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, 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 business activities:

Transmission & Gulf of Mexico is comprised of our interstate natural gas pipelines, Transco, Northwest Pipeline, and MountainWest, and their related natural gas storage facilities, as well as natural gas gathering and processing and crude oil production handling and transportation assets in the Gulf Coast region, including a 51 percent interest in Gulfstar One, a 50 percent equity-method investment in Gulfstream, and a 60 percent equity-method investment in Discovery. Transmission & Gulf of Mexico also includes natural gas storage facilities and pipelines providing services in north Texas.
Northeast G&P is comprised of our midstream gathering, processing, and fractionation businesses in the Marcellus Shale region primarily in Pennsylvania and New York, and the Utica Shale region of eastern Ohio, as well as a 65 percent interest in our Northeast JV which operates in West Virginia, Ohio, and Pennsylvania, a 66 percent interest in Cardinal which operates in Ohio, a 69 percent equity-method investment in Laurel Mountain, a 50 percent equity-method investment in Blue Racer, and Appalachia Midstream Investments.
West is comprised of our gas gathering, processing, and treating operations in the Rocky Mountain region of Colorado and Wyoming, the Barnett Shale region of north-central Texas, the Eagle Ford Shale region of south Texas, the Haynesville Shale region of east Texas and northwest Louisiana, and the Mid-Continent region which includes the Anadarko and Permian basins. This segment also includes our NGL storage facilities, an undivided 50 percent interest in an NGL fractionator near Conway, Kansas, a 50 percent equity-method investment in OPPL, a 50 percent equity-method investment in RMM, a 20 percent equity-method investment in Targa Train 7, and a 15 percent equity-method investment in Brazos Permian II.
Gas & NGL Marketing Services is comprised of our NGL and natural gas marketing and trading operations which includes risk management and transactions related to the storage and transportation of natural gas and NGLs on strategically positioned assets.


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

Unless indicated otherwise, the following discussion and analysis of results of operations and financial condition and liquidity relates to our current continuing operations and should be read in conjunction with the consolidated financial statements and notes thereto of this Form 10-Q and our Annual Report on Form 10-K for the year ended December 31, 2022 dated February 27, 2023.

Dividends

In June 2023, we paid a regular quarterly dividend of $0.4475 per share.

Overview of Six Months Ended June 30, 2023

Net income (loss) attributable to The Williams Companies, Inc., for the six months ended June 30, 2023, increased $607 million compared to the six months ended June 30, 2022. Further discussion of our results is found in this report in the Results of Operations.

Recent Developments

MountainWest Acquisition

On February 14, 2023, we closed on the acquisition of 100 percent of MountainWest, which includes FERC-regulated interstate natural gas pipeline systems and natural gas storage capacity, for $1.08 billion of cash, funded with available sources of short-term liquidity, and retaining $430 million outstanding principal amount of MountainWest long-term debt. The MountainWest Acquisition expands our existing transmission and storage infrastructure footprint into major markets in Utah, Wyoming, and Colorado.

Northwest Pipeline FERC Rate Case Settlement

On November 15, 2022, Northwest Pipeline received approval from the FERC for a stipulation and settlement agreement which generally reduces rates effective January 1, 2023, resolves other rate issues, establishes a Modernization and Emission Reduction Program, and satisfies its rate case filing obligation. Provisions were included in the settlement that establish a moratorium on any proceedings that would seek to place new rates in effect any earlier than January 1, 2026, and that a general rate case filing will be made for rates to become effective not later than April 1, 2028, unless we have entered into a pre-filing settlement prior to that date.

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 2023 includes a continued focus on earnings and cash flow growth.

In 2023, our operating results are expected to benefit from the MountainWest Acquisition, volume growth in the Haynesville and Northeast G&P areas, annual inflation-based rate increases across our gathering and processing business, and partial in-service of the Regional Energy Access project. We also anticipate increases resulting from a full year of contribution from recently acquired Trace and NorTex assets. These increases are partially offset by a lower expected commodity price environment.

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 2023 are expected to be in a range from $1.6 billion to $1.9 billion, excluding the MountainWest Acquisition. Growth capital spending in 2023 primarily includes Transco expansions, all of which are fully contracted with firm transportation agreements, projects supporting the Northeast G&P business and projects supporting growth in the Haynesville basin, including the Louisiana Energy


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

Gateway project. 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 reduce emissions, and meet legal, regulatory, and/or contractual commitments.

