~~0000107263 us-gaap:OperatingSegmentsMember wmb:AtlanticGulfMember 2019-01-01 2019-09-30~~

Registrant’s telephone number, including area code: (~~918~~) (918) 573-2000

(Former name, former address and former fiscal year, if changed since last report)

Securities registered pursuant to Section 12(b) of the Act:



Title of each class	Trading Symbol(s)	Name of each exchange on which registered
Common Stock, $1.00 par value	WMB	New York Stock Exchange

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☑ No ☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☑ No ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer

☑

Accelerated filer

☐

Non-accelerated filer

☐

Smaller reporting company

☐

Emerging growth company

☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act.) Yes ☐ No ☑

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.


Class						Shares Outstanding at October 29, 2020
Common Stock, $1.00 par value						1,213,585,717

The Williams Companies, Inc.

Index



	Page
Part I. Financial Information
Item 1. Financial Statements
Consolidated Statement of Income – Three and Nine Months Ended September 30, ~~2019~~2020 and ~~2018~~2019		6
Consolidated Statement of Comprehensive Income (Loss) – Three and Nine Months Ended September 30, ~~2019~~2020 and ~~2018~~2019		7
Consolidated Balance Sheet – September 30, ~~2019~~2020 and December 31, ~~2018~~2019		8
Consolidated Statement of Changes in Equity – Three and Nine Months Ended September 30, ~~2019~~2020 and ~~2018~~2019		9
Consolidated Statement of Cash Flows – Nine Months Ended September 30, ~~2019~~2020 and ~~2018~~2019		11
Notes to Consolidated Financial Statements		12
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		4036
Item 3. Quantitative and Qualitative Disclosures About Market Risk		6156
Item 4. Controls and Procedures		6156
Part II. Other Information		6156
Item 1. Legal Proceedings		6156
Item 1A. Risk Factors		6357

Item 6. Exhibits		6458

The reports, filings, and other public announcements of The Williams Companies, Inc. (Williams) may contain or incorporate by reference statements that do not directly or exclusively relate to historical facts. Such statements are “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (Securities Act), and Section 21E of the Securities Exchange Act of 1934, as amended (Exchange Act). These forward-looking statements relate to anticipated financial performance, management’s plans and objectives for future operations, business prospects, ~~outcome~~outcomes of regulatory proceedings, market conditions, and other matters. We make these forward-looking statements in reliance on the safe harbor protections provided under the Private Securities Litigation Reform Act of 1995.

All statements, other than statements of historical facts, included in this report that address activities, events, or developments that we expect, believe, or anticipate will exist or may occur in the future are forward-looking statements. Forward-looking statements can be identified by various forms of words such as “anticipates,” “believes,” “seeks,” “could,” “may,” “should,” “continues,” “estimates,” “expects,” “forecasts,” “intends,” “might,” “goals,” “objectives,” “targets,” “planned,” “potential,” “projects,” “scheduled,” “will,” “assumes,” “guidance,” “outlook,” “in-service date,” or other similar expressions. These forward-looking statements are based on management’s beliefs and assumptions and on information currently available to management and include, among others, statements regarding:

•Levels of dividends to Williams stockholders;

•Future credit ratings of Williams and its affiliates;

•Amounts and nature of future capital expenditures;

•Expansion and growth of our business and operations;

•Expected in-service dates for capital projects;

•Financial condition and liquidity;

•Business strategy;

•Cash flow from operations or results of operations;

•Seasonality of certain business components;

•Natural gas, ~~and~~ natural gas liquids, and crude oil prices, supply, and demand;

•Demand for our ~~services.~~services;

•The impact of the novel coronavirus (COVID-19) pandemic.

Forward-looking statements are based on numerous assumptions, uncertainties, and risks that could cause future events or results to be materially different from those stated or implied in this report. Many of the factors that will determine these results are beyond our ability to control or predict. Specific factors that could cause actual results to differ from results contemplated by the forward-looking statements include, among others, the following:

~~Whether we are able to pay current and expected levels of dividends;~~

~~Whether we will be able to effectively execute our financing plan;~~

•Availability of supplies, market demand, and volatility of prices;

~~Inflation, interest rates,~~•Development and ~~general economic conditions (including future disruptions and volatility in the global credit markets and the~~rate of adoption of alternative energy sources;

•The impact of ~~these events on~~existing and future laws and regulations, the regulatory environment, environmental liabilities, and litigation, as well as our ability to obtain necessary permits and approvals, and achieve favorable rate proceeding outcomes;

•Our exposure to the credit risk of our customers and ~~suppliers);~~counterparties;

~~The strength and financial resources of our competitors and the effects of competition;~~

~~Whether we are able to successfully identify, evaluate, and timely execute our capital projects and investment opportunities;~~

•Our ability to acquire new businesses and assets and successfully integrate those operations and assets into existing businesses as well as successfully expand our facilities, and to consummate asset sales on acceptable terms;

~~Development~~•Whether we are able to successfully identify, evaluate, and ~~rate~~timely execute our capital projects and investment opportunities;

•The strength and financial resources of ~~adoption~~our competitors and the effects of ~~alternative energy sources;~~competition;

•The ~~impact~~amount of cash distributions from and capital requirements of our investments and joint ventures in which we participate;

•Whether we will be able to effectively execute our financing plan;

•Increasing scrutiny and changing expectations from stakeholders with respect to our environmental, social, and governance practices;

•The physical and financial risks associated with climate change;

•The impacts of operational and developmental hazards and unforeseen interruptions;

•The ~~impact~~risks resulting from outbreaks or other public health crises, including COVID-19;

•Risks associated with weather and natural phenomena, including climate conditions and physical damage to our facilities;

•Acts of ~~existing~~terrorism, cybersecurity incidents, and future laws and regulations, the regulatory environment, environmental liabilities, and litigation, as well as our ability to obtain necessary permits and approvals, and achieve favorable rate proceeding outcomes;related disruptions;

•Our costs and funding obligations for defined benefit pension plans and other postretirement benefit plans;

•Changes in maintenance and construction costs, as well as our ability to obtain sufficient ~~construction related~~construction-related inputs, including skilled labor;

~~Changes~~•Inflation, interest rates, and general economic conditions (including future disruptions and volatility in the ~~current geopolitical situation;~~

~~Our exposure to~~global credit markets and the ~~credit risk~~impact of ~~our~~these events on customers and ~~counterparties;~~suppliers);

•Risks related to financing, including restrictions stemming from debt agreements, future changes in credit ratings as determined by nationally recognized credit rating agencies, and the availability and cost of capital;

•The ~~amount~~ability of ~~cash distributions from~~the members of the Organization of Petroleum Exporting Countries and ~~capital requirements~~other oil exporting nations to agree to and maintain oil price and production controls and the impact on domestic production;

•Changes in the current geopolitical situation;

•Whether we are able to pay current and expected levels of ~~our investments and joint ventures in which we participate;~~dividends;

~~Risks associated with weather and natural phenomena, including climate conditions and physical damage to our facilities;~~

~~Acts of terrorism, cybersecurity incidents, and related disruptions;~~

•Additional risks described in our filings with the Securities and Exchange Commission (SEC).

Given the uncertainties and risk factors that could cause our actual results to differ materially from those contained in any forward-looking statement, we caution investors not to unduly rely on our forward-looking statements. We disclaim any obligations to and do not intend to update the above list or announce publicly the result of any revisions to any of the forward-looking statements to reflect future events or developments.

In addition to causing our actual results to differ, the factors listed above and referred to below may cause our intentions to change from those statements of intention set forth in this report. Such changes in our intentions may also cause our results to differ. We may change our intentions, at any time and without notice, based upon changes in such factors, our assumptions, or otherwise.

Because forward-looking statements involve risks and uncertainties, we caution that there are important factors, in addition to those listed above, that may cause actual results to differ materially from those contained in the forward-looking statements. For a detailed discussion of those factors, see Part I, Item 1A. Risk Factors in our Annual Report on Form 10-K for the year ended December 31, 2019, as filed with the SEC on February ~~21, 2019.~~

24, 2020, as supplemented by the disclosures in Part II, Item 1A. in our Quarterly Report on Form 10-Q for the quarter ended March 31, 2020.

DEFINITIONS

The following is a listing of certain abbreviations, acronyms, and other industry terminology that may be used throughout this Form 10-Q.

Measurements:

Barrel: One barrel of petroleum products that equals 42 U.S. gallons

Bcf: One billion cubic feet of natural gas

Bcf/d: One billion cubic feet of natural gas per day

British Thermal Unit (Btu): A unit of energy needed to raise the temperature of one pound of water by one degree Fahrenheit

Dekatherms (Dth): A unit of energy equal to one million British thermal units

Mbbls/d: One thousand barrels per day

Mdth/d: One thousand dekatherms per day

MMcf/d: One million cubic feet per day

MMdth: One million dekatherms or approximately one trillion British thermal units

MMdth/d: One million dekatherms per day

Tbtu: One trillion British thermal units

Consolidated Entities:

Cardinal: Cardinal Gas Services, L.L.C.

~~Constitution:~~ ~~Constitution Pipeline Company, LLC~~

Gulfstar One: Gulfstar One LLC

Northwest Pipeline: Northwest Pipeline LLC

Transco: Transcontinental Gas Pipe Line Company, LLC

UEOM: Utica East Ohio Midstream LLC, previously a Partially Owned Entity until acquiring remaining interest in March 2019

Northeast JV: Ohio Valley Midstream LLC, a partially owned venture that includes our Ohio Valley assets and UEOM

~~WPZ:~~ Williams Partners L.P. Effective August 10, 2018, we completed our merger with WPZ, pursuant to which we acquired all outstanding common units of WPZ held by others and Williams continued as the surviving entity.

Partially Owned Entities: Entities in which we do not own a 100 percent ownership interest and which, as of September 30, ~~2019,~~2020, we account for as an equity-method ~~investment,~~investments, including principally the following:

Aux Sable: Aux Sable Liquid Products LP

~~Brazos Permian II:~~ ~~Brazos Permian II, LLC~~

Caiman II: Caiman Energy II, LLC

Discovery: Discovery Producer Services LLC

Gulfstream: Gulfstream Natural Gas System, L.L.C.

Jackalope: Jackalope Gas Gathering Services, L.L.C., which was sold in April 2019

Laurel Mountain: Laurel Mountain Midstream, LLC

OPPL: Overland Pass Pipeline Company LLC

RMM: Rocky Mountain Midstream Holdings LLC

Government and Regulatory:

EPA: Environmental Protection Agency

Exchange Act, the: Securities and Exchange Act of 1934, as amended

FERC: Federal Energy Regulatory Commission

IRS: Internal Revenue Service

SEC: Securities and Exchange Commission

Other:

Fractionation: The process by which a mixed stream of natural gas liquids is separated into constituent products, such as ethane, propane, and butane

GAAP: U.S. generally accepted accounting principles

LNG: Liquefied natural gas; natural gas which has been liquefied at cryogenic temperatures

MVC: Minimum volume commitment

NGLs: Natural gas liquids; natural gas liquids result from natural gas processing and crude oil refining and are used as petrochemical feedstocks, heating fuels, and gasoline additives, among other applications

NGL margins: NGL revenues less any applicable Btu replacement cost, plant fuel, transportation, and fractionation

~~WPZ Merger:~~ ~~The August 10, 2018, merger transactions pursuant to which we acquired all outstanding common units of WPZ held by others, merged WPZ into Williams, and Williams continued as the surviving entity~~

PART I – FINANCIAL INFORMATION

Item 1. Financial Statements

The Williams Companies, Inc.

Consolidated Statement of Income

(Unaudited)


	Three Months Ended September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
	(Millions, except per-share amounts)
Revenues:
Service revenues	$	1,479	$	1,495	$	4,399	$	4,424
Service revenues – commodity consideration	40		38		93		158
Product sales	414		466		1,135		1,512
Total revenues	1,933		1,999		5,627		6,094
Costs and expenses:
Product costs	380		434		1,047		1,442
Processing commodity expenses	21		19		49		83
Operating and maintenance expenses	336		364		993		1,091
Depreciation and amortization expenses	426		435		1,285		1,275
Selling, general, and administrative expenses	114		130		354		410
Impairment of certain assets (Note 12)	0		0		0		76
Impairment of goodwill (Note 12)	0		0		187		0
Other (income) expense – net	15		(11)		28		30
Total costs and expenses	1,292		1,371		3,943		4,407
Operating income (loss)	641		628		1,684		1,687
Equity earnings (losses) (Note 5)	106		93		236		260
Impairment of equity-method investments (Note 12)	0		(114)		(938)		(186)
Other investing income (loss) – net (Note 5)	2		7		6		132
Interest incurred	(298)		(303)		(898)		(915)
Interest capitalized	6		7		16		27
Other income (expense) – net	(23)		1		(14)		19
Income (loss) before income taxes	434		319		92		1,024
Provision (benefit) for income taxes	111		77		24		244


Net income (loss)	323		242		68		780
Less: Net income (loss) attributable to noncontrolling interests	14		21		(27)		54
Net income (loss) attributable to The Williams Companies, Inc.	309		221		95		726
Preferred stock dividends	1		1		2		2
Net income (loss) available to common stockholders	$	308	$	220	$	93	$	724



Basic earnings (loss) per common share:


Net income (loss)	$	.25	$	.18	$	.08	$	.60
Weighted-average shares (thousands)	1,213,912		1,212,270		1,213,512		1,211,938
Diluted earnings (loss) per common share:


Net income (loss)	$	.25	$	.18	$	.08	$	.60
Weighted-average shares (thousands)	1,215,335		1,214,165		1,214,757		1,213,943

Three Months Ended
September 30, Nine Months Ended
September 30,
2019 2018 2019 2018
(Millions, except per-share amounts)
Revenues:
Service revenues $ 1,495
$ 1,371
$ 4,424

$ 4,062
Service revenues – commodity consideration 38
121
158
316
Product sales 466
811
1,512

2,104
Total revenues 1,999
2,303
6,094

6,482
Costs and expenses:

Product costs 434

790

1,442

2,039
Processing commodity expenses 19

30

83

91
Operating and maintenance expenses 364

389

1,091

1,134
Depreciation and amortization expenses 435

425

1,275

1,290
Selling, general, and administrative expenses 130

174

410

436
Impairment of certain assets (Note 13) —

—

76

66
Other (income) expense – net (11 )
(6 )
30

24
Total costs and expenses 1,371

1,802

4,407

5,080
Operating income (loss) 628

501

1,687

1,402
Equity earnings (losses) 93

105

260

279
Other investing income (loss) – net (Note 5) (107 )
2

(54 )
74
Interest incurred (303 )
(286 )
(915 )
(856 )
Interest capitalized 7

16

27

38
Other income (expense) – net 1

52

19

99
Income (loss) before income taxes 319

390

1,024

1,036
Provision (benefit) for income taxes 77

190

244

297
Net income (loss) 242

200

780

739
Less: Net income (loss) attributable to noncontrolling interests 21

71

54

323
Net income (loss) attributable to The Williams Companies, Inc. 221

129

726

416
Preferred stock dividends 1
—
2
—
Net income (loss) available to common stockholders $ 220
$ 129
$ 724
$ 416
Basic earnings (loss) per common share:
Net income (loss) $ .18
$ .13
$ .60
$ .47
Weighted-average shares (thousands) 1,212,270
1,023,587
1,211,938
893,706
Diluted earnings (loss) per common share:
Net income (loss) $ .18
$ .13
$ .60
$ .46
Weighted-average shares (thousands) 1,214,165
1,026,504
1,213,943
896,322

See accompanying notes.

September 30,
2019 December 31,
2018
(Millions, except per-share amounts)
ASSETS
Current assets:
Cash and cash equivalents $ 247
$ 168
Trade accounts and other receivables (net of allowance of $6 at September 30, 2019 and $9 at December 31, 2018) 875
992
Inventories 129
130
Other current assets and deferred charges 183
174
Total current assets 1,434
1,464
Investments 6,228
7,821
Property, plant, and equipment 41,647
38,661
Accumulated depreciation and amortization (12,034 ) (11,157 )
Property, plant, and equipment – net 29,613
27,504
Intangible assets – net of accumulated amortization 8,041
7,767
Regulatory assets, deferred charges, and other 965
746
Total assets $ 46,281
$ 45,302
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable $ 602
$ 662
Accrued liabilities 1,184
1,102
Long-term debt due within one year 1,538
47
Total current liabilities 3,324
1,811
Long-term debt 20,719
22,367
Deferred income tax liabilities 1,651
1,524
Regulatory liabilities, deferred income, and other 3,728
3,603
Contingent liabilities (Note 14)

Equity:
Stockholders’ equity:
Preferred stock 35
35
Common stock ($1 par value; 1,470 million shares authorized at September 30, 2019 and December 31, 2018; 1,247 million shares issued at September 30, 2019 and 1,245 million shares issued at December 31, 2018) 1,247
1,245
Capital in excess of par value 24,310
24,693
Retained deficit (10,664 ) (10,002 )
Accumulated other comprehensive income (loss) (266 ) (270 )
Treasury stock, at cost (35 million shares of common stock) (1,041 ) (1,041 )
Total stockholders’ equity 13,621
14,660
Noncontrolling interests in consolidated subsidiaries 3,238
1,337
Total equity 16,859
15,997
Total liabilities and equity $ 46,281
$ 45,302

See accompanying notes.

The Williams Companies, Inc.

Consolidated Statement of Changes in Equity

Cash dividends – common stock ($0.40 per share)

Cash dividends – common stock ($0.38 per share)

Balance – June 30, 2018
$ —
$ 862
$ 18,552
$ (8,735 ) $ (293 ) $ (1,041 ) $ 9,345
$ 6,102
$ 15,447
Net income (loss) —
—
—
129
—
—
129
71
200
Other comprehensive income (loss) —
—
—
—
5
—
5
1
6
WPZ Merger (Note 1) —
382
6,112
—
(3 ) —
6,491
(4,629 ) 1,862
Issuance of preferred stock (Note 12) 35
—
—
—
—
—
35
—
35
Cash dividends – common stock ($0.34 per share)
—
—
—
(411 ) —
—
(411 ) —
(411 )
Dividends and distributions to noncontrolling interests —
—
—
—
—
—
—
(196 ) (196 )
Stock-based compensation and related common stock issuances, net of tax —
—
16
—
—
—
16
—
16
Changes in ownership of consolidated subsidiaries, net —
—
1
—
—
—
1
(1 ) —
Contributions from noncontrolling interests —
—
—
—
—
—
—
2
2
Other —
1
(1 ) (1 ) —
—
(1 ) (1 ) (2 )
Net increase (decrease) in equity 35
383
6,128
(283 ) 2
—
6,265
(4,753 ) 1,512
Balance – September 30, 2018
$ 35
$ 1,245
$ 24,680
$ (9,018 ) $ (291 ) $ (1,041 ) $ 15,610
$ 1,349
$ 16,959
*Accumulated Other Comprehensive Income (Loss)

See accompanying notes.

The Williams Companies, Inc.

Consolidated Statement of Changes in Equity (Continued)

Balance – December 31, 2017 $ —
$ 861
$ 18,508
$ (8,434 ) $ (238 ) $ (1,041 ) $ 9,656
$ 6,519
$ 16,175
Adoption of new accounting standards —
—
—
(23 ) (61 ) —
(84 ) (37 ) (121 )
Net income (loss) —
—
—
416
—
—
416
323
739
Other comprehensive income (loss) —
—
—
—
11
—
11
(2 ) 9
WPZ Merger (Note 1) —
382
6,112
—
(3 ) —
6,491
(4,629 ) 1,862
Issuance of preferred stock (Note 12) 35
—
—
—
—
—
35
—
35
Cash dividends – common stock ($1.02 per share) —
—
—
(974 ) —
—
(974 ) —
(974 )
Dividends and distributions to noncontrolling interests —
—
—
—
—
—
—
(598 ) (598 )
Stock-based compensation and related common stock issuances, net of tax —
1
48
—
—
—
49
—
49
Sales of limited partner units of Williams Partners L.P. —
—
—
—
—
—
—
46
46
Changes in ownership of consolidated subsidiaries, net —
—
14
—
—
—
14
(18 ) (4 )
Contributions from noncontrolling interests —
—
—
—
—
—
—
13
13
Deconsolidation of subsidiary (Note 5) —
—
—
—
—
—
—
(267 ) (267 )
Other —
1
(2 ) (3 ) —
—
(4 ) (1 ) (5 )
Net increase (decrease) in equity 35
384
6,172
(584 ) (53 ) —
5,954
(5,170 ) 784
Balance – September 30, 2018 $ 35
$ 1,245
$ 24,680
$ (9,018 ) $ (291 ) $ (1,041 ) $ 15,610
$ 1,349
$ 16,959


Balance – December 31, 2018	$	35	$	1,245	$	24,693	$	(10,002)	$	(270)	$	(1,041)	$	14,660	$	1,337	$	15,997

Net income (loss)	0		0		0		726		0		0		726		54		780
Other comprehensive income (loss)	0		0		0		0		4		0		4		0		4


Cash dividends – common stock ($1.14 per share)	0		0		0		(1,382)		0		0		(1,382)		0		(1,382)
Dividends and distributions to noncontrolling interests	0		0		0		0		0		0		0		(86)		(86)
Stock-based compensation and related common stock issuances, net of tax	0		2		43		0		0		0		45		0		45
Sale of partial interest in consolidated subsidiary (Note 2)	0		0		0		0		0		0		0		1,333		1,333
Changes in ownership of consolidated subsidiaries, net (Note 2)	0		0		(426)		0		0		0		(426)		568		142
Contributions from noncontrolling interests	0		0		0		0		0		0		0		32		32

Other	0		0		0		(6)		0		0		(6)		0		(6)
Net increase (decrease) in equity	0		2		(383)		(662)		4		0		(1,039)		1,901		862
Balance – September 30, 2019	$	35	$	1,247	$	24,310	$	(10,664)	$	(266)	$	(1,041)	$	13,621	$	3,238	$	16,859

*Accumulated Other Comprehensive Income (Loss)

See accompanying notes.

Note 1 – General, Description of Business, and Basis of Presentation

Our accompanying interim consolidated financial statements do not include all the notes in our annual financial statements and, therefore, should be read in conjunction with the consolidated financial statements and notes thereto for the year ended December 31, ~~2018,~~2019, in Exhibit 99.1 of our ~~Annual Report on~~ Form ~~10-K.~~8-K dated May 4, 2020. The accompanying unaudited financial statements include all normal recurring adjustments and others that, in the opinion of management, are necessary to present fairly our interim financial statements.

The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes. Actual results could differ from those estimates.

Unless the context clearly indicates otherwise, references in this report to “Williams,” “we,” “our,” “us,” or like terms refer to The Williams Companies, Inc. and its subsidiaries. Unless the context clearly indicates otherwise, references to “Williams,” “we,” “our,” and “us” include the operations in which we own interests accounted for as equity-method investments that are not consolidated in our financial statements. When we refer to our equity investees by name, we are referring exclusively to their businesses and operations.

On August 10, 2018, we completed our merger with Williams Partners L.P. (WPZ), our previously consolidated master limited partnership, pursuant to which we acquired all of the approximately 256 million publicly held outstanding common units of WPZ in exchange for 382 million shares of our common stock (WPZ Merger). Williams continued as the surviving entity. The WPZ Merger was accounted for as a noncash equity transaction resulting in increases to ~~Common stock~~ of ~~$382 million~~, ~~Capital in excess of par value~~ of ~~$6.112 billion, and~~ ~~Regulatory assets, deferred charges, and other~~ ~~of $33 million and decreases to~~ ~~Accumulated other comprehensive income (loss)~~ ~~(AOCI) of $3 million,~~ ~~Noncontrolling interests in consolidated subsidiaries~~ of ~~$4.629 billion, and~~ ~~Deferred income tax liabilities~~ of ~~$1.829 billion~~ ~~in the~~ ~~Consolidated Balance Sheet. Pursuant to its distribution reinvestment program, WPZ had issued 1,230,657 common units to the public in 2018 associated with reinvested distributions of $46 million.~~

Description of Business

We are a Delaware corporation whose common stock is listed and traded on the New York Stock Exchange. Our operations are located in the United ~~States and~~States. Effective January 1, 2020, following an organizational realignment, our interstate natural gas pipeline Northwest Pipeline LLC (Northwest Pipeline), which was reported within the West reporting segment throughout 2019, is now managed within the Transmission & Gulf of Mexico reporting segment (previously identified as the Atlantic-Gulf reporting segment). As a result, beginning with the reporting of first-quarter 2020, our operations are presented within the following reportable segments: Transmission & Gulf of Mexico, Northeast G&P, ~~Atlantic-Gulf,~~ and West, consistent with the manner in which our chief operating decision maker evaluates performance and allocates resources. All remaining business activities as well as corporate activities are included in Other. Prior period segment disclosures have been recast for the new segment presentation.

~~Northeast G&P is comprised~~Transmission & Gulf of our midstream gathering, processing, and fractionation businesses in the Marcellus Shale region primarily in Pennsylvania, New York, and West Virginia and the Utica Shale region of eastern Ohio, including a 66 percent interest in Cardinal Gas Services, L.L.C. (Cardinal) (a consolidated entity), as well as a 69 percent equity-method investment in Laurel Mountain Midstream, LLC (Laurel Mountain), a 58 percent equity-method investment in Caiman Energy II, LLC, and Appalachia Midstream Services, LLC, which owns equity-method investments with an approximate average 66 percent interest in multiple gas gathering systems in the Marcellus Shale (Appalachia Midstream Investments). Northeast G&P includes a 65 percent interest in Ohio Valley Midstream LLC (Northeast JV) (a consolidated entity). The Northeast JV includes our Ohio Valley assets and Utica East Ohio Midstream LLC (UEOM), a former equity-method investment in which we acquired the remaining ownership interest in March 2019 (see Note 2 – Acquisitions).

~~Notes (Continued)~~

~~Atlantic-Gulf~~Mexico is comprised of our interstate natural gas ~~pipeline,~~pipelines, Transcontinental Gas Pipe Line Company, LLC (Transco), and ~~significant~~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 LLC (Gulfstar One) (a consolidated ~~entity)~~variable interest entity, or VIE), which is a proprietary floating production system, ~~as well as~~ a 50 percent equity-method investment in Gulfstream Natural Gas System, L.L.C., and a 60 percent equity-method investment in Discovery Producer Services LLC (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 4165 percent interest in ~~Constitution Pipeline Company,~~Ohio Valley Midstream LLC ~~(Constitution)~~(Northeast JV) (a consolidated ~~entity)~~VIE) which operates in West Virginia, Ohio, and Pennsylvania, a 66 percent interest in Cardinal Gas Services, L.L.C. (Cardinal) (a consolidated VIE) which operates in Ohio, a 69 percent equity-method investment in Laurel Mountain Midstream, LLC (Laurel Mountain), ~~which is developing~~ a ~~pipeline project (see Note 4 – Variable Interest Entities)~~58 percent equity-method investment in Caiman Energy II, LLC (Caiman II), and Appalachia Midstream Services, LLC, 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 (Appalachia Midstream Investments).

