – commodity consideration (1) 5 14 7 Product sales (1) 132 134 99 Segment revenues 2,033 1,802 1,634 Product costs (1) (123) (135) (99) Net processing commodity expenses (1) (2) (3) (2) Other segment costs and expenses (566) (522) (503) Proportional Modified EBITDA of equity-method investments 574 654 682 Northeast G&P Modified EBITDA $ 1,916 $ 1,796 $ 1,712 Commodity margins $ 12 $ 10 $ 5 (1) Included as a component of Commodity margins . 2023 vs. 2022 Northeast G&P Modified EBITDA increased primarily due to higher Service revenues , partially offset by lower Proportional Modified EBITDA of equity-method investments and higher Other segment costs and expenses .
Provisions were included in the settlement that establishes a moratorium on any proceedings that would seek to place new rates in effect any earlier than January 1, 2026, and that a general rate case filing will be made for rates to become effective not later than April 1, 2028, unless we have entered into a pre-filing settlement prior to that date.
Provisions were included in the settlement that establish a moratorium on any proceedings that would seek to place new rates in effect any earlier than January 1, 2026, and that a general rate case filing will be made for rates to become effective not later than April 1, 2028, unless we have entered into a pre-filing settlement prior to that date. 51 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.
Note 18 – 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.
Year-Over-Year Operating Results – Segments We evaluate segment operating performance based upon Modified EBITDA . Note 18 – Segment Disclosures 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.
We are monitoring these sites in a coordinated effort with other potentially responsible parties, the EPA, or other governmental authorities. We are jointly and severally liable along with unrelated third parties in some of these activities and solely responsible in others.
We are jointly and severally liable along with 72 unrelated third parties in some of these activities and solely responsible in others.
The assumptions utilized to compute the benefit obligations and costs are shown in Note 7 – 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.
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.
Interest on the cash balance accounts is based on the 30-year U.S. Treasury securities rate. 51 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, 2022. The results of operations by segment are discussed in further detail following this consolidated overview discussion.
Treasury securities rate. 55 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, 2023 and should be read in conjunction with the results of operations by segment, as discussed in further detail following this consolidated overview discussion.
See Note 8 – Investing Activities of Notes to Consolidated Financial Statements for our more significant equity-method investees. Credit Ratings The interest rates at which we are able to borrow money are impacted by our credit ratings.
In each case, available cash is reduced, in part, by reserves appropriate for operating their respective businesses. See Note 8 – Investing Activities for our more significant equity-method investees. Credit Ratings The interest rates at which we are able to borrow money are impacted by our credit ratings.
The increase was also a result of higher expenses associated with our upstream operations, increased costs associated with Transco's Leidy South expansion project placed in service in December 2021, higher employee-related expenses, and higher expenses associated with the 2022 Trace Acquisition and NorTex Asset Purchase. 53 Depreciation and amortization expenses increased 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 West segment.
Depreciation and amortization expenses increased 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 West segment. 59 Selling, general, and administrative expenses increased primarily due to higher employee-related expenses driven by the Sequent Acquisition in July 2021 and higher expenses for various corporate costs, including technology costs to support efforts to track and quantify emissions associated with natural gas procurement, transmission, and delivery.
See Results of Operations— Year-Over-Year Operating Results - Segments for additional discussion of Commodity margins and Net realized product sales on a segment basis. Operating and maintenance expenses increased primarily due to higher operating and maintenance costs, including $63 million of higher reimbursable electric power and storage costs which are substantially offset in Service revenues.
Operating and maintenance expenses increased primarily due to higher operating and maintenance costs, including $63 million of higher reimbursable electric power and storage costs which are substantially offset in Service revenues.
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 . 63 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 the favorable impact of Winter 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 volume of production hedged in 2022 compared to 2021.
