Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

General

We are an energy company committed to being the leader in providing infrastructure that safely delivers natural gas products to reliably fuel the clean energy economy. Our operations are located in the United States.

Our interstate natural gas pipeline strategy is to create value by maximizing the utilization of our pipeline capacity by providing high quality, low cost transportation of natural gas to large and growing markets. Our gas pipeline businesses’ interstate transmission and storage activities are subject to regulation by the FERC and as such, our rates and charges for the transportation of natural gas in interstate commerce, and the extension, expansion or abandonment of jurisdictional facilities and accounting, among other things, are subject to regulation. The rates are established primarily through the FERC’s ratemaking process, but we also may negotiate rates with our customers pursuant to the terms of our tariffs and FERC policy. Changes in commodity prices and volumes transported have limited near-term impact on these revenues because the majority of cost of service is recovered through firm capacity reservation charges in transportation rates.

The ongoing strategy of our midstream operations is to safely and reliably operate large-scale midstream infrastructure where our assets can be fully utilized and drive low per-unit costs. We focus on consistently attracting new business by providing highly reliable service to our customers. These services include natural gas gathering, processing, treating, compression, and storage, NGL fractionation, transportation and storage, crude oil production handling and transportation, as well as marketing services for NGL, crude oil and natural gas.

Consistent with the manner in which our chief operating decision maker evaluates performance and allocates resources, our operations are conducted, managed, and presented within the following reportable segments: Transmission & Gulf of Mexico, Northeast G&P, West, and Gas & NGL Marketing Services. All remaining business activities, including our upstream operations and corporate activities, are included in Other. Our reportable segments are comprised of the following businesses:

• Transmission & Gulf of Mexico is comprised of our interstate natural gas pipelines and complimentary natural gas storage facilities within 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 VIE), 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 (a consolidated VIE) which operates in West Virginia, Ohio, and Pennsylvania, a 66 percent interest in Cardinal (a consolidated VIE) which operates in Ohio, a 69 percent equity-method investment in Laurel Mountain, a 50 percent equity-method investment in Blue Racer, and Appalachia Midstream Investments, 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 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, LLC.

Management’s Discussion and Analysis (Continued)			Table of Contents

• Gas & NGL Marketing Services includes our NGL and natural gas marketing and trading operations previously reported within the West segment prior to January 1, 2022, as well as the operations acquired in the Sequent Acquisition in 2021. This segment includes risk management and the storage and transportation of natural gas on strategically positioned assets, including our Transco system.

Dividends

In September 2022, we paid a regular quarterly dividend of $0.425 per share.

Overview of Nine Months Ended September 30, 2022

Net income (loss) attributable to The Williams Companies, Inc., for the nine months ended September 30, 2022, increased $485 million compared to the nine months ended September 30, 2021, reflecting the benefit of higher service revenues from commodity-based gathering and processing rates and higher gathering volumes, including from the Trace Acquisition in the West, as well as Transco’s Leidy South project placed in service in December 2021, higher results from our upstream operations associated with higher prices and increased scale of operations, higher commodity margins, higher equity earnings, and favorable interest expense due to debt retirements. These favorable impacts were partially offset by a $12 million unfavorable change in net unrealized loss on commodity derivatives, increased intangible asset amortization, the absence of a $77 million favorable impact in 2021 from Winter Storm Uri, higher operating and maintenance expenses, and higher selling, general, and administrative expenses, primarily resulting from the Sequent Acquisition. The tax provision benefited from the release of valuation allowances on deferred income tax assets and federal income tax settlements, as well as from a decrease in our estimated deferred state income tax rate.

Our results include a $12 million unfavorable change in net unrealized losses from commodity derivatives not designated as hedges for accounting purposes. We can 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 marketing 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 contracts, which is not recognized until the underlying transaction occurs.

The following discussion and analysis of results of operations and financial condition and liquidity should be read in conjunction with our consolidated financial statements and notes thereto of this Form 10‑Q and in Exhibit 99.1 of our Form 8-K dated May 2, 2022.

Recent Developments

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 for $972 million, subject to post-closing adjustments. The purpose of the Trace Acquisition was to expand our footprint into the east Texas area of the Haynesville Shale region, increasing in-basin scale in one of the largest growth basins in the country.

Purchase of North Texas Assets

On August 31, 2022, we purchased a group of assets in north Texas, primarily natural gas storage facilities and pipelines, from NorTex Midstream Holdings, LLC for approximately $424 million. These assets are included in the Transmission & Gulf of Mexico segment.

Northwest Pipeline FERC Rate Case Settlement Filing

On August 26, 2022, Northwest Pipeline filed a petition with the FERC for approval of a stipulation and settlement agreement, which establishes a new general system firm rate, to be effective January 1, 2023, resolves other rate issues, establishes a Modernization and Emission Reduction Program, and satisfies its rate case filing

Management’s Discussion and Analysis (Continued)			Table of Contents

obligation. Provisions were included in the settlement that a new rate case can be filed to be effective after January 1, 2026, and that a general rate case filing must be made for rates to become effective no later than April 1, 2028.

Company Outlook

Our strategy is to provide a large-scale, reliable, and clean energy infrastructure designed to maximize the opportunities created by the vast supply of natural gas and natural gas products that exists in the United States. We accomplish this by connecting the growing demand for cleaner fuels and feedstocks with our major positions in the premier natural gas and natural gas products supply basins. We continue to maintain a strong commitment to safety, environmental stewardship including seeking opportunities for renewable energy ventures, operational excellence, and customer satisfaction. We believe that accomplishing these goals will position us to deliver safe, reliable, clean energy services to our customers and an attractive return to our shareholders. Our business plan for 2022 includes a continued focus on earnings and cash flow growth.

