UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549
FORM 10-Q
(Mark One)
☑QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended March 31, 20202021
or
☐TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from _____________ to _____________
Commission file number 1-4174
1-4174

THE WILLIAMS COMPANIES, INC.
(Exact name of registrant as specified in its charter)
Delaware73-0569878
(State or other jurisdiction of incorporation or organization)(I.R.S. Employer Identification No.)
One Williams Center
TulsaOklahoma74172-0172
    (Address of principal executive offices)(Zip Code)
Registrant’s telephone number, including area code: (918) (918) 573-2000
NO CHANGE
(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 classTrading Symbol(s)Name of each exchange on which registered
Common Stock, $1.00 par valueWMBNew 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.
ClassShares Outstanding at April 29, 2021
Common Stock, $1.00 par value1,214,762,352
ClassShares Outstanding at April 30, 2020
Common Stock, $1.00 par value1,213,196,974





The Williams Companies, Inc.
Index


Page
Item 1. Financial Statements
Consolidated Statement of Operations – Three Months Ended March 31, 20202021 and 20192020
6
Consolidated Statement of Comprehensive Income (Loss) – Three Months Ended March 31, 20202021 and 20192020
7
Consolidated Balance Sheet – March 31, 20202021 and December 31, 20192020
8
Consolidated Statement of Changes in Equity – Three Months Ended March 31, 2021 and2020 and 2019
9
Consolidated Statement of Cash Flows – Three Months Ended March 31, 20202021 and 20192020
10
Notes to Consolidated Financial Statements
11
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
3130
Item 3. Quantitative and Qualitative Disclosures About Market Risk
4742
Item 4. Controls and Procedures
4742
4742
Item 1. Legal Proceedings
4742
Item 1A. Risk Factors
4843
Item 5. Other Information
43
Item 6. Exhibits
5045

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, outcomeoutcomes 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;
1

•Financial condition and liquidity;

•Business strategy;

•Cash flow from operations or results of operations;

•Seasonality of certain business components;

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

•Demand for our 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:

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

•Development and rate of adoption of alternative energy sources;

•The impact of existing and future laws and regulations, the regulatory environment, environmental liabilities,matters, 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 counterparties;

•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;

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

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

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

•The risks resulting from outbreaks or other public health crises, including the novel coronavirus (COVID-19);COVID-19;

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

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

•Our costs and funding obligations for defined benefit pension plans and other postretirement benefit plans;
2

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

•Inflation, interest rates, and general economic conditions (including future disruptions and volatility in the global credit markets and the impact of these events on customers and 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 ability of the members of the Organization of Petroleum Exporting Countries (OPEC) and 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;

•Changes in U.S. governmental administration and policies;
•Whether we are able to pay current and expected levels of dividends;

•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, 2019,2020, as filed with the SEC on February 24, 2020, as supplemented by the disclosure in Part II, Item 1A. Risk Factors in this Quarterly Report on Form 10-Q.

2021.

3

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
Mbbls/d: One thousand barrels per day
Bcf: One billion cubic feet of natural gas
Bcf/d: One billion cubic feet of natural gas per day
MMcf/d: One million cubic feet per day
British Thermal Unit (Btu): A unit of energy needed to raise the temperature of one pound of water by one degree Fahrenheit
Tbtu: One trillion British thermal units
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:
Caiman II: Caiman Energy II, LLC, (renamed Blue Racer Midstream Holdings, LLC, effective February 2, 2021) a former equity-method investment which is a consolidated entity following our November 2020 acquisition of an additional ownership interest
Cardinal: Cardinal Gas Services, L.L.C.
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

Partially Owned Entities: Entities in which we do not own a 100 percent ownership interest and which, as of March 31, 2020,2021, 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:Blue Racer: Caiman Energy II,Blue Racer Midstream 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
Targa Train 7: Targa Train 7 LLC
4

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:
EBITDA: Earnings before interest, taxes, depreciation, and amortization
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 commitmentcommitments
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



5

PART I – FINANCIAL INFORMATION

Item 1. Financial Statements

The Williams Companies, Inc.
Consolidated Statement of Operations
(Unaudited)
Three Months Ended 
March 31,
20212020
(Millions, except per-share amounts)
Revenues:
Service revenues$1,452 $1,474 
Service revenues – commodity consideration49 28 
Product sales1,111 411 
Total revenues2,612 1,913 
Costs and expenses:
Product costs932 396 
Processing commodity expenses21 13 
Operating and maintenance expenses360 337 
Depreciation and amortization expenses438 429 
Selling, general, and administrative expenses123 113 
Impairment of goodwill (Note 10)0 187 
Other (income) expense – net(1)7 
Total costs and expenses1,873 1,482 
Operating income (loss)739 431 
Equity earnings (losses) (Note 4)131 22 
Impairment of equity-method investments (Note 10)0 (938)
Other investing income (loss) – net2 3 
Interest incurred(296)(301)
Interest capitalized2 5 
Other income (expense) – net(2)4 
Income (loss) before income taxes576 (774)
Less: Provision (benefit) for income taxes141 (204)
Net income (loss)435 (570)
Less: Net income (loss) attributable to noncontrolling interests9 (53)
Net income (loss) attributable to The Williams Companies, Inc.426 (517)
Less: Preferred stock dividends1 1 
Net income (loss) available to common stockholders$425 $(518)
Basic earnings (loss) per common share:
Net income (loss)$.35 $(.43)
Weighted-average shares (thousands)1,214,646 1,213,019 
Diluted earnings (loss) per common share:
Net income (loss)$.35 $(.43)
Weighted-average shares (thousands)1,217,211 1,213,019 
 Three Months Ended 
March 31,
 2020 2019
 (Millions, except per-share amounts)
Revenues:   
Service revenues$1,474

$1,440
Service revenues – commodity consideration28
 64
Product sales411

550
Total revenues1,913

2,054
Costs and expenses:


Product costs396

525
Processing commodity expenses13

40
Operating and maintenance expenses337

340
Depreciation and amortization expenses429

416
Selling, general, and administrative expenses113

128
Impairment of goodwill (Note 11)187

—
Other (income) expense – net7

44
Total costs and expenses1,482

1,493
Operating income (loss)431

561
Equity earnings (losses) (Note 5)22

80
Impairment of equity-method investments (Note 11)(938) (74)
Other investing income (loss) – net3

1
Interest incurred(301)
(306)
Interest capitalized5

10
Other income (expense) – net4

11
Income (loss) before income taxes(774)
283
Provision (benefit) for income taxes(204)
69
Net income (loss)(570)
214
Less: Net income (loss) attributable to noncontrolling interests(53)
19
Net income (loss) attributable to The Williams Companies, Inc.(517)
195
Preferred stock dividends1
 1
Net income (loss) available to common stockholders$(518) $194
Basic earnings (loss) per common share:   
Net income (loss)$(.43) $.16
Weighted-average shares (thousands)1,213,019
 1,211,489
Diluted earnings (loss) per common share:   
Net income (loss)$(.43) $.16
Weighted-average shares (thousands)1,213,019
 1,213,592

See accompanying notes.

6

The Williams Companies, Inc.
Consolidated Statement of Comprehensive Income (Loss)
(Unaudited)

Three Months Ended 
March 31,		Three Months Ended 
March 31,
2020 201920212020
(Millions)(Millions)
Net income (loss)$(570) $214
Net income (loss)$435 $(570)
Other comprehensive income (loss):   Other comprehensive income (loss):
Cash flow hedging activities:Cash flow hedging activities:
Net unrealized gain (loss) from derivative instruments, net of taxes of $2 in 2021 and $0 in 2020Net unrealized gain (loss) from derivative instruments, net of taxes of $2 in 2021 and $0 in 2020(9)0 
Reclassifications into earnings of net derivative instruments (gain) loss, net of taxes of $0 in 2021 and $0 in 2020Reclassifications into earnings of net derivative instruments (gain) loss, net of taxes of $0 in 2021 and $0 in 20202 0 
Pension and other postretirement benefits:   Pension and other postretirement benefits:
Net actuarial gain (loss) arising during the year, net of taxes of $4 in 2020(14) —
Amortization of actuarial (gain) loss and net actuarial loss from settlements included in net periodic benefit cost (credit), net of taxes of ($2) in 2020 and ($1) in 20198
 3
Net actuarial gain (loss) arising during the year, net of taxes of $0 in 2021 and $4 in 2020Net actuarial gain (loss) arising during the year, net of taxes of $0 in 2021 and $4 in 20200 (14)
Amortization of actuarial (gain) loss and net actuarial loss from settlements included in net periodic benefit cost (credit), net of taxes of ($1) in 2021 and ($2) in 2020Amortization of actuarial (gain) loss and net actuarial loss from settlements included in net periodic benefit cost (credit), net of taxes of ($1) in 2021 and ($2) in 20203 8 
Other comprehensive income (loss)(6) 3
Other comprehensive income (loss)(4)(6)
Comprehensive income (loss)(576) 217
Comprehensive income (loss)431 (576)
Less: Comprehensive income (loss) attributable to noncontrolling interests(53) 19
Less: Comprehensive income (loss) attributable to noncontrolling interests9 (53)
Comprehensive income (loss) attributable to The Williams Companies, Inc.$(523) $198
Comprehensive income (loss) attributable to The Williams Companies, Inc.$422 $(523)
See accompanying notes.


7

The Williams Companies, Inc.
Consolidated Balance Sheet
(Unaudited)
March 31,
2021		December 31,
2020
(Millions, except per-share amounts)
ASSETS
Current assets:
Cash and cash equivalents$1,126 $142 
Trade accounts and other receivables1,059 1,000 
Allowance for doubtful accounts(1)(1)
Trade accounts and other receivables – net1,058 999 
Inventories144 136 
Other current assets and deferred charges169 152 
Total current assets2,497 1,429 
Investments5,129 5,159 
Property, plant, and equipment42,970 42,489 
Accumulated depreciation and amortization(13,894)(13,560)
Property, plant, and equipment – net29,076 28,929 
Intangible assets – net of accumulated amortization7,362 7,444 
Regulatory assets, deferred charges, and other1,198 1,204 
Total assets$45,262 $44,165 
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable$538 $482 
Accrued liabilities855 944 
Long-term debt due within one year2,142 893 
Total current liabilities3,535 2,319 
Long-term debt21,092 21,451 
Deferred income tax liabilities2,065 1,923 
Regulatory liabilities, deferred income, and other4,097 3,889 
Contingent liabilities (Note 11)00
Equity:
Stockholders’ equity:
Preferred stock35 35 
Common stock ($1 par value; 1,470 million shares authorized at March 31, 2021 and December 31, 2020; 1,249 million shares issued at March 31, 2021 and 1,248 million shares issued at December 31, 2020)1,249 1,248 
Capital in excess of par value24,384 24,371 
Retained deficit(12,825)(12,748)
Accumulated other comprehensive income (loss)(100)(96)
Treasury stock, at cost (35 million shares of common stock)(1,041)(1,041)
Total stockholders’ equity11,702 11,769 
Noncontrolling interests in consolidated subsidiaries2,771 2,814 
Total equity14,473 14,583 
Total liabilities and equity$45,262 $44,165 
  March 31,
2020		 December 31,
2019
  (Millions, except per-share amounts)
ASSETS  
Current assets:    
Cash and cash equivalents $400
 $289
Trade accounts and other receivables 940
 1,002
Allowance for doubtful accounts (10) (6)
Trade accounts and other receivables – net 930
 996
Inventories 105
 125
Other current assets and deferred charges 130
 170
Total current assets 1,565
 1,580
Investments 5,179
 6,235
Property, plant, and equipment 41,772
 41,510
Accumulated depreciation and amortization (12,631) (12,310)
Property, plant, and equipment – net 29,141
 29,200
Intangible assets – net of accumulated amortization 7,688
 7,959
Regulatory assets, deferred charges, and other 1,056
 1,066
Total assets $44,629
 $46,040
LIABILITIES AND EQUITY    
Current liabilities:    
Accounts payable $359
 $552
Accrued liabilities 1,129
 1,276
Long-term debt due within one year 628
 2,140
Total current liabilities 2,116
 3,968
Long-term debt 21,848
 20,148
Deferred income tax liabilities 1,602
 1,782
Regulatory liabilities, deferred income, and other 3,804
 3,778
Contingent liabilities (Note 12) 

 

Equity:    
Stockholders’ equity:    
Preferred stock 35
 35
Common stock ($1 par value; 1,470 million shares authorized at March 31, 2020 and December 31, 2019; 1,248 million shares issued at March 31, 2020 and 1,247 million shares issued at December 31, 2019) 1,248
 1,247
Capital in excess of par value 24,330
 24,323
Retained deficit (12,013) (11,002)
Accumulated other comprehensive income (loss) (205) (199)
Treasury stock, at cost (35 million shares of common stock) (1,041) (1,041)
Total stockholders’ equity 12,354
 13,363
Noncontrolling interests in consolidated subsidiaries 2,905
 3,001
Total equity 15,259
 16,364
Total liabilities and equity $44,629
 $46,040

See accompanying notes.

8


The Williams Companies, Inc.
Consolidated Statement of Changes in Equity
(Unaudited)
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, 2020$35 $1,248 $24,371 $(12,748)$(96)$(1,041)$11,769 $2,814 $14,583 
Net income (loss)0 0 0 426 0 0 426 9 435 
Other comprehensive income (loss)0 0 0 0 (4)0 (4)0 (4)
Cash dividends – common stock ($0.41 per share)0 0 0 (498)0 0 (498)0 (498)
Dividends and distributions to noncontrolling interests0 0 0 0 0 0 0 (54)(54)
Stock-based compensation and related common stock issuances, net of tax0 1 10 0 0 0 11 0 11 
Contributions from noncontrolling interests0 0 0 0 0 0 0 2 2 
Other0 0 3 (5)0 0 (2)0 (2)
   Net increase (decrease) in equity0 1 13 (77)(4)0 (67)(43)(110)
Balance – March 31, 2021$35 $1,249 $24,384 $(12,825)$(100)$(1,041)$11,702 $2,771 $14,473 
 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)—
 —
 —
 (517) —
 —
 (517) (53) (570)
Other comprehensive income (loss)—
 —
 —
 —
 (6) —
 (6) —
 (6)
Cash dividends – common stock ($0.40 per share)—
 —
 —
 (485) —
 —
 (485) —
 (485)
Dividends and distributions to noncontrolling interests—
 —
 —
 —
 —
 —
 —
 (44) (44)
Stock-based compensation and related common stock issuances, net of tax—
 1
 7
 —
 —
 —
 8
 —
 8
Contributions from noncontrolling interests—
 —
 —
 —
 —
 —
 —
 2
 2
Other—
 —
 —
 (9) —
 —
 (9) (1) (10)
   Net increase (decrease) in equity—
 1
 7
 (1,011) (6) —
 (1,009) (96) (1,105)
Balance – March 31, 2020$35
 $1,248
 $24,330
 $(12,013) $(205) $(1,041) $12,354
 $2,905
 $15,259
Balance – December 31, 2018$35
 $1,245
 $24,693
 $(10,002) $(270) $(1,041) $14,660
 $1,337
 $15,997
Net income (loss)—
 —
 —
 195
 —
 —
 195
 19
 214
Other comprehensive income (loss)—
 —
 —
 —
 3
 —
 3
 —
 3
Cash dividends – common stock ($0.38 per share)—
 —
 —
 (460) —
 —
 (460) —
 (460)
Dividends and distributions to noncontrolling interests—
 —
 —
 —
 —
 —
 —
 (41) (41)
Stock-based compensation and related common stock issuances, net of tax—
 1
 10
 —
 —
 —
 11
 —
 11
Contributions from noncontrolling interests—
 —
 —
 —
 —
 —
 —
 4
 4
Other—
 —
 —
 (3) —
 —
 (3) —
 (3)
   Net increase (decrease) in equity—
 1
 10
 (268) 3
 —
 (254) (18) (272)
Balance – March 31, 2019$35
 $1,246
 $24,703
 $(10,270) $(267) $(1,041) $14,406
 $1,319
 $15,725
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 (517)0 0 (517)(53)(570)
Other comprehensive income (loss)0 0 0 0 (6)0 (6)0 (6)
Cash dividends – common stock ($0.40 per share)0 0 0 (485)0 0 (485)0 (485)
Dividends and distributions to noncontrolling interests0 0 0 0 0 0 0 (44)(44)
Stock-based compensation and related common stock issuances, net of tax0 1 7 0 0 0 8 0 8 
Contributions from noncontrolling interests0 0 0 0 0 0 0 2 2 
Other0 0 0 (9)0 0 (9)(1)(10)
   Net increase (decrease) in equity0 1 7 (1,011)(6)0 (1,009)(96)(1,105)
Balance – March 31, 2020$35 $1,248 $24,330 $(12,013)$(205)$(1,041)$12,354 $2,905 $15,259 
*Accumulated Other Comprehensive Income (Loss)
*Accumulated Other Comprehensive Income (Loss)
See accompanying notes.