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

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 increases from inflation or 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;
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, 2022, as filed with the SEC on February 27, 2023.

Expansion Projects

Our ongoing major expansion projects include the following:

Transmission & Gulf of Mexico

Deepwater Shenandoah Project

In June 2021, we reached an agreement with two third-parties to provide offshore natural gas gathering and transportation services as well as onshore natural gas processing services. The project expands our existing Gulf of Mexico offshore infrastructure via a 5-mile offshore lateral pipeline from the Shenandoah platform to Discovery’s existing Keathley Canyon Connector pipeline, adds onshore processing facilities at Larose, Louisiana to handle the expected rich Shenandoah production, and the natural gas liquids will be fractionated and marketed at Discovery’s Paradis plant in Louisiana. We plan to place the project into service in the fourth quarter of 2024.

Deepwater Whale Project

In August 2021, we reached an agreement with two third-parties to provide offshore natural gas gathering and crude oil transportation services as well as onshore natural gas processing services. The project expands our existing Western Gulf of Mexico offshore infrastructure via a 26-mile gas lateral pipeline from the Whale platform to the existing Perdido gas pipeline and adds a new 125-mile oil pipeline from the Whale platform to our existing junction platform. We plan to place the project into service in the fourth quarter of 2024.


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

Regional Energy Access

In January 2023, we received approval from 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 a portion of the project into service as early as the fourth quarter of 2023, and the remainder of 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 July 2023, we received approval from 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 Virginia and North Carolina to delivery points in North Carolina. 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 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 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 first 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 2024, 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.

Alabama Georgia Connector

In April 2023, 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 our Station 85 pooling point in Alabama to customers in Georgia. 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 approximately 64 Mdth/d.

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,


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

including Transco, industrial markets, and growing LNG export demand along the Gulf Coast. This project is expected to go into service in the fourth quarter of 2024.

Haynesville Gathering Expansion

In February 2023, we announced our agreement with a third party to facilitate natural gas production growth in the Haynesville basin. We plan to construct a greenfield gathering system in support of the third party’s 26,000-acre dedication. The system, once constructed, will provide natural gas gathering services to the third party. The third party has also agreed to a long-term capacity commitment on our Louisiana Energy Gateway project.

Northeast G&P

Susquehanna Supply Hub Gathering Expansion

We have an agreement in place with a third party to facilitate natural gas production growth in the Susquehanna region. We plan to construct approximately 22 miles of gathering pipeline and associated incremental compression. The system, once constructed, will add incremental capacity of 320 MMcf/d and will provide natural gas gathering services to the third party. The project is expected to go into service in the fourth quarter of 2023.

Utica Shale Gathering Expansion

We have an agreement in place with a third party to facilitate natural gas production growth in the Utica region on our Cardinal gathering system. We are constructing approximately 30 miles of gathering pipeline and associated incremental compression. The system, once constructed, will add incremental capacity of 125 MMcf/d and will provide natural gas gathering services to the third party. The project is expected to go into service in the second half of 2023.


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, 2023, compared to the three and six months ended June 30, 2022. 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,
	2023		2022		$ Change*	% Change*		2023		2022		$ Change*	% Change*
	(Millions)							(Millions)
Revenues:
Service revenues	$	1,748	$	1,606	+142	+9	%	$	3,442	$	3,143	+299	+10	%
Service revenues – commodity consideration	27		86		-59	-69	%	63		163		-100	-61	%
Product sales	593		1,111		-518	-47	%	1,438		2,215		-777	-35	%
Net gain (loss) on commodity derivatives	115		(313)		+428	NM		621		(507)		+1,128	NM
Total revenues	2,483		2,490					5,564		5,014
Costs and expenses:
Product costs	421		857		+436	+51	%	974		1,660		+686	+41	%
Net processing commodity expenses	44		40		-4	-10	%	98		70		-28	-40	%
Operating and maintenance expenses	481		465		-16	-3	%	944		859		-85	-10	%
Depreciation and amortization expenses	515		506		-9	-2	%	1,021		1,004		-17	-2	%
Selling, general, and administrative expenses	161		160		-1	-1	%	337		314		-23	-7	%


