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


 
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 SeptemberJune 30, 20192020
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

THE WILLIAMS COMPANIES, INC.
(Exact name of registrant as specified in its charter)
Delaware 73-0569878
(State or other jurisdiction of incorporation or organization) (I.R.S. Employer Identification No.)
   
One Williams Center  
TulsaOklahoma 74172-0172
    (Address of principal executive offices) (Zip Code)
Registrant’s telephone number, including area code: (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.
Class Shares Outstanding at October 28, 2019July 30, 2020
Common Stock, $1.00 par value 1,212,048,8361,213,558,476
 



The Williams Companies, Inc.
Index


  Page
Part I. Financial Information
  
Item 1. Financial Statements
  
Consolidated Statement of IncomeOperations – Three and NineSix Months Ended SeptemberJune 30, 20192020 and 20182019
 
6
Consolidated Statement of Comprehensive Income (Loss) – Three and NineSix Months Ended SeptemberJune 30, 20192020 and 20182019
 
7
Consolidated Balance Sheet – SeptemberJune 30, 20192020 and December 31, 20182019
 
8
Consolidated Statement of Changes in Equity – Three and NineSix Months Ended SeptemberJune 30, 20192020 and 20182019
 
9
Consolidated Statement of Cash Flows – NineSix Months Ended SeptemberJune 30, 20192020 and 20182019
 
11
Notes to Consolidated Financial Statements
 
12
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
 
4036
Item 3. Quantitative and Qualitative Disclosures About Market Risk
 
6157
Item 4. Controls and Procedures
 
6157
Part II. Other Information
 
6157
Item 1. Legal Proceedings
 
6157
Item 1A. Risk Factors
 
6358
Item 6. Exhibits
 
6459

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;

Financial condition and liquidity;

Business strategy;

Cash flow from operations or results of operations;

Seasonality of certain business components;

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

Demand for our services.services;

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

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

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

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

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

Inflation, interest rates, and general economic conditions (including future disruptions and volatility in the global credit markets and the impact of these events on customers and suppliers);

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

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

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

Development and rate of adoption of alternative energy sources;

The impact of operational and developmental hazards and unforeseen interruptions;

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

Our exposure to the credit risk of our customers and 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 impacts of operational and developmental hazards and unforeseen interruptions;

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

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

Acts of terrorism, cybersecurity incidents, and related disruptions;

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

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



ChangesInflation, interest rates, and general economic conditions (including future disruptions and volatility in the current geopolitical situation;

Our exposure toglobal credit markets and the credit riskimpact of ourthese events on customers and counterparties;suppliers);

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

The amountability of cash distributions fromthe members of the Organization of Petroleum Exporting Countries and capital requirements of our investmentsother oil exporting nations to agree to and joint ventures in which we participate;maintain oil price and production controls and the impact on domestic production;

Risks associated with weather and natural phenomena, including climate conditions and physical damage to our facilities;Changes in the current geopolitical situation;

ActsWhether we are able to pay current and expected levels of terrorism, cybersecurity incidents, and related disruptions;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, as filed with the SEC on February 21, 2019.24, 2020, as supplemented by the disclosures in Part II, Item 1A. in our Quarterly Report on Form 10-Q for the quarter ended March 31, 2020.



DEFINITIONS

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

Measurements:
Barrel: One barrel of petroleum products that equals 42 U.S. gallons
Bcf: One billion cubic feet of natural gas
Bcf/d: One billion cubic feet of natural gas per day
British Thermal Unit (Btu): A unit of energy needed to raise the temperature of one pound of water by one degree Fahrenheit
Dekatherms (Dth): A unit of energy equal to one million British thermal units
Mbbls/d: One thousand barrels per day
Mdth/d: One thousand dekatherms per day
MMcf/d: One million cubic feet per day
MMdth: One million dekatherms or approximately one trillion British thermal units
MMdth/d: One million dekatherms per day
Tbtu: One trillion British thermal units
Consolidated Entities:
Cardinal: Cardinal Gas Services, L.L.C.
Constitution: Constitution Pipeline Company, LLC
Gulfstar One: Gulfstar One LLC
Northwest Pipeline: Northwest Pipeline LLC
Transco: Transcontinental Gas Pipe Line Company, LLC
UEOM: Utica East Ohio Midstream LLC, previously a Partially Owned Entity until acquiring remaining interest in March 2019
Northeast JV: Ohio Valley Midstream LLC, a partially owned venture that includes our Ohio Valley assets and UEOM
WPZ: Williams Partners L.P. Effective August 10, 2018, we completed our merger with WPZ, pursuant to which we acquired all outstanding common units of WPZ held by others and Williams continued as the surviving entity.
Partially Owned Entities: Entities in which we do not own a 100 percent ownership interest and which, as of SeptemberJune 30, 2019,2020, we account for as an equity-method investment, including principally the following:
Aux Sable: Aux Sable Liquid Products LP
Brazos Permian II: Brazos Permian II, LLC
Caiman II: Caiman Energy II, LLC
Discovery: Discovery Producer Services LLC
Gulfstream: Gulfstream Natural Gas System, L.L.C.
Jackalope: Jackalope Gas Gathering Services, L.L.C., which was sold in April 2019
Laurel Mountain: Laurel Mountain Midstream, LLC
OPPL: Overland Pass Pipeline Company LLC
RMM: Rocky Mountain Midstream Holdings LLC


Government and Regulatory:
EPA: Environmental Protection Agency
Exchange Act, the: Securities and Exchange Act of 1934, as amended
FERC: Federal Energy Regulatory Commission


IRS: Internal Revenue Service
SEC: Securities and Exchange Commission
Other:
Fractionation: The process by which a mixed stream of natural gas liquids is separated into constituent products, such as ethane, propane, and butane
GAAP: U.S. generally accepted accounting principles
LNG: Liquefied natural gas; natural gas which has been liquefied at cryogenic temperatures
MVC: Minimum volume commitment
NGLs: Natural gas liquids; natural gas liquids result from natural gas processing and crude oil refining and are used as petrochemical feedstocks, heating fuels, and gasoline additives, among other applications
NGL margins: NGL revenues less any applicable Btu replacement cost, plant fuel, transportation, and fractionation
WPZ Merger: The August 10, 2018, merger transactions pursuant to which we acquired all outstanding common units of WPZ held by others, merged WPZ into Williams, and Williams continued as the surviving entity




PART I – FINANCIAL INFORMATION

Item 1. Financial Statements

The Williams Companies, Inc.
Consolidated Statement of IncomeOperations
(Unaudited)
Three Months Ended 
 September 30,		 Nine Months Ended 
 September 30,		Three Months Ended 
June 30,		 Six Months Ended 
June 30,
2019 2018 2019 20182020 2019 2020 2019
(Millions, except per-share amounts)(Millions, except per-share amounts)
Revenues:              
Service revenues$1,495
 $1,371
 $4,424

$4,062
$1,446
 $1,489
 $2,920

$2,929
Service revenues – commodity consideration38
 121
 158
 316
25
 56
 53
 120
Product sales466
 811
 1,512

2,104
310
 496
 721

1,046
Total revenues1,999
 2,303
 6,094

6,482
1,781
 2,041
 3,694

4,095
Costs and expenses:  
 


  
 


Product costs434

790

1,442

2,039
271

483

667

1,008
Processing commodity expenses19

30

83

91
15

24

28

64
Operating and maintenance expenses364

389

1,091

1,134
320

387

657

727
Depreciation and amortization expenses435

425

1,275

1,290
430

424

859

840
Selling, general, and administrative expenses130

174

410

436
127

152

240

280
Impairment of certain assets (Note 13)—

—

76

66
Impairment of certain assets (Note 12)—
 64
 —
 76
Impairment of goodwill (Note 12)—

—

187

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

24
6

9

13

41
Total costs and expenses1,371

1,802

4,407

5,080
1,169

1,543

2,651

3,036
Operating income (loss)628

501

1,687

1,402
612

498

1,043

1,059
Equity earnings (losses)93

105

260

279
Equity earnings (losses) (Note 5)108

87

130

167
Impairment of equity-method investments (Note 12)—

2
 (938) (72)
Other investing income (loss) – net (Note 5)(107)
2

(54)
74
1

124

4

125
Interest incurred(303)
(286)
(915)
(856)(299)
(306)
(600)
(612)
Interest capitalized7

16

27

38
5

10

10

20
Other income (expense) – net1

52

19

99
5

7

9

18
Income (loss) before income taxes319

390

1,024

1,036
432

422

(342)
705
Provision (benefit) for income taxes77

190

244

297
117

98

(87)
167
Net income (loss)242

200

780

739
315

324

(255)
538
Less: Net income (loss) attributable to noncontrolling interests21

71

54

323
12

14

(41)
33
Net income (loss) attributable to The Williams Companies, Inc.221

129

726

416
303

310

(214)
505
Preferred stock dividends1
 —
 2
 —
—
 —
 1
 1
Net income (loss) available to common stockholders$220
 $129
 $724
 $416
$303
 $310
 $(215) $504
Basic earnings (loss) per common share:              
Net income (loss)$.18
 $.13
 $.60
 $.47
$.25
 $.26
 $(.18) $.42
Weighted-average shares (thousands)1,212,270
 1,023,587
 1,211,938
 893,706
1,213,601
 1,212,045
 1,213,310
 1,211,769
Diluted earnings (loss) per common share:              
Net income (loss)$.18
 $.13
 $.60
 $.46
$.25
 $.26
 $(.18) $.41
Weighted-average shares (thousands)1,214,165
 1,026,504
 1,213,943
 896,322
1,214,581
 1,214,065
 1,213,310
 1,213,830

See accompanying notes.


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

Three Months Ended 
 September 30,		 Nine Months Ended 
 September 30,		Three Months Ended 
June 30,		 Six Months Ended 
June 30,
2019 2018 2019 20182020 2019 2020 2019
(Millions)(Millions)
Net income (loss)$242
 $200
 $780
 $739
$315
 $324
 $(255) $538
Other comprehensive income (loss):              
Cash flow hedging activities:       
Net unrealized gain (loss) from derivative instruments, net of taxes of $3 and $6 in 2018—
 (5) —
 (19)
Reclassifications into earnings of net derivative instruments (gain) loss, net of taxes of ($2) and ($3) in 2018—
 7
 —
 10
Pension and other postretirement benefits:              
Net actuarial gain (loss) arising during the year, net of taxes of $1 and $1 in 2019, and ($0) and ($1) in 2018(5) —

(5)
4
Amortization of actuarial (gain) loss and net actuarial loss from settlements included in net periodic benefit cost (credit), net of taxes of ($0) and ($3) in 2019, and ($3) and ($5) in 20184
 4
 9
 14
Net actuarial gain (loss) arising during the year, net of taxes of ($7) and ($3) in 202023
 —
 9
 —
Amortization of actuarial (gain) loss and net actuarial loss from settlements included in net periodic benefit cost (credit), net of taxes of ($3) and ($5) in 2020 and ($2) and ($3) in 20196
 2
 14
 5
Other comprehensive income (loss)(1) 6
 4
 9
29
 2
 23
 5
Comprehensive income (loss)241
 206
 784
 748
344
 326
 (232) 543
Less: Comprehensive income (loss) attributable to noncontrolling interests21
 72
 54
 321
12
 14
 (41) 33
Comprehensive income (loss) attributable to The Williams Companies, Inc.$220
 $134
 $730
 $427
$332
 $312
 $(191) $510
See accompanying notes.



The Williams Companies, Inc.
Consolidated Balance Sheet
(Unaudited)
 September 30,
2019		 December 31,
2018		 June 30,
2020		 December 31,
2019
 (Millions, except per-share amounts) (Millions, except per-share amounts)
ASSETS    
Current assets:        
Cash and cash equivalents $247
 $168
 $1,133
 $289
Trade accounts and other receivables (net of allowance of $6 at September 30, 2019 and $9 at December 31, 2018) 875
 992
Trade accounts and other receivables 917
 1,002
Allowance for doubtful accounts (10) (6)
Trade accounts and other receivables – net 907
 996
Inventories 129
 130
 134
 125
Other current assets and deferred charges 183
 174
 164
 170
Total current assets 1,434
 1,464
 2,338
 1,580
Investments 6,228
 7,821
 5,155
 6,235
Property, plant, and equipment 41,647
 38,661
 42,092
 41,510
Accumulated depreciation and amortization (12,034) (11,157) (12,955) (12,310)
Property, plant, and equipment – net 29,613
 27,504
 29,137
 29,200
Intangible assets – net of accumulated amortization 8,041
 7,767
 7,609
 7,959
Regulatory assets, deferred charges, and other 965
 746
 1,104
 1,066
Total assets $46,281
 $45,302
 $45,343
 $46,040
LIABILITIES AND EQUITY        
Current liabilities:        
Accounts payable $602
 $662
 $769
 $552
Accrued liabilities 1,184
 1,102
 1,043
 1,276
Long-term debt due within one year 1,538
 47
 626
 2,140
Total current liabilities 3,324
 1,811
 2,438
 3,968
Long-term debt 20,719
 22,367
 22,323
 20,148
Deferred income tax liabilities 1,651
 1,524
 1,729
 1,782
Regulatory liabilities, deferred income, and other 3,728
 3,603
 3,773
 3,778
Contingent liabilities (Note 14) 

 

Contingent liabilities (Note 13) 

 

Equity:        
Stockholders’ equity:        
Preferred stock 35
 35
 35
 35
Common stock ($1 par value; 1,470 million shares authorized at September 30, 2019 and December 31, 2018; 1,247 million shares issued at September 30, 2019 and 1,245 million shares issued at December 31, 2018) 1,247
 1,245
Common stock ($1 par value; 1,470 million shares authorized at June 30, 2020 and December 31, 2019; 1,248 million shares issued at June 30, 2020 and 1,247 million shares issued at December 31, 2019) 1,248
 1,247
Capital in excess of par value 24,310
 24,693
 24,343
 24,323
Retained deficit (10,664) (10,002) (12,197) (11,002)
Accumulated other comprehensive income (loss) (266) (270) (176) (199)
Treasury stock, at cost (35 million shares of common stock) (1,041) (1,041) (1,041) (1,041)
Total stockholders’ equity 13,621
 14,660
 12,212
 13,363
Noncontrolling interests in consolidated subsidiaries 3,238
 1,337
 2,868
 3,001
Total equity 16,859
 15,997
 15,080
 16,364
Total liabilities and equity $46,281
 $45,302
 $45,343
 $46,040

See accompanying notes.


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 – June 30, 2019$35
 $1,246
 $24,296
 $(10,423) $(265) $(1,041) $13,848
 $3,233
 $17,081
Net income (loss)—
 —
 —
 221
 —
 —
 221
 21
 242
Other comprehensive income (loss)—
 —
 —
 —
 (1) —
 (1) —
 (1)
Cash dividends – common stock ($0.38 per share)
—
 —
 —
 (461) —
 —
 (461) —
 (461)
Dividends and distributions to noncontrolling interests—
 —
 —
 —
 —
 —
 —
 (18) (18)
Stock-based compensation and related common stock issuances, net of tax—
 1
 16
 —
 —
 —
 17
 —
 17
Changes in ownership of consolidated subsidiaries, net (Note 2)—
 —
 (1) —
 —
 —
 (1) 2
 1
Other—
 —
 (1) (1) —
 —
 (2) —
 (2)
   Net increase (decrease) in equity—
 1
 14
 (241) (1) —
 (227) 5
 (222)
Balance – September 30, 2019$35
 $1,247
 $24,310
 $(10,664) $(266) $(1,041) $13,621
 $3,238
 $16,859

Balance – June 30, 2018
$—
 $862
 $18,552
 $(8,735) $(293) $(1,041) $9,345
 $6,102
 $15,447
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 – March 31, 2020$35
 $1,248
 $24,330
 $(12,013) $(205) $(1,041) $12,354
 $2,905
 $15,259
Net income (loss)—
 —
 —
 129
 —
 —
 129
 71
 200
—
 —
 —
 303
 —
 —
 303
 12
 315
Other comprehensive income (loss)—
 —
 —
 —
 5
 —
 5
 1
 6
—
 —
 —
 —
 29
 —
 29
 —
 29
WPZ Merger (Note 1)—
 382
 6,112
 —
 (3) —
 6,491
 (4,629) 1,862
Issuance of preferred stock (Note 12)35
 —
 —
 —
 —
 —
 35
 —
 35
Cash dividends – common stock ($0.34 per share)
—
 —
 —
 (411) —
 —
 (411) —
 (411)
Cash dividends – common stock ($0.40 per share)
—
 —
 —
 (486) —
 —
 (486) —
 (486)
Dividends and distributions to noncontrolling interests—
 —
 —
 —
 —
 —
 —
 (196) (196)—
 —
 —
 —
 —
 —
 —
 (54) (54)
Stock-based compensation and related common stock issuances, net of tax—
 —
 16
 —
 —
 —
 16
 —
 16
—
 —
 13
 —
 —
 —
 13
 —
 13
Changes in ownership of consolidated subsidiaries, net—
 —
 1
 —
 —
 —
 1
 (1) —
Contributions from noncontrolling interests—
 —
 —
 —
 —
 —
 —
 2
 2
—
 —
 —
 —
 —
 —
 —
 2
 2
Other—
 1
 (1) (1) —
 —
 (1) (1) (2)—
 —
 —
 (1) —
 —
 (1) 3
 2
Net increase (decrease) in equity35
 383
 6,128
 (283) 2
 —
 6,265
 (4,753) 1,512
—
 —
 13
 (184) 29
 —
 (142) (37) (179)
Balance – September 30, 2018
$35
 $1,245
 $24,680
 $(9,018) $(291) $(1,041) $15,610
 $1,349
 $16,959
Balance – June 30, 2020$35
 $1,248
 $24,343
 $(12,197) $(176) $(1,041) $12,212
 $2,868
 $15,080

Balance – March 31, 2019$35
 $1,246
 $24,703
 $(10,270) $(267) $(1,041) $14,406
 $1,319
 $15,725
Net income (loss)—
 —
 —
 310
 —
 —
 310
 14
 324
Other comprehensive income (loss)—
 —
 —
 —
 2
 —
 2
 —
 2
Cash dividends – common stock ($0.38 per share)
—
 —
 —
 (461) —
 —
 (461) —
 (461)
Dividends and distributions to noncontrolling interests—
 —
 —
 —
 —
 —
 —
 (27) (27)
Stock-based compensation and related common stock issuances, net of tax—
 —
 17
 —
 —
 —
 17
 —
 17
Sale of partial interest in consolidated subsidiary (Note 2)—
 —
 —
 —
 —
 —
 —
 1,333
 1,333
Changes in ownership of consolidated subsidiaries, net (Note 2)—
 —
 (425) —
 —
 —
 (425) 566
 141
Contributions from noncontrolling interests—
 —
 —
 —
 —
 —
 —
 28
 28
Other—
 —
 1
 (2) —
 —
 (1) —
 (1)
   Net increase (decrease) in equity—
 —
 (407) (153) 2
 —
 (558) 1,914
 1,356
Balance – June 30, 2019$35
 $1,246
 $24,296
 $(10,423) $(265) $(1,041) $13,848
 $3,233
 $17,081
                  
*Accumulated Other Comprehensive Income (Loss)

See accompanying notes.














The Williams Companies, Inc.
Consolidated Statement of Changes in Equity (Continued)
(Unaudited)
The Williams Companies, Inc. Stockholders    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
Preferred
Stock
 Common
Stock		 
Capital in
Excess of
Par Value
 
Retained
Deficit
 AOCI* 
Treasury
Stock
 
Total
Stockholders’
Equity
 
Noncontrolling
Interests
 Total Equity
(Millions)(Millions)
Balance – December 31, 2018$35
 $1,245
 $24,693
 $(10,002) $(270) $(1,041) $14,660
 $1,337
 $15,997
Balance – December 31, 2019$35
 $1,247
 $24,323
 $(11,002) $(199) $(1,041) $13,363
 $3,001
 $16,364
Net income (loss)—
 —
 —
 726
 —
 —
 726
 54
 780
—
 —
 —
 (214) —
 —
 (214) (41) (255)
Other comprehensive income (loss)—
 —
 —
 —
 4
 —
 4
 —
 4
—
 —
 —
 —
 23
 —
 23
 —
 23
Cash dividends – common stock ($1.14 per share)—
 —
 —
 (1,382) —
 —
 (1,382) —
 (1,382)
Cash dividends – common stock ($0.80 per share)—
 —
 —
 (971) —
 —
 (971) —
 (971)
Dividends and distributions to noncontrolling interests—
 —
 —
 —
 —
 —
 —
 (86) (86)—
 —
 —
 —
 —
 —
 —
 (98) (98)
Stock-based compensation and related common stock issuances, net of tax—
 2
 43
 —
 —
 —
 45
 —
 45
—
 1
 20
 —
 —
 —
 21
 —
 21
Sale of partial interest in consolidated subsidiary (Note 2)—
 —
 —
 —
 —
 —
 —
 1,333
 1,333
Changes in ownership of consolidated subsidiaries, net (Note 2)—
 —
 (426) —
 —
 —
 (426) 568
 142
Contributions from noncontrolling interests—
 —
 —
 —
 —
 —
 —
 32
 32
—
 —
 —
 —
 —
 —
 —
 4
 4
Other—
 —
 —
 (6) —
 —
 (6) —
 (6)—
 —
 —
 (10) —
 —
 (10) 2
 (8)
Net increase (decrease) in equity—
 2
 (383) (662) 4
 —
 (1,039) 1,901
 862
—
 1
 20
 (1,195) 23
 —
 (1,151) (133) (1,284)
Balance – September 30, 2019$35
 $1,247
 $24,310
 $(10,664) $(266) $(1,041) $13,621
 $3,238
 $16,859
Balance – June 30, 2020$35
 $1,248
 $24,343
 $(12,197) $(176) $(1,041) $12,212
 $2,868
 $15,080
Balance – December 31, 2017$—
 $861
 $18,508
 $(8,434) $(238) $(1,041) $9,656
 $6,519
 $16,175
Adoption of new accounting standards—
 —
 —
 (23) (61) —
 (84) (37) (121)
Net income (loss)—
 —
 —
 416
 —
 —
 416
 323
 739
Other comprehensive income (loss)—
 —
 —
 —
 11
 —
 11
 (2) 9
WPZ Merger (Note 1)—
 382
 6,112
 —
 (3) —
 6,491
 (4,629) 1,862
Issuance of preferred stock (Note 12)35
 —
 —
 —
 —
 —
 35
 —
 35
Cash dividends – common stock ($1.02 per share)—
 —
 —
 (974) —
 —
 (974) —
 (974)
Dividends and distributions to noncontrolling interests—
 —
 —
 —
 —
 —
 —
 (598) (598)
Stock-based compensation and related common stock issuances, net of tax—
 1
 48
 —
 —
 —
 49
 —
 49
Sales of limited partner units of Williams Partners L.P.—
 —
 —
 —
 —
 —
 —
 46
 46
Changes in ownership of consolidated subsidiaries, net—
 —
 14
 —
 —
 —
 14
 (18) (4)
Contributions from noncontrolling interests—
 —
 —
 —
 —
 —
 —
 13
 13
Deconsolidation of subsidiary (Note 5)—
 —
 —
 —
 —
 —
 —
 (267) (267)
Other—
 1
 (2) (3) —
 —
 (4) (1) (5)
   Net increase (decrease) in equity35
 384
 6,172
 (584) (53) —
 5,954
 (5,170) 784
Balance – September 30, 2018$35
 $1,245
 $24,680
 $(9,018) $(291) $(1,041) $15,610
 $1,349
 $16,959
Balance – December 31, 2018$35
 $1,245
 $24,693
 $(10,002) $(270) $(1,041) $14,660
 $1,337
 $15,997
Net income (loss)—
 —
 —
 505
 —
 —
 505
 33
 538
Other comprehensive income (loss)—
 —
 —
 —
 5
 —
 5
 —
 5
Cash dividends – common stock ($0.76 per share)—
 —
 —
 (921) —
 —
 (921) —
 (921)
Dividends and distributions to noncontrolling interests—
 —
 —
 —
 —
 —
 —
 (68) (68)
Stock-based compensation and related common stock issuances, net of tax—
 1
 27
 —
 —
 —
 28
 —
 28
Sale of partial interest in consolidated subsidiary (Note 2)—
 —
 —
 —
 —
 —
 —
 1,333
 1,333
Changes in ownership of consolidated subsidiaries, net (Note 2)—
 —
 (425) —
 —
 —
 (425) 566
 141
Contributions from noncontrolling interests—
 —
 —
 —
 —
 —
 —
 32
 32
Other—
 —
 1
 (5) —
 —
 (4) —
 (4)
   Net increase (decrease) in equity—
 1
 (397) (421) 5
 —
 (812) 1,896
 1,084
Balance – June 30, 2019$35
 $1,246
 $24,296
 $(10,423) $(265) $(1,041) $13,848
 $3,233
 $17,081
 
*Accumulated Other Comprehensive Income (Loss)
See accompanying notes.