9

The Williams Companies, Inc.
Consolidated Statement of Cash Flows
(Unaudited)
Three Months Ended 
March 31,		Three Months Ended 
March 31,
2020 201920212020
(Millions)(Millions)
OPERATING ACTIVITIES: OPERATING ACTIVITIES:
Net income (loss)$(570) $214
Net income (loss)$435 $(570)
Adjustments to reconcile to net cash provided (used) by operating activities:   Adjustments to reconcile to net cash provided (used) by operating activities:
Depreciation and amortization429
 416
Depreciation and amortization438 429 
Provision (benefit) for deferred income taxes(177) 75
Provision (benefit) for deferred income taxes144 (177)
Equity (earnings) losses(22) (80)Equity (earnings) losses(131)(22)
Distributions from unconsolidated affiliates169
 172
Distributions from unconsolidated affiliates176 169 
Impairment of goodwill (Note 11)187
 —
Impairment of equity-method investments (Note 11)938
 74
Impairment of goodwill (Note 10)Impairment of goodwill (Note 10)0 187 
Impairment of equity-method investments (Note 10)Impairment of equity-method investments (Note 10)0 938 
Amortization of stock-based awards9
 14
Amortization of stock-based awards20 9 
Cash provided (used) by changes in current assets and liabilities:   Cash provided (used) by changes in current assets and liabilities:
Accounts receivable67
 97
Accounts receivable(59)67 
Inventories19
 1
Inventories(8)19 
Other current assets and deferred charges20
 (6)Other current assets and deferred charges(6)20 
Accounts payable(155) (39)Accounts payable38 (155)
Accrued liabilities(150) (142)Accrued liabilities(116)(150)
Other, including changes in noncurrent assets and liabilities23
 (21)Other, including changes in noncurrent assets and liabilities(16)23 
Net cash provided (used) by operating activities787
 775
Net cash provided (used) by operating activities915 787 
FINANCING ACTIVITIES:   FINANCING ACTIVITIES:
Proceeds from (payments of) commercial paper – net—
 1,014
Proceeds from long-term debt1,702
 708
Proceeds from long-term debt897 1,702 
Payments of long-term debt(1,518) (864)Payments of long-term debt(5)(1,518)
Proceeds from issuance of common stock6
 6
Proceeds from issuance of common stock3 6 
Common dividends paid(485) (460)Common dividends paid(498)(485)
Dividends and distributions paid to noncontrolling interests(44) (41)Dividends and distributions paid to noncontrolling interests(54)(44)
Contributions from noncontrolling interests2
 4
Contributions from noncontrolling interests2 2 
Payments for debt issuance costsPayments for debt issuance costs(6)0 
Other – net(10) (9)Other – net(13)(10)
Net cash provided (used) by financing activities(347) 358
Net cash provided (used) by financing activities326 (347)
INVESTING ACTIVITIES:   INVESTING ACTIVITIES:
Property, plant, and equipment:   Property, plant, and equipment:
Capital expenditures (1)(306) (422)Capital expenditures (1)(260)(306)
Dispositions – net(3) (4)Dispositions – net(1)(3)
Contributions in aid of construction14
 10
Contributions in aid of construction19 14 
Purchases of businesses, net of cash acquired (Note 2)—
 (727)
Purchases of and contributions to equity-method investments(30) (99)Purchases of and contributions to equity-method investments(14)(30)
Other – net(4) (16)Other – net(1)(4)
Net cash provided (used) by investing activities(329) (1,258)Net cash provided (used) by investing activities(257)(329)
Increase (decrease) in cash and cash equivalents111
 (125)Increase (decrease) in cash and cash equivalents984 111 
Cash and cash equivalents at beginning of year289
 168
Cash and cash equivalents at beginning of year142 289 
Cash and cash equivalents at end of period$400
 $43
Cash and cash equivalents at end of period$1,126 $400 
_____________   _____________
(1) Increases to property, plant, and equipment$(254) $(418)(1) Increases to property, plant, and equipment$(263)$(254)
Changes in related accounts payable and accrued liabilities(52) (4)Changes in related accounts payable and accrued liabilities3 (52)
Capital expenditures$(306) $(422)Capital expenditures$(260)$(306)

See accompanying notes.

10

The Williams Companies, Inc.
Notes to Consolidated Financial Statements
(Unaudited)

Note 1 – General, Description of Business, and Basis of Presentation
General
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, 2019,2020, in our Annual Report on Form 10-K. 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.
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. 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 operationsStates and are presented within the following reportable segments: Transmission & Gulf of Mexico, Northeast G&P, and West, consistent with the manner in which our chief operating decision maker evaluates performance and allocates resources. All remaining business activities, including our recently acquired upstream operations, as well as corporate activities are included in Other. Prior period segment disclosures have been recast for the new segment presentation.
Transmission & Gulf of Mexico is comprised of our interstate natural gas pipelines, Transcontinental Gas Pipe Line Company, LLC (Transco) and Northwest Pipeline LLC (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 variable interest entity, or VIE), which is a proprietary floating production system, 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 65 percent interest in Ohio Valley Midstream LLC (Northeast JV) (a consolidated 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), a 50 percent equity-method investment in Blue Racer Midstream LLC (Blue Racer) (we previously effectively owned a 29 percent indirect interest in Blue Racer through our 58 percent equity-method investment in Caiman Energy II, LLC (Caiman II) until acquiring a controlling interest in November 2020), and Appalachia Midstream Services, LLC, whicha wholly owned subsidiary that owns equity-method investments with an approximate average 66 percent interest in multiple gas gathering systems in the Marcellus Shale region (Appalachia Midstream Investments).
West is comprised of our gas gathering, processing, and treating operations in the Rocky Mountain region of Colorado and Wyoming, the Barnett Shale region of north-central Texas, the Eagle Ford Shale region of south Texas,


Notes (Continued)


the Haynesville Shale region of northwest Louisiana, and the Mid-Continent region which includes the
11


Notes (Continued)

Anadarko, Arkoma, and 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), a 20 percent equity-method investment in Targa Train 7 LLC (Targa Train 7) (a nonconsolidated VIE), and a 15 percent equity-method investmentinterest in Brazos Permian II, LLC (Brazos Permian II) (a nonconsolidated VIE). West also included our former 50 percent equity-method investment in Jackalope Gas Gathering Services, L.L.C., 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 recent financial and commodity market declines, 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.
Accounting standards issued and adopted
In June 2016, the Financial Accounting Standards Board issued Accounting Standards Update (ASU) 2016-13 “Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments” (ASU 2016-13). ASU 2016-13 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 are required to use a forward-looking “expected loss” model that generally will result in the earlier recognition of allowances for losses. We adopted ASU 2016-13 effective January 1, 2020, which primarily applied to our short-term trade receivables. 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 it very costly to replicate by another provider. 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. We do not have a material amount of significantly aged receivables at March 31, 2020.


Notes (Continued)


Note 2 – Acquisitions
UEOM
As of December 31, 2018, we owned a 62 percent interest in 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, net of $13 million cash acquired. As a result of acquiring this additional interest, we obtained control of and consolidated UEOM.
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 11 – 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.
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 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 $567 million, and decreased Capital in excess of par value by $426 million and Deferred income tax liabilities by $141 million in the Consolidated Balance Sheet in 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 Net income (loss) attributable to noncontrolling interests in the Consolidated Statement of Operations (see Note 11 – Fair Value Measurements and Guarantees).



Notes (Continued)


Note 2 – Variable Interest Entities
Consolidated VIEs
As of March 31, 2021, we consolidate the following VIEs:
Northeast JV
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.
12


Notes (Continued)

The following table presents amounts included in the Consolidated Balance Sheet that are only for the use or obligation of our consolidated VIEs:
March 31,
2021		December 31,
2020
(Millions)
Assets (liabilities):
Cash and cash equivalents$83 $107 
Trade accounts and other receivables – net128 148 
Other current assets and deferred charges5 7 
Property, plant, and equipment – net5,465 5,514 
Intangible assets – net of accumulated amortization2,349 2,376 
Regulatory assets, deferred charges, and other15 15 
Accounts payable(49)(42)
Accrued liabilities(34)(34)
Regulatory liabilities, deferred income, and other(287)(289)

Nonconsolidated VIEs
Targa Train 7
We own a 20 percent interest in Targa Train 7, which provides fractionation services at Mt. Belvieu and is a VIE due primarily to our limited participating rights as the minority equity holder. At March 31, 2021, the carrying value of our investment in Targa Train 7 was $50 million. Our maximum exposure to loss is limited to the carrying value of our investment.
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. During the first quarter of 2020 we recorded an impairment of our equity-method investment in Brazos Permian II. Our maximum exposure to loss is limited to the carrying value of our investment.

13


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 March 31, 2020               
Revenues from contracts with customers:               
Service revenues:               
Regulated interstate natural gas transportation and storage$604
 $115
 $—
 $—
 $—
 $—
 $(2) $717
Gathering, processing, transportation, fractionation, and storage:               
Monetary consideration—
 —
 99
 312
 299
 —
 (22) 688
Commodity consideration—
 —
 5
 2
 21
 —
 —
 28
Other3
 —
 6
 41
 9
 —
 (5) 54
Total service revenues607
 115
 110
 355
 329
 —
 (29) 1,487
Product Sales:               
NGL and natural gas20
 —
 32
 29
 359
 —
 (29) 411
Total revenues from contracts with customers627
 115
 142
 384
 688
 —
 (58) 1,898
Other revenues (1)—
 —
 2
 5
 3
 8
 (3) 15
Total revenues$627
 $115
 $144
 $389
 $691
 $8
 $(61) $1,913
                
                
Three Months Ended March 31, 2019               
Revenues from contracts with customers:               
Service revenues:               
Regulated interstate natural gas transportation and storage$570
 $114
 $—
 $—
 $—
 $—
 $—
 $684
Gathering, processing, transportation, fractionation, and storage:               
Monetary consideration—
 —
 128
 239
 344
 —
 (18) 693
Commodity consideration—
 —
 13
 5
 46
 —
 —
 64
Other—
 —
 4
 32
 11
 —
 (4) 43
Total service revenues570
 114
 145
 276
 401
 —
 (22) 1,484
Product Sales:               
NGL and natural gas24
 —
 58
 47
 479
 —
 (58) 550
Total revenues from contracts with customers594
 114
 203
 323
 880
 —
 (80) 2,034
Other revenues (1)3
 —
 4
 5
 4
 7
 (3) 20
Total revenues$597
 $114
 $207
 $328
 $884
 $7
 $(83) $2,054

(1)
Revenues not within the scopeTransco
Northwest PipelineGulf 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 Mexico MidstreamService revenuesNortheast
Midstream		 in our West MidstreamConsolidated Statement of OperationsOther, and amounts associated with our derivative contracts, which are reported inEliminations Product salesTotal
in our (Millions)Consolidated Statement of Operations.
Three Months Ended March 31, 2021
Revenues from contracts with customers:
Service revenues:
Regulated interstate natural gas transportation and storage$625 $113 $0 $0 $0 $0 $(3)$735 
Gathering, processing, transportation, fractionation, and storage:
Monetary consideration0 0 86 311 262 0 (21)638 
Commodity consideration0 0 11 3 35 0 0 49 
Other3 0 3 41 19 0 (4)62 
Total service revenues628 113 100 355 316 0 (28)1,484 
Product sales14 0 53 32 1,080 56 (90)1,145 
Total revenues from contracts with customers642 113 153 387 1,396 56 (118)2,629 
Other revenues (1)2 0 2 6 (31)7 (3)(17)
Total revenues$644 $113 $155 $393 $1,365 $63 $(121)$2,612 
Three Months Ended March 31, 2020
Revenues from contracts with customers:
Service revenues:
Regulated interstate natural gas transportation and storage$604 $115 $0 $0 $0 $0 $(2)$717 
Gathering, processing, transportation, fractionation, and storage:
Monetary consideration0 0 99 312 299 0 (22)688 
Commodity consideration0 0 5 2 21 0 0 28 
Other3 0 6 41 9 0 (5)54 
Total service revenues607 115 110 355 329 0 (29)1,487 
Product sales20 0 32 29 359 0 (29)411 
Total revenues from contracts with customers627 115 142 384 688 0 (58)1,898 
Other revenues (1)0 0 2 5 3 8 (3)15 
Total revenues$627 $115 $144 $389 $691 $8 $(61)$1,913 

(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 the Consolidated Statement of Operations, and amounts associated with our derivative contracts, which are reported in Product sales in the Consolidated Statement of Operations.