Other (income) expense – net	(9)		(10)		-1	-10	%	(40)		(19)		+21	+111	%
Total costs and expenses	1,613		2,018					3,334		3,888
Operating income (loss)	870		472					2,230		1,126
Equity earnings (losses)	160		163		-3	-2	%	307		299		+8	+3	%

Other investing income (loss) – net	13		2		+11	NM		21		3		+18	NM
Interest expense	(306)		(281)		-25	-9	%	(600)		(567)		-33	-6	%
Other income (expense) – net	19		6		+13	NM		39		11		+28	NM
Income (loss) before income taxes	756		362					1,997		872
Less: Provision (benefit) for income taxes	175		(45)		-220	NM		459		73		-386	NM
Income (loss) from continuing operations	581		407					1,538		799
Income (loss) from discontinued operations	(87)		—		-87	NM		(87)		—		-87	NM
Net income (loss)	494		407					1,451		799
Less: Net income (loss) attributable to noncontrolling interests	34		7		-27	NM		64		19		-45	NM
Net income (loss) attributable to The Williams Companies, Inc.	$	460	$	400	+60	+15	%	$	1,387	$	780	+607	+78	%

- = 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, 2023 vs. three months ended June 30, 2022

Service revenues increased primarily due to higher volumes from the MountainWest and Trace Acquisitions, and the NorTex Asset Purchase, and higher gathering and processing volumes as well as higher rates due to rate escalations and annual cost of service rate redetermination for certain of our Northeast G&P operations, partially offset by lower rates driven by unfavorable commodity pricing at our West operations.

Service revenues – commodity consideration decreased primarily due to lower NGL prices and volumes. 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 decreased primarily due to lower natural gas and NGL marketing prices and volumes. These decreases were substantially offset by lower prices and volumes for natural gas marketing associated purchases. 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. Product sales from our upstream operations decreased primarily due to lower commodity prices and lower NGL production volumes, offset by higher natural gas production volumes. Product sales also decreased due to lower prices and volumes related to our equity NGL sales.

Net gain (loss) on commodity derivatives includes realized and unrealized gains and losses from derivative instruments reflected within Total revenues in our Gas & NGL Marketing Services, West, and Other segments. We experience significant earnings volatility from the fair value accounting required for the derivatives used to hedge a portion of the economic value of the underlying transportation and storage portfolio as well as upstream related production. However, the unrealized fair value measurement gains and losses are generally offset by valuation changes in the economic value of the underlying production or transportation and storage contracts, which is not recognized until the underlying transaction occurs.

Product costs decreased primarily due to lower prices and volumes associated with our NGL marketing activities, and lower prices and volumes associated with NGLs acquired as commodity consideration related to our equity NGL production activities.

Net processing commodity expenses increased primarily due to the impact of net unrealized and realized losses on derivatives for processing plant shrink gas purchases, partially offset by lower prices and volumes for natural gas purchases associated with our equity NGL production activities.

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, Product sales and net realized gains and losses on commodity derivatives at our Other segment reflecting sales related to our oil and gas producing properties comprise Net realized product sales and are excluded from our Commodity margins. See Results of Operations— Period-Over-Period Operating Results - Segments for additional discussion of Commodity margins and Net realized product sales on a segment basis.

Operating and maintenance expenses increased primarily due to higher operating costs, including increased costs associated with the 2023 MountainWest Acquisition, the 2022 Trace Acquisition, and the NorTex Asset Purchase, partially offset by a favorable change due to the timing and scope of maintenance activities.

Depreciation and amortization expenses increased primarily related to our upstream assets, and assets acquired in the 2023 MountainWest Acquisition, the 2022 Trace Acquisition, and the NorTex Asset Purchase. The increase is partially offset by lower amortization of intangibles related to our 2021 Sequent Acquisition.

The change in Equity earnings (losses) resulted from a decrease at Laurel Mountain, partially offset by an increase at RMM.


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

Interest expense changed unfavorably primarily due to our March 2023 debt issuance and MountainWest’s long-term debt (see Note 6 – Debt and Banking Arrangements of Notes to Consolidated Financial Statements).