Other Year Ended December 31, 2023 2022 2021 (Millions) Service revenues $ 16 $ 24 $ 32 Product sales (1) 442 706 333 Net realized gain (loss) from commodity derivative instruments (1) 47 (104) (20) Net unrealized gain (loss) from commodity derivative instruments 1 25 — Net gain (loss) from commodity derivatives 48 (79) (20) Segment revenues 506 651 345 Other segment costs and expenses (197) (217) (167) Net gain from Energy Transfer litigation judgment 534 — — Proportional Modified EBITDA of equity-method investments (2) — — Other Modified EBITDA $ 841 $ 434 $ 178 Net realized product sales $ 489 $ 602 $ 313 ________________ (1) Included as a component of Net realized product sales . 68 2023 vs. 2022 Other Modified EBITDA increased primarily due to the Net gain from Energy Transfer litigation judgmen t (see Note 17 – Contingencies and Commitments), partially offset by lower results from our upstream operations, which included the following: • $113 million decrease in Net realized product sales primarily due to lower net realized commodity prices, partially offset by higher sales associated with increased production volumes.
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.
See Note 6 – Provision (Benefit) for Income Taxes 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 higher results at the Northeast JV.
Modified EBITDA should not be considered in isolation or as a substitute for a measure of performance prepared in accordance with GAAP. 55 Transmission & Gulf of Mexico 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 _______________ (1) Included as a component of Commodity margins . 2022 vs. 2021 Transmission & Gulf of Mexico Modified EBITDA increased primarily due to higher Service revenues , partially offset by higher Other segment costs and expenses.
Transmission & Gulf of Mexico Year Ended December 31, 2023 2022 2021 (Millions) Service revenues $ 3,858 $ 3,579 $ 3,385 Service revenues – commodity consideration (1) 38 64 52 Product sales (1) 252 404 349 Net realized gain (loss) from commodity derivatives (1) 2 — — Segment revenues 4,150 4,047 3,786 Product costs (1) (246) (399) (349) Net processing commodity expenses (1) (13) (26) (17) Other segment costs and expenses (1,157) (1,141) (982) Gain on sale of business 129 — — Proportional Modified EBITDA of equity-method investments 205 193 183 Transmission & Gulf of Mexico Modified EBITDA $ 3,068 $ 2,674 $ 2,621 Commodity margins $ 33 $ 43 $ 35 _______________ (1) Included as a component of Commodity margins . 60 2023 vs. 2022 Transmission & Gulf of Mexico Modified EBITDA increased primarily due to higher Service revenues and a Gain on sale of business.
The system, once constructed, will provide natural gas gathering services to the third party. The third party has also agreed to 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.
The system, once constructed, will provide natural gas gathering services to the 54 third party. The third party has also agreed to a long-term capacity commitment on our Louisiana Energy Gateway project. This project is expected to go into service in the second half of 2025.
Other segment costs and expenses increased primarily due to higher employee-related costs related to the Sequent Acquisition and higher corporate allocations. 62 2021 vs. 2020 Gas & NGL Marketing Services Modified EBITDA decreased primarily due to higher net unrealized losses from derivative instruments, lower Service revenues , and higher segment costs and expenses, partially offset by higher Commodity margins.
The change from 2022 is primarily due to a change in forward commodity prices relative to our hedge positions in 2023 compared to 2022. 67 2022 vs. 2021 Gas & NGL Marketing Services Modified EBITDA decreased primarily due to higher net unrealized loss from derivative instruments and higher Other segment costs and expenses , partially offset by higher Commodity margins .
Growth capital spending in 2023 primarily includes Transco expansions, all of which are fully contracted with firm transportation agreements, projects supporting the Northeast G&P business and projects supporting growth in the Haynesville basin, including the Louisiana Energy Gateway project. We also expect to invest capital in the development of our upstream oil and gas properties.
Our growth capital and investment expenditures in 2024 are expected to be in a range from $1.45 billion to $1.75 billion, excluding acquisitions. Growth capital spending in 2024 primarily includes Transco expansions, all of which are fully contracted with firm transportation agreements, projects supporting growth in the Haynesville Basin, and projects supporting the Northeast G&P business.
Our growth capital and investment expenditures in 2023 are expected to be in a range from $1.40 billion to $1.70 billion, excluding the MountainWest Acquisition.
Outlook Our growth capital and investment expenditures in 2024 are currently expected to be in a range from $1.45 billion to $1.75 billion, excluding the Gulf Coast Storage Acquisition for $1.95 billion (see Note 3 – Acquisitions and Divestitures).
The decrease was partially offset by an increase at Laurel Mountain primarily due to higher commodity-based gathering rates. 58 2021 vs. 2020 Northeast G&P Modified EBITDA increased primarily due to increased Proportional Modified EBITDA of equity-method investments and higher Service revenues , partially offset by increased Other segment costs and expenses .