14


Notes (Continued)


Contract Assets
The following table presents a reconciliation of our contract assets:
 Three Months Ended 
March 31,
 2020 2019
 (Millions)
Balance at beginning of period$8
 $4
Revenue recognized in excess of amounts invoiced23
 19
Minimum volume commitments invoiced(13) (1)
Balance at end of period$18
 $22

Three Months Ended 
March 31,
20212020
(Millions)
Balance at beginning of period$12 $8 
Revenue recognized in excess of amounts invoiced45 23 
Minimum volume commitments invoiced(32)(13)
Balance at end of period$25 $18 
Contract Liabilities
The following table presents a reconciliation of our contract liabilities:
 Three Months Ended 
March 31,
 2020 2019
 (Millions)
Balance at beginning of period$1,215
 $1,397
Payments received and deferred28
 33
Significant financing component3
 4
Recognized in revenue(57) (99)
Balance at end of period$1,189
 $1,335

Three Months Ended 
March 31,
20212020
(Millions)
Balance at beginning of period$1,209 $1,215 
Payments received and deferred13 28 
Significant financing component3 3 
Recognized in revenue(54)(57)
Balance at end of period$1,171 $1,189 
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) 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 March 31, 2020,2021, do not consider potential future performance obligations for which the renewal has not been exercised and excludesexclude contracts with customers for which the underlying facilities have not received FERC authorization to be placed into service. Consideration received prior to March 31, 2020,2021, that will be recognized in future periods is also excluded from our remaining performance obligations and is instead reflected in contract liabilities.
15


Notes (Continued)


The following table presents the amount of the contract liabilities balance expected to be recognized as revenue when performance obligations are satisfied and the transaction price allocated to the remaining performance obligations under certain contracts as of March 31, 2020.2021.
 Contract Liabilities Remaining Performance Obligations
 (Millions)
2020 (remainder)$110
 $2,552
2021132
 3,293
2022117
 3,149
2023107
 2,640
202499
 2,350
Thereafter624
 18,985
Total$1,189
 $32,969

Contract LiabilitiesRemaining Performance Obligations
(Millions)
2021 (remainder)$87 $2,610 
2022113 3,363 
2023105 3,097 
2024102 2,578 
202597 2,315 
Thereafter667 17,750 
Total$1,171 $31,713 
Accounts Receivable
The following is a summary of our Trade accounts and other receivables – net:
 March 31, 2020 December 31, 2019
 (Millions)
Accounts receivable related to revenues from contracts with customers$791
 $890
Other accounts receivable139
 106
Total reflected in Trade accounts and other receivables – net
$930
 $996

March 31, 2021December 31, 2020
(Millions)
Accounts receivable related to revenues from contracts with customers$1,007 $892 
Other accounts receivable51 107 
Trade accounts and other receivables – net
$1,058 $999 
Note 4 – Variable Interest EntitiesInvesting Activities
Consolidated VIEsImpairment of Equity-Method Investments
AsImpairment of equity-method investments for the three months ended March 31, 2020, we consolidateincludes $938 million associated with the following VIEs:
Northeast JV
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 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.
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:

March 31,
2020
December 31,
2019

(Millions)
Assets (liabilities):


Cash and cash equivalents$100
 $102
Trade accounts and other receivables – net170
 167
Other current assets and deferred charges3
 5
Property, plant, and equipment – net5,685
 5,745
Intangible assets – net of accumulated amortization2,454
 2,669
Regulatory assets, deferred charges, and other12
 13
Accounts payable(44) (58)
Accrued liabilities(54) (66)
Regulatory liabilities, deferred income, and other(285) (283)


Nonconsolidated VIEs
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. During the first quarter of 2020 we recorded an impairment of our equity-method investment in Brazos Permian IIinvestments (see Note 1110 – Fair Value Measurements and Guarantees). Our exposure
Equity Earnings (Losses)
Equity earnings (losses) for the three months ended March 31, 2020, includes a $78 million loss associated with the first-quarter 2020 full impairment of goodwill recognized by our investee RMM, which was allocated entirely to loss is limitedour member interest per the terms of the membership agreement.
Note 5 – Provision (Benefit) for Income Taxes
The Provision (benefit) for income taxes includes:
Three Months Ended 
March 31,
20212020
(Millions)
Current:
Federal$(2)$(28)
State(1)1 
(3)(27)
Deferred:
Federal115 (134)
State29 (43)
144 (177)
Provision (benefit) for income taxes$141 $(204)
16


Notes (Continued)

The effective income tax rates for the total provision (benefit) for both the three months ended March 31, 2021 and 2020 are greater than the federal statutory rate, primarily due to the carrying valueeffect of state income taxes.

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 investment.unrecognized tax benefit position.
Note 6 – Earnings (Loss) Per Common Share
Three Months Ended 
March 31,
20212020
(Dollars in millions, except per-share
amounts; shares in thousands)
Net income (loss) available to common stockholders$425 $(518)
Basic weighted-average shares1,214,646 1,213,019 
Effect of dilutive securities:
Nonvested restricted stock units2,565 0 
Diluted weighted-average shares (1)1,217,211 1,213,019 
Earnings (loss) per common share:
Basic$.35 $(.43)
Diluted$.35 $(.43)

(1)For the three months ended March 31, 2020, 1.3 million weighted-average nonvested restricted stock units have been excluded from the computation of diluted earnings (loss) per common share as their inclusion would be antidilutive due to our loss available to common stockholders.
Note 5 – Investing Activities
Equity earnings (losses) for the three months ended March 31, 2020, includes $78 million associated with the full impairment of goodwill recognized by our investee RMM, which was allocated entirely to our member interest per the terms of the membership agreement.
Impairment of equity-method investments for the three months ended March 31, 2020, includes $938 million associated with the impairment of equity-method investments (see Note 11 – Fair Value Measurements and Guarantees).
Note 6 – Provision (Benefit) for Income Taxes
The Provision (benefit) for income taxes includes:
 Three Months Ended 
March 31,
 2020 2019
 (Millions)
Current:   
Federal$(28) $(6)
State1
 —
 (27) (6)
Deferred:   
Federal(134) 61
State(43) 14
 (177) 75
Provision (benefit) for income taxes$(204) $69



Notes (Continued)


The effective income tax rate for the total provision (benefit) for both the three months ended March 31, 2020 and 2019 is greater than the federal statutory rate, primarily due to the effect of state income taxes.

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.
Note 7 – Earnings (Loss) Per Common Share
 Three Months Ended 
March 31,
 2020 2019
 
(Dollars in millions, except per-share
amounts; shares in thousands)
Net income (loss) available to common stockholders$(518) $194
Basic weighted-average shares1,213,019
 1,211,489
Effect of dilutive securities:   
Nonvested restricted stock units—
 1,845
Stock options—
 258
Diluted weighted-average shares (1)1,213,019
 1,213,592
Earnings (loss) per common share:   
Basic$(.43) $.16
Diluted$(.43) $.16
__________
(1)For the three months ended March 31, 2020, 1.3 million weighted-average nonvested restricted stock units have been excluded from the computation of diluted earnings (loss) per common share as their inclusion would be antidilutive due to our loss available to common stockholders.
Note 8 – Employee Benefit Plans
Net periodic benefit cost (credit) is as follows:

Pension BenefitsPension Benefits

Three Months Ended 
March 31,		Three Months Ended 
March 31,

2020
201920212020

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


Components of net periodic benefit cost (credit):
Service cost$8

$11
Service cost$8 $8 
Interest cost10

12
Interest cost7 10 
Expected return on plan assets(13)
(15)Expected return on plan assets(11)(13)
Amortization of net actuarial loss4

4
Amortization of net actuarial loss4 4 
Net actuarial loss from settlements6

—
Net actuarial loss from settlements0 6 
Net periodic benefit cost (credit)$15

$12
Net periodic benefit cost (credit)$8 $15 
17



Notes (Continued)


 Other Postretirement Benefits
 Three Months Ended 
March 31,
 2020 2019
 (Millions)
Components of net periodic benefit cost (credit):   
Interest cost$2
 $2
Expected return on plan assets(3) (2)
Reclassification to regulatory liability1
 —
Net periodic benefit cost (credit)$—
 $—

Other Postretirement Benefits
Three Months Ended 
March 31,
20212020
(Millions)
Components of net periodic benefit cost (credit):
Interest cost$1 $2 
Expected return on plan assets(2)(3)
Reclassification to regulatory liability1 1 
Net periodic benefit cost (credit)$0 $0 
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 Operations.Operations.
During the three months ended March 31, 2020,2021, we contributed $1$1 million to our pension plans and $1 million to our other postretirement benefit plans. We presently anticipate making additional contributions of approximately $13$2 million to our pension plans and approximately $4$5 million to our other postretirement benefit plans in the remainder of 2020.2021.
Note 8 – Debt and Banking Arrangements
Long-Term Debt
Issuances and retirements
On March 2, 2021, we completed a public offering of $900 million of 2.6 percent senior unsecured notes due 2031.
Commercial Paper Program
At March 31, 2021, 0 Commercial paper was outstanding under our $4 billion commercial paper program.
Credit Facilities
March 31, 2021
Stated CapacityOutstanding
(Millions)
Long-term credit facility (1)$4,500 $0 
Letters of credit under certain bilateral bank agreements17 
(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 9 – Debt and Banking Arrangements
Long-Term Debt
Retirements
We retired $1.5 billion of 5.25 percent senior unsecured notes that matured on March 15, 2020.
We retired $14 million of 8.75 percent senior unsecured notes that matured on January 15, 2020.
Commercial Paper Program
At March 31, 2020, 0 commercial paper was outstanding under our $4 billion commercial paper program.
Credit Facilities
 March 31, 2020
 Stated Capacity Outstanding
 (Millions)
    
Long-term credit facility (1)$4,500
 $1,700
Letters of credit under certain bilateral bank agreements  14
(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 10 – Stockholders’ Equity
Stockholder Rights Agreement
On March 19, 2020,As disclosed in our boardAnnual Report on Form 10-K filed February 24, 2021, a purported shareholder filed a putative class action lawsuit in the Delaware Court of directors approved the adoption of a limited durationChancery challenging our stockholder rights agreement (Rights Agreement) and. On February 26, 2021, the Delaware Court of Chancery issued a decision which declared a distribution of 1 preferred stock purchase right for each outstanding share of common stock. Thethe Rights Agreement is intended to protectunenforceable and permanently enjoined the interestscontinued operation of us and our stockholders by reducing the likelihood of another party gaining control of or significant influence over us without paying an appropriate premium considering recent volatile markets. Each preferred stock purchase right represents the right to purchase, upon certainRights Agreement, which otherwise would have expired on March 20, 2021.
18


Notes (Continued)


terms and conditions, one one-thousandth of a share of Series C Participating Cumulative Preferred Stock, $1.00 par value per share. Each one-thousandth 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.
AOCI
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, 2019$(2) $(1) $(196) $(199)
Other comprehensive income (loss) before reclassifications
—
 —
 (14) (14)
Amounts reclassified from accumulated other comprehensive income (loss)
—
 —
 8
 8
Other comprehensive income (loss)—
 —
 (6) (6)
Balance at March 31, 2020$(2) $(1) $(202) $(205)

Cash
Flow
Hedges		Foreign
Currency
Translation		Pension and
Other Postretirement
Benefits		Total
(Millions)
Balance at December 31, 2020$(3)$(1)$(92)$(96)
Other comprehensive income (loss) before reclassifications
(9)0 0 (9)
Amounts reclassified from accumulated other comprehensive income (loss)
2 0 3 5 
Other comprehensive income (loss)(7)0 3 (4)
Balance at March 31, 2021$(10)$(1)$(89)$(100)
Reclassifications out of AOCI are presented in the following table by component for the three months ended March 31, 2020:2021:
ComponentReclassificationsClassification
(Millions)
Cash flow hedges:
Energy commodity contracts$2 Product sales
Pension and other postretirement benefits:
Amortization of actuarial (gain) loss and net actuarial loss from settlements included in net periodic benefit cost (credit)4 
Other income (expense) – net below Operating income (loss)
Income tax benefit(1)Provision (benefit) for income taxes
Reclassifications during the period$5 
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) $10
 
Other income (expense) – net below Operating income (loss)
Income tax benefit (2) Provision (benefit) for income taxes
Reclassifications during the period $8
  
19



Notes (Continued)

Note 10 – 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, 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 March 31, 2021:
Measured on a recurring basis:
ARO Trust investments$243 $243 $243 $0 $0 
Additional disclosures:
Long-term debt, including current portion(23,234)(26,798)0 (26,798)0 
Guarantees(40)(26)0 (10)(16)
Assets (liabilities) at December 31, 2020:
Measured on a recurring basis:
ARO Trust investments$235 $235 $235 $0 $0 
Additional disclosures:
Long-term debt, including current portion(22,344)(27,043)0 (27,043)0 
Guarantees(40)(27)0 (11)(16)
Fair Value Methods
We use the following methods and assumptions in estimating the fair value of our financial instruments:
Assets 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.
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.
20


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 $26 millionat March 31, 2021. 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 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.

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 Operations. Our partner’s $65 million share of this impairment is reflected within Net income (loss) attributable to noncontrolling interests in the Consolidated Statement of Operations.

21


Notes (Continued)

The following table presents impairments of equity-method investments associated with certain nonrecurring fair value measurements within Level 3 of the fair value hierarchy.
Impairments
Three Months Ended 
March 31,
SegmentDate of MeasurementFair Value20212020
(Millions)
Impairment of equity-method investments:
RMM (1)WestMarch 31, 2020$557 $243 
Brazos Permian II (1)WestMarch 31, 20200 193 
Caiman II (2)Northeast G&PMarch 31, 2020191 229 
Appalachia Midstream Investments (2)Northeast G&PMarch 31, 20202,700 127 
Aux Sable (2)Northeast G&PMarch 31, 20207 39 
Laurel Mountain (2)Northeast G&PMarch 31, 2020236 10 
Discovery (2)Transmission & Gulf of MexicoMarch 31, 2020367 97 
Impairment of equity-method investments$0 $938 
_______________
(1)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 market declines previously discussed.
(2)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 market declines previously discussed.
Note 11 – Fair Value Measurements and Guarantees
The following table presents, by level within the fair value hierarchy, certain of our financial assets and liabilities. The carrying values of cash and cash equivalents, accounts receivable, margin deposits, 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 March 31, 2020:          
Measured on a recurring basis:          
ARO Trust investments $188
 $188
 $188
 $—
 $—
Energy derivative assets designated as hedging instruments 2
 2
 2
 —
 —
Energy derivative assets not designated as hedging instruments 2
 2
 2
 —
 —
Energy derivative liabilities not designated as hedging instruments (5) (5) (3) —
 (2)
Additional disclosures:          
Long-term debt, including current portion (22,476) (22,531) —
 (22,531) —
Guarantees (41) (27) —
 (11) (16)
           
Assets (liabilities) at December 31, 2019:          
Measured on a recurring basis:          
ARO Trust investments $201
 $201
 $201
 $—
 $—
Energy derivative assets not designated as hedging instruments 1
 1
 1
 —
 —
Energy derivative liabilities not designated as hedging instruments (3) (3) (1) —
 (2)
Additional disclosures:          
Long-term debt, including current portion (22,288) (25,319) —
 (25,319) —
Guarantees (41) (27) —
 (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.


Notes (Continued)


The fair value amounts are presented on a gross basis and do not reflect the netting of asset and liability positions 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 derivative assets are reported in Other current assets and deferred charges and Regulatory assets, deferred charges, and other in the Consolidated Balance Sheet. Energy derivative liabilities are reported in Accrued liabilities and Regulatory liabilities, deferred income, and other in the Consolidated Balance Sheet.
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.
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 millionat March 31, 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 recent 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 were 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,


Notes (Continued)


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 Operations. Our partner’s $65 million share of this impairment is reflected within Net income (loss) attributable to noncontrolling interests in the Consolidated Statement of Operations (see Note 2 – Acquisitions).