Provision (benefit) for income taxes changed unfavorably primarily due to the absence of a benefit associated with the release of valuation allowances on deferred income tax assets and federal income tax settlements both recorded in the prior year, and 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.

Income (loss) from discontinued operations in 2023 includes a pre-tax charge of $115 million to increase the related accrued liability associated with our Alaska refinery contamination litigation, partially offset by the related income tax effect. See Note 9 – Contingent Liabilities of Notes to Consolidated Financials Statements for further discussion.

The unfavorable change in Net income (loss) attributable to noncontrolling interests is primarily due to higher results at Cardinal.

Six months ended June 30, 2023 vs. six months ended June 30, 2022

Service revenues increased primarily due to higher volumes from the MountainWest and Trace Acquisitions, and the NorTex Asset Purchase, as well as higher gathering, processing, and transportation volumes, and higher rates due to rate escalations and annual cost of service rate redetermination for certain Northeast G&P operations, partially offset by lower rates driven by unfavorable commodity pricing at our West operations.

Product sales decreased primarily due to lower natural gas and NGL marketing prices and volumes. These decreases were substantially offset by lower prices and volumes for natural gas marketing associated purchases. 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. Product sales from our upstream operations decreased due to lower commodity prices and lower NGL and crude oil production volumes, offset by higher natural gas production volumes. Product sales also decreased due to lower prices and volumes related to our equity NGL sales.

Product costs decreased primarily due to lower prices and volumes associated with our NGL marketing activities, and lower volumes and prices associated with NGLs acquired as commodity consideration related to our equity NGL production activities.

Net processing commodity expenses increased primarily due to the impact of net unrealized and realized losses on derivatives for processing plant shrink gas purchases, partially offset by lower volumes and prices for natural gas purchases associated with our equity NGL production activities.

Operating and maintenance expenses increased primarily due to higher operating costs, including increased costs associated with the 2023 MountainWest Acquisition, the 2022 Trace Acquisition, and the NorTex Asset Purchase, as well as the increased production volumes from our upstream operations and increased scope and timing of activities.


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

related depreciation at Transco (offset in Other (income) expense – net within Operating income (loss) resulting in no net impact on our results of operations).

Selling, general, and administrative expenses increased primarily due to acquisition and transition-related costs associated with the MountainWest Acquisition.

Other (income) expense – net within Operating income (loss) changed favorably primarily due to a gain related to a contract settlement in 2023, and a favorable change associated with regulatory liabilities established for the impacts of deferred income taxes at Northwest Pipeline, partially offset by a decrease in the deferral of ARO-related depreciation (offset in Depreciation and amortization expenses, resulting in no net impact on our results of operations).

The change in Equity earnings (losses) resulted from an increase at RMM and OPPL, partially offset by a decrease at Laurel Mountain.

Interest expense changed unfavorable primarily due to our March 2023 debt issuance and MountainWest's long-term debt (see Note 6 – Debt and Banking Arrangements of Notes to Consolidated Financial Statements).

The favorable change in Other income (expense) – net below Operating income (loss) reflects an increase in allowance for equity funds used during construction (equity AFUDC).

The unfavorable change in Net income (loss) attributable to noncontrolling interests is primarily due to higher results at the Northeast JV and Cardinal.

Period-Over-Period Operating Results - Segments

We evaluate segment operating performance based upon Modified EBITDA. Note 10 – 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.


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

Transmission & Gulf of Mexico


	Three Months Ended June 30,				Six Months Ended June 30,
	2023		2022		2023		2022
	(Millions)
Service revenues	$	956	$	867	$	1,896	$	1,741
Service revenues – commodity consideration (1)	6		22		18		43
Product sales (1)	79		113		134		213
Net realized gain (loss) on commodity derivatives - product sales (1)	1		—		1		—
Segment revenues	1,042		1,002		2,049		1,997

Product costs (1)	(76)		(109)		(129)		(209)
Net processing commodity expenses (1)	(2)		(15)		(6)		(21)
Other segment costs and expenses	(281)		(271)		(569)		(511)

Proportional Modified EBITDA of equity-method investments	48		45		101		93
Transmission & Gulf of Mexico Modified EBITDA	$	731	$	652	$	1,446	$	1,349

Commodity margins	$	8	$	11	$	18	$	26

(1)Included as a component of Commodity margins.

