Item 1. Business
Item 1. Business
In this report, Williams (which includes The Williams Companies, Inc. and, unless the context otherwise indicates, all of our subsidiaries) is at times referred to in the first person as “we,” “us,” or “our.” We also sometimes refer to Williams as the “Company.”
GENERAL
We are an energy company committed to being the leader in providing infrastructure that safely delivers natural gas products to reliably fuel the clean energy economy. 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. 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.
We were founded in 1908, originally incorporated under the laws of the state of Nevada in 1949 and reincorporated under the laws of the state of Delaware in 1987. Our common stock trades on the New York Stock Exchange under the symbol “WMB.” Our operations are located in the United States. Williams’ headquarters are located in Tulsa, Oklahoma, with other major offices in Houston, Texas and Pittsburgh, Pennsylvania. Our telephone number is 800-945-5426 (800-WILLIAMS).
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Service Assets, Customers, and Contracts
Key variables for our businesses will continue to be:
• Obstacles to our expansion efforts, including delays or denials of necessary permits and opposition to hydrocarbon-based energy development;
• Producer drilling activities impacting natural gas supplies supporting our gathering and processing volumes;
• Retaining and attracting customers by continuing to provide reliable services;
• Revenue growth associated with additional infrastructure either completed or currently under construction;
• Prices impacting our commodity-based activities;
• Disciplined growth in our service areas.
Interstate Natural Gas Pipeline Assets
Our interstate natural gas pipelines, which are presented in our Transmission & Gulf of Mexico segment as described under the heading “Business Segments,” are subject to regulation by the FERC and as such, our rates and charges for the transportation of natural gas in interstate commerce are subject to regulation. The rates are established primarily through the FERC’s ratemaking process, but we also may negotiate rates with our customers pursuant to the terms of our tariffs and FERC policy.
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
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contracted under long-term firm reservation contracts with high credit quality customers. 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. Our top ten customers of our interstate natural gas pipelines in 2023 accounted for approximately 47 percent of our regulated interstate natural gas transportation and storage revenues.
Gathering, Processing, and Treating Assets
Our gathering, processing, and treating operations are presented within our Transmission & Gulf of Mexico, Northeast G&P, and West reporting segments as described under the heading “Business Segments.”
Our gathering systems receive natural gas from producers’ crude oil and natural gas wells and gather these volumes to gas processing, treating, or redelivery facilities. Typically, natural gas, in its raw form, is not acceptable for transportation in major interstate natural gas pipelines or for commercial use as a fuel. Our treating facilities remove water vapor, carbon dioxide, and other contaminants, and collect condensate. We are generally paid a fee based on the volume of natural gas gathered and/or treated, generally measured in the Btu heating value.
In addition, natural gas contains various amounts of NGLs, which generally have a higher value when separated from the natural gas stream. Our processing plants extract the NGLs, which include ethane, primarily used in the petrochemical industry; propane, used for heating, fuel, and also in the petrochemical industry; and, normal butane, isobutane, and natural gasoline, primarily used by the refining industry.
Our gas processing services generate revenues primarily from the following types of contracts:
• Fee-based: We are paid a fee based on the volume of natural gas processed, generally measured in the Btu heating value. A portion of our fee-based processing revenue includes a share of the margins on the NGLs produced. 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. For a keep-whole arrangement we replace the Btu content of the retained NGLs with natural gas purchases, also known as shrink replacement gas. For a percent-of-liquids arrangement, we deliver an agreed-upon percentage of the extracted NGLs and retain the remainder. Retained NGLs are referred to as our equity NGL production. 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. Certain contracts include cost of service mechanisms that are designed to support a return on invested capital and allow our gathering rates to be adjusted, subject to specified caps in certain cases, to account for variability in volume, capital expenditures, commodity price fluctuations, compression, and other expenses. We also have certain gas gathering and processing agreements with MVC, whereby the customer is obligated to pay a contractually determined fee based on any shortfall between the actual gathered and processed volumes and the MVC for a stated period.
Demand for gas gathering and processing services is dependent on producers’ drilling activities, which is impacted by the strength of the economy, commodity prices, and the resulting demand for natural gas by manufacturing and industrial companies and consumers. Our gathering, processing, and treating businesses do not have direct exposure to crude oil prices. Our on-shore natural gas gathering and processing businesses are substantially focused on gas-directed drilling basins rather than crude oil, with a broad diversity of basins and customers served. Declines in crude oil drilling would be expected to result in less associated natural gas production, which could drive more demand for natural gas produced from gas-directed basins we serve.