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
        Three Months Ended 
March 31,
  Segment Date of Measurement Fair Value 2020 2019
      (Millions)
Impairment of certain assets:          
Certain idle gathering assets (1) West March 31, 2019 $—
 
 $12
Impairment of equity-method investments:          
RMM (2) West March 31, 2020 $557
 $243
  
Brazos Permian II (2) West March 31, 2020 —
 193
  
Caiman II (3) Northeast G&P March 31, 2020 191
 229
  
Appalachia Midstream Investments (3) Northeast G&P March 31, 2020 2,700
 127
  
Aux Sable (3) Northeast G&P March 31, 2020 7
 39
  
Laurel Mountain (3) Northeast G&P March 31, 2020 236
 10
  
Discovery (3) Transmission & Gulf of Mexico March 31, 2020 367
 97
  
UEOM (4) Northeast G&P March 17, 2019 1,210
 
 $74
Impairment of equity-method investments       $938
 $74
_______________
(1)
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. This impairment is reported in Other (income) expense – net within Costs and expenses in the Consolidated Statement of Operations.

(2)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.

(3)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


Notes (Continued)


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 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.

(4)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.
Note 12 – 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.
22


Notes (Continued)

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 where we re-urged our motion for summary judgment. The district court denied the motion but granted our request to seek permission for an immediate appeal to the appellate court. Oral argument occurred before the appellate court on January 19, 2021, and we await the appellate court’s ruling.
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 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 iswas scheduled to begin June 14, 2021.2021, but the court struck the setting and has not reset it.
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


Notes (Continued)


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 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 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 Courtcourt permitted the State of Alaska to amend its complaint to add a claim for offsite PFOS/PFOA contamination. The Courtcourt 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. In the summer of 2019, the Court court
23


Notes (Continued)

deconsolidated the cases for purposes of trial. A bench trial on all claims except North Pole’s claims began in October 2019.
In January 2020, the Alaska Superior Court issued its Memorandum of Decision finding in favor of the State of Alaska and FHRA, with the total incurred and potential future damages estimated to be $86 million. The Courtcourt found that FHRA is not entitled to contractual indemnification from us because FHRA contributed to the sulfolane contamination. On March 23, 2020, the Courtcourt entered final judgment in the case. Filing deadlines have beenwere stayed until May 1, 2020. However, on April 21, 2020, we filed a Notice of Appeal. We also expectfiled post-judgment motions including a Motion for New Trial and a Motion to file post-judgment motions.Alter or Amend the Judgment. These post-trial motions will bewere resolved beforewith 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’s case pending resolution of the appeal in the State of Alaska and FHRA case. On December 23, 2020, we filed our opening brief on appeal. We have recorded an accrued liability in the amount of our estimate of the probable loss. It is reasonably possible that we may not be successful on appeal and could ultimately pay up to the amount of judgment.
Royalty Matters
Certain of our customers, including one major customer,Chesapeake Energy Corporation (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 customerChesapeake 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 customerChesapeake. Chesapeake has reached a tentative settlement to resolve substantially all Pennsylvania royalty cases pending, which settlement would applyapplies to both the customerChesapeake and us. The settlement as reported woulddoes not require any contribution from us.us and is awaiting court approval.
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


Notes (Continued)


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.
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
24


Notes (Continued)

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 previouslyoriginally scheduled trial for May 20 through May 24, 2019; the court struck the trialthat setting and re-scheduledreset trial for June 8 through June 11 and June 15, 2020;to occur in 2020. All 2020 trial settings were struck due to COVID-19, the court struck the setting andCOVID-19. Trial has re-scheduled trial for August 31 through September 4, 2020.
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 declared a mistrial due to the conduct of an officer of SABIC Petrochemicals and SABIC Petrochemicals’ expert witness. Trial is currentlybeen 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, 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 will become effective on June 1, 2020. As of March 31, 2020, we have provided a $248 million reserve for rate refunds related to increased rates collected since March 2019, which we believe is adequate for any refunds that may be required.May 10 through May 17, 2021.
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


Notes (Continued)


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 March 31, 2020,2021, we have accrued liabilities totaling $30$33 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, or our experience with other similar cleanup operations. At March 31, 2020,2021, 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.
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 March 31, 2020,2021, we have accrued liabilities of $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 March 31, 2020,2021, we have accrued liabilities totaling $6$8 million for these costs.
25


Notes (Continued)

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 March 31, 2020,2021, we have accrued environmental liabilities of $20$21 million related to these matters.


Notes (Continued)


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 warranties, tax, historic litigation, personal injury, property damage, environmental matters, right of way, and other representations that we have provided.
At March 31, 2020,2021, 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 whichthat 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 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 12 – Segment Disclosures
Our reportable segments are Transmission & Gulf of Mexico, Northeast G&P, 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. 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
26


Notes (Continued)

primarily represent the sale of NGLs from our natural gas processing plants and transportation services provided 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;
◦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.

27


Notes (Continued)

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

Transmission & Gulf of MexicoNortheast G&PWestOtherEliminationsTotal
(Millions)
Three Months Ended March 31, 2021
Segment revenues:
Service revenues
External$822 $347 $279 $4 $— $1,452 
Internal12 11 5 3 (31)— 
Total service revenues834 358 284 7 (31)1,452 
Total service revenues – commodity consideration11 3 35 0 0 49 
Product sales
External40 4 1,018 49 — 1,111 
Internal27 28 28 7 (90)— 
Total product sales67 32 1,046 56 (90)1,111 
Total revenues$912 $393 $1,365 $63 $(121)$2,612 
Three Months Ended March 31, 2020
Segment revenues:
Service revenues
External$814 $344 $311 $5 $— $1,474 
Internal15 14 0 3 (32)— 
Total service revenues829 358 311 8 (32)1,474 
Total service revenues – commodity consideration5 2 21 0 0 28 
Product sales
External41 23 347 0 — 411 
Internal11 6 12 0 (29)— 
Total product sales52 29 359 0 (29)411 
Total revenues$886 $389 $691 $8 $(61)$1,913 
March 31, 2021
Total assets (1)$19,395 $14,464 $10,533 $2,225 $(1,355)$45,262 
December 31, 2020
Total assets$19,110 $14,569 $10,558 $927 $(999)$44,165 
______________
(1)    The increase at our Other segment is primarily due to increased cash balance and the February 2021 acquisition of oil and gas properties, primarily comprised of approximately 2,000 operated wells, in the Wamsutter basin in Wyoming from a supermajor oil and gas company for approximately $79 million, a portion of which was paid in the prior year. We are working to identify an operating partner to optimize development of the properties and enhance the value of our connected midstream infrastructure. Our oil and gas exploration and production activities are accounted for under the successful efforts method. We recorded $290 million of property, plant, and equipment and $207 million of ARO related to this transaction.
28


Notes (Continued)

The following table reflects the reconciliation of Modified EBITDA to Net income (loss) as reported in the Consolidated Statement of Operations.
Three Months Ended 
March 31,
20212020
(Millions)
Modified EBITDA by segment:
Transmission & Gulf of Mexico$660 $662 
Northeast G&P402 369 
West315 215 
Other33 7 
1,410 1,253 
Accretion expense associated with asset retirement obligations for nonregulated operations(10)(10)
Depreciation and amortization expenses(438)(429)
Impairment of goodwill0 (187)
Equity earnings (losses)131 22 
Impairment of equity-method investments0 (938)
Other investing income (loss) – net2 3 
Proportional Modified EBITDA of equity-method investments(225)(192)
Interest expense(294)(296)
(Provision) benefit for income taxes(141)204 
Net income (loss)$435 $(570)


29

Note 13 – Segment DisclosuresItem 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
General
We are an energy infrastructure company focused on connecting North America’s significant hydrocarbon resource plays to growing markets for natural gas and NGLs through our gas pipeline and midstream business. Our operations are located in the United States.
Our interstate natural gas pipeline strategy is to create value by maximizing the utilization of our pipeline capacity by providing high quality, low cost transportation of natural gas to large and growing markets. Our gas pipeline businesses’ interstate transmission and storage activities are subject to regulation by the FERC and as such, our rates and charges for the transportation of natural gas in interstate commerce, and the extension, expansion or abandonment of jurisdictional facilities and accounting, among other things, are subject to regulation. Rates are established in accordance with the FERC’s ratemaking process. Changes in commodity prices and volumes transported have limited near-term impact on these revenues because the majority of cost of service is recovered through firm capacity reservation charges in transportation rates.
The ongoing strategy of our midstream operations is to safely and reliably operate large-scale midstream infrastructure where our assets can be fully utilized and drive low per-unit costs. We focus on consistently attracting new business by providing highly reliable service to our customers. These services include natural gas gathering, processing, treating, and compression, NGL fractionation and transportation, crude oil production handling and transportation, marketing services for NGL, crude oil and natural gas, as well as storage facilities.
Consistent with the manner in which our chief operating decision maker evaluates performance and allocates resources, our operations are conducted, managed, and presented within the following reportable segments aresegments: Transmission & Gulf of Mexico, Northeast G&P, and West. All remaining business activities, including our recently acquired upstream operations, as well as corporate activities are included in Other. (SeeOur reportable segments are comprised of the following businesses:
•Transmission & Gulf of Mexico is comprised of our interstate natural gas pipelines, Transco and Northwest Pipeline, as well as natural gas gathering and processing and crude oil production handling and transportation assets in the Gulf Coast region, including a 51 percent interest in Gulfstar One (a consolidated VIE), which is a proprietary floating production system, a 50 percent equity-method investment in Gulfstream, and a 60 percent equity-method investment in Discovery.
•Northeast G&P is comprised of our midstream gathering, processing, and fractionation businesses in the Marcellus Shale region primarily in Pennsylvania and New York, and the Utica Shale region of eastern Ohio, as well as a 65 percent interest in our Northeast JV (a consolidated VIE) which operates in West Virginia, Ohio, and Pennsylvania, a 66 percent interest in Cardinal (a consolidated VIE) which operates in Ohio, a 69 percent equity-method investment in Laurel Mountain, a 50 percent equity-method investment in Blue Racer (we previously effectively owned a 29 percent indirect interest in Blue Racer through our 58 percent equity-method investment in Caiman II until acquiring a controlling interest in November 2020), and Appalachia Midstream Investments, a wholly owned subsidiary that owns equity-method investments with an approximate average 66 percent interest in multiple gas gathering systems in the Marcellus Shale region.
•West is comprised of our gas gathering, processing, and treating operations in the Rocky Mountain region of Colorado and Wyoming, the Barnett Shale region of north-central Texas, the Eagle Ford Shale region of south Texas, the Haynesville Shale region of northwest Louisiana, and the Mid-Continent region which includes the Anadarko, Arkoma, and Permian basins. This segment also includes our 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 OPPL, a 50 percent equity-method investment in RMM, a 20 percent equity-method investment in Targa Train 7, and a 15 percent interest in Brazos Permian II.
30


Management’s Discussion and Analysis (Continued)
Dividends
In March 2021, we paid a regular quarterly dividend of $0.41 per share.
Overview of Three Months Ended March 31, 2021
Net income (loss) attributable to The Williams Companies, Inc., for the three months ended March 31, 2021, increased $943 millioncompared to the three months ended March 31, 2020, reflecting:
•The absence of $938 million of Impairment of equity-method investments in the first quarter of 2020;
•The absence of $187 million of Impairment of goodwill in 2020, of which $65 million was attributable to noncontrolling interests;
•A $128 million favorable change in our commodity margins primarily due to increases in net realized sales prices and volumes. Our commodity margins are comprised of the net sum of Service revenues – commodity consideration, Product sales, Product costs, and Processing commodity expenses; however, Product sales at our Other segment reflect sales related to our recently acquired upstream operations and are excluded from our commodity margins;
•A $109 million increase in equity earnings, primarily due to the absence of our $78 million share of an impairment of goodwill recorded by an equity-method investee in 2020;
•A $49 million increase in Product sales at our Other segment reflecting sales related to our recently acquired upstream operations.
These favorable changes were partially offset by:
•A $345 million unfavorable change in provision for income taxes, driven by higher pre-tax earnings;
•$23 million of higher Operating and maintenance expenses primarily due to the inclusion of our recently acquired upstream operations at our Other segment and higher employee-related expenses;
•$22 million of lower Service revenues primarily due to lower volumes and rates.
The following discussion and analysis of results of operations and financial condition and liquidity should be read in conjunction with the consolidated financial statements and notes thereto of this Form 10‑Q and our Annual Report on Form 10-K dated February 24, 2021.
Recent Developments
Expansion Project Update
Transmission & Gulf of Mexico
Southeastern Trail
In October 2019, we received approval from the FERC to expand Transco’s existing natural gas transmission system to provide incremental firm transportation capacity from the Pleasant Valley interconnect with Dominion’s Cove Point Pipeline in Virginia to the Station 65 pooling point in Louisiana. We placed 230 Mdth/d of capacity under the project into service in the fourth quarter of 2020, and the project was fully in service on January 1, 2021. In total, the project increased capacity by 296 Mdth/d.
COVID-19
The outbreak of COVID-19 has severely impacted global economic activity and caused significant volatility and negative pressure in financial markets. We continue to monitor the COVID-19 pandemic and have taken steps intended to protect the safety of our customers, employees, and communities, and to support the continued delivery
31


Management’s Discussion and Analysis (Continued)
of safe and reliable service to our customers and the communities we serve. Our financial condition, results of operations, and liquidity have not been materially impacted by direct effects of COVID-19.
Company Outlook
Our strategy is to provide large-scale energy infrastructure designed to maximize the opportunities created by the vast supply of natural gas and natural gas products that exists in the United States. We accomplish this by connecting the growing demand for cleaner fuels and feedstocks with our major positions in the premier natural gas and natural gas products supply basins. We continue to maintain a strong commitment to safety, environmental stewardship, operational excellence, and customer satisfaction. We believe that accomplishing these goals will position us to deliver safe and reliable service to our customers and an attractive return to our shareholders. Our business plan for 2021 includes a continued focus on earnings and cash flow growth, while continuing to improve leverage metrics and control operating costs.
In 2021, our operating results are expected to benefit from growth in our Northeast G&P gathering and processing volumes. We also anticipate increases from recently completed Transco expansion projects and higher Gulf of Mexico results primarily due to lower planned hurricane impacts. Our results also benefited from the overall net favorable impact of unusually high natural gas prices in the first quarter, including contributions from certain of our recently acquired upstream properties. These increases will be partially offset by a decrease in West results, including a reduction in NGL transportation volumes on OPPL and certain fee reductions in the Haynesville area in exchange for upstream value in natural gas properties. We also expect a modest increase in expenses, including higher operating taxes.
Our growth capital and investment expenditures in 2021 are expected to be in a range from $1.0 billion to $1.2 billion. Growth capital spending in 2021 primarily includes Transco expansions, all of which are fully contracted with firm transportation agreements, and projects supporting the Northeast G&P business and opportunities in the Haynesville area. In addition to growth capital and investment expenditures, we also remain committed to projects that maintain our assets for safe and reliable operations, as well as projects that meet legal, regulatory, and/or contractual commitments.
Potential risks and obstacles that could impact the execution of our plan include:
•Continued negative impacts of COVID-19 driving a global recession, which could result in further downturns in financial markets and commodity prices, as well as impact demand for natural gas and related products;
•Opposition to, and legal regulations affecting, our infrastructure projects, including the risk of delay or denial in permits and approvals needed for our projects;
•Counterparty credit and performance risk, including unexpected developments in customer bankruptcy proceedings;
•Unexpected significant increases in capital expenditures or delays in capital project execution;
•Unexpected changes in customer drilling and production activities, which could negatively impact gathering and processing volumes;
•Lower than anticipated demand for natural gas and natural gas products which could result in lower than expected volumes, energy commodity prices, and margins;
•General economic, financial markets, or further industry downturns, including increased interest rates;
•Physical damages to facilities, including damage to offshore facilities by weather-related events;
•Other risks set forth under Part I, Item 1A. Risk Factors in our Annual Report on Form 10-K for the year ended December 31, 2020, as filed with the SEC on February 24, 2021.
32