In 2022, our operating results are expected to benefit from higher commodity prices and volume growth in our Haynesville and Ohio Valley Midstream areas. We also anticipate increases resulting from Transco expansion projects, development of our upstream oil and gas properties, and our recently completed Trace Acquisition. These increases are partially offset by the absence of favorable results captured during Winter Storm Uri in 2021 by our Gas & NGL Marketing Services business and lower expected results in the Bradford Supply Hub primarily due to lower gathering rates resulting from annual cost of service contract redeterminations.

We seek to maintain a strong financial position and liquidity, as well as manage a diversified portfolio of safe, clean, and reliable energy infrastructure assets that continue to serve key growth markets and supply basins in the United States. Our growth capital and investment expenditures in 2022 are expected to be in a range from $1.25 billion to $1.35 billion, which excludes approximately $1.5 billion in total acquisitions and follow-on expenditures for the Trace Acquisition and NorTex Asset Purchase. Growth capital spending in 2022, excluding the Trace Acquisition and NorTex Asset Purchase, primarily includes Transco expansions, all of which are fully contracted with firm transportation agreements, projects supporting the Northeast G&P business, and an expansion in the Western Gulf area. We also expect to invest capital in the development of our upstream oil and gas properties. In addition to growth capital and investment expenditures, we also remain committed to projects that maintain our assets for safe and reliable operations, as well as projects that meet legal, regulatory, and/or contractual commitments.

Potential risks and obstacles that could impact the execution of our plan include:

• Continued negative impacts of COVID-19 driving a global recession, which could result in downturns in financial markets and commodity prices, as well as impact demand for natural gas and related products;

• Opposition to, and regulations affecting, our infrastructure projects, including the risk of delay or denial in permits and approvals needed for our projects;

• Counterparty credit and performance risk;

• Unexpected significant increases in capital expenditures or delays in capital project execution, including delays caused by supply chain disruptions;

• Unexpected changes in customer drilling and production activities, which could negatively impact gathering and processing volumes;

• Lower than anticipated demand for natural gas and natural gas products which could result in lower than expected volumes, energy commodity prices, and margins;

• General economic, financial markets, or industry downturns, including increased inflation and interest rates;

Management’s Discussion and Analysis (Continued)			Table of Contents

• Physical damages to facilities, including damage to offshore facilities by weather-related events;

• Other risks set forth under Part I, Item 1A. Risk Factors in our Annual Report on Form 10-K for the year ended December 31, 2021, as filed with the SEC on February 28, 2022, as supplemented by disclosures in Part II, Item 1A. Risk Factors in subsequent Quarterly Reports on Form 10-Q.

Expansion Projects

Our ongoing major expansion projects include the following:

Transmission & Gulf of Mexico

Regional Energy Access

In March 2021, we filed an application with the FERC for the project to expand Transco’s existing natural gas transmission system to provide incremental firm transportation capacity from receipt points in northeastern Pennsylvania to multiple delivery points in Pennsylvania, New Jersey, and Maryland. We plan to place the project into service as early as the fourth quarter of 2024, assuming timely receipt of all necessary regulatory approvals. The project is expected to increase capacity by 829 Mdth/d.

Southside Reliability Enhancement

In May 2022, we filed an application with the FERC for the project, which is an incremental expansion of Transco’s existing natural gas transmission system to provide firm transportation capacity from receipt points in Virginia and North Carolina to delivery points in North Carolina. We plan to place the project into service as early as the 2024/2025 winter heating season assuming timely receipt of all necessary regulatory approvals. The project is expected to increase capacity by 423 Mdth/d.

Texas to Louisiana Energy Pathway

In August 2022, we filed an application with the FERC for the project, which involves an expansion of Transco’s existing natural gas transmission system to provide incremental firm transportation capacity from receipt points in south Texas to delivery points in Texas and Louisiana. We plan to place the project into service as early as the fourth quarter of 2025, assuming timely receipt of all necessary regulatory approvals. The project is expected to provide 364 Mdth/d of new firm transportation service through a combination of increasing capacity, converting interruptible capacity to firm, and utilizing existing capacity.

Southeast Energy Connector

In August 2022, we filed an application with the FERC for the project, which is an expansion of Transco’s existing natural gas transmission system to provide incremental firm transportation capacity from receipt points in Mississippi and Alabama to a delivery point in Alabama. We plan to place the project into service in the fourth quarter of 2025, assuming timely receipt of all necessary regulatory approvals. The project is expected to increase capacity by 150 Mdth/d.

Commonwealth Energy Connector

In August 2022, we filed an application with the FERC for the project, which involves an expansion of Transco’s existing natural gas transmission system to provide incremental firm transportation capacity in Virginia. We plan to place the project into service as early as the fourth quarter of 2025, assuming timely receipt of all necessary regulatory approvals. The project is expected to increase capacity by 105 Mdth/d.

Management’s Discussion and Analysis (Continued)			Table of Contents

West

Louisiana Energy Gateway

In June 2022, we announced our intention to construct new natural gas gathering assets which are expected to gather 1.8 Bcf/d of natural gas produced in the Haynesville Shale basin for delivery to premium markets, including Transco, industrial markets, and growing LNG export demand along the Gulf Coast. This project is expected to go into service in late 2024.

Management’s Discussion and Analysis (Continued)			Table of Contents

Results of Operations

Consolidated Overview

The following table and discussion is a summary of our consolidated results of operations for the three and nine months ended September 30, 2022, compared to the three and nine months ended September 30, 2021. The results of operations by segment are discussed in further detail following this consolidated overview discussion.