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
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margins from our noncash commodity-based agreements. 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.
Gas and NGL Marketing
Our NGL and natural gas marketing services are presented primarily within our Gas & NGL Marketing Services segment. We market natural gas and NGL products to a wide range of users in the energy and petrochemical industries. In 2023, our three largest natural gas marketing customers accounted for approximately 10 percent of our gross natural gas marketing sales, and our three largest NGL marketing customers accounted for approximately 43 percent of our NGL marketing sales.
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. Additionally, our gas marketing business moves and optimizes natural gas to markets through transportation and storage agreements on our own strategically positioned assets. Our gas and NGL marketing services provide customers with access to diverse sources of supply and to various natural gas demand markets, including the southeastern and gulf coast regions which are the fastest growing natural gas demand regions in the United States.
We purchase natural gas for storage when the current market price paid to buy and transport natural gas plus the cost to store and finance the natural gas is less than an estimated, forward market price that can be received in the future, resulting in positive net product sales. Commodity-based exchange-traded futures contracts and over-the-counter (OTC) contracts are used to sell natural gas at that future price to substantially protect the natural gas revenues that will ultimately be realized when the stored natural gas is sold. Additionally, we enter into transactions to secure transportation capacity between delivery points in order to serve our customers and various markets. Commodity-based exchange-traded futures contracts and OTC contracts are used to capture the price differential or spread between the locations served by the capacity in order to substantially protect the natural gas revenues that will ultimately be realized when the physical flow of natural gas between receipt and delivery points occurs.
Monthly demand charges incurred for the contracted storage and transportation capacity and payments associated with asset management agreements are substantially indirectly reimbursed by our customers. As we are acting as an agent, our natural gas marketing revenues are presented net of the related costs of those activities. 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. Prior to the integration in 2022 of our historical gas marketing business with the acquired Sequent gas marketing business, natural gas marketing revenues and costs for our historical business were reported on a gross basis. Following the integration in 2022, the entire natural gas marketing portfolio is considered held for trading purposes, and the related revenues are therefore presented net of the related costs of those activities in 2022.
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. The NGL marketing business bears the risk of price changes in these NGL volumes while they are being transported to final sales delivery points. In order to meet sales contract obligations, we may purchase products in the spot market for resale.
We are exposed to commodity price risk. To manage this volatility, we use various contracts in our marketing and trading activities that generally meet the definition of derivatives. We enter into commodity-related derivatives to hedge exposures to natural gas and NGLs and retain exposure to price changes that can, in a volatile energy market, be material and can adversely affect our results of operations.
We experience significant earnings volatility from the fair value accounting required for the derivatives used to hedge a portion of the economic value of the underlying transportation and storage portfolio as well as upstream related production. However, the unrealized fair value measurement gains and losses are generally offset by
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valuation changes in the economic value of the underlying production or transportation and storage contracts, which is not recognized until the underlying transaction occurs.
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. 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.
Standalone, Market-Based Rate Natural Gas Storage Assets
Our standalone, market-based rate natural gas storage assets are presented in our Transmission & Gulf of Mexico segment as described under the heading “Business Segments” and include our NorTex assets acquired in August 2022 and our Gulf Coast storage assets acquired in January 2024. These natural gas storage assets provide natural gas storage services in interstate commerce under the jurisdiction of the FERC pursuant to the Natural Gas Act or Section 311 of the Natural Gas Policy Act. We are authorized to charge and collect market-based rates for all of the services that these natural gas storage assets provide.
We 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 these natural gas storage businesses are fully contracted under long-term firm reservation contracts with high credit quality customers. 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.
BUSINESS SEGMENTS
Consistent with the manner in which our chief operating decision maker evaluates performance and allocates resources, our operations are conducted, managed, and presented in Part I of this Annual Report 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.
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. (Gulfstream), and a 60 percent equity-method investment in Discovery Producer Services LLC (Discovery). 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. (Cardinal) which operates in Ohio, a 69 percent equity-method investment in Laurel Mountain Midstream, LLC (Laurel Mountain), a 50 percent equity-method investment in Blue Racer Midstream LLC (Blue Racer),
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and our equity-method investments with an approximate average 66 percent interest in multiple gas gathering systems in the Marcellus Shale region (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. 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.
