WILLIAMS COMPANIES, INC. 10-K

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 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 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 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). 5 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 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. 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. 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, 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 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, 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. 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 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. 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 market natural gas and NGL products to a wide range of users in the energy and petrochemical industries. In 2022, our three largest natural gas marketing customers accounted for approximately 12 percent of our gross natural gas marketing sales, and our three largest NGL marketing customers accounted for approximately 42 percent of our NGL marketing sales. 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 pipeline agreements connect with multiple pipelines that provide our customers with access to diverse sources of supply and various natural gas markets. The southeastern market served by our Gas & NGL Marketing Services segment is the fastest growing natural gas demand region in the United States and expands our natural gas marketing activities, as well as optimizes our pipeline and storage capabilities. 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 the 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 RMM and Discovery. 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 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. 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. 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, 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. 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. 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 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 This segment includes the Transco interstate natural gas pipeline that extends from the Gulf of Mexico to the eastern seaboard, the Northwest Pipeline interstate natural gas pipeline, the MountainWest interstate natural gas pipeline, as well as natural gas gathering, processing and treating, crude oil production handling, and NGL fractionation assets within the onshore, offshore shelf, and deepwater areas in and around the Gulf Coast states of 9 Texas, Louisiana, Mississippi, and Alabama. This segment also includes various petrochemical and feedstock pipelines in the Gulf Coast region and natural gas pipelines and storage facilities located in north Texas. 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. 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. 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. 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. 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 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 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’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. 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. 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. 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 pipeline company that owns and operates an approximately 2,000-mile natural gas pipeline system and provides transportation and underground natural gas storage services in Utah, Wyoming, and Colorado. At February 14, 2023, the MountainWest system had a design capacity totaling 8.0 MMdth/d. The system is located in the Rocky Mountains near six producing areas, including the Greater Green 10 River, Uinta, and Piceance basins. MountainWest also owns and operates 56 Bcf of natural gas storage capacity, including the Clay basin underground storage reservoir in Utah. 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. 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. 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. (2) Includes 100 percent of the statistics associated with operated equity-method investments. Transmission & Gulf of Mexico Operating Statistics 2022 2021 2020 (Annual Average Amounts) Consolidated: Interstate natural gas pipeline throughput (MMdth/d) (2) 16.9 16.2 15.1 Gathering volumes (Bcf/d) 0.29 0.28 0.25 Plant inlet natural gas volumes (Bcf/d) 0.47 0.45 0.48 NGL production (Mbbls/d) 28 29 29 NGL equity sales (Mbbls/d) 6 6 5 Crude oil transportation (Mbbls/d) 119 134 121 Non-consolidated: (1) Interstate natural gas pipeline throughput (MMdth/d) (2) 1.3 1.2 1.2 Gathering volumes (Bcf/d) 0.40 0.35 0.30 Plant inlet natural gas volumes (Bcf/d) 0.40 0.35 0.30 NGL production (Mbbls/d) 28 27 21 NGL equity sales (Mbbls/d) 8 8 6 _____________ (1) Includes 100 percent of the volumes associated with operated equity-method investments. (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. 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. 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 also include a crude oil production handling platform with capacity of 10 Mbbls/d and gas handling and separation capacity of 75 MMcf/d. Northeast G&P 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. 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. 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 and non-operated Blue Racer. (4) Natural gas processing facilities owned by non-operated Blue Racer. 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 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. Northeast G&P Operating Statistics 2022 2021 2020 (Annual Average Amounts) Consolidated: Gathering volumes (Bcf/d) 4.19 4.24 4.31 Plant inlet natural gas volumes (Bcf/d) 1.65 1.57 1.32 NGL production (Mbbls/d) 120 115 103 NGL equity sales (Mbbls/d) 1 1 2 Non-consolidated: (1) Gathering volumes (Bcf/d) 6.61 6.79 6.16 Plant inlet natural gas volumes (Bcf/d) 0.71 0.82 0.95 NGL production (Mbbls/d) 51 56 65 NGL equity sales (Mbbls/d) 3 6 6 __________ (1) Includes 100 percent of the volumes associated with operated equity-method investments, including the Laurel Mountain Midstream partnership; and the Bradford Supply Hub and the Marcellus South Supply Hub within Appalachia Midstream Investments. Periods after November 18, 2020, have been updated to include non-operated Blue Racer volumes. Further, the amounts for Blue Racer presented for 2020 are averages for the 44 days over which we included Blue Racer, not averages over the entire year. 