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

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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, and compression, NGL fractionation and transportation, crude oil production handling and transportation, marketing services for NGL, crude oil and natural gas, as well as storage facilities.

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, 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), 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 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 interest in Brazos Permian II, LLC.
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


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

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

Overview of Six Months Ended June 30, 2022

Net income (loss) attributable to The Williams Companies, Inc., for the six months ended June 30, 2022, increased $50 million compared to the six months ended June 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 during the second half of 2021, higher results from our upstream operations associated with 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 $356 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, and higher selling, general, and administrative expenses, primarily resulting from the Sequent Acquisition. The tax provision benefited from $134 million associated with the release of valuation allowances on deferred income tax assets and federal income tax settlements.

Our results include a $356 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 (Trace Acquisition) 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.

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 recently completed Transco expansion projects, development of our upstream oil and gas properties, and our recently completed Trace


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

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 $2.25 billion to $2.35 billion. Growth capital spending in 2022 primarily includes Transco expansions, all of which are fully contracted with firm transportation agreements, projects supporting the Northeast G&P business, the Trace Acquisition, 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;
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;
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.


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

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. The expansion project will add a total of approximately 423 Mdth/d of capacity. 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.

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. We may consider a partner for this project.


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 six months ended June 30, 2022, compared to the three and six months ended June 30, 2021. The results of operations by segment are discussed in further detail following this consolidated overview discussion.


	Three Months Ended June 30,							Six Months Ended June 30,
	2022		2021		$ Change*	% Change*		2022		2021		$ Change*	% Change*
	(Millions)							(Millions)
Revenues:
Service revenues	$	1,606	$	1,460	+146	+10	%	$	3,143	$	2,912	+231	+8	%
Service revenues – commodity consideration	86		51		+35	+69	%	163		100		+63	+63	%
Product sales	1,111		786		+325	+41	%	2,215		1,933		+282	+15	%
Net gain (loss) on commodity derivatives	(313)		(14)		-299	NM		(507)		(50)		-457	NM
Total revenues	2,490		2,283					5,014		4,895
Costs and expenses:
Product costs	857		697		-160	-23	%	1,660		1,629		-31	-2	%
Net processing commodity expenses	40		18		-22	-122	%	70		39		-31	-79	%
Operating and maintenance expenses	465		379		-86	-23	%	859		739		-120	-16	%
Depreciation and amortization expenses	506		463		-43	-9	%	1,004		901		-103	-11	%
Selling, general, and administrative expenses	160		114		-46	-40	%	314		237		-77	-32	%


Other (income) expense – net	(10)		12		+22	NM		(19)		11		+30	NM
Total costs and expenses	2,018		1,683					3,888		3,556
Operating income (loss)	472		600					1,126		1,339
Equity earnings (losses)	163		135		+28	+21	%	299		266		+33	+12	%

Other investing income (loss) – net	2		2		—	—	%	3		4		-1	-25	%
Interest expense	(281)		(298)		+17	+6	%	(567)		(592)		+25	+4	%
Other income (expense) – net	6		2		+4	+200	%	11		—		+11	NM
Income (loss) before income taxes	362		441					872		1,017
Less: Provision (benefit) for income taxes	(45)		119		+164	NM		73		260		+187	+72	%


Net income (loss)	407		322					799		757
Less: Net income (loss) attributable to noncontrolling interests	7		18		+11	+61	%	19		27		+8	+30	%
Net income (loss) attributable to The Williams Companies, Inc.	$	400	$	304				$	780	$	730

- = 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 June 30, 2022 vs. three months ended June 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 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 volumes of NGLs and natural gas, 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 and gas marketing activities, and higher other product sales. These increases were partially offset by 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.

Net gain (loss) on commodity derivatives includes realized and unrealized gains and losses from derivative instruments reflected within Total revenues. The unfavorable change primarily reflects net realized and unrealized losses in our Gas & NGL Marketing Services segment, as well as higher net realized losses related to derivative contracts in our Other and West segments. Higher net realized gains at our Other segment partially offset these impacts.

Product costs increased primarily due to higher prices for our NGL marketing activities, as well as higher NGL prices associated with volumes acquired as commodity consideration related to our equity NGL production activities, and higher other product costs. These increases were partially offset by the impact of netting the 2022 legacy natural gas marketing revenues with the associated costs.

Net processing commodity expenses increased primarily due to higher net realized prices for natural gas purchases associated with our equity NGL production activities, including a net gain from commodity derivatives related to these purchases in 2022. This net gain from commodity derivatives includes a realized gain in our West segment and an unrealized gain in our Gas & NGL Marketing segment.

