What changed in this filing

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Item 1. Business

2023-02-27 compared with 2022-02-28 · 177 added, 140 removed, 394 unchanged (45% of the section changed)

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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 30,000 miles of pipelines, 29 processing facilities, 7 fractionation facilities, and approximately 23 million barrels of NGL storage capacity, and deliver natural gas that is used every day for clean-power generation, heating, and industrial use.

We own an interest in and operate over 33,000 miles of pipelines in 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 Salt Lake City, Utah;

Houston, Texas;

and Pittsburgh, Pennsylvania.

Our telephone number is 918-573-2000.

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).

Service Assets, Customers, and Contracts

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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.

Our interstate natural gas transmission businesses are fully contracted under long-term firm reservation contracts with high credit quality customers.

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 Pipeline’s three largest customers in 2021 accounted for approximately 26 percent and 52 percent, respectively, of their total operating revenues.

Additionally, we offer storage services and interruptible transportation services under shorter-term agreements.

Transco’s and Northwest

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

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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.

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

Prior to the organizational realignment described under the heading “Business Segments,” certain of our commodity marketing activities were presented within our West reporting segment, while those acquired in 2021 as part of our Sequent Acquisition, which includes the operations of Sequent Energy Management, L.P.

and Sequent Energy Canada, Corp.

acquired on July 1, 2021 (Sequent Acquisition), were reported within the Sequent segment.

Beginning in January 2022, our NGL and natural gas marketing services are now presented primarily within our Gas & NGL Marketing Services segment.

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 utilities, municipalities, power generators, and producers, and moves gas to markets through transportation and storage agreements on strategically positioned assets.

Our gas marketing business markets natural gas 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 with expansions into new markets.

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.

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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 Sequent’s derivative activities qualify as held for trading purposes, which requires net presentation in the Consolidated Statement of Income.

In addition, all of our natural gas marketing derivative activities qualify as held for trading purposes, which requires net presentation in 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.

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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.

However, the unrealized fair value measurement gains and losses are generally offset by valuation changes in the economic value of the underlying transportation and storage portfolio, which is not recognized until the underlying transportation and storage transaction occurs.

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.

Crude Oil Transportation and Production Handling Assets

Our crude oil transportation operations, which are presented in our Transmission & Gulf of Mexico segment as described under the heading “Business Segments,” earn revenues primarily from a combination of fixed-monthly fees, contractual fixed or variable fees applied to production volumes, and contributions in aid of construction (CIAC) arrangements.

Our 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.

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Transmission & Gulf of Mexico, Northeast G&P, West, and Gas & NGL Marketing Services.

Effective January 1, 2022, following an organizational realignment, our NGL and natural gas marketing services, previously reported within the West and former Sequent segments, are now all managed within the Gas & NGL Marketing Services segment.

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 and Northwest Pipeline, as well as natural gas gathering and processing and crude oil production handling and transportation assets in the Gulf Coast region, including a 51 percent interest in Gulfstar One (a consolidated variable interest entity), which is a proprietary floating production system, a 50 percent equity-method investment in Gulfstream, and a 60 percent equity-method investment in Discovery.

• Northeast G&P is comprised of our midstream gathering, processing, and fractionation businesses in the Marcellus Shale region primarily in Pennsylvania and New York, and the Utica Shale region of eastern Ohio, as well as a 65 percent interest in our Northeast JV (a consolidated variable interest entity) which operates in West Virginia, Ohio, and Pennsylvania, a 66 percent interest in Cardinal (a consolidated variable interest entity) 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, a wholly owned subsidiary that owns equity-method investments with an approximate average 66 percent interest in multiple gas gathering systems in the Marcellus Shale region.

• 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 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, and a 20 percent equity-method investment in Targa Train 7.

• Gas & NGL Marketing Services includes our NGL and natural gas marketing services previously reported within the West segment prior to January 1, 2022, as well as the operations acquired on July 1, 2021 through our Sequent Acquisition.

• Other includes our upstream operations and minor business activities that are not reportable segments, as well as corporate operations.