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. 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. 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 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). BRMH (previously named Caiman Energy II, LLC), a former equity-method investment, is a consolidated entity following our acquisition of a controlling interest in November 2020 and the remaining interest in September 2021. BRMH’s primary asset is a 50 percent interest in Blue Racer, accounted for as an equity-method investment. 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 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. 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 2,265 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. (2) Includes 100 percent of the statistics associated with operated equity-method investments. 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. 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. Further, the amounts for the acquired assets presented for 2022 are averaged over the period owned, not over the entire year. (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. The purpose of this acquisition was to expand our footprint into the east Texas area of the Haynesville Shale region, increasing in-basin scale. 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 Denver-Julesberg 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 our RMM equity-method investment are also transported on OPPL. Rocky Mountain Midstream We operate and own a 50 percent interest in RMM. RMM includes a natural gas gathering pipeline, an approximate 100-mile crude oil transportation pipeline, and natural gas processing assets in Colorado’s Denver-Julesburg basin. It also includes crude oil storage and compression assets. 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. 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 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 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. Further, the amounts for the acquired assets presented for 2021 are averaged over the period owned, not over the entire year. (2) 2021 amounts have been updated to reflect revised natural gas and NGL volumes. 2020 amounts have been updated to reflect revised NGL volumes. 17 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. When a certain drilling hurdle is met, the third party’s interest in new wells increases to 75 percent. The third party met this drilling hurdle in early 2023. We retain ownership in the undeveloped acreage until a separate acreage earning hurdle is met, at which time remaining undeveloped acreage will be conveyed to the third party resulting in the third party owning 75 percent and us owning 25 percent. Operating Statistics 2022 2021 (Annual Average Amounts) Net Product Sales Volumes: Natural Gas (Bcf/d) 0.22 0.13 NGLs (Mbbls/d) 7 6 Crude Oil (Mbbls/d) 2 2 New Energy Ventures Our Other segment also includes investments in new energy ventures related to hydrogen, solar, renewable natural gas, and NextGen Gas. NextGen Gas is natural gas that has been independently certified as low emissions gas across all segments of the value chain. REGULATORY MATTERS FERC Our gas pipeline interstate transmission and storage activities are subject to FERC regulation under the Natural Gas Act of 1938 (NGA) and under the Natural Gas Policy Act of 1978, and, as such, our rates and charges for the transportation of natural gas in interstate commerce, accounting, and the extension, enlargement, or abandonment of our jurisdictional facilities, among other things, are subject to regulation. Each of our gas pipeline companies holds certificates of public convenience and necessity issued by the FERC authorizing ownership and operation of all pipelines, facilities, and properties for which certificates are required under the NGA. FERC Standards of Conduct govern how our interstate pipelines communicate and 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. 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. 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. 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. 19 In October 2019, PHMSA published the first of three rules that would be a part of the Mega Rule. The Mega Rule was more than 10 years in the making and since October 2019, PHMSA has also published Rules 2 and 3 as a part of the Mega Rule implementation. At the end of 2021, PHMSA published Rule 3 of the Mega Rule with an implementation date in May 2022. Rule 3 was also called The Gas Gathering Rule and expanded Federal Pipeline Safety oversight to more than 400,000 miles of pipeline across all operators, including approximately 5,400 miles and 4,500 miles of our regulated and unregulated pipelines, respectively. The rule established Federal pipeline safety oversight on previously unregulated gas gathering pipelines. The rule limits the use of “incidental gathering pipelines” to 10 miles in length or less. The rule also creates a new category of regulated gas gathering pipelines that are located in rural locations and will be subject to certain reporting and safety standards. New regulations in Rule 3 include requirements for public awareness, emergency response, damage prevention, incident notification, and annual reporting. As a result of the rule, we revised numerous procedures and are now reporting based on the expanded scope as required by regulation. In August 2022, PHMSA published Rule 2, which is the last in the three part Mega Rule set of regulations. Certain portions of Rule 2 go into effect in May 2023 with the remaining portions taking effect in February 2024. Rule 2 contains new corrosion control requirements, new requirements for repair criteria outside of high consequence areas (HCAs), inspections to be performed after extreme weather events or natural disasters, management of change, and other integrity management related rule changes. We are evaluating procedures that will need to be updated to maintain compliance and are also analyzing anticipated cost impacts. PHMSA’s new rule, Requirement of Valve Installation and Minimum Rupture Detection Standards, went into effect in October 2022. The rupture monitoring and emergency response standards are applicable to existing pipelines, but the installation of rupture mitigation valves (RMVs) is not retroactive and only applies to new pipelines and significant pipeline replacements. This new rule establishes criteria for how operators must monitor and respond to potential ruptures on their system. It also outlines requirements for the installation of RMVs or Alternative Equivalent Technology to allow for quicker isolation after an incident has occurred. In response to the new regulation, Williams has updated all applicable procedures and is developing implementation plans as a result of the rulemaking. 