Three months ended June 30, 2023 vs. three months ended June 30, 2022

Transmission & Gulf of Mexico 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 $60 million increase due to the acquisition of MountainWest in February 2023 primarily in transportation and storage revenues;
A $15 million increase due to the NorTex Asset Purchase in August 2022 primarily in storage and transportation revenues;
A $15 million increase in the Eastern Gulf Coast region primarily due to higher production handling volumes from new wells at Devils Tower;
A $7 million increase in Transco’s and Northwest Pipeline’s revenues associated with park and loan services; partially offset by
A $5 million decrease due to lower rates from the FERC rate case settlement effective January 1, 2023, at Northwest Pipeline.

Other segment costs and expenses increased primarily due to higher operating and administrative costs including higher operating, acquisition, and transition costs related to our MountainWest Acquisition and NorTex Asset Purchase. This increase is partially offset by favorable changes associated with employee-related costs and lower costs related to timing and scope of general maintenance activities at Transco; regulatory liabilities established for the impacts of deferred income taxes at Northwest Pipeline and allowance for equity funds used during construction as a result of increased capital expenditures at Transco.


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

Six months ended June 30, 2023 vs. six months ended June 30, 2022

Transmission & Gulf of Mexico 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 $93 million increase due to the acquisition of MountainWest in February 2023 primarily in transportation and storage revenues;
A $28 million increase due to the NorTex Asset Purchase in August 2022 primarily in storage and transportation revenues;
A $20 million increase in the Eastern Gulf Coast region primarily due to higher production handling volumes from new wells at Devils Tower;
A $17 million increase in Transco’s and Northwest Pipeline’s revenues associated with park and loan services; partially offset by
A $9 million decrease due to lower rates from the FERC rate case settlement effective January 1, 2023, at Northwest Pipeline.

Other segment costs and expenses increased primarily due to higher operating and administrative costs including higher operating, acquisition, and transition costs related to our MountainWest Acquisition and NorTex Asset Purchase and an unfavorable change in the deferral of ARO-related depreciation at Transco. These increases are partially offset by favorable changes associated with regulatory liabilities established for the impacts of deferred income taxes at Northwest Pipeline and allowance for equity funds used during construction as a result of increased capital expenditures at Transco.

Northeast G&P


	Three Months Ended June 30,				Six Months Ended June 30,
	2023		2022		2023		2022
	(Millions)
Service revenues	$	489	$	411	$	943	$	791
Service revenues – commodity consideration (1)	(3)		3		3		10
Product sales (1)	28		34		77		70
Segment revenues	514		448		1,023		871

Product costs (1)	(25)		(34)		(77)		(71)
Net processing commodity expenses (1)	(1)		(2)		1		(2)

Other segment costs and expenses	(132)		(136)		(264)		(254)

Proportional Modified EBITDA of equity-method investments	159		174		302		324
Northeast G&P Modified EBITDA	$	515	$	450	$	985	$	868

Commodity margins	$	(1)	$	1	$	4	$	7

(1)Included as a component of Commodity margins.

Three months ended June 30, 2023 vs. three months ended June 30, 2022

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


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

Service revenues increased primarily due to:

*•*A $38 million increase in gathering revenues in the Utica Shale region primarily related to higher rates resulting from annual cost of service rate redetermination as well as higher volumes;

*•*A $22 million increase in revenues at the Northeast JV primarily related to higher gathering, processing, transportation, and fractionation volumes as well as higher processing rates;

A $20 million increase in gathering revenues at Susquehanna Supply Hub primarily related to escalated rates as well as higher volumes.

Proportional Modified EBITDA of equity-method investments decreased at Laurel Mountain primarily due to lower commodity-based rates and MVC. The decrease was partially offset by an increase at Blue Racer primarily driven by higher volumes.

Six months ended June 30, 2023 vs. six months ended June 30, 2022

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

Service revenues increased primarily due to:

*•*A $70 million increase in revenues at the Northeast JV primarily related to higher processing, gathering, transportation, and fractionation volumes as well as higher processing rates;

A $59 million increase in gathering revenues in the Utica Shale region primarily related to higher rates resulting from annual cost of service rate redetermination as well as higher volumes;
A $23 million increase in gathering revenues at Susquehanna Supply Hub primarily related to escalated rates as well as higher volumes.