• 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.

• 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, which along with Item 8.

Financial Statements and Supplementary Data, continues to present our segments as they were historically defined before the organizational realignment on January 1, 2022.

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, 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 Texas, Louisiana, Mississippi, and Alabama.

This segment also includes various petrochemical and feedstock pipelines in the Gulf Coast region.

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

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 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, 2021, Transco’s system had a system-wide delivery capacity totaling approximately 18.6 MMdth/d.

During 2021, Transco completed two fully-contracted expansions, which added more than 0.5 MMdth/d interim firm transportation capacity to the pipeline.

In addition, we added more than 0.1 MMdth/d of interim firm transportation capacity to our pipeline which will continue until the Regional Energy Access expansion project is placed in service, please refer to Part II, Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Company Outlook.” Transco’s system includes 59 compressor stations, four underground storage fields, and one LNG storage facility.

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.

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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 194 MMdth of natural gas.

At December 31, 2021, Transco’s customers had stored in its facilities approximately 140 MMdth 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.

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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, 2021, Northwest Pipeline’s system had long-term firm transportation and storage redelivery agreements with aggregate capacity reservations of approximately 3.8 MMdth/d.

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 and contracts with a third party for natural gas storage services in an underground storage reservoir in the Clay Basin field in Utah.

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 14.2 MMdth, which is substantially utilized for third-party natural gas.

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

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

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Offshore Natural Gas Pipelines

Pipeline Capacity Ownership

Location Miles (Bcf/d) Interest Supply Basins

Location Pipeline Miles Inlet Capacity (Bcf/d) Ownership Interest Supply Basins

Consolidated:

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Natural Gas Processing Facilities

Inlet Production

Capacity Capacity Ownership

Location (Bcf/d) (Mbbls/d) Interest Supply Basins

Location Inlet Capacity (Bcf/d) NGL Production Capacity (Mbbls/d) Ownership Interest Supply Basins

Consolidated:

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Coden, AL 0.7 35 100% Eastern Gulf of Mexico

NorTex Jack Co., TX 0.1 13 100% Barnett Shale

Non-consolidated:

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Crude Oil Pipelines

Pipeline Capacity Ownership

Miles (Mbbls/d) Interest Supply Basins

Pipeline Miles Capacity (Mbbls/d) Ownership Interest Supply Basins

Consolidated:

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Production Handling Platforms

Gas Inlet Handling

Capacity Capacity Ownership

(MMcf/d) (Mbbls/d) Interest Supply Basins

Gas Inlet Capacity (MMcf/d) Crude/NGL Handling Capacity (Mbbls/d) Ownership Interest Supply Basins

Consolidated:

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Consolidated:

Interstate natural gas pipeline throughput (Tbtu/d) 16.2 15.1 15.3

Interstate natural gas pipeline throughput (MMdth/d) (2) 16.9 16.2 15.1

Gathering volumes (Bcf/d) 0.29 0.28 0.25

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Non-consolidated:

Interstate natural gas pipeline throughput (Tbtu/d) 1.2 1.2 1.2

Interstate natural gas pipeline throughput (MMdth/d) (2) 1.3 1.2 1.2

Gathering volumes (Bcf/d) 0.40 0.35 0.30

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(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.

Certain Equity-Method Investments

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, through a subsidiary, a 50 percent equity-method investment in Gulfstream.

We own a 50 percent equity-method investment in Gulfstream.

We share operating responsibilities for Gulfstream with the other 50 percent owner.

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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:

The following tables summarize the significant operated assets of this segment and non-operated Blue Racer:

Natural Gas Gathering Assets

Pipeline Capacity Ownership

Location Miles (Bcf/d) Interest Supply Basins

Location Pipeline Miles Inlet Capacity (Bcf/d) Ownership Interest Supply Basins

Consolidated:

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Laurel Mountain Pennsylvania 1,145 0.9 69% Appalachian

Blue Racer Ohio & West Virginia 741 1.5 50% Appalachian

Natural Gas Processing Facilities

Inlet Production

Capacity Capacity Ownership

Location (Bcf/d) (Mbbls/d) Interest Supply Basins

Location Inlet Capacity (Bcf/d) NGL Production Capacity (Mbbls/d) Ownership Interest Supply Basins

Consolidated:

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Leesville Carroll Co., OH 0.2 18 65% Appalachian

Non-consolidated:

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.