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 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 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 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. 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. 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. 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. “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. 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 – Contingent Liabilities and Commitments of Notes to Consolidated Financial Statements. COMPETITION 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 production from shales and other resource areas continues to grow. Our midstream services compete with similar facilities that are in the same proximity as our assets. We face competition from companies of varying size and financial capabilities, including major and independent natural gas midstream providers, private equity firms, and major integrated oil and natural gas companies that gather, transport, process, fractionate, store, and market natural gas and NGLs, as well as some larger exploration and production companies that are choosing to develop midstream services to handle their own natural gas. Our gathering and processing agreements are generally long-term agreements that may include acreage dedication. Competition for natural gas volumes is primarily based on reputation, commercial terms (products retained or fees charged), array of services provided, efficiency and reliability of services, location of gathering facilities, available capacity, downstream interconnects, and latent capacity. We believe our significant presence in traditional prolific supply basins, our solid positions in growing shale plays, our expertise and reputation as a reliable operator, and our ability to offer integrated packages of services position us well against our competition. 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. Additionally, pipeline capacity in many growing natural gas supply basins is constrained causing competition to increase among pipeline companies as they strive to connect those basins to major natural gas demand centers. In our business, we predominately compete with major intrastate and interstate natural gas pipelines. In the last few years, local distribution companies have also started entering into the long-haul transportation business through joint venture pipelines. The principle elements of competition in the interstate natural gas pipeline business are based on capacity available, rates, reliability, quality of customer service, diversity of supply, and proximity to customers and market hubs. We face competition in a number of our key markets and we compete with other interstate and intrastate pipelines for deliveries to customers who can take deliveries at multiple points. Natural gas delivered on our system competes with alternative energy sources used to generate electricity such as hydroelectric power, coal, fuel oil, and nuclear. Future demand for natural gas within the power sector could be increased by regulations limiting or discouraging coal use or could be adversely affected by laws mandating or encouraging renewable power sources. Significant entrance barriers to build new pipelines exist, including federal and growing state regulations and public opposition against new pipeline builds, and these factors will continue to impact potential competition for the foreseeable future. However, we believe our past success in working with regulators and the public, the position of our existing infrastructure, established strategic long-term contracts, and the fact that our pipelines have numerous receipt and delivery points along our systems provide us a competitive advantage, especially along the eastern seaboard and northwestern United States. Energy Management and Marketing Services Our Gas & NGL Marketing Services segment competes with national and regional full-service energy providers, producers, and pipelines marketing affiliates or other marketing companies that aggregate commodities with transportation and storage capacity. For additional information regarding competition for our services or otherwise affecting our business, please refer to Part 1, Item 1A. “Risk Factors” - “ The financial condition of our natural gas transportation and midstream businesses is dependent on the continued availability of natural gas supplies in the supply basins that we access and demand for those supplies in the markets we serve,” “ Our industry is highly competitive and increased competitive pressure could adversely affect our business and operating results ,” and “ We may not be able to replace, extend, or add additional customer contracts or contracted volumes on favorable terms, or at all, which could affect our financial condition, the amount of cash available to pay dividends, and our ability to grow. ” 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. 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. We encourage you to review our 2021 Sustainability Report available on our website for more information about our human capital programs and initiatives. Nothing on our website shall be deemed incorporated by reference into this Annual Report on Form 10-K. 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. When a safety hazard is recognized, every employee is empowered to stop work activities, make changes to enhance safety, and share the lessons learned with the organization on how we made it right. For 2021, safety and environmental-focused goals and related metrics comprised 10 percent of our annual incentive program for employees, and included our Loss of Primary Containment Events Reduction and High Potential Near Miss to Incident Ratio. For 2022, these goals included our Loss of Primary Containment Events Reduction, a new Behavioral Near Miss to Incident Ratio goal aimed to focus attention on behaviors that are the leading causes of incidents, as well as a new Methane Emissions Reduction goal focusing on our efforts to reduce greenhouse gas emissions. These three metrics comprise 15 percent of our annual incentive program for employees, and reinforce the importance of incident prevention and our commitment to environmental and safety-focused improvements. For 2022, our Behavioral Near Miss