West is comprised of our ~~interstate natural~~ gas ~~pipeline, Northwest Pipeline LLC (Northwest Pipeline), and our~~ 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 ~~Permian Shale region of west Texas, the~~ Haynesville Shale region of northwest Louisiana, and the Mid-Continent region which includes the Anadarko, Arkoma, and ~~Arkoma~~Permian basins. This segment also includes our natural gas liquid (NGL) and natural gas marketing business, storage facilities, an undivided 50 percent interest in an NGL fractionator near Conway, Kansas, a 50 percent equity-method investment in Overland Pass Pipeline Company LLC, a 50 percent equity-method investment in Rocky Mountain Midstream Holdings LLC (RMM), and a 15 percent ~~equity-method investment~~interest in Brazos Permian II, LLC (Brazos Permian II). West also included our former ~~natural gas gathering and processing assets in the Four Corners area of New Mexico and Colorado, which were sold during the fourth quarter of 2018, and our former~~ 50 percent ~~interest~~equity-method investment in Jackalope Gas Gathering Services, L.L.C. (Jackalope) ~~(an equity-method investment following deconsolidation as of June 30, 2018)~~, which was sold in April 2019.

Basis of Presentation

Significant risks and uncertainties

We believe that the carrying value of certain of our property, plant, and equipment and other identifiable intangible assets, notably certain acquired assets accounted for as business combinations between 2012 and 2014, may be in excess of current fair value. However, the carrying value of these assets, in our judgment, continues to be ~~recoverable based on our evaluation of undiscounted future cash flows.~~recoverable. It is reasonably possible that future strategic decisions, including transactions such as monetizing non-core assets or contributing assets to new ventures with third parties, as well as unfavorable changes in expected producer activities, including effects of financial distress caused by financial and commodity market declines or unfavorable developments in ongoing bankruptcy proceedings, could impact our assumptions and ultimately result in impairments of these assets. Such transactions or developments may also indicate that certain of our equity-method investments have experienced other-than-temporary declines in value, which could result in ~~impairment, or~~impairment.

In June 2020, our customer, Chesapeake Energy Corporation (Chesapeake), announced that ~~the fair value~~it had voluntarily filed for relief under Chapter 11 of the ~~reporting unit~~U.S. Bankruptcy Code. We provide midstream services, including wellhead gathering, for the natural gas that Chesapeake and its joint interest owners produce, primarily in the Eagle Ford Shale, Haynesville Shale, and Marcellus Shale regions (through Appalachia Midstream Investments). In 2019, Chesapeake accounted for approximately 6 percent of our ~~goodwill~~consolidated revenues. As of September 30, 2020, trade accounts receivable due from Chesapeake include $88 million related to services provided prior to Chesapeake’s bankruptcy filing. The remaining trade accounts receivable due from Chesapeake are current.

We have evaluated these receivables from Chesapeake and our related asset groups and investments involved in providing services to Chesapeake and determined that no expected credit losses or impairment charges are required to be recognized at this time. This evaluation considered the physical nature of our services in these basins, where we gather at the wellhead and are critical to Chesapeake’s ability to move product to market, along with an assessed low likelihood of contract rejection, noting that to date Chesapeake has not attempted to reject any of our contracts. Chesapeake also received initial limited approval to continue paying for services such as those we provide. We also considered our prior experiences with customer bankruptcies, where receivables were ultimately collectible even if the timing of collections was impacted. Future developments in Chesapeake’s ongoing bankruptcy proceedings could affect our assumptions and conclusions regarding credit losses and impairment charges.

Northeast Supply Enhancement

As of September 30, 2020, Property, plant, and equipment in our Consolidated Balance Sheet includes approximately $215 million of capitalized project development costs for the Northeast Supply Enhancement project. Approvals required for the project from the New York State Department of Environmental Conservation and the New Jersey Department of Environmental Protection have been denied and we have not refiled at this time. Beginning in May 2020, we discontinued capitalization of costs related to this project.

The customer precedent agreements for the Northeast Supply Enhancement project remain in effect and the project’s Federal Energy Regulatory Commission (FERC) certificate remains active. As such, we do not believe this project is ~~less than its~~probable of abandonment at this time and consider the carrying amount ~~which would result~~to be recoverable; thus, no

impairment charge has been recognized. It is reasonably possible that further adverse developments in ~~impairment.~~the near future could change this determination, resulting in a future impairment charge of a substantial portion of the capitalized costs.

Accounting standards issued and adopted

In ~~February~~June 2016, the Financial Accounting Standards Board ~~(FASB)~~ issued Accounting Standards Update (ASU) 2016-02 “Leases (Topic 842)” (ASU 2016-02). ASU 2016-02 establishes a comprehensive new lease accounting model. ASU 2016-02 modifies the definition of a lease, requires a dual approach to lease classification similar to prior lease accounting, and causes lessees to recognize operating leases on the balance sheet as a lease liability measured as the present value of the future lease payments with a corresponding right-of-use asset, with an exception for leases with a term of one year or less. Additional disclosures are required regarding the amount, timing, and uncertainty of cash flows arising from leases. In January 2018, the FASB issued ASU 2018-01 “Leases (Topic 842): Land Easement Practical Expedient for Transition to Topic 842” (ASU 2018-01). Per ASU 2018-01, land easements and rights-of-way are required to be assessed under ASU 2016-02 to determine whether the arrangements are or contain a lease. ASU 2018-01 permits an entity to elect a transition practical expedient to not apply ASU 2016-02 to land easements that exist or expired before the effective date of ASU 2016-02 and that were not previously assessed under the previous lease guidance in Accounting Standards Codification (ASC) Topic 840 “Leases.”

In July 2018, the FASB issued ASU 2018-11 “Leases (Topic 842): Targeted Improvements” (ASU 2018-11). Prior to ASU 2018-11, a modified retrospective transition was required for financing or operating leases existing at or entered into after the beginning of the earliest comparative period presented in the financial statements. ASU 2018-11 allows entities an additional transition method to the existing requirements whereby an entity could adopt the provisions of ASU 2016-02 by recognizing a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption without adjustment to the financial statements for periods prior to adoption. ASU 2018-11 also allows a

~~Notes (Continued)~~

practical expedient that permits lessors to not separate nonlease components from the associated lease component if certain conditions are present. ASU 2016-02 is effective for interim and annual periods beginning after December 15, 2018. We prospectively adopted ASU 2016-02 effective January 1, 2019, and did not adjust prior periods as permitted by ASU 2018-11 (see Note 10 – Leases).

We completed our review of contracts to identify leases based on the modified definition of a lease and implemented changes to our internal controls to support management in the accounting for and disclosure of leasing activities upon adoption of ASU 2016-02. We implemented a financial lease accounting system to assist management in the accounting for leases upon adoption. The most significant changes to our financial statements as a result of adopting ASU 2016-02 relate to the recognition of a $225 million lease liability and offsetting right-of-use asset in our ~~Consolidated Balance Sheet~~for operating leases. We also evaluated ASU 2016-02’s available practical expedients on adoption and have generally elected to adopt the practical expedients, which includes the practical expedient to not separate lease and nonlease components by both lessees and lessors by class of underlying assets and the land easements practical expedient.

~~Accounting standards issued but not yet adopted~~

~~In June 2016, the FASB issued ASU~~ 2016-13 “Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments” (ASU 2016-13). ASU 2016-13 ~~changes~~changed the impairment model for most financial assets and certain other instruments. For trade and other receivables, held-to-maturity debt securities, loans, and other instruments, entities ~~will be~~are required to use a ~~new~~ forward-looking “expected loss” model that generally will result in the earlier recognition of allowances for losses. ~~The guidance also requires increased disclosures.~~We adopted ASU 2016-13 is effective ~~for us for interim and annual periods beginning after December 15, 2019. We plan to adopt as of~~ January 1, ~~2020. We anticipate that ASU 2016-13 will~~2020, which primarily ~~apply~~applied to our short-term trade receivables. ~~While~~There was no cumulative effect adjustment to retained earnings upon adoption.

The majority of our trade receivable balances are due within 30 days. We monitor the credit quality of our counterparties through review of collection trends, credit ratings, and other analyses, such as bankruptcy monitoring. Financial assets from our natural gas transmission business and gathering and transportation business are segregated into separate pools for evaluation due to different counterparty risks inherent in each business. Changes in counterparty risk factors could lead to reassessment of the composition of our financial assets as separate pools or the need for additional pools. We calculate our allowance for credit losses incorporating an aging method. In estimating our expected credit losses, we utilized historical loss rates over many years, which included periods of both high and low commodity prices. Commodity prices could have a significant impact on a portion of our gathering and processing counterparties’ financial health and ability to satisfy current liabilities. Our expected credit loss estimate considered both internal and external forward-looking commodity price expectations, as well as counterparty credit ratings, and factors impacting their near-term liquidity. In addition, our expected credit loss estimate considered potential contractual, physical, and commercial protections and outcomes in the case of a counterparty bankruptcy. The physical location and nature of our services help to mitigate collectability concerns of our gathering and processing producer customers. Our gathering lines are physically connected to the wellhead and may be located in areas with limited service provider options, making them very costly to replicate by other providers. As such, our gathering assets play a critical role in our customers’ ability to generate operating cash flows. Commodity price movements generally do not impact the majority of our natural gas transmission businesses customers’ financial condition.

Past due accounts are generally written off against the allowance for doubtful accounts only after all collection attempts have been exhausted. Excluding previously discussed trade accounts receivable due from Chesapeake related to services provided prior to Chesapeake’s bankruptcy filing, we do not ~~expect~~have a significant financial impact, we have analyzed our historical credit loss experience and continue to develop and implement processes, procedures, and internal controls in order to make the necessary credit loss assessments and required disclosures upon adoption.material amount of past due receivables at September 30, 2020.

Note 2 – Acquisitions

As of December 31, 2018, we owned a 62 percent interest in ~~UEOM~~Utica East Ohio Midstream LLC (UEOM) which we accounted for as an equity-method investment. On March 18, 2019, we signed and closed the acquisition of the remaining 38 percent interest in UEOM. Total consideration paid, including post-closing adjustments, was $741 million in cash funded through credit facility borrowings and cash on ~~hand.~~hand, net of $13 million cash acquired. As a result of acquiring this additional interest, we obtained control of and ~~now consolidate~~consolidated UEOM.

UEOM is involved primarily in the processing and fractionation of natural gas and natural gas liquids in the Utica Shale play in eastern Ohio. The purpose of the acquisition is to enhance our position in the region. We expect synergies through common ownership of UEOM and our Ohio Valley midstream systems to create a more efficient platform for capital spending in the region, resulting in reduced operating and maintenance expenses and creating enhanced capabilities and benefits for producers in the area.

The acquisition of UEOM was accounted for as a business combination, which requires, among other things, that identifiable assets acquired and liabilities assumed be recognized at their acquisition date fair values. In March 2019, based on the transaction price for our purchase of the remaining interest in UEOM as finalized just prior to the acquisition, we recognized a $74 million noncash impairment loss related to our existing 62 percent interest (see Note 1312 – Fair Value Measurements and Guarantees). Thus, there was 0 gain or loss on remeasuring our existing equity-method investment to fair value due to the impairment recognized just prior to closing the acquisition of the additional interest.

The valuation techniques used to measure the acquisition date fair value of the UEOM acquisition consisted of the market approach for our previous equity-method investment in UEOM and the income approach (excess earnings method) for valuation of intangible assets and depreciated replacement costs for property, plant, and equipment.

The following table presents the allocation of the acquisition date fair value of the major classes of the assets acquired, which are presented in the Northeast G&P segment, and liabilities assumed at March 18, 2019. The net assets

Notes (Continued)

acquired reflect the sum of the consideration transferred and the noncash elimination of the fair value of our existing equity-method investment upon our acquisition of the additional interest. The fair value of accounts receivable acquired, presented in current assets in the table, equals contractual amounts receivable. After the March 31, 2019 financial statements were issued, we received an updated valuation report from a third-party valuation firm. Significant changes from the preliminary allocation disclosed in the first quarter to the final allocation reflect an increase of $169 million in goodwill, and decreases of $106 million in property, plant, and equipment and $61 million in other intangible assets.

(Millions)
Current assets, including $13 million cash acquired $ 55
Property, plant, and equipment 1,387
Other intangible assets 328
Total identifiable assets acquired 1,770

Current liabilities 7
Total liabilities assumed 7

Net identifiable assets acquired 1,763

Goodwill 188
Net assets acquired $ 1,951

The goodwill recognized in the acquisition relates primarily to enhancing and diversifying our basin positions and is reported within the Northeast G&P segment. Substantially all of the goodwill is expected to be deductible for tax purposes. Goodwill is included within ~~Intangible assets – net of accumulated amortization~~ ~~in the~~ ~~Consolidated Balance Sheet~~ and represents the excess of the consideration, plus the fair value of any previously held equity interest, over the fair value of the net assets acquired. It is not subject to amortization but is evaluated annually as of October 1 for impairment or more frequently if impairment indicators are present that would indicate it is more likely than not that the fair value of the reporting unit is less than its carrying amount.

Other intangible assets recognized in the acquisition are related to contractual customer relationships from gas gathering, processing, and fractionation agreements with our customers. The basis for determining the value of these intangible assets is estimated future net cash flows to be derived from acquired contractual customer relationships discounted using a risk-adjusted discount rate. These intangible assets are being amortized on a straight-line basis over an initial period of 20 years which represents the term over which the contractual customer relationships are expected to contribute to our cash flows. Approximately 49 percent of the expected future revenues from these contractual customer relationships are impacted by our ability and intent to renew or renegotiate existing customer contracts. We expense costs incurred to renew or extend the terms of our gas gathering, processing, and fractionation contracts with customers. Based on the estimated future revenues during the current contract periods (as estimated at the time of the acquisition), the weighted-average period prior to the next renewal or extension of the existing contractual customer relationships is approximately 10 years.

~~The following unaudited pro forma~~ ~~Revenues~~ ~~and~~ ~~Net income (loss) attributable to The Williams Companies, Inc.~~ for the three and nine months ended September 30, 2019 and 2018, are presented as if the UEOM acquisition had been completed on January 1, 2018. These pro forma amounts are not necessarily indicative of what the actual results would have been if the acquisition had in fact occurred on the date or for the periods indicated, nor do they purport to project ~~Revenues~~ or ~~Net income (loss) attributable to The Williams Companies, Inc.~~ for any future periods or as of any date. These amounts do not give effect to any potential cost savings, operating synergies, or revenue enhancements to result from the transaction or the potential costs to achieve these cost savings, operating synergies, and revenue enhancements.

~~Notes (Continued)~~

Three Months Ended
September 30, Nine Months Ended
September 30,
2019 2018 2019 2018
(Millions)
Revenues $ 1,999
$ 2,342
$ 6,126
$ 6,589

Net income (loss) attributable to The Williams Companies, Inc. $ 221
$ 138
$ 804
$ 434

~~Adjustments to pro forma~~ ~~Net income (loss) attributable to The Williams Companies, Inc.~~ include the removal of the previously described $74 million impairment loss recognized in March 2019 just prior to the acquisition. There are no pro forma adjustments for the three months ended September 30, 2019 as UEOM was consolidated and reflected in our results during the entire quarter.

~~During the period from the acquisition date of March 18, 2019 to September 30, 2019, UEOM contributed~~ ~~Revenues~~ ~~of $104 million and~~ ~~Net income (loss) attributable to The Williams Companies, Inc.~~ ~~of $25 million.~~

~~Costs related to this acquisition are $4 million and are reported within our Northeast G&P segment and included in~~ ~~Selling, general, and administrative expenses~~ ~~in our~~ ~~Consolidated Statement of Income~~.

Northeast JV

Concurrent with the UEOM acquisition, we executed an agreement whereby we contributed our consolidated interests in UEOM and our Ohio Valley midstream business to a newly formed partnership. In June 2019, our partner invested approximately $1.33 billion ~~(subject to post-closing adjustments)~~ for a 35 percent ownership interest, and we retained 65 percent ownership of, as well as operate and consolidate, the Northeast JV business. The change in ownership due to this transaction increased Noncontrolling interests in consolidated subsidiaries by ~~$568~~$567 million, and decreased Capital in excess of par value by $426 million and Deferred income tax liabilities by ~~$142~~$141 million in the Consolidated Balance Sheet for the year ended December 31, 2019.

The goodwill recognized in the UEOM acquisition of $187 million (includes a $1 million adjustment recorded in the first quarter of 2020) was impaired during the first quarter of 2020. Our partner’s $65 million share of this impairment is reflected within ~~. Costs related~~Net income (loss) attributable to ~~this transaction are $6 million and are reported within our Northeast G&P segment and included in~~ ~~Selling, general, and administrative expenses~~noncontrolling interests in ~~our~~ the Consolidated Statement of Income (see Note 12 – Fair Value Measurements and Guarantees).

Notes (Continued)

Note 3 – Revenue Recognition

Revenue by Category

The following table presents our revenue disaggregated by major service line:


																			Transco		Northwest Pipeline		Gulf of Mexico Midstream		Northeast Midstream		West Midstream		Other		Eliminations		Total
																			(Millions)
Three Months Ended September 30, 2020																		Three Months Ended September 30, 2020
Revenues from contracts with customers:																		Revenues from contracts with customers:
Service revenues:																		Service revenues:
Regulated interstate natural gas transportation and storage																		Regulated interstate natural gas transportation and storage	$	600	$	111	$	0	$	0	$	0	$	0	$	(3)	$	708
Gathering, processing, transportation, fractionation, and storage:																		Gathering, processing, transportation, fractionation, and storage:
Monetary consideration																		Monetary consideration	0		0		85		332		288		0		(17)		688
Commodity consideration																		Commodity consideration	0		0		6		2		32		0		0		40
Other																		Other	3		0		3		41		20		0		(2)		65
Total service revenues																		Total service revenues	603		111		94		375		340		0		(22)		1,501
Product sales:																		Product sales:
NGL and natural gas																		NGL and natural gas	21		0		26		12		394		0		(36)		417
Total revenues from contracts with customers																		Total revenues from contracts with customers	624		111		120		387		734		0		(58)		1,918
Other revenues (1)																		Other revenues (1)	2		0		3		6		0		8		(4)		15
Total revenues																		Total revenues	$	626	$	111	$	123	$	393	$	734	$	8	$	(62)	$	1,933
	Northeast Midstream		Atlantic- Gulf Midstream		West Midstream		Transco		Northwest Pipeline		Other		Intercompany Eliminations			Total
	(Millions)
Three Months Ended September 30, 2019	Three Months Ended September 30, 2019																	Three Months Ended September 30, 2019
Revenues from contracts with customers:																		Revenues from contracts with customers:
Service revenues:																		Service revenues:
Non-regulated gathering, processing, transportation, and storage:
Regulated interstate natural gas transportation and storage																		Regulated interstate natural gas transportation and storage	$	601	$	111	$	0	$	0	$	0	$	0	$	(2)	$	710
Gathering, processing, transportation, fractionation, and storage:																		Gathering, processing, transportation, fractionation, and storage:
Monetary consideration	$	310	$	117	$	308	$	—	$	—	$	—	$	(19	)	$	716	Monetary consideration	0		0		117		310		308		0		(19)		716
Commodity consideration	1		7		30		—		—		—		—			38		Commodity consideration	0		0		7		1		30		0		0		38
Regulated interstate natural gas transportation and storage	—		—		—		601		111		—		(2		)	710
Other	38		8		12		—		—		—		(5		)	53		Other	0		0		8		38		12		0		(5)		53
Total service revenues	349		132		350		601		111		—		(26		)	1,517		Total service revenues	601		111		132		349		350		0		(26)		1,517
Product Sales:
NGL and natural gas product sales	30		34		391		41		—		—		(28		)	468
Product sales:																		Product sales:
NGL and natural gas																		NGL and natural gas	41		0		34		30		391		0		(28)		468
Total revenues from contracts with customers	379		166		741		642		111		—		(54		)	1,985		Total revenues from contracts with customers	642		111		166		379		741		0		(54)		1,985
Other revenues (1)	5		2		—		3		—		7		(3		)	14		Other revenues (1)	3		0		2		5		0		7		(3)		14
Total revenues	$	384	$	168	$	741	$	645	$	111	$	7	$	(57	)	$	1,999	Total revenues	$	645	$	111	$	168	$	384	$	741	$	7	$	(57)	$	1,999

Three Months Ended September 30, 2018
Revenues from contracts with customers:
Service revenues:
Non-regulated gathering, processing, transportation, and storage:
Monetary consideration	$	219	$	139	$	409	$	—	$	—	$	1	$	(19	)	$	749
Commodity consideration	5		19		97		—		—		—		—			121
Regulated interstate natural gas transportation and storage	—		—		—		457		110		—		(1		)	566
Other	23		4		11		—		—		—		(4		)	34
Total service revenues	247		162		517		457		110		1		(24		)	1,470
Product Sales:
NGL and natural gas	69		88		720		41		—		—		(117		)	801
Other	—		—		12		—		—		—		(3		)	9
Total product sales	69		88		732		41		—		—		(120		)	810
Total revenues from contracts with customers	316		250		1,249		498		110		1		(144		)	2,280
Other revenues (1)	6		5		3		3		—		9		(3		)	23
Total revenues	$	322	$	255	$	1,252	$	501	$	110	$	10	$	(147	)	$	2,303

(1)Revenues not within the scope of Accounting Standards Codification Topic 606, “Revenue from Contracts with Customers,” consist of leasing revenues associated with our headquarters building and management fees that we receive for certain services we provide to operated equity-method investments, which are reported in Service revenues in our Consolidated Statement of Income, and amounts associated with our derivative contracts, which are reported in Product sales in our Consolidated Statement of Income.

Northeast
Midstream

Atlantic-
Gulf Midstream
West Midstream Transco Northwest Pipeline Other Intercompany Eliminations Total
(Millions)
Nine Months Ended September 30, 2019
Revenues from contracts with customers:
Service revenues:
Non-regulated gathering, processing, transportation, and storage:
Monetary consideration $ 840
$ 366
$ 1,007
$ —
$ —
$ —
$ (54 ) $ 2,159
Commodity consideration 9
33
116
—
—
—
—
158
Regulated interstate natural gas transportation and storage —
—
—
1,736
335
—
(4 ) 2,067
Other 104
21
32
1
—
—
(12 ) 146
Total service revenues 953
420
1,155
1,737
335
—
(70 ) 4,530
Product Sales:
NGL and natural gas product sales 114
140
1,300
88
—
—
(132 ) 1,510
Total revenues from contracts with customers 1,067
560
2,455
1,825
335
—
(202 ) 6,040
Other revenues (1) 15
6
12
8
—
22
(9 ) 54
Total revenues $ 1,082
$ 566
$ 2,467
$ 1,833
$ 335
$ 22
$ (211 ) $ 6,094

Nine Months Ended September 30, 2018
Revenues from contracts with customers:
Service revenues:
Non-regulated gathering, processing, transportation, and storage:
Monetary consideration $ 626
$ 404
$ 1,231
$ —
$ —
$ 2
$ (55 ) $ 2,208
Commodity consideration 14
45
257
—
—
—
—
316
Regulated interstate natural gas transportation and storage —
—
—
1,368
330
—
(2 ) 1,696
Other 65
12
35
1
—
—
(10 ) 103
Total service revenues 705
461
1,523
1,369
330
2
(67 ) 4,323
Product Sales:
NGL and natural gas 242
232
1,799
96
—
—
(285 ) 2,084
Other —
—
20
—
—
—
(4 ) 16
Total product sales 242
232
1,819
96
—
—
(289 ) 2,100
Total revenues from contracts with customers 947
693
3,342
1,465
330
2
(356 ) 6,423
Other revenues (1) 16
14
6
8
—
24
(9 ) 59
Total revenues $ 963
$ 707
$ 3,348
$ 1,473
$ 330
$ 26
$ (365 ) $ 6,482

~~(1)~~

Revenues not within the scope of ASC 606, “Revenue from Contracts with Customers,” consist of leasing revenues associated with our headquarters building and management fees that we receive for certain services we provide to operated equity-method investments, which are reported in ~~Service revenues~~ ~~in our Consolidated Statement of Income, and amounts associated with our derivative contracts, which are reported in~~ ~~Product sales~~ ~~in our Consolidated Statement of Income.~~

Notes (Continued)

Contract Assets

The following table presents a reconciliation of our contract assets:

Three Months Ended
September 30, Nine Months Ended
September 30,
2019 2018 2019 2018
(Millions)
Balance at beginning of period $ 17
$ 39
$ 4
$ 4
Revenue recognized in excess of amounts invoiced 14
17
53
53
Minimum volume commitments invoiced —
—
(26 ) (1 )
Balance at end of period $ 31
$ 56
$ 31
$ 56


	Three Months Ended September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
	(Millions)
Balance at beginning of period	$	30	$	17	$	8	$	4
Revenue recognized in excess of amounts invoiced	36		14		105		53
Minimum volume commitments invoiced	(24)		0		(71)		(26)
Balance at end of period	$	42	$	31	$	42	$	31

Contract Liabilities

The following table presents a reconciliation of our contract liabilities:

Three Months Ended
September 30, Nine Months Ended
September 30,
2019 2018 2019 2018
(Millions)
Balance at beginning of period $ 1,331
$ 1,535
$ 1,397
$ 1,596
Payments received and deferred 12
58
138
269
Deconsolidation of Jackalope interest (Note 5) —
—
—
(52 )
Significant financing component 3
4
10
11
Recognized in revenue (77 ) (112 ) (276 ) (339 )
Balance at end of period $ 1,269
$ 1,485
$ 1,269
$ 1,485


	Three Months Ended September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
	(Millions)
Balance at beginning of period	$	1,203	$	1,331	$	1,215	$	1,397
Payments received and deferred	14		12		116		138
Significant financing component	3		3		8		10
Recognized in revenue	(50)		(77)		(169)		(276)
Balance at end of period	$	1,170	$	1,269	$	1,170	$	1,269

Remaining Performance Obligations

Remaining performance obligations primarily include reservation charges on contracted capacity for our gas pipeline firm transportation contracts with customers, storage capacity contracts, long-term contracts containing minimum volume commitments associated with our midstream businesses, and fixed payments associated with offshore production handling. For our interstate natural gas pipeline businesses, remaining performance obligations reflect the rates for such services in our current ~~Federal Energy Regulatory Commission (FERC)~~FERC tariffs for the life of the related contracts; however, these rates may change based on future tariffs approved by the FERC and the amount and timing of these changes are not currently known.

Our remaining performance obligations exclude variable consideration, including contracts with variable consideration for which we have elected the practical expedient for consideration recognized in revenue as billed. Certain of our contracts contain evergreen and other renewal provisions for periods beyond the initial term of the contract. The remaining performance obligation amounts as of September 30, ~~2019,~~2020, do not consider potential future performance obligations for which the renewal has not been exercised and ~~excludes~~exclude contracts with customers for which the underlying facilities have not received FERC authorization to be placed into service. Consideration received prior to September 30, ~~2019,~~2020, that will be recognized in future periods is also excluded from our remaining performance obligations and is instead reflected in contract liabilities.