The Williams Companies, Inc.
Consolidated Statement of Cash Flows
(Unaudited)
Nine Months Ended 
 September 30,		Six Months Ended 
June 30,
2019 20182020 2019
(Millions)(Millions)
OPERATING ACTIVITIES:  
Net income (loss)$780
 $739
$(255) $538
Adjustments to reconcile to net cash provided (used) by operating activities:      
Depreciation and amortization1,275
 1,290
859
 840
Provision (benefit) for deferred income taxes268
 351
(59) 182
Equity (earnings) losses(260) (279)(130) (167)
Distributions from unconsolidated affiliates458
 507
323
 327
Net (gain) loss on disposition of equity-method investments (Note 5)(122) —
Impairment of equity-method investments (Note 13)186
 —
(Gain) loss on deconsolidation of businesses (Note 5)2
 (62)
Impairment of and net (gain) loss on sale of certain assets76
 64
Gain on disposition of equity-method investments (Note 5)—
 (122)
Impairment of goodwill (Note 12)187
 —
Impairment of equity-method investments (Note 12)938
 72
Impairment of certain assets (Note 12)—
 76
Amortization of stock-based awards44
 43
24
 30
Cash provided (used) by changes in current assets and liabilities:      
Accounts and notes receivable159
 75
Accounts receivable85
 149
Inventories7
 (39)(9) 4
Other current assets and deferred charges(10) (44)(13) (16)
Accounts payable(76) (76)236
 (98)
Accrued liabilities76
 (62)(236) 70
Other, including changes in noncurrent assets and liabilities(161) (176)(20) (41)
Net cash provided (used) by operating activities2,702
 2,331
1,930
 1,844
FINANCING ACTIVITIES:      
Proceeds from (payments of) commercial paper – net(4) 821
—
 (4)
Proceeds from long-term debt736
 3,745
3,896
 720
Payments of long-term debt(904) (3,201)(3,226) (868)
Proceeds from issuance of common stock10
 15
6
 6
Proceeds from sale of partial interest in consolidated subsidiary (Note 2)1,330
 —
—
 1,330
Common dividends paid(1,382) (974)(971) (921)
Dividends and distributions paid to noncontrolling interests(86) (552)(98) (68)
Contributions from noncontrolling interests32
 13
4
 32
Payments for debt issuance costs—
 (26)(17) —
Other – net(11) (46)(10) (9)
Net cash provided (used) by financing activities(279) (205)(416) 218
INVESTING ACTIVITIES:      
Property, plant, and equipment:      
Capital expenditures (1)(1,705) (2,659)(613) (919)
Dispositions – net(32) (2)(16) (15)
Contributions in aid of construction25
 395
19
 18
Purchases of businesses, net of cash acquired (Note 2)(728) —
—
 (727)
Proceeds from dispositions of equity-method investments (Note 5)485
 —
—
 485
Purchases of and contributions to equity-method investments(361) (803)(66) (242)
Other – net(28) 86
6
 (24)
Net cash provided (used) by investing activities(2,344) (2,983)(670) (1,424)
Increase (decrease) in cash and cash equivalents79
 (857)844
 638
Cash and cash equivalents at beginning of year168
 899
289
 168
Cash and cash equivalents at end of period$247
 $42
$1,133
 $806
_____________      
(1) Increases to property, plant, and equipment$(1,707) $(2,482)$(581) $(977)
Changes in related accounts payable and accrued liabilities2
 (177)(32) 58
Capital expenditures$(1,705) $(2,659)$(613) $(919)

See accompanying notes.


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, 2018,2019, in Exhibit 99.1 of our Annual Report on Form 10-K.8-K dated May 4, 2020. The accompanying unaudited financial statements include all normal recurring adjustments and others that, in the opinion of management, are necessary to present fairly our interim financial statements.
The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes. Actual results could differ from those estimates.
Unless the context clearly indicates otherwise, references in this report to “Williams,” “we,” “our,” “us,” or like terms refer to The Williams Companies, Inc. and its subsidiaries. Unless the context clearly indicates otherwise, references to “Williams,” “we,” “our,” and “us” include the operations in which we own interests accounted for as equity-method investments that are not consolidated in our financial statements. When we refer to our equity investees by name, we are referring exclusively to their businesses and operations.
WPZ Merger
On August 10, 2018, we completed our merger with Williams Partners L.P. (WPZ), our previously consolidated master limited partnership, pursuant to which we acquired all of the approximately 256 million publicly held outstanding common units of WPZ in exchange for 382 million shares of our common stock (WPZ Merger). Williams continued as the surviving entity. The WPZ Merger was accounted for as a noncash equity transaction resulting in increases to Common stock of $382 million, Capital in excess of par value of $6.112 billion, and Regulatory assets, deferred charges, and other of $33 million and decreases to Accumulated other comprehensive income (loss) (AOCI) of $3 million, Noncontrolling interests in consolidated subsidiaries of $4.629 billion, and Deferred income tax liabilities of $1.829 billion in the Consolidated Balance Sheet. Pursuant to its distribution reinvestment program, WPZ had issued 1,230,657 common units to the public in 2018 associated with reinvested distributions of $46 million.
Description of Business
We are a Delaware corporation whose common stock is listed and traded on the New York Stock Exchange. Our operations are located in the United States andStates. Effective January 1, 2020, following an organizational realignment, our interstate natural gas pipeline Northwest Pipeline LLC (Northwest Pipeline), which was reported within the West reporting segment throughout 2019, is now managed within the Transmission & Gulf of Mexico reporting segment (previously identified as the Atlantic-Gulf reporting segment). As a result, beginning with the reporting of first-quarter 2020, our operations are presented within the following reportable segments: Transmission & Gulf of Mexico, Northeast G&P, Atlantic-Gulf, and West, consistent with the manner in which our chief operating decision maker evaluates performance and allocates resources. All remaining business activities as well as corporate activities are included in Other. Prior period segment disclosures have been recast for the new segment presentation.
Northeast G&P is comprisedTransmission & Gulf of our midstream gathering, processing, and fractionation businesses in the Marcellus Shale region primarily in Pennsylvania, New York, and West Virginia and the Utica Shale region of eastern Ohio, including a 66 percent interest in Cardinal Gas Services, L.L.C. (Cardinal) (a consolidated entity), as well as a 69 percent equity-method investment in Laurel Mountain Midstream, LLC (Laurel Mountain), a 58 percent equity-method investment in Caiman Energy II, LLC, and Appalachia Midstream Services, LLC, which owns equity-method investments with an approximate average 66 percent interest in multiple gas gathering systems in the Marcellus Shale (Appalachia Midstream Investments). Northeast G&P includes a 65 percent interest in Ohio Valley Midstream LLC (Northeast JV) (a consolidated entity). The Northeast JV includes our Ohio Valley assets and Utica East Ohio Midstream LLC (UEOM), a former equity-method investment in which we acquired the remaining ownership interest in March 2019 (see Note 2 – Acquisitions).


Notes (Continued)


Atlantic-GulfMexico is comprised of our interstate natural gas pipeline,pipelines, Transcontinental Gas Pipe Line Company, LLC (Transco), and significantNorthwest Pipeline, as well as natural gas gathering and processing and crude oil production handling and transportation assets in the Gulf Coast region, including a 51 percent interest in Gulfstar One LLC (Gulfstar One) (a consolidated entity)variable interest entity, or VIE), which is a proprietary floating production system, as well as a 50 percent equity-method investment in Gulfstream Natural Gas System, L.L.C., and a 60 percent equity-method investment in Discovery Producer Services LLC (Discovery).
Northeast G&P is comprised of our midstream gathering, processing, and fractionation businesses in the Marcellus Shale region primarily in Pennsylvania and New York, and the Utica Shale region of eastern Ohio, as well as a 4165 percent interest in Constitution Pipeline Company,Ohio Valley Midstream LLC (Constitution)(Northeast JV) (a consolidated entity)VIE) which operates in West Virginia, Ohio, and Pennsylvania, a 66 percent interest in Cardinal Gas Services, L.L.C. (Cardinal) (a consolidated VIE) which operates in Ohio, a 69 percent equity-method investment in Laurel Mountain Midstream, LLC (Laurel Mountain), a 58 percent equity-method investment in Caiman Energy II, LLC (Caiman II), and Appalachia Midstream Services, LLC, which is developing a pipeline project (see Note 4 – Variable Interest Entities)owns equity-method investments with an approximate average 66 percent interest in multiple gas gathering systems in the Marcellus Shale (Appalachia Midstream Investments).
West is comprised of our interstate natural gas pipeline, Northwest Pipeline LLC (Northwest Pipeline), and our gathering, processing, and treating operations in the Rocky Mountain region of Colorado and Wyoming, the Barnett Shale region of north-central Texas, the Eagle Ford Shale region of south Texas, the Permian Shale region of west Texas,


Notes (Continued)


the Haynesville Shale region of northwest Louisiana, and the Mid-Continent region which includes the Anadarko, Arkoma, and ArkomaPermian basins. This segment also includes our natural gas liquid (NGL) and natural gas marketing business, storage facilities, an undivided 50 percent interest in an NGL fractionator near Conway, Kansas, a 50 percent equity-method investment in Overland Pass Pipeline Company LLC, a 50 percent equity-method investment in Rocky Mountain Midstream Holdings LLC (RMM), and a 15 percent equity-method investmentinterest in Brazos Permian II, LLC (Brazos Permian II). West also included our former natural gas gathering and processing assets in the Four Corners area of New Mexico and Colorado, which were sold during the fourth quarter of 2018, and our former 50 percent interestequity-method investment in Jackalope Gas Gathering Services, L.L.C. (Jackalope) (an equity-method investment following deconsolidation as of June 30, 2018), which was sold in April 2019.
Basis of Presentation
Significant risks and uncertainties
We believe that the carrying value of certain of our property, plant, and equipment and other identifiable intangible assets, notably certain acquired assets accounted for as business combinations between 2012 and 2014, may be in excess of current fair value. However, the carrying value of these assets, in our judgment, continues to be recoverable based on our evaluation of undiscounted future cash flows.recoverable. It is reasonably possible that future strategic decisions, including transactions such as monetizing non-core assets or contributing assets to new ventures with third parties, as well as unfavorable changes in expected producer activities, including effects of financial distress caused by recent financial and commodity market declines or unfavorable developments in ongoing bankruptcy proceedings, could impact our assumptions and ultimately result in impairments of these assets. Such transactions or developments may also indicate that certain of our equity-method investments have experienced other-than-temporary declines in value, which could result in impairment, orimpairment.
Customer bankruptcy
In June 2020, our customer, Chesapeake Energy Corporation (Chesapeake), announced that the fair valueit had voluntarily filed for relief under Chapter 11 of the reporting unitU.S. Bankruptcy Code. We provide midstream services, including wellhead gathering, for the natural gas that Chesapeake and its joint interest owners produce primarily in the Eagle Ford Shale, Haynesville Shale, and Marcellus Shale regions (through our goodwillAppalachia Midstream Investments). In 2019, Chesapeake accounted for approximately 6 percent of our consolidated revenues. As of June 30, 2020, we have approximately $91 million of trade accounts receivable due from Chesapeake, (substantially all of which is less than its carrying amount, which would resultcurrent at June 30, 2020).
We have evaluated these receivables from Chesapeake and our related asset groups and investments involved in impairment.
Accounting standards issuedproviding services to Chesapeake and adopted
In February 2016, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2016-02 “Leases (Topic 842)” (ASU 2016-02). ASU 2016-02 establishes a comprehensive new lease accounting model. ASU 2016-02 modifies the definition of a lease, requires a dual approach to lease classification similar to prior lease accounting, and causes lessees to recognize operating leases on the balance sheet as a lease liability measured as the present value of the future lease payments with a corresponding right-of-use asset, with an exception for leases with a term of one yeardetermined that no expected credit losses or less. Additional disclosures are required regarding the amount, timing, and uncertainty of cash flows arising from leases. In January 2018, the FASB issued ASU 2018-01 “Leases (Topic 842): Land Easement Practical Expedient for Transition to Topic 842” (ASU 2018-01). Per ASU 2018-01, land easements and rights-of-wayimpairment charges are required to be recognized at this time. This evaluation considered the physical nature of our services in these basins, where we gather at the wellhead and are critical to Chesapeake’s ability to move product to market, along with an assessed under ASU 2016-02low likelihood of contract rejection, noting that none of our contracts with Chesapeake were rejected in their initial bankruptcy filing. Chesapeake also received initial limited approval to determine whethercontinue paying for services such as those we provide. We also considered our prior experiences with customer bankruptcies, where receivables were ultimately collectible even if the arrangements are or contain a lease. ASU 2018-01 permits an entity to elect a transition practical expedient to not apply ASU 2016-02 to land easements that exist or expired beforetiming of collections was impacted. Future developments in Chesapeake’s ongoing bankruptcy proceedings could affect our assumptions and conclusions regarding credit losses and impairment charges.
Northeast Supply Enhancement
As of June 30, 2020, Property, plant, and equipment in our Consolidated Balance Sheet includes approximately $217 million of capitalized project development costs for the effective date of ASU 2016-02 and that were not previously assessed under the previous lease guidance in Accounting Standards Codification (ASC) Topic 840 “Leases.”
In July 2018, the FASB issued ASU 2018-11 “Leases (Topic 842): Targeted Improvements” (ASU 2018-11). Prior to ASU 2018-11, a modified retrospective transition wasNortheast Supply Enhancement project. Approvals required for financing or operating leases existingthe project from the New York State Department of Environmental Conservation and the New Jersey Department of Environmental Protection have been denied and we have not refiled at or entered into afterthis time. Beginning in May 2020, we discontinued capitalization of costs related to this project.
The customer precedent agreements remain in effect and the beginningproject’s Federal Energy Regulatory Commission (FERC) certificate remains active. As such, we do not believe this project is probable of abandonment at this time and consider the carrying amount to be recoverable; thus no impairment charge has been recognized. It is reasonably possible that further adverse developments in the near future could change this determination, resulting in a future impairment charge of a substantial portion of the earliest comparative period presented in the financial statements. ASU 2018-11 allows entities an additional transition method to the existing requirements whereby an entity could adopt the provisions of ASU 2016-02 by recognizing a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption without adjustment to the financial statements for periods prior to adoption. ASU 2018-11 also allows acapitalized costs.


Notes (Continued)


practical expedient that permits lessors to not separate nonlease components from the associated lease component if certain conditions are present. ASU 2016-02 is effective for interim and annual periods beginning after December 15, 2018. We prospectively adopted ASU 2016-02 effective January 1, 2019, and did not adjust prior periods as permitted by ASU 2018-11 (see Note 10 – Leases).
We completed our review of contracts to identify leases based on the modified definition of a lease and implemented changes to our internal controls to support management in the accounting for and disclosure of leasing activities upon adoption of ASU 2016-02. We implemented a financial lease accounting system to assist management in the accounting for leases upon adoption. The most significant changes to our financial statements as a result of adopting ASU 2016-02 relate to the recognition of a $225 million lease liability and offsetting right-of-use asset in our Consolidated Balance Sheetfor operating leases. We also evaluated ASU 2016-02’s available practical expedients on adoption and have generally elected to adopt the practical expedients, which includes the practical expedient to not separate lease and nonlease components by both lessees and lessors by class of underlying assets and the land easements practical expedient.
Accounting standards issued but not yetand adopted
In June 2016, the FASBFinancial Accounting Standards Board issued ASUAccounting Standards Update (ASU) 2016-13 “Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments” (ASU 2016-13). ASU 2016-13 changeschanged the impairment model for most financial assets and certain other instruments. For trade and other receivables, held-to-maturity debt securities, loans, and other instruments, entities will beare required to use a new forward-looking “expected loss” model that generally will result in the earlier recognition of allowances for losses. The guidance also requires increased disclosures.We adopted ASU 2016-13 is effective for us for interim and annual periods beginning after December 15, 2019. We plan to adopt as of January 1, 2020. We anticipate that ASU 2016-13 will2020, which primarily applyapplied to our short-term trade receivables. WhileThere 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 expectimpact 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 significant financial impact, we have analyzed our historical credit loss experience and continue to develop and implement processes, procedures, and internal controls in order to make the necessary credit loss assessments and required disclosures upon adoption.material amount of significantly aged receivables at June 30, 2020.
Note 2 – Acquisitions
UEOM
As of December 31, 2018, we owned a 62 percent interest in UEOMUtica East Ohio Midstream LLC (UEOM) which we accounted for as an equity-method investment. On March 18, 2019, we signed and closed the acquisition of the remaining 38 percent interest in UEOM. Total consideration paid, including post-closing adjustments, was $741 million in cash funded through credit facility borrowings and cash on hand.hand, net of $13 million cash acquired. As a result of acquiring this additional interest, we obtained control of and now consolidateconsolidated UEOM.
UEOM is involved primarily in the processing and fractionation of natural gas and natural gas liquids in the Utica Shale play in eastern Ohio. The purpose of the acquisition is to enhance our position in the region. We expect synergies through common ownership of UEOM and our Ohio Valley midstream systems to create a more efficient platform for capital spending in the region, resulting in reduced operating and maintenance expenses and creating enhanced capabilities and benefits for producers in the area.
The acquisition of UEOM was accounted for as a business combination, which requires, among other things, that identifiable assets acquired and liabilities assumed be recognized at their acquisition date fair values. In March 2019, based on the transaction price for our purchase of the remaining interest in UEOM as finalized just prior to the acquisition, we recognized a $74 million noncash impairment loss related to our existing 62 percent interest (see Note 1312 – Fair Value Measurements and Guarantees). Thus, there was 0 gain or loss on remeasuring our existing equity-method investment to fair value due to the impairment recognized just prior to closing the acquisition of the additional interest.
The valuation techniques used to measure the acquisition date fair value of the UEOM acquisition consisted of the market approach for our previous equity-method investment in UEOM and the income approach (excess earnings method) for valuation of intangible assets and depreciated replacement costs for property, plant, and equipment.
The following table presents the allocation of the acquisition date fair value of the major classes of the assets acquired, which are presented in the Northeast G&P segment, and liabilities assumed at March 18, 2019. The net assets


Notes (Continued)


acquired reflect the sum of the consideration transferred and the noncash elimination of the fair value of our existing equity-method investment upon our acquisition of the additional interest. The fair value of accounts receivable acquired, presented in current assets in the table, equals contractual amounts receivable. After the March 31, 2019 financial statements were issued, we received an updated valuation report from a third-party valuation firm. Significant changes from the preliminary allocation disclosed in the first quarter to the final allocation reflect an increase of $169 million in goodwill, and decreases of $106 million in property, plant, and equipment and $61 million in other intangible assets.
 (Millions)
Current assets, including $13 million cash acquired$55
Property, plant, and equipment1,387
Other intangible assets328
Total identifiable assets acquired1,770
  
Current liabilities7
Total liabilities assumed7
  
Net identifiable assets acquired1,763
  
Goodwill188
Net assets acquired$1,951

The goodwill recognized in the acquisition relates primarily to enhancing and diversifying our basin positions and is reported within the Northeast G&P segment. Substantially all of the goodwill is expected to be deductible for tax purposes. Goodwill is included within Intangible assets – net of accumulated amortization in the Consolidated Balance Sheet and represents the excess of the consideration, plus the fair value of any previously held equity interest, over the fair value of the net assets acquired. It is not subject to amortization but is evaluated annually as of October 1 for impairment or more frequently if impairment indicators are present that would indicate it is more likely than not that the fair value of the reporting unit is less than its carrying amount.
Other intangible assets recognized in the acquisition are related to contractual customer relationships from gas gathering, processing, and fractionation agreements with our customers. The basis for determining the value of these intangible assets is estimated future net cash flows to be derived from acquired contractual customer relationships discounted using a risk-adjusted discount rate. These intangible assets are being amortized on a straight-line basis over an initial period of 20 years which represents the term over which the contractual customer relationships are expected to contribute to our cash flows. Approximately 49 percent of the expected future revenues from these contractual customer relationships are impacted by our ability and intent to renew or renegotiate existing customer contracts. We expense costs incurred to renew or extend the terms of our gas gathering, processing, and fractionation contracts with customers. Based on the estimated future revenues during the current contract periods (as estimated at the time of the acquisition), the weighted-average period prior to the next renewal or extension of the existing contractual customer relationships is approximately 10 years.
The following unaudited pro forma Revenues and Net income (loss) attributable to The Williams Companies, Inc. for the three and nine months ended September 30, 2019 and 2018, are presented as if the UEOM acquisition had been completed on January 1, 2018. These pro forma amounts are not necessarily indicative of what the actual results would have been if the acquisition had in fact occurred on the date or for the periods indicated, nor do they purport to project Revenues or Net income (loss) attributable to The Williams Companies, Inc. for any future periods or as of any date. These amounts do not give effect to any potential cost savings, operating synergies, or revenue enhancements to result from the transaction or the potential costs to achieve these cost savings, operating synergies, and revenue enhancements.


Notes (Continued)


 Three Months Ended 
 September 30,		 Nine Months Ended 
 September 30,
 2019 2018 2019 2018
 (Millions)
Revenues$1,999
 $2,342
 $6,126
 $6,589
        
Net income (loss) attributable to The Williams Companies, Inc.$221
 $138
 $804
 $434
Adjustments to pro forma Net income (loss) attributable to The Williams Companies, Inc. include the removal of the previously described $74 million impairment loss recognized in March 2019 just prior to the acquisition. There are no pro forma adjustments for the three months ended September 30, 2019 as UEOM was consolidated and reflected in our results during the entire quarter.
During the period from the acquisition date of March 18, 2019 to September 30, 2019, UEOM contributed Revenues of $104 million and Net income (loss) attributable to The Williams Companies, Inc. of $25 million.
Costs related to this acquisition are $4 million and are reported within our Northeast G&P segment and included in Selling, general, and administrative expenses in our Consolidated Statement of Income.
Northeast JV
Concurrent with the UEOM acquisition, we executed an agreement whereby we contributed our consolidated interests in UEOM and our Ohio Valley midstream business to a newly formed partnership. In June 2019, our partner invested approximately $1.33 billion (subject to post-closing adjustments) for a 35 percent ownership interest, and we retained 65 percent ownership of, as well as operate and consolidate, the Northeast JV business. The change in ownership due to this transaction increased Noncontrolling interests in consolidated subsidiaries by $568$567 million, and decreased Capital in excess of par value by $426


Notes (Continued)


$426 million and Deferred income tax liabilities by $142$141 million in the Consolidated Balance Sheet. Costs related for the year ended December 31, 2019.
The goodwill recognized in the UEOM acquisition of $187 million (includes a $1 million adjustment recorded in the first quarter of 2020) was impaired during the first quarter of 2020. Our partner’s $65 million share of this impairment is reflected within Net income (loss) attributable to this transaction are $6 million and are reported within our Northeast G&P segment and included in Selling, general, and administrative expensesnoncontrolling interests in ourthe Consolidated Statement of IncomeOperations (see Note 12 – Fair Value Measurements and Guarantees).