Management’s Discussion and Analysis (Continued)
We seek to maintain a strong financial position and liquidity, as well as manage a diversified portfolio of energy infrastructure assets that continue to serve key growth markets and supply basins in the United States.
Expansion Projects
Our ongoing major expansion projects include the following:
Transmission & Gulf of Mexico
Leidy South
In July 2020, we received approval from the FERC for the project to expand Transco’s existing natural gas transmission system and also extend its system through a capacity lease with National Fuel Gas Supply Corporation that will enable us to provide incremental firm transportation from Clermont, Pennsylvania and from the Zick interconnection on Transco’s Leidy Line to the River Road regulating station in Lancaster County, Pennsylvania. We placed 125 Mdth/d of capacity under the project into service in the fourth quarter of 2020, and we plan to place the remainder of the project into service as early as the fourth quarter of 2021. The project is expected to increase capacity by 582 Mdth/d.
Regional Energy Access
In March 2021, we filed an application with the FERC for the project to expand Transco’s existing natural gas transmission system to provide incremental firm transportation capacity from receipt points in northeastern Pennsylvania to multiple delivery points in Pennsylvania, New Jersey, and Maryland. We plan to place the project into service as early as the fourth quarter of 2023, assuming timely receipt of all necessary regulatory approvals. The project is expected to increase capacity by 829 Mdth/d.
33


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 months ended March 31, 2021, compared to the three months ended March 31, 2020. The results of operations by segment are discussed in further detail following this consolidated overview discussion.
Three Months Ended 
March 31,
20212020$ Change*% Change*
(Millions)
Revenues:
Service revenues$1,452 $1,474 -22 -1 %
Service revenues – commodity consideration49 28 +21 +75 %
Product sales1,111 411 +700 +170 %
Total revenues2,612 1,913 
Costs and expenses:
Product costs932 396 -536 -135 %
Processing commodity expenses21 13 -8 -62 %
Operating and maintenance expenses360 337 -23 -7 %
Depreciation and amortization expenses438 429 -9 -2 %
Selling, general, and administrative expenses123 113 -10 -9 %
Impairment of goodwill— 187 +187 +100 %
Other (income) expense – net(1)7 +8 NM
Total costs and expenses1,873 1,482 
Operating income (loss)739 431 
Equity earnings (losses)131 22 +109 NM
Impairment of equity-method investments— (938)+938 +100 %
Other investing income (loss) – net2 3 -1 -33 %
Interest expense(294)(296)+2 +1 %
Other income (expense) – net(2)4 -6 NM
Income (loss) before income taxes576 (774)
Less: Provision (benefit) for income taxes141 (204)-345 NM
Net income (loss)435 (570)
Less: Net income (loss) attributable to noncontrolling interests9 (53)-62 NM
Net income (loss) attributable to The Williams Companies, Inc.$426 $(517)
*    + = 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.
Three months ended March 31, 2021 vs. three months ended March 31, 2020
Service revenues decreased primarily due to lower volumes driven by production declines and lower gathering and processing rates, both in our West segment, as well as producer operational issues at certain offshore Gulf of Mexico operations. This decrease was partially offset by higher MVC revenue in our West segment and higher transportation fee revenues associated with expansion projects placed in service at Transco in 2020.
Service revenues – commodity consideration increased primarily due to higher NGL prices. These revenues represent consideration we receive in the form of commodities as full or partial payment for processing services provided. Most of these NGL volumes are sold during the month processed and therefore are offset within Product costs below.
34


Management’s Discussion and Analysis (Continued)
Product sales increased primarily due to higher net realized prices and higher volumes associated with our marketing activities, and the inclusion of our recently acquired upstream operations (see Note 112 – General, DescriptionSegment Disclosures of Business,Notes to Consolidated Financial Statements). This increase also includes higher prices related to our equity NGL sales activities. Marketing sales are partially offset within Product costs.
Product costs increased primarily due to higher prices and Basishigher volumes for our marketing activities, as well as higher NGL prices associated with volumes acquired related to our equity NGL production activities.
The net sum of Presentation.)Service revenues – commodity consideration, Product sales, Product costs and Processing commodity expenses comprise our commodity margins. However, Product sales at our Other segment reflect sales related to our oil and gas producing properties and are excluded from our commodity margins.
Performance MeasurementOperating and maintenance expenses increased primarily due to the inclusion of our recently acquired upstream operations and higher employee-related expenses.
Selling, general, and administrative expenses increased primarily due to higher employee-related expenses.
Impairment of goodwill reflects the 2020 charge at the Northeast reporting unit (see Note 10 – Fair Value Measurements and Guarantees of Notes to Consolidated Financial Statements).
Equity earnings (losses) changed favorably primarily due to the absence of the 2020 impairment of goodwill at RMM and due to an increase at Appalachia Midstream Investments, partially offset by a decrease at OPPL.
The change in Impairment of equity-method investments reflects the absence of 2020 impairments to various equity-method investments (see Note 10 – Fair Value Measurements and Guarantees of Notes to Consolidated Financial Statements).
Provision (benefit) for income taxes changed unfavorably primarily due to higher pre-tax income. See Note 5 – Provision (Benefit) for Income Taxes of Notes to Consolidated Financial Statements for a discussion of the effective tax rate compared to the federal statutory rate for both periods.
The unfavorable change in Net income (loss) attributable to noncontrolling interests is primarily due to the absence of our partner’s share of the 2020 goodwill impairment at the Northeast reporting unit.
Period-Over-Period Operating Results - Segments
We evaluate segment operating performance based upon Modified EBITDA. This measure represents the basisNote 12 – Segment Disclosures 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 plantsNotes 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;
◦Impairment of goodwill;
◦Depreciation and amortization expenses;
◦Accretion expense associated with asset retirement obligations for nonregulated operations.


Notes (Continued)


•
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.
The following table reflects theConsolidated Financial Statements includes a reconciliation of Segment revenues to Total revenues as reported in the Consolidated Statement of Operations and Total assets by reportable segment.
 Transmission & Gulf of Mexico Northeast G&P West Other Eliminations Total
   (Millions)
Three Months Ended March 31, 2020
Segment revenues:           
Service revenues           
External$814
 $344
 $311
 $5
 $—
 $1,474
Internal15
 14
 —
 3
 (32) —
Total service revenues829
 358
 311
 8
 (32) 1,474
Total service revenues – commodity consideration5
 2
 21
 —
 —
 28
Product sales           
External41
 23
 347
 —
 —
 411
Internal11
 6
 12
 —
 (29) —
Total product sales52
 29
 359
 —
 (29) 411
Total revenues$886
 $389
 $691
 $8
 $(61) $1,913
            
            
Three Months Ended March 31, 2019
Segment revenues:           
Service revenues           
External$811
 $266
 $359
 $4
 $—
 $1,440
Internal12
 10
 —
 3
 (25) —
Total service revenues823
 276
 359
 7
 (25) 1,440
Total service revenues – commodity consideration13
 5
 46
 —
 —
 64
Product sales           
External52
 36
 462
 —
 —
 550
Internal30
 11
 17
 —
 (58) —
Total product sales82
 47
 479
 —
 (58) 550
Total revenues$918
 $328
 $884
 $7
 $(83) $2,054
            
March 31, 2020           
Total assets$18,656
 $14,702
 $10,619
 $1,309
 $(657) $44,629
December 31, 2019           
Total assets$18,796
 $15,399
 $11,265
 $1,151
 $(571) $46,040



Notes (Continued)


The following table reflects the reconciliation of Modified EBITDAthis 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 reporteda substitute for a measure of performance prepared in accordance with GAAP.
35


Management’s Discussion and Analysis (Continued)
Transmission & Gulf of Mexico
Three Months Ended 
March 31,
20212020
(Millions)
Service revenues$834 $829 
Service revenues – commodity consideration
11 5 
Product sales67 52 
Segment revenues912 886 
Product costs(66)(52)
Processing commodity expenses(4)(2)
Other segment costs and expenses(229)(214)
Proportional Modified EBITDA of equity-method investments47 44 
Transmission & Gulf of Mexico Modified EBITDA$660 $662 
Commodity margins$8 $3 
Three months ended March 31, 2021 vs. three months ended March 31, 2020
Transmission & Gulf of Mexico Modified EBITDA decreased primarily due to unfavorable changes to Other segment costs and expenses, partially offset by higher Commodity margins and Service revenues.
Service revenues increased primarily due to:
•A $17 million increase in Transco’s natural gas transportation revenues primarily associated with expansion projects placed in service in 2020, partially offset by one less billing day;
•A $10 million increase associated with Norphlet; partially offset by
•An $18 million decrease due to lower volumes primarily from certain Gulf of Mexico operations due to producer operational issues.
The increase in Product sales includes a $12 million increase in commodity marketing sales primarily due to higher NGL prices. 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 higher employee-related costs.
36


Management’s Discussion and Analysis (Continued)
Northeast G&P
Three Months Ended 
March 31,
20212020
(Millions)
Service revenues$358 $358 
Service revenues – commodity consideration
3 2 
Product sales32 29 
Segment revenues393 389 
Product costs(32)(29)
Processing commodity expenses— (1)
Other segment costs and expenses(112)(110)
Proportional Modified EBITDA of equity-method investments153 120 
Northeast G&P Modified EBITDA$402 $369 
Commodity margins$3 $1 
Three months ended March 31, 2021 vs. three months ended March 31, 2020
Northeast G&P Modified EBITDA increased primarily due to increased Proportional Modified EBITDA of equity-method investments.
Product sales increased slightly primarily due to higher sales prices of NGLs associated with our marketing activities, which were substantially offset by lower sales volumes. Marketing sales are offset by similar changes in marketing purchases, reflected above as Product costs, and therefore have little impact to Modified EBITDA.
Proportional Modified EBITDA of equity-method investments increased at Appalachia Midstream Investments primarily driven by higher volumes. Additionally, there was an increase at Blue Racer/Caiman II due to the favorable impact of increased ownership, partially offset by lower volumes.
West
Three Months Ended 
March 31,
20212020
(Millions)
Service revenues$284 $311 
Service revenues – commodity consideration
35 21 
Product sales1,046 359 
Segment revenues1,365 691 
Product costs(936)(368)
Processing commodity expenses(17)(10)
Other segment costs and expenses(122)(126)
Proportional Modified EBITDA of equity-method investments25 28 
West Modified EBITDA$315 $215 
Commodity margins$128 $2 
37


Management’s Discussion and Analysis (Continued)
Three months ended March 31, 2021 vs. three months ended March 31, 2020
West Modified EBITDA increased primarily due to higher Commodity margins, partially offset by lower Service revenues.
Service revenues decreased primarily due to:
•A $26 million decrease associated with lower gathering and processing rates, primarily in the Haynesville Shale region due to a customer contract change and in the Piceance region driven primarily by unfavorable commodity pricing;
•An $11 million decrease associated with lower volumes, primarily due to production declines in the Haynesville Shale region. The impact of lower gathering volumes in the Eagle Ford Shale region was substantially offset by the recognition of higher MVC revenue;
•A $10 million decrease related to lower deferred revenue amortization primarily in the Barnett Shale region; partially offset by
•A $10 million increase associated with higher MVC revenue, primarily in the Wamsutter region due to timing of recognition;
•A $10 million increase in revenues associated primarily with reimbursable compressor power and fuel purchases due to higher prices related to the impact of severe winter weather, which are offset by similar changes in Other segment costs and expenses.
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 marketing and equity NGLs margins. Marketing margins increased by $122 million primarily due to favorable changes in net realized commodity prices, including the impact of severe winter weather in the first quarter of 2021. Product margins from our equity NGLs increased $4 million, primarily due to higher net realized sales prices.
Other segment costs and expenses decreased primarily due to lower operating expenses including costs related to fewer leased compressors. These decreases are partially offset by higher reimbursable compressor power and fuel purchases which are offset in Service revenues.
Proportional Modified EBITDA of equity-method investments decreased primarily due to lower volumes at OPPL, partially offset by improvements at other equity-method investees.
Other
Three Months Ended March 31,
20212020
(Millions)
Other Modified EBITDA$33 $7 
Three months ended March 31, 2021 vs. three months ended March 31, 2020
Other Modified EBITDA increased primarily due to our recently acquired upstream operations, including the favorable commodity price impact of severe winter weather in the first quarter of 2021. See Note 12 – Segment Disclosures of Notes to Consolidated StatementFinancial Statements.
38


Management’s Discussion and Analysis (Continued)
Management’s Discussion and Analysis of OperationsFinancial Condition and Liquidity
Outlook
As previously discussed in Company Outlook, our growth capital and investment expenditures in 2021 are currently expected to be in a range from $1.0 billion to $1.2 billion. Growth capital spending in 2021 primarily includes Transco expansions, all of which are fully contracted with firm transportation agreements, and projects supporting the Northeast G&P business and opportunities in the Haynesville area. In addition to growth capital and investment expenditures, we also remain committed to projects that maintain our assets for safe and reliable operations, as well as projects that meet legal, regulatory, and/or contractual commitments. We intend to fund substantially all of our planned 2021 capital spending with cash available after paying dividends. We retain the flexibility to adjust planned levels of growth capital and investment expenditures in response to changes in economic conditions or business opportunities.
During the first quarter of 2021, we issued $900 million of new long-term debt to fund the repayment of long-term debt maturing in 2021 and for general corporate purposes. As of March 31, 2021, we have approximately $2.1 billion of long-term debt due within one year. Our potential sources of liquidity available to address these maturities include cash on hand, proceeds from refinancing at attractive long-term rates or from our credit facility, as well as proceeds from asset monetizations.
Liquidity
Based on our forecasted levels of cash flow from operations and other sources of liquidity, we expect to have sufficient liquidity to manage our businesses in 2021. Our potential material internal and external sources and uses of liquidity are as follows:
Sources:
Cash and cash equivalents on hand
Cash generated from operations
Distributions from our equity-method investees
Utilization of our credit facility and/or commercial paper program
Cash proceeds from issuance of debt and/or equity securities
Proceeds from asset monetizations
Uses:
Working capital requirements
Capital and investment expenditures
Product costs
Other operating costs including human capital expenses
Quarterly dividends to our shareholders
Debt service payments, including payments of long-term debt
Distributions to noncontrolling interests
As of March 31, 2021, we have approximately $21.1 billion of long-term debt due after one year. Our potential sources of liquidity available to address these maturities include cash generated from operations, proceeds from refinancing at attractive long-term rates or from our credit facility, as well as proceeds from asset monetizations.
Potential risks associated with our planned levels of liquidity discussed above include those previously discussed in Company Outlook.
 Three Months Ended 
March 31,
 2020 2019
 (Millions)
Modified EBITDA by segment:   
Transmission & Gulf of Mexico$662
 $636
Northeast G&P369
 299
West215
 256
Other7
 (4)
 1,253
 1,187
Accretion expense associated with asset retirement obligations for nonregulated operations(10) (9)
Depreciation and amortization expenses(429) (416)
Impairment of goodwill(187) —
Equity earnings (losses)22
 80
Impairment of equity-method investments(938) (74)
Other investing income (loss) – net3
 1
Proportional Modified EBITDA of equity-method investments(192) (190)
Interest expense(296) (296)
(Provision) benefit for income taxes204
 (69)
Net income (loss)$(570) $214
39


