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 infrastructure company focused on connecting North America’s significant hydrocarbon resource plays to growing markets for natural gas and NGLs through our gas pipeline and midstream business. 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. Rates are established in accordance with the FERC’s ratemaking process. 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 Sequent. All remaining business activities, including our recently acquired upstream operations, as well as 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 (we previously effectively owned a 29 percent indirect interest in Blue Racer through our 58 percent equity-method investment in Caiman II until acquiring a controlling interest of Caiman II in November 2020 and the remaining interest in September 2021), and Appalachia Midstream Investments, a wholly owned subsidiary that owns equity-method investments with an approximate average 66 percent interest in multiple gas gathering systems in the Marcellus Shale region.
West is comprised of our gas gathering, processing, and treating operations in the Rocky Mountain region of Colorado and Wyoming, the Barnett Shale region of north-central Texas, the Eagle Ford Shale region of south Texas, the Haynesville Shale region of northwest Louisiana, and the Mid-Continent region which includes the Anadarko and Permian basins. This segment also includes our NGL and natural gas marketing business (excluding the activities within the Sequent segment described below), 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.


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Sequent includes the operations of Sequent Energy Management, L.P. and Sequent Energy Canada, Corp. (collectively, Sequent) acquired on July 1, 2021. Sequent focuses on risk management and the marketing, trading, storage, and transportation of natural gas for a diverse set of natural gas utilities, municipalities, power generators, and producers, and moves gas to markets through transportation and storage agreements on strategically positioned assets, including along our Transco system.

Dividends

In September 2021, we paid a regular quarterly dividend of $0.41 per share.

Overview of Nine Months Ended September 30, 2021

Net income (loss) attributable to The Williams Companies, Inc., for the nine months ended September 30, 2021, increased $800 million compared to the nine months ended September 30, 2020, reflecting:

The absence of $938 million of Impairment of equity-method investments in the first quarter of 2020;
A $190 million favorable change in our commodity margins primarily due to increases in net realized sales prices and volumes. Our commodity margins are comprised of the net sum of Service revenues – commodity consideration, Product sales, net realized gains and losses on our commodity derivatives, Product costs, and Processing commodity expenses; however, Product sales at our Other segment reflect sales related to our recently acquired upstream operations and are excluded from our commodity margins;
A $210 million increase in Product sales net of realized losses on our commodity derivatives at our Other segment reflecting net realized sales related to our recently acquired upstream operations;
The absence of $187 million of Impairment of goodwill in 2020, of which $65 million was attributable to noncontrolling interests;
A $187 million increase in equity earnings, primarily due to the absence of our $78 million share of an impairment of goodwill recorded by an equity-method investee in 2020 and higher volumes from certain of our Northeast G&P investments.

These favorable changes were partially offset by:

$315 million change in net unrealized losses on commodity derivatives discussed below;
A $289 million unfavorable change in provision for income taxes, driven by higher pre-tax earnings;
$155 million of higher Operating and maintenance expenses primarily due to the inclusion of our recently acquired upstream operations at our Other segment and higher employee-related expenses;

*•*A $103 million unfavorable change in Depreciation and amortization expenses.

The net unrealized losses on commodity derivatives include $277 million related to derivative contracts within the Sequent segment that are not designated as hedges for accounting purposes. Sequent 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 portfolio. However, the unrealized fair value measurement gains and losses are offset by valuation changes in the economic value of the underlying transportation and storage portfolio, which is not accounted for on a fair value basis.

The net unrealized losses on commodity derivatives also includes the impact from derivative contracts from certain of our other businesses that are not designated as hedges for accounting purposes.

The following discussion and analysis of results of operations and financial condition and liquidity 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 dated February 24, 2021.


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Recent Developments

Share Repurchase Program

In September 2021, our Board of Directors authorized a new share repurchase program with a maximum dollar limit of $1.5 billion. Repurchases may be made from time to time in the open market, by block purchases, in privately negotiated transactions or in such other manner as determined by our management. Our management will also determine the timing and amount of any repurchases based on market conditions and other factors. The share repurchase program does not obligate us to acquire any particular amount of common stock, and it may be suspended or discontinued at any time. This stock repurchase program does not have an expiration date. There were no repurchases under the program through September 30, 2021.