Notes (Continued)


Note 3 – Revenue Recognition
Revenue by Category
The following table presents our revenue disaggregated by major service line:
Northeast
Midstream
 
Atlantic-
Gulf Midstream
 West Midstream Transco Northwest Pipeline Other Intercompany Eliminations  TotalTransco Northwest Pipeline Gulf of Mexico Midstream 
Northeast
Midstream
 West Midstream Other Eliminations  Total
(Millions)(Millions)
Three Months Ended September 30, 2019  
Three Months Ended June 30, 2020               
Revenues from contracts with customers:                              
Service revenues:                              
Non-regulated gathering, processing, transportation, and storage:               
Regulated interstate natural gas transportation and storage$592
 $110
 $—
 $—
 $—
 $—
 $(1) $701
Gathering, processing, transportation, fractionation, and storage:               
Monetary consideration$310
 $117
 $308
 $—
 $—
 $—
 $(19) $716
—
 —
 78
 308
 297
 —
 (19) 664
Commodity consideration1
 7
 30
 —
 —
 —
 —
 38
—
 —
 3
 1
 21
 —
 —
 25
Regulated interstate natural gas transportation and storage—
 —
 —
 601
 111
 —
 (2) 710
Other38
 8
 12
 —
 —
 —
 (5) 53
2
 —
 10
 41
 17
 —
 (4) 66
Total service revenues349
 132
 350
 601
 111
 —
 (26) 1,517
594
 110
 91
 350
 335
 —
 (24) 1,456
Product Sales:                              
NGL and natural gas product sales30
 34
 391
 41
 —
 —
 (28) 468
NGL and natural gas20
 —
 17
 1
 303
 —
 (31) 310
Total revenues from contracts with customers379
 166
 741
 642
 111
 —
 (54) 1,985
614
 110
 108
 351
 638
 —
 (55) 1,766
Other revenues (1)5
 2
 —
 3
 —
 7
 (3) 14
2
 —
 1
 5
 2
 9
 (4) 15
Total revenues$384
 $168
 $741
 $645
 $111
 $7
 $(57) $1,999
$616
 $110
 $109
 $356
 $640
 $9
 $(59) $1,781
                              
Three Months Ended September 30, 2018
               
Three Months Ended June 30, 2019               
Revenues from contracts with customers:                              
Service revenues:                              
Non-regulated gathering, processing, transportation, and storage:               
Regulated interstate natural gas transportation and storage$565
 $110
 $—
 $—
 $—
 $—
 $(2) $673
Gathering, processing, transportation, fractionation, and storage:               
Monetary consideration$219
 $139
 $409
 $—
 $—
 $1
 $(19) $749
—
 —
 121
 291
 355
 —
 (17) 750
Commodity consideration5
 19
 97
 —
 —
 —
 —
 121
—
 —
 13
 3
 40
 —
 —
 56
Regulated interstate natural gas transportation and storage—
 —
 —
 457
 110
 —
 (1) 566
Other23
 4
 11
 —
 —
 —
 (4) 34
1
 —
 9
 34
 9
 —
 (3) 50
Total service revenues247
 162
 517
 457
 110
 1
 (24) 1,470
566
 110
 143
 328
 404
 —
 (22) 1,529
Product Sales:                              
NGL and natural gas69
 88
 720
 41
 —
 —
 (117) 801
23
 —
 48
 37
 430
 —
 (46) 492
Other—
 —
 12
 —
 —
 —
 (3) 9
Total product sales69
 88
 732
 41
 —
 —
 (120) 810
Total revenues from contracts with customers316
 250
 1,249
 498
 110
 1
 (144) 2,280
589
 110
 191
 365
 834
 —
 (68) 2,021
Other revenues (1)6
 5
 3
 3
 —
 9
 (3) 23
2
 —
 —
 5
 8
 8
 (3) 20
Total revenues$322
 $255
 $1,252
 $501
 $110
 $10
 $(147) $2,303
$591
 $110
 $191
 $370
 $842
 $8
 $(71) $2,041
               


Notes (Continued)



 
Northeast
Midstream
 
Atlantic-
Gulf Midstream
 West Midstream Transco Northwest Pipeline Other Intercompany Eliminations  Total
 (Millions)
Nine Months Ended September 30, 2019
Revenues from contracts with customers:               
Service revenues:               
Non-regulated gathering, processing, transportation, and storage:               
Monetary consideration$840
 $366
 $1,007
 $—
 $—
 $—
 $(54) $2,159
Commodity consideration9
 33
 116
 —
 —
 —
 —
 158
Regulated interstate natural gas transportation and storage—
 —
 —
 1,736
 335
 —
 (4) 2,067
Other104
 21
 32
 1
 —
 —
 (12) 146
Total service revenues953
 420
 1,155
 1,737
 335
 —
 (70) 4,530
Product Sales:               
NGL and natural gas product sales114
 140
 1,300
 88
 —
 —
 (132) 1,510
Total revenues from contracts with customers1,067
 560
 2,455
 1,825
 335
 —
 (202) 6,040
Other revenues (1)15
 6
 12
 8
 —
 22
 (9) 54
Total revenues$1,082
 $566
 $2,467
 $1,833
 $335
 $22
 $(211) $6,094
                
Nine Months Ended September 30, 2018
Revenues from contracts with customers:               
Service revenues:               
Non-regulated gathering, processing, transportation, and storage:               
Monetary consideration$626
 $404
 $1,231
 $—
 $—
 $2
 $(55) $2,208
Commodity consideration14
 45
 257
 —
 —
 —
 —
 316
Regulated interstate natural gas transportation and storage—
 —
 —
 1,368
 330
 —
 (2) 1,696
Other65
 12
 35
 1
 —
 —
 (10) 103
Total service revenues705
 461
 1,523
 1,369
 330
 2
 (67) 4,323
Product Sales:               
NGL and natural gas242
 232
 1,799
 96
 —
 —
 (285) 2,084
Other—
 —
 20
 —
 —
 —
 (4) 16
Total product sales242
 232
 1,819
 96
 —
 —
 (289) 2,100
Total revenues from contracts with customers947
 693
 3,342
 1,465
 330
 2
 (356) 6,423
Other revenues (1)16
 14
 6
 8
 —
 24
 (9) 59
Total revenues$963
 $707
 $3,348
 $1,473
 $330
 $26
 $(365) $6,482

 Transco Northwest Pipeline Gulf of Mexico Midstream 
Northeast
Midstream
 West Midstream Other Eliminations  Total
 (Millions)
Six Months Ended June 30, 2020               
Revenues from contracts with customers:               
Service revenues:               
Regulated interstate natural gas transportation and storage$1,196
 $225
 $—
 $—
 $—
 $—
 $(3) $1,418
Gathering, processing, transportation, fractionation, and storage:               
Monetary consideration—
 —
 177
 620
 596
 —
 (41) 1,352
Commodity consideration—
 —
 8
 3
 42
 —
 —
 53
Other5
 —
 16
 82
 26
 —
 (9) 120
Total service revenues1,201
 225
 201
 705
 664
 —
 (53) 2,943
Product Sales:               
NGL and natural gas40
 —
 49
 30
 662
 —
 (60) 721
Total revenues from contracts with customers1,241
 225
 250
 735
 1,326
 —
 (113) 3,664
Other revenues (1)2
 —
 3
 10
 5
 17
 (7) 30
Total revenues$1,243
 $225
 $253
 $745
 $1,331
 $17
 $(120) $3,694
                
                
Six Months Ended June 30, 2019               
Revenues from contracts with customers:               
Service revenues:               
Regulated interstate natural gas transportation and storage$1,135
 $224
 $—
 $—
 $—
 $—
 $(2) $1,357
Gathering, processing, transportation, fractionation, and storage:               
Monetary consideration—
 —
 249
 530
 699
 —
 (35) 1,443
Commodity consideration—
 —
 26
 8
 86
 —
 —
 120
Other1
 —
 13
 66
 20
 —
 (7) 93
Total service revenues1,136
 224
 288
 604
 805
 —
 (44) 3,013
Product Sales:               
NGL and natural gas47
 —
 106
 84
 909
 —
 (104) 1,042
Total revenues from contracts with customers1,183
 224
 394
 688
 1,714
 —
 (148) 4,055
Other revenues (1)5
 —
 4
 10
 12
 15
 (6) 40
Total revenues$1,188
 $224
 $398
 $698
 $1,726
 $15
 $(154) $4,095

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


Notes (Continued)


Contract Assets
The following table presents a reconciliation of our contract assets:
Three Months Ended 
 September 30,		 Nine Months Ended 
 September 30,		Three Months Ended 
June 30,		 Six Months Ended 
June 30,
2019 2018 2019 20182020 2019 2020 2019
(Millions)(Millions)
Balance at beginning of period$17
 $39
 $4
 $4
$18
 $22
 $8
 $4
Revenue recognized in excess of amounts invoiced14
 17
 53
 53
46
 20
 69
 39
Minimum volume commitments invoiced—
 —
 (26) (1)(34) (25) (47) (26)
Balance at end of period$31
 $56
 $31
 $56
$30
 $17
 $30
 $17

Contract Liabilities
The following table presents a reconciliation of our contract liabilities:
Three Months Ended 
 September 30,		 Nine Months Ended 
 September 30,		Three Months Ended 
June 30,		 Six Months Ended 
June 30,
2019 2018 2019 20182020 2019 2020 2019
(Millions)(Millions)
Balance at beginning of period$1,331
 $1,535
 $1,397
 $1,596
$1,189
 $1,335
 $1,215
 $1,397
Payments received and deferred12
 58
 138
 269
74
 93
 102
 126
Deconsolidation of Jackalope interest (Note 5)—
 —
 —
 (52)
Significant financing component3
 4
 10
 11
2
 3
 5
 7
Recognized in revenue(77) (112) (276) (339)(62) (100) (119) (199)
Balance at end of period$1,269
 $1,485
 $1,269
 $1,485
$1,203
 $1,331
 $1,203
 $1,331

Remaining Performance Obligations
Remaining performance obligations primarily include reservation charges on contracted capacity for our gas pipeline firm transportation contracts with customers, storage capacity contracts, long-term contracts containing minimum volume commitments associated with our midstream businesses, and fixed payments associated with offshore production handling. For our interstate natural gas pipeline businesses, remaining performance obligations reflect the rates for such services in our current Federal Energy Regulatory Commission (FERC)FERC tariffs for the life of the related contracts; however, these rates may change based on future tariffs approved by the FERC and the amount and timing of these changes are not currently known.
Our remaining performance obligations exclude variable consideration, including contracts with variable consideration for which we have elected the practical expedient for consideration recognized in revenue as billed. Certain of our contracts contain evergreen and other renewal provisions for periods beyond the initial term of the contract. The remaining performance obligation amounts as of SeptemberJune 30, 2019,2020, do not consider potential future performance obligations for which the renewal has not been exercised and excludes contracts with customers for which the underlying facilities have not received FERC authorization to be placed into service. Consideration received prior to SeptemberJune 30, 2019,2020, that will be recognized in future periods is also excluded from our remaining performance obligations and is instead reflected in contract liabilities.


Notes (Continued)


The following table presents the amount of the contract liabilities balance as of September 30, 2019, expected to be recognized as revenue aswhen performance obligations are satisfied and the transaction price allocated to the remaining performance obligations under certain contracts as of SeptemberJune 30, 2019.2020.


Notes (Continued)


Contract Liabilities Remaining Performance ObligationsContract Liabilities Remaining Performance Obligations
(Millions)(Millions)
2019 (remainder)$70
 $762
2020167
 3,028
2020 (remainder)$97
 $1,662
2021126
 2,873
81
 3,266
2022112
 2,705
62
 3,100
2023103
 2,244
56
 2,682
202456
 2,282
Thereafter691
 19,840
851
 18,138
Total$1,269
 $31,452
$1,203
 $31,130

Accounts Receivable
The following is a summary of our Trade accounts and other receivables– net:
September 30, 2019 December 31, 2018June 30, 2020 December 31, 2019
(Millions)(Millions)
Accounts receivable related to revenues from contracts with customers$791
 $858
$749
 $890
Other accounts receivable84
 134
158
 106
Total reflected in Trade accounts and other receivables
$875
 $992
Total reflected in Trade accounts and other receivables – net
$907
 $996

Note 4 – Variable Interest Entities
Consolidated VIEs
As of SeptemberJune 30, 2019,2020, we consolidate the following variable interest entities (VIEs):
Gulfstar One
We own a 51 percent interest in Gulfstar One, a subsidiary that, due to certain risk-sharing provisions in its customer contracts, is a VIE. Gulfstar One includes a proprietary floating-production system, Gulfstar FPS, and associated pipelines which provide production handling and gathering services in the eastern deepwater Gulf of Mexico. We are the primary beneficiary because we have the power to direct the activities that most significantly impact Gulfstar One’s economic performance.
Constitution
We own a 41 percent interest in Constitution, a subsidiary that, due to shipper fixed-payment commitments under its long-term firm transportation contracts, is a VIE. We are the primary beneficiary because we have the power to direct the activities that most significantly impact Constitution’s economic performance. We, as operator of Constitution, are responsible for constructing the proposed pipeline, which will extend from Susquehanna County, Pennsylvania, to the Iroquois Gas Transmission and the Tennessee Gas Pipeline systems in New York. While we previously estimated the total remaining cost of the project to be approximately $740 million, this amount is expected to increase and the revised estimate is being developed. The project costs would be funded with capital contributions from us and the other equity partners on a proportional basis.
In December 2014, Constitution received approval from the FERC to construct and operate its proposed pipeline. However, in April 2016, the New York State Department of Environmental Conservation (NYSDEC) denied the necessary water quality certification under Section 401 of the Clean Water Act for the New York portion of the pipeline. In May 2016, Constitution appealed the NYSDEC’s denial of the Section 401 certification to the United States Court of Appeals for the Second Circuit, but in August 2017 the court issued a decision upholding NYSDEC’s denial. Constitution filed a petition for rehearing with the Second Circuit Court of Appeals, but in October 2017 the court denied our petition.


Notes (Continued)


In October 2017, we filed a petition for declaratory order requesting the FERC to find that, by operation of law, the Section 401 certification requirement for the New York State portion of Constitution’s pipeline project was waived due to the failure by the NYSDEC to act on Constitution’s Section 401 application within a reasonable period of time as required by the express terms of such statute. By orders issued in January 2018 and July 2018, the FERC denied our petition, finding that Section 401 provides that a state waives certification only when it does not act on an application within one year from the date of the application.
Thereafter, we petitioned the D.C. Circuit for review of the FERC’s decision. In November 2018, the D.C. Circuit granted a motion filed by the FERC to hold our appeal in abeyance pending a decision by the court in the Hoopa Valley Tribe v. FERC case. In January 2019, the D.C. Circuit issued its decision in Hoopa Valley Tribe, finding that the applicant’s withdrawal and resubmission of a Clean Water Act Section 401 water quality certification request did not trigger new statutory periods of review for the state agencies, which resulted in the state agencies waiving their Section 401 authority regarding the hydropower project in question. As a result of the Hoopa Valley Tribe decision, the FERC filed a motion for voluntary remand of our appeal, and in February 2019, the D.C. Circuit granted the motion, sending our waiver case back to the FERC to determine whether or not NYSDEC waived its authority under Section 401.
On August 28, 2019, the FERC issued an order finding that NYSDEC waived its water quality certification authority under Section 401 with respect to Constitution. The FERC interpreted the Hoopa Valley Tribe decision to stand for the general principle that where an applicant withdraws and resubmits an application for water quality certification for the purpose of avoiding Section 401’s one-year time limit, and the state agency does not act within one year of the receipt of the original application, the state agency has “failed or refused to act under Section 401” and, therefore, has waived its Section 401 authority.
The equity partners are evaluating the next steps in connection with advancing the project.
At September 30, 2019, capitalized project costs total $376 million, of which we have funded our proportionate share, and are included within Property, plant, and equipment in the Consolidated Balance Sheet. Beginning in April 2016, we discontinued capitalization of development costs related to this project. It is possible that we could incur certain supplier-related costs in the event of a continued prolonged delay or termination of the project.
Cardinal
We own 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.VIEs:
Northeast JV
As a result of the June 2019 sale of a 35 percent interest in the Northeast JV (see Note 2 – Acquisitions), we nowWe 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:

September 30,
2019
December 31,
2018		June 30,
2020
December 31,
2019

(Millions)(Millions)
Assets (liabilities):





Cash and cash equivalents$90
 $33
$91
 $102
Trade accounts and other receivables – net152
 62
143
 167
Other current assets and deferred charges5
 2
8
 5
Property, plant, and equipment – net6,167
 2,363
5,625
 5,745
Intangible assets – net of accumulated amortization2,697
 1,177
2,427
 2,669
Regulatory assets, deferred charges, and other13
 —
12
 13
Accounts payable(54) (15)(27) (58)
Accrued liabilities(100) (115)(49) (66)
Regulatory liabilities, deferred income, and other(268) (264)(288) (283)


Nonconsolidated VIEs
Jackalope
At December 31, 2018, we owned a50 percent interest in Jackalope, which provides gathering and processing services for the Powder River basin and was a VIE due to certain risks shared with customers. In April 2019, we sold our interest in Jackalope for $485 million in cash (see Note 5 – Investing Activities).
Brazos Permian II
We own a 15 percent interest in Brazos Permian II, which provides gathering and processing services in the Delaware basin and is a VIE due primarily to our limited participating rights as the minority equity holder. At September 30, 2019,During the carrying valuefirst quarter of 2020 we recorded an impairment of our equity-method investment in Brazos Permian II was $197 million.(see Note 12 – Fair Value Measurements and Guarantees). Our maximum exposure to loss is limited to the carrying value of our investment.
Note 5 – Investing Activities
The following table presents certain items reflected in Other investing income (loss) – net in the Consolidated Statement of IncomeOperations:
 Three Months Ended 
 September 30,		 Nine Months Ended 
 September 30,
 2019 2018 2019 2018
 (Millions)
Impairment of equity-method investments (Note 13)$(114) $—
 $(186) $—
Gain (loss) on deconsolidation of businesses—
 —
 (2) 62
Gain on disposition of equity-method investments—
 —
 122
 —
Other7
 2
 12
 12
Other investing income (loss) – net
$(107) $2
 $(54) $74

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


Notes (Continued)


 Three Months Ended 
June 30,		 Six Months Ended 
June 30,
 2020 2019 2020 2019
 (Millions)
Gain on disposition of equity-method investments (1)$—
 $122
 $—
 $122
Other1
 2
 4
 3
Other investing income (loss) – net
$1
 $124
 $4
 $125
$62 million. We estimated_______________
(1)In April 2019, we sold our 50 percent equity-method interest in Jackalope for $485 million in cash, resulting in a gain on the disposition of $122 million.
Impairment of Equity-Method Investments
Impairment of equity-method investments for the fair value of our interest to be $310six months ended June 30, 2020, includes $938 million using an income approach based on expected future cash flows and an appropriate discount rate (a Level 3 measurement within the fair value hierarchy). The determination of expected future cash flows involved significant assumptions regarding gathering and processing volumes and related capital spending. A 10.9 percent discount rate was utilized and reflected our estimate of the cost of capital as impacted by market conditions and risks associated with the underlying business. The deconsolidated carrying valuefirst-quarter 2020 impairment of the net assets of Jackalope included $47 million of goodwill.
Sale of Jackalope
In April 2019, we sold our 50 percent equity-method interest in Jackalope for $485 million in cash, resulting in a gain on the disposition of $122 million.


Notes (Continued)


investments (see Note 612 – Other IncomeFair Value Measurements and Expenses
The following table presents, by segment, certain other items included in our Consolidated Statement of Income:
 Three Months Ended 
 September 30,		 Nine Months Ended 
 September 30,
 2019 2018 2019 2018
 (Millions)
Selling, general, and administrative expenses       
Other       
Charitable contribution of preferred stock to The Williams Companies Foundation, Inc. (see Note 12)$—
 $35
 $—
 $35
WPZ Merger costs—
 15
 —
 19
        
Other (income) expense – net within Costs and expenses
       
Atlantic-Gulf       
Amortization of regulatory assets associated with asset retirement obligations1
 8
 17
 24
Net accrual (amortization) of regulatory liability related to overcollection of certain employee expenses(9) 5
 (11) 16
Adjustments to regulatory liabilities related to tax reform—
 —
 —
 (10)
Amortization of regulatory liability associated with tax reform(12) —
 (19) —
Reversal of expenditures previously capitalized—
 —
 10
 —
Gain on asset retirement—
 (10) —
 (10)
        
West       
Adjustments to regulatory liabilities related to tax reform—
 —
 —
 (7)
Regulatory charge per approved rates related to tax reform6
 6
 18
 18
Charge for regulatory liability associated with the decrease in Northwest Pipeline’s estimated deferred state income tax rates following WPZ Merger—
 12
 —
 12
        
Other       
Change to (benefit of) regulatory asset associated with Transco’s estimated deferred state income tax rate following WPZ Merger—
 (37) 12
 (37)
        
Other income (expense) – net below Operating income (loss)
       
Atlantic-Gulf       
Allowance for equity funds used during construction9
 32
 21
 78
        
Other       
Income associated with a regulatory asset related to deferred taxes on equity funds used during construction3
 19
 7
 28
Net loss associated with early retirement of debt—
 —
 —
 (7)

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


Notes (Continued)


nineImpairment of RMM Goodwill
Equity earnings (losses) for the six months ended SeptemberJune 30, 2020, includes a $78 million loss associated with the first-quarter 2020 full impairment of goodwill recognized by our investee RMM, which was allocated entirely to our member interest per the terms of the membership agreement.
Note 6 – Other Accruals
The second quarter of 2019 reflectreflects charges of $3 million and $23 million respectively,within Operating and maintenance expenses and $20 million within Selling, general, and administrative expenses for estimated severance and related costs, primarily associated with the VSP.a voluntary separation program. The severance and related costs by segment for the three and six months ended June 30, 2019 are as follows:
Three Months Ended September 30, Nine Months Ended September 30,(Millions)
2019
(Millions)
Transmission & Gulf of Mexico$22
Northeast G&P$(3) $7
10
Atlantic-Gulf11
 30
West2
 16
11
Total$10
 $53
$43


Note 7 – Provision (Benefit) for Income Taxes
The Provision (benefit) for income taxes includes:
Three Months Ended 
 September 30,		 Nine Months Ended 
 September 30,		Three Months Ended 
June 30,		 Six Months Ended 
June 30,
2019 2018 2019 20182020 2019 2020 2019
(Millions)(Millions)
Current:              
Federal$(10) $(19) $(25) $(55)$—
 $(9) $(28) $(15)
State—
 —
 —
 1
(1) —
 —
 —
Foreign1
 —
 1
 —
(9) (19) (24) (54)(1) (9) (28) (15)
Deferred:              
Federal73
 188
 225
 312
93
 91
 (41) 152
State13
 21
 43
 39
25
 16
 (18) 30
86
 209
 268
 351
118
 107
 (59) 182
Provision (benefit) for income taxes$77
 $190
 $244
 $297
$117
 $98
 $(87) $167

The effective income tax ratesrate for the total provision (benefit) for the three and ninesix months ended SeptemberJune 30, 2020 and 2019 areis greater than the federal statutory rate, primarily due to the effect of state income taxes.
The effective income tax rates for the total provision for the three and nine months ended September 30, 2018, are higher than the federal statutory rate primarily due to the effect of state income taxes and a $105 million valuation allowance associated with foreign tax credits, that expire between 2024 and 2027. This is partially offset by the impact of the allocation of income to nontaxable noncontrolling interests. The state income tax provisions include a $38 million provision related to an increase in the deferred state income tax rate (net of federal benefit) partially offset by a net decrease in valuation allowances of $31 million on state net operating losses, both primarily driven by the impact that the completion of the WPZ Merger (see Note 1 – General, Description of Business, and Basis of Presentation) had on income allocation for state tax purposes.

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

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


Notes (Continued)


Note 8 – Earnings (Loss) Per Common Share
Three Months Ended 
 September 30,		 Nine Months Ended 
 September 30,		Three Months Ended 
June 30,		 Six Months Ended 
June 30,
2019 2018 2019 20182020 2019 2020 2019
(Dollars in millions, except per-share
amounts; shares in thousands)
(Dollars in millions, except per-share
amounts; shares in thousands)
Net income (loss) available to common stockholders$220
 $129
 $724
 $416
$303
 $310
 $(215) $504
Basic weighted-average shares1,212,270
 1,023,587
 1,211,938
 893,706
1,213,601
 1,212,045
 1,213,310
 1,211,769
Effect of dilutive securities:              
Nonvested restricted stock units1,790
 2,387
 1,809
 2,102
980
 1,792
 —
 1,818
Stock options105
 530
 196
 514
—
 228
 —
 243
Diluted weighted-average shares(1)1,214,165
 1,026,504
 1,213,943
 896,322
1,214,581
 1,214,065
 1,213,310
 1,213,830
Earnings (loss) per common share:              
Basic$.18
 $.13
 $.60
 $.47
$.25
 $.26
 $(.18) $.42
Diluted$.18
 $.13
 $.60
 $.46
$.25
 $.26
 $(.18) $.41


__________
(1)For the six months ended June 30, 2020, 1.1 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 9 – Employee Benefit Plans
Net periodic benefit cost (credit) is as follows:

Pension BenefitsPension Benefits

Three Months Ended 
 September 30,
Nine Months Ended 
 September 30,		Three Months Ended 
June 30,
Six Months Ended 
June 30,

2019
2018
2019
20182020
2019
2020
2019

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













Service cost$11

$12

$33

$37
$7

$11

$15

$22
Interest cost13

12

38

35
9

13

19

25
Expected return on plan assets(15)
(16)
(46)
(47)(14)
(16)
(27)
(31)
Amortization of net actuarial loss3

6

11

17
7

4

11

8
Net actuarial loss from settlements1

1

1

2
2

—

8

—
Net periodic benefit cost (credit)$13

$15

$37

$44
$11

$12

$26

$24

Other Postretirement BenefitsOther Postretirement Benefits
Three Months Ended 
 September 30,		 Nine Months Ended 
 September 30,		Three Months Ended 
June 30,		 Six Months Ended 
June 30,
2019 2018 2019 20182020 2019 2020 2019
(Millions)(Millions)
Components of net periodic benefit cost (credit):              
Service cost$1
 $1
 $1
 $1
Interest cost2
 1
 6
 5
$1
 $2
 $3
 $4
Expected return on plan assets(3) (2) (8) (8)(2) (3) (5) (5)
Amortization of prior service credit—
 —
 —
 (1)
Reclassification to regulatory liability—
 —
 1
 1
—
 1
 1
 1
Net periodic benefit cost (credit)$—
 $—
 $—
 $(2)$(1) $—
 $(1) $—

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 IncomeOperations.