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

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 expenses, including those associated with the Sequent Acquisition, and Trace Acquisition costs.


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

Other (income) expense – net within Operating income (loss) changed favorably primarily due to the deferral of ARO depreciation (offset in Depreciation and amortization expenses resulting in no net impact on our results of operations).

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

Interest expense changed favorably primarily due to the early retirement of notes, partially offset by interest on outstanding commercial paper (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 of $134 million related to the release of valuation allowances on certain federal and state deferred income tax assets and federal income tax settlements, as well as lower 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.

Six months ended June 30, 2022 vs. six months ended June 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 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 increased primarily due to higher marketing sales volumes of NGLs and natural gas, 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 partially offset by 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) and lower gas marketing sales prices related to the absence of severe winter weather in 2022 as compared to the first quarter of 2021. 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.

The unfavorable change in Net gain (loss) on commodity derivatives primarily reflects net realized and unrealized losses in our Gas & NGL Marketing Services and Other segments.

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


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

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.

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

The favorable change in Other income (expense) – net below Operating income (loss) reflects the absence of an accrual for a loss contingency in 2021.

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 June 30,				Six Months Ended June 30,
	2022		2021		2022		2021
	(Millions)
Service revenues	$	867	$	823	$	1,741	$	1,657
Service revenues – commodity consideration	22		10		43		21
Product sales	113		67		213		134
Segment revenues	1,002		900		1,997		1,812

Product costs	(109)		(68)		(209)		(134)
Net processing commodity expenses	(15)		(2)		(21)		(6)
Other segment costs and expenses	(271)		(230)		(511)		(459)

Proportional Modified EBITDA of equity-method investments	45		46		93		93
Transmission & Gulf of Mexico Modified EBITDA	$	652	$	646	$	1,349	$	1,306

Commodity margins	$	11	$	7	$	26	$	15


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

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

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

Service revenues increased primarily due to a $51 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 during the second quarter of 2022. The 2022 quarter also benefited from higher reimbursable electric power costs, which is offset by a similar change in electricity charges reflected in Other segment costs and expenses.

Other segment costs and expenses increased primarily due to higher operating costs, including costs associated with the Leidy South expansion project, 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, and higher employee-related costs. These increases are partially offset by a favorable change in the deferral of ARO related depreciation at Transco.

Six months ended June 30, 2022 vs. six months ended June 30, 2021

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

Service revenues increased primarily due to a $91 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 during the second quarter of 2022. The 2022 period also benefited from higher reimbursable electric power costs, which is offset by a similar change in electricity charges reflected in Other segment costs and expenses.

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 costs associated with the Leidy South expansion project, 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, and higher employee-related costs. 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 June 30,				Six Months Ended June 30,
	2022		2021		2022		2021
	(Millions)
Service revenues	$	411	$	373	$	791	$	731
Service revenues – commodity consideration	3		2		10		5
Product sales	34		24		70		56
Segment revenues	448		399		871		792

Product costs	(34)		(26)		(71)		(58)
Net processing commodity expenses	(2)		—		(2)		—

Other segment costs and expenses	(136)		(126)		(254)		(238)

Proportional Modified EBITDA of equity-method investments	174		162		324		315
Northeast G&P Modified EBITDA	$	450	$	409	$	868	$	811

Commodity margins	$	1	$	—	$	7	$	3

Three months ended June 30, 2022 vs. three months ended June 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 $15 million increase in revenues at the Northeast JV primarily related to higher processing and gathering volumes;

A $10 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 $10 million increase in revenues in the Utica Shale region primarily related to higher gathering rates resulting from annual cost of service contract redetermination.

Other segment costs and expenses increased primarily due to higher operating expenses.

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.

Six months ended June 30, 2022 vs. six months ended June 30, 2021

Service revenues increased primarily due to:

*•*A $20 million increase in revenues at the Northeast JV primarily related to higher processing volumes;

A $19 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 $9 million increase in revenues in the Utica Shale region primarily related to higher gathering rates resulting from annual cost of service contract redetermination;


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

A $9 million increase in revenues associated with reimbursable electricity expenses, which is offset by similar changes in electricity charges, reflected in Other segment costs and expenses.

Other segment costs and expenses increased primarily due to higher operating expenses, including higher electricity charges.