Sequent Acquisition

In July 2021, we completed the acquisition of 100 percent of Sequent Energy Management, L.P. and Sequent Energy Canada, Corp. (collectively, Sequent). Total consideration for this acquisition was $159 million, which included $109 million related to working capital. Of the total consideration, $134 million of cash was paid in the third quarter of 2021 and $25 million was accrued in the same period for post-closing working capital adjustments. Sequent focuses on risk management and the marketing, trading, storage, and transportation of natural gas for a diverse set of natural gas utilities, municipalities, power generators, and producers, and moves gas to markets through transportation and storage agreements on strategically positioned assets, including along our Transco system. The addition of Sequent complements the current geographic footprint of our core pipeline transportation and storage business and is expected to enhance our gas marketing capabilities and expand the suite of services we can provide to our existing midstream customers.

Upstream Joint Ventures

In the third quarter of 2021, we cross-conveyed certain of our oil and gas properties in the Wamsutter field (see Note 14 – Segment Disclosures of Notes to Consolidated Financial Statements) to a venture along with certain oil and gas properties cross-conveyed by a third-party operator in the region. The combined properties consist of over 1.2 million net acres and an interest in over 3,500 wells. Under the terms of the agreement, our partner owns a 25 percent undivided interest in each well’s working interest percentage, and we own a 75 percent undivided interest in each well’s working interest percentage.

In August 2021, we agreed to sell 50 percent of certain of our existing wells and wellbore rights in the South Mansfield area of the Haynesville Shale region to a third party (see Note 14 – Segment Disclosures of Notes to Consolidated Financial Statements), in a strategic effort to develop the acreage, thereby enhancing the value of our midstream natural gas infrastructure. Under the agreement, the third party will operate the upstream position and develop the undeveloped acreage, and we will continue to operate and retain full ownership of our midstream assets. We will additionally retain ownership in the undeveloped acreage until certain acreage earning and carried interest hurdles are met, at which time remaining undeveloped acreage will be conveyed to the third party resulting in their 75 percent and our 25 percent ownership.

Expansion Project Update

Transmission & Gulf of Mexico

Southeastern Trail

In October 2019, we received approval from the FERC to expand Transco’s existing natural gas transmission system to provide incremental firm transportation capacity from the Pleasant Valley interconnect with Dominion’s Cove Point Pipeline in Virginia to the Station 65 pooling point in Louisiana. We placed 230 Mdth/d of capacity under the project into service in the fourth quarter of 2020, and the project was fully in service on January 1, 2021. In total, the project increased capacity by 296 Mdth/d.


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COVID-19

The outbreak of COVID-19 has severely impacted global economic activity and caused significant volatility and negative pressure in financial markets. We continue to monitor the COVID-19 pandemic and have taken steps intended to protect the safety of our customers, employees, and communities, and to support the continued delivery of safe and reliable service to our customers and the communities we serve. Our financial condition, results of operations, and liquidity have not been materially impacted by direct effects of COVID-19.

Company Outlook

Our strategy is to provide large-scale 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, operational excellence, and customer satisfaction. We believe that accomplishing these goals will position us to deliver safe and reliable service to our customers and an attractive return to our shareholders. Our business plan for 2021 includes a continued focus on earnings and cash flow growth, while continuing to improve leverage metrics and control operating costs.

In 2021, our operating results are expected to benefit from growth in our Northeast G&P gathering and processing volumes. We also anticipate increases from recently completed Transco expansion projects and higher Gulf of Mexico results despite recent hurricane related shut-ins. Our results also benefited from the overall net favorable impact of unusually high natural gas prices in the first quarter associated with Winter Storm Uri and more recently a strong commodity price environment, including contributions from our upstream properties. These increases will be partially offset by decreases in the West, including a reduction in NGL transportation volumes on OPPL and certain fee reductions in the Haynesville area in exchange for future value in upstream natural gas properties. We also expect an increase in expenses, including higher incentive compensation costs and operating taxes.

Our growth capital and investment expenditures in 2021 are expected to be in a range from $1.0 billion to $1.2 billion. Growth capital spending in 2021 includes Transco expansions, all of which are fully contracted with firm transportation agreements, projects supporting the Northeast G&P business, midstream opportunities in the Haynesville area in the West segment, and the recent acquisitions of certain upstream operations and Sequent. 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 further downturns in financial markets and commodity prices, as well as impact demand for natural gas and related products;
Opposition to, and legal 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 further industry downturns, including increased interest rates;


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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, 2020, as filed with the SEC on February 24, 2021, as supplemented by the disclosures in Part II, Item 1A. of this Quarterly Report on Form 10-Q for the quarter ended September 30, 2021.