Notes (Continued)

The following table presents the amount of the contract liabilities balance ~~as of September 30, 2019,~~ expected to be recognized as revenue aswhen performance obligations are satisfied and the transaction price allocated to the remaining performance obligations under certain contracts as of September 30, ~~2019.~~2020.

~~Notes (Continued)~~

Contract Liabilities Remaining Performance Obligations
(Millions)
2019 (remainder) $ 70
$ 762
2020 167
3,028
2021 126
2,873
2022 112
2,705
2023 103
2,244
Thereafter 691
19,840
Total $ 1,269
$ 31,452


	Contract Liabilities		Remaining Performance Obligations
	(Millions)
2020 (remainder)	$	45	$	840
2021	72		3,315
2022	69		3,145
2023	54		2,811
2024	52		2,301

Thereafter	878		18,178
Total	$	1,170	$	30,590

Accounts Receivable

The following is a summary of our Trade accounts and other receivables– net:

September 30, 2019 December 31, 2018
(Millions)
Accounts receivable related to revenues from contracts with customers $ 791
$ 858
Other accounts receivable 84
134
Total reflected in Trade accounts and other receivables
$ 875
$ 992


	September 30, 2020		December 31, 2019
	(Millions)
Accounts receivable related to revenues from contracts with customers	$	868	$	890
Other accounts receivable	143		106
Total reflected in Trade accounts and other receivables – net	$	1,011	$	996

Note 4 – Variable Interest Entities

Consolidated VIEs

As of September 30, ~~2019,~~2020, we consolidate the following ~~variable interest entities (VIEs):~~

~~Gulfstar One~~

We own a 51 percent interest in Gulfstar One, a subsidiary that, due to certain risk-sharing provisions in its customer contracts, is a VIE. Gulfstar One includes a proprietary floating-production system, Gulfstar FPS, and associated pipelines which provide production handling and gathering services in the eastern deepwater Gulf of Mexico. We are the primary beneficiary because we have the power to direct the activities that most significantly impact Gulfstar One’s economic performance.

~~Constitution~~

We own a 41 percent interest in Constitution, a subsidiary that, due to shipper fixed-payment commitments under its long-term firm transportation contracts, is a VIE. We are the primary beneficiary because we have the power to direct the activities that most significantly impact Constitution’s economic performance. We, as operator of Constitution, are responsible for constructing the proposed pipeline, which will extend from Susquehanna County, Pennsylvania, to the Iroquois Gas Transmission and the Tennessee Gas Pipeline systems in New York. While we previously estimated the total remaining cost of the project to be approximately $740 million, this amount is expected to increase and the revised estimate is being developed. The project costs would be funded with capital contributions from us and the other equity partners on a proportional basis.

In December 2014, Constitution received approval from the FERC to construct and operate its proposed pipeline. However, in April 2016, the New York State Department of Environmental Conservation (NYSDEC) denied the necessary water quality certification under Section 401 of the Clean Water Act for the New York portion of the pipeline. In May 2016, Constitution appealed the NYSDEC’s denial of the Section 401 certification to the United States Court of Appeals for the Second Circuit, but in August 2017 the court issued a decision upholding NYSDEC’s denial. Constitution filed a petition for rehearing with the Second Circuit Court of Appeals, but in October 2017 the court denied our petition.

~~Notes (Continued)~~

In October 2017, we filed a petition for declaratory order requesting the FERC to find that, by operation of law, the Section 401 certification requirement for the New York State portion of Constitution’s pipeline project was waived due to the failure by the NYSDEC to act on Constitution’s Section 401 application within a reasonable period of time as required by the express terms of such statute. By orders issued in January 2018 and July 2018, the FERC denied our petition, finding that Section 401 provides that a state waives certification only when it does not act on an application within one year from the date of the application.

Thereafter, we petitioned the D.C. Circuit for review of the FERC’s decision. In November 2018, the D.C. Circuit granted a motion filed by the FERC to hold our appeal in abeyance pending a decision by the court in the ~~Hoopa Valley Tribe v. FERC~~ ~~case. In January 2019, the D.C. Circuit issued its decision in~~ ~~Hoopa Valley Tribe~~, finding that the applicant’s withdrawal and resubmission of a Clean Water Act Section 401 water quality certification request did not trigger new statutory periods of review for the state agencies, which resulted in the state agencies waiving their Section 401 authority regarding the hydropower project in question. As a result of the ~~Hoopa Valley Tribe~~ decision, the FERC filed a motion for voluntary remand of our appeal, and in February 2019, the D.C. Circuit granted the motion, sending our waiver case back to the FERC to determine whether or not NYSDEC waived its authority under Section 401.

~~On August 28, 2019, the FERC issued an order finding that NYSDEC waived its water quality certification authority under Section 401 with respect to Constitution. The FERC interpreted the~~ ~~Hoopa Valley Tribe~~ decision to stand for the general principle that where an applicant withdraws and resubmits an application for water quality certification for the purpose of avoiding Section 401’s one-year time limit, and the state agency does not act within one year of the receipt of the original application, the state agency has “failed or refused to act under Section 401” and, therefore, has waived its Section 401 authority.

~~The equity partners are evaluating the next steps in connection with advancing the project.~~

~~At September 30, 2019, capitalized project costs total $376 million, of which we have funded our proportionate share, and are included within~~ ~~Property, plant, and equipment~~ in the Consolidated Balance Sheet. Beginning in April 2016, we discontinued capitalization of development costs related to this project. It is possible that we could incur certain supplier-related costs in the event of a continued prolonged delay or termination of the project.

~~Cardinal~~

~~We own a~~66 percent interest in Cardinal, a subsidiary that provides gathering services for the Utica Shale region and is a VIE due to certain risks shared with customers. We are the primary beneficiary because we have the power to direct the activities that most significantly impact Cardinal’s economic performance. Future expansion activity is expected to be funded with capital contributions from us and the other equity partner on a proportional basis.VIEs:

Northeast JV

~~As a result of the June 2019 sale of a 35 percent interest in the Northeast JV (see Note 2 – Acquisitions), we now~~We own a 65 percent interest in the Northeast JV, a subsidiary that is a VIE due to certain of our voting rights being disproportionate to our obligation to absorb losses and substantially all of the Northeast JV’s activities being performed on our behalf. We are the primary beneficiary because we have the power to direct the activities that most significantly impact the Northeast JV’s economic performance. The Northeast JV provides midstream services for producers in the Marcellus Shale and Utica Shale regions. Future expansion activity is expected to be funded with capital contributions from us and the other equity partner on a proportional basis.

Gulfstar One

We own a 51 percent interest in Gulfstar One, a subsidiary that, due to certain risk-sharing provisions in its customer contracts, is a VIE. Gulfstar One includes a proprietary floating production system, Gulfstar FPS, and associated pipelines that provide production handling and gathering services in the eastern deepwater Gulf of Mexico. We are the primary beneficiary because we have the power to direct the activities that most significantly impact Gulfstar One’s economic performance.

Cardinal

We own a66 percent interest in Cardinal, a subsidiary that provides gathering services for the Utica Shale region and is a VIE due to certain risks shared with customers. We are the primary beneficiary because we have the power to direct the activities that most significantly impact Cardinal’s economic performance. Future expansion activity is expected to be funded with capital contributions from us and the other equity partner on a proportional basis.

Notes (Continued)

The following table presents amounts included in our Consolidated Balance Sheet that are only for the use or obligation of our consolidated VIEs:


	September 30, 2020		December 31, 2019
	(Millions)
Assets (liabilities):
Cash and cash equivalents	$	62	$	102
Trade accounts and other receivables – net	150		167


Other current assets and deferred charges	6		5

Property, plant, and equipment – net	5,562		5,745
Intangible assets – net of accumulated amortization	2,404		2,669
Regulatory assets, deferred charges, and other	12		13
Accounts payable	(27)		(58)

Accrued liabilities	(36)		(66)




Regulatory liabilities, deferred income, and other	(287)		(283)

September 30,
2019
December 31,
2018

(Millions)
Assets (liabilities):

Cash and cash equivalents $ 90
$ 33
Trade accounts and other receivables – net 152
62
Other current assets and deferred charges 5
2
Property, plant, and equipment – net 6,167
2,363
Intangible assets – net of accumulated amortization 2,697
1,177
Regulatory assets, deferred charges, and other 13
—
Accounts payable (54 ) (15 )
Accrued liabilities (100 ) (115 )
Regulatory liabilities, deferred income, and other (268 ) (264 )

Nonconsolidated VIEs

~~Jackalope~~

~~At December 31, 2018, we owned a~~50 percent interest in Jackalope, which provides gathering and processing services for the Powder River basin and was a VIE due to certain risks shared with customers. In April 2019, we sold our interest in Jackalope for $485 million in cash (see Note 5 – Investing Activities).

Brazos Permian II

We own a 15 percent interest in Brazos Permian II, which provides gathering and processing services in the Delaware basin and is a VIE due primarily to our limited participating rights as the minority equity holder. ~~At September 30, 2019,~~During the ~~carrying value~~first quarter of 2020 we recorded an impairment of our equity-method investment in Brazos Permian II ~~was $197 million.~~(see Note 12 – Fair Value Measurements and Guarantees). Our ~~maximum~~ exposure to loss is limited to the carrying value of our investment.

Note 5 – Investing Activities

The following table presents certain items reflected in Other investing income (loss) – net in the Consolidated Statement of ~~Income~~:Income:

Three Months Ended
September 30, Nine Months Ended
September 30,
2019 2018 2019 2018
(Millions)
Impairment of equity-method investments (Note 13) $ (114 ) $ —
$ (186 ) $ —
Gain (loss) on deconsolidation of businesses —
—
(2 ) 62
Gain on disposition of equity-method investments —
—
122
—
Other 7
2
12
12
Other investing income (loss) – net
$ (107 ) $ 2
$ (54 ) $ 74


	Three Months Ended September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
	(Millions)

Gain on disposition of equity-method investments (1)	$	0	$	0	$	0	$	122
Other	2		7		6		10
Other investing income (loss) – net	$	2	$	7	$	6	$	132

~~Jackalope Deconsolidation~~_______________

During the second quarter of 2018, we deconsolidated our 50 percent interest in Jackalope. We recorded our interest in Jackalope as an equity-method investment at its estimated fair value, resulting in a deconsolidation gain of

~~Notes (Continued)~~

$62 million. We estimated the fair value of our interest to be $310 million using an income approach based on expected future cash flows and an appropriate discount rate (a Level 3 measurement within the fair value hierarchy). The determination of expected future cash flows involved significant assumptions regarding gathering and processing volumes and related capital spending. A 10.9 percent discount rate was utilized and reflected our estimate of the cost of capital as impacted by market conditions and risks associated with the underlying business. The deconsolidated carrying value of the net assets of Jackalope included $47 million of goodwill.

~~Sale of Jackalope~~

(1) In April 2019, we sold our 50 percent equity-method interest in Jackalope for $485 million in cash, resulting in a gain on the disposition of $122 million.

Impairment of Equity-Method Investments

See Note 12 – Fair Value Measurements and Guarantees for information regarding impairments of our equity-method investments.

Notes (Continued)

Impairment of RMM Goodwill

Equity earnings (losses) for the nine months ended September 30, 2020, includes a $78 million loss associated with the first-quarter 2020 full impairment of goodwill recognized by our investee RMM, which was allocated entirely to our member interest per the terms of the membership agreement.

Note 6 – Other ~~Income and Expenses~~Accruals

~~The following table presents, by segment, certain other items included in our~~ ~~Consolidated Statement of Income~~:

Three Months Ended
September 30, Nine Months Ended
September 30,
2019 2018 2019 2018
(Millions)
Selling, general, and administrative expenses
Other
Charitable contribution of preferred stock to The Williams Companies Foundation, Inc. (see Note 12) $ —
$ 35
$ —
$ 35
WPZ Merger costs —
15
—
19

Other (income) expense – net within Costs and expenses

Atlantic-Gulf
Amortization of regulatory assets associated with asset retirement obligations 1
8
17
24
Net accrual (amortization) of regulatory liability related to overcollection of certain employee expenses (9 ) 5
(11 ) 16
Adjustments to regulatory liabilities related to tax reform —
—
—
(10 )
Amortization of regulatory liability associated with tax reform (12 ) —
(19 ) —
Reversal of expenditures previously capitalized —
—
10
—
Gain on asset retirement —
(10 ) —
(10 )

West
Adjustments to regulatory liabilities related to tax reform —
—
—
(7 )
Regulatory charge per approved rates related to tax reform 6
6
18
18
Charge for regulatory liability associated with the decrease in Northwest Pipeline’s estimated deferred state income tax rates following WPZ Merger —
12
—
12

Other
Change to (benefit of) regulatory asset associated with Transco’s estimated deferred state income tax rate following WPZ Merger —
(37 ) 12
(37 )

Other income (expense) – net below Operating income (loss)

Atlantic-Gulf
Allowance for equity funds used during construction 9
32
21
78

Other
Income associated with a regulatory asset related to deferred taxes on equity funds used during construction 3
19
7
28
Net loss associated with early retirement of debt —
—
—
(7 )

In conjunction with a previously announced organizational realignment and considering asset sales in recent years, we are evaluating our cost structure and have implemented a voluntary separation program (VSP) for certain eligible employees. Operating and maintenance expenses for the three and nine months ended September 30, 2019, reflect charges of $7 million and $30 million, respectively, and Selling, general, and administrative expenses for the three and

~~Notes (Continued)~~

nine months ended September 30, 2019, reflect charges of $3 million and $23 million, respectively, for estimated severance and related costs, primarily associated with ~~the VSP.~~a voluntary separation program. The severance and related costs by segment for the three and nine months ended September 30, 2019 are as follows:


	Three Months Ended September 30,		Nine Months Ended September 30,
	2019
	(Millions)
Transmission & Gulf of Mexico	$	14	$	36
Northeast G&P	(3)		7
West	(1)		10
Total	$	10	$	53

Three Months Ended September 30, Nine Months Ended September 30,
2019
(Millions)
Northeast G&P $ (3 ) $ 7
Atlantic-Gulf 11
30
West 2
16
Total $ 10
$ 53

Note 7 – Provision (Benefit) for Income Taxes

The Provision (benefit) for income taxes includes:

Three Months Ended
September 30, Nine Months Ended
September 30,
2019 2018 2019 2018
(Millions)
Current:
Federal $ (10 ) $ (19 ) $ (25 ) $ (55 )
State —
—
—
1
Foreign 1
—
1
—
(9 ) (19 ) (24 ) (54 )
Deferred:
Federal 73
188
225
312
State 13
21
43
39
86
209
268
351
Provision (benefit) for income taxes $ 77
$ 190
$ 244
$ 297

The effective income tax rates for the total provision (benefit) for the three and nine months ended September 30, 2020 and 2019 are greater than the federal statutory rate, primarily due to the effect of state income taxes.

The effective income tax rates for the total provision for the three and nine months ended September 30, 2018, are higher than the federal statutory rate primarily due to the effect of state income taxes and a $105 million valuation allowance associated with foreign tax credits, that expire between 2024 and 2027. This is partially offset by the impact of the allocation of income to nontaxable noncontrolling interests. The state income tax provisions include a $38 million provision related to an increase in the deferred state income tax rate (net of federal benefit) partially offset by a net decrease in valuation allowances of $31 million on state net operating losses, both primarily driven by the impact that the completion of the WPZ Merger (see Note 1 – General, Description of Business, and Basis of Presentation) had on income allocation for state tax purposes.

A valuation allowance for deferred tax assets, including foreign tax credits, is recognized when it is more likely than not that some, or all, of the benefit from the deferred tax asset will not be realized. To assess that likelihood, we use estimates and judgment regarding our sources of future taxable income, including available tax planning strategies, to determine whether a valuation allowance is required. The completion of the WPZ Merger decreased our deferred income tax liability by $1.829 billion at September 30, 2018. Increased tax depreciation from the additional tax basis will reduce taxable income in future years and may limit our ability to realize the full benefit of certain short-lived deferred tax assets.

During the next 12 months, we do not expect ultimate resolution of any unrecognized tax benefit associated with domestic or international matters to have a material impact on our unrecognized tax benefit position.

Three Months Ended
September 30, Nine Months Ended
September 30,
2019 2018 2019 2018

(Dollars in millions, except per-share
amounts; shares in thousands)
Net income (loss) available to common stockholders $ 220
$ 129
$ 724
$ 416
Basic weighted-average shares 1,212,270
1,023,587
1,211,938
893,706
Effect of dilutive securities:
Nonvested restricted stock units 1,790
2,387
1,809
2,102
Stock options 105
530
196
514
Diluted weighted-average shares 1,214,165
1,026,504
1,213,943
896,322
Earnings (loss) per common share:
Basic $ .18
$ .13
$ .60
$ .47
Diluted $ .18
$ .13
$ .60
$ .46


	Three Months Ended September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
	(Dollars in millions, except per-share amounts; shares in thousands)
Net income (loss) available to common stockholders	$	308	$	220	$	93	$	724
Basic weighted-average shares	1,213,912		1,212,270		1,213,512		1,211,938
Effect of dilutive securities:
Nonvested restricted stock units	1,423		1,790		1,241		1,809
Stock options	0		105		4		196
Diluted weighted-average shares	1,215,335		1,214,165		1,214,757		1,213,943
Earnings (loss) per common share:
Basic	$	.25	$	.18	$	.08	$	.60
Diluted	$	.25	$	.18	$	.08	$	.60

Note 9 – Employee Benefit Plans

Net periodic benefit cost (credit) is as follows:

Pension Benefits

Three Months Ended
September 30,
Nine Months Ended
September 30,

2019
2018
2019
2018

(Millions)
Components of net periodic benefit cost (credit):

Service cost $ 11

$ 12

$ 33

$ 37
Interest cost 13

12

38

35
Expected return on plan assets (15 )
(16 )
(46 )
(47 )
Amortization of net actuarial loss 3

6

11

17
Net actuarial loss from settlements 1

1

1

2
Net periodic benefit cost (credit) $ 13

$ 15

$ 37

$ 44


	Pension Benefits
	Three Months Ended September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
	(Millions)
Components of net periodic benefit cost (credit):
Service cost	$	8	$	11	$	23	$	33
Interest cost	9		13		28		38
Expected return on plan assets	(13)		(15)		(40)		(46)

Amortization of net actuarial loss	5		3		16		11
Net actuarial loss from settlements	1		1		9		1
Net periodic benefit cost (credit)	$	10	$	13	$	36	$	37

The components of Net periodic benefit cost (credit) other than the Service cost component are included in Other income (expense) – net below Operating income (loss) in the Consolidated Statement of ~~Income~~.Income.

~~Notes (Continued)~~

~~Amortization of prior service credit~~ ~~included in~~ ~~Net periodic benefit cost (credit)~~ ~~for our other postretirement benefit plans associated with Transco and Northwest Pipeline is recorded to regulatory assets/liabilities instead of Other comprehensive income (loss).~~ ~~The amount of~~ ~~Amortization of prior service credit~~ ~~recognized in regulatory liabilities was $1 million for~~During the nine months ended September 30, ~~2018.~~

~~During the~~ ~~nine~~ ~~months ended~~ ~~September 30, 2019~~,2020, we contributed ~~$63~~$12 million to our pension plans and $4$4 million to our other postretirement benefit plans. We presently anticipate making additional contributions of

approximately $1$2 million to our pension plans and approximately $1 million to our other postretirement benefit plans in the remainder of ~~2019.~~2020.

~~Note 10 – Leases~~

We are a lessee through noncancellable lease agreements for property and equipment consisting primarily of buildings, land, vehicles, and equipment used in both our operations and administrative functions. We recognize a lease liability with an offsetting right-of-use asset in our ~~Consolidated Balance Sheet~~ for operating leases based on the present value of the future lease payments. As an accounting policy, we have elected to combine lease and nonlease components for all classes of leased assets in our calculation of the lease liability and the offsetting right-of-use asset.

Our lease agreements require both fixed and variable periodic payments, with initial terms typically ranging from one year to 15 years, but a certain land lease has a term of 108 years. Payment provisions in certain of our lease agreements contain escalation factors which may be based on stated rates or a change in a published index at a future time. The amount by which a lease escalates based on the change in a published index, which is not known at lease commencement, is considered a variable payment and is not included in the present value of the future lease payments, which only includes those that are stated or can be calculated based on the lease agreement at lease commencement. In addition to the noncancellable periods, many of our lease agreements provide for one or more extensions of the lease agreement for periods ranging from one year in length to an indefinite number of times following the specified contract term. Other lease agreements provide for extension terms that allow us to utilize the identified leased asset for an indefinite period of time so long as the asset continues to be utilized in our operations. In consideration of these renewal features, we assess the term of the lease agreements, which includes using judgment in the determination of which renewal periods and termination provisions, when at our sole election, will be reasonably certain of being exercised. Periods after the initial term or extension terms that allow for either party to the lease to cancel the lease are not considered in the assessment of the lease term. Additionally, we have elected to exclude leases with an original term of one year or less, including renewal periods, from the calculation of the lease liability and the offsetting right-of-use asset.

We used judgment in determining the discount rate upon which the present value of the future lease payments is determined. This rate is based on a collateralized interest rate corresponding to the term of the lease agreement using company, industry, and market information available.

~~When permitted under our lease agreements, we may sublease certain unused office space for fixed periods that could extend up to the length of the original lease agreement.~~

~~Notes (Continued)~~

Three Months Ended
September 30, Nine Months Ended
September 30,
2019
(Millions)
Lease Cost:
Operating lease cost $ 10
$ 31
Short-term lease cost —
—
Variable lease cost 7
21
Sublease income —
(1 )
Total lease cost $ 17
$ 51
Cash paid for amounts included in the measurement of operating lease liabilities $ 10
$ 30
September 30, 2019
(Millions)
Other Information:
Right-of-use asset (included in Regulatory assets, deferred charges, and other in our Consolidated Balance Sheet)
$ 213
Operating lease liabilities:
Current (included in Accrued liabilities in our Consolidated Balance Sheet)
$ 23
Noncurrent (included in Regulatory liabilities, deferred income, and other in our Consolidated Balance Sheet)
$ 190
Weighted-average remaining lease term – operating leases (years)
13
Weighted-average discount rate – operating leases
4.60%

As of September 30, 2019, the following table represents our operating lease maturities, including renewal provisions that we have assessed as being reasonably certain of exercise, for each of the years ended December 31:

(Millions)
2019 (remainder) $ 8
2020 32
2021 33
2022 27
2023 21
Thereafter 171
Total future lease payments 292
Less amount representing interest 79
Total obligations under operating leases $ 213

~~We are the lessor to certain lease agreements for office space in our headquarters building, which are insignificant to our financial statements.~~

Note 1110 – Debt and Banking Arrangements

~~Retirements~~Issuances and retirements

On August 17, 2020, we retired $600 million of 4.125 percent senior unsecured notes that were due November 15, 2020.

On May 14, 2020, we completed a public offering of $1 billion of 3.5 percent senior unsecured notes due 2030.

On May 8, 2020, Transco issued $700 million of 3.25 percent senior unsecured notes due 2030 and $500 million of 3.95 percent senior unsecured notes due 2050 to investors in a private debt placement. As part of the issuance, Transco entered into a registration rights agreement with the initial purchasers of the unsecured notes. Transco is obligated to file and consummate a registration statement for an offer to exchange the notes for a new issue of substantially identical notes registered under the Securities Act of 1933, as amended, within 365 days from closing and to use commercially reasonable efforts to complete the exchange offer. Transco is required to provide a shelf registration statement to cover resales of the notes under certain circumstances. If Transco fails to fulfill these obligations, additional interest will accrue on the affected securities. The rate of additional interest will be 0.25 percent per annum on the principal amount of the affected securities for the first 90-day period immediately following the occurrence of a registration default, increasing by an additional 0.25 percent per annum with respect to each subsequent 90-day period thereafter, up to a maximum amount for all such registration defaults of 0.5 percent annually. Following the cure of any registration defaults, the accrual of additional interest will cease.

We retired ~~approximately $32 million~~$1.5 billion of ~~7.625~~5.25 percent senior unsecured notes that matured on ~~July~~March 15, ~~2019.~~2020.

We retired $14 million of 8.75 percent senior unsecured notes that matured on January 15, 2020.

Commercial Paper Program

At September 30, ~~2019, 0 commercial~~2020, $40 million of Commercial paper was outstanding under our $4 billion commercial paper ~~program.~~

~~Notes (Continued)~~

program with a weighted average interest rate of 0.35 percent.


	September 30, 2020
	Stated Capacity		Outstanding
	(Millions)

Long-term credit facility (1)	$	4,500	$	0
Letters of credit under certain bilateral bank agreements			15

(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.

Note 1211 – Stockholders’ Equity

~~Issuance~~Stockholder Rights Agreement

On March 19, 2020, our board of ~~Preferred Shares~~directors approved the adoption of a limited duration stockholder rights agreement (Rights Agreement) and declared a distribution of 1 preferred stock purchase right for each outstanding share of common stock. The Rights Agreement is intended to protect the interests of us and our stockholders by reducing the likelihood of another party gaining control of or significant influence over us without paying an

~~In July 2018, through~~

appropriate premium considering recent volatile markets. Each preferred stock purchase right represents the right to purchase, upon certain terms and conditions, one one-thousandth (.001) of a ~~wholly owned subsidiary, we contributed 35,000 shares~~share of ~~newly issued~~ Series ~~B Non-Voting Perpetual~~C Participating Cumulative Preferred Stock, (Preferred Stock) to The Williams Companies Foundation, Inc. (a not-for-profit corporation) for use in future charitable and nonprofit causes. The charitable contribution of Preferred Stock was recorded as an expense in the third quarter of 2018. The Preferred Stock was issued for an aggregate value of $35 million and pays non-cumulative quarterly cash dividends when, as and if declared, at a rate of 7.25 percent per year. Our certificate of incorporation authorizes 30 million shares of Preferred Stock, $1$1.00 par value per ~~shares.~~share. Each one-thousandth (.001) of a share of Series C Participating Cumulative Preferred Stock, if issued, would have rights similar to one share of our common stock. The distribution of preferred stock purchase rights occurred on March 30, 2020, to holders of record as of the close of business on that date. The Rights Agreement expires on March 20, 2021. Please see our Current Report on Form 8-K dated March 20, 2020, for additional details of the Rights Agreement.

On August 27, 2020, a purported shareholder filed a putative class action lawsuit in the Delaware Court of Chancery challenging the Rights Agreement. The plaintiff alleges that the individual members of our board of directors breached their fiduciary duties by adopting the Rights Agreement. The complaint seeks declaratory relief, an injunction against the agreement, and an award of attorneys’ fees and costs, which are not expected to be material. On September 3, 2020, a purported shareholder filed a separate putative class action lawsuit in the Delaware Court of Chancery, asserting identical claims to the August 27, 2020 lawsuit. The court consolidated the lawsuits, and trial is scheduled to begin January 11, 2021.