Additionally, Appalachia Midstream Investments increased primarily driven by higher gathering volumes and annual rate escalations at Marcellus South, partially offset by lower gathering rates resulting from annual cost of service contract redeterminations and lower volumes at the Bradford Supply Hub. 63 2022 vs. 2021 Northeast G&P Modified EBITDA increased primarily due to higher Service revenues , partially offset by lower Proportional Modified EBITDA of equity-method investments and higher Other segment costs and expenses .
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.
Southeast Supply Enhancement We plan to file an application with the FERC as early as the third quarter of 2024 for this project, which involves 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 Virginia, North Carolina, South Carolina, Georgia, and Alabama.
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.
Equity earnings (losses) changed unfavorably primarily due to a decrease at Laurel Mountain and our share of a loss contingency accrual related to our 14 percent ownership in Aux Sable Liquid Products LP, partially offset by increases at Blue Racer and OPPL.
Distributions from Equity-Method Investees The organizational documents of entities in which we have an equity-method investment generally require periodic distributions of their available cash to their members. In each case, available cash is reduced, in part, by reserves appropriate for operating their respective businesses.
Registrations Prior to the expiration of our shelf registration statement, we anticipate filing a new shelf registration statement as a well-known seasoned issuer. Distributions from Equity-Method Investees The organizational documents of entities in which we have an equity-method investment generally require periodic distributions of their available cash to their members.
We believe that accomplishing these goals will position us to deliver safe, reliable, clean energy services to our customers and an attractive return to our shareholders.
We believe that accomplishing these goals will position us to deliver safe, reliable, clean energy services to our customers and an attractive return to our shareholders. Our business plan for 2024 includes a continued focus on earnings and cash flow growth. In 2024, our operating results are expected to benefit from the recent Gulf Coast Storage and DJ Basin acquisitions.
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 a $10 million charge related to an accrual for loss contingency in 2021. 2021 vs. 2020 Other Modified EBITDA increased primarily due to: • A $168 million increase related to our upstream operations, including the favorable commodity price impact of Winter Storm Uri in the first quarter of 2021; • A $24 million increase due to the absence of a 2020 charge related to a legal settlement associated with our former olefins operations; • A $15 million increase due to the absence of 2020 charges related to write-offs of certain regulatory assets associated with cancelled projects; partially offset by • A $10 million decrease associated with a 2021 charge related to a legal settlement. 64 Management’s Discussion and Analysis of Financial Condition and Liquidity Overview We have continued to focus on earnings and cash flow growth, while continuing to improve leverage metrics and operating costs metrics.
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 a $10 million charge related to an accrual for loss contingency in 2021. 69 Management’s Discussion and Analysis of Financial Condition and Liquidity Overview We have continued to focus on earnings and cash flow growth, noting significant increases in both net income and cash provided by operating activities.
These increases are partially offset by a favorable change in the 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.
Gain on sale of business reflects a gain recognized on the sale of certain liquids pipelines in the Gulf Coast region in September 2023 (see Note 3 – Acquisitions and Divestitures). 61 2022 vs. 2021 Transmission & Gulf of Mexico Modified EBITDA increased primarily due to higher Service revenues , partially offset by higher Other segment costs and expenses.
Dividends We increased our regular quarterly cash dividend to common stockholders by approximately 3.7 percent from the $0.41 per share paid in each quarter of 2021, to $0.425 per share paid in each quarter of 2022. Registrations In February 2021, we filed a shelf registration statement as a well-known seasoned issuer.
See Note 12 – Debt and Banking Arrangements for additional information on our credit facility and commercial paper program. Dividends We increased our regular quarterly cash dividend to common stockholders by approximately 5.3 percent from the $0.425 per share paid in each quarter of 2022, to $0.4475 per share paid in each quarter of 2023.