			Three Months Ended September 30,																								Nine Months Ended September 30,
			2022						2021						$ Change*						% Change*						2022						2021						$ Change*						% Change*
			(Millions)																								(Millions)
Revenues:
Service revenues			$	1,685					$	1,506					+179						+12		%				$	4,828					$	4,418					+410						+9		%
Service revenues – commodity consideration			60						64						-4						-6		%				223						164						+59						+36		%
Product sales			1,260						1,296						-36						-3		%				3,475						3,229						+246						+8		%
Net gain (loss) on commodity derivatives			16						(391)						+407						NM						(491)						(441)						-50						-11		%
Total revenues			3,021						2,475																		8,035						7,370
Costs and expenses:
Product costs			990						1,043						+53						+5		%				2,650						2,672						+22						+1		%
Net processing commodity expenses			29						28						-1						-4		%				99						67						-32						-48		%
Operating and maintenance expenses			486						409						-77						-19		%				1,345						1,148						-197						-17		%
Depreciation and amortization expenses			500						487						-13						-3		%				1,504						1,388						-116						-8		%
Selling, general, and administrative expenses			163						152						-11						-7		%				477						389						-88						-23		%
Other (income) expense – net			33						1						-32						NM						14						12						-2						-17		%
Total costs and expenses			2,201						2,120																		6,089						5,676
Operating income (loss)			820						355																		1,946						1,694
Equity earnings (losses)			193						157						+36						+23		%				492						423						+69						+16		%
Other investing income (loss) – net			1						2						-1						-50		%				4						6						-2						-33		%
Interest expense			(291)						(292)						+1						—		%				(858)						(884)						+26						+3		%
Other income (expense) – net			(6)						4						-10						NM						5						4						+1						+25		%
Income (loss) before income taxes			717						226																		1,589						1,243
Less: Provision (benefit) for income taxes			96						53						-43						-81		%				169						313						+144						+46		%
Net income (loss)			621						173																		1,420						930
Less: Net income (loss) attributable to noncontrolling interests			21						8						-13						-163		%				40						35						-5						-14		%
Net income (loss) attributable to The Williams Companies, Inc.			$	600					$	165																	$	1,380					$	895

• • = Favorable change; - = Unfavorable change; NM = A percentage calculation is not meaningful due to a change in signs, a zero-value denominator, or a percentage change greater than 200.

Management’s Discussion and Analysis (Continued)			Table of Contents

Three months ended September 30, 2022 vs. three months ended September 30, 2021

Service revenues increased primarily due to higher gathering rates driven by favorable commodity prices and annual contractual rate escalations for certain of our West and Northeast G&P operations, higher gathering volumes including from the Trace Acquisition, higher transportation fee revenues associated with the Leidy South expansion project placed fully in service at Transco in December 2021, and higher reimbursable electric power and storage costs, which are substantially offset in Operating and maintenance expenses.

Product sales decreased primarily due to the impact of netting the 2022 legacy natural gas marketing revenues with the associated costs (see Note 1 – General, Description of Business, and Basis of Presentation of Notes to Consolidated Financial Statements). As we are acting as agent for natural gas marketing customers of our Gas & NGL Marketing Services segment, our natural gas marketing product sales are presented net of the related costs of those activities including a 2022 lower of cost or net realizable value adjustment to our gas marketing storage inventory. Additional unfavorable impacts include lower marketing and equity NGL sales volumes. These decreases were substantially offset by higher marketing sales prices, higher sales prices and volumes associated with our upstream operations presented in our Other segment, higher sales prices related to our equity NGL sales, and higher other product sales.

Net gain (loss) on commodity derivatives includes realized and unrealized gains and losses from derivative instruments reflected within Total revenues. The favorable change primarily reflects a net gain related to derivative contracts in our Gas & NGL Marketing Services segment.

Product costs decreased primarily due to the impact of netting the 2022 legacy natural gas marketing revenues with the associated costs. This decrease was partially offset by higher prices, volumes, and lower of cost or net realizable value inventory adjustments in 2022 associated with our NGL marketing activities, higher NGL prices associated with volumes acquired as commodity consideration related to our equity NGL production activities, and higher other product costs.

The net sum of Service revenues – commodity consideration, Product sales, Product costs, net realized gains and losses on commodity derivatives related to sales of product, and net realized processing commodity expenses comprise our Commodity margins. However, Net realized product sales at our Other segment reflect sales of our upstream related production net of the associated realized gains and losses and are excluded from our Commodity Margins.

Operating and maintenance expenses increased primarily due to higher operating costs including higher reimbursable electric power and storage costs, which are substantially offset in Service revenues, higher expenses associated with our upstream operations, and increased costs associated with Transco's Leidy South expansion project placed in service in December 2021.

Depreciation and amortization expenses increased primarily due to amortization of intangibles acquired in the Sequent and Trace Acquisitions, partially offset by the absence of 2021 depreciation on certain decommissioned facilities in our West segment.

Selling, general, and administrative expenses increased primarily due to higher employee-related expenses.

Other (income) expense – net within Operating income (loss) changed unfavorably primarily due to losses related to Eminence storage cavern abandonments and regulatory charges associated with a decrease in Transco’s estimated deferred state income tax rate.

Equity earnings (losses) changed favorably primarily due to an increase at Laurel Mountain.

Provision (benefit) for income taxes changed unfavorably primarily due to higher pre-tax income, partially offset by a benefit related to a decrease in our estimate of the state deferred income tax rate. See Note 5 – Provision (Benefit) for Income Taxes of Notes to Consolidated Financial Statements for a discussion of the effective tax rate compared to the federal statutory rate for both periods.

Management’s Discussion and Analysis (Continued)			Table of Contents

Nine months ended September 30, 2022 vs. nine months ended September 30, 2021

Service revenues increased primarily due to higher gathering and processing rates driven by favorable commodity prices and annual contractual rate escalations for certain of our West and Northeast G&P operations, higher gathering volumes including from the Trace Acquisition, higher transportation fee revenues associated with the Leidy South expansion project placed fully in service at Transco in December 2021, and higher reimbursable electric power and storage costs, which are substantially offset in Operating and maintenance expenses.