The following table presents the changes in AOCI by component, net of income taxes:

Cash
Flow
Hedges

Foreign
Currency
Translation

Pension and
Other Postretirement
Benefits
Total
(Millions)
Balance at December 31, 2018 $ (2 ) $ (1 ) $ (267 ) $ (270 )
Other comprehensive income (loss) before reclassifications
—
—
(5 ) (5 )
Amounts reclassified from accumulated other comprehensive income (loss)
—
—
9
9
Other comprehensive income (loss) —
—
4
4
Balance at September 30, 2019 $ (2 ) $ (1 ) $ (263 ) $ (266 )

Other comprehensive income (loss) before reclassifications

Amounts reclassified from accumulated other comprehensive income (loss)

Reclassifications out of AOCI are presented in the following table by component for the nine months ended September 30, ~~2019:~~2020:

Other income (expense) – net below Operating income (loss)

Component Reclassifications Classification
(Millions)
Pension and other postretirement benefits:
Amortization of actuarial (gain) loss and net actuarial loss from settlements included in net periodic benefit cost (credit) $ 12
Note 9 – Employee Benefit Plans
Income tax benefit (3 ) Provision (benefit) for income taxes
Reclassifications during the period $ 9

Notes (Continued)

Note 1312 – Fair Value Measurements and Guarantees

The following table presents, by level within the fair value hierarchy, certain of our significant financial assets and liabilities. The carrying values of cash and cash equivalents, accounts receivable, margin deposits, commercial paper, and accounts payable approximate fair value because of the short-term nature of these instruments. Therefore, these assets and liabilities are not presented in the following table.

Fair Value Measurements Using

Carrying
Amount

Fair
Value

Quoted
Prices In
Active
Markets for
Identical
Assets
(Level 1)

Significant
Other
Observable
Inputs
(Level 2)

Significant
Unobservable
Inputs
(Level 3)
(Millions)
Assets (liabilities) at September 30, 2019:
Measured on a recurring basis:
ARO Trust investments $ 187
$ 187
$ 187
$ —
$ —
Energy derivatives assets not designated as hedging instruments 4
4
4
—
—
Energy derivatives liabilities not designated as hedging instruments (5 ) (5 ) (2 ) —
(3 )
Additional disclosures:
Long-term debt, including current portion (22,257 ) (25,234 ) —
(25,234 ) —
Guarantees (42 ) (29 ) —
(13 ) (16 )

Assets (liabilities) at December 31, 2018:
Measured on a recurring basis:
ARO Trust investments $ 150
$ 150
$ 150
$ —
$ —
Energy derivatives assets not designated as hedging instruments 3
3
3
—
—
Energy derivatives liabilities not designated as hedging instruments (7 ) (7 ) (4 ) —
(3 )
Additional disclosures:
Long-term debt, including current portion (22,414 ) (23,330 ) —
(23,330 ) —
Guarantees (43 ) (30 ) —
(14 ) (16 )


					Fair Value Measurements Using
	Carrying Amount		Fair Value		Quoted Prices In Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
	(Millions)
Assets (liabilities) at September 30, 2020:
Measured on a recurring basis:
ARO Trust investments	$	220	$	220	$	220	$	0	$	0




Additional disclosures:

Long-term debt, including current portion	(22,343)		(26,000)		0		(26,000)		0
Guarantees	(41)		(27)		0		(11)		(16)

Assets (liabilities) at December 31, 2019:
Measured on a recurring basis:
ARO Trust investments	$	201	$	201	$	201	$	0	$	0



Additional disclosures:
Long-term debt, including current portion	(22,288)		(25,319)		0		(25,319)		0
Guarantees	(41)		(27)		0		(11)		(16)

Fair Value Methods

We use the following methods and assumptions in estimating the fair value of our financial instruments:

Assets and liabilities measured at fair value on a recurring basis

ARO Trust investments: Transco deposits a portion of its collected rates, pursuant to its rate case settlement, into an external trust (ARO Trust) that is specifically designated to fund future asset retirement obligations (ARO). The ARO Trust invests in a portfolio of actively traded mutual funds that are measured at fair value on a recurring basis based on quoted prices in an active market and is reported in Regulatory assets, deferred charges, and other in the Consolidated Balance Sheet. Both realized and unrealized gains and losses are ultimately recorded as regulatory assets or liabilities.

~~Energy derivatives~~: Energy derivatives include commodity-based exchange-traded contracts and over-the-counter contracts, which consist of physical forwards, futures, and swaps that are measured at fair value on a recurring basis. The fair value amounts are presented on a gross basis and do not reflect the netting of asset and liability positions

~~Notes (Continued)~~

permitted under the terms of our master netting arrangements. Further, the amounts do not include cash held on deposit in margin accounts that we have received or remitted to collateralize certain derivative positions. Energy derivatives assets are reported in ~~Other current assets and deferred charges~~ ~~and~~ ~~Regulatory assets, deferred charges, and other~~ ~~in the Consolidated Balance Sheet. Energy derivatives liabilities are reported in~~ ~~Accrued liabilities~~ ~~and~~ ~~Regulatory liabilities, deferred income, and other~~ ~~in the Consolidated Balance Sheet.~~

Reclassifications of fair value between Level 1, Level 2, and Level 3 of the fair value hierarchy, if applicable, are made at the end of each quarter. No transfers between Level 1 and Level 2 occurred during the ~~nine~~ ~~months ended~~ ~~September 30, 2019~~ or ~~2018~~.

Additional fair value disclosures

Long-term debt, including current portion: The disclosed fair value of our long-term debt is determined primarily by a market approach using broker quoted indicative period-end bond prices. The quoted prices are based on observable transactions in less active markets for our debt or similar instruments. The fair values of the financing obligations associated with our Dalton lateral and Atlantic Sunrise projects, which are included within long-term debt, were determined using an income approach.

Guarantees: Guarantees primarily consist of a guarantee we have provided in the event of nonpayment by our previously owned communications subsidiary, Williams Communications Group (WilTel), on a lease performance obligation that extends through 2042. Guarantees also include an indemnification related to a disposed operation.

Notes (Continued)

To estimate the fair value of the WilTel guarantee, an estimated default rate is applied to the sum of the future contractual lease payments using an income approach. The estimated default rate is determined by obtaining the average cumulative issuer-weighted corporate default rate based on the credit rating of WilTel’s current owner and the term of the underlying obligation. The default rate is published by Moody’s Investors Service. The carrying value of the WilTel guarantee is reported in Accrued liabilities in the Consolidated Balance Sheet. The maximum potential undiscounted exposure is approximately ~~$28~~$27 million at September 30, ~~2019.~~2020. Our exposure declines systematically through the remaining term of WilTel’s obligation.

The fair value of the guarantee associated with the indemnification related to a disposed operation was estimated using an income approach that considered probability-weighted scenarios of potential levels of future performance. The terms of the indemnification do not limit the maximum potential future payments associated with the guarantee. The carrying value of this guarantee is reported in Regulatory liabilities, deferred income, and other in the Consolidated Balance Sheet.

We are required by our revolving credit agreement to indemnify lenders for certain taxes required to be withheld from payments due to the lenders and for certain tax payments made by the lenders. The maximum potential amount of future payments under these indemnifications is based on the related borrowings and such future payments cannot currently be determined. These indemnifications generally continue indefinitely unless limited by the underlying tax regulations and have 0 carrying value. We have never been called upon to perform under these indemnifications and have no current expectation of a future claim.

Nonrecurring fair value measurements

During the first quarter of 2020, we observed a significant decline in the publicly traded price of our common stock (NYSE: WMB), which declined 40 percent during the quarter, including a 26 percent decline in the month of March. These changes were generally attributed to macroeconomic and geopolitical conditions, including significant declines in crude oil prices driven by both surplus supply and a decrease in demand caused by the novel coronavirus (COVID-19) pandemic. As a result of these conditions, we performed an interim assessment of the goodwill associated with our Northeast G&P reporting unit as of March 31, 2020. This goodwill resulted from the March 2019 acquisition of UEOM (see Note 2 – Acquisitions).

The assessment considered the total fair value of the businesses within the Northeast G&P reporting unit, which was determined using income and market approaches. We utilized internally developed industry weighted-average discount rates and estimates of valuation multiples of comparable publicly traded gathering and processing companies. In assessing the fair value as of the March 31, 2020 measurement date, we were required to consider recent publicly available indications of value, which included lower observed publicly traded EBITDA (earnings before interest, taxes, depreciation, and amortization) market multiples as compared with recent history and significantly higher industry weighted-average discount rates. The fair value of the reporting unit was further reconciled to our estimated total enterprise value as of March 31, 2020, which considered observable valuation multiples of comparable publicly traded companies applied to each distinct business including the Northeast G&P reporting unit. This assessment indicated that the estimated fair value of the Northeast G&P reporting unit was below its carrying value, including goodwill. As a result of this Level 3 measurement, we recognized a full impairment charge of $187 million as of March 31, 2020, in Impairment of goodwill in the Consolidated Statement of Income. Our partner’s $65 million share of this impairment is reflected within Net income (loss) attributable to noncontrolling interests in the Consolidated Statement of Income (see Note 2 – Acquisitions).

Notes (Continued)

~~Nonrecurring fair value measurements~~

The following table presents impairments of assets and equity-method investments associated with certain nonrecurring fair value measurements within Level 3 of the fair value hierarchy, except as specifically noted.


					Impairments														Impairments
					Nine Months Ended September 30,														Nine Months Ended September 30,
	Segment	Date of Measurement	Fair Value		2019			2018				Segment		Date of Measurement		Fair Value			2020		2019
			(Millions)													(Millions)
Impairment of certain assets:										Impairment of certain assets:
Certain gathering assets (1)	West	June 30, 2019	$	40	$	59				Certain gathering assets (1)		West		June 30, 2019		$	40				$	59
Certain idle gathering assets (2)	West	March 31, 2019	—		12					Certain idle gathering assets (2)		West		March 31, 2019		0					12
Certain idle pipeline assets (3)	Other	June 30, 2018	25					$	66
Other impairments and write-downs					5			—		Other impairments and write-downs											5
Impairment of certain assets					$	76		$	66	Impairment of certain assets											$	76
Impairment of equity-method investments:										Impairment of equity-method investments:
RMM (3)										RMM (3)		West		March 31, 2020		$	557		$	243
Brazos Permian II (3)										Brazos Permian II (3)		West		March 31, 2020		0			193
Caiman II (4)										Caiman II (4)		Northeast G&P		March 31, 2020		191			229
Appalachia Midstream Investments ~~(5)~~(4)											Northeast G&P		March 31, 2020		2,700			127
Aux Sable (4)										Aux Sable (4)		Northeast G&P		March 31, 2020		7			39
Laurel Mountain (4)	Northeast G&P	September 30, 2019	$	242	$	79				Laurel Mountain (4)		Northeast G&P		March 31, 2020		236			10
Appalachia Midstream Investments ~~(5)~~(4)	Northeast G&P	September 30, 2019	102		17
Pennant (6)	Northeast G&P	August 31, 2019	11		17
UEOM (7)	Northeast G&P	March 17, 2019	1,210		74
Discovery (4)										Discovery (4)		Transmission & Gulf of Mexico		March 31, 2020		367			97
Laurel Mountain (5)										Laurel Mountain (5)		Northeast G&P		September 30, 2019		242					$	79
Appalachia Midstream Investments (6)										Appalachia Midstream Investments (6)		Northeast G&P		September 30, 2019		102					17
Pennant (7)										Pennant (7)		Northeast G&P		August 31, 2019		11					17
UEOM (8)										UEOM (8)		Northeast G&P		March 17, 2019		1,210					74
Other					(1		)			Other									0		(1)
Impairment of equity-method investments					$	186				Impairment of equity-method investments									$	938	$	186

_______________

~~(1)~~

(1)Relates to a gas gathering system in the Eagle Ford Shale region with expected declines in asset utilization and possible idling of the gathering system. The estimated fair value of the Property, plant, and equipment – net was determined using a market approach which incorporated indications of interest from third parties.

(2)Reflects impairment of Property, plant, and equipment – net that is no longer in use for which the fair value was determined to be lower than the carrying value.

(3)Following the previously described declining market conditions during the first quarter of 2020, we evaluated these investments for other-than-temporary impairment. The fair value was measured using an income approach. Both investees operate in primarily oil-driven basins where significant expected reductions in producer activities led to reduced estimates of expected future cash flows. Our fair value estimates also reflected discount rates of approximately 17 percent for these investments. We also considered any debt held at the investee level, and its impact to fair value. The industry weighted-average discount rates utilized were significantly influenced by the recent market declines previously discussed.~~Property, plant, and equipment – net~~ ~~was determined using a market approach which incorporated indications of interest from third parties.~~


~~(2)~~	~~Reflects impairment of~~ ~~Property, plant, and equipment – net~~ ~~that is no longer in use for which the fair value was determined to be lower than the carrying value.~~

~~(3)~~

~~Relates to certain idle pipelines. The estimated fair value of the~~ ~~Property, plant, and equipment – net~~ was determined by a market approach incorporating information derived from bids received for these assets, which we marketed for sale together with certain other assets. These inputs resulted in a fair value measurement within Level 2 of the fair value hierarchy. We sold these assets in the fourth quarter of 2018.

~~(4)~~

Relates to a gas gathering system in the Marcellus region that was adversely impacted by lower sustained forward natural gas price expectations and changes in expected producer activity. The estimated fair value was determined using an income approach. We utilized a discount rate of 10.2 percent in our analysis. This impairment is reported in ~~Other investing income (loss) – net~~ ~~in the~~ ~~Consolidated Statement of Income~~.

~~(5)~~

Relates to a certain gathering system held in Appalachia Midstream Investments that was adversely impacted by changes in the timing of expected producer activity. The estimated fair value was determined using an income approach. We utilized a discount rate of 9.0 percent in our analysis. This impairment is reported in ~~Other investing income (loss) – net~~ ~~in the~~ ~~Consolidated Statement of Income~~.

Notes (Continued)

(4)Following the previously described declining market conditions during the first quarter of 2020, we evaluated these investments for other-than-temporary impairment. The impairments within our Northeast G&P segment are primarily associated with operations in wet-gas areas where producer drilling activities are influenced by NGL prices which historically trend with crude oil prices. The fair values of our investments in Caiman II and Aux Sable Liquid Products LP (Aux Sable) were estimated using a market approach, reflecting valuation multiples ranging from 5.0x to 6.2x EBITDA (weighted-average 6.0x). The fair values of the other investments, including gathering systems that are part of Appalachia Midstream Investments, were estimated using an income approach, with discount rates ranging from 9.7 percent to 13.5 percent (weighted-average 12.6 percent). We also considered any debt held at the investee level, and its impact to fair value. The assumed valuation multiples and industry weighted-average discount rates utilized were both significantly influenced by the recent market declines previously discussed.

~~(6)~~

(5)Relates to a gas gathering system in the Marcellus region that was adversely impacted by lower sustained forward natural gas price expectations and changes in expected producer activity. The estimated fair value was determined using an income approach. We utilized a discount rate of 10.2 percent in our analysis.

(6)Relates to a certain gathering system held in Appalachia Midstream Investments that was adversely impacted by changes in the timing of expected producer activity. The estimated fair value was determined using an income approach. We utilized a discount rate of 9.0 percent in our analysis.

(7)The estimated fair value of Pennant Midstream, LLC (Pennant) was determined by a market approach based on recent observable third-party transactions. These inputs resulted in a fair value measurement within Level 2 of the fair value hierarchy.

(8)The estimated fair value was determined by a market approach based on the transaction price for the purchase of the remaining interest in UEOM as finalized just prior to the signing and closing of the acquisition in March 2019 (see Note 2 – Acquisitions). These inputs resulted in a fair value measurement within Level 2 of the fair value hierarchy.

The estimated fair value of Pennant Midstream, LLC (“Pennant”) was determined by a market approach based on recent observable third-party transactions. These inputs resulted in a fair value measurement within Level 2 of the fair value hierarchy. This impairment is reported in ~~Other investing income (loss) – net~~ ~~in the~~ ~~Consolidated Statement of Income~~.

~~(7)~~

The estimated fair value was determined by a market approach based on the transaction price for the purchase of the remaining interest in UEOM as finalized just prior to the signing and closing of the acquisition in March 2019 (see Note 2 – Acquisitions). These inputs resulted in a fair value measurement within Level 2 of the fair value hierarchy. This impairment is reported in ~~Other investing income (loss) - net~~ ~~in the~~ ~~Consolidated Statement of Income~~.

Note 1413 – Contingent Liabilities

Reporting of Natural Gas-Related Information to Trade Publications

Direct and indirect purchasers of natural gas in various states filed individual and class actions against us, our former affiliate WPX Energy, Inc. (WPX) and its subsidiaries, and others alleging the manipulation of published gas price indices and seeking unspecified amounts of damages. Such actions were transferred to the Nevada federal district court for consolidation of discovery and pre-trial issues. We have agreed to indemnify WPX and its subsidiaries related to this matter.

In the individual action, filed by Farmland Industries Inc. (Farmland), the court issued an order on May 24, 2016, granting one of our co-defendant’s motion for summary judgment as to Farmland’s claims. On January 5, 2017, the court extended such ruling to us, entering final judgment in our favor. Farmland appealed. On March 27, 2018, the appellate court reversed the district court’s grant of summary judgment, and on April 10, 2018, the defendants filed a petition for rehearing with the appellate court, which was denied on May 9, 2018. The case was remanded to the Nevada federal district court and subsequently has been remanded to its originally filed court, the Kansas federal district court.

In the putative class actions, on March 30, 2017, the court issued an order denying the plaintiffs’ motions for class certification. On June 13, 2017, the United States Court of Appeals for the Ninth Circuit granted the plaintiffs’ petition for permission to appeal the order. On August 6, 2018, the Ninth Circuit reversed the order denying class certification and remanded the case to the Nevada federal district court.

We reached an agreement to settle two of the actions, and on April 22, 2019, the Nevada federal district court preliminarily approved the settlements, which are on behalf of Kansas and Missouri class members. The final

Notes (Continued)

fairness hearing on the settlement occurred August 5, 2019, and a final judgment of dismissal with prejudice was entered the same day.

Two putative class actions remain unresolved, and they have been remanded to their originally filed court, the Wisconsin federal district court. Trial is scheduled to begin June 14, 2021.

Because of the uncertainty around the remaining ~~pending~~ unresolved issues, we cannot reasonably estimate a range of potential exposure at this time. However, it is reasonably possible that the ultimate resolution of these actions and our related indemnification obligation could result in a potential loss that may be material to our results of operations. In connection with this indemnification, we have an accrued liability balance associated with this matter and, as a result, have exposure to future developments.

Alaska Refinery Contamination Litigation

We are involved in litigation arising from our ownership and operation of the North Pole Refinery in North Pole, Alaska, from 1980 until 2004, through our wholly owned subsidiaries Williams Alaska Petroleum Inc. (WAPI) and MAPCO Inc. We sold the refinery to Flint Hills Resources Alaska, LLC (FHRA), a subsidiary of Koch Industries, Inc., in 2004. The litigation involves three cases, with filing dates ranging from 2010 to 2014. The actions primarily arise from sulfolane contamination allegedly emanating from the refinery. A putative class action lawsuit was filed by James West in 2010 naming us, WAPI, and FHRA as defendants. We and FHRA filed claims against each other seeking, among other things, contractual indemnification alleging that the other party caused the sulfolane contamination. In 2011, we and FHRA

~~Notes (Continued)~~

settled the claim with James West. Certain claims by FHRA against us were resolved by the Alaska Supreme Court in our favor. FHRA’s claims against us for contractual indemnification and statutory claims for damages related to off-site sulfolane ~~remain pending.~~were remanded to the Alaska Superior Court. The State of Alaska filed its action in March 2014, seeking damages. The City of North Pole (North Pole) filed its lawsuit in November 2014, seeking past and future damages, as well as punitive damages. Both we and WAPI asserted counterclaims against the State of Alaska and North Pole, and cross-claims against FHRA. FHRA has also filed cross-claims against us.

The underlying factual basis and claims in the cases are similar and may duplicate exposure. As such, in February 2017, the three cases were consolidated into one action in state court containing the remaining claims from the James West case and those of the State of Alaska and North Pole. The State of Alaska later announced the discovery of additional contaminants per- and polyfluoralkyl (PFOS and PFOA) offsite of the refinery, and the court permitted the State of Alaska to amend its complaint to add a claim for offsite PFOS/PFOA contamination. The court subsequently remanded the offsite PFOS/PFOA claims to the Alaska Department of Environmental Conservation for investigation and stayed the claims pending their potential resolution at the administrative agency. Several trial dates encompassing all three cases have been scheduled and stricken. ~~Trial commenced~~In the summer of 2019, the court deconsolidated the cases for purposes of trial. A bench trial on all claims except North Pole’s claims began in October 2019. ~~Due to~~

In January 2020, the ~~ongoing assessment~~Alaska Superior Court issued its Memorandum of ~~the level and extent~~Decision finding in favor of ~~sulfolane contamination, the lack of an articulated cleanup level for sulfolane, and the lack of a concrete remedial proposal and cost estimate, we are unable to estimate a range of exposure to~~ the State of Alaska and FHRA, with the total incurred and potential future damages estimated to be $86 million. The court found that FHRA is not entitled to contractual indemnification from us because FHRA contributed to the sulfolane contamination. On March 23, 2020, the court entered final judgment in the case. Filing deadlines were stayed until May 1, 2020. However, on April 21, 2020, we filed a Notice of Appeal. We also filed post-judgment motions including a Motion for New Trial and a Motion to Alter or Amend the Judgment. These post-trial motions have now been resolved with the court’s denial of the last motion on June 11, 2020. Our Statement of Points on Appeal was filed on July 13, 2020. On June 22, 2020, the court stayed the North ~~Pole at this time.~~Pole’s case pending resolution of the appeal in the State of Alaska and FHRA case. We ~~currently~~have recorded an accrued liability in the amount of our estimate ~~that our~~of the probable loss. It is reasonably possible ~~loss exposure to FHRA~~that we may not be successful on appeal and could ~~range from an insignificant amount~~ultimately pay up to ~~$32 million, although uncertainties inherent in~~ the ~~litigation process, expert evaluations, and jury dynamics might cause our exposure to exceed that amount.~~amount of judgment.

Independent of the litigation matter described in the preceding paragraphs, in 2013, the Alaska Department of Environmental Conservation indicated that it views FHRA and us as responsible parties, and that it intends to enter a compliance order to address the environmental remediation of sulfolane and other possible contaminants including cleanup work outside the refinery’s boundaries. To date, no compliance order has been issued. Due to the ongoing assessment of the level and extent of sulfolane contamination, the ultimate cost of remediation and division of costs among the potentially responsible parties, and the previously described separate litigation, we are unable to estimate a range of exposure at this time.

Notes (Continued)

Royalty Matters

Certain of our customers, including ~~one major customer,~~Chesapeake, have been named in various lawsuits alleging underpayment of royalties and claiming, among other things, violations of anti-trust laws and the Racketeer Influenced and Corrupt Organizations Act. We have also been named as a defendant in certain of these cases filed in Pennsylvania based on allegations that we improperly participated with ~~that major customer~~Chesapeake in causing the alleged royalty underpayments. We believe that the claims asserted are subject to indemnity obligations owed to us by ~~that major customer. That customer~~Chesapeake. Chesapeake has reached a tentative settlement to resolve substantially all Pennsylvania royalty cases pending, which settlement would apply to both ~~the customer~~Chesapeake and us. The settlement as reported would not require any contribution from us. On June 28, 2020, Chesapeake filed for Chapter 11 bankruptcy protection in the United States Bankruptcy Court for the Southern District of Texas.

Litigation Against Energy Transfer and Related Parties

On April 6, 2016, we filed suit in Delaware Chancery Court against Energy Transfer Equity, L.P. (Energy Transfer) and LE GP, LLC (the general partner for Energy Transfer) alleging willful and material breaches of the Agreement and Plan of Merger (ETE Merger Agreement) with Energy Transfer resulting from the private offering by Energy Transfer on March 8, 2016, of Series A Convertible Preferred Units (Special Offering) to certain Energy Transfer insiders and other accredited investors. The suit seeks, among other things, an injunction ordering the defendants to unwind the Special Offering and to specifically perform their obligations under the ETE Merger Agreement. On April 19, 2016, we filed an amended complaint seeking the same relief. On May 3, 2016, Energy Transfer and LE GP, LLC filed an answer and counterclaims.

On May 13, 2016, we filed a separate complaint in Delaware Chancery Court against Energy Transfer, LE GP, LLC and the other Energy Transfer affiliates that are parties to the ETE Merger Agreement, alleging material breaches of the ETE Merger Agreement for failing to cooperate and use necessary efforts to obtain a tax opinion required under the ETE Merger Agreement (Tax Opinion) and for otherwise failing to use necessary efforts to consummate the merger under the ETE Merger Agreement wherein we would be merged with and into the newly formed Energy Transfer Corp LP (ETC) (ETC Merger). The suit sought, among other things, a declaratory judgment and injunction preventing Energy Transfer from terminating or otherwise avoiding its obligations under the ETE Merger Agreement due to any failure to obtain the Tax Opinion.

~~Notes (Continued)~~

The Court of Chancery coordinated the Special Offering and Tax Opinion suits. On May 20, 2016, the Energy Transfer defendants filed amended affirmative defenses and verified counterclaims in the Special Offering and Tax Opinion suits, alleging certain breaches of the ETE Merger Agreement by us and seeking, among other things, a declaration that we were not entitled to specific performance, that Energy Transfer could terminate the ETC Merger, and that Energy Transfer is entitled to a $1.48 billion termination fee. On June 24, 2016, following a two-day trial, the court issued a Memorandum Opinion and Order denying our requested relief in the Tax Opinion suit. The court did not rule on the substance of our claims related to the Special Offering or on the substance of Energy Transfer’s counterclaims. On June 27, 2016, we filed an appeal of the court’s decision with the Supreme Court of Delaware, seeking reversal and remand to pursue damages. On March 23, 2017, the Supreme Court of Delaware affirmed the Court of Chancery’s ruling. On March 30, 2017, we filed a motion for reargument with the Supreme Court of Delaware, which was denied on April 5, 2017.

On September 16, 2016, we filed an amended complaint with the Court of Chancery seeking damages for breaches of the ETE Merger Agreement by defendants. On September 23, 2016, Energy Transfer filed a second amended and supplemental affirmative defenses and verified counterclaim with the Court of Chancery seeking, among other things, payment of the $1.48 billion termination fee due to our alleged breaches of the ETE Merger Agreement. On December 1, 2017, the court granted our motion to dismiss certain of Energy Transfer’s counterclaims, including its claim seeking payment of the $1.48 billion termination fee. On December 8, 2017, Energy Transfer filed a motion for reargument, which the Court of Chancery denied on April 16, 2018. The Court of Chancery ~~previously~~had scheduled trial for May 20 through May 24, 2019; the court struck ~~the trial~~this setting and ~~has re-scheduled~~reset the trial for June 8 through June 11, and June 15, 2020. Due to COVID-19, the court struck the June 2020 setting and re-scheduled the trial for August 31 through September 4, 2020; this setting was also struck as a result of COVID-19. Trial has been reset for December 14 through December 18, 2020.