Notes (Continued)


Amortization of prior service credit included in Net periodic benefit cost (credit) for our other postretirement benefit plans associated with Transco and Northwest Pipeline is recorded to regulatory assets/liabilities instead of Other comprehensive income (loss). The amount of Amortization of prior service credit recognized in regulatory liabilities was $1 million for the nine months ended September 30, 2018.
During the ninesix months ended SeptemberJune 30, 20192020, we contributed $63$11 million to our pension plans and $43 million to our other postretirement benefit plans. We presently anticipate making additional contributions of approximately $13 million to our pension plans and approximately $1$2 million to our other postretirement benefit plans in the remainder of 2019.2020.
Note 10 – Leases
We are a lessee through noncancellable lease agreements for property and equipment consisting primarily of buildings, land, vehicles, and equipment used in both our operations and administrative functions. We recognize a lease liability with an offsetting right-of-use asset in our Consolidated Balance Sheet for operating leases based on the present value of the future lease payments. As an accounting policy, we have elected to combine lease and nonlease components for all classes of leased assets in our calculation of the lease liability and the offsetting right-of-use asset.
Our lease agreements require both fixed and variable periodic payments, with initial terms typically ranging from one year to 15 years, but a certain land lease has a term of 108 years. Payment provisions in certain of our lease agreements contain escalation factors which may be based on stated rates or a change in a published index at a future time. The amount by which a lease escalates based on the change in a published index, which is not known at lease commencement, is considered a variable payment and is not included in the present value of the future lease payments, which only includes those that are stated or can be calculated based on the lease agreement at lease commencement. In addition to the noncancellable periods, many of our lease agreements provide for one or more extensions of the lease agreement for periods ranging from one year in length to an indefinite number of times following the specified contract term. Other lease agreements provide for extension terms that allow us to utilize the identified leased asset for an indefinite period of time so long as the asset continues to be utilized in our operations. In consideration of these renewal features, we assess the term of the lease agreements, which includes using judgment in the determination of which renewal periods and termination provisions, when at our sole election, will be reasonably certain of being exercised. Periods after the initial term or extension terms that allow for either party to the lease to cancel the lease are not considered in the assessment of the lease term. Additionally, we have elected to exclude leases with an original term of one year or less, including renewal periods, from the calculation of the lease liability and the offsetting right-of-use asset.
We used judgment in determining the discount rate upon which the present value of the future lease payments is determined. This rate is based on a collateralized interest rate corresponding to the term of the lease agreement using company, industry, and market information available.
When permitted under our lease agreements, we may sublease certain unused office space for fixed periods that could extend up to the length of the original lease agreement.


Notes (Continued)


 Three Months Ended 
 September 30,		 Nine Months Ended 
 September 30,
 2019
 (Millions)
Lease Cost:   
Operating lease cost$10
 $31
Short-term lease cost—
 —
Variable lease cost7
 21
Sublease income—
 (1)
Total lease cost$17
 $51
Cash paid for amounts included in the measurement of operating lease liabilities$10
 $30
  September 30, 2019
  (Millions)
Other Information:  
Right-of-use asset (included in Regulatory assets, deferred charges, and other in our Consolidated Balance Sheet)
 $213
Operating lease liabilities:  
Current (included in Accrued liabilities in our Consolidated Balance Sheet)
 $23
Noncurrent (included in Regulatory liabilities, deferred income, and other in our Consolidated Balance Sheet)
 $190
Weighted-average remaining lease term – operating leases (years)
 13
Weighted-average discount rate – operating leases
 4.60%

As of September 30, 2019, the following table represents our operating lease maturities, including renewal provisions that we have assessed as being reasonably certain of exercise, for each of the years ended December 31:
 (Millions)
2019 (remainder)$8
202032
202133
202227
202321
Thereafter171
Total future lease payments292
Less amount representing interest79
Total obligations under operating leases$213

We are the lessor to certain lease agreements for office space in our headquarters building, which are insignificant to our financial statements.
Note 1110 – Debt and Banking Arrangements
Long-Term Debt
RetirementsIssuances and retirements
On May 14, 2020, we completed a public offering of $1 billion of 3.5 percent senior unsecured notes due 2030.
On May 8, 2020, Transco issued $700 million of 3.25 percent senior unsecured notes due 2030 and $500 million of 3.95 percent senior unsecured noted due 2050 to investors in a private debt placement. As part of the issuance, Transco entered into a registration rights agreement with the initial purchasers of the unsecured notes. Transco is obligated to file and consummate a registration statement for an offer to exchange the notes for a new issue of substantially identical notes registered under the Securities Act of 1933, as amended, within 365 days from closing and to use commercially reasonable efforts to complete the exchange offer. Transco is required to provide a shelf registration statement to cover resales of the notes under certain circumstances. If Transco fails to fulfill these obligations, additional interest will accrue on the affected securities. The rate of additional interest will be 0.25 percent per annum on the principal amount of the affected securities for the first 90-day period immediately following the occurrence of a registration default, increasing by an additional 0.25 percent per annum with respect to each subsequent 90-day period thereafter, up to a maximum amount for all such registration defaults of 0.5 percent annually. Following the cure of any registration defaults, the accrual of additional interest will cease.
We retired approximately $32 million$1.5 billion of 7.6255.25 percent senior unsecured notes that matured on JulyMarch 15, 2019.2020.
We retired $14 million of 8.75 percent senior unsecured notes that matured on January 15, 2020.
Commercial Paper Program
At SeptemberJune 30, 2019,2020, 0 commercial paper was outstanding under our $4 billion commercial paper program.


Notes (Continued)


Credit Facilities
September 30, 2019June 30, 2020
Stated Capacity OutstandingStated Capacity Outstanding
(Millions)(Millions)
      
Long-term credit facility (1)$4,500
 $—
$4,500
 $—
Letters of credit under certain bilateral bank agreements  14
  15
 
(1)In managing our available liquidity, we do not expect a maximum outstanding amount in excess of the capacity of our credit facility inclusive of any outstanding amounts under our commercial paper program.

Note 1211 – Stockholders’ Equity
IssuanceStockholder Rights Agreement
On March 19, 2020, our board of Preferred Shares
In July 2018, throughdirectors approved the adoption of a wholly owned subsidiary, we contributed 35,000 shareslimited duration stockholder rights agreement (Rights Agreement) and declared a distribution of newly issued1 preferred stock purchase right for each outstanding share of common stock. The Rights Agreement is intended to protect the interests of us and our stockholders by reducing the likelihood of another party gaining control of or significant influence over us without paying an appropriate premium considering recent volatile markets. Each preferred stock purchase right represents the right to purchase, upon certain terms and conditions, one one-thousandth of a share of Series B Non-Voting PerpetualC Participating Cumulative Preferred Stock, (Preferred Stock) to The Williams Companies Foundation, Inc. (a not-for-profit corporation) for use in future charitable and nonprofit causes. The charitable contribution of Preferred Stock was recorded as an expense in the third quarter of 2018. The Preferred Stock was issued for an aggregate value of $35 million and pays non-cumulative quarterly cash dividends when, as and if declared, at a rate of 7.25 percent per year. Our certificate of incorporation authorizes 30 million shares of Preferred Stock, $1$1.00 par value per shares.share. Each one-thousandth of a share of Series C Participating Cumulative Preferred Stock, if issued, would


Notes (Continued)


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
Cash
Flow
Hedges
 
Foreign
Currency
Translation
 
Pension and
Other Postretirement
Benefits
 Total
(Millions)(Millions)
Balance at December 31, 2018$(2) $(1) $(267) $(270)
Balance at December 31, 2019$(2) $(1) $(196) $(199)
Other comprehensive income (loss) before reclassifications
—
 —
 (5) (5)—
 —
 9
 9
Amounts reclassified from accumulated other comprehensive income (loss)
—
 —
 9
 9
—
 —
 14
 14
Other comprehensive income (loss)—
 —
 4
 4
—
 —
 23
 23
Balance at September 30, 2019$(2) $(1) $(263) $(266)
Balance at June 30, 2020$(2) $(1) $(173) $(176)

Reclassifications out of AOCI are presented in the following table by component for the ninesix months ended SeptemberJune 30, 2019:2020:
Component Reclassifications Classification Reclassifications Classification
 (Millions)  (Millions) 
Pension and other postretirement benefits:      
Amortization of actuarial (gain) loss and net actuarial loss from settlements included in net periodic benefit cost (credit) $12
 Note 9 – Employee Benefit Plans $19
 
Other income (expense) – net below Operating income (loss)
Income tax benefit (3) Provision (benefit) for income taxes (5) Provision (benefit) for income taxes
Reclassifications during the period $9
  $14
 



Notes (Continued)


Note 1312 – 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     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)
 
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) (Millions)
Assets (liabilities) at September 30, 2019:          
Assets (liabilities) at June 30, 2020:          
Measured on a recurring basis:                    
ARO Trust investments $187
 $187
 $187
 $—
 $—
 $214
 $214
 $214
 $—
 $—
Energy derivatives assets not designated as hedging instruments 4
 4
 4
 —
 —
Energy derivatives liabilities not designated as hedging instruments (5) (5) (2) —
 (3)
Energy derivative assets designated as hedging instruments 2
 2
 2
 —
 —
Energy derivative assets not designated as hedging instruments 2
 2
 1
 1
 —
Energy derivative liabilities not designated as hedging instruments (4) (4) (1) (1) (2)
Additional disclosures:                    
Long-term debt, including current portion (22,257) (25,234) —
 (25,234) —
 (22,949) (26,387) —
 (26,387) —
Guarantees (42) (29) —
 (13) (16) (41) (27) —
 (11) (16)
                    
Assets (liabilities) at December 31, 2018:          
Assets (liabilities) at December 31, 2019:          
Measured on a recurring basis:                    
ARO Trust investments $150
 $150
 $150
 $—
 $—
 $201
 $201
 $201
 $—
 $—
Energy derivatives assets not designated as hedging instruments 3
 3
 3
 —
 —
Energy derivatives liabilities not designated as hedging instruments (7) (7) (4) —
 (3)
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 (22,414) (23,330) —
 (23,330) —
 (22,288) (25,319) —
 (25,319) —
Guarantees (43) (30) —
 (14) (16) (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


Notes (Continued)


permitted under the terms of our master netting arrangements. Further, the amounts do not include cash held on deposit in margin accounts that we have received or remitted to collateralize certain derivative positions. Energy derivativesderivative assets are reported in Other current assets and deferred charges and Regulatory assets, deferred charges, and other in the Consolidated Balance Sheet. Energy derivativesderivative liabilities are reported in Accrued liabilities and Regulatory liabilities, deferred income, and other in the Consolidated Balance Sheet.
Reclassifications of fair value between Level 1, Level 2, and Level 3 of the fair value hierarchy, if applicable, are made at the end of each quarter. No transfers between Level 1 and Level 2 occurred during the nine months ended September 30, 2019 or 2018.
Additional fair value disclosures
Long-term debt, including current portion: The disclosed fair value of our long-term debt is determined primarily by a market approach using broker quoted indicative period-end bond prices. The quoted prices are based on observable transactions in less active markets for our debt or similar instruments. The fair values of the financing obligations associated with our Dalton lateral and Atlantic Sunrise projects, which are included within long-term debt, were determined using an income approach.
Guarantees: Guarantees primarily consist of a guarantee we have provided in the event of nonpayment by our previously owned communications subsidiary, Williams Communications Group (WilTel), on a lease performance obligation that extends through 2042. Guarantees also include an indemnification related to a disposed operation.
To estimate the fair value of the WilTel guarantee, an estimated default rate is applied to the sum of the future contractual lease payments using an income approach. The estimated default rate is determined by obtaining the average cumulative issuer-weighted corporate default rate based on the credit rating of WilTel’s current owner and the term of the underlying obligation. The default rate is published by Moody’s Investors Service. The carrying value of the WilTel guarantee is reported in Accrued liabilities in the Consolidated Balance Sheet. The maximum potential undiscounted exposure is approximately $28$27 million at SeptemberJune 30, 2019.2020. Our exposure declines systematically through the remaining term of WilTel’s obligation.
The fair value of the guarantee associated with the indemnification related to a disposed operation was estimated using an income approach that considered probability-weighted scenarios of potential levels of future performance. The terms of the indemnification do not limit the maximum potential future payments associated with the guarantee. The carrying value of this guarantee is reported in Regulatory liabilities, deferred income, and other in the Consolidated Balance Sheet.
We are required by our revolving credit agreement to indemnify lenders for certain taxes required to be withheld from payments due to the lenders and for certain tax payments made by the lenders. The maximum potential amount of future payments under these indemnifications is based on the related borrowings and such future payments cannot currently be determined. These indemnifications generally continue indefinitely unless limited by the underlying tax regulations and have 0 carrying value. We have never been called upon to perform under these indemnifications and have no current expectation of a future claim.
Nonrecurring fair value measurements

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

The assessment considered the total fair value of the businesses within the Northeast G&P reporting unit, which 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)


Nonrecurringdepreciation, and amortization) market multiples as compared with recent history and significantly higher industry weighted-average discount rates. The fair value measurementsof 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   Impairments
   Nine Months Ended 
 September 30,		   Six Months Ended 
June 30,
 Segment Date of Measurement Fair Value 2019 2018 Segment Date of Measurement Fair Value 2020 2019
 (Millions) (Millions)
Impairment of certain assets:            
Certain gathering assets (1) West June 30, 2019 $40
 $59
   West June 30, 2019 $40
 
 $59
Certain idle gathering assets (2) West March 31, 2019 —
 12
   West March 31, 2019 —
 
 12
Certain idle pipeline assets (3) Other June 30, 2018 25
 
 $66
Other impairments and write-downs   5
 —
     5
Impairment of certain assets   $76
 $66
   
 $76
Impairment of equity-method investments:            
RMM (3) West March 31, 2020 $557
 $243
  
Brazos Permian II (3) West March 31, 2020 —
 193
  
Caiman II (4) Northeast G&P March 31, 2020 191
 229
  
Appalachia Midstream Investments (4) Northeast G&P March 31, 2020 2,700
 127
  
Aux Sable (4) Northeast G&P March 31, 2020 7
 39
  
Laurel Mountain (4) Northeast G&P September 30, 2019 $242
 $79
   Northeast G&P March 31, 2020 236
 10
  
Appalachia Midstream Investments (5) Northeast G&P September 30, 2019 102
 17
  
Pennant (6) Northeast G&P August 31, 2019 11
 17
  
UEOM (7) Northeast G&P March 17, 2019 1,210
 74
  
Discovery (4) Transmission & Gulf of Mexico March 31, 2020 367
 97
  
UEOM (5) Northeast G&P March 17, 2019 1,210
 
 $74
Other   (1)     —
 (2)
Impairment of equity-method investments   $186
     $938
 $72
_______________
(1)
Relates to a gas gathering system in the Eagle Ford Shale region with expected declines in asset utilization and possible idling of the gathering system. The estimated fair value of the Property, plant, and equipment – net was determined using a market approach which incorporated indications of interest from third parties.

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

(3)
Relates to certain idle pipelines. The estimated fair value ofFollowing the Property, plant, and equipment – net was determined by apreviously described declining market approach incorporating information derived from bids received for these assets, which we marketed for sale together with certain other assets. These inputs resulted in a fair value measurement within Level 2 ofconditions during the fair value hierarchy. We sold these assets in the fourthfirst quarter of 2018.

(4)
Relates to a gas gathering system in the Marcellus region that was adversely impacted by lower sustained forward natural gas price expectations and changes in expected producer activity.2020, we evaluated these investments for other-than-temporary impairment. The estimated fair value was determinedmeasured using an income approach. We utilized a discount rate of 10.2 percent in our analysis. This impairment is reported in Other investing income (loss) – net in the Consolidated Statement of Income.

(5)
Relates to a certain gathering system held in Appalachia Midstream Investments that was adversely impacted by changes in the timing of expected producer activity. The estimated fair value was determined using an income approach. We utilized a discount rate of 9.0 percent in our analysis. This impairment is reported in Other investing income (loss) – net in the Consolidated Statement of Income.



Notes (Continued)


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.

(6)(4)
Following the previously described declining market conditions during the first quarter of 2020, we evaluated these investments for other-than-temporary impairment. The impairments within our Northeast G&P segment are primarily associated with operations in wet-gas areas where producer drilling activities are influenced by NGL prices which historically trend with crude oil prices. The fair values of our investments in Caiman II and Aux Sable Liquid Products LP (Aux Sable) were estimated fair value of Pennant Midstream, LLC (“Pennant”) was determined byusing a market approach, based on recent observable third-party transactions. These inputs resulted in areflecting valuation multiples ranging from 5.0x to 6.2x EBITDA (weighted-average 6.0x). The fair value measurement within Level 2values 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 hierarchy. This impairment is reported in Other investing income (loss) – net invalue. The assumed valuation multiples and industry weighted-average discount rates utilized were both significantly influenced by the Consolidated Statement of Income.
recent market declines previously discussed.

(7)(5)
The estimated fair value was determined by a market approach based on the transaction price for the purchase of the remaining interest in UEOM as finalized just prior to the signing and closing of the acquisition in March 2019 (see Note 2 – Acquisitions). These inputs resulted in a fair value measurement within Level 2 of the fair value hierarchy. This impairment is reported in Other investing income (loss) - net in the Consolidated Statement of Income.
Note 1413 – Contingent Liabilities
Reporting of Natural Gas-Related Information to Trade Publications
Direct and indirect purchasers of natural gas in various states filed individual and class actions against us, our former affiliate WPX Energy, Inc. (WPX) and its subsidiaries, and others alleging the manipulation of published gas price indices and seeking unspecified amounts of damages. Such actions were transferred to the Nevada federal district court for consolidation of discovery and pre-trial issues. We have agreed to indemnify WPX and its subsidiaries related to this matter.
In the individual action, filed by Farmland Industries Inc. (Farmland), the court issued an order on May 24, 2016, granting one of our co-defendant’s motion for summary judgment as to Farmland’s claims. On January 5, 2017, the court extended such ruling to us, entering final judgment in our favor. Farmland appealed. On March 27, 2018, the appellate court reversed the district court’s grant of summary judgment, and on April 10, 2018, the defendants filed a petition for rehearing with the appellate court, which was denied on May 9, 2018. The case was remanded to the Nevada federal district court and subsequently has been remanded to its originally filed court, the Kansas federal district court.
In the putative class actions, on March 30, 2017, the court issued an order denying the plaintiffs’ motions for class certification. On June 13, 2017, the United States Court of Appeals for the Ninth Circuit granted the plaintiffs’ petition for permission to appeal the order. On August 6, 2018, the Ninth Circuit reversed the order denying class certification and remanded the case to the Nevada federal district court.
We reached an agreement to settle two of the actions, and on April 22, 2019, the Nevada federal district court preliminarily approved the settlements, which are on behalf of Kansas and Missouri class members. The final fairness hearing on the settlement occurred August 5, 2019, and a final judgment of dismissal with prejudice was entered the same day.
Two putative class actions remain unresolved, and they have been remanded to their originally filed court, the Wisconsin federal district court. Trial is scheduled to begin June 14, 2021.
Because of the uncertainty around the remaining pending unresolved issues, we cannot reasonably estimate a range of potential exposure at this time. However, it is reasonably possible that the ultimate resolution of these actions and our related indemnification obligation could result in a potential loss that may be material to our results of operations.


Notes (Continued)


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


Notes (Continued)


settled the claim with James West. Certain claims by FHRA against us were resolved by the Alaska Supreme Court in our favor. FHRA’s claims against us for contractual indemnification and statutory claims for damages related to off-site sulfolane remain pending.were remanded to the Alaska Superior Court. The State of Alaska filed its action in March 2014, seeking damages. The City of North Pole (North Pole) filed its lawsuit in November 2014, seeking past and future damages, as well as punitive damages. Both we and WAPI asserted counterclaims against the State of Alaska and North Pole, and cross-claims against FHRA. FHRA has also filed cross-claims against us.
The underlying factual basis and claims in the cases are similar and may duplicate exposure. As such, in February 2017, the three cases were consolidated into one action in state court containing the remaining claims from the James West case and those of the State of Alaska and North Pole. The State of Alaska later announced the discovery of additional contaminants per- and polyfluoralkyl (PFOS and PFOA) offsite of the refinery, and the Court permitted the State of Alaska to amend its complaint to add a claim for offsite PFOS/PFOA contamination. The Court subsequently remanded the offsite PFOS/PFOA claims to the Alaska Department of Environmental Conservation for investigation and stayed the claims pending their potential resolution at the administrative agency. Several trial dates encompassing all three cases have been scheduled and stricken. Trial commencedIn the summer of 2019, the Court deconsolidated the cases for purposes of trial. A bench trial on all claims except North Pole’s claims began in October 2019. Due to
In January 2020, the ongoing assessmentAlaska Superior Court issued its Memorandum of the level and extentDecision finding in favor of sulfolane contamination, the lack of an articulated cleanup level for sulfolane, and the lack of a concrete remedial proposal and cost estimate, we are unable to estimate a range of exposure to the State of Alaska and FHRA, with the total incurred and potential future damages estimated to be $86 million. The Court found that FHRA is not entitled to contractual indemnification from us because FHRA contributed to the sulfolane contamination. On March 23, 2020, the Court entered final judgment in the case. Filing deadlines were stayed until May 1, 2020. However, on April 21, 2020, we filed a Notice of Appeal. We also filed post-judgment motions including a Motion for New Trial and a Motion to Alter or Amend the Judgment. These post-trial motions have now been resolved with the Court’s denial of the last motion on June 11, 2020. Our Statement of Points on Appeal was filed on July 13, 2020. On June 22, 2020, the Court stayed the North Pole at this time.Pole’s case pending resolution of the appeal in the State of Alaska and FHRA case. We currentlyhave recorded an accrued liability in the amount of our estimate that ourof the probable loss. It is reasonably possible loss exposure to FHRAthat we may not be successful on appeal and could range from an insignificant amountultimately pay up to $32 million, although uncertainties inherent in the litigation process, expert evaluations, and jury dynamics might cause our exposure to exceed that amount.
Independentamount of the litigation matter described in the preceding paragraphs, in 2013, the Alaska Department of Environmental Conservation indicated that it views FHRA and us as responsible parties, and that it intends to enter a compliance order to address the environmental remediation of sulfolane and other possible contaminants including cleanup work outside the refinery’s boundaries. To date, no compliance order has been issued. Due to the ongoing assessment of the level and extent of sulfolane contamination, the ultimate cost of remediation and division of costs among the potentially responsible parties, and the previously described separate litigation, we are unable to estimate a range of exposure at this time.judgment.
Royalty Matters
Certain of our customers, including one major customer,Chesapeake, have been named in various lawsuits alleging underpayment of royalties and claiming, among other things, violations of anti-trust laws and the Racketeer Influenced and Corrupt Organizations Act. We have also been named as a defendant in certain of these cases filed in Pennsylvania based on allegations that we improperly participated with that major 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 apply to both the customerChesapeake and us. The settlement as reported would not require any contribution from us. On June 28, 2020, Chesapeake filed for Chapter 11 bankruptcy protection in the United States Bankruptcy Court for the Southern District of Texas.


Notes (Continued)


Litigation Against Energy Transfer and Related Parties
On April 6, 2016, we filed suit in Delaware Chancery Court against Energy Transfer Equity, L.P. (Energy Transfer) and LE GP, LLC (the general partner for Energy Transfer) alleging willful and material breaches of the Agreement and Plan of Merger (ETE Merger Agreement) with Energy Transfer resulting from the private offering by Energy Transfer on March 8, 2016, of Series A Convertible Preferred Units (Special Offering) to certain Energy Transfer insiders and other accredited investors. The suit seeks, among other things, an injunction ordering the defendants to unwind the Special Offering and to specifically perform their obligations under the ETE Merger Agreement. On April 19, 2016, we filed an amended complaint seeking the same relief. On May 3, 2016, Energy Transfer and LE GP, LLC filed an answer and counterclaims.
On May 13, 2016, we filed a separate complaint in Delaware Chancery Court against Energy Transfer, LE GP, LLC, and the other Energy Transfer affiliates that are parties to the ETE Merger Agreement, alleging material breaches of the ETE Merger Agreement for failing to cooperate and use necessary efforts to obtain a tax opinion required under the ETE Merger Agreement (Tax Opinion) and for otherwise failing to use necessary efforts to consummate the merger under the ETE Merger Agreement wherein we would be merged with and into the newly formed Energy Transfer Corp LP (ETC) (ETC Merger). The suit sought, among other things, a declaratory judgment and injunction preventing Energy Transfer from terminating or otherwise avoiding its obligations under the ETE Merger Agreement due to any failure to obtain the Tax Opinion.