Service revenues – commodity consideration increased primarily due to higher NGL prices. These revenues represent consideration we receive in the form of commodities as full or partial payment for processing services provided. Most of these NGL volumes are sold during the month processed and therefore are offset within Product costs below.

Product sales increased primarily due to higher marketing sales prices and volumes, including the increase associated with the Sequent Acquisition in third-quarter 2021, higher sales prices and volumes associated with our upstream operations presented in our Other segment, higher sales prices related to our equity NGL sales activities, and higher other product sales. These increases were substantially offset by the impact of netting the 2022 legacy natural gas marketing revenues with the associated costs, including a 2022 lower of cost or net realizable value adjustment to our gas marketing storage inventory (see Note 1 – General, Description of Business, and Basis of Presentation of Notes to Consolidated Financial Statements) as well as lower gas marketing sales prices related to the absence of a 2021 favorable impact from Winter Storm Uri severe winter weather.

The unfavorable change in Net gain (loss) on commodity derivatives primarily reflects a higher net realized loss, offset by a favorable change in net unrealized gains and losses related to derivative contracts in our Other segment. The change also reflects a lower net realized loss, offset by a higher net unrealized loss related to derivative contracts in our Gas & NGL Marketing Services segment.

Product costs decreased primarily due to the impact of netting the 2022 legacy natural gas marketing revenues with the associated costs. This decrease was partially offset by higher prices, volumes, and lower of cost or net realizable value inventory adjustments in 2022 associated with our NGL marketing activities, higher NGL prices associated with volumes acquired as commodity consideration related to our equity NGL production activities, and higher other product costs.

Net processing commodity expenses increased primarily due to higher net realized prices for natural gas purchases associated with our equity NGL production activities, partially offset by favorable change in net unrealized gains from commodity derivatives related to these purchases. These net gains from commodity derivatives include realized gains in our West segment and unrealized gains in our Gas & NGL Marketing segment.

Operating and maintenance expenses increased primarily due to higher operating costs including higher reimbursable electric power and storage costs which are substantially offset in Service revenues, higher expenses associated with our upstream operations, increased costs associated with Transco's Leidy South expansion project placed in service in 2021, and higher employee-related expenses.

Depreciation and amortization expenses increased primarily due to amortization of intangibles acquired in the Sequent and Trace Acquisitions and an increase in depreciation at Transco related to ARO revisions (offset in Other (income) expense – net within Operating income (loss) resulting in no net impact on our results of operations), partially offset by the absence of 2021 depreciation on certain decommissioned facilities in our West segment.

Selling, general, and administrative expenses increased primarily due to higher employee-related and other general expenses, primarily resulting from the Sequent Acquisition, as well as Trace Acquisition costs.

Other (income) expense – net within Operating income (loss) changed unfavorably primarily due to losses related to Eminence storage cavern abandonments and regulatory charges associated with a decrease in Transco’s estimated deferred state income tax rate, offset by the deferral of ARO depreciation (offset in Depreciation and amortization expenses resulting in no net impact on our results of operations).

Management’s Discussion and Analysis (Continued)			Table of Contents

Equity earnings (losses) changed favorably primarily due to increases at Laurel Mountain and RMM, offset by a decrease at Appalachia Midstream Investments.

Interest expense changed favorably primarily due to the early retirement of notes (see Note 8 – Debt and Banking Arrangements of Notes to Consolidated Financial Statements).

Provision (benefit) for income taxes changed favorably primarily due to a benefit related to the release of a valuation allowance, a benefit associated with a decrease in our estimate of the state deferred income tax rate, and federal settlements, partially offset by higher pre-tax income. See Note 5 – Provision (Benefit) for Income Taxes of Notes to Consolidated Financial Statements for a discussion of the effective tax rate compared to the federal statutory rate for both periods.

Period-Over-Period Operating Results - Segments

We evaluate segment operating performance based upon Modified EBITDA. Note 12 – Segment Disclosures of Notes to Consolidated Financial Statements includes a reconciliation of this non-GAAP measure to Net income (loss). Management uses Modified EBITDA because it is an accepted financial indicator used by investors to compare company performance. In addition, management believes that this measure provides investors an enhanced perspective of the operating performance of our assets. Modified EBITDA should not be considered in isolation or as a substitute for a measure of performance prepared in accordance with GAAP.

Transmission & Gulf of Mexico

			Three Months Ended September 30,												Nine Months Ended September 30,
			2022						2021						2022						2021
			(Millions)
Service revenues			$	910					$	836					$	2,651					$	2,493
Service revenues – commodity consideration			11						13						54						34
Product sales			121						88						334						222
Net unrealized gain (loss) from derivative instruments			1						—						1						—
Segment revenues			1,043						937						3,040						2,749
Product costs			(120)						(89)						(329)						(223)
Net processing commodity expenses			(2)						(4)						(23)						(10)
Other segment costs and expenses			(333)						(259)						(844)						(718)
Proportional Modified EBITDA of equity-method investments			50						45						143						138
Transmission & Gulf of Mexico Modified EBITDA			$	638					$	630					$	1,987					$	1,936
Commodity margins			$	10					$	8					$	36					$	23

Three months ended September 30, 2022 vs. three months ended September 30, 2021

Transmission & Gulf of Mexico Modified EBITDA increased primarily due to a favorable change to Service revenues, substantially offset by higher Other segment costs and expenses.