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.
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. 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. 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. During 2023, Transco began partial early service on the Regional Energy Access expansion project, which added approximately 0.5 MMdth/d of firm transportation capacity to its pipeline. In addition, Transco added almost 0.1 MMdth/d of firm transportation capacity by converting certain interruptible transportation feeder capacity to firm transportation. 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. At December 31, 2023, Transco’s customers had stored in its facilities approximately 142 Bcf of natural gas. Storage capacity permits our customers to inject gas into storage during the summer and off-peak periods for delivery during peak winter demand periods.
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. Northwest Pipeline provides services for
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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. 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. 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.
MountainWest Acquisition
On February 14, 2023, we closed on the acquisition of 100 percent of MountainWest Pipelines Holding Company. MountainWest is an interstate natural gas transmission company that owns and operates an approximately 2,000-mile natural gas pipeline system which is regulated by the FERC. The system is comprised of MountainWest Pipeline, LLC; MountainWest Overthrust Pipeline, LLC; a 50 percent equity-method interest in White River Hub, LLC; and 56 Bcf of natural gas storage capacity, including the Clay basin underground storage reservoir in Utah. MountainWest is located in the Rocky Mountains near six producing areas, including the Greater Green River basin in Wyoming, the Uinta basin in Utah, and the Piceance basin in Colorado. At December 31, 2023, MountainWest’s system has a design capacity totaling 8.0 MMdth/d.
Standalone Natural Gas Storage Assets
Gulf Coast Storage Acquisition
On January 3, 2024, we closed on the acquisition of a strategic portfolio of approximately 230 miles of natural gas transmission pipelines and six underground storage facilities with a capacity of approximately 115 Bcf of natural gas storage across Louisiana and Mississippi and direct access to LNG export facilities and interstate pipelines. 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. 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.
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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
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(1) Includes 100 percent of the statistics associated with our operated equity-method investment Discovery.
Crude Oil Transportation and Production Handling Assets
In addition to our natural gas assets, we own and operate four deepwater crude oil pipelines and own production platforms serving the deepwater in the Gulf of Mexico. Our offshore floating production platforms provide centralized services to deepwater producers such as compression, separation, production handling, water removal, and pipeline landings.
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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
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(1) Statistics reflect 100 percent of the assets from our 51 percent interest in Gulfstar One floating production system (FPS).
(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. 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. 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. Discovery’s assets also include a crude oil production handling platform with capacity of 10 Mbbls/d and gas handling and separation capacity of 75 MMcf/d.
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Transmission & Gulf of Mexico Operating Statistics
2023 2022 2021
(Annual Average Amounts)
Consolidated:
Interstate natural gas pipeline throughput (MMdth/d) (1) (2)
20.4 16.9 16.2
Gathering volumes (Bcf/d) 0.26 0.29 0.28
Plant inlet natural gas volumes (Bcf/d) 0.44 0.47 0.45
NGL production (Mbbls/d) 27 28 29
NGL equity sales (Mbbls/d) 6 6 6
Crude oil transportation (Mbbls/d) 123 119 134
Non-consolidated: (3)
Interstate natural gas pipeline throughput (MMdth/d) (1)
1.2 1.3 1.2
Gathering volumes (Bcf/d) 0.34 0.40 0.35
Plant inlet natural gas volumes (Bcf/d) 0.34 0.40 0.35
NGL production (Mbbls/d) 27 28 27
NGL equity sales (Mbbls/d) 7 8 8
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(1) Tbtu converted to MMdth at one trillion British thermal units = one million dekatherms.
(2) Includes volumes for natural gas transmission assets acquired in the MountainWest Acquisition after the purchase on February 14, 2023, including 100 percent of the volumes associate with the operated equity-method investment White River Hub, LLC. Further, the amounts for the acquired assets are averaged over the period owned, not over the entire year.
(3) Includes 100 percent of the volumes associated with our operated equity-method investments Gulfstream and Discovery.
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.
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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
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(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.
(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. The listed inlet capacity of 0.6 Bcf/d is incremental capacity to the Cardinal gathering capacity of 0.7 Bcf/d.
(3) Includes 100 percent of the statistics associated with operated equity-method investments.