Notes (Continued)

Former Olefins Business

SABIC Petrochemicals, the other interest owner in our former Geismar, Louisiana, olefins facility we sold in July 2017, is seeking recovery from us for losses it allegedly suffered, including its share of personal injury settlements in which it was a co-defendant, as well as amounts related to lost income, defense costs, and property damage associated with an explosion and fire at the plant in June 2013. Due to the complexity of the various claims and available defenses, we are unable to reliably estimate any reasonably possible losses at this time. Trial began on October 14, 2019, as scheduled, but on October 21, 2019, the ~~Court~~court declared a mistrial due to the conduct of an officer of SABIC Petrochemicals and SABIC Petrochemicals’ expert witness. ~~No new trial date has been set.~~Trial is currently reset for November 4, 2020. We believe that certain losses incurred arising directly from the explosion and fire will be covered by our general liability policy and any uninsured losses are not expected to be material.

Other

On August 31, 2018, Transco submitted to the FERC a general rate filing principally designed to recover increased costs and to comply with the terms of the settlement in its prior rate proceeding. The new rates became effective March 1, 2019, subject to refund and the outcome of a hearing. In October 2019, we reached an agreement on the terms of a settlement with the participants that would resolve all issues in the rate case without the need for a ~~hearing. Final resolution of the rate case is subject to the filing of~~hearing, and on December 31, 2019, we filed a formal stipulation and agreement with ~~and subsequent approval by,~~ the ~~FERC. As~~FERC setting forth such terms of ~~September 30, 2019, we have provided a $131 million reserve for~~settlement. On March 24, 2020, the FERC issued an order approving the uncontested rate case settlement, which became effective on June 1, 2020. Rate refunds ~~which we believe is adequate for any refunds that may be required.~~related to the increased rates collected prior to the effective date of the settlement were paid on July 1, 2020.

Environmental Matters

We are a participant in certain environmental activities in various stages including assessment studies, cleanup operations, and/or remedial processes at certain sites, some of which we currently do not own. We are monitoring these sites in a coordinated effort with other potentially responsible parties, the U.S. Environmental Protection Agency (EPA), or other governmental authorities. We are jointly and severally liable along with unrelated third parties in some of these activities and solely responsible in others. Certain of our subsidiaries have been identified as potentially responsible parties at various Superfund and state waste disposal sites. In addition, these subsidiaries have incurred, or are alleged to have incurred, various other hazardous materials removal or remediation obligations under environmental laws. As of September 30, ~~2019,~~2020, we have accrued liabilities totaling ~~$33~~$34 million for these matters, as discussed below. Estimates of the most likely costs of cleanup are generally based on completed assessment studies, preliminary results of studies,

~~Notes (Continued)~~

or our experience with other similar cleanup operations. At September 30, ~~2019,~~2020, certain assessment studies were still in process for which the ultimate outcome may yield different estimates of most likely costs. Therefore, the actual costs incurred will depend on the final amount, type, and extent of contamination discovered at these sites, the final cleanup standards mandated by the EPA or other governmental authorities, and other factors.

The EPA and various state regulatory agencies routinely promulgate and propose new rules and issue updated guidance to existing rules. These rulemakings include, but are not limited to, rules for reciprocating internal combustion engine and combustion turbine maximum achievable control technology, air quality standards for one-hour nitrogen dioxide emissions, and volatile organic compound and methane new source performance standards impacting design and operation of storage vessels, pressure valves, and compressors. The EPA previously issued its rule regarding National Ambient Air Quality Standards for ground-level ozone. We are monitoring the rule’s implementation as it will trigger additional federal and state regulatory actions that may impact our operations. Implementation of the regulations is expected to result in impacts to our operations and increase the cost of additions to Property, plant, and equipment – net in the Consolidated Balance Sheet for both new and existing facilities in affected areas. We are unable to reasonably estimate the cost of additions that may be required to meet the regulations at this time due to uncertainty created by various legal challenges to these regulations and the need for further specific regulatory guidance.

Notes (Continued)

Continuing operations

Our interstate gas pipelines are involved in remediation activities related to certain facilities and locations for polychlorinated biphenyls, mercury, and other hazardous substances. These activities have involved the EPA and various state environmental authorities, resulting in our identification as a potentially responsible party at various Superfund waste sites. At September 30, ~~2019~~,2020, we have accrued liabilities of $5$4 million for these costs. We expect that these costs will be recoverable through rates.

We also accrue environmental remediation costs for natural gas underground storage facilities, primarily related to soil and groundwater contamination. At September 30, ~~2019~~,2020, we have accrued liabilities totaling $8 million for these costs.

Former operations

We have potential obligations in connection with assets and businesses we no longer operate. These potential obligations include remediation activities at the direction of federal and state environmental authorities and the indemnification of the purchasers of certain of these assets and businesses for environmental and other liabilities existing at the time the sale was consummated. Our responsibilities relate to the operations of the assets and businesses described below.

•Former agricultural fertilizer and chemical operations and former retail petroleum and refining operations;

•Former petroleum products and natural gas pipelines;

•Former petroleum refining facilities;

•Former exploration and production and mining operations;

•Former electricity and natural gas marketing and trading operations.

At September 30, ~~2019~~,2020, we have accrued environmental liabilities of ~~$20~~$22 million related to these matters.

Other Divestiture Indemnifications

Pursuant to various purchase and sale agreements relating to divested businesses and assets, we have indemnified certain purchasers against liabilities that they may incur with respect to the businesses and assets acquired from us. The indemnities provided to the purchasers are customary in sale transactions and are contingent upon the purchasers incurring liabilities that are not otherwise recoverable from third parties. The indemnities generally relate to breach of

~~Notes (Continued)~~

warranties, tax, historic litigation, personal injury, property damage, environmental matters, right of way, and other representations that we have provided.

At September 30, ~~2019~~,2020, other than as previously disclosed, we are not aware of any material claims against us involving the above-described indemnities; thus, we do not expect any of the indemnities provided pursuant to the sales agreements to have a material impact on our future financial position. Any claim for indemnity brought against us in the future may have a material adverse effect on our results of operations in the period in which the claim is made.

In addition to the foregoing, various other proceedings are pending against us ~~which~~that are incidental to our operations, none of which are expected to be material to our expected future annual results of operations, liquidity, and financial position.

Summary

We have disclosed our estimated range of reasonably possible losses for certain matters above, as well as all significant matters for which we are unable to reasonably estimate a range of possible loss. We estimate that for all other matters for which we are able to reasonably estimate a range of loss, our aggregate reasonably possible losses

Notes (Continued)

beyond amounts accrued are immaterial to our expected future annual results of operations, liquidity, and financial position. These calculations have been made without consideration of any potential recovery from third parties.

Note 1514 – Segment Disclosures

Our reportable segments are Transmission & Gulf of Mexico, Northeast G&P, ~~Atlantic-Gulf,~~ and West. All remaining business activities are included in Other. (See Note 1 – General, Description of Business, and Basis of Presentation.)

Performance Measurement

We evaluate segment operating performance based upon Modified EBITDA ~~(earnings before interest, taxes, depreciation, and amortization)~~. This measure represents the basis of our internal financial reporting and is the primary performance measure used by our chief operating decision maker in measuring performance and allocating resources among our reportable segments. Intersegment revenues primarily represent the sale of NGLs from our natural gas processing plants to our marketing business.

We define Modified EBITDA as follows:

•Net income (loss) before:

◦Provision (benefit) for income taxes;

◦Interest incurred, net of interest capitalized;

◦Equity earnings (losses);

◦Impairment of equity-method investments;

◦Other investing income (loss) – net;

◦– ~~net;~~Impairment of goodwill;

◦Depreciation and amortization expenses;

◦Accretion expense associated with asset retirement obligations for nonregulated operations.


•	•This measure is further adjusted to include our proportionate share (based on ownership interest) of Modified EBITDA from our equity-method investments calculated consistently with the definition described above.

Notes (Continued)

The following table reflects the reconciliation of Segment revenues to Total revenues as reported in the Consolidated Statement of Income and Total assets by reportable segment.


	Transmission & Gulf of Mexico		Northeast G&P		West		Other		Eliminations		Total
	(Millions)
Three Months Ended September 30, 2020
Segment revenues:
Service revenues
External	$	797	$	366	$	311	$	5	$	—	$	1,479
Internal	10		13		0		3		(26)		—
Total service revenues	807		379		311		8		(26)		1,479
Total service revenues – commodity consideration	6		2		32		0		0		40
Product sales
External	34		2		378		0		—		414
Internal	12		10		13		0		(35)		—
Total product sales	46		12		391		0		(35)		414
Total revenues	$	859	$	393	$	734	$	8	$	(61)	$	1,933

Three Months Ended September 30, 2019
Segment revenues:
Service revenues
External	$	829	$	340	$	322	$	4	$	—	$	1,495
Internal	13		13		0		3		(29)		—
Total service revenues	842		353		322		7		(29)		1,495
Total service revenues – commodity consideration	7		1		30		0		0		38
Product sales
External	66		22		378		0		—		466
Internal	10		8		11		0		(29)		—
Total product sales	76		30		389		0		(29)		466
Total revenues	$	925	$	384	$	741	$	7	$	(58)	$	1,999

Nine Months Ended September 30, 2020
Segment revenues:
Service revenues
External	$	2,394	$	1,052	$	938	$	15	$	—	$	4,399
Internal	37		39		0		10		(86)		—
Total service revenues	2,431		1,091		938		25		(86)		4,399
Total service revenues – commodity consideration	14		5		74		0		0		93
Product sales
External	104		17		1,014		0		—		1,135
Internal	30		25		39		0		(94)		—
Total product sales	134		42		1,053		0		(94)		1,135
Total revenues	$	2,579	$	1,138	$	2,065	$	25	$	(180)	$	5,627

Northeast G&P Atlantic-Gulf West Other Eliminations Total
(Millions)
Three Months Ended September 30, 2019
Segment revenues:
Service revenues
External $ 340
$ 718
$ 433
$ 4
$ —
$ 1,495
Internal 13
13
—
3
(29 ) —
Total service revenues 353
731
433
7
(29 ) 1,495
Total service revenues – commodity consideration 1
7
30
—
—
38
Product sales
External 22
66
378
—
—
466
Internal 8
10
11
—
(29 ) —
Total product sales 30
76
389
—
(29 ) 466
Total revenues $ 384
$ 814
$ 852
$ 7
$ (58 ) $ 1,999

Three Months Ended September 30, 2018
Segment revenues:
Service revenues
External $ 236
$ 595
$ 533
$ 7
$ —
$ 1,371
Internal 11
12
—
3
(26 ) —
Total service revenues 247
607
533
10
(26 ) 1,371
Total service revenues – commodity consideration 6
18
97
—
—
121
Product sales
External 59
46
706
—
—
811
Internal 10
85
26
—
(121 ) —
Total product sales 69
131
732
—
(121 ) 811
Total revenues $ 322
$ 756
$ 1,362
$ 10
$ (147 ) $ 2,303

Nine Months Ended September 30, 2019
Segment revenues:
Service revenues
External $ 925
$ 2,102
$ 1,384
$ 13
$ —
$ 4,424
Internal 34
36
—
9
(79 ) —
Total service revenues 959
2,138
1,384
22
(79 ) 4,424
Total service revenues – commodity consideration 9
33
116
—
—
158
Product sales
External 87
169
1,256
—
—
1,512
Internal 27
57
46
—
(130 ) —
Total product sales 114
226
1,302
—
(130 ) 1,512
Total revenues $ 1,082
$ 2,397
$ 2,802
$ 22
$ (209 ) $ 6,094

Notes (Continued)


	Transmission & Gulf of Mexico		Northeast G&P		West		Other		Eliminations		Total
	(Millions)

Nine Months Ended September 30, 2019
Segment revenues:
Service revenues
External	$	2,437	$	925	$	1,049	$	13	$	—	$	4,424
Internal	36		34		0		9		(79)		—
Total service revenues	2,473		959		1,049		22		(79)		4,424
Total service revenues – commodity consideration	33		9		116		0		0		158
Product sales
External	169		87		1,256		0		—		1,512
Internal	57		27		46		0		(130)		—
Total product sales	226		114		1,302		0		(130)		1,512
Total revenues	$	2,732	$	1,082	$	2,467	$	22	$	(209)	$	6,094

September 30, 2020
Total assets	$	19,246	$	14,526	$	10,745	$	756	$	(953)	$	44,320
December 31, 2019
Total assets	$	18,796	$	15,399	$	11,265	$	1,151	$	(571)	$	46,040

Northeast G&P Atlantic-Gulf West Other Eliminations Total
(Millions)
Nine Months Ended September 30, 2018
Segment revenues:
Service revenues
External $ 677
$ 1,769
$ 1,599
$ 17
$ —
$ 4,062
Internal 30
37
—
9
(76 ) —
Total service revenues 707
1,806
1,599
26
(76 ) 4,062
Total service revenues – commodity consideration 14
45
257
—
—
316
Product sales
External 214
131
1,759
—
—
2,104
Internal 28
198
63
—
(289 ) —
Total product sales 242
329
1,822
—
(289 ) 2,104
Total revenues $ 963
$ 2,180
$ 3,678
$ 26
$ (365 ) $ 6,482

September 30, 2019
Total assets $ 15,445
$ 16,888
$ 13,550
$ 928
$ (530 ) $ 46,281
December 31, 2018
Total assets $ 14,526
$ 16,346
$ 13,948
$ 849
$ (367 ) $ 45,302

The following table reflects the reconciliation of Modified EBITDA to Net income (loss) as reported in the Consolidated Statement of ~~Income~~.Income.


	Three Months Ended September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
	(Millions)
Modified EBITDA by segment:
Transmission & Gulf of Mexico	$	616	$	665	$	1,893	$	1,891
Northeast G&P	387		345		1,126		947
West	247		245		715		713
Other	(7)		(2)		8		1
	1,243		1,253		3,742		3,552
Accretion expense associated with asset retirement obligations for nonregulated operations	(10)		(8)		(27)		(25)
Depreciation and amortization expenses	(426)		(435)		(1,285)		(1,275)
Impairment of goodwill	0		0		(187)		0
Equity earnings (losses)	106		93		236		260
Impairment of equity-method investments	0		(114)		(938)		(186)
Other investing income (loss) – net	2		7		6		132
Proportional Modified EBITDA of equity-method investments	(189)		(181)		(573)		(546)
Interest expense	(292)		(296)		(882)		(888)
(Provision) benefit for income taxes	(111)		(77)		(24)		(244)

Net income (loss)	$	323	$	242	$	68	$	780

Three Months Ended
September 30, Nine Months Ended
September 30,
2019 2018 2019 2018
(Millions)
Modified EBITDA by segment:
Northeast G&P $ 345
$ 281
$ 947
$ 786
Atlantic-Gulf 599
492
1,683
1,418
West 311
412
921
1,214
Other (2 ) 6
1
(49 )
1,253
1,191
3,552
3,369
Accretion expense associated with asset retirement obligations for nonregulated operations (8 ) (8 ) (25 ) (26 )
Depreciation and amortization expenses (435 ) (425 ) (1,275 ) (1,290 )
Equity earnings (losses) 93
105
260
279
Other investing income (loss) – net (107 ) 2
(54 ) 74
Proportional Modified EBITDA of equity-method investments (181 ) (205 ) (546 ) (552 )
Interest expense (296 ) (270 ) (888 ) (818 )
(Provision) benefit for income taxes (77 ) (190 ) (244 ) (297 )
Net income (loss) $ 242
$ 200
$ 780
$ 739

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.~~businesses. 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~~Rates are established ~~through~~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 our 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~~services 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.~~storage.

~~Our operations are presented~~Effective January 1, 2020, following an organizational realignment, our interstate natural gas pipeline Northwest Pipeline, which was reported within the ~~following reportable segments: Northeast G&P,~~West reporting segment throughout 2019, is now managed within the Transmission & Gulf of Mexico reporting segment (previously identified as the Atlantic-Gulf ~~and West, consistent~~reporting segment). Consistent with the manner in which our chief operating decision maker evaluates performance and allocates ~~resources.~~resources, our operations are conducted, managed, and presented within the following reportable segments: Transmission & Gulf of Mexico, Northeast G&P, and West. All remaining business activities as well as corporate activities are included in Other. Our reportable segments are comprised of the following businesses:

•Other includes minor business activities that are not operating segments, as well as corporate operations.

Management’s Discussion and Analysis (Continued)

In September ~~2019,~~2020, we paid a regular quarterly dividend of ~~$0.38~~$0.40 per share.

Overview of Nine Months Ended September 30, ~~2019~~2020

Net income (loss) attributable to The Williams Companies, Inc., for the nine months ended September 30, ~~2019, increased $310~~2020, decreased $631 million compared to the nine months ended September 30, ~~2018, reflecting $362~~2019, reflecting:

•$752 million increase in Impairment of equity-method investments driven by $938 million of ~~increased~~ impairments in the first quarter of 2020;

•~~service revenues~~$187 million of Impairment of goodwill ~~primarily associated with expansion projects, a $269~~in 2020;

•$122 million decrease due to the absence of a 2019 gain on the sale of our interest in Jackalope;

•A $33 million unfavorable change in Other income (expense) – net;

•A $25 million decrease in service revenues reflecting decreases in deferred revenue recognition at Gulfstar One and in the Barnett, as well as the expiration of the MVC agreement in the Barnett Shale region in 2019, partially offset by revenue growth from our Northeast JV and Transco expansion projects;

•A $24 million decrease in equity earnings, primarily due to our $78 million share of an impairment of goodwill recorded by an equity-method investee in 2020, partially offset by increased contributions from our Northeast G&P investments.

These unfavorable changes were partially offset by:

•A $220 million favorable change in provision for income taxes;

•$98 million of lower Operating and maintenance expenses;

•An $81 million favorable change in Net income (loss) attributable to noncontrolling interestsprimarily due to the ~~WPZ Merger, a $122~~noncontrolling interests’ share of the first-quarter 2020 goodwill impairment charge;

•$76 million ~~gain on the second-quarter 2019 sale of our 50 percent interest in Jackalope, and~~increase due to the absence of ~~a 2018 charge for a valuation allowance on foreign tax credits. These increases are partially offset by $186~~2019 Impairment of certain assets;

•$56 million of ~~impairments of equity-method investments in 2019,~~ lower commodity margins, the absence of the Four Corners area business which was sold in October 2018, higher interest expense, the absence of a prior year $62 million gain on deconsolidation of Jackalope, lower Transco allowance for equity funds used during construction (AFUDC),Selling, general, and ~~current year severance charges. Long-lived asset impairments in the current year were substantially offset by similar levels of impairments in the prior year.~~administrative expenses.

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~~annual consolidated financial statements and notes thereto in Exhibit 99.1 of our Form ~~10-K~~8-K dated ~~February 21, 2019.~~May 4, 2020.

~~Acquisition of UEOM~~

As of December 31, 2018, we owned a 62 percent interest in UEOM which we accounted for as an equity-method investment. On March 18, 2019, we signed and closed the acquisition of the remaining 38 percent interest in UEOM. Total consideration paid, including post-closing adjustments, was $741 million in cash funded through credit facility borrowings and cash on hand. As a result of acquiring this additional interest, we obtained control of and now consolidate UEOM. (See Note 2 – Acquisitions of Notes to Consolidated Financial Statements.)

~~In April 2019, we sold our interest in Jackalope for $485 million in cash, resulting in a gain on the disposition of $122 million.~~Recent Developments

Expansion Project Update

~~Rivervale South to Market~~Transmission & Gulf of Mexico

In ~~August 2018, we received approval from~~February 2016, the FERC ~~to expand~~issued a certificate order for the initial phases of Transco’s Hillabee Expansion Project. The project involves an expansion of Transco’s existing natural gas transmission system from Station 85 in west central Alabama to ~~provide incremental firm transportation capacity from the existing Rivervale~~an interconnection with ~~Tennessee Gas Pipeline on Transco’s North New Jersey Extension to other existing Transco locations within New Jersey.~~the Sabal Trail pipeline in east central Alabama. The project ~~was placed into partial service on July 1, 2019. The remaining portion~~is being constructed in phases, and all of the project expansion capacity is dedicated to Sabal Trail pursuant to a capacity lease agreement. Phase I was completed in 2017 and it increased capacity by 818 Mdth/d. We placed Phase II into service on ~~September~~May 1, ~~2019. The full~~2020. Together, the first two phases of the project increased capacity by ~~190~~1,025 Mdth/d.

~~Ohio River Supply Hub Expansion~~

We agreed to expand our services for certain customers to provide additional rich gas processing capacity in the Marcellus and Upper Devonian Shale in West Virginia and Pennsylvania. Associated with these agreements, we have expanded the inlet processing capacity of our Oak Grove facility to 400 MMdf/d. We have also constructed

Management’s Discussion and Analysis (Continued)

COVID-19

~~a new NGL pipeline from Moundsville~~The outbreak of COVID-19 has severely impacted global economic activity and caused significant volatility and negative pressure in financial markets. We are monitoring 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. We are continuing to monitor developments with respect to the ~~Harrison Hub fractionation facility~~outbreak and note the following:

•Our financial condition, results of operations, and liquidity have not been materially impacted by direct effects of COVID-19.

•We believe we have the ability to ~~provide an additional outlet for NGLs. These expansions are supported~~access the debt market, if necessary, as evidenced by ~~long-term, fee-based agreements~~the successful completion of debt offerings during second-quarter 2020, and ~~volumetric commitments.~~continue to have significant levels of unused capacity on our revolving credit facility.

~~Norphlet Project~~•We continue to monitor and adapt our remote working arrangements and limit business-related travel. Implementation of these measures has not required material expenditures or significantly impacted our ability to operate our business.

•Our remote working arrangements have not significantly impacted our internal controls over financial reporting and disclosure controls and procedures.

Customer Bankruptcies

In ~~March 2016, we~~June 2020, our customer Chesapeake announced that it had voluntarily filed for relief under Chapter 11 of the U.S. Bankruptcy Code. We provide midstream services, including wellhead gathering, for the natural gas that Chesapeake and its joint interest owners produce, primarily in the Eagle Ford Shale, Haynesville Shale, and Marcellus Shale regions (through Appalachia Midstream Investments). In 2019, Chesapeake accounted for approximately 6 percent of our consolidated revenues. As of September 30, 2020, trade accounts receivable due from Chesapeake include $88 million related to services provided prior to Chesapeake’s bankruptcy filing. The remaining trade accounts receivable due from Chesapeake are current.

We have evaluated these receivables from Chesapeake and our related asset groups and investments involved in providing services to Chesapeake and determined that no expected credit losses or impairment charges are required to be recognized at this time. This evaluation considered the physical nature of our services in these basins, where we ~~reached~~gather at the wellhead and are critical to Chesapeake’s ability to move product to market, along with an ~~agreement~~assessed low likelihood of contract rejection, noting that to ~~provide deepwater~~date Chesapeake has not attempted to reject any of our contracts. Chesapeake also received initial limited approval to continue paying for services such as those we provide. We also considered our prior experiences with customer bankruptcies, where receivables were ultimately collectible even if the timing of collections was impacted. Future developments in Chesapeake’s ongoing bankruptcy proceedings could affect our assumptions and conclusions regarding credit losses and impairment charges.

We have certain other customers of our consolidated operations and investees, which are less significant to our consolidated results of operations, that have also filed for bankruptcy protection. To date, based on considerations such as our review of those bankruptcy filings, our assessment of the likelihood of contract rejection, and/or ongoing collections of amounts invoiced, we have not recognized any significant credit losses or impairment charges related to these customers. We continue to monitor these ongoing customer bankruptcy proceedings as it is reasonably possible that future developments could affect our assumptions and conclusions.

Crude Oil Price Decline

During the first several months of 2020, crude oil prices decreased as a result of surplus supply and weakened demand caused by the COVID-19 pandemic. In addition, in early March, Saudi Arabia announced that it would cut export prices and increase production, contributing to a sharp decline in crude oil prices. The significant decline in crude oil prices also impacted NGL prices. While our businesses do not have direct exposure to crude oil prices, the

Management’s Discussion and Analysis (Continued)

combined impacts of the crude oil price decline on our industry and the financial market declines driven by COVID-19 have impacted us as follows:

•The publicly traded price for our common stock (NYSE: WMB) declined significantly in the first quarter of 2020. As a result, our board of directors approved a limited duration shareholder rights agreement. (See Note 11 – Stockholders’ Equity of Notes to the Consolidated Financial Statements.)

•Driven by the decline in our market capitalization and the underlying decrease in fair value of our Northeast G&P reporting unit, we recognized a $187 million impairment of goodwill during the first quarter of 2020. (See Note 12 – Fair Value Measurements and Guarantees of Notes to the Consolidated Financial Statements.)

•The same economic conditions impacted the fair value of certain of our equity-method investments, resulting in $938 million of other-than-temporary impairments of these investments in the first quarter of 2020. (See Note 12 – Fair Value Measurements and Guarantees of Notes to the Consolidated Financial Statements.)

Considering the decline in crude oil prices, we note the following about our businesses:

•Our interstate natural gas transmission businesses are fully contracted under long-term firm reservation contracts with high credit quality customers and are not exposed to crude oil prices.

•We believe counterparty credit concerns in our gathering and processing business are significantly mitigated by the physical nature of our services, where we gather at the wellhead and are therefore critical to a producer’s ability to move product to market.

•Our on-shore natural gas gathering ~~services~~and processing businesses are substantially focused on gas-directed drilling basins rather than oil, with a broad diversity of basins and customers served. Further, a decline in oil drilling would be expected to ~~the Appomattox development~~result in the Gulf of Mexico. We completed modifications to install an alternate delivery route to our Main Pass 261 Platform, as well as modifications to our onshore Mobile Bay processing facility. The project went in service early in July 2019, atless associated natural gas production, which ~~time~~could drive more demand for natural gas produced from gas-directed basins we ~~also purchased~~serve.

•Our deepwater transportation business is supported mostly by major oil producers with a ~~54-mile-long, 16-inch-diameter pipeline (the Norphlet Pipeline) for $200 million. This pipeline transports gas from the Appomattox development to our Main Pass 261 Platform.~~

~~Filing of Rate Case~~

On August 31, 2018, Transco filed a general rate case with the FERC for an overall increase in rates. In September 2018, with the exception of certain rates that reflected a rate decrease, the FERC accepted and suspended our general rate filing to be effective March 1, 2019, subject to refund and the outcome of a hearing. The specific rates that reflected a rate decrease were accepted, without suspension, to be effective October 1, 2018, as requested by Transco, and will not be subject to refund. In March 2019, the FERC accepted our motion to place the rates that were suspended by the September 2018 order into effect on March 1, 2019, subject to refund. In October 2019, we reached an agreement on the terms of a settlement with the participants that would resolve all issues in the rate case without the need for a hearing. Final resolution of the rate case is subject to the filing of a formal stipulation and agreement with, and subsequent approval by, the FERC. We have provided a reserve of $131 million for rate refunds which we believe is adequate for any refunds that may be required.

~~Commodity Prices~~long-cycle perspective.

NGL ~~per-unit~~Margins

Per-unit non-ethane margins were approximately 5135 percent lower in the first nine months of ~~2019~~2020 compared to the same period ~~of 2018~~in 2019 primarily due to a 3230 percent decrease in per-unit non-ethane sales prices, ~~and an approximate 3~~partially offset by 31 percent ~~increase in~~lower per-unit natural gas feedstock prices.