Notes (Continued)


The Court of Chancery coordinated the Special Offering and Tax Opinion suits. On May 20, 2016, the Energy Transfer defendants filed amended affirmative defenses and verified counterclaims in the Special Offering and Tax Opinion suits, alleging certain breaches of the ETE Merger Agreement by us and seeking, among other things, a declaration that we were not entitled to specific performance, that Energy Transfer could terminate the ETC Merger, and that Energy Transfer is entitled to a $1.48 billion termination fee. On June 24, 2016, following a two-day trial, the court issued a Memorandum Opinion and Order denying our requested relief in the Tax Opinion suit. The court did not rule on the substance of our claims related to the Special Offering or on the substance of Energy Transfer’s counterclaims. On June 27, 2016, we filed an appeal of the court’s decision with the Supreme Court of Delaware, seeking reversal and remand to pursue damages. On March 23, 2017, the Supreme Court of Delaware affirmed the Court of Chancery’s ruling. On March 30, 2017, we filed a motion for reargument with the Supreme Court of Delaware, which was denied on April 5, 2017.
On September 16, 2016, we filed an amended complaint with the Court of Chancery seeking damages for breaches of the ETE Merger Agreement by defendants. On September 23, 2016, Energy Transfer filed a second amended and supplemental affirmative defenses and verified counterclaim with the Court of Chancery seeking, among other things, payment of the $1.48 billion termination fee due to our alleged breaches of the ETE Merger Agreement. On December 1, 2017, the court granted our motion to dismiss certain of Energy Transfer’s counterclaims, including its claim seeking payment of the $1.48 billion termination fee. On December 8, 2017, Energy Transfer filed a motion for reargument, which the Court of Chancery denied on April 16, 2018. The Court of Chancery previouslyhad scheduled trial for May 20 through May 24, 2019; the court struck the trialthis setting and has re-scheduledreset the trial for June 8 through June 11, and June 15, 2020. Due to COVID-19, the court struck the June 2020 setting and re-scheduled the trial for August 31 through September 4, 2020; this setting was also struck as a result of COVID-19. We await a new trial setting.
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. No new trial date has been set.Trial is currently reset for November 4, 2020. We believe that certain losses incurred arising directly from the explosion and fire will be covered by our general liability policy and any uninsured losses are not expected to be material.


Notes (Continued)


Other
On August 31, 2018, Transco submitted to the FERC a general rate filing principally designed to recover increased costs and to comply with the terms of the settlement in its prior rate proceeding. The new rates became effective March 1, 2019, subject to refund and the outcome of a hearing. In October 2019, we reached an agreement on the terms of a settlement with the participants that would resolve all issues in the rate case without the need for a hearing. Final resolution of the rate case is subject to the filing ofhearing, and on December 31, 2019, we filed a formal stipulation and agreement with and subsequent approval by, the FERC.FERC setting forth such terms of settlement. On March 24, 2020, the FERC issued an order approving the uncontested rate case settlement, which became effective on June 1, 2020. As of SeptemberJune 30, 2019,2020, we have provided a $131$284 million reserve for rate refunds which we believe is adequate for anyrelated to increased rates collected since March 2019, reflected in Accounts payable in the Consolidated Balance Sheet. The refunds that may be required.were paid on July 1, 2020.
Environmental Matters
We are a participant in certain environmental activities in various stages including assessment studies, cleanup operations, and/or remedial processes at certain sites, some of which we currently do not own. We are monitoring these sites in a coordinated effort with other potentially responsible parties, the U.S. Environmental Protection Agency (EPA), or other governmental authorities. We are jointly and severally liable along with unrelated third parties in some of these activities and solely responsible in others. Certain of our subsidiaries have been identified as potentially responsible parties at various Superfund and state waste disposal sites. In addition, these subsidiaries have incurred, or are alleged to have incurred, various other hazardous materials removal or remediation obligations under environmental laws. As of SeptemberJune 30, 2019,2020, we have accrued liabilities totaling $33$30 million for these matters, as discussed below. Estimates of the most likely costs of cleanup are generally based on completed assessment studies, preliminary results of studies,


Notes (Continued)


or our experience with other similar cleanup operations. At SeptemberJune 30, 2019,2020, certain assessment studies were still in process for which the ultimate outcome may yield different estimates of most likely costs. Therefore, the actual costs incurred will depend on the final amount, type, and extent of contamination discovered at these sites, the final cleanup standards mandated by the EPA or other governmental authorities, and other factors.
The EPA and various state regulatory agencies routinely promulgate and propose new rules and issue updated guidance to existing rules. These rulemakings include, but are not limited to, rules for reciprocating internal combustion engine and combustion turbine maximum achievable control technology, air quality standards for one-hour nitrogen dioxide emissions, and volatile organic compound and methane new source performance standards impacting design and operation of storage vessels, pressure valves, and compressors. The EPA previously issued its rule regarding National Ambient Air Quality Standards for ground-level ozone. We are monitoring the rule’s implementation as it will trigger additional federal and state regulatory actions that may impact our operations. Implementation of the regulations is expected to result in impacts to our operations and increase the cost of additions to Property, plant, and equipment – net in the Consolidated Balance Sheet for both new and existing facilities in affected areas. We are unable to reasonably estimate the cost of additions that may be required to meet the regulations at this time due to uncertainty created by various legal challenges to these regulations and the need for further specific regulatory guidance.
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 SeptemberJune 30, 20192020, we have accrued liabilities of $5$4 million for these costs. We expect that these costs will be recoverable through rates.
We also accrue environmental remediation costs for natural gas underground storage facilities, primarily related to soil and groundwater contamination. At SeptemberJune 30, 20192020, we have accrued liabilities totaling $8$7 million for these costs.
Former operations
We have potential obligations in connection with assets and businesses we no longer operate. These potential obligations include remediation activities at the direction of federal and state environmental authorities and the indemnification of the purchasers of certain of these assets and businesses for environmental and other liabilities existing


Notes (Continued)


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 SeptemberJune 30, 20192020, we have accrued environmental liabilities of $20$19 million related to these matters.
Other Divestiture Indemnifications
Pursuant to various purchase and sale agreements relating to divested businesses and assets, we have indemnified certain purchasers against liabilities that they may incur with respect to the businesses and assets acquired from us. The indemnities provided to the purchasers are customary in sale transactions and are contingent upon the purchasers incurring liabilities that are not otherwise recoverable from third parties. The indemnities generally relate to breach of


Notes (Continued)


warranties, tax, historic litigation, personal injury, property damage, environmental matters, right of way, and other representations that we have provided.
At SeptemberJune 30, 20192020, other than as previously disclosed, we are not aware of any material claims against us involving the indemnities; thus, we do not expect any of the indemnities provided pursuant to the sales agreements to have a material impact on our future financial position. Any claim for indemnity brought against us in the future may have a material adverse effect on our results of operations in the period in which the claim is made.
In addition to the foregoing, various other proceedings are pending against us which 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 1514 – Segment Disclosures
Our reportable segments are Transmission & Gulf of Mexico, Northeast G&P, Atlantic-Gulf, and West. All remaining business activities are included in Other. (See Note 1 – General, Description of Business, and Basis of Presentation.)
Performance Measurement
We evaluate segment operating performance based upon Modified EBITDA (earnings before interest, taxes, depreciation, and amortization). This measure represents the basis of our internal financial reporting and is the primary performance measure used by our chief operating decision maker in measuring performance and allocating resources among our reportable segments. Intersegment revenues primarily represent the sale of NGLs from our natural gas processing plants to our marketing business.


Notes (Continued)


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.


Notes (Continued)


The following table reflects the reconciliation of Segment revenues to Total revenues as reported in the Consolidated Statement of IncomeOperations and Total assets by reportable segment.
Northeast G&P Atlantic-Gulf West Other Eliminations TotalTransmission & Gulf of Mexico Northeast G&P West Other Eliminations Total
(Millions)  (Millions)
Three Months Ended September 30, 2019
Three Months Ended June 30, 2020Three Months Ended June 30, 2020
Segment revenues:                      
Service revenues                      
External$340
 $718
 $433
 $4
 $—
 $1,495
$783
 $342
 $316
 $5
 $—
 $1,446
Internal13
 13
 —
 3
 (29) —
12
 12
 —
 4
 (28) —
Total service revenues353
 731
 433
 7
 (29) 1,495
795
 354
 316
 9
 (28) 1,446
Total service revenues – commodity consideration1
 7
 30
 —
 —
 38
3
 1
 21
 —
 —
 25
Product sales                      
External22
 66
 378
 —
 —
 466
29
 (8) 289
 —
 —
 310
Internal8
 10
 11
 —
 (29) —
7
 9
 14
 —
 (30) —
Total product sales30
 76
 389
 —
 (29) 466
36
 1
 303
 —
 (30) 310
Total revenues$384
 $814
 $852
 $7
 $(58) $1,999
$834
 $356
 $640
 $9
 $(58) $1,781
                      
Three Months Ended September 30, 2018
Three Months Ended June 30, 2019Three Months Ended June 30, 2019
Segment revenues:                      
Service revenues                      
External$236
 $595
 $533
 $7
 $—
 $1,371
$797
 $319
 $368
 $5
 $—
 $1,489
Internal11
 12
 —
 3
 (26) —
11
 11
 —
 3
 (25) —
Total service revenues247
 607
 533
 10
 (26) 1,371
808
 330
 368
 8
 (25) 1,489
Total service revenues – commodity consideration6
 18
 97
 —
 —
 121
13
 3
 40
 —
 —
 56
Product sales                      
External59
 46
 706
 —
 —
 811
51
 29
 416
 —
 —
 496
Internal10
 85
 26
 —
 (121) —
17
 8
 18
 —
 (43) —
Total product sales69
 131
 732
 —
 (121) 811
68
 37
 434
 —
 (43) 496
Total revenues$322
 $756
 $1,362
 $10
 $(147) $2,303
$889
 $370
 $842
 $8
 $(68) $2,041
                      
Nine Months Ended September 30, 2019
Six Months Ended June 30, 2020Six Months Ended June 30, 2020
Segment revenues:                      
Service revenues                      
External$925
 $2,102
 $1,384
 $13
 $—
 $4,424
$1,597
 $686
 $627
 $10
 $—
 $2,920
Internal34
 36
 —
 9
 (79) —
27
 26
 —
 7
 (60) —
Total service revenues959
 2,138
 1,384
 22
 (79) 4,424
1,624
 712
 627
 17
 (60) 2,920
Total service revenues – commodity consideration9
 33
 116
 —
 —
 158
8
 3
 42
 —
 —
 53
Product sales                      
External87
 169
 1,256
 —
 —
 1,512
70
 15
 636
 —
 —
 721
Internal27
 57
 46
 —
 (130) —
18
 15
 26
 —
 (59) —
Total product sales114
 226
 1,302
 —
 (130) 1,512
88
 30
 662
 —
 (59) 721
Total revenues$1,082
 $2,397
 $2,802
 $22
 $(209) $6,094
$1,720
 $745
 $1,331
 $17
 $(119) $3,694
                      
           



Notes (Continued)


Northeast G&P Atlantic-Gulf West Other Eliminations TotalTransmission & Gulf of Mexico Northeast G&P West Other Eliminations Total
(Millions)  (Millions)
Nine Months Ended September 30, 2018
           
Six Months Ended June 30, 2019Six Months Ended June 30, 2019
Segment revenues:                      
Service revenues                      
External$677
 $1,769
 $1,599
 $17
 $—
 $4,062
$1,608
 $585
 $727
 $9
 $—
 $2,929
Internal30
 37
 —
 9
 (76) —
23
 21
 —
 6
 (50) —
Total service revenues707
 1,806
 1,599
 26
 (76) 4,062
1,631
 606
 727
 15
 (50) 2,929
Total service revenues – commodity consideration14
 45
 257
 —
 —
 316
26
 8
 86
 —
 —
 120
Product sales                      
External214
 131
 1,759
 —
 —
 2,104
103
 65
 878
 —
 —
 1,046
Internal28
 198
 63
 —
 (289) —
47
 19
 35
 —
 (101) —
Total product sales242
 329
 1,822
 —
 (289) 2,104
150
 84
 913
 —
 (101) 1,046
Total revenues$963
 $2,180
 $3,678
 $26
 $(365) $6,482
$1,807
 $698
 $1,726
 $15
 $(151) $4,095
                      
September 30, 2019           
June 30, 2020           
Total assets (1)$19,569
 $14,609
 $10,647
 $1,797
 $(1,279) $45,343
December 31, 2019           
Total assets$15,445
 $16,888
 $13,550
 $928
 $(530) $46,281
$18,796
 $15,399
 $11,265
 $1,151
 $(571) $46,040
December 31, 2018           
Total assets$14,526
 $16,346
 $13,948
 $849
 $(367) $45,302

_______________
(1)
Increase in Other Total assets is due primarily to increased cash balance.
The following table reflects the reconciliation of Modified EBITDA to Net income (loss) as reported in the Consolidated Statement of IncomeOperations.
Three Months Ended 
 September 30,		 Nine Months Ended 
 September 30,		Three Months Ended 
June 30,		 Six Months Ended 
June 30,
2019 2018 2019 20182020 2019 2020 2019
(Millions)(Millions)
Modified EBITDA by segment:              
Transmission & Gulf of Mexico$615
 $590
 $1,277
 $1,226
Northeast G&P$345
 $281
 $947
 $786
370
 303
 739
 602
Atlantic-Gulf599
 492
 1,683
 1,418
West311
 412
 921
 1,214
253
 212
 468
 468
Other(2) 6
 1
 (49)8
 7
 15
 3
1,253
 1,191
 3,552
 3,369
1,246
 1,112
 2,499
 2,299
Accretion expense associated with asset retirement obligations for nonregulated operations(8) (8) (25) (26)(7) (8) (17) (17)
Depreciation and amortization expenses(435) (425) (1,275) (1,290)(430) (424) (859) (840)
Impairment of goodwill—
 —
 (187) —
Equity earnings (losses)93
 105
 260
 279
108
 87
 130
 167
Impairment of equity-method investments—
 2
 (938) (72)
Other investing income (loss) – net(107) 2
 (54) 74
1
 124
 4
 125
Proportional Modified EBITDA of equity-method investments(181) (205) (546) (552)(192) (175) (384) (365)
Interest expense(296) (270) (888) (818)(294) (296) (590) (592)
(Provision) benefit for income taxes(77) (190) (244) (297)(117) (98) 87
 (167)
Net income (loss)$242
 $200
 $780
 $739
$315
 $324
 $(255) $538



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.
Our operations are presentedEffective January 1, 2020, following an organizational realignment, our interstate natural gas pipeline Northwest Pipeline, which was reported within the following reportable segments: Northeast G&P,West reporting segment throughout 2019, is now managed within the Transmission & Gulf of Mexico reporting segment (previously identified as the Atlantic-Gulf and West, consistentreporting segment). Consistent with the manner in which our chief operating decision maker evaluates performance and allocates resources.resources, our operations are conducted, managed, and presented within the following reportable segments: Transmission & Gulf of Mexico, Northeast G&P, and West. All remaining business activities as well as corporate activities are included in Other. Our reportable segments are comprised of the following businesses:
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 West Virginia and the Utica Shale region of eastern Ohio, includingas 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), as well as 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). Northeast G&P includes a 65 percent interest in the Northeast JV (a consolidated entity), which includes our existing Ohio Valley assets and UEOM (see Note 2 – Acquisitions of Notes to Consolidated Financial Statements).
Atlantic-Gulf is comprised of our interstate natural gas pipeline, Transco, and significant 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 entity), which is a proprietary floating production system, as well as a 50 percent equity-method investment in Gulfstream, a 60 percent equity-method investment in Discovery, and a 41 percent interest in Constitution (a consolidated entity), which is developing a pipeline project (see Note 4 – Variable Interest Entities of Notes to Consolidated Financial Statements).
West is comprised of our interstate natural gas pipeline, Northwest Pipeline, and our gathering, processing, and treating operations in the Rocky Mountain region of Colorado and Wyoming, the Barnett Shale region of north-central Texas, the Eagle Ford Shale region of south Texas, the Permian Shale region of west Texas, the Haynesville Shale region of northwest Louisiana, and the Mid-Continent region which includes the Anadarko, Arkoma, and ArkomaPermian 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 investmentinterest in Brazos Permian II.II, LLC (Brazos Permian II). West also included our former natural gas gathering and processing assets in the Four Corners area of New Mexico and Colorado, which were sold during the fourth quarter of 2018, and our former 50 percent interestequity-method investment in Jackalope, (an equity-method investment following deconsolidation as of June 30, 2018), 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 September 2019,June 2020, we paid a regular quarterly dividend of $0.38$0.40 per share.
Overview of NineSix Months Ended SeptemberJune 30, 20192020
Net income (loss) attributable to The Williams Companies, Inc., for the ninesix months ended SeptemberJune 30, 2019, increased $3102020, decreased $719 million compared to the ninesix months ended SeptemberJune 30, 2018, reflecting $362 million of increased 2019, reflecting:service revenues primarily associated with expansion projects, a $269
•
$866 million increase in Impairment of equity-method investments;
•
$187 million of Impairment of goodwill in 2020;
$122 million decrease to Net income (loss) attributable to noncontrolling interests primarily due to the WPZ Merger, a $122 million gain on the second-quarter 2019 sale of our 50 percent interest in Jackalope, and the absence of a 2018 charge for a valuation allowance2019 gain on foreign tax credits. the sale of our interest in Jackalope;
A $37 million decrease in equity earnings, primarily due to our share of an impairment of goodwill recorded by an equity-method investee in 2020;
$15 million of lower commodity margins.
These increases areunfavorable changes were partially offset by:
A $254 million favorable change in provision for income taxes driven by $186 million of impairments of equity-method investments in 2019, lower commodity margins, the absence of the Four Corners area business which was sold in October 2018, higher interest expense, the absence of a prior year $62 million gain on deconsolidation of Jackalope, lower Transco allowance for equity funds used during construction (AFUDC), and current year severance charges. Long-lived asset impairments in the current year were substantially offset by similar levels of impairments in the prior year.pre-tax income;
•
$76 million increase due to the absence of 2019 Impairment of certain assets;
•
A $74 million favorable change in Net income (loss) attributable to noncontrolling interests primarily due to the noncontrolling interests’ share of the first-quarter 2020 goodwill impairment charge;
•
$70 million of lower Operating and maintenance expenses;
•
$40 million of lower Selling, general, and administrative expenses.
The following discussion and analysis of results of operations and financial condition and liquidity should be read in conjunction with the consolidated financial statements and notes thereto of this Form 10‑Q and our Annual Report onannual consolidated financial statements and notes thereto in Exhibit 99.1 of our Form 10-K8-K dated February 21, 2019.May 4, 2020.
Acquisition of UEOM
As of December 31, 2018, we owned a 62 percent interest in UEOM which we accounted for as an equity-method investment. On March 18, 2019, we signed and closed the acquisition of the remaining 38 percent interest in UEOM. Total consideration paid, including post-closing adjustments, was $741 million in cash funded through credit facility borrowings and cash on hand. As a result of acquiring this additional interest, we obtained control of and now consolidate UEOM. (See Note 2 – Acquisitions of Notes to Consolidated Financial Statements.)
Northeast JV
Concurrent with the UEOM acquisition, we executed an agreement whereby we contributed our consolidated interests in UEOM and our Ohio Valley midstream business to a newly formed partnership. In June 2019, our partner invested approximately $1.33 billion (subject to post-closing adjustments) for a 35 percent ownership interest, and we retained 65 percent ownership of, as well as operate and consolidate, the Northeast JV business.
Sale of Jackalope
In April 2019, we sold our interest in Jackalope for $485 million in cash, resulting in a gain on the disposition of $122 million.Recent Developments
Expansion Project Update
Rivervale South to MarketTransmission & Gulf of Mexico
Hillabee
In August 2018, we received approval fromFebruary 2016, the FERC to expandissued a certificate order for the initial phases of Transco’s Hillabee Expansion Project. The project involves an expansion of Transco’s existing natural gas transmission system from Station 85 in west central Alabama to provide incremental firm transportation capacity from the existing Rivervalean interconnection with Tennessee Gas Pipeline on Transco’s North New Jersey Extension to other existing Transco locations within New Jersey.the Sabal Trail pipeline in east central Alabama. The project was placed into partial service on July 1, 2019. The remaining portionis 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 SeptemberMay 1, 2019. The full2020. Together, the first two phases of the project increased capacity by 1901,025 Mdth/d.
Ohio River Supply Hub Expansion
We agreed to expand our services for certain customers to provide additional rich gas processing capacity in the Marcellus and Upper Devonian Shale in West Virginia and Pennsylvania. Associated with these agreements, we have expanded the inlet processing capacity of our Oak Grove facility to 400 MMdf/d. We have also constructed


Management’s Discussion and Analysis (Continued)

a new NGL pipeline from MoundsvilleCOVID-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 have taken steps intended to protect the safety of our customers, employees and communities, and to support the continued delivery of safe and reliable service to our customers and the communities we serve. We are continuing to monitor developments with respect to the Harrison Hub fractionation facilityoutbreak and note the following:
Our financial condition, results of operations, and liquidity have not been materially impacted by direct effects of COVID-19.
We believe we have the ability to provide an additional outlet for NGLs. These expansions are supportedaccess the debt market, if necessary, as evidenced by long-term, fee-based agreementsthe successful completion of debt offerings during second-quarter 2020, and volumetric commitments.continue to have significant levels of unused capacity on our revolving credit facility.
Norphlet ProjectWe 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.
Customer Bankruptcies
In March 2016, weJune 2020, our customer Chesapeake Energy Corporation (Chesapeake) announced that it had voluntarily filed for relief under Chapter 11 of the U.S. Bankruptcy Code. We provide midstream services, including wellhead gathering, for the natural gas that Chesapeake and its joint interest owners produce primarily in the Eagle Ford Shale, Haynesville Shale, and Marcellus Shale regions (through our Appalachia Midstream Investments). In 2019, Chesapeake accounted for approximately 6 percent of our consolidated revenues. As of June 30, 2020, we reachedhave approximately $91 million of trade accounts receivable due from Chesapeake, (substantially all of which is current at June 30, 2020).
We have evaluated these receivables from Chesapeake and our related asset groups and investments involved in providing services to Chesapeake and determined that no expected credit losses or impairment charges are required to be recognized at this time. This evaluation considered the physical nature of our services in these basins, where we gather at the wellhead and are critical to Chesapeake’s ability to move product to market, along with an agreementassessed low likelihood of contract rejection, noting that none of our contracts with Chesapeake were rejected in their initial bankruptcy filing. Chesapeake also received initial limited approval to provide deepwatercontinue paying for services such as those we provide. We also considered our prior experiences with customer bankruptcies, where receivables were ultimately collectible even if the timing of collections was impacted. Future developments in Chesapeake’s ongoing bankruptcy proceedings could affect our assumptions and conclusions regarding credit losses and impairment charges.
We have certain other customers of our consolidated operations and investees, which are less significant to our consolidated results of operations, that have also filed for bankruptcy protection. To date, based on considerations such as our review of those bankruptcy filings, our assessment of the likelihood of contract rejection, and/or ongoing collections of amounts invoiced, we have not recognized any significant credit losses or impairment charges related to these customers. For example, Extraction Oil & Gas, Inc., a customer of our RMM investee, has not rejected any contracts with RMM and has paid pre-petition amounts due to RMM. We continue to monitor these ongoing customer bankruptcy proceedings as it is reasonably possible that future developments could affect our assumptions and conclusions.
Crude Oil Price Decline
During the first several months of 2020, crude oil prices decreased as a result of surplus supply and weakened demand caused by the COVID-19 pandemic. In addition, in early March, Saudi Arabia announced that it would cut export prices and increase production, contributing to a sharp decline in crude oil prices. The significant decline in crude oil prices has also impacted NGL prices. While our businesses do not have direct exposure to crude oil prices,


Management’s Discussion and Analysis (Continued)

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 significantly in the first quarter of 2020. As a result, our board of directors approved a limited duration shareholder rights agreement. (See Note 11 – Stockholders’ Equity of Notes to the Consolidated Financial Statements.)
Driven by the decline in our market capitalization and the underlying decrease in fair value of our Northeast G&P reporting unit, we recognized a $187 million impairment of goodwill during the first quarter of 2020. (See Note 12 – Fair Value Measurements and Guarantees of Notes to the Consolidated Financial Statements.)
The same economic conditions impacted the fair value of certain of our equity-method investments, resulting in $938 million of other-than-temporary impairments of these investments in the first quarter of 2020. (See Note 12 – Fair Value Measurements and Guarantees of Notes to the Consolidated Financial Statements.)
Considering the decline in crude oil prices, we note the following about our businesses:
Our interstate natural gas transmission businesses are fully contracted under long-term firm reservation contracts with high credit quality customers and are not exposed to crude oil prices.
We believe counterparty credit concerns in our gathering and processing business are significantly mitigated by the physical nature of our services, where we gather at the wellhead and are therefore critical to a producer’s ability to move product to market.
Our on-shore natural gas gathering servicesand processing businesses are substantially focused on gas-directed drilling basins rather than oil, with a broad diversity of basins and customers served. Further, a decline in oil drilling would be expected to the Appomattox developmentresult in the Gulf of Mexico. We completed modifications to install an alternate delivery route to our Main Pass 261 Platform, as well as modifications to our onshore Mobile Bay processing facility. The project went in service early in July 2019, atless associated natural gas production, which timecould drive more demand for natural gas produced from gas-directed basins we also purchasedserve.
Our deepwater transportation business is supported mostly by major oil producers with a 54-mile-long, 16-inch-diameter pipeline (the Norphlet Pipeline) for $200 million. This pipeline transports gas from the Appomattox development to our Main Pass 261 Platform.
Filing of Rate Case
On August 31, 2018, Transco filed a general rate case with the FERC for an overall increase in rates. In September 2018, with the exception of certain rates that reflected a rate decrease, the FERC accepted and suspended our general rate filing to be effective March 1, 2019, subject to refund and the outcome of a hearing. The specific rates that reflected a rate decrease were accepted, without suspension, to be effective October 1, 2018, as requested by Transco, and will not be subject to refund. In March 2019, the FERC accepted our motion to place the rates that were suspended by the September 2018 order into effect on March 1, 2019, subject to refund. In October 2019, we reached an agreement on the terms of a settlement with the participants that would resolve all issues in the rate case without the need for a hearing. Final resolution of the rate case is subject to the filing of a formal stipulation and agreement with, and subsequent approval by, the FERC. We have provided a reserve of $131 million for rate refunds which we believe is adequate for any refunds that may be required.
Commodity Priceslong-cycle perspective.
NGL per-unitMargins
Per-unit non-ethane margins were approximately 5140 percent lower in the first ninesix months of 20192020 compared to the same period of 2018in 2019 primarily due to a 3240 percent decrease in per-unit non-ethane sales prices, and an approximate 3partially offset by 36 percent increase inlower 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 20192020 is further discussed in the following Company Outlook.
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


Management’s Discussion and Analysis (Continued)

the terms of a settlement with the participants that would resolve all issues in the rate case without the need for a hearing, and on December 31, 2019, we filed a formal stipulation and agreement with the FERC setting forth such terms of settlement. On March 24, 2020, the FERC issued an order approving the uncontested rate case settlement, which became effective on June 1, 2020. As of June 30, 2020, we have provided a $284 million reserve for rate refunds related to increased rates collected since March 2019. The refunds were paid on July 1, 2020.
Company Outlook
Our strategy is to provide large-scale energy infrastructure designed to maximize the opportunities created by the vast supply of natural gas and natural gas products that exists in the United States. We accomplish this by connecting the growing demand for cleaner fuels and feedstocks with our major positions in the premier natural gas and natural gas products supply basins. We continue to maintain a strong commitment to safety, environmental stewardship, operational excellence, and customer satisfaction. We believe that accomplishing these goals will position us to deliver safe and reliable service to our customers and an attractive return to our shareholders.
Our business plan for 20192020 includes a continued focus on growingearnings and cash flow growth, while continuing to improve leverage metrics and control operating costs. Many of our fee-based businesses, executingproducer customers are impacted by extremely low energy commodity prices, which has resulted 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, including some that have filed for bankruptcy protection. But as previously discussed, the physical nature of services we provide supports the success of these customers. In many cases, we have long-term acreage dedications with strong historical contractual conveyances that create real estate interests in unproduced gas. In exchange for such dedication of production, we invest capital to build gathering lines uniquely to serve a producer’s wells. Therefore, our gathering lines are physically connected to the customer’s wellheads and 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 One 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 G&P 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 continue to negatively impact our results. We expect increases from Transco’s and Northwest Pipeline’s recent expansion projects including through joint ventures,placed in-service and accomplishing cost discipline initiatives to ensure operations support our strategy. We anticipateTransco’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 increase through organic business growth driven by Transco expansion projects and continued expansion in the Northeast region.