West


	Three Months Ended June 30,				Six Months Ended June 30,
	2022		2021		2022		2021
	(Millions)
Service revenues	$	383	$	297	$	714	$	588
Service revenues – commodity consideration	61		39		110		74
Product sales	252		112		439		264
Net gain (loss) on commodity derivatives	(9)		(5)		(14)		(7)
Segment revenues	687		443		1,249		919

Product costs	(247)		(104)		(429)		(241)
Net processing commodity expenses	(37)		(16)		(63)		(33)
Other segment costs and expenses	(146)		(122)		(267)		(247)

Proportional Modified EBITDA of equity-method investments	31		22		58		47
West Modified EBITDA	$	288	$	223	$	548	$	445

Commodity margins	$	25	$	26	$	48	$	57

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

West Modified EBITDA increased primarily due to higher Service revenues, partially offset by higher Other segment costs and expenses.

Service revenues increased primarily due to:

A $50 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 $34 million increase in the Barnett Shale region primarily due to higher gathering rates driven by favorable commodity pricing.

Product margins from our equity NGLs decreased $1 million, primarily due to higher net realized prices for natural gas purchases associated with our equity NGLs production activities and lower non-ethane sales volumes, substantially offset by higher net realized commodity sales prices.

Other segment costs and expenses changed unfavorably primarily due to higher operating expenses and expenses associated with our Trace Acquisition in April 2022.

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


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

Six months ended June 30, 2022 vs. six months ended June 30, 2021

West Modified EBITDA increased primarily due to higher Service revenues, partially offset by higher Other segment costs and expenses.

Service revenues increased primarily due to:

A $68 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;
A $42 million increase in the Barnett Shale region primarily due to higher gathering rates driven by favorable commodity pricing;
A $25 million increase in the Piceance region primarily driven by higher processing rates driven by favorable commodity pricing; partially offset by
An $11 million decrease associated with lower MVC revenue in the Wamsutter region;
A $2 million decrease in the Eagle Ford Shale region primarily due to a production decline, substantially offset by higher MVC revenue.

Marketing margins decreased $17 million, primarily due to the absence of severe winter weather in the first quarter of 2022 as compared to 2021. Product margins from our equity NGLs were zero with higher net realized commodity sales prices 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 $8 million primarily due to higher commodity prices.

Other segment costs and expenses changed unfavorably primarily due to higher operating expenses and expenses associated with our Trace Acquisition in April 2022.

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

Gas & NGL Marketing Services


	Three Months Ended June 30,				Six Months Ended June 30,
	2022		2021		2022		2021
	(Millions)
Service revenues	$	—	$	1	$	1	$	2
Product sales	872		727		1,840		1,815

Net realized gain (loss) from derivative instruments	(16)		(1)		(72)		(35)
Net unrealized gain (loss) from derivative instruments	(297)		(3)		(356)		(3)
Net gain (loss) on commodity derivatives	(313)		(4)		(428)		(38)

Segment revenues	559		724		1,413		1,779
Net unrealized gain (loss) from derivative instruments within Net processing commodity expenses	9		—		11		—
Product costs	(833)		(713)		(1,645)		(1,672)
Other segment costs and expenses	(17)		(3)		(48)		(6)
Gas & NGL Marketing Services Modified EBITDA	$	(282)	$	8	$	(269)	$	101

Commodity margins	$	23	$	13	$	123	$	108


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

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

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

Commodity margins increased $10 million primarily due to:

*•*A $7 million increase in NGL marketing margins primarily due to higher net realized prices on sales of inventory;

*•*A $3 million increase from our natural gas marketing operations including $13 million of higher natural gas transportation capacity marketing margins due to favorable net realized commodity pricing, partially offset by $10 million lower natural gas storage marketing margins due to a second-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 related to the Sequent Acquisition in July 2021 and the discontinuance of hedge accounting for new hedges beginning in the second half of 2021.

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

Six months ended June 30, 2022 vs. six months ended June 30, 2021

Commodity margins increased $15 million primarily due to:

*•*An $8 million increase in natural gas marketing margins which included the following:

An $86 million increase in natural gas transportation capacity marketing margins primarily associated with the Sequent Acquisition;
A $5 million increase in natural gas storage marketing margins due to higher net realized commodity prices; partially offset by
A $58 million decrease associated with our legacy natural gas marketing operations primarily due to lower net realized natural gas prices from the absence of severe winter weather in the first quarter of 2022 as compared to the first quarter of 2021;
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; and
A $10 million charge related to a lower of cost or net realizable value inventory adjustment in 2022;
A $7 million increase in our NGL marketing margins primarily due to higher net realized commodity prices and higher volumes.

Net unrealized gain (loss) from derivative instruments changed significantly primarily due to the Sequent Acquisition in July 2021 and the discontinuance of hedge accounting for new hedges beginning in the second half of 2021.