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Item 7A. Quantitative and Qualitative Disclosures About Market Risk

Market Risk — interest-rate, FX, commodity exposure

9 edited+1 added−2 removed7 unchanged
Biggest changeThese economic hedges are not designated for hedge accounting treatment. 69 The maturities of our derivative contracts at December 31, 2022, as well as the maturities of the derivative contracts related to the operations acquired in the Sequent Acquisition at December 31, 2021, were as follows: Total Fair Value Maturity Fair Value Measurements Using (1) 2023 2024 - 2025 2026 - 2027+ (Millions) Level 1 (2) $ (2) $ 11 $ (9) $ (4) Level 2 (586) (171) (224) (191) Level 3 (56) (19) 2 (39) Fair value of contracts outstanding at December 31, 2022 $ (644) $ (179) $ (231) $ (234) Total Fair Value Maturity Fair Value Measurements Using (1) 2022 2023 - 2024 2025 - 2026+ (Millions) Level 1 (3) $ (69) $ (49) $ (30) $ 10 Level 2 (317) (77) (108) (132) Level 3 (16) (13) (11) 8 Fair value of contracts outstanding at December 31, 2021 $ (402) $ (139) $ (149) $ (114) _______________ (1) See Note 15 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk of Notes to Consolidated Financial Statements for discussion of valuation techniques by level within the fair value hierarchy.
Biggest changeThese economic hedges are not designated for hedge accounting treatment. 74 The maturities of our commodity derivative contracts at December 31, 2023 and 2022 were as follows: Total Fair Value Maturity Fair Value Measurements of Assets (Liabilities) Using (1) 2024 2025 - 2026 2027 - 2028+ (Millions) Level 1 (2) $ 138 $ 110 $ 33 $ (5) Level 2 (166) 14 (71) (109) Level 3 53 2 16 35 Fair value of contracts outstanding at December 31, 2023 $ 25 $ 126 $ (22) $ (79) Total Fair Value Maturity Fair Value Measurements of Assets (Liabilities) Using (1) 2023 2024 - 2025 2026 - 2027+ (Millions) Level 1 (3) $ (2) $ 11 $ (9) $ (4) Level 2 (586) (171) (224) (191) Level 3 (56) (19) 2 (39) Fair value of contracts outstanding at December 31, 2022 $ (644) $ (179) $ (231) $ (234) _______________ (1) See Note 15 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk for discussion of valuation techniques by level within the fair value hierarchy.
(2) The weighted-average interest rate for commercial paper was 4.8 percent as of December 31, 2022. Commodity Price Risk We are exposed to commodity price risk through our natural gas and NGL marketing activities, including contracts to purchase, sell, transport, and store product.
(2) The weighted-average interest rate for commercial paper as of December 31, 2023 and 2022 was 5.6 percent and 4.8 percent, respectively. Commodity Price Risk We are exposed to commodity price risk through our natural gas and NGL marketing activities, including contracts to purchase, sell, transport, and store product.
We are also exposed to commodity prices through our upstream business and certain gathering and processing contracts. We use derivative instruments to lock in forward sales prices on a portion of our expected future production.
We are also exposed to commodity prices through our upstream business and certain gathering and processing contracts. We use derivative instruments to lock in forward sales prices on a portion of our expected future production and to lock in NGL margin on a portion of our commodity-exposed gathering and processing volumes.
See Note 16 – Derivatives of Notes to Consolidated Financial Statements for the amount of change in fair value recognized in our Consolidated Statement of Income. (2) Net commodity derivative assets and liabilities exclude $202 million of net cash collateral in Level 1.
See Note 16 – Commodity Derivatives for the amount of change in fair value recognized in our Consolidated Statement of Income. (2) Commodity derivative assets and liabilities exclude $2 million of net cash collateral in Level 1. (3) Commodity derivative assets and liabilities exclude $202 million of net cash collateral in Level 1.
We had the following VaRs for the periods shown: Nine Months Ended December 31, 2022 Three Months Ended March 31, 2022 Six Months Ended December 31, 2021 Trading Sequent Only Sequent Only (Millions) Average $ 10 $ 6 $ 4 High $ 39 $ 10 $ 7 Low $ 4 $ 4 $ 2 Our non-trading portfolio primarily consists of derivatives that hedge our upstream business and certain gathering and processing contracts.
We had the following VaRs for the periods shown: Twelve Months Ended December 31, 2023 Nine Months Ended December 31, 2022 Three Months Ended March 31, 2022 Trading Trading Sequent Only (Millions) Average $ 6 $ 10 $ 6 High $ 13 $ 39 $ 10 Low $ 4 $ 4 $ 4 Our non-trading portfolio primarily consists of commodity derivatives that hedge our upstream business and certain gathering and processing contracts.