Other NGL Operations
We own and operate a 43 Mbbls/d NGL fractionation facility at Moundsville, West Virginia, de-ethanization and condensate facilities at our Oak Grove processing plant, a condensate stabilization facility near our Moundsville fractionator, an ethane pipeline, and an NGL pipeline. Our Oak Grove de-ethanizer is capable of handling up to approximately 80 Mbbls/d of mixed NGLs to extract up to approximately 40 Mbbls/d of ethane. Our condensate stabilizers are capable of handling approximately 17 Mbbls/d of field condensate. We also own and operate 44 Mbbls/d of condensate stabilization capacity, a 135 Mbbls/d NGL fractionation facility, approximately 970,000 barrels of NGL storage capacity, and other ancillary assets, including loading and terminal facilities in Ohio.
NGLs are extracted from the natural gas stream in our Oak Grove and Fort Beeler cryogenic processing plants. 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
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resulting products are then transported on truck, rail, or pipeline. Ohio Valley Midstream provides residue natural gas take away options for our customers with interconnections to three interstate transmission pipelines.
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. 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.
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. 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. 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. 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.
Northeast 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
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(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.
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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
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(1) Fort Lupton and Keenesburg I are a part of RMM which became a wholly owned subsidiary during 2023.
(2) Purchased as a part of the DJ Basin Acquisitions on November 30, 2023.
DJ Basin Acquisitions
On November 30, 2023, we closed on the acquisition of 100 percent of Cureton Front Range, LLC and the acquisition of the remaining 50 percent interest in Rocky Mountain Midstream Holdings LLC, both of which operate midstream assets in Colorado’s DJ Basin. The Cureton Acquisition includes gas gathering pipelines and two processing plants, one of which is currently idled. The RMM Acquisition was the purchase of our partner’s 50 percent interest, resulting in 100 percent ownership by us. RMM includes a natural gas gathering pipeline, an approximate 100-mile crude oil transportation pipeline, and natural gas processing assets in the DJ Basin. 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. The purpose of this
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acquisition was to expand our footprint into the east Texas area of the Haynesville Shale region, increasing in-basin scale.
Other NGL Operations
We own interests in and/or operate NGL fractionation and storage assets in central Kansas near Conway. These assets include a 50 percent interest in an NGL fractionation facility with capacity of slightly more than 100 Mbbls/d and we own approximately 23 million barrels of NGL storage capacity. We also own a 189-mile NGL pipeline from our fractionator near Conway, Kansas, to an interconnection with a third-party NGL pipeline system in Oklahoma.
Certain Equity-Method Investments
Overland Pass Pipeline
We operate and own a 50 percent interest in OPPL. 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. 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.
Targa Train 7
We own a 20 percent interest in Targa Train 7, a Mt. Belvieu, Texas, fractionation train.
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
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(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. Further, the amounts for the acquired assets are averaged over the period owned, not over the entire year.
(2) Includes 100 percent of the volumes associated with operated equity-method investment RMM prior to acquisition of the remaining 50 percent interest on November 30, 2023.
Gas & NGL Marketing Services
Our natural gas marketing business 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 markets natural gas from the production at our upstream properties. 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
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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. See the Gas and NGL Marketing section of Service Assets, Customers, and Contracts in Item 1. Business for additional information related to this business segment.
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
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(1) Includes 100% of the volumes associated with the Sequent Acquisition after the purchase on July 1, 2021. Further, the amounts for the acquired assets presented for 2021 are averaged over the period owned, not over the entire year.
Other
Other includes our upstream operations and minor business activities that are not reportable segments, as well as corporate operations.
Upstream Ventures
We acquired certain crude oil and natural gas properties in the Wamsutter basin in February 2021. These properties were conveyed to a venture in the third quarter of 2021 along with certain oil and gas properties conveyed by a third-party operator in the region. Under the terms of the agreement, the third party owns a 25 percent and we own a 75 percent undivided interest in each well’s working interest. We will retain ownership in the undeveloped acreage until certain acreage earning hurdles are met, at which time the third party will receive an additional 25 percent of any new wells and 50 percent of the remaining undeveloped acreage resulting in the third party owning 50 percent and us owning 50 percent. The combined properties consist of over 1.2 million net acres and an interest in over 3,500 wells.