Other segment costs and expenses increased primarily due to higher operating expenses related to the scope and timing of activities.

Proportional Modified EBITDA of equity-method investments decreased at Laurel Mountain primarily due to lower commodity-based rates and MVC, and a decrease at Aux Sable Liquid Products LP. The decrease was partially offset by an increase at Blue Racer primarily driven by higher volumes, as well as an increase at Appalachia Midstream Investments primarily driven by higher volumes offset by lower gathering rates resulting from annual cost of service rate redetermination.


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

West


	Three Months Ended June 30,				Six Months Ended June 30,
	2023		2022		2023		2022
	(Millions)
Service revenues	$	358	$	383	$	714	$	714
Service revenues – commodity consideration (1)	24		61		42		110
Product sales (1)	85		252		175		439

Net realized gain (loss) on commodity derivatives – service revenues	29		(5)		68		(5)
Net realized gain (loss) on commodity derivatives – product sales (1)	4		(4)		4		(9)
Net realized gain (loss) on commodity derivatives	33		(9)		72		(14)

Segment revenues	500		687		1,003		1,249

Product costs (1)	(84)		(247)		(169)		(429)
Net processing commodity expenses (1)	(11)		(37)		(58)		(63)
Other segment costs and expenses	(136)		(146)		(236)		(267)


Proportional Modified EBITDA of equity-method investments	43		31		76		58
West Modified EBITDA	$	312	$	288	$	616	$	548

Commodity margins	$	18	$	25	$	(6)	$	48
_________
(1) Included as a component of Commodity margins.

Three months ended June 30, 2023 vs. three months ended June 30, 2022

West Modified EBITDA increased primarily due to favorable Net realized gain (loss) on commodity derivatives – service revenues, higher Proportional Modified EBITDA of equity-method investments, and lower Other segment costs and expenses, partially offset by lower Service revenues.

Service revenues decreased primarily due to:

A $38 million decrease in the Barnett Shale region primarily due to lower gathering rates driven by unfavorable commodity pricing; partially offset by
A $17 million increase in the Haynesville Shale region primarily associated with higher gathering volumes including from the Trace Acquisition in April 2022 and increased producer activity, partially offset by lower rates driven by unfavorable commodity pricing.

Net realized gain (loss) on commodity derivatives – service revenues reflects a favorable change in settled commodity prices relative to our natural gas hedge positions.

Other segment costs and expenses decreased primarily due to lower operating costs and the absence of acquisition-related costs associated with the Trace Acquisition in 2022.

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


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

Six months ended June 30, 2023 vs. six months ended June 30, 2022

West Modified EBITDA increased primarily due to favorable Net realized gain (loss) on commodity derivatives – service revenues, lower Other segment costs and expenses, higher Proportional Modified EBITDA of equity-method investments, partially offset by lower Commodity margins.

Service revenues were unchanged primarily due to:

A $64 million increase in the Haynesville Shale region primarily associated with higher gathering volumes including from the Trace Acquisition in April 2022 and increased producer activity, partially offset by lower rates driven by unfavorable commodity pricing; partially offset by
A $45 million decrease in the Barnett Shale region primarily due to lower gathering rates driven by unfavorable commodity pricing, partially offset by higher gathering volumes from increased producer activity;
A $9 million decrease in the Piceance region primarily due to lower gathering and processing volumes driven by natural production rate declines;
An $8 million decrease in the Wamsutter region primarily due to lower volumes associated with weather-related events in first-quarter 2023.

Net realized gain (loss) on commodity derivatives – service revenues reflects a favorable change in settled commodity prices relative to our natural gas hedge positions.

Commodity margins decreased primarily due to a $44 million decrease from our equity NGLs, driven by unfavorable net realized pricing for equity NGL sales and shrink gas purchases, as well as lower volumes processed under commodity-consideration contracts.

Other segment costs and expenses decreased primarily due to favorable contract settlements in first-quarter 2023, a favorable change in our net imbalance liability due to changes in pricing, the absence of acquisition-related costs associated with the Trace Acquisition in 2022, partially offset by higher operating expenses related to operations acquired in the Trace Acquisition.