We seek to maintain a strong financial position and liquidity, as well as manage a diversified portfolio of energy infrastructure assets that continue to serve key growth markets and supply basins in the United States.

Expansion Projects

Our ongoing major expansion projects include the following:

Transmission & Gulf of Mexico

Leidy South

In July 2020, we received approval from the FERC for the project to expand Transco’s existing natural gas transmission system and also extend its system through a capacity lease with National Fuel Gas Supply Corporation that will enable us to provide incremental firm transportation from Clermont, Pennsylvania and from the Zick interconnection on Transco’s Leidy Line to the River Road regulating station in Lancaster County, Pennsylvania. We placed 125 Mdth/d of capacity under the project into service in the fourth quarter of 2020, and in September and October of 2021, we placed approximately 382 Mdth/d of additional capacity into service. We plan to place the remainder of the project into service by year-end 2021. The project is expected to increase capacity by 582 Mdth/d.

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 2023, assuming timely receipt of all necessary regulatory approvals. The project is expected to increase capacity by 829 Mdth/d.


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Results of Operations

Consolidated Overview

The following table and discussion is a summary of our consolidated results of operations for the three and nine months ended September 30, 2021, compared to the three and nine months ended September 30, 2020. The results of operations by segment are discussed in further detail following this consolidated overview discussion.


	Three Months Ended September 30,							Nine Months Ended September 30,
	2021		2020		$ Change*	% Change*		2021		2020		$ Change*	% Change*
	(Millions)							(Millions)
Revenues:
Service revenues	$	1,506	$	1,479	+27	+2	%	$	4,418	$	4,399	+19	—	%
Service revenues – commodity consideration	64		40		+24	+60	%	164		93		+71	+76	%
Product sales	1,296		418		+878	NM		3,229		1,139		+2,090	+183	%
Net gain (loss) on commodity derivatives	(391)		(4)		-387	NM		(441)		(4)		-437	NM
Total revenues	2,475		1,933					7,370		5,627
Costs and expenses:
Product costs	1,043		380		-663	-174	%	2,672		1,047		-1,625	-155	%
Processing commodity expenses	28		21		-7	-33	%	67		49		-18	-37	%
Operating and maintenance expenses	409		336		-73	-22	%	1,148		993		-155	-16	%
Depreciation and amortization expenses	487		426		-61	-14	%	1,388		1,285		-103	-8	%
Selling, general, and administrative expenses	152		114		-38	-33	%	389		354		-35	-10	%

Impairment of goodwill	—		—		—	—	%	—		187		+187	+100	%
Other (income) expense – net	1		15		+14	+93	%	12		28		+16	+57	%
Total costs and expenses	2,120		1,292					5,676		3,943
Operating income (loss)	355		641					1,694		1,684
Equity earnings (losses)	157		106		+51	+48	%	423		236		+187	+79	%
Impairment of equity-method investments	—		—		—	—	%	—		(938)		+938	+100	%
Other investing income (loss) – net	2		2		—	—	%	6		6		—	—	%
Interest expense	(292)		(292)		—	—	%	(884)		(882)		-2	—	%
Other income (expense) – net	4		(23)		+27	NM		4		(14)		+18	NM
Income (loss) before income taxes	226		434					1,243		92
Less: Provision (benefit) for income taxes	53		111		+58	+52	%	313		24		-289	NM


Net income (loss)	173		323					930		68
Less: Net income (loss) attributable to noncontrolling interests	8		14		+6	+43	%	35		(27)		-62	NM
Net income (loss) attributable to The Williams Companies, Inc.	$	165	$	309				$	895	$	95

- = 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.


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Three months ended September 30, 2021 vs. three months ended September 30, 2020

Service revenues increased primarily due to higher transportation fee revenues associated with expansion projects placed in service at Transco in 2020 and 2021.

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 prices and volumes associated with our marketing activities, and higher prices partially offset by lower volumes related to our equity NGL sales activities. This increase also includes our recently acquired upstream operations, as well as our Sequent segment. Marketing sales for Sequent are netted with its product costs within Product sales.

Net gain (loss) on commodity derivatives includes realized and unrealized gains and losses from derivative instruments. The unfavorable change primarily reflects unrealized losses in our Sequent segment, as well as the impact from derivative contracts from certain of our other businesses.