NGL margins are defined as NGL revenues less any applicable Btu replacement cost, plant fuel, and third-party transportation and fractionation. Per-unit NGL margins are calculated based on sales of our own equity volumes at the processing plants. Our equity volumes include NGLs where we own the rights to the value from NGLs recovered at our plants under both “keep-whole” processing agreements, where we have the obligation to replace the lost heating value with natural gas, and “percent-of-liquids” agreements whereby we receive a portion of the extracted liquids with no obligation to replace the lost heating value.

The potential impact of commodity prices on our business for the remainder of ~~2019~~2020 is further discussed in the following Company Outlook.

Filing of Rate Case

Management’s Discussion and Analysis (Continued)

were suspended by the September 2018 order into effect on March 1, 2019, subject to refund. In October 2019, we reached an agreement on the terms of a settlement with the participants that would resolve all issues in the rate case without the need for a hearing, and on December 31, 2019, we filed a formal stipulation and agreement with the FERC setting forth such terms of settlement. On March 24, 2020, the FERC issued an order approving the uncontested rate case settlement, which became effective on June 1, 2020. Rate refunds related to increased rates collected prior to the effective date of the settlement were paid on July 1, 2020.

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 ~~2019~~2020 includes a continued focus on ~~growing~~earnings and cash flow growth, while continuing to improve leverage metrics and control operating costs. Many of our ~~fee-based businesses, executing~~producer customers have been impacted by extremely low energy commodity prices, which resulted in a decrease in drilling activity and the temporary shut-in of certain existing production. We are responding by reducing the pace of our capital growth ~~projects,~~spending in our gathering and processing business and remaining committed to operating cost discipline.

In the current environment, the credit profiles of certain of our producer customers are increasingly challenged, including ~~through joint ventures,~~some that have filed for bankruptcy protection. But as previously discussed, the physical nature of services we provide supports the success of these customers. In many cases, we have long-term acreage dedications with strong historical contractual conveyances that create real estate interests in unproduced gas. In exchange for such dedication of production, we invest capital to build gathering lines uniquely to serve a producer’s wells. Therefore, our gathering lines are physically connected to the customer’s wellheads and ~~accomplishing cost discipline initiatives~~pads, conditioning and connecting the production to ~~ensure operations support~~available markets. There may not be other gathering lines nearby. The construction of gathering systems is capital intensive and it would be very costly for others to replicate, especially considering the depletion to date of the associated reserves. As a result, we play a critical role in getting a customer’s production from the wellhead to a marketable condition and location. This tends to reduce collectability risk as our ~~strategy. We anticipate~~services enable producers to generate operating cash flows.

In 2020, our operating results ~~will increase through organic business growth driven by Transco~~are expected to include higher Northeast G&P results associated with higher gathering and processing volumes and the benefit of lower expenses associated with our organizational realignment completed earlier this year as well as other cost-savings initiatives. We also anticipate increases from Transco’s and Northwest Pipeline’s recent expansion projects placed in-service and ~~continued expansion~~Transco’s rate settlement, as well as a full year contribution from the Norphlet project in the ~~Northeast~~Eastern Gulf region.

~~Management’s Discussion~~ These increases will be partially offset by lower deferred revenue amortization related to the West’s Barnett Shale region and ~~Analysis (Continued)~~

Gulfstar One in the Eastern Gulf region. We also expect lower fee revenues in the West, as well as reduced results from the Gulf of Mexico due to loss of production and an increase in repair expenses as a result of several named windstorms.

Our growth capital and investment expenditures in ~~2019~~2020 are expected to be in a range from ~~$2.3~~$1.0 billion to ~~$2.5~~$1.2 billion. Growth capital spending in ~~2019~~2020 primarily includes Transco expansions, all of which are fully contracted with firm transportation agreements, and ~~continuing to develop~~ our ~~gathering and processing infrastructure~~Bluestem NGL pipeline project in the ~~Northeast G&P and West segments.~~Mid-Continent region. 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.

As a result of our significant continued capital and investment expenditures on Transco expansion projects and fee-based gathering and processing projects, fee-based businesses are a significant component of our portfolio and serve to reduce the influence of commodity price fluctuations on our operating results and cash flows. We expect to benefit as continued growth in demand for low-cost natural gas is driven by increases in LNG exports, industrial demand, and power generation. For 2019, current forward market prices indicate crude oil, natural gas, and NGL prices are expected to be lower compared to 2018. We continue to address certain pricing risks through the utilization of commodity hedging strategies.

In 2019, our operating results are expected to include increases from our regulated Transco fee-based business, primarily related to projects placed in-service beginning early 2018 and 2019, as well as the favorable impact from Transco’s agreement on the terms of a settlement in its general rate case as previously discussed. For our non-regulated businesses, we anticipate increases in fee-based revenue in the Northeast G&P segment driven by expansion projects, partially offset with a decrease in the West segment primarily due to the absence of results of our former sold or deconsolidated assets, lower commodity margins and commodity-based gathering and processing rates, and reduced recognition of deferred revenue associated with the end of a contractual MVC period. We expect overall gathering and processing volumes to grow in 2019 for our continuing businesses. Additionally, we believe our expenses will be impacted by the changes in our asset portfolio, including the UEOM acquisition and asset divestitures, as well as severance charges and other costs associated with our previously announced organizational realignment.

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;

Management’s Discussion and Analysis (Continued)

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

•Counterparty credit and performance risk, including unexpected developments in ongoing customer bankruptcy proceedings;

•Unexpected significant increases in capital expenditures or delays in capital project execution;

~~Counterparty credit and performance risk;~~

•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 downturn, including increased interest rates;

•Physical damages to facilities, including damage to offshore facilities by named windstorms;

•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, ~~2018,~~2019, as filed with the SEC on February ~~21, 2019.~~24, 2020, as supplemented by the disclosures in Part II, Item 1A. in our Quarterly Report on Form 10-Q for the quarter ended March 31, 2020.

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

~~Management’s Discussion and Analysis (Continued)~~

Expansion Projects

Our ongoing major expansion projects include the following:

~~Northeast G&P~~

~~Susquehanna Supply Hub Expansion~~

~~We continue to expand the gathering systems in the Susquehanna Supply Hub that are needed to meet our customers’ production plans by 2020. This next expansion~~Transmission & Gulf of ~~the gathering infrastructure includes an additional 40,000 horsepower of new compression and gathering pipelines to bring the capacity to approximately 4.5 Bcf/d.~~

~~Atlantic-Gulf~~

~~Constitution Pipeline~~

We currently own 41 percent of Constitution with three other parties holding 25 percent, 24 percent, and 10 percent, respectively. We are the operator of Constitution. The 126-mile Constitution pipeline is proposed to connect our gathering system in Susquehanna County, Pennsylvania, to the Iroquois Gas Transmission and Tennessee Gas Pipeline systems in New York, as well as to a local distribution company serving New York and Pennsylvania. For further discussion on the status of this project, see Note 4 – Variable Interest Entities of Notes to Consolidated Financial Statements.

~~Gateway~~

In December 2018, we received approval from the FERC to expand Transco’s existing natural gas transmission system to provide incremental firm transportation capacity from PennEast Pipeline Company’s proposed interconnection with Transco’s mainline south of Station 205 in New Jersey to other existing Transco meter stations within New Jersey. We plan to place the project into service in the first half of 2020, assuming timely receipt of all necessary regulatory approvals. The project is expected to increase capacity by 65 Mdth/d.

~~Hillabee~~

In February 2016, the FERC issued a certificate order for the initial phases of Transco’s Hillabee Expansion Project. The project involves an expansion of Transco’s existing natural gas transmission system from Station 85 in west central Alabama to a new interconnection with the Sabal Trail pipeline in Alabama. The project is being constructed in phases, and all of the project expansion capacity is dedicated to Sabal Trail pursuant to a capacity lease agreement. Phase I was completed in 2017 and it increased capacity by 818 Mdth/d. The in-service date of Phase II is planned for the second quarter of 2020, and together Phases I and II are expected to increase capacity by 1,025 Mdth/d.Mexico

Northeast Supply Enhancement

In May 2019, we received approval from the FERC to expand Transco’s existing natural gas transmission system to provide incremental firm transportation capacity from Station 195 in Pennsylvania to the Rockaway Delivery Lateral transfer point in New York. ~~Approvals~~However, approvals required for the project from the New York State Department of Environmental Conservation and the New Jersey Department of Environmental Protection ~~remain pending, with each such agency having~~were denied ~~without prejudice, Transco’s applications for such approvals.~~in May 2020. We have not refiled our applications for those ~~approvals and have addressed the technical issues identified by the agencies. We plan to place the project into service in the fourth quarter of 2020, assuming timely receipt of these remaining~~ approvals. The project ~~is expected to~~would increase capacity by 400 Mdth/d. See further discussion in Critical Accounting Estimates.

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 plan to place up to 230 Mdth/d of capacity under the project into

~~Management’s Discussion and Analysis (Continued)~~

service in ~~late~~the fourth quarter of 2020, ~~assuming timely receipt~~and the remainder of ~~all remaining necessary regulatory approvals. The~~the project capacity into service in the first quarter of 2021. In total, the project is expected to increase capacity by 296 Mdth/d.

Leidy South

In July ~~2019,~~2020, we ~~filed an application with~~received approval from the FERC for ~~approval of~~ 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 plan to place up to 125 Mdth/d of capacity under the project into service in the ~~second half~~fourth quarter of ~~2022,~~2020, and we plan to place the remainder of the project into service as early as the fourth quarter of

Management’s Discussion and Analysis (Continued)

2021, assuming timely receipt of all necessary regulatory approvals. The project is expected to increase capacity by 582 Mdth/d.

West

~~North Seattle Lateral Upgrade~~

In July 2018, we received approval from the FERC to expand delivery capabilities on Northwest Pipeline’s North Seattle Lateral. The project consists of the removal and replacement of approximately 5.9 miles of 8-inch diameter pipeline with new 20-inch diameter pipeline. We plan to place the project into service during the fourth quarter of 2019. The project is expected to increase delivery capacity by approximately 159 Mdth/d.

~~Wamsutter Expansion~~

We have expanded our gathering and processing infrastructure in the Wamsutter region of Wyoming in order to meet our customers’ production plans. We have completed construction of new compressor stations and modifications to our processing facilities, which are now in service. The expansion added approximately 20 miles of gathering pipelines and approximately 15,000 horsepower of compression. Additional expansion is expected in 2020, subject to the level of production activity in the area.

Project Bluestem

We are expanding our presence in the Mid-Continent region through building a 188-mile NGL pipeline from our fractionator near Conway, Kansas, to an ~~interconnect~~interconnection with a third-party NGL pipeline system in Oklahoma, providing us with firm access to Mt. Belvieu pricing. As part of the project, the third-party ~~intends to construct~~is constructing a 110-mile pipeline extension of ~~their~~its existing NGL pipeline system that will have an initial capacity of 120 Mbbls/d. The pipeline and extension projects are expected to be in operation by the end of the fourth quarter of 2020. Further, during the first quarter of 2019, we exercised an option to purchase a 20 percent equity interest in a Mt. Belvieu fractionation train developed by the third ~~party. The pipeline and extension projects are expected to be~~party, which was placed into service ~~during~~in the first quarter of ~~2021.~~2020.

Critical Accounting Estimates

~~Constitution Pipeline Capitalized Project Costs~~

~~As of September 30, 2019,~~ ~~Property, plant, and equipment~~inour Consolidated Balance Sheet includes approximately $376 million of capitalized project costs for Constitution, for which we are the construction manager and own a 41 percent consolidated interest. As a result of the events discussed in Note 4 – Variable Interest Entities of Notes to Consolidated Financial Statements, we have evaluated the capitalized project costs for impairment and determined that no impairment was necessary. Our evaluation considered probability-weighted scenarios of undiscounted future net cash flows, including scenarios assuming construction of the pipeline, as well as a scenario where the project does not proceed. It is reasonably possible that future unfavorable developments, such as failure to successfully renegotiate associated customer contracts, increased estimates of construction costs, or further significant delays, could result in a future impairment.

~~Regulatory Liabilities Resulting from Tax Reform~~

In December 2017, the Tax Cuts and Jobs Act (Tax Reform) was enacted, which, among other things, reduced the corporate income tax rate from 35 percent to 21 percent. Rates charged to customers of our regulated natural gas

~~Management’s Discussion and Analysis (Continued)~~

pipelines are subject to the rate-making policies of the FERC, which have historically permitted the recovery of an income tax allowance that includes a deferred income tax component. Due to the reduced income tax rate from Tax Reform and the collection of historical rates that reflected historical federal income tax rates, we expect that our regulated natural gas pipelines will be required to return amounts to certain customers through future rates. As a result, we established regulatory liabilities during 2017 and at September 30, 2019, these liabilities total $609 million. The timing and actual amount of such return related to Transco will be subject to the final outcome of the rate case discussed in Overview while the amount of such return related to Northwest Pipeline will be subject to future negotiations regarding this matter and many other elements of cost-of-service rate proceedings, including other costs of providing service.

Equity-Method Investments

We ~~continue to~~ monitor our equity-method investments for any indications that the carrying value may have experienced an other-than-temporary decline in value. ~~When evidence~~

In the first quarter of 2020, we observed a ~~loss~~significant decline in the publicly traded price of our common stock (NYSE: WMB) as well as other industry peers and increases in equity yields within the midstream and overall energy industry, which served to increase our estimates of discount rates and weighted-average cost of capital. These changes were attributed to the swift, world-wide economic declines associated with actions to address the spread of COVID-19, coupled with the energy industry impact of significantly reduced energy commodity prices, which were further impacted by crude oil price declines associated with geopolitical actions during the quarter. These significant macroeconomic changes served as indications that the carrying amount of certain of our equity-method investments may have experienced an other-than temporary decline in fair value, ~~has occurred,~~determined in accordance with Accounting Standards Codification (ASC) Topic 323, “Investments - Equity Method and Joint Ventures.”

As a result, we ~~compare our estimate of~~estimated the fair value of ~~the investment to the carrying value~~these equity-method investments in accordance with ASC Topic 820, “Fair Value Measurement,” as of the ~~investment~~March 31, 2020, measurement date. In assessing the fair value, we were required to ~~determine whether an impairment has occurred. We generally estimate~~consider recent publicly available indications of value, which included lower observed publicly traded EBITDA market multiples as compared with recent history, and significantly higher industry weighted-average discount rates. As a result, we determined that there were other-than-temporary declines in the fair value of our investments using an income approach where significant judgments and assumptions include expected future cash flows and the appropriate discount rate. In some cases, we may utilize a form of market approach to estimate the fair valuecertain of our ~~investments. During 2019, we have~~equity-method investments, resulting in recognized impairments during the first quarter of 2020 totaling ~~$186 million related to our equity-method investments.~~$938 million. (See Note 1312 – Fair Value Measurements and Guarantees of Notes to Consolidated Financial Statements.) This included impairments of certain of our equity-method investments in our Northeast G&P segment totaling $405 million, primarily associated with operations in wet-gas areas where producer drilling activities are influenced by NGL prices, which historically trend with crude oil prices. This total was primarily comprised of impairments of our investment in Caiman II and predominantly wet-gas gathering systems that are part of Appalachia Midstream Investments. We also recognized an impairment of $97 million related to Discovery within the Transmission & Gulf of Mexico segment. We estimated the fair value of these investments as of the March 31, 2020, measurement date utilizing income and market approaches, which were impacted by assumptions reflecting the significant recent market declines previously discussed, such as higher discount rates, ranging from 9.7 percent to 13.5 percent, and lower EBITDA multiples ranging from 5.0x to 6.2x. We also considered any debt held at the investee level, and its impact to fair value. We estimate that a one percentage point increase or decrease in the discount rates used would increase these recognized impairments by approximately $197 million or decrease the level of these recognized impairments by approximately $121 million and a 0.5x increase or decrease in the EBITDA multiples assumed would decrease or increase the level of impairments recognized by approximately $48 million.

During the first quarter of 2020 we also recognized $436 million of impairments within our West segment related to our investments in RMM and Brazos Permian II, measured using an income approach. Both investees

Management’s Discussion and Analysis (Continued)

operate in primarily crude oil-driven basins where our gathering volumes are driven by crude oil drilling. Our expectation of continued lower crude oil prices and related expectation of significant reductions in current and future producer activities in these areas led to reduced estimates of expected future cash flows. Our fair value estimates also reflected increases in the discount rates to approximately 17 percent for these investments. We also considered any debt held at the investee level, and its impact to fair value. We estimate that a one percentage point increase in the discount rate would increase these recognized impairments by approximately $32 million, while a one percentage point decrease would decrease these impairments by approximately $43 million.

Judgments and assumptions are inherent in our estimates of future cash flows, discount rates, and market measures utilized. The use of alternate judgments and assumptions could result in a different calculation of fair value, which could ultimately result in the recognition of a different impairment charge in the consolidated financial statements, potentially including impairments for investments that were evaluated but for which no impairments were recognized.

Property, Plant, and Equipment and Other Identifiable Intangible Assets

As a result of the previously described significant macroeconomic changes during the first quarter of 2020, we also evaluated certain of our property, plant, and equipment and other identifiable intangible assets for indicators of impairment as of March 31, 2020. In our assessments, we considered the impact of the then current market conditions on certain of our assets and did not identify any indicators that the carrying amounts of those assets may not be recoverable. The use of alternate judgments or changes in future conditions could result in a different conclusion regarding the occurrence and measurement of impairments affecting the consolidated financial statements.

As of September 30, 2020, Property, plant, and equipment in our Consolidated Balance Sheet includes approximately $215 million of capitalized project development costs for the Northeast Supply Enhancement project. As previously discussed, approvals required for the project from the New York State Department of Environmental Conservation and the New Jersey Department of Environmental Protection have been denied and we have not refiled at this time. Beginning in May 2020, we discontinued capitalization of costs related to this project.

The customer precedent agreements for the Northeast Supply Enhancement project remain in effect and the project’s FERC certificate remains active. As such, we do not believe this project is probable of abandonment at this time and consider the carrying amount to be recoverable; thus, no impairment charge has been recognized. It is reasonably possible that further adverse developments in the near future could change this determination, resulting in a future impairment charge of a substantial portion of the capitalized costs.

Management’s Discussion and Analysis (Continued)

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, ~~2019,~~2020, compared to the three and nine months ended September 30, ~~2018.~~2019. 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,
2019 2018 $ Change* % Change* 2019 2018 $ Change* % Change*
(Millions) (Millions)
Revenues:
Service revenues $ 1,495
$ 1,371
+124
+9 % $ 4,424
$ 4,062
+362
+9 %
Service revenues – commodity consideration 38
121
-83
-69 % 158
316
-158
-50 %
Product sales 466
811
-345
-43 % 1,512
2,104
-592
-28 %
Total revenues 1,999
2,303
6,094
6,482

Costs and expenses:
Product costs 434
790
+356
+45 % 1,442
2,039
+597
+29 %
Processing commodity expenses 19
30
+11
+37 % 83
91
+8
+9 %
Operating and maintenance expenses 364
389
+25
+6 % 1,091
1,134
+43
+4 %
Depreciation and amortization expenses 435
425
-10
-2 % 1,275
1,290
+15
+1 %
Selling, general, and administrative expenses 130
174
+44
+25 % 410
436
+26
+6 %
Impairment of certain assets —
—
—
—
76
66
-10
-15 %
Other (income) expense – net (11 ) (6 ) +5
+83 % 30
24
-6
-25 %
Total costs and expenses 1,371
1,802
4,407
5,080

Operating income (loss) 628
501
1,687
1,402

Equity earnings (losses) 93
105
-12
-11 % 260
279
-19
-7 %
Other investing income (loss) – net (107 ) 2
-109
NM
(54 ) 74
-128
NM
Interest expense (296 ) (270 ) -26
-10 % (888 ) (818 ) -70
-9 %
Other income (expense) – net 1
52
-51
-98 % 19
99
-80
-81 %
Income (loss) before income taxes 319
390
1,024
1,036

Provision (benefit) for income taxes 77
190
+113
+59 % 244
297
+53
+18 %
Net income (loss) 242
200
780
739

Less: Net income (loss) attributable to noncontrolling interests 21
71
+50
+70 % 54
323
+269
+83 %
Net income (loss) attributable to The Williams Companies, Inc. $ 221
$ 129
$ 726
$ 416


	Three Months Ended September 30,							Nine Months Ended September 30,
	2020		2019		$ Change*	% Change*		2020		2019		$ Change*	% Change*
	(Millions)							(Millions)
Revenues:
Service revenues	$	1,479	$	1,495	-16	-1	%	$	4,399	$	4,424	-25	-1	%
Service revenues – commodity consideration	40		38		+2	+5	%	93		158		-65	-41	%
Product sales	414		466		-52	-11	%	1,135		1,512		-377	-25	%
Total revenues	1,933		1,999					5,627		6,094
Costs and expenses:
Product costs	380		434		+54	+12	%	1,047		1,442		+395	+27	%
Processing commodity expenses	21		19		-2	-11	%	49		83		+34	+41	%
Operating and maintenance expenses	336		364		+28	+8	%	993		1,091		+98	+9	%
Depreciation and amortization expenses	426		435		+9	+2	%	1,285		1,275		-10	-1	%
Selling, general, and administrative expenses	114		130		+16	+12	%	354		410		+56	+14	%
Impairment of certain assets	—		—		—	—	%	—		76		+76	+100	%
Impairment of goodwill	—		—		—	—	%	187		—		-187	NM
Other (income) expense – net	15		(11)		-26	NM		28		30		+2	+7	%
Total costs and expenses	1,292		1,371					3,943		4,407
Operating income (loss)	641		628					1,684		1,687
Equity earnings (losses)	106		93		+13	+14	%	236		260		-24	-9	%
Impairment of equity-method investments	—		(114)		+114	+100	%	(938)		(186)		-752	NM
Other investing income (loss) – net	2		7		-5	-71	%	6		132		-126	-95	%
Interest expense	(292)		(296)		+4	+1	%	(882)		(888)		+6	+1	%
Other income (expense) – net	(23)		1		-24	NM		(14)		19		-33	NM
Income (loss) before income taxes	434		319					92		1,024
Provision (benefit) for income taxes	111		77		-34	-44	%	24		244		+220	+90	%


Net income (loss)	323		242					68		780
Less: Net income (loss) attributable to noncontrolling interests	14		21		+7	+33	%	(27)		54		+81	NM
Net income (loss) attributable to The Williams Companies, Inc.	$	309	$	221				$	95	$	726


*	~~+ = 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.~~

* + = 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)

Three months ended September 30, ~~2019~~2020 vs. three months ended September 30, ~~2018~~2019

Service revenues ~~increased~~decreased primarily due to lower deferred revenue amortization associated with the end of the exclusive use period at Gulfstar One, lower volumes in our West segment, and temporary shut-ins at certain offshore Gulf of Mexico operations. This decrease was partially offset by an increase in the Eagle Ford Shale region primarily due to higher MVC revenue, higher Northeast JV revenues driven by higher volumes, as well as higher transportation fee revenues at Transco associated with expansion projects placed in service in 2019 and ~~2018,~~2020.

Product sales decreased primarily due to lower volumes associated with our marketing activities. This decrease also includes lower system management gas sales. Marketing revenues and system management gas sales are substantially offset in Product costs.

Product costs decreased primarily due to lower volumes for marketing activities and lower system management gas costs.

Operating and maintenance expenses decreased primarily due to lower employee-related expenses, including the absence of 2019 severance and related costs and the favorable impact of a change in an employee benefit policy (see Note 6 – Other Accruals of Notes to Consolidated Financial Statements), and lower maintenance and operating costs primarily due to timing and scope of activities.

Selling, general, and administrative expenses decreased primarily due to lower employee-related expenses and lower external legal costs.

The unfavorable change in Other (income) expense – net within Operating income (loss) includes net unfavorable changes in charges and credits to regulatory assets and liabilities related to the absence of a third-quarter 2019 adjustment associated with Transco’s rate case settlement and the absence of a 2019 customer settlement.

The favorable change in Operating income (loss) includes the impact of an increase in the Eagle Ford Shale region primarily due to higher MVC revenue, higher Northeast JV volumes, lower employee-related expenses, and the favorable impact from ~~UEOM, which is now a consolidated entity after~~Transco’s expansion projects. The favorable change was partially offset by lower deferred revenue amortization associated with the ~~remaining ownership interest was purchased~~end of the exclusive use period at Gulfstar One and lower volumes in ~~March 2019,~~our West segment.

Equity earnings (losses) changed favorably primarily due to increases at Appalachia Midstream Investments and ~~from~~Caiman II driven by higher volumes, partially offset by a decrease at Laurel Mountain driven by our share of an impairment of certain assets.

The change in Impairment of equity-method investments is due to the ~~Susquehanna Supply Hub. These increases are~~absence of 2019 impairments to our equity-method investments, including Laurel Mountain (see Note 12 – Fair Value Measurements and Guarantees of Notes to Consolidated Financial Statements).

The unfavorable change in Other income (expense) – net below Operating income (loss) includes lower allowance for equity funds used during construction (equity AFUDC) as well as the write-off of a regulatory asset related to a cancelled project, partially offset by the absence of ~~revenues~~2019 charges for loss contingencies associated with ~~asset divestitures and deconsolidations during 2018, including our~~ former ~~Four Corners area operations, and~~operations.

Provision (benefit) for income taxes changed unfavorably primarily due to higher pre-tax income. See Note 7 – 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, 2020 vs. nine months ended September 30, 2019

Service revenues decreased primarily due to lower deferred revenue ~~recognition~~amortization at Gulfstar One, the expiration of an MVC agreement in the Barnett Shale region, lower volumes and rates in our West segment, and temporary shut-ins at certain Gulf of Mexico operations. This decrease was partially offset by higher Northeast G&P revenues driven by higher volumes and the March 2019 consolidation of UEOM, higher MVC revenue in the Eagle Ford

Management’s Discussion and Analysis (Continued)

Shale region, as well as higher transportation fee revenues at Transco, associated with expansion projects placed in service in 2019 and 2020, and increased volumes in the ~~end of a contractual MVC period.~~Eastern Gulf region.

Service revenues – commodity consideration decreased primarily due to lower commodity prices, as well as lower equity NGL ~~prices, and lower~~processing volumes due to ~~the absence of our former Four Corners area operations and ethane rejection.~~less producer drilling activity. 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 within the month processed and therefore are offset in Product costs below.

Product sales decreased primarily due to lower NGL and natural gas prices associated with our marketing and equity NGL sales ~~activities.~~activities, as well as lower volumes associated with our equity NGL sales activities, partially offset by higher marketing volumes. This decrease also includes lower ~~volumes from our equity NGL sales primarily reflecting the absence of our former Four Corners area operations and lower~~ system management gas ~~sales, partially offset by higher marketing volumes.~~sales. Marketing revenues and system management gas sales are substantially offset in Product costs.

Product costs decreased primarily due to lower NGL and natural gas prices associated with our marketing and equity NGL production activities. This decrease also includes lower volumes acquired as commodity consideration for NGL processing services ~~reflecting the absence of our former Four Corners area operations~~ and lower system management gas costs, partially offset by higher volumes for marketing activities.