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


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

Gas & NGL Marketing Services


	Three Months Ended June 30,				Six Months Ended June 30,
	2023		2022		2023		2022
	(Millions)
Service revenues	$	—	$	—	$	1	$	1
Product sales (1)	427		872		1,102		1,840

Net realized gain (loss) from derivative instruments (1)	(45)		(16)		72		(72)
Net unrealized gain (loss) from derivative instruments	123		(297)		461		(356)
Net gain (loss) on commodity derivatives	78		(313)		533		(428)

Segment revenues	505		559		1,636		1,413
Net unrealized gain (loss) from derivative instruments within Net processing commodity expenses	(29)		9		(34)		11
Product costs (1)	(384)		(833)		(911)		(1,645)
Other segment costs and expenses	(24)		(17)		(56)		(48)
Gas & NGL Marketing Services Modified EBITDA	$	68	$	(282)	$	635	$	(269)

Commodity margins	$	(2)	$	23	$	263	$	123

(1) Included as a component of Commodity margins.

Three months ended June 30, 2023 vs. three months ended June 30, 2022

Gas & NGL Marketing Services Modified EBITDA increased primarily due to a favorable change in Net unrealized gain (loss) from derivative instruments within Segment revenues and Net processing commodity expenses, partially offset by lower Commodity margins.

Commodity margins decreased $25 million primarily due to:

*•*A $27 million decrease in our NGL marketing margins including losses on sale of inventory in 2023 compared to gains in 2022 driven by an unfavorable change in NGL prices; partially offset by

A $2 million increase from our natural gas marketing operations including $7 million of higher natural gas transportation capacity marketing margins due to favorable net realized pricing spreads. The increase is partially offset by a decrease of $14 million lower natural gas storage marketing margins primarily due to realized derivative losses, partially reduced by $9 million benefit due to the absence of a lower of cost or net realizable value adjustment in 2022.

Net unrealized gain (loss) from derivative instruments within Segment revenues and Net processing commodity expenses relates to derivative contracts that are not designated as hedges for accounting purposes. The change from 2022 is primarily due to a change in forward commodity prices relative to our hedge positions in 2023 compared to 2022.

Six months ended June 30, 2023 vs. six months ended June 30, 2022


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

Commodity margins increased $140 million primarily due to:

*•*A $182 million increase from our natural gas marketing operations including $92 million of higher natural gas transportation capacity marketing margins due to favorable net realized pricing spreads and $90 million of higher natural gas storage marketing margins primarily driven by lower cost of storage inventory in the first quarter of 2023 resulting from a fourth-quarter 2022 lower of cost or net realizable value inventory adjustment. The increase in our natural gas storage marketing margins also includes the absence of a $15 million charge related to the remaining recognition of a purchase accounting inventory fair value adjustment in 2022, partially offset by an unfavorable change of $6 million lower of cost or net realizable value adjustment; partially offset by

*•*A $42 million decrease in our NGL marketing margins including losses on sale of inventory in 2023 compared to gains in 2022 driven by an unfavorable change in NGL prices.

Other


	Three Months Ended June 30,				Six Months Ended June 30,
	2023		2022		2023		2022
	(Millions)
Service revenues	$	5	$	7	$	8	$	16
Product sales (1)	83		180		185		284

Net realized gain (loss) from derivative instruments (1)	14		(38)		32		(46)
Net unrealized gain (loss) from derivative instruments	(11)		47		(17)		(19)
Net gain (loss) on commodity derivatives	3		9		15		(65)

Segment revenues	91		196		208		235

Other segment costs and expenses	(49)		(57)		(92)		(91)
Proportional Modified EBITDA of equity-method investments	(1)		—		(1)		—
Other Modified EBITDA	$	41	$	139	$	115	$	144

Net realized product sales	$	97	$	142	$	217	$	238

(1) Included as a component of Net realized product sales.

Three months ended June 30, 2023 vs. three months ended June 30, 2022

Other Modified EBITDA decreased primarily due to lower results from our upstream operations which included the following:

*•*A $58 million unfavorable change in Net unrealized gain (loss) from derivative instruments due to a change in forward commodity prices relative to our hedge positions in 2023 compared to 2022;

*•*A $45 million decrease in Net realized product sales primarily due to lower net realized commodity prices, partially offset by higher sales associated with increased production volumes. Higher natural gas production


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

volumes from new wells in our Haynesville Shale region were partially offset by lower natural gas and NGL production volumes in our Wamsutter region driven by the impact of severe winter weather in 2023.