Product costs increased primarily due to higher prices and volumes for our marketing activities, as well as higher NGL prices associated with volumes acquired as commodity consideration related to our equity NGL production activities.

The net sum of Service revenues – commodity consideration, Product sales, Product costs, Processing commodity expenses, and net realized gains and losses on commodity derivatives comprise our commodity margins. However, Product sales at our Other segment reflect sales related to our oil and gas producing properties and are excluded from our commodity margins.

Operating and maintenance expenses increased primarily due to the inclusion of our recently acquired upstream operations, and higher employee-related expenses, which include increased incentive compensation costs and the absence of a 2020 favorable impact of a change in an employee benefit policy.

Depreciation and amortization expenses increased primarily due to the amortization of intangible assets resulting from Sequent business combination accounting, the inclusion of our recently acquired upstream operations, as well as reduced estimated useful lives for certain facilities in our West segment expected to be decommissioned during 2021.

Selling, general, and administrative expenses increased primarily due to higher employee-related expenses, which include increased incentive compensation costs and expenses associated with the Sequent acquisition, as well as higher expenses for various corporate costs.

Equity earnings (losses) changed favorably primarily due to increases at Appalachia Midstream Investments, Laurel Mountain, and Aux Sable.

The favorable change in Other income (expense) – net below Operating income (loss) includes higher allowance for equity funds used during construction (equity AFUDC) and the absence of a 2020 write-off of a regulatory asset related to a cancelled project.

Provision (benefit) for income taxes changed favorably primarily due to lower pre-tax income. See Note 6 – 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.

Nine months ended September 30, 2021 vs. nine months ended September 30, 2020

Service revenues increased primarily due to higher transportation fee revenues associated with expansion projects placed in service at Transco in 2020 and 2021, higher revenue associated with reimbursable electricity expenses, higher processing and fractionation revenues in our Northeast G&P segment, and an increase associated


Management’s Discussion and Analysis (Continued)			T able of Contents

with Norphlet. This increase was partially offset by lower volumes driven by production declines, the impact of which is substantially offset by higher MVC revenue, and lower deferred revenue amortization, as well as the absence of a temporary volume deficiency fee from a customer in our West segment. Additional offsets include lower deferred revenue amortization and lower volumes primarily from producer operational issues, both in the Transmission & Gulf of Mexico segment.

Product sales increased primarily due to higher prices and volumes associated with our marketing activities, and the inclusion of our recently acquired upstream operations, as well as our Sequent segment. This increase also includes higher prices related to our equity NGL sales activities. Marketing sales for Sequent are netted with its product costs within Product sales.

Product costs increased primarily due to higher prices and volumes associated with our marketing activities, as well as higher NGL prices associated with volumes acquired as commodity consideration related to our equity NGL production activities.

Processing commodity expenses increased primarily due to higher prices for natural gas purchases associated with our equity NGL production activities, partially offset by lower volumes.

Operating and maintenance expenses increased primarily due to the inclusion of our recently acquired upstream operations and higher employee-related expenses, which include increased incentive compensation costs and the absence of a 2020 favorable impact of a change in an employee benefit policy, as well as higher reimbursable electricity expenses.

Depreciation and amortization expenses increased primarily due to the inclusion of our recently acquired upstream operations, reduced estimated useful lives for certain facilities in our West segment expected to be decommissioned during 2021, the amortization of intangible assets resulting from Sequent business combination accounting, and new assets placed in-service at Transco.

Selling, general, and administrative expenses increased primarily due to higher employee-related expenses, which include increased incentive compensation costs and expenses at Sequent and the absence of 2020 favorable impact of a change in an employee benefit policy, and were partially offset by lower expenses for various corporate costs.

Impairment of goodwill reflects the 2020 charge at the Northeast reporting unit (see Note 11 – Fair Value Measurements and Guarantees of Notes to Consolidated Financial Statements).

The favorable change in Other (income) expense – net within Operating income (loss) was due to the gains on the sales of certain assets in our West segment, offset by a Transco cashout surcharge.

Equity earnings (losses) changed favorably primarily due to the absence of the 2020 impairment of goodwill at RMM, increases at Appalachia Midstream Investments, Discovery, Aux Sable and Laurel Mountain, partially offset by a decrease at OPPL.

The change in Impairment of equity-method investments reflects the absence of 2020 impairments to various equity-method investments (see Note 11 – Fair Value Measurements and Guarantees of Notes to Consolidated Financial Statements).