Processing commodity expenses decreased primarily due to lower natural gas purchases associated with equity NGL production primarily due to lower natural gas prices and lower volumes.

Operating and maintenance expenses decreased ~~primarily~~ due to lower employee-related expenses, including the absence of our former Four Corners area operations and a decrease in Transco’s contracted services mainly due to the timing of required engine overhauls and integrity testing, partially offset by the consolidation of UEOM, and by an accrual for estimated2019 severance and related costs ~~primarily~~and the associated ~~with our voluntary separation program (VSP)~~reduced costs in 2020 (see Note 6 – Other ~~Income and Expenses~~Accruals of Notes to Consolidated Financial Statements). as well as the favorable impact of a change in an employee benefit policy, and lower maintenance and operating primarily due to timing and scope of activities. This decrease was partially offset by higher expenses related to the consolidation of UEOM in March 2019.

Depreciation and amortization expenses increased primarily due to ~~the consolidation of UEOM and~~ new assets placed in service ~~substantially~~and the March 2019 consolidation of UEOM, partially offset by ~~the 2018 impairment of certain~~lower expense related to assets that became fully depreciated in the ~~Barnett Shale region.~~fourth quarter of 2019.

Selling, general, and administrative expenses decreased primarily due to lower employee-related expenses, including the ~~absences~~absence of ~~a charge for a 2018 charitable contribution~~2019 severance and related costs and the associated reduced costs in 2020 (see Note 6 – Other Accruals of ~~preferred stock~~Notes to ~~The Williams Companies Foundation, Inc. and fees~~Consolidated Financial Statements), as well as the absence of transaction costs associated with our 2019 acquisition of UEOM and the ~~WPZ Merger.~~formation of the Northeast JV.

The favorable change in Impairment of certain assets includes the absence of 2019 impairments of certain Eagle Ford Shale gathering assets and certain idle gathering assets (see Note 12 – Fair Value Measurements and Guarantees of Notes to Consolidated Financial Statements).

Impairment of goodwill reflects the goodwill impairment charge at Northeast JV in 2020 (see Note 12 – Fair Value Measurements and Guarantees of Notes to Consolidated Financial Statements).

The favorable change in Other (income) expense – net within Operating income (loss) includes net favorable changes to charges and credits associated with a regulatory asset related to Transco's asset retirement obligations and the absence of a 2019 unfavorable regulatory ~~assets and liabilities, partially~~asset adjustment at Other, offset by the absence of a ~~2018 gain on asset retirement (see Note 6 – Other Income and Expenses of Notes to Consolidated Financial Statements).~~2019 customer settlement.

The ~~favorable~~unfavorable change in Operating income (loss) includes the 2020 impairment of goodwill at Northeast G&P, lower deferred revenue amortization at Gulfstar One, the expiration of an ~~increase in~~ ~~Service revenues~~ ~~primarily associated with Transco projects placed in-service and higher gathering volumes~~MVC agreement in the ~~Northeast~~Barnett Shale region, ~~the absence of a charge for a charitable contribution of preferred stock to the Williams Foundation, Inc.,~~ and ~~the absence of fees associated with the WPZ Merger, partially offset by~~ unfavorable commodity margins primarily reflecting lower NGL sales ~~prices~~prices. The unfavorable change was partially offset by higher Northeast JV volumes, the absence of the 2019 impairment of certain assets, lower employee-related expenses, the favorable impacts of the consolidation of UEOM, and ~~lower~~the favorable impact from Transco’s expansion projects.

Management’s Discussion and Analysis (Continued)

Equity earnings (losses) changed unfavorably primarily due to our share of the 2020 impairment of goodwill at RMM (see Note 5 – Investing Activities of Notes to Consolidated Financial Statements) and a decrease at OPPL. This decrease was partially offset by increases at Appalachia Midstream Investments and Caiman II driven by higher volumes.

Impairment of equity-method investments includes impairments of various equity-method investments in 2020, partially offset by the absence of impairments of equity method investments in 2019 (see Note 12 – Fair Value Measurements and Guarantees of Notes to Consolidated Financial Statements).

The unfavorable change in Other investing income (loss) – net is primarily due to the absence of a 2019 ~~impairments to~~gain on the sale of our equity-method ~~investments, including Laurel Mountain~~investment in Jackalope (see Note 135 – ~~Fair Value Measurements and Guarantees~~Investing Activities of Notes to Consolidated Financial Statements).

~~Interest expense~~ ~~increased primarily due to an increase in financing obligations associated with Transco’s Atlantic Sunrise project and lower capitalized interest due to projects placed in service.~~

~~Management’s Discussion and Analysis (Continued)~~

The unfavorable change in Other income (expense) – net below Operating income (loss) ~~is primarily due~~includes lower equity AFUDC, the write-off of a regulatory asset related to a ~~decrease in equity AFUDC associated with reduced capital expenditures on projects~~cancelled project, and a 2020 pension plan settlement charge, partially offset by the absence of 2019 charges for loss contingencies associated with former operations.

Provision (benefit) for income taxes changed favorably primarily due to ~~the absence of a $105 million 2018 valuation allowance on certain deferred tax assets that may not be realized following the WPZ merger, partially offset by higher~~lower pre-tax ~~income attributable to The Williams Companies, Inc.~~income. See Note 7 – 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 favorable change in Net income (loss) attributable to noncontrolling interests is primarily due to ~~our third- quarter 2018 acquisition~~the noncontrolling interests’ share of the ~~publicly held interests in WPZ associated with the WPZ Merger.~~

~~Nine months ended September 30, 2019 vs. nine months ended September 30, 2018~~

~~Service revenuesincreased primarily due to higher transportation fee revenues~~first-quarter 2020 goodwill impairment charge at ~~Transco associated with expansion projects placed in service in 2019~~Northeast JV, and ~~2018 and the consolidation of UEOM, as well as higher volumes at the Susquehanna Supply Hub, and higher rates and volumes from new wells in the Utica Shale region. These increases are~~lower Gulfstar One results, partially offset by the absence of revenues associated with asset divestitures and deconsolidations during 2018, including our former Four Corners area operations, and lower deferred revenue recognition in the Barnett Shale associated with the end of a contractual MVC period.

~~Service revenues – commodity consideration~~ decreased due to lower NGL prices and lower volumes primarily due to the absence of our former Four Corners area operations. 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 within the month processed and therefore are offset in ~~Product costs~~ ~~below.~~

~~Product salesdecreased primarily due to lower NGL and natural gas prices associated with our marketing and equity NGL sales activities and lower volumes~~impact from our equity NGL sales primarily reflecting the absence of our former Four Corners area operations and lower system management gas sales, partially offset by higher marketing volumes. Marketing revenues and system management gas sales are substantially offset in ~~Product costs~~.

~~Product costs~~ decreased primarily due to lower NGL and natural gas prices associated with our marketing and equity NGL production activities. This decrease also includes lower volumes acquired as commodity consideration for NGL processing services reflecting the absence of our former Four Corners area operations and lower system management gas costs, partially offset by higher volumes for marketing activities.

~~Operating and maintenance expenses~~decreased primarily due to the absence of our former Four Corners area operations, partially offset by the consolidation of UEOM, and by an accrual for estimated severance and related costs primarily associated with our VSP.

~~Depreciation and amortization expenses~~ decreased primarily due to the 2018 impairment of certain assets in the Barnett Shale region and the absence of our former Four Corners area operations, partially offset by new assets placed in service and by the consolidation of UEOM.

~~Selling, general, and administrative expenses~~ decreased primarily due to the absences of a charitable contribution of preferred stock to the Williams Foundation, Inc. and fees associated with the WPZ Merger, partially offset by an accrual for estimated severance and related costs primarily associated with our VSP, and transaction expenses associated with the acquisition of UEOM and the formation of the Northeast ~~JV.~~

~~The unfavorable change~~JV in ~~Impairment of certain assets~~ includes a second-quarter 2019 impairment of certain Eagle Ford Shale gathering assets and a first-quarter 2019 impairment of certain idle gathering assets, partially offset by the absence of a 2018 impairment of certain idle pipelines.

~~The unfavorable change in~~ ~~Other (income) expense – net~~ ~~within~~ ~~Operating income (loss)~~ ~~includes the absence of a 2018 gain on asset retirement, a 2019 charge for the reversal of expenditures previously capitalized, and net unfavorable~~

~~Management’s Discussion and Analysis (Continued)~~

~~changes to charges and credits to regulatory assets and liabilities (see Note 6 – Other Income and Expenses of Notes to Consolidated Financial Statements).~~

~~The favorable change in~~ ~~Operating income (loss)~~ ~~includes an increase in~~ ~~Service revenues~~ primarily associated with Transco projects placed in-service and higher gathering volumes in the Northeast region, the favorable impact of acquiring the additional interest of UEOM, the absence of a charitable contribution of preferred stock to the Williams Foundation, Inc., and the absence of fees associated with the WPZ Merger. These favorable changes were partially offset by the impact of asset divestitures and deconsolidations during 2018, including our former Four Corners area operations, unfavorable commodity margins primarily reflecting lower NGL sales prices and lower volumes, an accrual for estimated severance and related costs primarily associated with our VSP, and transaction expenses associated with the acquisition of UEOM and the formation of the Northeast JV.

~~The unfavorable change in~~ ~~Other investing income (loss) – net~~ reflects noncash impairments to equity method investments (see Note 13 – Fair Value Measurements and Guarantees of Notes to Consolidated Financial Statements) and the absence of a 2018 gain on deconsolidation of our former Jackalope operations, partially offset by a 2019 gain on sale of our equity-method investment in Jackalope.

~~Interest expense~~ ~~increased primarily due to an increase in financing obligations associated with Transco’s Atlantic Sunrise project.~~

~~The unfavorable change in~~ ~~Other income (expense) – net~~ ~~below~~ ~~Operating income (loss)~~ ~~is primarily due to a decrease in equity AFUDC associated with reduced capital expenditures on projects.~~

~~Provision (benefit) for income taxes~~ changed favorably primarily due to the absence of a $105 million 2018 valuation allowance on certain deferred tax assets that may not be realized following the WPZ merger, partially offset by higher pre-tax income attributable to The Williams Companies, Inc. See Note 7 – 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 favorable change in~~ ~~Net income (loss) attributable to noncontrolling interests~~ ~~is primarily due to our third- quarter 2018 acquisition of the publicly held interests in WPZ associated with the WPZ Merger and lower results at Gulfstar.~~June 2019.

Period-Over-Period Operating Results - Segments

We evaluate segment operating performance based upon Modified EBITDA. Note 1514 – 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,
	2020		2019		2020		2019
	(Millions)
Service revenues	$	807	$	842	$	2,431	$	2,473
Service revenues – commodity consideration	6		7		14		33
Product sales	46		76		134		226
Segment revenues	859		925		2,579		2,732

Product costs	(47)		(75)		(136)		(226)
Processing commodity expenses	(1)		(2)		(4)		(12)
Other segment costs and expenses	(233)		(227)		(670)		(733)

Proportional Modified EBITDA of equity-method investments	38		44		124		130
Transmission & Gulf of Mexico Modified EBITDA	$	616	$	665	$	1,893	$	1,891

Commodity margins	$	4	$	6	$	8	$	21

Three months ended September 30, 2020 vs. three months ended September 30, 2019

Transmission & Gulf of Mexico Modified EBITDA decreased primarily due to lower Service revenues.

Management’s Discussion and Analysis (Continued)

~~Northeast G&P~~

Three Months Ended
September 30, Nine Months Ended
September 30,
2019 2018 2019 2018
(Millions)
Service revenues $ 353
$ 247
$ 959
$ 707
Service revenues – commodity consideration
1
6
9
14
Product sales 30
69
114
242
Segment revenues 384
322
1,082
963

Product costs (29 ) (69 ) (114 ) (245 )
Processing commodity expenses (1 ) (3 ) (6 ) (7 )
Other segment costs and expenses (117 ) (100 ) (348 ) (279 )
Proportional Modified EBITDA of equity-method investments 108
131
333
354
Northeast G&P Modified EBITDA $ 345
$ 281
$ 947
$ 786

Commodity margins $ 1
$ 3
$ 3
$ 4

~~Three months ended September 30, 2019 vs. three months ended September 30, 2018~~

~~Northeast G&P Modified EBITDA~~ ~~increased primarily due to higher~~ Service revenues due to increased gathering volumes and the favorable impact of acquiring the additional interest of UEOM, which is a consolidated entity after the remaining ownership interest was purchased in March 2019.

~~Service revenues~~ ~~increased~~decreased primarily due to:

•A ~~$50~~$32 million ~~increase~~decrease due to lower deferred revenue amortization associated with the ~~consolidation~~end of ~~UEOM, as previously discussed;~~

~~A $24 million increase associated with higher gathering revenues~~the exclusive use period at ~~Susquehanna Supply Hub reflecting 18 percent higher gathering volumes due to increased production from customers;~~

~~An $18 million increase at Ohio Valley Midstream primarily due to higher gathering and processing revenues;~~

~~A $9 million increase in gathering revenues in~~Gulfstar One for the ~~Utica Shale region due to volumes from new wells and higher rates.~~

~~Product sales~~ decreased primarily due to lower non-ethane prices and volumes within our marketing activities. The changes in marketing revenues are offset by similar changes in marketing purchases, reflected above as ~~Product costs~~.

~~Other segment costs and expenses~~ ~~increased primarily due to expenses associated with the consolidation of UEOM.~~

~~Proportional Modified EBITDA of equity-method investments~~ ~~decreased primarily due to the consolidation of UEOM.~~

~~Nine months ended September 30, 2019 vs. nine months ended September 30, 2018~~

~~Northeast G&P Modified EBITDA~~ ~~increased primarily due to higher~~ ~~Service revenues~~ ~~due to increased gathering volumes and the favorable impact of acquiring the additional interest of UEOM, partially offset by 2019 severance and related costs.~~

~~Management’s Discussion and Analysis (Continued)~~

~~Service revenues~~ ~~increased primarily due to:~~

~~A $98 million increase associated with the consolidation of UEOM;~~

~~An $89 million increase associated with higher gathering revenues at Susquehanna Supply Hub reflecting 22 percent higher gathering volumes due to increased production from new wells and higher rates;~~

~~A $28 million increase in gathering revenues in the Utica Shale region due to volumes from new wells and higher rates;~~

~~A $21 million increase at Ohio Valley Midstream primarily due to higher gathering and processing volumes;~~

~~A $12 million increase in compression revenues for services charged to an affiliate driven by higher volumes.~~

~~Product sales~~ decreased primarily due to lower non-ethane volumes and prices within our marketing activities. The changes in marketing revenues are offset by similar changes in marketing purchases, reflected above as ~~Product costs~~.

~~Other segment costs and expenses~~ ~~increased due to multiple factors, including:~~Tubular Bells field;

•A ~~$35~~$12 million ~~increase associated with~~decrease due to temporary named windstorm related shut-ins;

•An $11 million decrease due to the ~~consolidation~~absence of ~~UEOM;~~

~~A $10 million increase~~a third-quarter 2019 adjustment related to ~~transaction expenses associated with the acquisition of UEOM and the formation of the Northeast JV;~~Transco’s general rate case settlement;

•A ~~$7 million accrual in 2019 for estimated severance and related costs primarily associated with our VSP;~~

A $14 million increase ~~due to~~at Gulfstar One associated with higher ~~allocated corporate costs and higher costs related to various maintenance and repairs.~~

~~Proportional Modified EBITDA of equity-method investments~~ ~~decreased $37 million as a result of~~volumes in the ~~consolidation of UEOM. This decrease was partially offset by a $20 million increase at Appalachia Midstream Investments, reflecting higher volumes.~~

~~Atlantic-Gulf~~

Three Months Ended
September 30, Nine Months Ended
September 30,
2019 2018 2019 2018
(Millions)
Service revenues $ 731
$ 607
$ 2,138
$ 1,806
Service revenues – commodity consideration
7
18
33
45
Product sales 76
131
226
329
Segment revenues 814
756
2,397
2,180

Product costs (75 ) (134 ) (226 ) (332 )
Processing commodity expenses (2 ) (3 ) (12 ) (10 )
Other segment costs and expenses (182 ) (176 ) (606 ) (556 )
Proportional Modified EBITDA of equity-method investments 44
49
130
136
Atlantic-Gulf Modified EBITDA $ 599
$ 492
$ 1,683
$ 1,418

Commodity margins $ 6
$ 12
$ 21
$ 32

~~Management’s Discussion and Analysis (Continued)~~

~~Three months ended September 30, 2019 vs. three months ended September 30, 2018~~

~~Atlantic-Gulf Modified EBITDA~~ ~~increased primarily due to higher~~ ~~Service revenues~~.

~~Service revenues~~ ~~increased~~Tubular Bells field due to a ~~$143~~new well and higher production;

•A $13 million increase in Transco’s natural gas transportation revenues ~~primarily driven by a $116 million increase related to~~associated with Transco’s expansion projects placed in service in ~~2018~~2019 and 2019, as well as an adjustment associated with Transco’s reserve for rate refunds. This increase was partially offset by $21 million lower gathering and processing fees primarily due to maintenance downtime at Gulfstar, lower volumes at our Perdido Norte system in the Western Gulf of Mexico, and the sale of certain Gulf Coast pipeline assets in the fourth quarter of 2018. Additionally, certain of Transco’s natural gas transportation revenues, which decreased due to lower rates effective October 2018, were substantially offset by higher revenue related to reimbursable power and storage expenses.2020.

The net sum of Service revenues – commodity consideration,, Product sales, Product costs, and Processing commodity expenses comprise our commodity ~~product~~ margins. ~~Our commodity product margins associated with our equity NGLs decreased $7 million driven by unfavorable NGL prices. Additionally, the~~The decrease in Product sales includes $23 million of lower system management gas sales and a ~~$44~~$6 million decrease in commodity marketing ~~sales due to lower NGL prices~~sales. System management and ~~volumes. Marketing~~marketing sales are substantially offset in Product costs and therefore have little impact to Modified EBITDA.

Other segment costs and expenses increased primarily due to ~~a $23 million unfavorable change in~~lower equity AFUDC ~~due to lower construction activity, an $11 million accrual in 2019 for estimated severance~~ and ~~related costs primarily associated with our VSP (see Note 6 – Other Income and Expenses of Notes to Consolidated Financial Statements),~~ the absence of a ~~$10 million 2018 gain on asset retirements, and higher reimbursable power and storage expenses at Transco. These unfavorable changes were partially offset by $33 million of~~third-quarter 2019 net favorable ~~changes~~adjustment to charges and credits associated with regulatory assets and liabilities ~~which were significantly~~primarily driven by the ~~previously mentioned agreement to the~~ terms of a settlement in Transco’s general rate case, partially offset by lower employee-related expenses, including the absence of third-quarter 2019 severance and related costs (see Note 6 – Other ~~Income and Expenses~~Accruals of Notes to Consolidated Financial Statements)~~, and a $21 million decrease in Transco’s contracted services compared to 2018 mainly due to the timing of required engine overhauls and integrity testing.~~.

Nine months ended September 30, ~~2019~~2020 vs. nine months ended September 30, ~~2018~~2019

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

Service revenues ~~increased~~decreased primarily due to:

•A $92 million decrease due to ~~a $361~~lower deferred revenue amortization associated with the end of the exclusive use period at Gulfstar One for the Tubular Bells field;

•A $34 million decrease due to temporary shut-ins primarily at Perdido and Gulfstar One related to named windstorms, pricing, and scheduled maintenance;

•A $40 million increase in Transco’s natural gas transportation revenues ~~primarily driven by a $335 million increase related to~~associated with Transco’s expansion projects placed in service in ~~2018~~2019 and ~~2019, as well as an adjustment~~2020;

•A $30 million increase at Gulfstar One associated with ~~Transco’s reserve for rate refunds. Partially offsetting these increases were lower gathering and processing fees of $40 million primarily~~higher volumes in the Tubular Bells field due to ~~maintenance downtime at Gulfstar~~a new well and ~~the sale of certain Gulf Coast pipeline assets~~higher production;

•A $17 million increase associated with volumes from Norphlet placed in the fourth quarter of 2018. Additionally, certain of Transco’s natural gas transportation revenues, which decreased due to lower rates effective October 2018, were substantially offset by higher revenue related to reimbursable power and storage expenses.service in June 2019.

The net sum of Service revenues – commodity consideration,, Product sales, Product costs, and Processing commodity expenses comprise our commodity ~~product~~ margins. Our commodity ~~product~~ margins associated with our equity NGLs decreased ~~$12~~$10 million primarily driven by unfavorable NGL sales prices ~~partially offset by higher~~and volumes. Additionally, the decrease in Product sales includes a ~~$74~~$42 million decrease in commodity marketing sales primarily due to lower NGL prices and ~~volumes and an $19~~$31 million ~~decrease in~~lower system management gas sales. Marketing ~~sales~~revenues and system management gas sales are substantially offset in Product costs and therefore have little impact to Modified EBITDA.

Other segment costs and expenses ~~increased~~decreased primarily ~~due a $55 million unfavorable change in equity AFUDC~~ due to lower ~~construction activity, a $30 million accrual in~~employee-related expenses, including the absence of 2019 ~~for estimated~~ severance and related costs ~~primarily~~and the associated ~~with our VSP, a $15 million increase~~reduced costs in ~~reimbursable power and storage expenses, $15 million of expense in 2019 related to the reversal of expenditures previously capitalized, and~~2020, the absence of a ~~$10 million 2018 gain on asset retirements. These unfavorable changes were partially offset by $43 million~~2019 charge

Management’s Discussion and Analysis (Continued)

for reversal of costs capitalized in previous periods, and net favorable changes to charges and credits associated with a regulatory ~~assets~~asset related to Transco’s asset retirement obligations. Additionally, expenses decreased due to lower maintenance costs primarily due to a decrease in contracted services related to general maintenance and ~~liabilities, which~~other testing at Transco, partially offset by lower equity AFUDC and higher operating taxes.

Northeast G&P


	Three Months Ended September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
	(Millions)
Service revenues	$	379	$	353	$	1,091	$	959
Service revenues – commodity consideration	2		1		5		9
Product sales	12		30		42		114
Segment revenues	393		384		1,138		1,082

Product costs	(12)		(29)		(41)		(114)
Processing commodity expenses	(1)		(1)		(3)		(6)
Other segment costs and expenses	(114)		(117)		(335)		(348)

Proportional Modified EBITDA of equity-method investments	121		108		367		333
Northeast G&P Modified EBITDA	$	387	$	345	$	1,126	$	947

Commodity margins	$	1	$	1	$	3	$	3

Three months ended September 30, 2020 vs. three months ended September 30, 2019

Northeast G&P Modified EBITDA increased primarily due to higher Service revenues and increased Proportional Modified EBITDA of equity-method investments.

Service revenues increased primarily due to:

•A $13 million increase at the Northeast JV related to higher processing, fractionation, transportation, and gathering revenues primarily associated with higher volumes;

•A $7 million increase associated with higher gathering volumes in the Utica Shale region.

Product sales decreased primarily due to lower non-ethane volumes within our marketing activities. The changes in marketing revenues are offset by similar changes in marketing purchases, reflected above as Product costs, and therefore have little impact to Modified EBITDA.

Other segment costs and expenses decreased primarily due to lower maintenance and operating expenses, as well as lower external legal costs. These decreases were ~~significantly driven~~partially offset by the ~~previously mentioned~~absence of a 2019 customer settlement.

Proportional Modified EBITDA of equity-method investments increased at Appalachia Midstream Investments and Caiman II primarily due to higher volumes, partially offset by a decrease at Laurel Mountain due to $11 million for our share of an impairment of certain assets that were subsequently sold.

Nine months ended September 30, 2020 vs. nine months ended September 30, 2019

Northeast G&P Modified EBITDA increased primarily due to higher Service revenues and increased Proportional Modified EBITDA of equity-method investments, in addition to the favorable impact of acquiring the additional interest in UEOM, which is a consolidated entity after the remaining ownership interest was purchased in March 2019, and lower Other segment costs and expenses.

Management’s Discussion and Analysis (Continued)

Service revenues increased primarily due to:

~~agreement~~•A $96 million increase at the Northeast JV, including $64 million higher processing, fractionation, transportation, and gathering revenues primarily due to ~~the terms of a settlement in Transco’s general rate case,~~higher volumes and a ~~$41~~$32 million ~~decrease~~increase associated with the consolidation of UEOM, as previously discussed;

•An $18 million increase in ~~Transco’s contracted services compared~~gathering revenues associated with higher volumes in the Utica Shale region;

•A $13 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.

Product sales decreased primarily due to ~~2018 mainly~~lower NGL prices and lower non-ethane volumes within our marketing activities. The changes in marketing revenues are offset by similar changes in marketing purchases, reflected above as Product costs, and therefore have little impact to Modified EBITDA.

Other segment costs and expenses decreased due to lower maintenance and repair expenses and operating expenses primarily due to the timing and scope of ~~required engine overhauls~~activities. Additionally, Other segment costs and ~~integrity testing.~~expenses decreased due to lower employee-related expenses, including the absence of second-quarter 2019 severance and related costs (see Note 6 – Other Accruals of Notes to Consolidated Financial Statements) and the associated reduced costs in 2020, and the absence of transaction costs associated with our 2019 acquisition of UEOM and the formation of the Northeast JV. These decreases were partially offset by higher reimbursable electricity expenses, increased expenses associated with the consolidation of UEOM, and the absence of a 2019 customer settlement.

Proportional Modified EBITDA of equity-method investments increased at Appalachia Midstream Investments driven by higher volumes and at Caiman II driven by higher volumes and a gain on early debt retirement. These increases were partially offset by a $16 million decrease as a result of the consolidation of UEOM, as previously discussed, as well as a decrease at Laurel Mountain due to $11 million for our share of an impairment of certain assets that subsequently sold.

West


	Three Months Ended September 30,						Nine Months Ended September 30,							Three Months Ended September 30,				Nine Months Ended September 30,
	2019			2018			2019			2018				2020		2019		2020		2019
	(Millions)													(Millions)
Service revenues	$	433		$	533		$	1,384		$	1,599		Service revenues	$	311	$	322	$	938	$	1,049
Service revenues – commodity consideration	30			97			116			257			Service revenues – commodity consideration	32		30		74		116
Product sales	389			732			1,302			1,822			Product sales	391		389		1,053		1,302
Segment revenues	852			1,362			2,802			3,678			Segment revenues	734		741		2,065		2,467

Product costs	(382		)	(730		)	(1,294		)	(1,813		)	Product costs	(377)		(382)		(1,026)		(1,294)
Processing commodity expenses	(13		)	(26		)	(63		)	(76		)	Processing commodity expenses	(18)		(13)		(41)		(63)
Other segment costs and expenses	(175		)	(219		)	(531		)	(637		)	Other segment costs and expenses	(122)		(130)		(365)		(404)
Impairment of certain assets	—			—			(76		)	—			Impairment of certain assets	—		—		—		(76)
Proportional Modified EBITDA of equity-method investments	29			25			83			62			Proportional Modified EBITDA of equity-method investments	30		29		82		83
West Modified EBITDA	$	311		$	412		$	921		$	1,214		West Modified EBITDA	$	247	$	245	$	715	$	713

Commodity margins	$	24		$	73		$	61		$	190		Commodity margins	$	28	$	24	$	60	$	61

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

Management’s Discussion and Analysis (Continued)

Service revenuesdecreased primarily due to:

•A $29 million decrease associated with lower volumes, excluding the Eagle Ford Shale region;

•$14 million associated with various other decreases;

•A $21 million increase in the Eagle Ford Shale region due to higher MVC revenue and higher rates, partially offset by lower volumes primarily due to decreased producer activity;

•An $11 million increase associated with a temporary volume deficiency fee from a customer.