(2) UEOM inlet capacity consists of 1.3 Bcf/d of a high pressure gathering pipeline that delivers Cardinal gathering volumes to UEOM processing facilities.

(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.

(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

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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 or rail.

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.

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Gathering volumes (Bcf/d) 6.61 6.79 6.16

(1) 2020 amount has been updated to reflect revised NGL production.

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.

Acquisition of UEOM and formation of Northeast JV

As of December 31, 2018, we owned a 62 percent interest in UEOM which we accounted for as an equity-method investment.

On March 18, 2019, we signed and closed the acquisition of the remaining 38 percent interest in UEOM.

As a result of acquiring this additional interest, we obtained control of and consolidated UEOM.

(See Note 3 – Acquisitions of Notes to Consolidated Financial Statements).

In June 2019, we contributed our consolidated interests in UEOM and our Ohio Valley midstream business to a newly formed partnership, and we retained 65 percent ownership of, as well as operate and consolidate, the Northeast JV business.

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 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.

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.

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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.

We own a 50 percent interest in Blue Racer which is operated by Blue Racer Midstream Holdings, LLC.

Additionally, certain Laurel Mountain agreements have MVCs.

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.

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Eagle Ford Shale Texas 1,251 0.5 100% Eagle Ford Shale

Haynesville Shale Louisiana 648 1.8 100% Haynesville Shale

Haynesville Shale (1) Louisiana & Texas 929 4.7 100% Haynesville Shale, Bossier Shale

Permian Texas 112 0.1 100% Permian

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Natural Gas Processing Facilities

Inlet Production

Capacity Capacity Ownership

Location (Bcf/d) (Mbbls/d) Interest Supply Basins

Location Inlet Capacity (Bcf/d) NGL Production Capacity (Mbbls/d) Ownership Interest Supply Basins

Consolidated:

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Non-consolidated:

Fort Lupton Colorado 0.3 50 50% Denver-Julesburg

Keenesburg I Colorado 0.2 40 50% Denver-Julesburg

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.

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________________

(1) Includes 100 percent of the volumes associated with operated equity-method investments, including RMM and Jackalope.

Jackalope was sold effective second-quarter 2019.

(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.

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

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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, which was placed into service in the first quarter of 2020.

Belvieu, Texas, fractionation train.

Gas & NGL Marketing Services

On July 1, 2021, we completed the Sequent Acquisition which is part of our new Gas & NGL Marketing Services business segment.

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 utilities, municipalities, power generators, and producers and markets natural gas from the production at our upstream properties.

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.

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2022 2021 2020

(Annual Average Amounts)

Sales Volumes:

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________________

(1) Average volumes over the period we owned the operations.

(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.

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

(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

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Each of our gas pipeline companies holds certificates of public convenience and necessity issued by the FERC authorizing ownership and operation of all pipelines, facilities, and properties for which certificates are required under the NGA.

FERC Standards of Conduct govern how our interstate pipelines communicate and do business with gas marketing employees.

Among other things, the Standards of Conduct require that interstate gas pipelines not operate their systems to preferentially benefit gas marketing functions.

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.

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Our intrastate natural gas liquids pipelines providing common carrier service are subject to regulation by various state regulatory agencies.

FERC Updates Certificate Policy Statement and Issues Interim Greenhouse Gas (GHG) Policy Statement

On February 18, 2022, 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 FERC will apply in pending and future certificate proceedings.

This policy statement provides an analytical framework for how FERC will consider whether a project is in the public convenience and necessity and explains that 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 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.