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The favorable change in Other income (expense) – net below Operating income (loss) includes higher equity AFUDC and the write-off of a regulatory asset related to a 2020 cancelled project, offset by the unfavorable impact of a 2021 accrual for a loss contingency.

Provision (benefit) for income taxes changed unfavorably primarily due to higher pre-tax income. See Note 6 – 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.

The unfavorable change in Net income (loss) attributable to noncontrolling interests is primarily due to the absence of our partner’s share of the 2020 goodwill impairment at the Northeast reporting unit.

Period-Over-Period Operating Results - Segments

We evaluate segment operating performance based upon Modified EBITDA. Note 14 – Segment Disclosures of Notes to Consolidated Financial Statements includes a reconciliation of this non-GAAP measure to Net income (loss). Management uses Modified EBITDA because it is an accepted financial indicator used by investors to compare company performance. In addition, management believes that this measure provides investors an enhanced perspective of the operating performance of our assets. Modified EBITDA should not be considered in isolation or as a substitute for a measure of performance prepared in accordance with GAAP.

Transmission & Gulf of Mexico


	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
	(Millions)
Service revenues	$	836	$	807	$	2,493	$	2,431
Service revenues – commodity consideration	13		6		34		14
Product sales	88		46		222		134
Segment revenues	937		859		2,749		2,579

Product costs	(89)		(47)		(223)		(136)
Processing commodity expenses	(4)		(1)		(10)		(4)
Other segment costs and expenses	(259)		(233)		(718)		(670)

Proportional Modified EBITDA of equity-method investments	45		38		138		124
Transmission & Gulf of Mexico Modified EBITDA	$	630	$	616	$	1,936	$	1,893

Commodity margins	$	8	$	4	$	23	$	8

Three months ended September 30, 2021 vs. three months ended September 30, 2020

Transmission & Gulf of Mexico Modified EBITDA increased primarily due to favorable changes to Service revenues and Proportional Modified EBITDA of equity-method investments, partially offset by higher Other segment costs and expenses.

Service revenues increased primarily due to:

A $43 million increase in Transco’s natural gas transportation revenues primarily associated with expansion projects placed in service in 2020 and 2021, higher reimbursable electric power costs and a cash out surcharge, which are offset by similar changes in electricity and cash out charges, reflected in Other segment costs and expenses; partially offset by
A $20 million decrease in the Eastern Gulf Coast region primarily due to lower volumes associated with temporary shut-ins due to ongoing producer operational issues and weather-related events and lower deferred revenue recognition.


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Other segment costs and expenses increased primarily due to higher incentive and benefit employee-related costs, higher operating costs, including higher reimbursable electric power costs, and a cash out surcharge, which are offset by similar changes in electricity and cash out reimbursements, reflected in Service revenues. These increases are partially offset by a favorable change in allowance for equity funds used during construction.

Proportional Modified EBITDA of equity-method investments increased at Discovery driven by higher volumes due to the absence of prior year scheduled maintenance and NGL sales prices.

Nine months ended September 30, 2021 vs. nine months ended September 30, 2020

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

Service revenues increased primarily due to:

A $78 million increase in Transco’s natural gas transportation revenues primarily associated with expansion projects placed in service in 2020 and 2021, higher reimbursable electric power costs and a cash out surcharge, which are offset by similar changes in electricity and cash out charges, reflected in Other segment costs and expenses; partially offset by one less billing day;
A $13 million increase in the Western Gulf Coast region primarily driven by higher volumes due to the absence of temporary shut-ins in 2020 related to scheduled maintenance; partially offset by
A decrease in the Eastern Gulf Coast region operations primarily due to:

◦A $23 million decrease due to lower volumes primarily from certain operations due to ongoing producer operational issues, partially offset by the absence of temporary shut-ins related to pricing in 2020;

◦A $19 million decrease at Gulfstar One for the Tubular Bells field primarily due to lower deferred revenue amortization; partially offset by

◦A $17 million increase associated with the Norphlet pipeline.

Commodity margins associated with our equity NGLs increased $14 million primarily driven by favorable NGL sales prices.

Proportional Modified EBITDA of equity-method investments increased at Discovery driven by higher NGL sales prices and higher volumes due to the absence of prior year scheduled maintenance.