Service revenues increased primarily due to:

• A $43 million increase in Transco’s natural gas transportation and storage revenues primarily associated with the Leidy South expansion project placed fully in service in December 2021 and higher storage rates effective since the second quarter of 2022 as well as benefited from higher reimbursable electric power costs, which is offset by a similar change in electricity charges reflected in Other segment costs and expenses.

• A $24 million increase in the Eastern Gulf Coast region primarily due to higher volumes from the absence of temporary shut-ins due to producer operational issues and weather-related events in 2021.

Management’s Discussion and Analysis (Continued)			Table of Contents

Other segment costs and expenses increased primarily due to higher operating costs including higher reimbursable electric power costs and storage costs, which are offset by a similar change in electricity reimbursements and storage revenues reflected in Service revenues; losses related to Eminence storage cavern abandonments; higher maintenance costs primarily related to general maintenance at Transco; regulatory charges associated with a decrease in Transco’s estimated deferred state income tax rate; and costs associated with the Leidy South expansion project.

Nine months ended September 30, 2022 vs. nine months ended September 30, 2021

Transmission & Gulf of Mexico Modified EBITDA increased primarily due to favorable changes to Service revenues and Commodity margins, partially offset by higher Other segment costs and expenses.

Service revenues increased primarily due to:

• A $134 million increase in Transco’s natural gas transportation and storage revenues primarily associated with the Leidy South expansion project placed fully in service in December 2021 and higher storage rates effective since the second quarter of 2022 as well as benefited from higher reimbursable electric power costs, which is offset by a similar change in electricity charges reflected in Other segment costs and expenses and higher short-term firm transportation, overall demand and commodity revenues.

• A $19 million increase in the Eastern Gulf Coast region primarily due to higher volumes from the absence of temporary shut-ins due to producer operational issues and weather-related events in 2021, partially offset by a decrease at Gulfstar One for the Tubular Bells field primarily due to lower volumes from natural decline.

Commodity margins associated with our equity NGLs increased $10 million primarily driven by favorable NGL sales prices, partially offset by higher prices for natural gas purchases associated with our equity NGL production activities.

Other segment costs and expenses increased primarily due to higher operating costs including higher reimbursable electric power costs and storage costs, which are offset by a similar change in electricity reimbursements and storage revenues reflected in Service revenues; costs associated with the Leidy South expansion project; higher maintenance costs primarily related to general maintenance at Transco and Gulf Coast region; higher employee-related costs; losses related to Eminence storage cavern abandonments; and regulatory charges associated with a decrease in Transco’s estimated deferred state income tax rate. These increases are partially offset by a favorable change in the deferral of ARO related depreciation at Transco.

Management’s Discussion and Analysis (Continued)			Table of Contents

Northeast G&P

			Three Months Ended September 30,												Nine Months Ended September 30,
			2022						2021						2022						2021
			(Millions)
Service revenues			$	417					$	399					$	1,208					$	1,130
Service revenues – commodity consideration			2						(1)						12						4
Product sales			40						19						110						75
Segment revenues			459						417						1,330						1,209
Product costs			(39)						(19)						(110)						(77)
Net processing commodity expenses			—						(1)						(2)						(1)
Other segment costs and expenses			(138)						(130)						(392)						(368)
Proportional Modified EBITDA of equity-method investments			182						175						506						490
Northeast G&P Modified EBITDA			$	464					$	442					$	1,332					$	1,253
Commodity margins			$	3					$	(2)					$	10					$	1

Three months ended September 30, 2022 vs. three months ended September 30, 2021

Northeast G&P Modified EBITDA increased primarily due to higher Service revenues and higher Proportional Modified EBITDA of equity-method investments, partially offset by higher Other segment costs and expenses.

Service revenues increased primarily due to a $16 million increase in revenues at the Northeast JV primarily related to higher gathering and processing volumes as well as higher processing rates. Higher escalated rates at Susquehanna Supply Hub and higher cost of service rates in the Utica Shale region were substantially offset by lower volumes.

Other segment costs and expenses increased primarily due to higher operating expenses, including higher electricity and fuel, which is partially offset by reimbursable revenue.

Proportional Modified EBITDA of equity-method investments increased at Laurel Mountain due to higher commodity-based gathering rates and higher MVC revenue, partially offset by a decrease at Appalachia Midstream Investments primarily driven by lower gathering rates resulting from annual cost of service contract redetermination.

Nine months ended September 30, 2022 vs. nine months ended September 30, 2021

Northeast G&P Modified EBITDA increased primarily due to higher Service revenues and higher Proportional Modified EBITDA of equity-method investments, partially offset by higher Other segment costs and expenses.

Service revenues increased primarily due to:

*•*A $36 million increase in revenues at the Northeast JV primarily related to higher gathering and processing volumes as well as higher processing rates;

• A $15 million increase in revenues at Susquehanna Supply Hub primarily related to higher gathering rates resulting from annual rate escalation, partially offset by lower gathering volumes;

• A $12 million increase in revenues in the Utica Shale region primarily related to higher gathering rates resulting from annual cost of service contract redetermination;

*•*A $12 million increase in revenues associated with reimbursable expenses, which is offset by similar changes in the charges reflected in Other segment costs and expenses.

Management’s Discussion and Analysis (Continued)			Table of Contents

Other segment costs and expenses increased primarily due to higher operating expenses, including higher electricity and fuel, which is partially offset by reimbursable revenue.

Proportional Modified EBITDA of equity-method investments increased at Laurel Mountain due to higher commodity-based gathering rates and higher MVC revenue, partially offset by a decrease at Appalachia Midstream Investments primarily driven by lower gathering rates resulting from annual cost of service contract redetermination.