Management’s Discussion and Analysis (Continued)
As of March 31, 2021, we had a working capital deficit of $1.038 billion, including cash and cash equivalents and long-term debt due within one year. Our available liquidity is as follows:
Available LiquidityMarch 31, 2021
(Millions)
Cash and cash equivalents$1,126 
Capacity available under our $4.5 billion credit facility, less amounts outstanding under our $4 billion commercial paper program (1)4,500 
$5,626 
(1)In managing our available liquidity, we do not expect a maximum outstanding amount in excess of the capacity of our credit facility inclusive of any outstanding amounts under our commercial paper program. We had no commercial paper outstanding as of March 31, 2021. Through March 31, 2021, there was no amount outstanding under our commercial paper program and credit facility during 2021. At March 31, 2021, we were in compliance with the financial covenants associated with our credit facility.
Dividends
We increased our regular quarterly cash dividend to common stockholders by approximately 2.5 percent from the $0.40 per share paid in each quarter of 2020, to $0.41 per share paid in March 2021.
Registrations
In February 2021, we filed a shelf registration statement as a well-known seasoned issuer.
Distributions from Equity-Method Investees
The organizational documents of entities in which we have an equity-method investment generally require periodic distributions of their available cash to their members. In each case, available cash is reduced, in part, by reserves appropriate for operating their respective businesses.
Credit Ratings
The interest rates at which we are able to borrow money are impacted by our credit ratings. The current ratings are as follows:
Rating AgencyOutlookSenior Unsecured
Debt Rating
S&P Global RatingsStableBBB
Moody’s Investors ServicePositiveBaa3
Fitch RatingsStableBBB
These credit ratings are included for informational purposes and are not recommendations to buy, sell, or hold our securities, and each rating should be evaluated independently of any other rating. No assurance can be given that the credit rating agencies will continue to assign us investment-grade ratings even if we meet or exceed their current criteria for investment-grade ratios. A downgrade of our credit ratings might increase our future cost of borrowing and would require us to provide additional collateral to third parties, negatively impacting our available liquidity.
40


Management’s Discussion and Analysis (Continued)
Sources (Uses) of Cash
The following table summarizes the sources (uses) of cash and cash equivalents for each of the periods presented (see Notes to Consolidated Financial Statements for the Notes referenced in the table):
Cash FlowThree Months Ended 
March 31,
Category20212020
(Millions)
Sources of cash and cash equivalents:
Operating activities – netOperating$915 $787 
Proceeds from long-term debt (see Note 8)Financing897 2 
Proceeds from credit-facility borrowingsFinancing— 1,700 
Uses of cash and cash equivalents:
Common dividends paidFinancing(498)(485)
Capital expendituresInvesting(260)(306)
Dividends and distributions paid to noncontrolling interestsFinancing(54)(44)
Purchases of and contributions to equity-method investmentsInvesting(14)(30)
Payments of long-term debtFinancing(5)(1,518)
Other sources / (uses) – netFinancing and Investing3 5 
Increase (decrease) in cash and cash equivalents$984 $111 
Operating activities
The factors that determine operating activities are largely the same as those that affect Net income (loss), with the exception of noncash items such as Depreciation and amortization, Provision (benefit) for deferred income taxes, Equity (earnings) losses, Impairment of goodwill, and Impairment of equity-method investments. Our Net cash provided (used) by operating activities for the three months ended March 31, 2021, increased from the same period in 2020 primarily due to higher operating income (excluding noncash items as previously discussed) in 2021.
41

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
General
We are an energy infrastructure company focused on connecting North America’s significant hydrocarbon resource plays to growing markets for natural gas and NGLs through our gas pipeline and midstream business. Our operations are located in the United States.
Our interstate natural gas pipeline strategy is to create value by maximizing the utilization of our pipeline capacity by providing high quality, low cost transportation of natural gas to large and growing markets. Our gas pipeline businesses’ interstate transmission and storage activities are subject to regulation by the FERC and as such, our rates and charges for the transportation of natural gas in interstate commerce, and the extension, expansion or abandonment of jurisdictional facilities and accounting, among other things, are subject to regulation. The rates are established through the FERC’s ratemaking process. Changes in commodity prices and volumes transported have limited near-term impact on these revenues because the majority of cost of service is recovered through firm capacity reservation charges in transportation rates.
The ongoing strategy of our midstream operations is to safely and reliably operate large-scale midstream infrastructure where our assets can be fully utilized and drive low per-unit costs. We focus on consistently attracting new business by providing highly reliable service to our customers. These services include natural gas gathering, processing, treating, and compression, NGL fractionation and transportation, crude oil production handling and transportation, marketing services for NGL, crude oil and natural gas, as well as storage facilities.
Effective January 1, 2020, following an organizational realignment, our interstate natural gas pipeline 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). Consistent with the manner in which our chief operating decision maker evaluates performance and allocates resources, our operations are conducted, managed, and presented within the following reportable segments: Transmission & Gulf of Mexico, Northeast G&P, and West. All remaining business activities as well as corporate activities are included in Other. Our reportable segments are comprised of the following businesses:
Transmission & Gulf of Mexico is comprised of our interstate natural gas pipelines, Transco and Northwest Pipeline, as well as natural gas gathering and processing and crude oil production handling and transportation assets in the Gulf Coast region, including a 51 percent interest in Gulfstar One (a consolidated variable interest entity), which is a proprietary floating production system, a 50 percent equity-method investment in Gulfstream, and a 60 percent equity-method investment in Discovery.
Northeast G&P is comprised of our midstream gathering, processing, and fractionation businesses in the Marcellus Shale region primarily in Pennsylvania, New York, and the Utica Shale region of eastern Ohio, as well as a 65 percent interest in our Northeast JV (a consolidated variable interest entity) which operates in West Virginia, Ohio, and Pennsylvania, a 66 percent interest in Cardinal (a consolidated variable interest entity) which operates in Ohio, a 69 percent equity-method investment in Laurel Mountain, a 58 percent equity-method investment in Caiman II, 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).
West is comprised of our gas gathering, processing, and treating operations in the Rocky Mountain region of Colorado and Wyoming, the Barnett Shale region of north-central Texas, the Eagle Ford Shale region of south Texas, the Haynesville Shale region of northwest Louisiana, and the Mid-Continent region which includes the Anadarko, Arkoma, and Permian basins. This segment also includes our 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 OPPL, a 50 percent equity-method investment in RMM, and a 15 percent equity-method investment in Brazos Permian II. West also included our former 50 percent equity-method investment in Jackalope, which was sold in April 2019.
Other includes minor business activities that are not operating segments, as well as corporate operations.


Management’s Discussion and Analysis (Continued)

Dividends
In March 2020, we paid a regular quarterly dividend of $0.40 per share.
Overview of Three Months Ended March 31, 2020
Net income (loss) attributable to The Williams Companies, Inc., for the three months ended March 31, 2020, decreased $712 millioncompared to the three months ended March 31, 2019, reflecting:
•
An increase of $864 million of Impairment of equity-method investments;
•
$187 million of Impairment of goodwill;
A $58 million decrease in equity earnings, primarily due to our share of an impairment of goodwill recorded by an equity method investee;
$19 million of lower commodity margins.
These unfavorable changes were partially offset by:
•
$34 million of increased Service revenues;
•
$15 million of lower Selling, general, and administrative expenses;
•
A $72 million favorable change in Net income (loss) attributable to noncontrolling interests primarily due to the noncontrolling interests’ share of the goodwill impairment;
A $273 million decrease in provision for income taxes driven by lower pre-tax income.
The following discussion and analysis ofresults of operations and financial condition and liquidity should be read in conjunction with the consolidated financial statements and notes thereto of this Form 10‑Q and our Annual Report on Form 10-K dated February 24, 2020.
Recent Developments
COVID-19
The outbreak of novel coronavirus (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 are taking 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 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 access the debt market, if necessary, and continue to have significant levels of unused capacity on our revolving credit facility.
We have implemented remote working arrangements where possible and restricted 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.


Management’s Discussion and Analysis (Continued)

Crude Oil Price Decline
In recent months, crude oil prices have 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 has also impacted NGL prices. While our businesses do not have direct exposure to crude oil prices, the 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 40 percent during the first quarter of 2020, including a 26 percent decline in the month of March. As a result, our board of directors approved a limited duration shareholder rights agreement. (See Note 10 – 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 11 – 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 11 – 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 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 result in less associated natural gas production, which could drive more demand for natural gas produced from gas-directed basins we serve.
Our deepwater transportation business is supported mostly by major oil producers with a long-cycle perspective.
NGL Margins
Per-unit non-ethane margins were approximately 24 percent lower in the first three months of 2020 compared to the same period in 2019 primarily due to a 35 percent decrease in per-unit non-ethane sales prices, partially offset by 42 percent 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 2020 is further discussed in the following Company Outlook.


Management’s Discussion and Analysis (Continued)

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 were not 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, 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 will become effective on June 1, 2020. As of March 31, 2020, we have provided a $248 million reserve for rate refunds related to increased rates collected since March 2019, which we believe is adequate for any refunds that may be required.
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 2020 includes a continued focus on earnings and cash flow growth, while continuing to improve leverage metrics and control operating costs. Many of our producer customers are impacted by extremely low energy commodity prices, which may result in a decrease in drilling activity and the temporary shut-in of existing production in certain oil-directed and liquids-rich areas. We are responding by reducing the pace of our capital growth 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. 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 interest 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 pads, conditioning and connecting the production to 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 services enable producers to generate operating cash flows.
In 2020, our operating results are expected to include lower deferred revenue amortization related to the West’s Barnett Shale region and Gulfstar in the Eastern Gulf region. We also expect lower NGL margins overall and lower fee revenues in the West and Eastern Gulf region primarily from a decrease in drilling activity associated with a significant reduction in crude oil prices. Northeast results are expected to increase from higher gathering and processing volumes. If current market conditions persist, the temporary shut-in of existing onshore and offshore production in certain oil-directed and liquids-rich areas will decrease our results. We expect increases from Transco’s and Northwest Pipeline’s recent expansion projects placed in-service and Transco’s rate settlement as well as a full year contribution from the Norphlet project in the Eastern Gulf region. Additionally, we expect operating results will benefit from lower expenses associated with our recently implemented organizational realignment.
Our growth capital and investment expenditures in 2020 are expected to be in a range from $1.1 billion to $1.3 billion. Growth capital spending in 2020 primarily includes Transco expansions, all of which are fully contracted with firm transportation agreements, and our Bluestem NGL pipeline project in the 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.


Management’s Discussion and Analysis (Continued)

Potential risks and obstacles that could impact the execution of our plan include:
Continued negative impacts of COVID-19 driving a global recession, which could result in further downturns in financial markets and commodity prices, as well as impact demand for natural gas and related products;
Opposition to, and legal regulations affecting, our infrastructure projects, including the risk of delay or denial in permits and approvals needed for our projects;
Counterparty credit and performance risk;
Unexpected significant increases in capital expenditures or delays in capital project execution;
Unexpected changes in customer drilling and production activities, which could negatively impact gathering and processing volumes;
Lower than anticipated demand for natural gas and natural gas products which could result in lower than expected volumes, energy commodity prices, and margins;
General economic, financial markets, or further industry 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, 2019, as filed with the SEC on February 24, 2020, as supplemented by the disclosure in Part II, Item 1A. Risk Factors in this Quarterly Report on Form 10-Q.
We seek to maintain a strong financial position and liquidity, as well as manage a diversified portfolio of energy infrastructure assets which continue to serve key growth markets and supply basins in the United States.
Expansion Projects
Our ongoing major expansion projects include the following:
Transmission & Gulf of Mexico
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 an 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. We placed Phase II into service on May 1, 2020. Together, the first two phases of the project increased capacity by 1,025 Mdth/d.
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 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 denied, without prejudice, Transco’s applications for such approvals. We have 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 fall of 2021, assuming timely receipt of these remaining approvals. The project is expected to increase capacity by 400 Mdth/d.


Management’s Discussion and Analysis (Continued)

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 the project into service in late 2020. The project is expected to increase capacity by 296 Mdth/d.
Leidy South
In July 2019, we filed an application with 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 the project into service as early as the fourth quarter of 2021, assuming timely receipt of all necessary regulatory approvals. The project is expected to increase capacity by 582 Mdth/d.
West
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 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 a 110-mile pipeline extension of their existing NGL pipeline system that will have an initial capacity of 120 Mbbls/d. 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 placed into service during the first quarter of 2021.
Critical Accounting Estimates
Equity-Method Investments
We monitor our equity-method investments for any indications that the carrying value may have experienced an other-than-temporary decline in value.
In the first quarter of 2020, we observed a 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, determined in accordance with Accounting Standards Codification (ASC) Topic 323, “Investments - Equity Method and Joint Ventures.”
As a result, we estimated the fair value of these equity-method investments in accordance with ASC Topic 820, “Fair Value Measurement,” as of the March 31, 2020, measurement date. In assessing the fair value, 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. Although there have been recent improvements subsequent to March 31, 2020, it is difficult to predict the timing and degree of any sustained recovery. As a result, we have determined that there are other-than-temporary declines in the fair value of certain of our equity-method investments, resulting in recognized impairments totaling $938 million. (See Note 11 – 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


Management’s Discussion and Analysis (Continued)

total was primarily comprised of impairments of our investment in Caiman II and predominantly wet gas gathering systems that are part of the 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.
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 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 and, as previously discussed, were significantly impacted by the recent unfavorable macroeconomic changes. 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 which 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. In our assessments, we considered the impact of the 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.