Management’s Discussion and Analysis (Continued)

benefit from lower expenses associated with our organizational realignment completed earlier this year.
Our growth capital and investment expenditures in 20192020 are expected to be in a range from $2.3$1.0 billion to $2.5$1.2 billion. Growth capital spending in 20192020 primarily includes Transco expansions, all of which are fully contracted with firm transportation agreements, and continuing to develop our gathering and processing infrastructureBluestem NGL pipeline project in the Northeast G&P and West segments.Mid-Continent region. In addition to growth capital and investment expenditures, we also remain committed to projects that maintain our assets for safe and reliable operations, as well as projects that meet legal, regulatory, and/or contractual commitments.
As a result of our significant continued capital and investment expenditures on Transco expansion projects and fee-based gathering and processing projects, fee-based businesses are a significant component of our portfolio and serve to reduce the influence of commodity price fluctuations on our operating results and cash flows. We expect to benefit as continued growth in demand for low-cost natural gas is driven by increases in LNG exports, industrial demand, and power generation. For 2019, current forward market prices indicate crude oil, natural gas, and NGL prices are expected to be lower compared to 2018. We continue to address certain pricing risks through the utilization of commodity hedging strategies.
In 2019, our operating results are expected to include increases from our regulated Transco fee-based business, primarily related to projects placed in-service beginning early 2018 and 2019, as well as the favorable impact from Transco’s agreement on the terms of a settlement in its general rate case as previously discussed. For our non-regulated businesses, we anticipate increases in fee-based revenue in the Northeast G&P segment driven by expansion projects, partially offset with a decrease in the West segment primarily due to the absence of results of our former sold or deconsolidated assets, lower commodity margins and commodity-based gathering and processing rates, and reduced recognition of deferred revenue associated with the end of a contractual MVC period. We expect overall gathering and processing volumes to grow in 2019 for our continuing businesses. Additionally, we believe our expenses will be impacted by the changes in our asset portfolio, including the UEOM acquisition and asset divestitures, as well as severance charges and other costs associated with our previously announced organizational realignment.
Potential risks and obstacles that could impact the execution of our plan include:
Continued negative impacts of COVID-19 driving a global recession, which could result in further downturns in financial markets and commodity prices, as well as impact demand for natural gas and related products;


Management’s Discussion and Analysis (Continued)

Opposition to, and legal regulations affecting, our infrastructure projects, including the risk of delay or denial in permits and approvals needed for our projects;
Counterparty credit and performance risk, including unexpected developments in ongoing customer bankruptcy proceedings;
Unexpected significant increases in capital expenditures or delays in capital project execution;
Counterparty credit and performance risk;
Unexpected changes in customer drilling and production activities, which could negatively impact gathering and processing volumes;
Lower than anticipated demand for natural gas and natural gas products which could result in lower than expected volumes, energy commodity prices, and margins;
General economic, financial markets, or further industry downturn, including increased interest rates;
Physical damages to facilities, including damage to offshore facilities by named windstorms;
Other risks set forth under Part I, Item 1A. Risk Factors in our Annual Report on Form 10-K for the year ended December 31, 2018,2019, as filed with the SEC on February 21, 2019.24, 2020, as supplemented by the disclosures in Part II, Item 1A. in our Quarterly Report on Form 10-Q for the quarter ended March 31, 2020.
We seek to maintain a strong financial position and liquidity, as well as manage a diversified portfolio of energy infrastructure assets which continue to serve key growth markets and supply basins in the United States.


Management’s Discussion and Analysis (Continued)

Expansion Projects
Our ongoing major expansion projects include the following:
Northeast G&P
Susquehanna Supply Hub Expansion
We continue to expand the gathering systems in the Susquehanna Supply Hub that are needed to meet our customers’ production plans by 2020. This next expansionTransmission & Gulf of the gathering infrastructure includes an additional 40,000 horsepower of new compression and gathering pipelines to bring the capacity to approximately 4.5 Bcf/d.
Atlantic-Gulf
Constitution Pipeline
We currently own 41 percent of Constitution with three other parties holding 25 percent, 24 percent, and 10 percent, respectively. We are the operator of Constitution. The 126-mile Constitution pipeline is proposed to connect our gathering system in Susquehanna County, Pennsylvania, to the Iroquois Gas Transmission and Tennessee Gas Pipeline systems in New York, as well as to a local distribution company serving New York and Pennsylvania. For further discussion on the status of this project, see Note 4 – Variable Interest Entities of Notes to Consolidated Financial Statements.
Gateway
In December 2018, we received approval from the FERC to expand Transco’s existing natural gas transmission system to provide incremental firm transportation capacity from PennEast Pipeline Company’s proposed interconnection with Transco’s mainline south of Station 205 in New Jersey to other existing Transco meter stations within New Jersey. We plan to place the project into service in the first half of 2020, assuming timely receipt of all necessary regulatory approvals. The project is expected to increase capacity by 65 Mdth/d.
Hillabee
In February 2016, the FERC issued a certificate order for the initial phases of Transco’s Hillabee Expansion Project. The project involves an expansion of Transco’s existing natural gas transmission system from Station 85 in west central Alabama to a new interconnection with the Sabal Trail pipeline in Alabama. The project is being constructed in phases, and all of the project expansion capacity is dedicated to Sabal Trail pursuant to a capacity lease agreement. Phase I was completed in 2017 and it increased capacity by 818 Mdth/d. The in-service date of Phase II is planned for the second quarter of 2020, and together Phases I and II are expected to increase capacity by 1,025 Mdth/d.Mexico
Northeast Supply Enhancement
In May 2019, we received approval from the FERC to expand Transco’s existing natural gas transmission system to provide incremental firm transportation capacity from Station 195 in Pennsylvania to the Rockaway Delivery Lateral transfer point in New York. ApprovalsHowever, 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 havingwere denied without prejudice, Transco’s applications for such approvals.in May 2020. We have not refiled our applications for those approvals and have addressed the technical issues identifiedapprovals. The project, which would increase capacity by the agencies. We plan400 Mdth/d, was planned to place the projectbe placed into service in the fourth quarterfall of 2020, assuming timely receipt of these remaining approvals. The project is expected to increase capacity by 400 Mdth/d.2021. See further discussion in Critical Accounting Estimates.
Southeastern Trail
In October 2019, we received approval from the FERC to expand Transco’s existing natural gas transmission system to provide incremental firm transportation capacity from the Pleasant Valley interconnect with Dominion’s Cove Point Pipeline in Virginia to the Station 65 pooling point in Louisiana. We plan to place up to 230 Mdth/d of capacity under the project into


Management’s Discussion and Analysis (Continued)

service in latethe fourth quarter of 2020, assuming timely receiptand the remainder of all remaining necessary regulatory approvals. Thethe project capacity into service in the first quarter of 2021. In total, the project is expected to increase capacity by 296 Mdth/d.
Leidy South
In July 2019,2020, we filed an application withreceived approval from the FERC for approval of the project to expand Transco’s existing natural gas transmission system and also extend its system through a capacity lease with National Fuel Gas Supply Corporation that will enable us to provide incremental firm transportation from Clermont, Pennsylvania and from the Zick interconnection on Transco’s Leidy Line to the River Road regulating station in Lancaster County, Pennsylvania.


Management’s Discussion and Analysis (Continued)

We plan to place the project into service inas early as the second halffourth quarter of 2022,2021, assuming timely receipt of all necessary regulatory approvals. The project is expected to increase capacity by 582 Mdth/d.
West
North Seattle Lateral Upgrade
In July 2018, we received approval from the FERC to expand delivery capabilities on Northwest Pipeline’s North Seattle Lateral. The project consists of the removal and replacement of approximately 5.9 miles of 8-inch diameter pipeline with new 20-inch diameter pipeline. We plan to place the project into service during the fourth quarter of 2019. The project is expected to increase delivery capacity by approximately 159 Mdth/d.
Wamsutter Expansion
We have expanded our gathering and processing infrastructure in the Wamsutter region of Wyoming in order to meet our customers’ production plans. We have completed construction of new compressor stations and modifications to our processing facilities, which are now in service. The expansion added approximately 20 miles of gathering pipelines and approximately 15,000 horsepower of compression. Additional expansion is expected in 2020, subject to the level of production activity in the area.
Project Bluestem
We are expanding our presence in the Mid-Continent region through building a 188-mile NGL pipeline from our fractionator near Conway, Kansas to an interconnect 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 constructis constructing a 110-mile pipeline extension of their existing NGL pipeline system that will have an initial capacity of 120 Mbbls/d. The pipeline and extension projects are expected to be placed into service during the first quarter of 2021. 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 beparty, which was placed into service duringin the first quarter of 2021.2020.
Critical Accounting Estimates
Constitution Pipeline Capitalized Project Costs
As of September 30, 2019, Property, plant, and equipmentinour Consolidated Balance Sheet includes approximately $376 million of capitalized project costs for Constitution, for which we are the construction manager and own a 41 percent consolidated interest. As a result of the events discussed in Note 4 – Variable Interest Entities of Notes to Consolidated Financial Statements, we have evaluated the capitalized project costs for impairment and determined that no impairment was necessary. Our evaluation considered probability-weighted scenarios of undiscounted future net cash flows, including scenarios assuming construction of the pipeline, as well as a scenario where the project does not proceed. It is reasonably possible that future unfavorable developments, such as failure to successfully renegotiate associated customer contracts, increased estimates of construction costs, or further significant delays, could result in a future impairment.
Regulatory Liabilities Resulting from Tax Reform
In December 2017, the Tax Cuts and Jobs Act (Tax Reform) was enacted, which, among other things, reduced the corporate income tax rate from 35 percent to 21 percent. Rates charged to customers of our regulated natural gas


Management’s Discussion and Analysis (Continued)

pipelines are subject to the rate-making policies of the FERC, which have historically permitted the recovery of an income tax allowance that includes a deferred income tax component. Due to the reduced income tax rate from Tax Reform and the collection of historical rates that reflected historical federal income tax rates, we expect that our regulated natural gas pipelines will be required to return amounts to certain customers through future rates. As a result, we established regulatory liabilities during 2017 and at September 30, 2019, these liabilities total $609 million. The timing and actual amount of such return related to Transco will be subject to the final outcome of the rate case discussed in Overview while the amount of such return related to Northwest Pipeline will be subject to future negotiations regarding this matter and many other elements of cost-of-service rate proceedings, including other costs of providing service.
Equity-Method Investments
We continue to monitor our equity-method investments for any indications that the carrying value may have experienced an other-than-temporary decline in value. When evidence
In the first quarter of 2020, we observed a losssignificant decline in the publicly traded price of our common stock (NYSE: WMB) as well as other industry peers and increases in equity yields within the midstream and overall energy industry, which served to increase our estimates of discount rates and weighted-average cost of capital. These changes were attributed to the swift, world-wide economic declines associated with actions to address the spread of COVID-19, coupled with the energy industry impact of significantly reduced energy commodity prices, which were further impacted by crude oil price declines associated with geopolitical actions during the quarter. These significant macroeconomic changes served as indications that the carrying amount of certain of our equity-method investments may have experienced an other-than temporary decline in fair value, has occurred,determined in accordance with Accounting Standards Codification (ASC) Topic 323, “Investments - Equity Method and Joint Ventures.”
As a result, we compare our estimate ofestimated the fair value of the investment to the carrying valuethese equity-method investments in accordance with ASC Topic 820, “Fair Value Measurement,” as of the investmentMarch 31, 2020, measurement date. In assessing the fair value, we were required to determine whether an impairment has occurred. We generally estimateconsider 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. As a result, we determined that there were other-than-temporary declines in the fair value of our investments using an income approach where significant judgments and assumptions include expected future cash flows and the appropriate discount rate. In some cases, we may utilize a form of market approach to estimate the fair valuecertain of our investments. During 2019, we haveequity-method investments, resulting in recognized impairments during the first quarter of 2020 totaling $186 million related to our equity-method investments.$938 million. (See Note 1312 – Fair Value Measurements and Guarantees of Notes to Consolidated Financial Statements.) This included impairments of certain of our equity-method investments in our Northeast G&P segment totaling $405 million, primarily associated with operations in wet-gas areas where producer drilling activities are influenced by NGL prices, which historically trend with crude oil prices. This total was primarily comprised of impairments of our investment in Caiman II and predominantly wet-gas gathering systems that are part of 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.
During the first quarter of 2020 we also recognized $436 million of impairments within our West segment related to our investments in RMM and Brazos Permian II, measured using an income approach. Both investees operate in primarily crude oil-driven basins where our gathering volumes are driven by crude oil drilling. Our expectation of


Management’s Discussion and Analysis (Continued)

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 as of March 31, 2020. In our assessments, we considered the impact of the then current market conditions on certain of our assets and did not identify any indicators that the carrying amounts of those assets may not be recoverable. The use of alternate judgments or changes in future conditions could result in a different conclusion regarding the occurrence and measurement of impairments affecting the consolidated financial statements.
As of June 30, 2020, Property, plant, and equipment in our Consolidated Balance Sheet includes approximately $217 million of capitalized project development costs for the Northeast Supply Enhancement project. As previously discussed, approvals required for the project from the New York State Department of Environmental Conservation and the New Jersey Department of Environmental Protection have been denied and we have not refiled at this time. Beginning in May 2020, we discontinued capitalization of costs related to this project.
The customer precedent agreements remain in effect and the project’s FERC certificate remains active. As such, we do not believe this project is probable of abandonment at this time and consider the carrying amount to be recoverable; thus no impairment charge has been recognized. It is reasonably possible that further adverse developments in the near future could change this determination, resulting in a future impairment charge of a substantial portion of the capitalized costs.







Management’s Discussion and Analysis (Continued)


Results of Operations
Consolidated Overview
The following table and discussion is a summary of our consolidated results of operations for the three and ninesix months ended SeptemberJune 30, 2019,2020, compared to the three and ninesix months ended SeptemberJune 30, 2018.2019. The results of operations by segment are discussed in further detail following this consolidated overview discussion.
Three Months Ended 
 September 30,		     Nine Months Ended 
 September 30,		    Three Months Ended 
June 30,		     Six Months Ended 
June 30,		    
2019 2018 $ Change* % Change* 2019 2018 $ Change* % Change*2020 2019 $ Change* % Change* 2020 2019 $ Change* % Change*
(Millions)     (Millions)    (Millions)     (Millions)    
Revenues:                              
Service revenues$1,495
 $1,371
 +124
 +9 % $4,424
 $4,062
 +362
 +9 %$1,446
 $1,489
 -43
 -3 % $2,920
 $2,929
 -9
 — %
Service revenues – commodity consideration38
 121
 -83
 -69 % 158
 316
 -158
 -50 %25
 56
 -31
 -55 % 53
 120
 -67
 -56 %
Product sales466
 811
 -345
 -43 % 1,512
 2,104
 -592
 -28 %310
 496
 -186
 -38 % 721
 1,046
 -325
 -31 %
Total revenues1,999
 2,303
     6,094
 6,482
    1,781
 2,041
     3,694
 4,095
    
Costs and expenses:                              
Product costs434
 790
 +356
 +45 % 1,442
 2,039
 +597
 +29 %271
 483
 +212
 +44 % 667
 1,008
 +341
 +34 %
Processing commodity expenses19
 30
 +11
 +37 % 83
 91
 +8
 +9 %15
 24
 +9
 +38 % 28
 64
 +36
 +56 %
Operating and maintenance expenses364
 389
 +25
 +6 % 1,091
 1,134
 +43
 +4 %320
 387
 +67
 +17 % 657
 727
 +70
 +10 %
Depreciation and amortization expenses435
 425
 -10
 -2 % 1,275
 1,290
 +15
 +1 %430
 424
 -6
 -1 % 859
 840
 -19
 -2 %
Selling, general, and administrative expenses130
 174
 +44
 +25 % 410
 436
 +26
 +6 %127
 152
 +25
 +16 % 240
 280
 +40
 +14 %
Impairment of certain assets—
 —
 —
 —
 76
 66
 -10
 -15 %—
 64
 +64
 +100 % —
 76
 +76
 +100 %
Impairment of goodwill—
 —
 —
 —
 187
 —
 -187
 NM
Other (income) expense – net(11) (6) +5
 +83 % 30
 24
 -6
 -25 %6
 9
 +3
 +33 % 13
 41
 +28
 +68 %
Total costs and expenses1,371
 1,802
     4,407
 5,080
    1,169
 1,543
     2,651
 3,036
    
Operating income (loss)628
 501
     1,687
 1,402
    612
 498
     1,043
 1,059
    
Equity earnings (losses)93
 105
 -12
 -11 % 260
 279
 -19
 -7 %108
 87
 +21
 +24 % 130
 167
 -37
 -22 %
Impairment of equity-method investments—
 2
 -2
 -100 % (938) (72) -866
 NM
Other investing income (loss) – net(107) 2
 -109
 NM
 (54) 74
 -128
 NM
1
 124
 -123
 -99 % 4
 125
 -121
 -97 %
Interest expense(296) (270) -26
 -10 % (888) (818) -70
 -9 %(294) (296) +2
 +1 % (590) (592) +2
 — %
Other income (expense) – net1
 52
 -51
 -98 % 19
 99
 -80
 -81 %5
 7
 -2
 -29 % 9
 18
 -9
 -50 %
Income (loss) before income taxes319
 390
     1,024
 1,036
    432
 422
     (342) 705
    
Provision (benefit) for income taxes77
 190
 +113
 +59 % 244
 297
 +53
 +18 %117
 98
 -19
 -19 % (87) 167
 +254
 NM
Net income (loss)242
 200
     780
 739
    315
 324
     (255) 538
    
Less: Net income (loss) attributable to noncontrolling interests21
 71
 +50
 +70 % 54
 323
 +269
 +83 %12
 14
 +2
 +14 % (41) 33
 +74
 NM
Net income (loss) attributable to The Williams Companies, Inc.$221
 $129
     $726
 $416
    $303
 $310
     $(214) $505
    

*+ = Favorable change; - = Unfavorable change; NM = A percentage calculation is not meaningful due to a change in signs, a zero-value denominator, or a percentage change greater than 200.


Management’s Discussion and Analysis (Continued)

Three months ended SeptemberJune 30, 20192020 vs. three months ended SeptemberJune 30, 20182019
Service revenues increaseddecreased primarily due to lower volumes in our West segment, the expiration of an MVC agreement in the Barnett Shale region, lower deferred revenue amortization at Gulfstar One, and temporary shut-ins at certain offshore Gulf of Mexico operations. This decrease was partially offset by an increase in the Eagle Ford Shale region primarily due to higher MVC revenue, higher transportation fee revenues at Transco primarily associated with expansion projects placed in service in 2019 and 2018, from UEOM, which is now a consolidated entity after the remaining ownership interest was purchased in March 2019, and fromits rate case settlement, as well as higher volumes at the Susquehanna Supply Hub. These increases are partially offsetNortheast JV revenues driven by the absence of revenues associated with asset divestitures and deconsolidations during 2018, including our former Four Corners area operations, and lower deferred revenue recognition in the Barnett Shale associated with the end of a contractual MVC period.higher volumes.
Service revenues – commodity consideration decreased primarily due to lower commodity prices, along with lower equity NGL prices, and lowerprocessing volumes due to less producer drilling activity. These revenues represent consideration we receive in the form of commodities as full or partial payment for processing services provided. Most of these NGL volumes are sold within the month processed and therefore are offset in Product costs below.
Product 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.
Operating and maintenance expenses decreased due to lower employee-related expenses driven by the absence of second-quarter 2019 severance and related costs (see Note 6 – Other Accruals of Notes to Consolidated Financial Statements) and the associated reduced costs in 2020, as well as lower maintenance costs primarily due to timing and scope of activities.
Selling, general, and administrative expenses decreased primarily due to lower employee-related expenses, including the absence of second-quarter 2019 severance and related costs (see Note 6 – Other Accruals of Notes to Consolidated Financial Statements) and the associated reduced costs in 2020, as well as the absence of transaction costs associated with our former Four Corners area operations2019 formation of the Northeast JV.
The favorable change in Impairment of certain assets includes the absence of a 2019 impairment of certain Eagle Ford Shale gathering assets (see Note 12 – Fair Value Measurements and Guarantees of Notes to Consolidated Financial Statements).
The favorable change in Operating income (loss) includes the absence of the 2019 impairment of certain assets, as well as higher Northeast JV volumes, lower employee-related expenses, and the favorable impact from Transco's expansion projects and rate case. The favorable change was partially offset by the expiration of an MVC agreement in the Barnett Shale region, lower deferred revenue amortization at Gulfstar One, and the impact of various temporary shut-ins across the Gulf of Mexico.
Equity earnings (losses) increased primarily due to increases at Appalachia Midstream Investments and Caiman II.
The unfavorable change in Other investing income (loss) – net includes the absence of a 2019 gain on the sale of our equity-method investment in Jackalope (see Note 5 – Investing Activities of Notes to Consolidated Financial Statements).
Provision (benefit) for income taxes changed unfavorably primarily due to the allocation of losses to nontaxable noncontrolling interest and higher pre-tax income. See Note 7 – Provision (Benefit) for Income Taxes of Notes to Consolidated Financial Statements for a discussion of the effective tax rate compared to the federal statutory rate for both periods.