West

			Three Months Ended September 30,												Nine Months Ended September 30,
			2022						2021						2022						2021
			(Millions)
Service revenues			$	425					$	320					$	1,139					$	908
Service revenues – commodity consideration			47						52						157						126
Product sales			245						177						684						441
Net realized gain (loss) on commodity derivatives – service revenues			(10)						(4)						(15)						(4)
Net realized gain (loss) on commodity derivatives – product sales			1						(14)						(8)						(21)
Net realized gain (loss) on commodity derivatives			(9)						(18)						(23)						(25)
Segment revenues			708						531						1,957						1,450
Product costs			(238)						(170)						(667)						(411)
Net processing commodity expenses			(28)						(24)						(91)						(57)
Other segment costs and expenses			(146)						(107)						(413)						(354)
Proportional Modified EBITDA of equity-method investments			41						27						99						74
West Modified EBITDA			$	337					$	257					$	885					$	702
Commodity margins			$	27					21						$	75					$	78

Three months ended September 30, 2022 vs. three months ended September 30, 2021

West Modified EBITDA increased primarily due to higher Service revenues and Proportional Modified EBITDA of equity-method investments, partially offset by higher Other segment costs and expenses.

Service revenues increased primarily due to:

• A $59 million increase in the Haynesville Shale region primarily associated with higher gathering volumes including from the Trace Acquisition (see Note 3 – Acquisitions of Notes to Consolidated Financial Statements) in April 2022 as well as higher gathering rates driven by favorable commodity pricing;

• A $40 million increase in the Barnett Shale region primarily due to higher gathering rates driven by favorable commodity pricing.

Product margins from our equity NGLs increased $5 million, primarily due to higher net realized commodity sales prices, partially offset by higher net realized prices for natural gas purchases associated with our equity NGLs production activities and lower non-ethane sales volumes. Other product margins increased $6 million primarily due to the Trace Acquisition. Marketing margins decreased $5 million.

Management’s Discussion and Analysis (Continued)			Table of Contents

Other segment costs and expenses increased primarily due to higher operating expenses related to the Trace Acquisition as well as higher compressor electricity and fuel costs, and the absence of a gain on an asset sale in 2021.

Proportional Modified EBITDA of equity-method investments increased primarily due to higher commodity prices and volumes at RMM as well as higher volumes at OPPL.

Nine months ended September 30, 2022 vs. nine months ended September 30, 2021

West Modified EBITDA increased primarily due to higher Service revenues and Proportional Modified EBITDA of equity-method investments, partially offset by higher Other segment costs and expenses.

Service revenues increased primarily due to:

• A $127 million increase in the Haynesville Shale region primarily due to higher gathering volumes including from the Trace Acquisition as well as higher gathering rates driven by favorable commodity pricing;

• An $88 million increase in the Barnett Shale region primarily due to higher gathering rates driven by favorable commodity pricing;

• A $16 million increase in the Piceance region primarily driven by higher processing rates driven by favorable commodity pricing;

• A $1 million increase in the Eagle Ford Shale region primarily due to higher MVC revenues, escalated gathering rates, and higher deferred revenue amortization, substantially offset by a production decline; partially offset by

• An $11 million decrease associated with lower MVC revenue in the Wamsutter region.

Marketing margins decreased $21 million, primarily due to the absence of the favorable impact of Winter Storm Uri in the first quarter of 2021. Other product margins increased $13 million primarily due to higher condensate sales and the Trace Acquisition in 2022. Product margins from our equity NGLs increased $5 million primarily due to higher net realized commodity sales prices, partially offset by higher net realized prices for natural gas purchases associated with our equity NGLs production activities and lower sales volumes primarily due to a customer contract change.

Other segment costs and expenses increased primarily due to higher operating expenses related to higher electricity and compressor fuel costs, the absence of gains on asset sales in 2021, higher corporate allocations, and expenses associated with the Trace Acquisition in 2022.

Proportional Modified EBITDA of equity-method investments increased primarily due to higher volumes and commodity prices at RMM and higher volumes at OPPL.

Management’s Discussion and Analysis (Continued)			Table of Contents

Gas & NGL Marketing Services

			Three Months Ended September 30,												Nine Months Ended September 30,
			2022						2021						2022						2021
			(Millions)
Service revenues			$	1					$	—					$	2					$	2
Product sales			884						1,234						2,724						3,049
Net realized gain (loss) from derivative instruments			54						(58)						(18)						(93)
Net unrealized gain (loss) from derivative instruments			(1)						(294)						(357)						(297)
Net gain (loss) on commodity derivatives			53						(352)						(375)						(390)
Segment revenues			938						882						2,351						2,661
Net unrealized gain (loss) from derivative instruments within Net processing commodity expenses			6						—						17						—
Product costs			(899)						(1,130)						(2,544)						(2,802)
Other segment costs and expenses			(25)						(14)						(73)						(20)
Gas & NGL Marketing Services Modified EBITDA			$	20					$	(262)					$	(249)					$	(161)
Commodity margins			$	39					$	46					$	162					$	154

Three months ended September 30, 2022 vs. three months ended September 30, 2021

Gas & NGL Marketing Services Modified EBITDA increased primarily due to the absence of a 2021 net unrealized loss from derivative instruments, partially offset by higher Other segment costs and expenses and lower Commodity margins.

Commodity margins decreased $7 million primarily due to:

*•*A $55 million decrease in NGL marketing margins primarily due to:

◦A $38 million unfavorable change in realized gains and losses on sales of product;

◦A $22 million charge related to lower of cost or net realizable value inventory adjustments in the third quarter of 2022; partially offset by

◦A $5 million favorable change in net realized gain (loss) from derivative instruments.

*•*A $48 million increase from our natural gas marketing operations including $83 million of higher natural gas transportation capacity marketing margins due to favorable pricing spreads, partially offset by $35 million lower natural gas storage marketing margins primarily due to a third-quarter 2022 charge related to a lower of cost or net realizable value inventory adjustment.