See Note 15 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk of Notes to Consolidated Financial Statements for the methods used in determining the fair value of our long-term debt. 2023 2024 2025 2026 2027 Thereafter (1) Total Fair Value December 31, 2022 (Millions) Long-term debt, including current portion: Fixed rate $ 629 $ 2,281 $ 1,619 $ 1,245 $ 1,993 $ 14,787 $ 22,554 $ 21,569 Weighted-average interest rate 5.0 % 5.0 % 5.1 % 5.0 % 5.0 % 5.1 % Commercial paper (2) $ 350 $ — $ — $ — $ — $ — $ 350 $ 350 2022 2023 2024 2025 2026 Thereafter (1) Total Fair Value December 31, 2021 (Millions) Long-term debt, including current portion: Fixed rate $ 2,026 $ 1,478 $ 2,281 $ 1,619 $ 1,244 $ 15,027 $ 23,675 $ 27,768 Weighted-average interest rate 4.9 % 5.0 % 5.1 % 5.1 % 5.1 % 5.1 % __________________ (1) Includes unamortized discount / premium and debt issuance costs.
See Note 15 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk for the methods used in determining the fair value of our long-term debt. 2024 2025 2026 2027 2028 Thereafter (1) Total Fair Value December 31, 2023 (Millions) Long-term debt, including current portion: Fixed rate $ 2,338 $ 2,263 $ 2,345 $ 1,993 $ 1,445 $ 15,329 $ 25,713 $ 25,553 Weighted-average interest rate 4.9 % 5.0 % 5.1 % 5.0 % 5.1 % 5.1 % Commercial paper (2) $ 725 $ — $ — $ — $ — $ — $ 725 $ 725 2023 2024 2025 2026 2027 Thereafter (1) Total Fair Value December 31, 2022 (Millions) Long-term debt, including current portion: Fixed rate $ 629 $ 2,281 $ 1,619 $ 1,245 $ 1,993 $ 14,787 $ 22,554 $ 21,569 Weighted-average interest rate 5.0 % 5.0 % 5.1 % 5.0 % 5.0 % 5.1 % Commercial paper (2) $ 350 $ — $ — $ — $ — $ — $ 350 $ 350 __________________ (1) Includes unamortized discount / premium and debt issuance costs.
(See Note 12 – Debt and Banking Arrangements of Notes to Consolidated Financial Statements.) The tables below provide information by maturity date about our interest rate risk-sensitive instruments as of December 31, 2022 and 2021.
We may utilize interest rate derivative instruments to hedge interest rate risk associated with future debt issuances (see Note 12 – Debt and Banking Arrangements). The tables below provide information by maturity date about our interest rate risk-sensitive instruments as of December 31, 2023 and 2022.
For the second half of 2021 and the first quarter of 2022, the VaR presented reflects the legacy Sequent operations only. 70 At December 31, 2022, the VaR associated with this activity was $10 million.
For the first quarter of 2022, the VaR presented reflects the legacy Sequent operations only. 75 The VaR associated with our integrated natural gas trading operations was $9 million at December 31, 2023 and $10 million at December 31, 2022.
Our VaR may not be comparable to that of other companies due to differences in the factors used to calculate VaR.
Value at Risk (VaR) VaR is the maximum predicted loss in portfolio value over a specified time period that is not expected to be exceeded within a given degree of probability. Our VaR may not be comparable to that of other companies due to differences in the factors used to calculate VaR.
Removed
(3) Net commodity derivative assets and liabilities related to the operations acquired in the Sequent Acquisition exclude $267 million of net cash collateral in Level 1. Value at Risk (VaR) VaR is the maximum predicted loss in portfolio value over a specified time period that is not expected to be exceeded within a given degree of probability.
Added
The VaR associated with these commodity derivatives was $3 million at December 31, 2023 and $8 million at December 31, 2022. We had the following VaRs for the periods shown: Twelve Months Ended December 31, 2023 Six Months Ended December 31, 2022 (Millions) Average $ 4 $ 16 High $ 8 $ 33 Low $ 2 $ 7 76
Removed
At December 31, 2022, the VaR associated with these derivatives was $8 million. 71

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