FERC also seeks comment on all aspects of the interim policy statement, including the approach to assessing the significance of the proposed project’s contribution to climate change.

While the guidance is subject to revision based on the comments received, FERC will begin applying the framework established in this policy statement to pending cases.

Updated Certificate Policy Statement and Interim Greenhouse Gas (GHG) Policy Statement

On February 18, 2022, the FERC issued two policy statements providing guidance for its pending and future consideration of interstate natural gas pipeline projects.

The first policy statement is an Updated Certificate Policy Statement, which provides an analytical framework for how the FERC will consider whether a project is in the public convenience and necessity and explains that the FERC will consider all impacts of a proposed project, including economic and environmental impacts, together.

The second policy statement is an Interim GHG Policy Statement, which sets forth how the FERC will assess the impacts of natural gas infrastructure projects on climate change in its reviews under the National Environmental Policy Act and the NGA.

The FERC sought comment on all aspects of the policy statements, including the approach to assessing the significance of the proposed project’s contribution to climate change.

On March 24, 2022, the FERC issued an order converting the Updated Certificate Policy Statement and the Interim GHG Policy Statement into draft policy statements and announcing that it will not apply either policy statement to pending applications or applications filed before the FERC issues any final guidance on the policy statements.

The FERC has not yet issued final guidance on the policy statements.

Pipeline Safety

Our gas pipelines are subject to the Natural Gas Pipeline Safety Act of 1968, as amended, the Pipeline Safety Improvement Act of 2002, the Pipeline Safety, Regulatory Certainty, and Jobs Creation Act of 2011 (Pipeline Safety Act), and the Protecting Our Infrastructure of Pipelines and Enhancing Safety Act (PIPES Act) of 2016 and 2020, which regulate safety requirements in the design, construction, operation, and maintenance of interstate natural gas transmission facilities.

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.

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To ensure compliance with these provisions, PHMSA performs pipeline safety inspections and has the authority to initiate enforcement actions.

In October 2019, PHMSA published a final rulemaking imposing new or more stringent requirements for certain natural gas pipelines including, expanding certain of PHMSA’s current regulatory safety programs for natural gas lines in high-population areas (also known as moderate consequence areas (MCAs)) that do not qualify as high-consequence areas (HCAs) and requiring maximum allowable operating pressure (MAOP) validation through re-verification of all historical records for pipelines in service, which may require natural gas pipelines installed before 1970 (previously excluded from certain pressure testing obligations) to be pressure tested.

PHMSA split this rule (Mega Rule), into three separate rulemaking proceedings.

The first of these three rulemakings, relating to onshore gas transmission pipelines, imposes numerous requirements, including MAOP reconfirmation, material and component verification, the periodic assessment of additional pipeline mileage outside of HCAs, the reporting of exceedances of MAOP, and the consideration of seismicity as a risk factor in integrity management.

of these three rulemakings contains new repair requirements for HCAs and non-HCAs, and requires operators to inspect pipelines within 72 hours of extreme weather events or natural disasters.

Operators will have to install or enhance leak detection systems, and make modifications to their pipeline systems to accommodate inline inspection tools.

The third of these three rulemakings provides PHMSA with the authority to issue emergency orders to address imminent hazards, such as unsafe conditions or faulty components used on pipes.

In accordance with the final rule, we have developed new procedures and updated our existing pipeline safety program to facilitate meeting all requirements within the time frames stated.

We are also expecting additional regulations due to the PIPES Act of 2020 that became law in December 2020.

The PIPES Act of 2020 reauthorized PHMSA’s pipeline safety program through September 2023.

The new legislation includes mandates for PHMSA to publish final rules for advanced leak detection for gas pipelines, additional repair criteria for gas and hazardous liquids pipelines, updated operating and maintenance standards requirements applicable to large-scale liquefied natural gas facilities, and certain coastal waters and coastal beaches to be designated as unusually sensitive areas ecological resources for purposes of determining whether a hazardous liquid pipeline is in a high consequence area.

In November 2021, in accordance with the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011, PHMSA issued a final rule for onshore gas gathering pipelines.