Net unrealized gain (loss) from derivative instruments relates to derivative contracts that are not designated as hedges for accounting purposes. The change from 2021 is primarily due to a change in forward commodity prices relative to our hedge positions in 2022 compared to 2021.

Other segment costs and expenses increased primarily due to higher employee-related costs.

Nine months ended September 30, 2022 vs. nine months ended September 30, 2021

Gas & NGL Marketing Services Modified EBITDA decreased primarily due to higher Other segment costs and expenses and higher net unrealized loss from derivative instruments, partially offset by higher Commodity margins.

Management’s Discussion and Analysis (Continued)			Table of Contents

Commodity margins increased $8 million primarily due to:

*•*A $56 million increase in natural gas marketing margins which included the following:

◦A $169 million increase in natural gas transportation capacity marketing margins primarily associated with the Sequent Acquisition in the third quarter of 2021 and favorable pricing spreads in the third quarter of 2022; partially offset by

◦A $58 million decrease associated with our legacy natural gas marketing operations primarily due to the absence of the favorable impact of Winter Storm Uri in the first quarter of 2021;

◦A $40 million decrease in natural gas storage marketing margins due primarily to a lower of cost or net realizable value inventory adjustment in 2022; and

◦A $15 million charge in 2022 related to the remaining recognition of a purchase accounting inventory fair value adjustment which increased the weighted-average cost of inventory.

• A $48 million decrease in our NGL marketing margins primarily due to:

◦A $25 million unfavorable change in realized gains on sales of product;

◦A $25 million charge related to lower of cost or net realizable value inventory adjustments in 2022; partially offset by

◦A $2 million favorable change in net realized gain (loss) from derivative instruments.

Net unrealized gain (loss) from derivative instruments changed primarily due to the Sequent Acquisition in July 2021, and a change in forward commodity prices relative to our hedge positions in 2022 compared to 2021.

Other segment costs and expenses increased primarily due to higher employee-related costs related to the Sequent Acquisition.

Other

			Three Months Ended September 30,												Nine Months Ended September 30,
			2022						2021						2022						2021
			(Millions)
Service revenues			$	6					$	8					$	22					$	23
Product sales			238						111						522						216
Net realized gain (loss) from derivative instruments			(58)						(6)						(104)						(6)
Net unrealized gain (loss) from derivative instruments			29						(15)						10						(20)
Net gain (loss) on commodity derivatives			(29)						(21)						(94)						(26)
Segment revenues			215						98						450						213
Other segment costs and expenses			(75)						(60)						(166)						(122)
Other Modified EBITDA			$	140					$	38					$	284					$	91
Net realized product sales			$	180					$	105					$	418					$	210

Management’s Discussion and Analysis (Continued)			Table of Contents

Three months ended September 30, 2022 vs. three months ended September 30, 2021

Other Modified EBITDA increased primarily due to $105 million higher results from our upstream operations which included the following:

*•*A $75 million increase in Net realized product sales primarily due to higher net realized commodity prices and higher volumes associated with production from new wells, partially offset by an unfavorable change in Net realized gain (loss) from derivative instruments due to an increase in commodity prices relative to our hedge positions;

*•*A $44 million favorable change in Net unrealized gain (loss) from derivative instruments due to a change in forward commodity prices relative to our hedge positions and an increase in the volume of production hedged in 2022 compared to 2021; partially offset by

• A $14 million increase in Other segment costs and expenses primarily due to the increased scale of our upstream operations and higher associated property and production taxes which were also impacted by higher commodity prices.

Other segment costs and expenses also includes an $11 million charge related to an accrual for loss contingency in the third quarter of 2022.

Nine months ended September 30, 2022 vs. nine months ended September 30, 2021

Other Modified EBITDA increased primarily due to $190 million higher results from our upstream operations which included the following:

*•*A $208 million increase in Net realized product sales primarily due to higher net realized commodity prices in the second and third quarters of 2022, partially offset by lower prices from the absence of the favorable impact of Winter Storm Uri in the first quarter of 2021 and an unfavorable change in Net realized gain (loss) from derivative instruments due to an increase in commodity prices relative to our hedge positions. Net realized product sales also increased due to higher production from new wells and higher volumes associated with acquisitions of additional ownership interests in 2021; and

*•*A $30 million favorable change in Net unrealized gain (loss) from derivative instruments due to a change in forward commodity prices relative to our hedge positions and an increase in the volume of production hedged in 2022 compared to 2021; partially offset by

• A $48 million increase in Other segment costs and expenses primarily due to the increased scale of our upstream operations and higher associated property and production taxes which were also impacted by higher commodity prices.

Other segment costs and expenses also includes an $11 million charge related to an accrual for loss contingency in the third quarter of 2022, substantially offset by the absence of a $10 million charge related to an accrual for loss contingency in 2021.

Management’s Discussion and Analysis (Continued)			Table of Contents

Management’s Discussion and Analysis of Financial Condition and Liquidity

Outlook

Our growth capital and investment expenditures in 2022 are currently expected to be in a range from $1.25 billion to $1.35 billion, which excludes approximately $1.5 billion in total acquisitions and follow-on expenditures for the Trace Acquisition and NorTex Asset Purchase. Growth capital spending in 2022, excluding the Trace Acquisition and NorTex Asset Purchase, primarily includes Transco expansions, all of which are fully contracted with firm transportation agreements, projects supporting the Northeast G&P business, and an expansion in the Western Gulf area. We also expect to invest capital in the development of our upstream oil and gas properties. In addition to growth capital and investment expenditures, we also remain committed to projects that maintain our assets for safe and reliable operations, as well as projects that meet legal, regulatory, and/or contractual commitments. We funded both the Trace Acquisition and the NorTex Asset Purchase with available sources of short-term liquidity and intend to fund substantially all additional planned 2022 capital spending with cash available after paying dividends. We retain the flexibility to adjust planned levels of growth capital and investment expenditures in response to changes in economic conditions or business opportunities including the repurchase of our common stock.