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Northeast G&P


	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
	(Millions)
Service revenues	$	399	$	379	$	1,130	$	1,091
Service revenues – commodity consideration	(1)		2		4		5
Product sales	19		12		75		42
Segment revenues	417		393		1,209		1,138

Product costs	(19)		(12)		(77)		(41)
Processing commodity expenses	(1)		(1)		(1)		(3)
Other segment costs and expenses	(130)		(114)		(368)		(335)

Proportional Modified EBITDA of equity-method investments	175		121		490		367
Northeast G&P Modified EBITDA	$	442	$	387	$	1,253	$	1,126

Commodity margins	$	(2)	$	1	$	1	$	3

Three months ended September 30, 2021 vs. three months ended September 30, 2020

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

Service revenues increased primarily due to:

A $10 million increase in revenues at the Northeast JV primarily related to higher processing and fractionation volumes;
A $6 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, and higher incentive and benefit employee-related costs.

Proportional Modified EBITDA of equity-method investments increased at Appalachia Midstream Investments primarily driven by higher volumes. There was also an increase at Laurel Mountain due to higher commodity-based gathering rates as well as the absence of our $11 million share of an impairment of certain assets in the third quarter of 2020 that were subsequently sold. Additionally, there was an increase at Blue Racer/Caiman II due to the favorable impact of increased ownership, and an increase at Aux Sable.

Nine months ended September 30, 2021 vs. nine months ended September 30, 2020

Service revenues increased primarily due to:

A $19 million increase in revenues at the Northeast JV primarily related to higher processing and fractionation volumes, partially offset by lower gathering volumes;


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A $17 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; partially offset by
A $6 million decrease in revenues at Susquehanna Supply Hub primarily related to lower gathering volumes, partially offset by higher gathering rates.

Other segment costs and expenses increased primarily due to higher maintenance and operating expenses, including higher electricity charges, as well as higher incentive and benefit employee-related costs.

Proportional Modified EBITDA of equity-method investments increased at Appalachia Midstream Investments primarily driven by higher volumes. Additionally, there was an increase at Blue Racer/Caiman II primarily due to the favorable impact of increased ownership, partially offset by the absence of a gain on early debt retirement at Blue Racer in the second quarter of 2020. There was also an increase at Laurel Mountain due to higher commodity-based gathering rates as well as the absence of our $11 million share of an impairment of certain assets in the third quarter of 2020 that were subsequently sold, and an increase at Aux Sable.

Total Northeast G&P gathering volumes, including our operated equity-method investments, increased 8 percent over the prior year.

West


	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
	(Millions)
Service revenues	$	312	$	311	$	887	$	938
Service revenues – commodity consideration	52		32		126		74
Product sales	1,170		395		2,983		1,057
Net gain (loss) on commodity derivatives	(48)		(4)		(93)		(4)
Segment revenues	1,486		734		3,903		2,065

Product costs	(1,108)		(377)		(2,748)		(1,026)
Processing commodity expenses	(24)		(18)		(57)		(41)
Other segment costs and expenses	(105)		(122)		(350)		(365)

Proportional Modified EBITDA of equity-method investments	27		30		74		82
West Modified EBITDA	$	276	$	247	$	822	$	715

Commodity margins	$	63	$	30	$	235	$	62
Net unrealized gain (loss) from derivative instruments	(17)		(2)		(20)		(2)

Three months ended September 30, 2021 vs. three months ended September 30, 2020

West Modified EBITDA increased primarily due to higher Commodity margins and lower Other segment costs and expenses, partially offset by an unfavorable change in Net unrealized gain (loss) from derivative instruments.

Service revenues increased primarily due to:

A $16 million increase related to higher MVC revenue primarily in the Eagle Ford Shale region;
An $11 million increase primarily due to higher gathering rates in the Barnett Shale region and higher processing rates in the Piceance region, both driven by favorable commodity pricing, were partially offset by lower gathering rates in the Haynesville Shale region due to a customer contract change; partially offset by


Management’s Discussion and Analysis (Continued)			T able of Contents

A $15 million decrease associated with lower volumes, primarily in the Eagle Ford Shale region which impact is substantially offset by the recognition of higher MVC revenue (see above);
An $11 million decrease due to the absence of a temporary volume deficiency fee from a customer in 2020.

The net sum of Service revenues – commodity consideration, Product sales, Product costs, Processing commodity expenses, and net realized gains and losses on commodity derivatives comprise our Commodity margins. We further segregate our commodity margins into product margins associated with our equity NGLs and marketing margins. The change in product margins from our equity NGLs was zero, primarily due to favorable net realized commodity price changes, offset by lower sales volumes. Marketing margins increased $30 million, primarily due to higher net realized NGL and natural gas prices. The higher net realized prices were partially offset by an unfavorable change in net unrealized losses from derivatives associated with our marketing activities.