Management’s Discussion and Analysis (Continued)

Six months ended June 30, 2020 vs. six months ended June 30, 2019
Service revenuesdecreased primarily due to the expiration of an MVC agreement in the Barnett Shale region, lower deferred revenue amortization at Gulfstar One, lower volumes and rates in our West segment, and temporary shut-ins at certain Gulf of Mexico operations. This decrease was partially offset by higher Northeast JV revenues driven by higher volumes and the March 2019 consolidation of UEOM, higher transportation fee revenues at Transco primarily associated with its expansion projects placed in service in 2019 and rate case settlement, as well as higher MVC revenue in the Eagle Ford Shale region.
Service revenues – commodity consideration decreased primarily due to lower commodity prices, as well as lower equity NGL processing volumes due to less producer drilling activity and higher ethane rejection. These revenues represent consideration we receive in the form of commodities as full or partial payment for processing services provided. Most of these NGL volumes are sold within the month processed and therefore are offset in Product costs below.
Product sales decreased primarily due to lower NGL and natural gas prices associated with our marketing and equity NGL sales activities.activities, as well as lower volumes associated with our equity NGL sales activities, partially offset by higher marketing volumes. This decrease also includes lower volumes from our equity NGL sales primarily reflecting the absence of our former Four Corners area operations and lower system management gas sales, partially offset by higher marketing volumes.sales. Marketing revenues and system management gas sales are substantially offset in Product costs.
Product costs decreased primarily due to lower NGL and natural gas prices associated with our marketing and equity NGL production activities. This decrease also includes lower volumes acquired as commodity consideration for NGL processing services reflecting the absence of our former Four Corners area operations and lower system management gas costs, partially offset by higher volumes for marketing activities.
Processing commodity expenses decreased primarily due to lower natural gas purchases associated with equity NGL production primarily due to lower volumes and lower natural gas prices.
Operating and maintenance expenses decreased due to lower employee-related expenses, including the absence of second-quarter 2019 severance and related costs and the associated reduced costs in 2020, and lower maintenance primarily due to the absencetiming and scope of our former Four Corners area operations and aactivities. This decrease in Transco’s contracted services mainly due to the timing of required engine overhauls and integrity testing,was partially offset by higher expenses related to the consolidation of UEOM and by an accrual for estimated severance and related costs primarily associated with our voluntary separation program (VSP) (see Note 6 – Other Income and Expenses of Notes to Consolidated Financial Statements).in March 2019.
Depreciation and amortization expenses increased primarily due to the consolidation of UEOM and new assets placed in service substantiallyand the March 2019 consolidation of UEOM, partially offset by the 2018 impairment of certainlower expense related to assets that became fully depreciated in the Barnett Shale region.fourth quarter of 2019.
Selling, general, and administrative expenses decreased primarily due to lower employee-related expenses, including the absencesabsence of a charge for a 2018 charitable contributionsecond-quarter 2019 severance and related costs and the associated reduced costs in 2020, as well as the absence of preferred stock to The Williams Companies Foundation, Inc. and feestransaction costs associated with our 2019 acquisition of UEOM and the WPZ Merger.formation of the Northeast JV.
The favorable change in Impairment of certain assets includes the absence of 2019 impairments of certain Eagle Ford Shale gathering assets and certain idle gathering assets.
Impairment of goodwill reflects the goodwill impairment charge at Northeast G&P in 2020 (see Note 12 – Fair Value Measurements and Guarantees of Notes to Consolidated Financial Statements).
The favorable change in Other (income) expense – net within Operating income (loss) includes net favorable changes to charges and credits toassociated with regulatory assets and liabilities partially offset byprimarily associated with Transco’s rate case settlement and the absence of a 2018 gain on2019 unfavorable regulatory asset retirement (see Note 6 – Other Income and Expenses of Notes to Consolidated Financial Statements).adjustment at Other.
The favorableunfavorable change in Operating income (loss) includes the 2020 impairment of goodwill at Northeast G&P, the expiration of an increase in Service revenues primarily associated with Transco projects placed in-service and higher gathering volumesMVC agreement in the NortheastBarnett Shale region, the absence of a charge for a charitable contribution of preferred stock to the Williams Foundation, Inc.,lower deferred revenue amortization at Gulfstar One, and the absence of fees associated with the WPZ Merger, partially offset by unfavorable commodity margins primarily reflecting lower NGL sales pricesprices. The unfavorable change was partially offset by higher Northeast JV volumes, the absence of the 2019 impairment of certain assets, lower employee-related


Management’s Discussion and lower volumes.Analysis (Continued)

expenses, the favorable impacts of the consolidation of UEOM, and the favorable impact from Transco's expansion projects and rate case.
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 increases at Appalachia Midstream Investments and Caiman II.
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 12 – Fair Value Measurements and Guarantees of Notes to Consolidated Financial Statements).
The unfavorable change in Other investing income (loss) – net is primarily due to the absence of a 2019 impairments togain on the sale of our equity-method investments, including Laurel Mountain (see Note 13 – Fair Value Measurements and Guarantees of Notes to Consolidated Financial Statements).
Interest expense increased primarily due to an increaseinvestment in financing obligations associated with Transco’s Atlantic Sunrise project and lower capitalized interest due to projects placed in service.Jackalope.


Management’s Discussion and Analysis (Continued)

The unfavorable change in Other income (expense) – net below Operating income (loss) is primarily due to a decrease in equity AFUDC associated with reduced capital expenditures on projects and 2019 charges for loss contingencies associated with former operations.2020 pension plan settlement charge.
Provision (benefit) for income taxes changed favorably primarily due to the absence of a $105 million 2018 valuation allowance on certain deferred tax assets that may not be realized following the WPZ merger, partially offset by higherlower pre-tax income attributable to The Williams Companies, Inc.income. See Note 7 – Provision (Benefit) for Income Taxes of Notes to Consolidated Financial Statements for a discussion of the effective tax rate compared to the federal statutory rate for both periods.
The favorable change in Net income (loss) attributable to noncontrolling interests is primarily due to our third- quarter 2018 acquisitionthe noncontrolling interests’ share of the publicly held interests in WPZ associated with the WPZ Merger.
Nine months ended September 30, 2019 vs. nine months ended September 30, 2018
Service revenuesincreased primarily due to higher transportation fee revenues at Transco associated with expansion projects placed in service in 2019first-quarter 2020 goodwill impairment charge, and 2018 and the consolidation of UEOM, as well as higher volumes at the Susquehanna Supply Hub, and higher rates and volumes from new wells in the Utica Shale region. These increases arelower Gulfstar One results, partially offset by the absence of revenues associated with asset divestitures and deconsolidations during 2018, including our former Four Corners area operations, and lower deferred revenue recognition in the Barnett Shale associated with the end of a contractual MVC period.
Service revenues – commodity consideration decreased dueimpact from to lower NGL prices and lower volumes primarily due to the absence of our former Four Corners area operations. These revenues represent consideration we receive in the form of commodities as full or partial payment for processing services provided. Most of these NGL volumes are sold within the month processed and therefore are offset in Product costs below.
Product salesdecreased primarily due to lower NGL and natural gas prices associated with our marketing and equity NGL sales activities and lower volumes from our equity NGL sales primarily reflecting the absence of our former Four Corners area operations and lower system management gas sales, partially offset by higher marketing volumes. Marketing revenues and system management gas sales are substantially offset in Product costs.
Product costs decreased primarily due to lower NGL and natural gas prices associated with our marketing and equity NGL production activities. This decrease also includes lower volumes acquired as commodity consideration for NGL processing services reflecting the absence of our former Four Corners area operations and lower system management gas costs, partially offset by higher volumes for marketing activities.
Operating and maintenance expensesdecreased primarily due to the absence of our former Four Corners area operations, partially offset by the consolidation of UEOM, and by an accrual for estimated severance and related costs primarily associated with our VSP.
Depreciation and amortization expenses decreased primarily due to the 2018 impairment of certain assets in the Barnett Shale region and the absence of our former Four Corners area operations, partially offset by new assets placed in service and by the consolidation of UEOM.
Selling, general, and administrative expenses decreased primarily due to the absences of a charitable contribution of preferred stock to the Williams Foundation, Inc. and fees associated with the WPZ Merger, partially offset by an accrual for estimated severance and related costs primarily associated with our VSP, and transaction expenses associated with the acquisition of UEOM and the formation of the Northeast JV.
The unfavorable changeJV in Impairment of certain assets includes a second-quarter 2019 impairment of certain Eagle Ford Shale gathering assets and a first-quarter 2019 impairment of certain idle gathering assets, partially offset by the absence of a 2018 impairment of certain idle pipelines.
The unfavorable change in Other (income) expense – net within Operating income (loss) includes the absence of a 2018 gain on asset retirement, a 2019 charge for the reversal of expenditures previously capitalized, and net unfavorable


Management’s Discussion and Analysis (Continued)

changes to charges and credits to regulatory assets and liabilities (see Note 6 – Other Income and Expenses of Notes to Consolidated Financial Statements).
The favorable change in Operating income (loss) includes an increase in Service revenues primarily associated with Transco projects placed in-service and higher gathering volumes in the Northeast region, the favorable impact of acquiring the additional interest of UEOM, the absence of a charitable contribution of preferred stock to the Williams Foundation, Inc., and the absence of fees associated with the WPZ Merger. These favorable changes were partially offset by the impact of asset divestitures and deconsolidations during 2018, including our former Four Corners area operations, unfavorable commodity margins primarily reflecting lower NGL sales prices and lower volumes, an accrual for estimated severance and related costs primarily associated with our VSP, and transaction expenses associated with the acquisition of UEOM and the formation of the Northeast JV.
The unfavorable change in Other investing income (loss) – net reflects noncash impairments to equity method investments (see Note 13 – Fair Value Measurements and Guarantees of Notes to Consolidated Financial Statements) and the absence of a 2018 gain on deconsolidation of our former Jackalope operations, partially offset by a 2019 gain on sale of our equity-method investment in Jackalope.
Interest expense increased primarily due to an increase in financing obligations associated with Transco’s Atlantic Sunrise project.
The unfavorable change in Other income (expense) – net below Operating income (loss) is primarily due to a decrease in equity AFUDC associated with reduced capital expenditures on projects.
Provision (benefit) for income taxes changed favorably primarily due to the absence of a $105 million 2018 valuation allowance on certain deferred tax assets that may not be realized following the WPZ merger, partially offset by higher pre-tax income attributable to The Williams Companies, Inc. See Note 7 – Provision (Benefit) for Income Taxes of Notes to Consolidated Financial Statements for a discussion of the effective tax rate compared to the federal statutory rate for both periods.
The favorable change in Net income (loss) attributable to noncontrolling interests is primarily due to our third- quarter 2018 acquisition of the publicly held interests in WPZ associated with the WPZ Merger and lower results at Gulfstar.June 2019.
Period-Over-Period Operating Results - Segments
We evaluate segment operating performance based upon Modified EBITDA. Note 1514 – Segment Disclosures of Notes to Consolidated Financial Statements includes a reconciliation of this non-GAAP measure to Net income (loss). Management uses Modified EBITDA because it is an accepted financial indicator used by investors to compare company performance. In addition, management believes that this measure provides investors an enhanced perspective of the operating performance of our assets. Modified EBITDA should not be considered in isolation or as a substitute for a measure of performance prepared in accordance with GAAP.
Transmission & Gulf of Mexico
 Three Months Ended 
June 30,		 Six Months Ended 
June 30,
 2020 2019 2020 2019
 (Millions)
Service revenues$795
 $808
 $1,624
 $1,631
Service revenues – commodity consideration
3
 13
 8
 26
Product sales36
 68
 88
 150
Segment revenues834
 889
 1,720
 1,807
        
Product costs(37) (69) (89) (151)
Processing commodity expenses(1) (5) (3) (10)
Other segment costs and expenses(223) (269) (437) (506)
Proportional Modified EBITDA of equity-method investments42
 44
 86
 86
Transmission & Gulf of Mexico Modified EBITDA$615
 $590
 $1,277
 $1,226
        
Commodity margins$1
 $7
 $4
 $15


Management’s Discussion and Analysis (Continued)

Three months ended June 30, 2020 vs. three months ended June 30, 2019
Transmission & Gulf of Mexico Modified EBITDA increased primarily due to favorable changes to Other segment costs and expenses.
Service revenues decreased primarily due to:
A $31 million decrease due to lower deferred revenue amortization and the end of the exclusive use period at Gulfstar One;
A $21 million decrease due to temporary shut-ins primarily at Perdido and Gunflint related to pricing and scheduled maintenance.
These decreases were partially offset by:
A $26 million increase in Transco’s natural gas transportation revenues primarily driven by higher revenues from Transco’s expansion projects placed in service and rate case settlement in 2019;
An increase at Gulfstar One associated with higher volumes in the Tubular Bells field due to a new well and higher production.
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 volumes and prices. Additionally, the decrease in Product sales includes a $21 million decrease in commodity marketing sales. Marketing sales are substantially offset in Product costs and therefore have little impact to Modified EBITDA.
Other segment costs and expenses decreased primarily due to lower employee-related expenses, including the absence of second-quarter 2019 severance and related costs and the associated reduced costs in 2020 (see Note 6 of Notes to Consolidated Financial Statements) and the absence of $15 million of expense in 2019 related to the reversal of expenditures previously capitalized, as well as net favorable changes to charges and credits associated with regulatory assets and liabilities primarily driven by the terms of settlement in Transco’s general rate case. Additionally, expenses decreased due to lower maintenance costs.
Six months ended June 30, 2020 vs. six months ended June 30, 2019
Transmission & Gulf of Mexico Modified EBITDA increased primarily due to favorable changes to Other segment costs and expenses.
Service revenues decreased primarily due to:
A $61 million decrease due to lower deferred revenue amortization and the end of the exclusive use period at Gulfstar One;
A $21 million decrease due to temporary shut-ins primarily at Perdido and Gunflint related to pricing and scheduled maintenance.
These decreases were partially offset by:
A $58 million increase in Transco’s natural gas transportation revenues primarily driven by higher revenues from Transco’s expansion projects placed in service and rate case settlement in 2019;
A $13 million increase at Gulfstar One associated with higher volumes in the Tubular Bells field due to a new well and higher production;


Management’s Discussion and Analysis (Continued)

An $11 million increase associated with higher Norphlet volumes.
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 $8 million primarily driven by unfavorable NGL sales prices and volumes. Additionally, the decrease in Product sales includes a $36 million decrease in commodity marketing sales primarily due to lower NGL prices and $8 million lower system management gas sales. 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 lower employee-related expenses, including the absence of second-quarter 2019 severance and related costs and the associated reduced costs in 2020, as well as net favorable changes to charges and credits associated with regulatory assets and liabilities primarily driven by the terms of settlement in Transco’s general rate case, and the absence of $15 million of expense in 2019 related to the reversal of expenditures previously capitalized. Additionally, expenses decreased due to lower contracted services mainly related to general maintenance and other testing at Transco. These decreases were partially offset by higher operating taxes and a 2020 pension plan settlement charge.
Northeast G&P
Three Months Ended 
 September 30,		 Nine Months Ended 
 September 30,		Three Months Ended 
June 30,		 Six Months Ended 
June 30,
2019 2018 2019 20182020 2019 2020 2019
(Millions)(Millions)
Service revenues$353
 $247
 $959
 $707
$354
 $330
 $712
 $606
Service revenues – commodity consideration
1
 6
 9
 14
1
 3
 3
 8
Product sales30
 69
 114
 242
1
 37
 30
 84
Segment revenues384
 322
 1,082
 963
356
 370
 745
 698
              
Product costs(29) (69) (114) (245)—
 (38) (29) (85)
Processing commodity expenses(1) (3) (6) (7)(1) (2) (2) (5)
Other segment costs and expenses(117) (100) (348) (279)(111) (130) (221) (231)
Proportional Modified EBITDA of equity-method investments108
 131
 333
 354
126
 103
 246
 225
Northeast G&P Modified EBITDA$345
 $281
 $947
 $786
$370
 $303
 $739
 $602
              
Commodity margins$1
 $3
 $3
 $4
$1
 $—
 $2
 $2
Three months ended SeptemberJune 30, 20192020 vs. three months ended SeptemberJune 30, 20182019
Northeast G&P Modified EBITDA increased primarily due to higher Service revenues, increased Proportional Modified EBITDA of equity-method investments, and lower Other segment costs and expenses.
Service revenues increased primarily due to:
A $23 million increase at the Northeast JV, related to higher gathering, processing, fractionation, and transportation revenues primarily associated with higher volumes, partially offset by
A $7 million decrease associated with lower gathering volumes at Susquehanna Supply Hub.
Product sales decreased primarily due to lower non-ethane prices within our marketing activities. The changes in marketing revenues are offset by similar changes in marketing purchases, reflected above as Product costs.
Other segment costs and expenses decreased primarily due to lower employee-related expenses driven by the absence of second-quarter 2019 severance and related costs (see Note 6 – Other Accruals of Notes to Consolidated


Management’s Discussion and Analysis (Continued)

Financial Statements) and the associated reduced costs in 2020, and the absence of transaction costs associated with the formation of the Northeast JV. Additionally, maintenance and repairs expenses decreased primarily due to timing and scope of activities.
Proportional Modified EBITDA of equity-method investmentsincreased gatheringat Appalachia Midstream Investments primarily due to higher volumes and at Caiman II driven by a gain on early debt retirement at Blue Racer Midstream, LLC.
Six months ended June 30, 2020 vs. six months ended June 30, 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 2019.2019, 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 $50An $84 million increase at the Northeast JV, including $52 million higher gathering, processing, fractionation, and transportation revenues primarily due to higher volumes, and a $32 million increase associated with the consolidation of UEOM, as previously discussed;
•
An $11 million increase in reimbursable electricity expenses, which are offset by similar changes in electricity charges, reflected in Other segment costs and expenses;
A $24 million increase associated with higher gathering revenues at Susquehanna Supply Hub reflecting 18 percent higher gathering volumes due to increased production from customers;
An $18 million increase at Ohio Valley Midstream primarily due to higher gathering and processing revenues;
A $9$6 million increase in gathering revenues in the Utica Shale regionat Cardinal primarily due to volumes from new wells and higher rates.volumes.
Product sales decreased primarily due to lower non-ethaneNGL prices and lower non-ethane volumes within our marketing activities. The changes in marketing revenues are offset by similar changes in marketing purchases, reflected above as Product costs.
Other segment costs and expenses increaseddecreased primarily due to lower employee-related expenses, including the absence of second-quarter 2019 severance and related costs and the associated reduced costs in 2020, and the absence of transaction costs associated with our 2019 acquisition of UEOM and the formation of the Northeast JV. Additionally, maintenance and repair expenses and operating expenses decreased primarily due to timing and scope of activities. These decreases were partially offset by higher reimbursable electricity expenses in addition to increased expenses associated with the consolidation of UEOM.
Proportional Modified EBITDA of equity-method investments decreased primarily due toincreased at Appalachia Midstream Investments driven by higher volumes and at Caiman II driven by higher volumes and a gain on early debt retirement. These increases were partially offset by a $16 million decrease as a result of the consolidation of UEOM.UEOM, as previously discussed.
Nine months ended September 30, 2019 vs. nine months ended September 30, 2018
Northeast G&P Modified EBITDA increased primarily due to higher Service revenues due to increased gathering volumes and the favorable impact of acquiring the additional interest of UEOM, partially offset by 2019 severance and related costs.


Management’s Discussion and Analysis (Continued)

Service revenues increased primarily due to:
A $98 million increase associated with the consolidation of UEOM;
An $89 million increase associated with higher gathering revenues at Susquehanna Supply Hub reflecting 22 percent higher gathering volumes due to increased production from new wells and higher rates;
A $28 million increase in gathering revenues in the Utica Shale region due to volumes from new wells and higher rates;
A $21 million increase at Ohio Valley Midstream primarily due to higher gathering and processing volumes;
A $12 million increase in compression revenues for services charged to an affiliate driven by higher volumes.
Product sales decreased primarily due to lower non-ethane volumes and prices within our marketing activities. The changes in marketing revenues are offset by similar changes in marketing purchases, reflected above as Product costs.
Other segment costs and expenses increased due to multiple factors, including:
•A $35 million increase associated with the consolidation of UEOM;
A $10 million increase related to transaction expenses associated with the acquisition of UEOM and the formation of the Northeast JV;
•A $7 million accrual in 2019 for estimated severance and related costs primarily associated with our VSP;
A $14 million increase due to higher allocated corporate costs and higher costs related to various maintenance and repairs.
Proportional Modified EBITDA of equity-method investments decreased $37 million as a result of the consolidation of UEOM. This decrease was partially offset by a $20 million increase at Appalachia Midstream Investments, reflecting higher volumes.
Atlantic-GulfWest
 Three Months Ended 
 September 30,		 Nine Months Ended 
 September 30,
 2019 2018 2019 2018
 (Millions)
Service revenues$731
 $607
 $2,138
 $1,806
Service revenues – commodity consideration
7
 18
 33
 45
Product sales76
 131
 226
 329
Segment revenues814
 756
 2,397
 2,180
        
Product costs(75) (134) (226) (332)
Processing commodity expenses(2) (3) (12) (10)
Other segment costs and expenses(182) (176) (606) (556)
Proportional Modified EBITDA of equity-method investments44
 49
 130
 136
Atlantic-Gulf Modified EBITDA$599
 $492
 $1,683
 $1,418
        
Commodity margins$6
 $12
 $21
 $32


Management’s Discussion and Analysis (Continued)

 Three Months Ended 
June 30,		 Six Months Ended 
June 30,
 2020 2019 2020 2019
 (Millions)
Service revenues$316
 $368
 $627
 $727
Service revenues – commodity consideration
21
 40
 42
 86
Product sales303
 434
 662
 913
Segment revenues640
 842
 1,331
 1,726
        
Product costs(281) (437) (649) (912)
Processing commodity expenses(13) (19) (23) (50)
Other segment costs and expenses(117) (138) (243) (274)
Impairment of certain assets—
 (64) —
 (76)
Proportional Modified EBITDA of equity-method investments24
 28
 52
 54
West Modified EBITDA$253
 $212
 $468
 $468
        
Commodity margins$30
 $18
 $32
 $37
Three months ended SeptemberJune 30, 20192020 vs. three months ended SeptemberJune 30, 20182019
Atlantic-GulfWest Modified EBITDA increased primarily due to the absence of Impairment of certain assets, lower Other segment costs and expenses, and higherCommodity margins, partially offset by lower Service revenues.
Service revenues increaseddecreased primarily due toto:
A $33 million decrease driven by lower deferred revenue amortization and MVC deficiency fee revenues associated with the second-quarter 2019 expiration of the MVC agreement in the Barnett Shale region;
A $22 million decrease associated with lower volumes, excluding the Eagle Ford Shale region;
A $17 million decrease associated with lower rates, excluding the Eagle Ford Shale region, driven by lower commodity pricing in the Barnett Shale region and the expiration of a $143cost-of-service period on a contract in the Mid-Continent region;
An $11 million decrease driven by the absence of a favorable 2019 cost-of-service agreement adjustment in the Mid-Continent region;
A $25 million increase in Transco’s natural gas transportation revenues primarily driven by a $116 million increase relatedthe Eagle Ford Shale region due to expansion projects placed in service in 2018higher MVC revenue and 2019, as well as an adjustment associated with Transco’s reserve for rate refunds. This increase washigher rates, partially offset by $21 million lower gathering and processing feesvolumes primarily due to maintenance downtime at Gulfstar, lower volumes at our Perdido Norte system in the Western Gulf of Mexico, and the sale ofdecreased producer activity, including shut-ins on certain Gulf Coast pipeline assets in the fourth quarter of 2018. Additionally, certain of Transco’s natural gas transportation revenues, which decreased due to lower rates effective October 2018, were substantially offset by higher revenue related to reimbursable power and storage expenses.gathering systems;
A $9 million increase associated with a temporary volume deficiency fee from a customer.
The net sum of Service revenues – commodity consideration, Product sales, Product costs, and Processing commodity expenses comprise our commodity product margins. Our commoditymargins, which we further segregate into product margins associated with our equity NGLs decreased $7and marketing margins. Marketing margins increased by $25 million driven by unfavorable NGLprimarily due to favorable changes in net commodity prices. Additionally, theThe decrease in Product sales includes a $44$107 million decrease in commodity marketing sales, which is due to lower NGLsales prices, andpartially offset by higher marketing sales volumes. Marketing salesThese decreases are substantially offset in Product costscosts.
Additionally, product margins from our equity NGLs decreased $13 million primarily due to:


Management’s Discussion and therefore have little impactAnalysis (Continued)