During the first quarter of 2022, we early retired $1.25 billion of 3.6 percent senior unsecured notes that were scheduled to mature in March 2022 using proceeds from our October 2021 debt offering. During the second quarter of 2022, we early retired $750 million of 3.35 percent senior unsecured notes that were scheduled to mature in August 2022 using issuances of commercial paper. During the third quarter of 2022, we issued $1.75 billion of long-term debt that we used to pay down our commercial paper outstanding and, in October 2022, to early retire our $850 million of 3.7 percent senior unsecured notes that were scheduled to mature in January 2023.

Liquidity

Based on our forecasted levels of cash flow from operations and other sources of liquidity, we expect to have sufficient liquidity to manage our businesses in 2022. Our potential material internal and external sources and uses of liquidity are as follows:

Sources:
			Cash and cash equivalents on hand
			Cash generated from operations
			Distributions from our equity-method investees
			Utilization of our credit facility and/or commercial paper program
			Cash proceeds from issuance of debt and/or equity securities
			Proceeds from asset monetizations
Uses:
			Working capital requirements
			Capital and investment expenditures
			Product costs
			Other operating costs including human capital expenses
			Quarterly dividends to our shareholders
			Repayments of borrowings under our credit facility and/or commercial paper program
			Debt service payments, including payments of long-term debt
			Distributions to noncontrolling interests
			Share repurchase program

Management’s Discussion and Analysis (Continued)			Table of Contents

As of September 30, 2022, we have $22.5 billion of long-term debt due after one year. Our potential sources of liquidity available to address these maturities include cash generated from operations, proceeds from refinancing, our credit facility, or our commercial paper program, as well as proceeds from asset monetizations.

Potential risks associated with our planned levels of liquidity discussed above include those previously discussed in Company Outlook*.*

As of September 30, 2022, we had a working capital deficit of $579 million, including cash and cash equivalents and long-term debt due within one year. Our available liquidity is as follows:

Available Liquidity			September 30, 2022
			(Millions)
Cash and cash equivalents			$	859
Capacity available under our $3.75 billion credit facility, less amounts outstanding under our $3.5 billion commercial paper program (1)			3,750
			$	4,609

(1)In managing our available liquidity, we do not expect a maximum outstanding amount in excess of the capacity of our credit facility inclusive of any outstanding amounts under our commercial paper program. We had no commercial paper outstanding as of September 30, 2022. Through September 30, 2022, the highest amount outstanding under our commercial paper program and credit facility during 2022 was $1.219 billion. At September 30, 2022, we were in compliance with the financial covenants associated with our credit facility. Borrowing capacity under our credit facility as of October 27, 2022 was $3.630 billion.

Dividends

We increased our regular quarterly cash dividend to common stockholders by approximately 3.7 percent from the $0.41 per share paid in each quarter of 2021, to $0.425 per share paid in March, June, and September 2022.

Distributions from Equity-Method Investees

The organizational documents of entities in which we have an equity-method investment generally require periodic distributions of their available cash to their members. In each case, available cash is reduced, in part, by reserves appropriate for operating their respective businesses.

Credit Ratings

The interest rates at which we are able to borrow money are impacted by our credit ratings. The current ratings are as follows:

Rating Agency						Outlook						Senior Unsecured Debt Rating
S&P Global Ratings						Stable						BBB
Moody’s Investors Service						Stable						Baa2
Fitch Ratings						Stable						BBB

These credit ratings are included for informational purposes and are not recommendations to buy, sell, or hold our securities, and each rating should be evaluated independently of any other rating. No assurance can be given that the credit rating agencies will continue to assign us investment-grade ratings even if we meet or exceed their current criteria for investment-grade ratios. A downgrade of our credit ratings might increase our future cost of borrowing and, if ratings were to fall below investment-grade, could require us to provide additional collateral to third parties, negatively impacting our available liquidity.

Management’s Discussion and Analysis (Continued)			Table of Contents

Sources (Uses) of Cash

The following table summarizes the sources (uses) of cash and cash equivalents for each of the periods presented (see Notes to Consolidated Financial Statements for the Notes referenced in the table):

			Cash Flow						Nine Months Ended September 30,
			Category						2022						2021
									(Millions)
Sources of cash and cash equivalents:
Operating activities – net			Operating						$	3,670					$	2,806
Proceeds from long-term debt			Financing						1,752						898
Uses of cash and cash equivalents:
Payments of long-term debt			Financing						(2,019)						(887)
Common dividends paid			Financing						(1,553)						(1,494)
Capital expenditures			Investing						(1,447)						(957)
Purchases of businesses, net of cash acquired (see Note 3)			Investing						(933)						(126)
Dividends and distributions paid to noncontrolling interests			Financing						(141)						(135)
Purchases of and contributions to equity-method investments			Investing						(140)						(79)
Other sources / (uses) – net			Financing and Investing						(10)						46
Increase (decrease) in cash and cash equivalents									$	(821)					$	72

Operating activities

The factors that determine operating activities are largely the same as those that affect Net income (loss), with the exception of noncash items such as Depreciation and amortization, Provision (benefit) for deferred income taxes, Equity (earnings) losses, and Net unrealized (gain) loss from derivative instruments.

Our Net cash provided (used) by operating activities for the nine months ended September 30, 2022, increased from the same period in 2021 primarily due higher operating income (excluding noncash items as previously discussed), favorable changes in margin requirements, and higher Distributions from unconsolidated affiliates.