Six months ended June 30, 2023 vs. six months ended June 30, 2022

Other Modified EBITDA decreased primarily due to lower results from our upstream operations which included the following:

*•*A $21 million decrease in Net realized product sales primarily due to lower net realized commodity prices, partially offset by higher sales associated with increased production volumes. Higher natural gas production volumes from new wells in our Haynesville Shale region were partially offset by lower natural gas, NGL, and crude oil production volumes in our Wamsutter region driven by the impact of severe winter weather in 2023;

An increase in Other segment costs and expenses primarily due to the increased production volumes from our upstream operations.


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 2023 are currently expected to be in a range from $1.6 billion to $1.9 billion, excluding the MountainWest Acquisition discussed below. Growth capital spending in 2023 primarily includes Transco expansions, all of which are fully contracted with firm transportation agreements, projects supporting the Northeast G&P business and projects supporting growth in the Haynesville basin, including the Louisiana Energy Gateway project. 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 reduce emissions, and meet legal, regulatory, and/or contractual commitments. We intend to fund substantially all planned 2023 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.

On February 14, 2023, we acquired 100 percent of MountainWest which includes FERC-regulated interstate natural gas pipeline systems and natural gas storage capacity, for $1.08 billion of cash and retaining $430 million outstanding principal amount of MountainWest’s long-term debt. The acquisition was funded with available sources of short-term liquidity.

During the first quarter of 2023, we issued $1.5 billion of long-term debt, a portion of which we used to pay down our commercial paper outstanding. As of June 30, 2023, we have approximately $2.88 billion of long-term debt due within one year. 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.


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

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 2023. 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
			Gas & NGL Marketing Services payments for transportation and storage capacity and gas supply
			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, 2023, we have $21.5 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 June 30, 2023, we had a working capital deficit of $2.7 billion, including cash and cash equivalents and long-term debt due within one year. Our available liquidity is as follows:


Available Liquidity	June 30, 2023
	(Millions)
Cash and cash equivalents	$	551
Capacity available under our $3.75 billion credit facility, less amounts outstanding under our $3.5 billion commercial paper program (1)	3,750
	$	4,301

(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 June 30, 2023. Through June 30, 2023, the highest amount outstanding under our commercial paper program and credit facility during 2023 was $730 million. At June 30, 2023, we were in compliance with the financial covenants associated with our credit facility.


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

Dividends

We increased our regular quarterly cash dividend to common stockholders by approximately 5.3 percent from the $0.425 per share paid in each quarter of 2022, to $0.4475 per share paid in March and June 2023.

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 in the Consolidated Statement of Cash Flows (see Notes to Consolidated Financial Statements for the Notes referenced in the table):


	Cash Flow	Six Months Ended June 30,
	Category	2023		2022
		(Millions)
Sources of cash and cash equivalents:
Net cash provided (used) by operating activities	Operating	$	2,891	$	2,180
Proceeds from long-term debt	Financing	1,503		5
Proceeds from (payments of) commercial paper - net	Financing	—		1,037



Uses of cash and cash equivalents:
Capital expenditures	Investing	(1,155)		(606)
Common dividends paid	Financing	(1,091)		(1,035)

Purchases of businesses, net of cash acquired (see Note 3)	Investing	(1,053)		(933)
Proceeds from (payments of) commercial paper - net	Financing	(352)		—
Purchases of treasury stock	Financing	(130)		—
Dividends and distributions paid to noncontrolling interests	Financing	(112)		(95)
Purchases of and contributions to equity-method investments	Investing	(69)		(100)
Payments of long-term debt	Financing	(14)		(2,012)

Other sources / (uses) – net	Financing and Investing	(19)		12
Increase (decrease) in cash and cash equivalents		$	399	$	(1,547)

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, Net unrealized (gain) loss from derivative instruments, Inventory write-downs, and Amortization of stock-based awards.

Our Net cash provided (used) by operating activities for the six months ended June 30, 2023 increased from the same period in 2022 primarily due to higher operating income (excluding noncash items as previously discussed), net favorable changes in operating working capital, and improved derivative margin requirements.

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