to Incident Ratio and Methane Emissions Reduction goals outperformed the established targets, and while Loss of Primary Containment Events were reduced, they fell short of the overall reduction target. Workforce Health, Engagement, and Development Our employees are our most valued resource, are instrumental in our mission to safely deliver products that fuel the clean energy economy, and are the driving force behind our reputation as a safe, reliable company that does the right thing, every time. Cultivating a healthy work environment increases productivity and promotes long-term value creation. We provide a comprehensive total rewards program that includes base salary, an all-employee annual incentive program, retirement benefits, and health benefits, including wellness and employee assistance programs. We provide employees with company-paid life insurance, disability coverage, and paid parental leave for both birth and non-birth parents, as well as adoption assistance. Our annual incentive program is a key component of our commitment to a performance culture focused on recognizing and rewarding high performance. In order to attract and retain top talent, we create and are committed to maintaining a safe, inclusive workplace where employees feel valued, heard, respected, and supported in their personal and professional development. Our Employee Development Council is a cross-functional, cross-enterprise advisory board that works to understand the needs of the business by providing input on, and advocating for, employee development initiatives. Additionally, we support strong employee engagement by encouraging open dialogue regarding professional development and succession planning. We offer robust corporate and technical training programs to support the professional development of our employees and add long-term value to our business. Our Learning and Training Council defines and maintains an agile governance structure that ensures training plans are effective and aligned to business needs and employee development. Performance is measured considering both the achieved results associated with attaining annual goals and observable skills and behaviors based on our defined competencies that contribute to workplace effectiveness and career success. Including the defined competencies in our annual performance program illustrates our emphasis on, and commitment to, achieving results in the right way. Additionally, we are committed to strengthening the communities where we operate through philanthropic giving and volunteerism. We support Science, Technology, Engineering, and Math education initiatives, environmental conservation and first responder efforts, and the work of United Way agencies across the United States. 24 The Compensation and Management Development Committee of our Board of Directors oversees the establishment and administration of our compensation programs, including incentive compensation and equity-based plans, as well as the oversight of human capital management, including diversity and inclusion, and development. Diversity & Inclusion We are committed to creating an inclusive culture, where differences are embraced and employees feel valued, welcomed, appreciated, and compelled to reach their full potential. We believe that inclusion fosters innovation, collaboration, and drives business growth and long-term success. To create a culture of inclusion, we embrace, appreciate, and fully leverage the diversity within our teams, including gender, race and ethnicity, life experiences, thoughts, perspectives, and anything that makes us different from one another. We believe that incorporating our many differences into a team of people who are working toward the same goal gives us a competitive advantage. To create space for employees to share personal experiences and perspectives, and to appreciate and celebrate what makes people different, we offer Employee Resource Groups (ERGs). These groups are employee-led and based on similar interests and experiences, represent diverse communities and their allies, and are open to everyone. ERG members participate in community events, volunteer, lend professional and personal support to one another, and promote inclusion across the company. They also provide input to the leadership team. We are committed to helping all employees develop and succeed. We strive for diverse representation at all levels of the organization through our talent management practices and employee development programs, including required baseline diversity and inclusion training for all leaders across the company. Diversity metrics are reported monthly to our management team to enhance transparency and opportunities for improvement. Our Diversity and Inclusion Council, which includes members of the executive officer team, organizational and operational leaders, and individual employees, promotes policies, practices, and procedures that support the growth of a high-performing workforce where all individuals can achieve their full potential. The council serves as the governing body over enterprise diversity and inclusion initiatives, including a quarterly candid conversation meeting for all employees, 10 active ERGs, and annual awards that recognize an outstanding leader and an individual contributor who champion inclusion. As of December 31, 2022, our Board of Directors includes 12 members, 11 of whom are independent members, and one-quarter of which are women. As part of the director selection and nominating process, the Governance and Sustainability Committee annually assesses the Board’s diversity in areas such as geography, gender, race and ethnicity, and age. We strive to maintain a board of directors with diverse occupational and personal backgrounds. WEBSITE ACCESS TO REPORTS AND OTHER INFORMATION We file our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, proxy statements, and other documents electronically with the SEC under the Exchange Act. Our Internet website is www.williams.com . We make available, free of charge, through the Investors tab of our Internet website our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8‑K, and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC. Our Corporate Governance Guidelines, Sustainability Report, Code of Ethics for Senior Officers, Board committee charters, and the Williams Code of Business Conduct are also available on our Internet website. We will also provide, free of charge, a copy of any of our corporate documents listed above upon written request to our Corporate Secretary, One Williams Center, Suite 4700, Tulsa, Oklahoma 74172. 25