Certain natural gas properties in Louisiana were transferred to us in November 2020 as part of a bankruptcy resolution with one of our customers. In the third quarter of 2021, we sold 50 percent of the existing wells and wellbore rights in the South Mansfield area of the Haynesville Shale region to a third party operator, in a strategic effort to develop the acreage, thereby enhancing the value of our midstream natural gas infrastructure. Under the agreement, the third party operates the upstream position and develops the undeveloped acreage. The third party’s interest in new wells increased to 75 percent in early 2023 when a certain drilling hurdle was met. 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.
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. NextGen Gas is natural gas that has been independently certified as low emissions gas across all segments of the value chain.
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REGULATORY MATTERS
FERC
Our gas pipeline interstate transmission and storage activities are subject to FERC regulation under the Natural Gas Act of 1938 (NGA) and under the Natural Gas Policy Act of 1978, and, as such, our rates and charges for the transportation of natural gas in interstate commerce, accounting, and the extension, enlargement, or abandonment of our jurisdictional facilities, among other things, are subject to regulation. Each of our gas pipeline companies holds certificates of public convenience and necessity issued by the FERC authorizing ownership and operation of all pipelines, facilities, and properties for which certificates are required under the NGA. FERC Standards of Conduct govern how our interstate pipelines communicate and conduct transmission transactions with an affiliate that engages in marketing functions. 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 gas pipeline companies establish rates through the FERC’s ratemaking process. In addition, our interstate gas pipelines may enter into negotiated rate agreements where cost-based recourse rates are made available. Key determinants in the FERC ratemaking process include:
• Costs of providing service, including depreciation expense;
• Allowed rate of return, including the equity component of the capital structure and related income taxes;
• Contract and volume throughput assumptions.
The allowed rate of return is determined in each rate case. Rate design and the allocation of costs between the reservation and commodity rates also impact profitability. As a result of these proceedings, certain revenues previously collected may be subject to refund.
We also own interests in and operate natural gas liquids pipelines that are regulated by various federal and state governmental agencies. Services provided on our interstate natural gas liquids pipelines are subject to regulation under the Interstate Commerce Act by the FERC, which has authority over the terms and conditions of service; rates, including depreciation and amortization policies; and initiation of service. Our intrastate natural gas liquids pipelines providing common carrier service are subject to regulation by various state regulatory agencies.
Updated Certificate Policy Statement and Interim Greenhouse Gas (GHG) Policy Statement
On February 18, 2022, the FERC issued two policy statements providing guidance for its pending and future consideration of interstate natural gas pipeline projects. The first policy statement is an Updated Certificate Policy Statement, which provides an analytical framework for how the FERC will consider whether a project is in the public convenience and necessity and explains that the FERC will consider all impacts of a proposed project, including economic and environmental impacts, together. The second policy statement is an Interim GHG Policy Statement, which sets forth how the FERC will assess the impacts of natural gas infrastructure projects on climate change in its reviews under the National Environmental Policy Act and the NGA. The FERC sought comment on all aspects of the policy statements, including the approach to assessing the significance of the proposed project’s contribution to climate change. On March 24, 2022, the FERC issued an order converting the Updated Certificate Policy Statement and the Interim GHG Policy Statement into draft policy statements and announcing that it will not apply either policy statement to pending applications or applications filed before the FERC issues any final guidance on the policy statements. The FERC has not yet issued final guidance on the policy statements.
Pipeline Safety
Our gas pipelines are subject to the Natural Gas Pipeline Safety Act of 1968, as amended, the Pipeline Safety Improvement Act of 2002, the Pipeline Safety, Regulatory Certainty, and Jobs Creation Act of 2011, 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.
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The United States Department of Transportation Pipeline and Hazardous Materials Safety Administration (PHMSA) administers federal pipeline safety laws.
Federal pipeline safety laws authorize PHMSA to establish minimum safety standards for pipeline facilities and persons engaged in the transportation of gas or hazardous liquids by pipeline. These safety standards apply to the design, construction, testing, operation, and maintenance of gas and hazardous liquids pipeline facilities affecting interstate or foreign commerce. PHMSA has also established reporting requirements for operators of gas and hazardous liquid pipeline facilities, as well as provisions for establishing the qualification of pipeline personnel and requirements for managing the integrity of gas transmission and distribution lines and certain hazardous liquid pipelines. To ensure compliance with these provisions, PHMSA performs pipeline safety inspections and has the authority to initiate enforcement actions.