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


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

Other


	Three Months Ended June 30,				Six Months Ended June 30,
	2022		2021		2022		2021
	(Millions)
Service revenues	$	7	$	8	$	16	$	15
Product sales	180		49		284		105

Net realized gain (loss) from derivative instruments	(38)		—		(46)		—
Net unrealized gain (loss) from derivative instruments	47		(5)		(19)		(5)
Net gain (loss) on commodity derivatives	9		(5)		(65)		(5)

Segment revenues	196		52		235		115

Other segment costs and expenses	(57)		(32)		(91)		(62)
Other Modified EBITDA	$	139	$	20	$	144	$	53

Net realized product sales	$	142	$	49	$	238	$	105

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

Other Modified EBITDA increased primarily due to $117 million higher results from our upstream operations which included the following:

*•*A $93 million increase in Net realized product sales primarily due to higher net realized commodity prices in the second quarter of 2022 and higher volumes associated with acquisitions of additional ownership interests in the second and third quarters of 2021 and higher production from new wells;

*•*A $52 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 $28 million increase in Other segment costs and expenses primarily related to higher expenses associated with the increased scale of our upstream operations and higher production and property taxes associated with higher commodity prices.

Six months ended June 30, 2022 vs. six months ended June 30, 2021

Other Modified EBITDA increased primarily due to $85 million higher results from our upstream operations which included the following:

*•*A $133 million increase in Net realized product sales primarily due to higher volumes associated with acquisitions of additional ownership interests in the second and third quarters of 2021 and higher production from new wells. Net realized product sales also increased due to higher net realized commodity prices in the second quarter of 2022, partially offset by lower prices from the absence of winter weather in the first quarter of 2022 compared to the first quarter of 2021; partially offset by

*•*A $14 million unfavorable 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 production hedged in 2022 compared to 2021; and


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

A $34 million increase in Other segment costs and expenses primarily related to higher expenses associated with the increased scale of our upstream operations and higher production and property taxes associated with higher commodity prices.

Other segment costs and expenses also reflects a $10 million favorable impact for the absence of 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 $2.25 billion to $2.35 billion. Growth capital spending in 2022 primarily includes Transco expansions, all of which are fully contracted with firm transportation agreements, projects supporting the Northeast G&P business, the Trace Acquisition, 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 the Trace Acquisition 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. As of June 30, 2022, we have $876 million of long-term debt due within one year and $1.040 billion of Commercial paper outstanding (at par value). Our potential sources of liquidity available to address these maturities include cash on hand, proceeds from refinancing, our credit facility, or our commercial paper program, as well as proceeds from asset monetizations.

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

As of June 30, 2022, we have $20.8 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.


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

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

As of June 30, 2022, we had a working capital deficit of $2.051 billion, including cash and cash equivalents, long-term debt due within one year, and commercial paper. Our available liquidity is as follows:


Available Liquidity	June 30, 2022
	(Millions)
Cash and cash equivalents	$	133
Capacity available under our $3.75 billion credit facility, less amounts outstanding under our $3.5 billion commercial paper program (1)	2,710
	$	2,843

(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 $1.040 billion of Commercial paper (at par value) outstanding as of June 30, 2022. Through June 30, 2022, the highest amount outstanding under our commercial paper program and credit facility during 2022 was $1.219 billion. At June 30, 2022, we were in compliance with the financial covenants associated with our credit facility. Borrowing capacity under our credit facility as of July 28, 2022 was $2.712 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 and June 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	Six Months Ended June 30,
	Category	2022		2021
		(Millions)
Sources of cash and cash equivalents:
Operating activities – net	Operating	$	2,180	$	1,972
Proceeds from commercial paper - net	Financing	1,037		—
Proceeds from long-term debt	Financing	5		898



Uses of cash and cash equivalents:
Payments of long-term debt	Financing	(2,012)		(11)
Common dividends paid	Financing	(1,035)		(996)
Capital expenditures	Investing	(606)		(685)

Purchases of businesses, net of cash acquired (see Note 3)	Investing	(933)		—
Dividends and distributions paid to noncontrolling interests	Financing	(95)		(95)
Purchases of and contributions to equity-method investments	Investing	(100)		(44)

Other sources / (uses) – net	Financing and Investing	12		20
Increase (decrease) in cash and cash equivalents		$	(1,547)	$	1,059

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 six months ended June 30, 2022, increased from the same period in 2021 primarily due to higher operating income (excluding noncash items as previously discussed), favorable changes in margin requirements, and higher distributions from unconsolidated affiliates, partially offset by net unfavorable changes in operating working capital.

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