The net sum of Service revenues – commodity consideration, Product sales, Product costs, and Processing commodity expenses comprise our commodity margins, which we further segregate into product margins associated with our equity NGLs and marketing margins. Marketing margins increased by $9 million primarily due to favorable changes in net commodity prices. Additionally, product margins from our equity NGLs decreased $5 million.

Other segment costs and expenses decreased primarily due to lower operating costs primarily due to fewer leased compressors, lower maintenance costs primarily due to timing and scope of activities, and lower employee-related expenses in 2020.

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

West Modified EBITDA increased primarily due to the absence of ~~EBITDA~~ Impairment of certain ~~of our former sold or deconsolidated~~ assets ~~lower service revenues associated with the expiration of a certain MVC,~~ and lower ~~commodity margins due to unfavorable commodity prices related to our ongoing operations.~~Other segment costs and expenses, partially offset by lower Service revenues.

Service revenues decreased primarily due to:

•A $62 million decrease associated with asset divestitures and deconsolidations during 2018, including our former Four Corners area assets and certain Delaware basin assets that were contributed to our Brazos Permian II equity-method investment;

•A ~~$23~~$65 million decrease associated with lower volumes, excluding the Eagle Ford Shale region;

•A $41 million decrease associated with lower rates, ~~primarily~~excluding the Eagle Ford Shale region, driven by lower commodity pricing in the ~~Piceance and~~ Barnett Shale ~~regions~~region and the ~~transition from~~expiration of a cost-of-service ~~to fixed-fee rate for~~period on a ~~certain customer~~ contract in the Mid-Continent ~~region.~~region;

~~These decreases were~~•An $11 million decrease associated with lower fractionation fees driven by lower volumes;

•An $11 million decrease driven by the absence of a favorable 2019 cost-of-service agreement adjustment in the Mid-Continent region;

•A $72 million increase in the Eagle Ford Shale region due to higher MVC revenue and higher rates, partially offset by ~~a $17~~lower volumes primarily due to decreased producer activity, including shut-ins on certain gathering systems;

•A $20 million increase associated with ~~higher other MVC~~a temporary volume deficiency fee ~~revenues, higher volumes, and higher other fee revenues.~~from a customer.

The net sum of Service revenues – commodity consideration,, Product sales, Product costs, and Processing commodity expenses comprise our commodity ~~product margins. Our commodity~~margins, which we further segregate into product margins associated with our equity NGLs and marketing margins. Product margins from our equity NGLs decreased ~~$44~~$22 million primarily due to:

•A $35 million decrease associated with lower sales volumes primarily due to $21 million associated with the absence of our former Four Corners area assets and $14 million related to 70 percent lower ethane sales volumes due to ethane rejection;

Management’s Discussion and Analysis (Continued)

•A $21 million increase related to a ~~decrease~~decline in natural gas purchases associated with ~~lower~~ equity NGL production ~~volumes and~~due to lower natural gas ~~prices.~~prices and lower equity non-ethane production volumes.

Additionally, ~~the~~marketing margins increased by $21 million primarily due to favorable changes in net commodity prices. The decrease in Product sales includes a ~~$263~~$194 million decrease in marketing sales, which is due to lower sales prices, partially offset by higher marketing sales ~~volumes, a $14 million decrease related to the sale of other products, and a $7 million decrease in system management gas sales.~~volumes. These decreases are substantially offset in Product costs.~~Marketing margins decreased by $12 million primarily due to unfavorable changes in pricing.~~

~~Other segment costs and expenses~~ decreased primarily due a $37 million reduction associated with the absence of our former Four Corners area assets and the absence of a 2018 unfavorable charge of $12 million for a regulatory liability associated with a decrease in Northwest Pipeline’s estimated deferred state income tax rate following the WPZ Merger.

~~Proportional Modified EBITDA of equity-method investments~~ increased primarily due to the addition of the RMM equity-method investment during the third quarter of 2018, partially offset by the absence of the Jackalope equity-method investment sold in April 2019.

~~Nine months ended September 30, 2019 vs. Nine months ended September 30, 2018~~

~~West Modified EBITDA~~ decreased primarily due to the absence of EBITDA of certain of our former sold or deconsolidated assets, 2019 impairments of certain assets, lower commodity margins due to unfavorable commodity prices and lower volumes associated with equity NGL production related to our ongoing operations, and lower service revenues associated with the expiration of a certain MVC.

~~Service revenues~~ ~~decreased primarily due to:~~

~~The net sum of~~ ~~Service revenues~~ – ~~commodity consideration, Product sales, Product costs,~~ ~~and~~ ~~Processing commodity expenses~~ ~~comprise our commodity product margins. Our commodity product margins associated with our equity NGLs decreased $114 million primarily due to:~~

~~Management’s Discussion and Analysis (Continued)~~

~~Additionally, the decrease in~~ ~~Product sales~~ includes a $332 million decrease in marketing sales, which is due to lower sales prices, partially offset by higher sales volumes, a $31 million decrease related to the sale of other products, and a $26 million decrease in system management gas sales. These decreases are substantially offset in ~~Product costs.~~ ~~Marketing margins decreased by $15 million primarily due to unfavorable changes in pricing.~~

Other segment costs and expenses decreased primarily due to ~~a $124 million reduction associated with the absences of our former Four Corners area assets and from the Jackalope deconsolidation in second-quarter 2018, as well as~~lower employee-related expenses driven by the absence of a 2018 unfavorable charge of $12 million for a regulatory liability associated with a decrease in Northwest Pipeline’s estimated deferred state income tax rate following the WPZ Merger as previously discussed. These decreases were partially offset by an unfavorable accrual insecond-quarter 2019 ~~for estimated~~ severance and related costs ~~of $16 million primarily~~and the associated ~~with our VSP~~reduced costs in 2020 (see Note 6 – Other ~~Income and Expenses~~Accruals of Notes to Consolidated Financial Statements), as well as lower operating costs due to fewer leased compressors and ~~the absence~~lower maintenance costs primarily due to timing and scope of ~~a $7 million favorable adjustment to the regulatory liability associated with Tax Reform at Northwest Pipeline in first-quarter 2018.~~activities.

Impairment of certain assets ~~increased~~decreased primarily due to the absence of a $59 million impairment of certain Eagle Ford Shale gathering assets and a $12 million impairment of certain idle gathering assets in 2019 (see Note 1312 – Fair Value Measurements and Guarantees of Notes to the Consolidated Financial Statements).

Proportional Modified EBITDA of equity-method investments ~~increased~~decreased primarily due to lower volumes at OPPL and the ~~additions~~absence of the Jackalope equity-method investment sold in April 2019, partially offset by growth at the RMM and the Brazos Permian II equity-method ~~investments in the second half of 2018.~~investments.

Three Months Ended September 30, Nine Months Ended September 30,
2019 2018 2019 2018
(Millions)
Other Modified EBITDA $ (2 ) $ 6
$ 1
$ (49 )


	Three Months Ended September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
	(Millions)
Other Modified EBITDA	$	(7)	$	(2)	$	8	$	1

Three months ended September 30, ~~2019~~2020 vs. three months ended September 30, ~~2018~~2019

Other Modified EBITDA ~~decreased~~includes:

•A third-quarter 2020 charge of $8 million for the write-off of a regulatory asset associated with a cancelled project;

•The absence of a third-quarter 2019 $9 million accrual for loss contingencies associated with former operations.

Nine months ended September 30, 2020 vs. nine months ended September 30, 2019

Other Modified EBITDA increased primarily due to:

•The absence of a ~~$37~~first-quarter 2019 $12 million ~~benefit from establishing~~unfavorable adjustment to a regulatory asset associated with an increase in Transco’s estimated deferred state income tax rate following the ~~WPZ Merger in~~merger transaction wherein we acquired all of the ~~third quarter~~outstanding common units held by others of ~~2018;~~our former publicly traded master limited partnership;

~~A $16 million decrease in income associated with a regulatory asset related to deferred taxes on equity funds used during construction;~~

~~These decreases were partially offset by:~~



Delaware		73-0569878
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

One Williams Center
Tulsa	Oklahoma	74172-0172
(Address of principal executive offices)		(Zip Code)


~~Class~~		~~Shares Outstanding at October 28, 2019~~
~~Common Stock, $1.00 par value~~	~~1,212,048,836~~


	The Williams Companies, Inc. Stockholders
	Preferred Stock		Common Stock		Capital in Excess of Par Value		Retained Deficit		AOCI*		Treasury Stock		Total Stockholders’ Equity		Noncontrolling Interests		Total Equity
	(Millions)
Balance – December 31, 2019	$	35	$	1,247	$	24,323	$	(11,002)	$	(199)	$	(1,041)	$	13,363	$	3,001	$	16,364
Net income (loss)	0		0		0		95		0		0		95		(27)		68
Other comprehensive income (loss)	0		0		0		0		39		0		39		0		39
Cash dividends – common stock ($1.20 per share)	0		0		0		(1,456)		0		0		(1,456)		0		(1,456)
Dividends and distributions to noncontrolling interests	0		—		0		0		0		0		0		(147)		(147)
Stock-based compensation and related common stock issuances, net of tax	0		1		36		0		0		0		37		0		37


Contributions from noncontrolling interests	0		0		0		0		0		0		0		5		5
Other	0		0		0		(13)		0		0		(13)		1		(12)
Net increase (decrease) in equity	0		1		36		(1,374)		39		0		(1,298)		(168)		(1,466)
Balance – September 30, 2020	$	35	$	1,248	$	24,359	$	(12,376)	$	(160)	$	(1,041)	$	12,065	$	2,833	$	14,898



☑			QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934



☐			TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934



	September 30, 2019			December 31, 2018
	(Millions, except per-share amounts)
ASSETS
Current assets:
Cash and cash equivalents	$	247		$	168
Trade accounts and other receivables (net of allowance of $6 at September 30, 2019 and $9 at December 31, 2018)	875			992
Inventories	129			130
Other current assets and deferred charges	183			174
Total current assets	1,434			1,464
Investments	6,228			7,821
Property, plant, and equipment	41,647			38,661
Accumulated depreciation and amortization	(12,034		)	(11,157		)
Property, plant, and equipment – net	29,613			27,504
Intangible assets – net of accumulated amortization	8,041			7,767
Regulatory assets, deferred charges, and other	965			746
Total assets	$	46,281		$	45,302
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	602		$	662
Accrued liabilities	1,184			1,102
Long-term debt due within one year	1,538			47
Total current liabilities	3,324			1,811
Long-term debt	20,719			22,367
Deferred income tax liabilities	1,651			1,524
Regulatory liabilities, deferred income, and other	3,728			3,603
Contingent liabilities (Note 14)
Equity:
Stockholders’ equity:
Preferred stock	35			35
Common stock ($1 par value; 1,470 million shares authorized at September 30, 2019 and December 31, 2018; 1,247 million shares issued at September 30, 2019 and 1,245 million shares issued at December 31, 2018)	1,247			1,245
Capital in excess of par value	24,310			24,693
Retained deficit	(10,664		)	(10,002		)
Accumulated other comprehensive income (loss)	(266		)	(270		)
Treasury stock, at cost (35 million shares of common stock)	(1,041		)	(1,041		)
Total stockholders’ equity	13,621			14,660
Noncontrolling interests in consolidated subsidiaries	3,238			1,337
Total equity	16,859			15,997
Total liabilities and equity	$	46,281		$	45,302


	The Williams Companies, Inc. Stockholders
	Preferred Stock		Common Stock		Capital in Excess of Par Value		Retained Deficit		AOCI*		Treasury Stock		Total Stockholders’ Equity		Noncontrolling Interests		Total Equity
	(Millions)
Balance – June 30, 2020	$	35	$	1,248	$	24,343	$	(12,197)	$	(176)	$	(1,041)	$	12,212	$	2,868	$	15,080
Net income (loss)	0		0		0		309		0		0		309		14		323
Other comprehensive income (loss)	0		0		0		0		16		0		16		0		16
Cash dividends – common stock ($0.40 per share)	0		0		0		(485)		0		0		(485)		0		(485)
Dividends and distributions to noncontrolling interests	0		0		0		0		0		0		0		(49)		(49)
Stock-based compensation and related common stock issuances, net of tax	0		0		16		0		0		0		16		0		16


Contributions from noncontrolling interests	0		0		0		0		0		0		0		1		1
Other	0		0		0		(3)		0		0		(3)		(1)		(4)
Net increase (decrease) in equity	0		0		16		(179)		16		0		(147)		(35)		(182)
Balance – September 30, 2020	$	35	$	1,248	$	24,359	$	(12,376)	$	(160)	$	(1,041)	$	12,065	$	2,833	$	14,898



Balance – June 30, 2018	$	—	$	862	$	18,552		$	(8,735	)	$	(293	)	$	(1,041	)	$	9,345		$	6,102		$	15,447
Net income (loss)	—		—		—			129			—			—			129			71			200
Other comprehensive income (loss)	—		—		—			—			5			—			5			1			6
WPZ Merger (Note 1)	—		382		6,112			—			(3		)	—			6,491			(4,629		)	1,862
Issuance of preferred stock (Note 12)	35		—		—			—			—			—			35			—			35
Cash dividends – common stock ($0.34 per share)	—		—		—			(411		)	—			—			(411		)	—			(411		)
Dividends and distributions to noncontrolling interests	—		—		—			—			—			—			—			(196		)	(196		)
Stock-based compensation and related common stock issuances, net of tax	—		—		16			—			—			—			16			—			16
Changes in ownership of consolidated subsidiaries, net	—		—		1			—			—			—			1			(1		)	—
Contributions from noncontrolling interests	—		—		—			—			—			—			—			2			2
Other	—		1		(1		)	(1		)	—			—			(1		)	(1		)	(2		)
Net increase (decrease) in equity	35		383		6,128			(283		)	2			—			6,265			(4,753		)	1,512
Balance – September 30, 2018	$	35	$	1,245	$	24,680		$	(9,018	)	$	(291	)	$	(1,041	)	$	15,610		$	1,349		$	16,959



Balance – December 31, 2017	$	—	$	861	$	18,508		$	(8,434	)	$	(238	)	$	(1,041	)	$	9,656		$	6,519		$	16,175
Adoption of new accounting standards	—		—		—			(23		)	(61		)	—			(84		)	(37		)	(121		)
Net income (loss)	—		—		—			416			—			—			416			323			739
Other comprehensive income (loss)	—		—		—			—			11			—			11			(2		)	9
WPZ Merger (Note 1)	—		382		6,112			—			(3		)	—			6,491			(4,629		)	1,862
Issuance of preferred stock (Note 12)	35		—		—			—			—			—			35			—			35
Cash dividends – common stock ($1.02 per share)	—		—		—			(974		)	—			—			(974		)	—			(974		)
Dividends and distributions to noncontrolling interests	—		—		—			—			—			—			—			(598		)	(598		)
Stock-based compensation and related common stock issuances, net of tax	—		1		48			—			—			—			49			—			49
Sales of limited partner units of Williams Partners L.P.	—		—		—			—			—			—			—			46			46
Changes in ownership of consolidated subsidiaries, net	—		—		14			—			—			—			14			(18		)	(4		)
Contributions from noncontrolling interests	—		—		—			—			—			—			—			13			13
Deconsolidation of subsidiary (Note 5)	—		—		—			—			—			—			—			(267		)	(267		)
Other	—		1		(2		)	(3		)	—			—			(4		)	(1		)	(5		)
Net increase (decrease) in equity	35		384		6,172			(584		)	(53		)	—			5,954			(5,170		)	784
Balance – September 30, 2018	$	35	$	1,245	$	24,680		$	(9,018	)	$	(291	)	$	(1,041	)	$	15,610		$	1,349		$	16,959



	(Millions)
Current assets, including $13 million cash acquired	$	55
Property, plant, and equipment	1,387
Other intangible assets	328
Total identifiable assets acquired	1,770

Current liabilities	7
Total liabilities assumed	7

Net identifiable assets acquired	1,763

Goodwill	188
Net assets acquired	$	1,951



	September 30, 2019		December 31, 2018
	(Millions)
Accounts receivable related to revenues from contracts with customers	$	791	$	858
Other accounts receivable	84		134
Total reflected in Trade accounts and other receivables	$	875	$	992



	Other Postretirement Benefits
	Three Months Ended September 30,						Nine Months Ended September 30,
	2019			2018			2019			2018
	(Millions)
Components of net periodic benefit cost (credit):
Service cost	$	1		$	1		$	1		$	1
Interest cost	2			1			6			5
Expected return on plan assets	(3		)	(2		)	(8		)	(8		)
Amortization of prior service credit	—			—			—			(1		)
Reclassification to regulatory liability	—			—			1			1
Net periodic benefit cost (credit)	$	—		$	—		$	—		$	(2	)



	(Millions)
2019 (remainder)	$	8
2020	32
2021	33
2022	27
2023	21
Thereafter	171
Total future lease payments	292
Less amount representing interest	79
Total obligations under operating leases	$	213



(Exact name of registrant as specified in its charter)


~~(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.



	Cash Flow Hedges			Foreign Currency Translation			Pension and Other Postretirement Benefits			Total
	(Millions)
Balance at December 31, 2018	$	(2	)	$	(1	)	$	(267	)	$	(270	)
Other comprehensive income (loss) before reclassifications	—			—			(5		)	(5		)
Amounts reclassified from accumulated other comprehensive income (loss)	—			—			9			9
Other comprehensive income (loss)	—			—			4			4
Balance at September 30, 2019	$	(2	)	$	(1	)	$	(263	)	$	(266	)



Component	Reclassifications			Classification
	(Millions)
Pension and other postretirement benefits:
Amortization of actuarial (gain) loss and net actuarial loss from settlements included in net periodic benefit cost (credit)	$	12		Note 9 – Employee Benefit Plans
Income tax benefit	(3		)	Provision (benefit) for income taxes
Reclassifications during the period	$	9



	Northeast G&P		Atlantic-Gulf		West		Other		Eliminations			Total
	(Millions)
Three Months Ended September 30, 2019
Segment revenues:
Service revenues
External	$	340	$	718	$	433	$	4	$	—		$	1,495
Internal	13		13		—		3		(29		)	—
Total service revenues	353		731		433		7		(29		)	1,495
Total service revenues – commodity consideration	1		7		30		—		—			38
Product sales
External	22		66		378		—		—			466
Internal	8		10		11		—		(29		)	—
Total product sales	30		76		389		—		(29		)	466
Total revenues	$	384	$	814	$	852	$	7	$	(58	)	$	1,999

Three Months Ended September 30, 2018
Segment revenues:
Service revenues
External	$	236	$	595	$	533	$	7	$	—		$	1,371
Internal	11		12		—		3		(26		)	—
Total service revenues	247		607		533		10		(26		)	1,371
Total service revenues – commodity consideration	6		18		97		—		—			121
Product sales
External	59		46		706		—		—			811
Internal	10		85		26		—		(121		)	—
Total product sales	69		131		732		—		(121		)	811
Total revenues	$	322	$	756	$	1,362	$	10	$	(147	)	$	2,303

Nine Months Ended September 30, 2019
Segment revenues:
Service revenues
External	$	925	$	2,102	$	1,384	$	13	$	—		$	4,424
Internal	34		36		—		9		(79		)	—
Total service revenues	959		2,138		1,384		22		(79		)	4,424
Total service revenues – commodity consideration	9		33		116		—		—			158
Product sales
External	87		169		1,256		—		—			1,512
Internal	27		57		46		—		(130		)	—
Total product sales	114		226		1,302		—		(130		)	1,512
Total revenues	$	1,082	$	2,397	$	2,802	$	22	$	(209	)	$	6,094



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
		~~Contributions from noncontrolling interests~~
Uses:
~~Uses:~~
	Working capital requirements
		Capital and investment expenditures
		Quarterly dividends to our shareholders
		Debt service payments, including payments of long-term debt
		Distributions to noncontrolling interests



Available Liquidity	September 30, 2019
	(Millions)
Cash and cash equivalents	$	247
Capacity available under our $4.5 billion credit facility, less amounts outstanding under our $4 billion commercial paper program (1)	4,500
	$	4,747


	Cash Flow	Nine Months Ended September 30,							Cash Flow	Nine Months Ended September 30,
	Category	2019			2018				Category	2020		2019
		(Millions)								(Millions)
Sources of cash and cash equivalents:								Sources of cash and cash equivalents:
Operating activities – net	Operating	$	2,702		$	2,331		Operating activities – net	Operating	$	2,382	$	2,702
Proceeds from long-term debt								Proceeds from long-term debt	Financing	2,198		36
Proceeds from credit-facility borrowings								Proceeds from credit-facility borrowings	Financing	1,700		700
Proceeds from commercial paper – net								Proceeds from commercial paper – net	Financing	40		—
Proceeds from sale of partial interest in consolidated subsidiary (see Note 2)	Financing	1,330			—			Proceeds from sale of partial interest in consolidated subsidiary (see Note 2)	Financing	—		1,330
Proceeds from credit-facility borrowings	Financing	700			1,680
Proceeds from dispositions of equity-method investments (see Note 5)	Investing	485			—			Proceeds from dispositions of equity-method investments (see Note 5)	Investing	—		485
Proceeds from long-term debt	Financing	36			2,065
Contributions in aid of construction	Investing	25			395
Proceeds from commercial paper – net	Financing	—			821

Uses of cash and cash equivalents:								Uses of cash and cash equivalents:
Payments of long-term debt								Payments of long-term debt	Financing	(2,136)		(44)
Payments on credit-facility borrowings								Payments on credit-facility borrowings	Financing	(1,700)		(860)
Common dividends paid								Common dividends paid	Financing	(1,456)		(1,382)
Capital expenditures	Investing	(1,705		)	(2,659		)	Capital expenditures	Investing	(938)		(1,705)
Common dividends paid	Financing	(1,382		)	(974		)
Payments on credit-facility borrowings	Financing	(860		)	(1,950		)
Purchases of businesses, net of cash acquired (see Note 2)	Investing	(728		)	—
Purchases of and contributions to equity-method investments	Investing	(361		)	(803		)	Purchases of and contributions to equity-method investments	Investing	(150)		(361)
Dividends and distributions paid to noncontrolling interests	Financing	(86		)	(552		)	Dividends and distributions paid to noncontrolling interests	Financing	(147)		(86)
Payments of long-term debt	Financing	(44		)	(1,251		)
Purchases of businesses, net of cash acquired (see Note 2)								Purchases of businesses, net of cash acquired (see Note 2)	Investing	—		(728)
Payments of commercial paper – net	Financing	(4		)	—			Payments of commercial paper – net	Financing	—		(4)

Other sources / (uses) – net	Financing and Investing	(29		)	40			Other sources / (uses) – net	Financing and Investing	(12)		(4)
Increase (decrease) in cash and cash equivalents		$	79		$	(857	)	Increase (decrease) in cash and cash equivalents		$	(219)	$	79


Exhibit No.				Description

~~Exhibit~~ ~~No.~~ 2.1			—	~~Description~~

~~2.1+~~	—	Agreement and Plan of Merger dated as of May 16, 2018, by and among The Williams Companies, Inc., SCMS LLC, Williams Partners L.P., and WPZ GP LLC (filed on May 17, 2018 as Exhibit 2.1 to The Williams Companies, Inc.’s current report on Form 8-K (File No. 001-04174) and incorporated herein by reference).
2.2			—	Amendment No 1. to Agreement and Plan of Merger dated as of May 1, 2016, by and among The Williams Companies, Inc., Energy Transfer Corp LP, Energy Transfer Corp GP, LLC, Energy Transfer Equity, L.P., LE GP, LLC , and Energy Transfer Equity GP, LLC (filed on May 3, 2016 as Exhibit 2.1 to The Williams Companies, Inc.’s current report on Form 8-K (File No. 001-04174) and incorporated herein by reference).
~~2.3+~~2.3			—	Agreement and Plan of Merger dated as of September 28, 2015, by and among The Williams Companies, Inc., Energy Transfer Corp LP, Energy Transfer Corp GP, LLC, Energy Transfer Equity, L.P., LE GP, LLC , and Energy Transfer Equity GP, LLC (filed on October 1, 2015 as Exhibit 2.1 to The Williams Companies, Inc.’s current report on Form 8-K (File No. 001-04174) and incorporated herein by reference).
3.1			—	Amended and Restated Certificate of Incorporation as supplemented (filed on May 26, 2010, as Exhibit 3.1 to The Williams Companies, Inc.’s current report on Form 8-K (File No. 001-04174) and incorporated herein by reference).
3.2			—	Certificate of Designations of Series B Preferred Stock of The Williams Companies, Inc. (filed on July 17, 2018 as Exhibit 3.1 to The Williams Companies, Inc.’s current report on Form 8-K (File No. 001-04174) and incorporated herein by reference).
3.3			—	Certificate of Amendment dated August 10, 2018 (filed on August 10, 2018 as Exhibit 3.1 to The Williams Companies, Inc.’s current report on Form 8-K (File No. 001-04174) and incorporated herein by reference).
3.4			—	By-Laws (filed on January 20, 2017 as Exhibit 3.1 to The Williams Companies, Inc.’s current report on Form 8-K (File No. 001-04174) and incorporated herein by reference).
31.1*3.5			—	Certificate of Designations of Series C Participating Preferred Stock of The Williams Companies, Inc. (filed on March 20, 2020 as Exhibit 3.1 to The Williams Companies, Inc.’s current report on Form 8‑K (File No. 001-04174) and incorporated herein by reference).
31.1*			—	Certification of Chief Executive Officer pursuant to Rules 13a-14(a) and 15d-14(a) promulgated under the Securities Exchange Act of 1934, as amended, and Item 601(b)(31) of Regulation ~~S-K,~~S‑K, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*			—	Certification of Chief Financial Officer pursuant to Rules 13a-14(a) and 15d-14(a) promulgated under the Securities Exchange Act of 1934, as amended, and Item 601(b)(31) of Regulation S-K, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32**			—	Certification of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
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§	~~Management contract or compensatory plan or arrangement.~~


+	~~Pursuant to item 601(b)(2) of Regulation S-K, the registrant agrees to furnish supplementally a copy of any omitted exhibit or schedule to the SEC upon request.~~



			THE WILLIAMS COMPANIES, INC.
			(Registrant)

			/s/ TJohn D. PorterED ~~T. TIMMERMANS~~
			~~Ted T. Timmermans~~John D. Porter
			Vice President, Controller, and Chief Accounting Officer (Duly Authorized Officer and Principal Accounting Officer)