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 months ended March 31, 2020, compared to the three months ended March 31, 2019. The results of operations by segment are discussed in further detail following this consolidated overview discussion.
 Three Months Ended 
March 31,		    
 2020 2019 $ Change* % Change*
 (Millions)    
Revenues:       
Service revenues$1,474
 $1,440
 +34
 +2 %
Service revenues – commodity consideration28
 64
 -36
 -56 %
Product sales411
 550
 -139
 -25 %
Total revenues1,913
 2,054
    
Costs and expenses:       
Product costs396
 525
 +129
 +25 %
Processing commodity expenses13
 40
 +27
 +68 %
Operating and maintenance expenses337
 340
 +3
 +1 %
Depreciation and amortization expenses429
 416
 -13
 -3 %
Selling, general, and administrative expenses113
 128
 +15
 +12 %
Impairment of goodwill187
 —
 -187
 NM
Other (income) expense – net7
 44
 +37
 +84 %
Total costs and expenses1,482
 1,493
    
Operating income (loss)431
 561
    
Equity earnings (losses)22
 80
 -58
 -73 %
Impairment of equity-method investments(938) (74) -864
 NM
Other investing income (loss) – net3
 1
 +2
 +200 %
Interest expense(296) (296) —
 — %
Other income (expense) – net4
 11
 -7
 -64 %
Income (loss) before income taxes(774) 283
    
Provision (benefit) for income taxes(204) 69
 +273
 NM
Net income (loss)(570) 214
    
Less: Net income (loss) attributable to noncontrolling interests(53) 19
 +72
 NM
Net income (loss) attributable to The Williams Companies, Inc.$(517) $195
    

*+ = 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.
Three months ended March 31, 2020 vs. three months ended March 31, 2019
Service revenuesincreased primarily due to higher Northeast revenues driven by higher volumes and the March 2019 consolidation of UEOM, as well as higher transportation fee revenues at Transco primarily associated with its rate case settlement and expansion projects placed in service in 2019. This increase was partially offset by the expiration of an MVC agreement in the Barnett Shale region and lower deferred revenue amortization at Gulfstar.
Service revenues – commodity consideration decreased primarily due to lower equity NGL processing volumes due to higher ethane rejection and less producer drilling activity in addition to lower commodity prices. These revenues represent consideration we receive in the form of commodities as full or partial payment for processing services provided. Most of these NGL volumes are sold within the month processed and therefore are offset in Product costs below.


Management’s Discussion and Analysis (Continued)

Product salesdecreased primarily due to lower NGL and natural gas prices associated with our marketing and equity NGL sales activities, as well as lower volumes associated with our equity NGL sales activities, partially offset by higher marketing volumes. 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 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 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 volumes and lower natural gas prices.
Operating and maintenance expenses decreased due to lower maintenance and employee-related expenses, substantially offset by higher expenses related to the consolidation of UEOM in March 2019.
Depreciation and amortization expenses increased primarily due to the March 2019 consolidation of UEOM and new assets placed in service, partially offset by lower expense related to assets that became fully depreciated in the fourth quarter of 2019.
Selling, general, and administrative expenses decreased primarily due to lower employee-related expenses.
Impairment of goodwill reflects the goodwill impairment charge at Northeast G&P in 2020 (see Note 11 – Fair Value Measurements and Guarantees of Notes to Consolidated Financial Statements).
The favorable change in Other (income) expense – net within Operating income (loss) includes net favorable changes to regulatory assets and liabilities primarily associated with Transco’s rate case settlement, as well as the absence of both a 2019 impairment of a certain asset at West and a 2019 unfavorable regulatory asset adjustment at Other.
The unfavorable change in Operating income (loss) includes the 2020 impairment of goodwill at Northeast G&P, lower deferred revenue amortization in the West and at Gulfstar, and unfavorable commodity margins primarily reflecting lower NGL sales prices. The unfavorable change was partially offset by higher volumes in the Northeast, the favorable impacts of the consolidation of UEOM, and Transco's rate case settlement.
Equity earnings (losses) decreased primarily due to our share of the 2020 impairment of goodwill at RMM (see Note 5 – Investing Activities of Notes to Consolidated Financial Statements). This decrease was partially offset by an increase at Appalachia Midstream Investments.
Impairment of equity-method investments includes impairments of various equity-method investments in 2020, partially offset by the absence of a 2019 impairment of UEOM (see Note 11 – Fair Value Measurements and Guarantees of Notes to Consolidated Financial Statements).
The unfavorable change in Other income (expense) – net below Operating income (loss) is primarily due to a 2020 pension plan settlement charge.
Provision (benefit) for income taxes changed favorably primarily due to lower pre-tax income. See Note 6 – Provision (Benefit) for Income Taxes of Notes to Consolidated Financial Statements for a discussion of the effective tax rate compared to the federal statutory rate for both periods.
The favorable change in Net income (loss) attributable to noncontrolling interests is primarily due to the goodwill impairment and lower Gulfstar results, partially offset by increased results related to the formation of the Northeast JV in June 2019.


Management’s Discussion and Analysis (Continued)

Period-Over-Period Operating Results - Segments
We evaluate segment operating performance based upon Modified EBITDA. Note 13 – 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 
March 31,
 2020 2019
 (Millions)
Service revenues$829
 $823
Service revenues – commodity consideration
5
 13
Product sales52
 82
Segment revenues886
 918
    
Product costs(52) (82)
Processing commodity expenses(2) (5)
Other segment costs and expenses(214) (237)
Proportional Modified EBITDA of equity-method investments44
 42
Transmission & Gulf of Mexico Modified EBITDA$662
 $636
    
Commodity margins$3
 $8
Three months ended March 31, 2020 vs. three months ended March 31, 2019
Transmission & Gulf of Mexico Modified EBITDA increased primarily due to favorable changes to Other segment costs and expenses and increased Service revenues.
Service revenues increased primarily due to a $32 million increase in Transco’s natural gas transportation revenues primarily driven by higher revenues from Transco’s rate case settlement and expansion projects placed in service in 2019. This increase was partially offset by $29 million lower gathering, processing, and other transportation fees primarily due to lower deferred revenue amortization at Gulfstar.
The net sum of Service revenues – commodity consideration, Product sales, Product costs, and Processing commodity expenses comprise our commodity margins. Our commodity margins associated with our equity NGLs decreased $4 million primarily driven by unfavorable NGL sales prices. Additionally, the decrease in Product sales includes a $16 million decrease in commodity marketing sales and $6 million lower system management gas sales primarily due to lower NGL prices. Marketing 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 decreased primarily due to net favorable changes associated with regulatory assets and liabilities primarily driven by the terms of settlement in Transco’s general rate case, as well as decreased maintenance costs and lower employee-related costs.


Management’s Discussion and Analysis (Continued)

Northeast G&P
 Three Months Ended 
March 31,
 2020 2019
 (Millions)
Service revenues$358
 $276
Service revenues – commodity consideration
2
 5
Product sales29
 47
Segment revenues389
 328
    
Product costs(29) (47)
Processing commodity expenses(1) (3)
Other segment costs and expenses(110) (101)
Proportional Modified EBITDA of equity-method investments120
 122
Northeast G&P Modified EBITDA$369
 $299
    
Commodity margins$1
 $2
Three months ended March 31, 2020 vs. three months ended March 31, 2019
Northeast G&P Modified EBITDA increased primarily due to higher Service revenues 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, in addition to increased Proportional Modified EBITDA of equity-method investments from higher volumes at Appalachia Midstream Investments and Caiman II.
Service revenues increased primarily due to:
•
A $68 million increase at the Northeast JV, including a $32 million increase associated with the consolidation of UEOM, as previously discussed, $8 million associated with higher UEOM volumes, and $20 million higher gathering, processing, fractionation, and transportation revenues from our Ohio Valley Midstream business due to higher volumes. Additionally, revenues increased related to $8 million of higher amounts for reimbursable electricity expenses, which are offset by similar changes in electricity charges, reflected above in Other segment costs and expenses;
An $8 million increase in gathering revenues at Cardinal primarily due to higher rates;
A $6 million increase in gathering revenues at Susquehanna Supply Hub.
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.
Other segment costs and expenses increased primarily due to the consolidation of UEOM in addition to higher reimbursable electricity expenses. These increases are partially offset by lower costs related to various maintenance and repairs and employee expenses.
Proportional Modified EBITDA of equity-method investments decreased $16 million as a result of the consolidation of UEOM, as previously discussed. This decrease was substantially offset by increases at Appalachia Midstream Investments and Caiman II driven by higher volumes.



Management’s Discussion and Analysis (Continued)

West
 Three Months Ended 
March 31,
 2020 2019
 (Millions)
Service revenues$311
 $359
Service revenues – commodity consideration
21
 46
Product sales359
 479
Segment revenues691
 884
    
Product costs(368) (475)
Processing commodity expenses(10) (31)
Other segment costs and expenses(126) (148)
Proportional Modified EBITDA of equity-method investments28
 26
West Modified EBITDA$215
 $256
    
Commodity margins$2
 $19
Three months ended March 31, 2020 vs. three months ended March 31, 2019
West Modified EBITDA decreased primarily due to lower Service revenues and lower Commodity margins due to unfavorable commodity prices, partially offset by lower Other segment costs and expenses.
Service revenues decreased primarily due to:
A $38 million decrease driven by lower deferred revenue amortization and MVC deficiency fee revenues associated with the expiration of the MVC agreement in the Barnett Shale region;
A $23 million decrease associated with lower rates driven by lower commodity pricing in the Barnett Shale region and the expiration of a cost-of-service period on a contract in the Mid-Continent region;
A $12 million decrease associated with lower volumes;
A $26 million increase in the Eagle Ford Shale region.
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. Product margins from our equity NGLs decreased $4 million primarily due to:
A $16 million decrease associated with lower sales volumes primarily due to 87 percent lower ethane sales volumes primarily due to higher ethane rejection as well as 18 percent lower non-ethane sales volumes primarily due to less producer drilling activity;
A $10 million decrease associated with lower sales prices primarily due to 32 percent lower average net realized per-unit non-ethane sales prices;
A $22 million increase related to a decrease in natural gas purchases associated with lower equity NGL production volumes and lower natural gas prices.
Additionally, marketing margins decreased by $13 million primarily due to unfavorable changes in prices. The decrease in Product sales includes an $88 million decrease in marketing sales, which is due to lower sales prices, partially offset by higher marketing sales volumes. These decreases are substantially offset in Product costs.


Management’s Discussion and Analysis (Continued)

Other segment costs and expenses decreased primarily due the absence of a $12 million 2019 impairment of assets and lower operating and maintenance and general and administrative costs due primarily to lower employee-related costs and maintenance expenses.
Proportional Modified EBITDA of equity-method investments increased primarily due to increased activity at the RMM equity-method investment, partially offset by the absence of the Jackalope equity-method investment sold in April 2019.
Other
 Three Months Ended March 31,
 2020 2019
 (Millions)
Other Modified EBITDA$7
 $(4)
Three months ended March 31, 2020 vs. three months ended March 31, 2019
Other Modified EBITDA increased primarily due to the absence of a first-quarter 2019 $12 million unfavorable adjustment to a regulatory asset associated with an increase in Transco’s estimated deferred state income tax rate following the merger transaction wherein we acquired all of the outstanding common units held by others of our former publicly traded master limited partnership.



Management’s Discussion and Analysis (Continued)

Management’s Discussion and Analysis of Financial Condition and Liquidity
Outlook
As previously discussed in Company Outlook, our growth capital and investment expenditures in 2020 are currently expected to be in a range from $1.1 billion to $1.3 billion. Growth capital spending in 2020 includes Transco expansions, all of which are fully contracted with firm transportation agreements, and our Bluestem NGL pipeline project in the 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. We intend to fund substantially all of our planned 2020 capital spending with cash available after paying dividends. We retain the flexibility to adjust planned levels of growth capital and investment expenditures in response to changes in economic conditions or business opportunities.
During the first quarter of 2020, we retired $1.514 billion of long-term debt utilizing proceeds borrowed under our credit facility. We have an additional $607 million of long-term debt maturing in 2020. Potential sources of liquidity available to address our debt maturities include proceeds from the issuance of new debt, available capacity under our credit facility, and proceeds from any asset monetizations.
Liquidity
Based on our forecasted levels of cash flow from operations and other sources of liquidity, we expect to have sufficient liquidity to manage our businesses in 2020. Our potential material internal and external sources and uses of liquidity are as follows:
Sources:
Cash and cash equivalents on hand
Cash generated from operations
Distributions from our equity-method investees
Utilization of our credit facility and/or commercial paper program
Cash proceeds from issuance of debt and/or equity securities
Proceeds from asset monetizations
Contributions from noncontrolling interests
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
Potential risks associated with our planned levels of liquidity discussed above include those previously discussed in Company Outlook.


Management’s Discussion and Analysis (Continued)

As of March 31, 2020, we had a working capital deficit of $551 million, including cash and cash equivalents and long-term debt due within one year. Our available liquidity is as follows:
Available LiquidityMarch 31, 2020
 (Millions)
Cash and cash equivalents$400
Capacity available under our $4.5 billion credit facility, less amounts outstanding under our $4 billion commercial paper program (1)2,800
 $3,200
(1)In managing our available liquidity, we do not expect a maximum outstanding amount in excess of the capacity of our credit facility inclusive of any outstanding amounts under our commercial paper program. We had no commercial paper outstanding as of March 31, 2020. Through March 31, 2020, the highest amount outstanding under our commercial paper program and credit facility during 2020 was $1.7 billion. At March 31, 2020, we were in compliance with the financial covenants associated with our credit facility. Borrowing capacity available under our credit facility as of May 1, 2020, was $2.8 billion.
Dividends
We increased our regular quarterly cash dividend to common stockholders by approximately 5 percent from the previous quarterly cash dividends of $0.38 per share paid in each quarter of 2019, to $0.40 per share for the quarterly cash dividends paid in March 2020.
Registrations
In February 2018, we filed a shelf registration statement as a well-known seasoned issuer. In August 2018, we filed a prospectus supplement for the offer and sale from time to time of shares of our common stock having an aggregate offering price of up to $1 billion. These sales are to be made over a period of time and from time to time in transactions at then-current prices. Such sales are to be made pursuant to an equity distribution agreement between us and certain entities who may act as sales agents or purchase for their own accounts as principals at a price agreed upon at the time of the sale.
Distributions from Equity-Method Investees
The organizational documents of entities in which we have an equity-method investment generally require distribution of their available cash to their members on a quarterly basis. In each case, available cash is reduced, in part, by reserves appropriate for operating their respective businesses.
Credit Ratings
The interest rates at which we are able to borrow money are impacted by our credit ratings. The current ratings are as follows:
Rating AgencyOutlook
Senior Unsecured
Debt Rating
S&P Global RatingsStableBBB
Moody’s Investors ServiceStableBaa3
Fitch RatingsStableBBB-
These credit ratings are included for informational purposes and are not recommendations to buy, sell, or hold our securities, and each rating should be evaluated independently of any other rating. No assurance can be given that the credit rating agencies will continue to assign us investment-grade ratings even if we meet or exceed their current criteria for investment-grade ratios. A downgrade of our credit ratings might increase our future cost of borrowing and would require us to provide additional collateral to third parties, negatively impacting our available liquidity.