All gas gathering pipelines, including previously unregulated pipelines, will be subject to PHMSA’s annual and incident reporting requirements.

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.

The rule adds 400,000 miles of gas gathering lines under PHMSA jurisdiction, including approximately 5,400 miles and 4,500 miles of our regulated and unregulated pipelines, respectively.

New regulations adopted by PHMSA may impose more stringent requirements applicable to integrity management programs and other pipeline safety aspects of our operations, which could cause us to incur increased capital and operating costs and operational delays.

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 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 gas pipeline operators to develop an integrity management program for gas transmission pipelines that could affect HCAs in the event of pipeline failure.

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.

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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.

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Cybersecurity Matters

The Transportation Security Administration (TSA) issued Security Directive Pipeline-2021-01 (Security Directive 1) on May 26, 2021, which required that owners/operators of critical pipelines to (1) report cybersecurity incidents to the Cybersecurity and Infrastructure Agency (CISA) within 12 hours;

(2) appoints a cybersecurity coordinator to coordinate with TSA and CISA;

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.

We fully complied with the requirements of Security Directive 1 within the timeframe required.

On July 19, 2021, the TSA issued Security Directive Pipeline-2021-02 (Security Directive 2), which required owners/operators of critical pipelines to implement additional cybersecurity measures to prevent disruption and degradation to their infrastructure in response to a purported ongoing threat.

We have evaluated the impacts of Security Directive 2 and made significant progress towards compliance.

We are coordinating with the TSA to establish action plans and timelines to remain in compliance with Security Directive 2.

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.

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Gathering and Processing

Competition for natural gas gathering, processing, treating, transporting, and storing natural gas as well as NGLs transportation, fractionation, and storage continues to increase as production from shales and other resource areas continues to grow.

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.

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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.

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.

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HUMAN CAPITAL RESOURCES

We are committed to maintaining an 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.

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.

As of February 1, 2023, we had 5,043 full-time employees located throughout the United States.

Of this total, approximately 21 percent are women and more than 16 percent are ethnically diverse.

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 references into this Annual Report on Form 10-K.

Nothing on our website shall be deemed incorporated by reference into this Annual Report on Form 10-K.

Workforce Safety

We continue to advance our safety-first culture by developing and empowering our employees to operate our assets in a safe, reliable, and customer-focused way.

We strive to continuously improve safety and achieve better performance than the industry benchmark.

When a safety hazard is recognized, every employee is empowered to stop work activities and make it right.

For 2020 and 2021, safety and environmental-focused goals and related metrics comprise 10 percent of our annual incentive program for employees, providing an increased focus on activities that help us meet enterprise safety commitments.

For 2020 and 2021, these metrics include our High Potential Near Miss to Incident Ratio, emphasizing our safety focus on high potential hazard recognition and reinforcing the importance of incident prevention, and our environmental metric Loss of Primary Containment, focused on reducing greenhouse gases and considered a leading indicator to more significant process safety incidents.

For 2021, both our high potential near miss to incident ratio and loss of primary containment events exceeded their respective established targets.

For 2022, in addition to the above, we added a third goal related to methane emission reductions.

These three goals now comprise 15 percent of our annual incentive program for employees.

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

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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.

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 offer robust corporate and technical training programs to support the professional development of our employees and add long-term value to our business.

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.

In response to the ongoing impact of coronavirus, including its variants (COVID-19), we took action to safeguard the health and safety of our employees, including allowing our employees to work remotely where possible, while implementing safety guidance and best practices designed to protect the health of those entering our facilities.

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 diverse differences are embraced and employees feel valued, welcomed, appreciated, and compelled to reach their full potential.

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.

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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.

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.

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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 identify trends and opportunities for improvement.

Our Diversity and Inclusion Council - chaired by our chief executive officer and including 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.

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, 2021, our Board of Directors includes 12 members, 11 of whom are independent members and approximately one-quarter of which are women.

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.

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What changed 10-K

Item 1. Business