In August 2022, PHMSA published Rule 2, which is the last in the three part Mega Rule set of regulations. Rule 2 went into effect in May 2023, but a Stay of Enforcement until February 2024 limited the amount of the regulation that was implemented. Rule 2 contains new corrosion control requirements, new requirements for repair criteria outside of high consequence areas (HCAs), inspections to be performed after extreme weather events or natural disasters, management of change, and other integrity management related rule changes. Since the rule was published in 2022, we have worked to understand the regulatory changes and modify our procedures as needed. In total, we have modified more than 20 Williams procedures and forms to account for the Rule 2 changes. All procedures will be in effect when the February 2024 Stay of Enforcement expires.
In May 2023, PHMSA published the Gas Pipeline Leak Detection and Repair Notice of Proposed Rule Making (NPRM). While this regulation has not been published as final and is still subject to change, the rule could institute many new requirements including: increased survey and patrol frequencies, new timelines for repairing and mitigating leaks, strict performance standards for advanced leak detection programs, and other additional requirements focused on reducing methane emissions. We have been actively working to provide comments on the rule and are working to understand the overall impact if implemented as currently written.
Pipeline Integrity Regulations
We have an enterprise-wide Gas Integrity Management Plan that meets the PHMSA final rule that was issued pursuant to the requirements of the Pipeline Safety Improvement Act of 2002. The rules require gas pipeline operators to develop an integrity management program for pipelines that could affect HCAs in the event of pipeline failure. The integrity management program includes a baseline assessment plan along with periodic reassessments to be completed within required time frames. In meeting the integrity regulations, we have identified HCAs and developed baseline assessment plans. Ongoing periodic reassessments and initial assessments of any new HCAs have been completed. Also, in response to the portion of the Mega Rule implemented in 2021, we have identified Moderate Consequence Areas, and Class 3 and 4 pipeline locations required by the rule and integrated those segments into our integrity program, and have begun scheduling required assessments and reassessments as needed to meet the regulatory timelines. We estimate that the cost to be incurred in 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.
We have an enterprise-wide Liquid Integrity Management Plan that we believe meets the PHMSA final rule that was issued pursuant to the requirements of the Pipeline Safety Improvement Act of 2002. The rule requires liquid pipeline operators to develop an integrity management program for liquid transmission pipelines that could affect HCAs in the event of pipeline failure. The integrity management program includes a baseline assessment plan along with periodic reassessments expected to be completed within required time frames. In meeting the integrity regulations, we utilized government defined HCAs and developed baseline assessment plans. We completed assessments within the required time frames. 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. Management considers the costs associated with compliance with the rule to be prudent costs incurred in the ordinary course of business.
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Cybersecurity Matters
The Transportation Security Administration (TSA) issued Security Directive Pipeline-2021-01B (Security Directive 1B) on May 29, 2022, which requires that owners/operators of critical pipelines (1) report cybersecurity incidents to the Cybersecurity and Infrastructure Agency (CISA) within 24 hours; (2) appoint a cybersecurity coordinator to coordinate with TSA and CISA; and (3) conduct a self-assessment of cybersecurity practices, identify any gaps, and develop a plan and timeline for remediation. On July 27, 2022, the TSA issued Security Directive Pipeline-2021-02C (Security Directive 2C), which requires owners/operators of critical pipelines to (1) establish and implement a TSA-approved Cybersecurity Implementation Plan that describes the specific cybersecurity measures employed and the schedule for achieving the cybersecurity outcomes described in Security Directive 2C; (2) develop and maintain a Cybersecurity Incident Response Plan to reduce the risk of operational disruption or other significant impacts from a cybersecurity incident; and (3) establish a Cybersecurity Assessment Program and submit an annual plan describing how the effectiveness of cybersecurity measures will be assessed. We have established and received TSA approval for our Cybersecurity Implementation Plan and are compliant with the remaining requirements established in Security Directives 1B and 2C. New regulations or security directives issued by TSA may impose additional requirements applicable to our cybersecurity program, which could cause us to incur increased capital and operating costs and operational delays.
See Part I, Item 1A. “Risk Factors” — “A breach of our information technology infrastructure, including a breach caused by a cybersecurity attack on us or third parties with whom we are interconnected, may interfere with the safe operation of our assets, result in the disclosure of personal or proprietary information, and harm our reputation.”