Other segment costs and expenses changed favorably primarily due to a gain on an asset sale in 2021.

Nine months ended September 30, 2021 vs. nine months ended September 30, 2020

West Modified EBITDA increased primarily due to higher Commodity margins, partially offset by lower Service revenues.

Service revenues decreased primarily due to:

A $64 million decrease associated with lower volumes, primarily due to production declines in the Eagle Ford Shale region which impact is substantially offset by the recognition of higher MVC revenue (see below). Additionally, lower volumes in the Haynesville Shale region were impacted by production declines;
A $23 million decrease related to lower deferred revenue amortization primarily in the Barnett Shale region;
A $20 million decrease due to the absence of a temporary volume deficiency fee from a customer in 2020;
A $9 million decrease associated with lower gathering rates, primarily in the Haynesville Shale region due to a customer contract change, partially offset by an increase in gathering rates in the Barnett Shale region associated with favorable commodity pricing and escalated rates in the Eagle Ford Shale region; partially offset by
A $52 million increase associated with higher MVC revenue, primarily in the Eagle Ford Shale region;
A $14 million increase in revenues associated primarily with reimbursable compressor power and fuel purchases due to higher prices related to the impact of severe winter weather, which are offset by similar changes in Other segment costs and expenses.

Product margins from our equity NGLs increased by $10 million, primarily due to favorable net realized commodity price changes, partially offset by lower sales volumes. Marketing margins increased by $155 million primarily due to favorable changes in net realized natural gas and NGL prices, including the impact of severe winter weather in the first quarter of 2021. The higher net realized prices were partially offset by an unfavorable change in net unrealized losses from derivatives associated with our marketing activities.

Other segment costs and expenses decreased primarily due to gains on asset sales in 2021 and lower leased compressor expenses, partially offset by higher reimbursable compressor power and fuel purchases which are offset in Service revenues, and higher incentive and benefit employee-related expenses.

Proportional Modified EBITDA of equity-method investments decreased primarily due to lower volumes at OPPL, partially offset by higher volumes and commodity prices at Brazos Permian II.


Management’s Discussion and Analysis (Continued)			T able of Contents

Sequent


	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
	(Millions)
Product sales	$	54	$	—	$	54	$	—
Net gain (loss) on commodity derivatives	(322)		—		(322)		—
Segment revenues	(268)		—		(268)		—


Other segment costs and expenses	(13)		—		(13)		—
Sequent Modified EBITDA	$	(281)	$	—	$	(281)	$	—


Commodity margins	$	9	$	—	$	9	$	—
Net unrealized gain (loss) from derivative instruments	(277)		—		(277)		—

Three and nine months ended September 30, 2021 vs. three and nine months ended September 30, 2020

Commodity margins were primarily due to storage withdrawals driven by strong pricing.

The net unrealized loss on commodity derivatives relates to derivative contracts within the Sequent segment that are not designated as hedges for accounting purposes. Sequent 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 portfolio. However, the unrealized fair value measurement gains and losses are offset by valuation changes in the economic value of the underlying transportation and storage portfolio, which is not accounted for on a fair value basis.

Other segment costs and expenses primarily include employee-related costs.

Other


	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
	(Millions)
Other Modified EBITDA	$	38	$	(7)	$	91	$	8

Three and nine months ended September 30, 2021 vs. three and nine months ended September 30, 2020

Other Modified EBITDA increased primarily due to our recently acquired upstream operations, including the favorable commodity price impact of severe winter weather in the first quarter of 2021. See Note 14 – Segment Disclosures of Notes to Consolidated Financial Statements. The year-to-date comparative period also includes the impact of a $10 million accrual for a loss contingency in 2021 and the absence of a third-quarter 2020 charge of $8 million for the write-off of a regulatory asset associated with a cancelled project.


Management’s Discussion and Analysis (Continued)			T able of Contents

Management’s Discussion and Analysis of Financial Condition and Liquidity

Outlook

As previously discussed in Company Outlook, our growth capital and investment expenditures in 2021 are currently expected to be in a range from $1.0 billion to $1.2 billion. Growth capital spending in 2021 includes Transco expansions, all of which are fully contracted with firm transportation agreements, projects supporting the Northeast G&P business, midstream opportunities in the Haynesville area in the West segment, and the recent acquisitions of certain upstream operations and Sequent. 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 intend to fund substantially all of our planned 2021 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 as previously discussed in Recent Developments.