Management’s Discussion and Analysis (Continued)

Sources (Uses) of Cash
The following table summarizes the sources (uses) of cash and cash equivalents for each of the periods presented (see Notes to Consolidated Financial Statements for the Notes referenced in the table):
 Cash Flow Three Months Ended 
March 31,
 Category 2020 2019
   (Millions)
Sources of cash and cash equivalents:     
Operating activities – netOperating $787
 $775
Proceeds from credit-facility borrowingsFinancing 1,700
 700
Proceeds from commercial paper – netFinancing —
 1,014
      
Uses of cash and cash equivalents:     
Payments of long-term debtFinancing (1,518) (4)
Common dividends paidFinancing (485) (460)
Capital expendituresInvesting (306) (422)
Dividends and distributions paid to noncontrolling interestsFinancing (44) (41)
Purchases of and contributions to equity-method investmentsInvesting (30) (99)
Payments on credit-facility borrowingsFinancing —
 (860)
Purchases of businesses, net of cash acquired (see Note 2)Investing —
 (727)
      
Other sources / (uses) – netFinancing and Investing 7
 (1)
Increase (decrease) in cash and cash equivalents  $111
 $(125)
Operating activities
The factors that determine operating activities are largely the same as those that affect Net income (loss), with the exception of noncash items such as Depreciation and amortization, Provision (benefit) for deferred income taxes, Equity (earnings) losses, Impairment of goodwill, and Impairment of equity-method investments. Our Net cash provided (used) by operating activities for the three months ended March 31, 2020, increased from the same period in 2019 primarily due to higher operating income (excluding noncash items as previously discussed) in 2020.
Off-Balance Sheet Arrangements and Guarantees of Debt or Other Commitments
We have various other guarantees and commitments which are disclosed in Note 4 – Variable Interest Entities, Note 11 – Fair Value Measurements and Guarantees, and Note 12 – Contingent Liabilities of Notes to Consolidated Financial Statements. We do not believe these guarantees and commitments or the possible fulfillment of them will prevent us from meeting our liquidity needs.


Item 3. Quantitative and Qualitative Disclosures About Market Risk
Interest Rate Risk
Our current interest rate risk exposure is related primarily to our debt portfolio and has not materially changed during the first three months of 2020.2021.

Item 4. Controls and Procedures
Our management, including our Chief Executive Officer and Chief Financial Officer, does not expect that our disclosure controls and procedures (as defined in Rules 13a - 15(e) and 15d - 15(e) of the Securities Exchange Act of 1934, as amended) (Disclosure Controls) or our internal control over financial reporting (Internal Controls) will prevent all errors and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within the company have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty, and that breakdowns can occur because of simple error or mistake. Additionally, controls can be circumvented by the individual acts of some persons, by collusion of two or more people, or by management override of the control. The design of any system of controls also is based in part upon certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions. Because of the inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and not be detected. We monitor our Disclosure Controls and Internal Controls and make modifications as necessary; our intent in this regard is that the Disclosure Controls and Internal Controls will be modified as systems change and conditions warrant.
Evaluation of Disclosure Controls and Procedures
An evaluation of the effectiveness of the design and operation of our Disclosure Controls was performed as of the end of the period covered by this report. This evaluation was performed under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer. Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that these Disclosure Controls are effective at a reasonable assurance level.
Changes in Internal Control Over Financial Reporting
There have been no changes during the first quarter of 20202021 that have materially affected, or are reasonably likely to materially affect, our Internal Control over Financial Reporting.
PART II. OTHER INFORMATION
Item 1. Legal Proceedings
Environmental
Certain reportable legal proceedings involving governmental authorities under federal, state, and local laws regulating the discharge of materials into the environment are described below. While it is not possible for us to predict the final outcome of the proceedings whichthat are still pending, we do not anticipate a material effect on our consolidated financial position if we receive an unfavorable outcome in any one or more of such proceedings.
On June 13, 2013, an explosion and fire occurred at our formerly owned Geismar olefins plant and rendered the facility temporarily inoperable (Geismar Incident). On October 21, 2013, the EPA, Region 6, issued an Inspection Report pursuant to the Clean Air Act’s Risk Management Program following its inspection of the facility on June 24 through June 28, 2013. The report notes the EPA’s preliminary determinations about the facility’s documentation regarding process safety, process hazard analysis, as well as operating procedures, employee training, and other matters.


On June 16, 2014, we received Our threshold for disclosing material environmental legal proceedings involving a request for information related to the Geismar Incident from the EPA under Section 114 of the Clean Air Act to which we responded on August 13, 2014. We have worked with the agency to resolve these matters and in the second half of 2019, entered into a Stipulation of Settlement, which includes a penalty of $750,000 that will be due within thirty days of the Court’s entry of the settlement. The Court set a fairness hearing on the settlement for December 11, 2019. Prior to the scheduled hearing, the Court continued the hearing without setting a new date.
On May 5, 2017, we entered into a Consent Order with the Georgia Department of Natural Resources, Environmental Protection Division (GADNR) pertaining to alleged violations of the Georgia Water Quality Control Act and associated rules arising from a permit issued by GADNR for construction of Transco’s Dalton expansion project. Pursuant to the Consent Order, we paid a fine of $168,750 and agreed to a Corrective Action Plan. On March 26, 2020, the GADNR issued a closure letter to Transco approving the final Corrective Action Plan implementation and acknowledging that all conditions of the Consent Order have been achieved.governmental authority where potential monetary sanctions are involved is $1 million.
On January 19, 2016, we received a Notice of Noncompliance with certain Leak Detection and Repair (LDAR) regulations under the Clean Air Act at our Moundsville Fractionator Facility from the EPA, Region 3. Subsequently,
42

the EPA alleged similar violations of certain LDAR regulations at our Oak Grove Gas Plant. On March 19, 2018, we received a Notice of Violation of certain LDAR regulations at our former Ignacio Gas Plant from the EPA, Region 8, following an on-site inspection of the facility. On March 20, 2018, we also received a Notice of Violation of certain LDAR regulations at our Parachute Creek Gas Plant from the EPA, Region 8. All Noticessuch notices were subsequently referred to a common attorney at the Department of Justice (DOJ). We are exploring global resolution of the claims at these facilities, as well as alleged violations at certain other facilities, with the DOJ. Global resolution would include both payment of a civil penalty and an injunctive relief component. We continue to work with the DOJ and the other agencies to resolve these claims, whether individually or globally, and negotiations are ongoing.
Other environmental matters called for by this Item are described under the caption “Environmental Matters” in Note 1211 – Contingent Liabilities of Notes to Consolidated Financial Statements included under Part I, Item 1. Financial Statements of this report, which information is incorporated by reference into this Item.
Other litigation
The additional information called for by this Item is provided in Note 129 – Stockholders’ Equity and Note 11 – Contingent Liabilities of Notes to Consolidated Financial Statements included under Part I, Item 1. Financial Statements of this report, which information is incorporated by reference into this Item.
Item 1A. Risk Factors

Part I, Item 1A. Risk Factors in our Annual Report on Form 10-K for the year ended December 31, 2019,2020, includes risk factors that could materially affect our business, financial condition, or future results. Those Risk Factors have not materially changed, except that they are supplemented or modified bychanged.
Item 5. Other Information
On April 28, 2021, we and Williams Field Services Group, LLC, an indirect wholly owned subsidiary of ours (Williams FSG), entered into an Equity Purchase Agreement (the Purchase Agreement) with Southern Company Gas Investments, Inc. (SECC Seller), Sequent Holdings, LLC, (SEM LP Seller), Sequent, LLC (SEM GP Seller and, together with SECC Seller and SEM LP Seller, the following risk factors:

Prices forSellers) and Southern Company Gas (Seller Parent), pursuant to which the Sellers have agreed to sell, and Williams FSG has agreed to buy, (i) a ninety-nine percent limited partnership interest in Sequent Energy Management, L.P. (SEM), (ii) a one percent general partner interest in SEM, and (iii) all of the outstanding shares of common stock of Sequent Energy Canada Corp. (SECC and together with SEM, the Companies). The Companies provide natural gas NGLs, oil,marketing and logistics services. The purchase price is $50 million plus working capital acquired. The Base Purchase Price as defined in the Purchase Agreement, which includes a $60 million target for acquired working capital, is $110 million, subject to adjustment for actual working capital relative to the target as well as certain other commodities, are volatilecustomary adjustments.

The Purchase Agreement contains customary (i) representations and this volatility haswarranties, (ii) covenants, including with respect to actions taken prior to the closing, cooperation with respect to regulatory issues, and could continue to adversely affect our financial condition, results of operations, cash flows, access to capital,information, and ability(iii) indemnification provisions. Williams FSG will obtain a customary buyer’s representation and warranty insurance policy. The Purchase Agreement is subject to maintaincustomary closing conditions, including the expiration or grow our businesses.termination of the applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976.
Our revenues, operating results, future rate
We have agreed to guarantee the obligations of growth,Williams FSG under the Purchase Agreement. At closing, we will also issue a payment performance guarantee to Seller Parent equal to Seller Parent’s outstanding guarantee obligation with respect to the Companies’ payment performance from the period after the transaction closes until Seller Parent is released from those obligations. We anticipate issuing replacement guarantees directly to the Companies’ counterparties to obtain such release of Seller Parent. The total amount of such obligations varies based on changes in natural gas prices, market conditions, and the valuenumber of certain componentsactive contracts and transactions of the Companies with counterparties. We anticipate combined volumes from the Companies’ business and our businesses depend primarily upon the prices ofexisting natural gas NGLs, oil, or other commodities, andmarketing business will exceed 8 Bcf/d, which we believe would be in the differences between pricestop five of these commodities and could be materially adversely affected by an extended period of low commodity prices, or a decline in commodity prices. Price volatility has and could continue to impact both the amount we receive for our products and services and the volume of products and services we sell. Prices affect the amount of cash flow available for capital expenditures and our ability to borrow money or raise additional capital. Price volatility has and could continue to have an adverse effect on our business, results of operations, financial condition, and cash flows.North American natural gas marketers.
43


The markets for natural gas, NGLs, oil, and other commodities are likely to continue to be volatile. As an example, the recent “oil price war” between Russia and Saudi Arabia combined with existing oil production,Purchase Agreement contains certain termination rights, including by domestic producers, and the rapid drop in demand for oil due to the economic impactmutual written consent of the COVID-19 pandemic resulted in a


significant oversupply of oil and negatively impacted pricing. Wide fluctuations in prices might result from oneparties or more factors beyond our control, including:
Imbalances in supply and demand whether rising from worldwide or domestic supplies of and demand for natural gas, NGLs, oil, and related commodities;

Turmoil inif, subject to certain conditions, the Middle East and other producing regions;

The activities of the Organization of Petroleum Exporting Countries (OPEC) and other countries, whether acting independently of or informally aligned with OPEC, which have significant oil, natural gas or other commodity production capabilities including Russia;

The level of consumer demand;

The price and availability of other types of fuels or feedstocks;

The availability of pipeline capacity;

Supply disruptions, including plant outages and transportation disruptions;

The price and quantity of foreign imports and domestic exports of natural gas and oil;

Domestic and foreign governmental regulations and taxes;

The credit of participants in the markets where products are bought and sold.

We face risks related to the COVID-19 pandemic and other health epidemics.

The global outbreak of the novel coronavirus (COVID-19) is currently impacting countries, communities, supply chains, and markets. We provide a critical service to our customers, which means that it is paramount that we keep our employees safe. To date, COVID-19closing has not had a material impactoccurred on our business operations. However, we cannot predict whether, andor before August 26, 2021. We expect closing to occur during the extent to which, COVID-19 will have a material impact on our business, including our liquidity, financial condition, and resultsthird quarter of operations. COVID-19 could pose a risk to our employees, our customers, our suppliers, and the communities in which we operate, which could negatively impact our business. To the extent that our access to the capital markets is adversely affected by COVID-19, we may need to consider alternative sources of funding for our operations and for working capital, any of which could increase our cost of capital. Measures to try to contain the virus, such as travel bans and restrictions, quarantines, shelter in place orders, and shutdowns, may cause us to experience operational delays or to delay plans for growth. The extent to which COVID-19 may impact our business will depend on future developments, which are highly uncertain and cannot be predicted, including new information concerning the severity of COVID-19 and the actions taken to contain it or treat its impact, among others.2021.

To the extent the COVID-19 pandemic adversely affects our business and financial results, it may also have the effect of heightening many of the other factors described in the Risk Factors disclosed in Part I, Item 1A. Risk Factors in our Annual Report on Form 10-K for the year ended December 31, 2019.

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Item 6.  Exhibits
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—
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).
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 references.reference).
4.1—
Rights Agreement,Fourth Supplemental Indenture, dated as of March 20, 2020,2, 2021, between The Williams Companies, Inc. and ComputershareThe Bank of New York Mellon Trust Company, N.A., as Rights Agent, which includes for Form of Certificate of Designation of Series C Participating Cumulative Preferred Stock of The Williams Companies, Inc. as Exhibit A, the Summary of Terms of the Rights Agreement as Exhibit B and the Form of Rights Certificate as Exhibit Ctrustee (filed on March 20, 20202, 2021 as Exhibit 4.1 to The Williams Companies, Inc.’s current report on Form 8‑K (File No. 001-04174001-04174) and incorporated herein by references)reference).
10.1§*—
Amended Form of 2019 Performance-Based Restricted Stock Unit Agreement among The Williams Companies, Inc. and certain employees and officers
10.2§*—
Form of 2020 2021 Performance-Based Restricted Stock Unit Agreement among The Williams Companies, Inc. and certain employees and officers.
10.3§*31.1*—
Form of 2020 Time-Based Restricted Stock Unit Agreement among The Williams Companies, Inc. and certain employees and officers.
10.4§*—
Form of 2020 Time-Based Restricted Stock Unit Agreement among The Williams Companies, Inc. and certain non-management directors.
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*—
Exhibit
No.
Description
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.
101.INS*—XBRL Instance Document. The instance document does not appear in the interactive data file because its XBRL tags are embedded within the inline XBRL document.
101.SCH*—XBRL Taxonomy Extension Schema.
101.CAL*—XBRL Taxonomy Extension Calculation Linkbase.
45

101.DEF*Exhibit
No.		—Description
101.DEF*—XBRL Taxonomy Extension Definition Linkbase.
101.LAB*—XBRL Taxonomy Extension Label Linkbase.
101.PRE*—XBRL Taxonomy Extension Presentation Linkbase.
104*—Cover Page Interactive Data File. The cover page interactive data file does not appear in the interactive data file because its XBRL tags are embedded within the inline XBRL document (contained in Exhibit 101).
*
*    Filed herewith.
**Furnished herewith.
§Management contract or compensatory plan or arrangement.

**    Furnished herewith.
§    Management contract or compensatory plan or arrangement.


46

SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

THE WILLIAMS COMPANIES, INC.
(Registrant)
/s/ John D. Porter
John D. Porter
Vice President, Controller, and Chief Accounting Officer (Duly Authorized Officer and Principal Accounting Officer)
May 4, 20203, 2021