State Gathering Regulations
Our onshore midstream gathering operations are subject to laws and regulations in the various states in which we operate. For example, the Texas Railroad Commission has the authority to regulate the terms of service for our intrastate natural gas gathering business in Texas. Although the applicable state regulations vary widely, they generally require that pipeline rates and practices be reasonable and nondiscriminatory, and may include provisions covering marketing, pricing, pollution, environment, and human health and safety. Some states, such as New York and Ohio, have specific regulations pertaining to the design, construction, and operations of gathering lines within such state.
Intrastate Liquids Pipelines in the Gulf Coast
Our intrastate liquids pipelines in the Gulf Coast are regulated by the Louisiana Department of Natural Resources, the Texas Railroad Commission, and various other state and federal agencies. These pipelines are also subject to the liquid pipeline safety and integrity regulations discussed above since both Louisiana and Texas have adopted the integrity management regulations defined in PHMSA.
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. “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. ”
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ENVIRONMENTAL MATTERS
Our operations are subject to federal environmental laws and regulations as well as the state, local, and tribal laws and regulations adopted by the jurisdictions in which we operate. We could incur liability to governments or third parties for any unlawful discharge of pollutants into the air, soil, or water, as well as liability for cleanup costs. Materials could be released into the environment in several ways including, but not limited to:
• Leakage from gathering systems, underground gas storage caverns, pipelines, processing or treating facilities, transportation facilities, and storage tanks;
• Damage to facilities resulting from accidents during normal operations;
• Damages to onshore and offshore equipment and facilities resulting from storm events or natural disasters;
• Blowouts, cratering, and explosions.
In addition, we may be liable for environmental damage caused by former owners or operators of our properties.
We believe compliance with current environmental laws and regulations will not have a material adverse effect on our capital expenditures, earnings, or current competitive position. However, environmental laws and regulations could affect our business in various ways from time to time, including incurring capital and maintenance expenditures, fines and penalties, and creating the need to seek relief from the FERC for rate increases to recover the costs of certain capital expenditures and operation and maintenance expenses.
For additional information regarding the potential impact of federal, state, tribal, or local regulatory measures on our business and specific environmental issues, please refer to Part 1, Item 1A. “Risk Factors” — “Our operations are subject to environmental laws and regulations, including laws and regulations relating to climate change and greenhouse gas emissions, which may expose us to significant costs, liabilities, and expenditures that could exceed our expectations,” and Part II, Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Environmental” and “Environmental Matters” in Part II, Item 8. Financial Statements and Supplementary Data — Note 17 – Contingencies and Commitments.
COMPETITION
Our competitive strategy spans all our product and service offerings. We have a narrowed natural gas value chain focus that supports the exceptional reliability and quality services that are valued by our customers.
Gathering and Processing
Competition for natural gas gathering, processing, treating, transportation, and storage, as well as NGLs transportation, fractionation, and storage continues to increase as United States production continues to grow. Our midstream services compete with similar facilities that are in close proximity to our assets.
We face competition from companies of varying size and financial capabilities, including major and independent natural gas midstream providers, private equity firms, and major integrated oil and natural gas companies that gather, transport, process, fractionate, store, and market natural gas and NGLs, as well as some larger exploration and production companies that are choosing to develop midstream services to handle their own natural gas.
Our gathering and processing agreements are generally long-term agreements that may include acreage dedication. Competition for natural gas volumes is primarily based on reputation, 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. 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.
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Regulated Interstate Natural Gas Transportation and Storage
The market for supplying natural gas is highly competitive and new pipelines, storage facilities, and other related services are expanding to service the growing demand for natural gas. Additionally, pipeline capacity in many 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. 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.
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. 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.
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. However, we believe our past success in working with regulators and the public, the position of our existing infrastructure, established strategic long-term contracts, and the fact that our pipelines have numerous receipt and delivery points along our systems provide us a competitive advantage, especially along the eastern seaboard and northwestern United States.
Energy Management and Marketing Services
Our Gas & NGL Marketing Services segment competes with national and regional full-service energy providers, producers, and 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. “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.
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.
We encourage you to review our 2022 Sustainability Report available on our website for more information about our human capital programs and initiatives. Nothing on our website shall be deemed incorporated by reference into this Annual Report on Form 10-K.
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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. 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.
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. 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.
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.
Workforce Health, Engagement, and Development
Our employees are our most valued resource, are instrumental in our mission to safely deliver products that fuel the clean energy economy, and are the driving force behind our reputation as a safe, reliable company that does the right thing, every time. Cultivating a healthy work environment increases productivity and promotes long-term value creation.