In the first half of 2021, we acquired various oil and gas properties in the Wamsutter field in Wyoming, funding the $165 million paid with cash on hand (see Note 14 – Segment Disclosures of Notes to Consolidated Financial Statements). In July 2021, we acquired Sequent, funding the $134 million paid with cash on hand (see Note 3 – Acquisitions of Notes to Consolidated Financial Statements).

During the first quarter of 2021, we issued $900 million of new long-term debt to fund the third quarter 2021 repayment of $500 million of 4.0 percent senior unsecured notes that were scheduled to mature in November 2021 as well as $371 million of 7.875 percent senior unsecured notes that were due September 2021, and for general corporate purposes. In October 2021, we issued an additional $1.25 billion of new long-term debt to fund the repayment of debt maturing in 2022 and for general corporate purposes. As of September 30, 2021, we have approximately $2.0 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 at attractive long-term rates or from our credit facility, as well as proceeds from asset monetizations.


Management’s Discussion and Analysis (Continued)			T able 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 2021. 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
			Debt service payments, including payments of long-term debt
			Distributions to noncontrolling interests
			Share repurchase program

As of September 30, 2021, we have approximately $20.3 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 at attractive long-term rates or from our credit facility, as well as proceeds from asset monetizations.

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

As of September 30, 2021, we had a working capital deficit of $2.055 billion, including cash and cash equivalents and long-term debt due within one year. Our available liquidity is as follows:


Available Liquidity	September 30, 2021
	(Millions)
Cash and cash equivalents	$	214
Capacity available under our $4.5 billion credit facility, less amounts outstanding under our $4 billion commercial paper program (1)	4,500
	$	4,714

(1)In managing our available liquidity, we do not expect a maximum outstanding amount in excess of the capacity of our credit facility inclusive of any outstanding amounts under our commercial paper program. We had no commercial paper outstanding as of September 30, 2021. Through September 30, there was no amount outstanding under our commercial paper program and credit facility during 2021. At September 30, 2021, we were in compliance with the financial covenants associated with our credit facility. Effective October 8, 2021, we entered into a new credit agreement whereby we have $3.75 billion available under our credit facility and we reduced the size of our commercial paper program to $3.5 billion. As of October 28, 2021, we have $3.75 billion available under our new credit facility.


Management’s Discussion and Analysis (Continued)			T able of Contents

Dividends

We increased our regular quarterly cash dividend to common stockholders by approximately 2.5 percent from the $0.40 per share paid in each quarter of 2020, to $0.41 per share paid in March, June, and September 2021.

Registrations

In February 2021, we filed a shelf registration statement as a well-known seasoned issuer.

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

In June 2021, Moody’s upgraded our credit rating from Baa3 to Baa2.

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)			T able of Contents

Sources (Uses) of Cash

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


	Cash Flow	Nine Months Ended September 30,
	Category	2021		2020
		(Millions)
Sources of cash and cash equivalents:
Operating activities – net	Operating	$	2,806	$	2,382
Proceeds from long-term debt (see Note 9)	Financing	898		2,198
Proceeds from credit-facility borrowings	Financing	—		1,700
Proceeds from commercial paper – net	Financing	—		40

Uses of cash and cash equivalents:
Common dividends paid	Financing	(1,494)		(1,456)
Capital expenditures	Investing	(957)		(938)
Payments of long-term debt	Financing	(887)		(2,136)
Payments on credit-facility borrowings	Financing	—		(1,700)
Purchases of businesses, net of cash acquired (see Note 3)	Investing	(126)		—
Dividends and distributions paid to noncontrolling interests	Financing	(135)		(147)
Purchases of and contributions to equity-method investments	Investing	(79)		(150)

Other sources / (uses) – net	Financing and Investing	46		(12)
Increase (decrease) in cash and cash equivalents		$	72	$	(219)

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, Impairment of goodwill, Impairment of equity-method investments, and Net unrealized (gain) loss from derivative instruments. Our Net cash provided (used) by operating activities for the nine months ended September 30, 2021, increased from the same period in 2020 primarily due to higher operating income (excluding noncash items as previously discussed) and favorable changes in net operating working capital in 2021, partially offset by unfavorable changes in current and noncurrent derivative assets and liabilities.

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