We provide a comprehensive total rewards program that includes base salary, an annual incentive program, retirement benefits, and health benefits, including wellness and employee assistance programs. We provide employees with company-paid life insurance, disability coverage, and paid parental leave for both birth and non-birth parents, as well as adoption assistance. Our annual incentive program is a key component of our commitment to a performance culture focused on recognizing and rewarding high performance.
In order to attract and retain top talent, we create and are committed to maintaining a safe, inclusive workplace where employees feel valued, heard, respected, and supported in their personal and professional development. We utilize employee surveys and employee led advisory councils to ensure we understand the needs of the business from the perspective of our employees regarding engagement, development and inclusion. Additionally, we support employee engagement through formal programming including professional development, mentoring, and succession planning.
We provide comprehensive corporate and technical training programs that are agile and robust. These programs are designed to support the professional, skill, and technological development of our employees, which in turn creates a competitive advantage for our business. We are committed to adding long-term value to our business by investing in our employees’ growth and development. In addition to our internal development programming, we also support external development opportunities to further enhance our employees’ professional and technical skills. Performance is measured considering both the achieved results associated with attaining annual goals and observable skills and behaviors based on our defined competencies that contribute to workplace effectiveness and career success. Including the defined competencies in our annual performance assessments illustrates our emphasis on, and commitment to, achieving results in the right way.
Additionally, we are committed to strengthening the communities where we operate through philanthropic giving and volunteerism. We support Science, Technology, Engineering, and Math education initiatives, environmental conservation, first responder efforts, and the work of United Way agencies across the United States.
The Compensation and Management Development Committee of our Board of Directors oversees executive compensation and equity-based compensation plans and the material risks associated with our compensation
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program, as well as the oversight elements of human capital management, including diversity and inclusion, and talent development.
Diversity & Inclusion
We are committed to creating an inclusive culture, where differences are embraced and employees feel valued, welcomed, appreciated, and compelled to reach their full potential. We believe that inclusion fosters innovation, collaboration, and drives business growth and long-term success. To create a culture of inclusion, we embrace, appreciate, and fully leverage the diversity within our teams, including gender, race and ethnicity, life experiences, thoughts, perspectives, and anything that makes us different from one another. We believe that incorporating our many differences into a team of people who are working toward the same goal gives us a competitive advantage.
To create space for employees to share personal experiences and perspectives, and to appreciate and celebrate what makes people different, we offer Employee Resource Groups (ERGs). These groups are employee-led and based on similar interests and experiences, represent diverse communities and their allies, and are open to everyone. ERG members participate in community events, volunteer, lend professional and personal support to one another, and promote inclusion across the company. They also have executive sponsors and provide input to the leadership team.
We are committed to helping all employees develop and succeed. We strive for diverse representation at all levels of the organization through our talent management practices and employee development programs, including required baseline diversity and inclusion training for all leaders across the company. Diversity metrics are reported monthly to our management team to enhance transparency and opportunities for improvement.
Our Diversity and Inclusion Council, which includes members of the executive officer team, organizational and operational leaders, and individual employees, promotes policies, practices, and procedures that support the growth of a high-performing workforce where all individuals can achieve their full potential. The council serves as the governing body over enterprise diversity and inclusion initiatives, including 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.
As of December 31, 2023, our Board of Directors includes 12 members, 11 of whom are independent members, 25 percent of whom are women, and 8.33 percent of whom are from an underrepresented race or ethnicity. As part of the director selection and nominating process, the Governance and Sustainability Committee annually assesses the Board’s diversity in areas such as expertise, geography, gender, race and ethnicity, and age. We strive to maintain a board of directors with diverse occupational and personal backgrounds.
WEBSITE ACCESS TO REPORTS AND OTHER INFORMATION
We file our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, proxy statements, and other documents electronically with the SEC under the Exchange Act.
Our Internet website is www.williams.com . We make available, free of charge, through the Investors tab of our Internet website our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8‑K, and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC. Our Corporate Governance Guidelines, Sustainability Report, Code of Ethics for Senior Officers, Board committee charters, and the Williams Code of Business Conduct are also available on our Internet website. We will also provide, free of charge, a copy of any of our corporate documents listed above upon written request to our Corporate Secretary, One Williams Center, Suite 4700, Tulsa, Oklahoma 74172.
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