A $13 million decrease associated with lower sales prices primarily due to Modified EBITDA.48 percent lower average net realized per-unit non-ethane sales prices;
A $6 million decrease associated with lower sales volumes primarily due to 14 percent lower non-ethane sales volumes primarily due to less producer drilling activity;
A $6 million increase related to a decline in natural gas purchases associated with lower natural gas prices and lower equity NGL production volumes.
Other segment costs and expenses increaseddecreased primarily due to a $23 million unfavorable change in equity AFUDC due to lower construction activity, an $11 million accrual inemployee-related expenses driven by the absence of second-quarter 2019 for estimated severance and related costs primarilyand the associated with our VSPreduced costs in 2020 (see Note 6 – Other Income and ExpensesAccruals of Notes to the Consolidated Financial Statements), lower maintenance costs primarily due to timing and scope of activities, and lower operating costs due to fewer leased compressors.
Impairment of certain assets decreased primarily due to the absence of a $10$59 million 2018 gain on asset retirements, and higher reimbursable power and storage expenses at Transco. These unfavorable changes were partially offset by $33 millionimpairment of net favorable changes to charges and credits associated with regulatorycertain Eagle Ford Shale gathering assets and liabilities, which were significantly driven by the previously mentioned agreement to the terms of a settlement in Transco’s general rate case2019 (see Note 612 – Other IncomeFair Value Measurements and ExpensesGuarantees of Notes to the Consolidated Financial Statements), and a $21 million decrease in Transco’s contracted services compared to 2018 mainly.
Proportional Modified EBITDA of equity-method investments decreased primarily due to the timing of required engine overhauls and integrity testing.lower volumes at OPPL.
NineSix months ended SeptemberJune 30, 20192020 vs. ninesix months ended SeptemberJune 30, 20182019
Atlantic-GulfWest Modified EBITDA increased primarily due to higherincludes lower Service revenues, partiallyand lower Commodity margins, offset by higherthe absence of Impairment of certain assets and lower Other segment costs and expenses.expenses.
Service revenues increaseddecreased primarily due to:
A $72 million decrease driven by lower deferred revenue amortization and MVC deficiency fee revenues associated with the second-quarter 2019 expiration of the MVC agreement in the Barnett Shale region;
A $40 million decrease associated with lower rates, excluding the Eagle Ford Shale region, 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 $35 million decrease associated with lower volumes, excluding the Eagle Ford Shale region;
An $11 million decrease driven by the absence of a favorable 2019 cost-of-service agreement adjustment in the Mid-Continent region;
A $51 million increase in the Eagle Ford Shale region due to higher MVC revenue and higher rates, partially offset by lower volumes primarily due to a $361decreased producer activity, including shut-ins on certain gathering systems;
A $9 million increase in Transco’s natural gas transportation revenues primarily driven by a $335 million increase related to expansion projects placed in service in 2018 and 2019, as well as an adjustment associated with Transco’s reserve for rate refunds. Partially offsetting these increases were lower gathering and processing fees of $40 million primarily due to maintenance downtime at Gulfstar and the sale of certain Gulf Coast pipeline assets in the fourth quarter of 2018. Additionally, certain of Transco’s natural gas transportation revenues, which decreased due to lower rates effective October 2018, were substantially offset by higher revenue related to reimbursable power and storage expenses.a temporary volume deficiency fee from a customer.
The net sum of Service revenues – commodity consideration, Product sales, Product costs, and Processing commodity expenses comprise our commodity product margins. Our commoditymargins, which we further segregate into product margins associated with our equity NGLs decreased $12 million driven by unfavorable NGL prices, partially offset by higher volumes. Additionally, the decrease in and marketing margins. Product sales includes a $74 million decrease in commodity marketing sales due to lower NGL prices and volumes and an $19 million decrease in system management gas sales. Marketing sales and system management gas sales are substantially offset in Product costs and therefore have little impact to Modified EBITDA.
Other segment costs and expenses increased primarily due a $55 million unfavorable change in equity AFUDC due to lower construction activity, a $30 million accrual in 2019 for estimated severance and related costs primarily associated with our VSP, a $15 million increase in reimbursable power and storage expenses, $15 million of expense in 2019 related to the reversal of expenditures previously capitalized, and the absence of a $10 million 2018 gain on asset retirements. These unfavorable changes were partially offset by $43 million of net favorable changes to charges and credits associated with regulatory assets and liabilities, which were significantly driven by the previously mentioned


Management’s Discussion and Analysis (Continued)

agreement to the terms of a settlement in Transco’s general rate case, and a $41 million decrease in Transco’s contracted services compared to 2018 mainly due to the timing of required engine overhauls and integrity testing.
West
 Three Months Ended 
 September 30,		 Nine Months Ended 
 September 30,
 2019 2018 2019 2018
 (Millions)
Service revenues$433
 $533
 $1,384
 $1,599
Service revenues – commodity consideration
30
 97
 116
 257
Product sales389
 732
 1,302
 1,822
Segment revenues852
 1,362
 2,802
 3,678
        
Product costs(382) (730) (1,294) (1,813)
Processing commodity expenses(13) (26) (63) (76)
Other segment costs and expenses(175) (219) (531) (637)
Impairment of certain assets—
 —
 (76) —
Proportional Modified EBITDA of equity-method investments29
 25
 83
 62
West Modified EBITDA$311
 $412
 $921
 $1,214
        
Commodity margins$24
 $73
 $61
 $190
Three months ended September 30, 2019 vs. three months ended September 30, 2018
West Modified EBITDA decreased primarily due to the absence of EBITDA of certain of our former sold or deconsolidated assets, lower service revenues associated with the expiration of a certain MVC, and lower commodity margins due to unfavorable commodity prices related to our ongoing operations.
Service revenues decreased primarily due to:
A $62 million decrease associated with asset divestitures and deconsolidations during 2018, including our former Four Corners area assets and certain Delaware basin assets that were contributed to our Brazos Permian II equity-method investment;
A $29 million decrease driven by lower deferred revenue amortization and MVC deficiency fee revenues associated with the expiration of a certain MVC agreement in the Barnett Shale region;
A $23 million decrease associated with lower rates primarily driven by lower commodity pricing in the Piceance and Barnett Shale regions and the transition from a cost-of-service to fixed-fee rate for a certain customer contract in the Mid-Continent region.
These decreases were partially offset by a $17 million increase associated with higher other MVC deficiency fee revenues, higher volumes, and higher other fee revenues.
The net sum of Service revenues – commodity consideration, Product sales, Product costs, and Processing commodity expenses comprise our commodity product margins. Our commodity product margins associated with our equity NGLs decreased $44$17 million primarily due to:
A $35 million decrease associated with lower sales volumes primarily due to $21 million associated with the absence of our former Four Corners area assets and $14 million related to 70 percent lower ethane sales volumes due to ethane rejection;
A $22$24 million decrease associated with lower sales prices primarily due to 40 percent and 82 percent lower average net realized per-unit non-ethane and ethane sales prices, respectively; partially offset byprices;


Management’s Discussion and Analysis (Continued)

A $13$19 million decrease associated with 16 percent lower non-ethane sales volumes primarily due to less producer drilling activity as well as lower sales volumes primarily due to 49 percent lower ethane sales volumes resulting from higher ethane rejection;
A $26 million increase related to a decrease in natural gas purchases associated with lower equity NGL production volumes and lower natural gas prices.
Additionally, themarketing margins increased by $12 million primarily due to favorable changes in net commodity prices. The decrease in Product sales includes a $263$195 million decrease in marketing sales, which is due to lower sales prices, partially offset by higher marketing sales volumes, a $14 million decrease related to the sale of other products, and a $7 million decrease in system management gas sales.volumes. These decreases are substantially offset in Product costs.Marketing margins decreased by $12 million primarily due to unfavorable changes in pricing.
Other segment costs and expenses decreased primarily due a $37 million reduction associated with the absence of our former Four Corners area assets and the absence of a 2018 unfavorable charge of $12 million for a regulatory liability associated with a decrease in Northwest Pipeline’s estimated deferred state income tax rate following the WPZ Merger.
Proportional Modified EBITDA of equity-method investments increased primarily due to the addition of the RMM equity-method investment during the third quarter of 2018, partially offset by the absence of the Jackalope equity-method investment sold in April 2019.
Nine months ended September 30, 2019 vs. Nine months ended September 30, 2018
West Modified EBITDA decreased primarily due to the absence of EBITDA of certain of our former sold or deconsolidated assets, 2019 impairments of certain assets, lower commodity margins due to unfavorable commodity prices and lower volumes associated with equity NGL production related to our ongoing operations, and lower service revenues associated with the expiration of a certain MVC.
Service revenues decreased primarily due to:
A $201 million decrease associated with asset divestitures and deconsolidations during 2018, including our former Four Corners area assets, certain Delaware basin assets that were contributed to our Brazos Permian II equity-method investment, and our Jackalope assets which were deconsolidated in second-quarter 2018;
A $29 million decrease driven by lower deferred revenue amortization and MVC deficiency fee revenues associated with the expiration of a certain MVC agreement in the Barnett Shale region;
A $19 million decrease driven by lower gathering volumes primarily in the Mid-Continent, Barnett Shale, and Wamsutter regions;
An $18 million decrease associated with lower rates primarily driven by lower commodity pricing in the Piceance region and the transition from a cost-of-service to fixed-fee rate for a certain customer contract in the Mid-Continent region; partially offset by
A $26 million increase in other fee revenues driven by higher fractionation and storage fees;
An $11 million increase associated with the expected resolution of a prior period performance obligation;
An $11 million increase related to higher other MVC deficiency fee revenues.
The net sum of Service revenues – commodity consideration, Product sales, Product costs, and Processing commodity expenses comprise our commodity product margins. Our commodity product margins associated with our equity NGLs decreased $114 million primarily due to:
A $79 million decrease associated with lower sales volumes, consisting of $54 million related to the absence of our former Four Corners area assets and $25 million due to 11 percent lower non-ethane volumes and 17 percent lower ethane sales volumes primarily due to well freeze-offs and temporary shut-ins associated with more severe weather conditions in first-quarter 2019, natural declines, and ethane rejection;


Management’s Discussion and Analysis (Continued)

A $48 million decrease associated with lower sales prices primarily due to 29 percent and 41 percent lower average net realized per-unit non-ethane and ethane sales prices, respectively; partially offset by
A $13 million increase related to a net decrease in natural gas purchases associated with lower equity NGL production volumes partially offset higher lower natural gas prices.
Additionally, the decrease in Product sales includes a $332 million decrease in marketing sales, which is due to lower sales prices, partially offset by higher sales volumes, a $31 million decrease related to the sale of other products, and a $26 million decrease in system management gas sales. These decreases are substantially offset in Product costs. Marketing margins decreased by $15 million primarily due to unfavorable changes in pricing.
Other segment costs and expenses decreased primarily due to a $124 million reduction associated with the absences of our former Four Corners area assets and from the Jackalope deconsolidation in second-quarter 2018, as well aslower employee-related expenses driven by the absence of a 2018 unfavorable charge of $12 million for a regulatory liability associated with a decrease in Northwest Pipeline’s estimated deferred state income tax rate following the WPZ Merger as previously discussed. These decreases were partially offset by an unfavorable accrual insecond-quarter 2019 for estimated severance and related costs of $16 million primarily associated with our VSP (see Note 6 – Other Income and Expensesof Notes to Consolidated Financial Statements) and the absenceassociated reduced costs in 2020, as well as lower maintenance costs primarily due to timing and scope of a $7 million favorable adjustmentactivities, and lower operating costs due to the regulatory liability associated with Tax Reform at Northwest Pipeline in first-quarter 2018.fewer leased compressors.
Impairment of certain assets increaseddecreased primarily due to the absence of a $59 million impairment of certain Eagle Ford Shale gathering assets and a $12 million impairment of certain idle gathering assets in 2019 (see Note 13 – Fair Value Measurements and Guarantees of Notes to Consolidated Financial Statements).2019.
Proportional Modified EBITDA of equity-method investments increaseddecreased primarily due to lower volumes at OPPL and the additionsabsence of the Jackalope equity-method investment sold in April 2019, partially offset by growth at the RMM and Brazos Permian II equity-method investments in the second half of 2018.investment.
Other
 Three Months Ended September 30, Nine Months Ended September 30,
 2019 2018 2019 2018
 (Millions)
Other Modified EBITDA$(2) $6
 $1
 $(49)
 Three Months Ended June 30, Six Months Ended June 30,
 2020 2019 2020 2019
 (Millions)
Other Modified EBITDA$8
 $7
 $15
 $3
ThreeSix months ended SeptemberJune 30, 20192020 vs. threesix months ended SeptemberJune 30, 20182019
Other Modified EBITDA decreasedincreased primarily due to:
Theto the absence of a $37first-quarter 2019 $12 million benefit from establishingunfavorable adjustment to a regulatory asset associated with an increase in Transco’s estimated deferred state income tax rate following the WPZ Merger in the third quarter of 2018;
A $16 million decrease in income associated with a regulatory asset related to deferred taxes on equity funds used during construction;
A $9 million accrual in the third quarter of 2019 for loss contingencies associated with former operations.
These decreases were partially offset by:
The absence of a $35 million charge associated with a charitable contribution of preferred stock to The Williams Companies Foundation, Inc. (a not-for-profit corporation) in the third quarter of 2018 (see Note 12 – Stockholders’ Equity of Notes to Consolidated Financial Statements);
The absence of $15 million in costs associated with the WPZ Merger in the third quarter of 2018.


Management’s Discussion and Analysis (Continued)

Nine months ended September 30, 2019 vs. nine months ended September 30, 2018
Other Modified EBITDA increased primarily due to:
The absencemerger transaction wherein we acquired all of the $66 million impairmentoutstanding common units held by others of certain idle pipelines in the second quarter of 2018 (see Note 13 – Fair Value Measurements and Guarantees of Notes to Consolidated Financial Statements);our former publicly traded master limited partnership.
The absence of a $35 million charitable contribution charge in the third quarter of 2018 as detailed above;
The absence of $19 million in costs associated with the WPZ Merger in 2018;
The absence of a 2018 loss on early retirement of debt of $7 million in the first quarter of 2018.
These increases were partially offset by:
The absence of a $37 million benefit associated with a regulatory asset in the third quarter of 2018 as detailed above;
A $21 million decrease in income associated with a regulatory asset related to deferred taxes on equity funds used during construction;
A $12 million unfavorable change to a regulatory asset associated with an estimated deferred state income tax rate in the first quarter of 2019;
A $9 million accrual in the third quarter of 2019 for loss contingencies as detailed above.


Management’s Discussion and Analysis (Continued)

Management’s Discussion and Analysis of Financial Condition and Liquidity
Outlook
Fee-based businesses are a significant component of our portfolio and serve to reduce the influence of commodity price fluctuations on our cash flows. We expect to benefit as continued growth in demand for low-cost natural gas is driven by increases in LNG exports, industrial demand, and power generation.
As previously discussed in Company Outlook, our growth capital and investment expenditures in 20192020 are currently expected to be in a range from $2.3$1.0 billion to $2.5$1.2 billion. Growth capital spending in 20192020 includes Transco expansions, all of which are fully contracted with firm transportation agreements, and continuing to develop our gathering and processing infrastructureBluestem NGL pipeline project in the Northeast G&P and West segments.Mid-Continent region. In addition to growth capital and investment expenditures, we also remain committed to projects that maintain our assets for safe and reliable operations, as well as projects that meet legal, regulatory, and/or contractual commitments. We intend to fund substantially all of our planned 2019 growth2020 capital spending with retained cash flow and certain sources of available liquidity described below.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.
We fundedDuring the $741 million total consideration paid, including post-closing adjustments, for our March 2019 acquisitionfirst half of the remaining interest in UEOM with credit facility borrowings and cash on hand. In June 2019,2020, we receivedretired approximately $1.33$1.5 billion from our partner upon closing the sale of a 35 percent interest in the Northeast JV. Also in April 2019, we received $485 million from the sale of our 50 percent interest in Jackalope. These proceeds are being used to reducelong-term debt and fund capital growth.issued approximately $2.2 billion of new long-term debt. In August 2020, we expect to early retire our $600 million of 4.125 percent senior unsecured notes that are scheduled to mature in November 2020. In July 2020, we paid $284 million for rate refunds related to Transco’s increased rates collected since the new rates became effective in March 2019. (See Note 13 – Contingent Liabilities of Notes to Consolidated Financial Statements.)
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 2019.2020. Our potential material internal and external sources and uses of liquidity for 2019 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 SeptemberJune 30, 2019,2020, we had a working capital deficit of $1.89 billion,$100 million, including cash and cash equivalents.equivalents and long-term debt due within one year. Our available liquidity is as follows:
Available LiquiditySeptember 30, 2019June 30, 2020
(Millions)(Millions)
Cash and cash equivalents$247
$1,133
Capacity available under our $4.5 billion credit facility, less amounts outstanding under our $4 billion commercial paper program (1)4,500
4,500
$4,747
$5,633
 
(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 SeptemberJune 30, 2019.2020. Through SeptemberJune 30, 2019,2020, the highest amount outstanding under our commercial paper program and credit facility during 20192020 was $1.226$1.7 billion. At SeptemberJune 30, 2019,2020, 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 125 percent from the previous quarterly cash dividends of $0.34$0.38 per share paid in each quarter of 2018,2019, to $0.38$0.40 per share for the quarterly cash dividends paid in March and June and September 2019.2020.
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 Agency Outlook 
Senior Unsecured
Debt Rating
Corporate
Credit Rating
S&P Global Ratings StableBBB BBB
Moody’s Investors Service Stable Baa3N/A
Fitch Ratings Rating Watch PositiveStable BBB-N/A
In July 2019, S&P GlobalMay 2020, Fitch Ratings changed its Outlook from NegativeRating Watch Positive to Stable.
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 Nine Months Ended 
 September 30,		Cash Flow Six Months Ended 
June 30,
Category 2019 2018Category 2020 2019
 (Millions) (Millions)
Sources of cash and cash equivalents:        
Operating activities – netOperating $2,702
 $2,331
Operating $1,930
 $1,844
Proceeds from long-term debtFinancing 2,196
 20
Proceeds from credit-facility borrowingsFinancing 1,700
 700
Proceeds from sale of partial interest in consolidated subsidiary (see Note 2)Financing 1,330
 —
Financing —
 1,330
Proceeds from credit-facility borrowingsFinancing 700
 1,680
Proceeds from dispositions of equity-method investments (see Note 5)Investing 485
 —
Investing —
 485
Proceeds from long-term debtFinancing 36
 2,065
Contributions in aid of constructionInvesting 25
 395
Proceeds from commercial paper – netFinancing —
 821
        
Uses of cash and cash equivalents:        
Payments on credit-facility borrowingsFinancing (1,700) (860)
Payments of long-term debtFinancing (1,526) (8)
Common dividends paidFinancing (971) (921)
Capital expendituresInvesting (1,705) (2,659)Investing (613) (919)
Common dividends paidFinancing (1,382) (974)
Payments on credit-facility borrowingsFinancing (860) (1,950)
Dividends and distributions paid to noncontrolling interestsFinancing (98) (68)
Purchases of and contributions to equity-method investmentsInvesting (66) (242)
Purchases of businesses, net of cash acquired (see Note 2)Investing (728) —
Investing —
 (727)
Purchases of and contributions to equity-method investmentsInvesting (361) (803)
Dividends and distributions paid to noncontrolling interestsFinancing (86) (552)
Payments of long-term debtFinancing (44) (1,251)
Payments of commercial paper – netFinancing (4) —
        
Other sources / (uses) – netFinancing and Investing (29) 40
Financing and Investing (8) 4
Increase (decrease) in cash and cash equivalents $79
 $(857) $844
 $638
Operating activities
The factors that determine operating activities are largely the same as those that affect Net income (loss), with the exception of noncash items such as Depreciation and amortization, Provision (benefit) for deferred income taxes, Equity (earnings) losses, Net (gain) lossGain on disposition of equity-method investments, Impairment of equity-method investmentsgoodwill, (Gain) loss on deconsolidationImpairment of businessesequity-method investments, and Impairment of and net (gain) loss on sale of certain assets. Our Net cash provided (used) by operating activities for the ninesix months ended SeptemberJune 30, 2019,2020, increased from the same period in 20182019 primarily due to the net favorable changes in net operating working capital in 2019, including the collection of Transco’s filed rates subject to refund and the receipt of an income tax refund, as well as higher operating income (excluding noncash items as previously discussed) in 2019,2020 partially offset by the impactabsence of decreased distributions from unconsolidated affiliatesan income tax refund that was received in 2019.
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 – Debt and Banking Arrangements, Note 1312 – Fair Value Measurements and Guarantees, and Note 1413 – 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 ninesix months of 2019.2020.

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 thirdsecond quarter of 20192020 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 which 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 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 recentlyin 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.
On February 21, 2017, we received notice from Prior to the Environmental Enforcement Section ofscheduled hearing, the United States Department of Justice (DOJ) regarding certain alleged violations ofCourt continued the Clean Air Act at our Moundsville facility as set forth inhearing without setting a Notice of Noncompliance issued by the EPA on January 14, 2016. The notice includes an offer to avoid further legal action on the alleged violations by paying $2 million. In discussion with the DOJ and the EPA, the EPA has indicated its belief that additional similar violations have occurred at our Oak Grove facility and has expressed interest in pursuing a global settlement. On July 23, 2018, we received an offer from the DOJ to globally settle the government’s claim for civil penalties associated with the alleged violations at both the Moundsville and the Oak Grove facilities for $1.6 million. We are continuing to work with the agencies to resolve this matter.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 perform 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 completionConsent Order have been achieved.
On January 19, 2016, we received a Notice of which is pending.
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, 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 from the EPA, Region 8, regardingof certain alleged violations of the Clean Air ActLDAR regulations at our former Ignacio Gas Plant in Durango, Colorado,from the EPA, Region 8, following a previousan on-site inspection of the facility. We were subsequently informed that this matter has been referred to the DOJ for handling. The Notice of Violation does not contain an initial penalty assessment. We have responded to the alleged violations and continue to work with the agencies to resolve this matter.
On March 20, 2018, we also received a Notice of Violation from the EPA, Region 8, regardingof certain alleged violations of the Clean Air ActLDAR regulations at our Parachute Creek Gas Plant in Parachute, Colorado, followingfrom the EPA, Region 8. All Notices were subsequently referred to a previous on-site inspectioncommon attorney at the Department of Justice (DOJ). We are exploring global resolution of the facility. We were informed that this matter has been referred to the DOJ for handling. The Notice of Violation does not contain an initial penalty assessment. We have responded to theclaims 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 this matter.
On August 27, 2018, Northwest Pipeline LLC received a Notice of Violation/Ceasethese claims, whether individually or globally, and Desist Order from the Colorado Department of Public Health & Environment (CDPHE) regarding certain alleged violations of the Colorado Water Quality Control Act and its General Permit under the Colorado Discharge Permit System related to its stormwater management practices at two construction sites. On March 4, 2019, the CDPHE provided us with its initial penalty calculation, proposing a penalty of $81,000 in settlement of all violations alleged in its notice. On July 2, 2019, we entered into a Compliance Order on Consent with CDPHE, which includes a penalty amount of $81,000, to fully resolve the matter.negotiations are ongoing.
Other environmental matters called for by this Item are described under the caption “Environmental Matters” in Note 1413 – 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 1413 – 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, 2018,2019, includes risk factors that could materially affect our business, financial condition, or future results. Those risk factorsRisk Factors have not materially changed.changed, except as they were supplemented or modified pursuant to Part II, Item 1A. in our Quarterly Report on Form 10-Q for the quarter ended March 31, 2020.




Item 6.  Exhibits
Exhibit
No.
   Description
     
2.1+2.1 — 
Agreement and Plan of Merger dated as of May 16, 2018, by and among The Williams Companies, Inc., SCMS LLC, Williams Partners L.P., and WPZ GP LLC (filed on May 17, 2018 as Exhibit 2.1 to The Williams Companies, Inc.’s current report on Form 8-K (File No. 001-04174) and incorporated herein by reference).
2.2 — 
Amendment No 1. to Agreement and Plan of Merger dated as of May 1, 2016, by and among The Williams Companies, Inc., Energy Transfer Corp LP, Energy Transfer Corp GP, LLC, Energy Transfer Equity, L.P., LE GP, LLC and Energy Transfer Equity GP, LLC (filed on May 3, 2016 as Exhibit 2.1 to The Williams Companies, Inc.’s current report on Form 8-K (File No. 001-04174) and incorporated herein by reference).
2.3+2.3 — 
Agreement and Plan of Merger dated as of September 28, 2015, by and among The Williams Companies, Inc., Energy Transfer Corp LP, Energy Transfer Corp GP, LLC, Energy Transfer Equity, L.P., LE GP, LLC and Energy Transfer Equity GP, LLC (filed on October 1, 2015 as Exhibit 2.1 to The Williams Companies, Inc.’s current report on Form 8-K (File No. 001-04174) and incorporated herein by reference).
3.1 — 
Amended and Restated Certificate of Incorporation as supplemented (filed on May 26, 2010, as Exhibit 3.1 to The Williams Companies, Inc.’s current report on Form 8-K (File No. 001-04174) and incorporated herein by reference).
3.2 
—

 
Certificate of Designations of Series B Preferred Stock of The Williams Companies, Inc. (filed on July 17, 2018 as Exhibit 3.1 to The Williams Companies, Inc.’s current report on Form 8-K (File No. 001-04174) and incorporated herein by reference).
3.3 
—

 
Certificate of Amendment dated August 10, 2018 (filed on August 10, 2018 as Exhibit 3.1 to The Williams Companies, Inc.’s current report on Form 8-K (File No. 001-04174) and incorporated herein by reference).
3.4 — 
By-Laws (filed on January 20, 2017, as Exhibit 3.1 to The Williams Companies, Inc.’s current report on Form 8-K (File No. 001-04174) and incorporated herein by reference).
3.5—
Certificate of Designations of Series C Participating Preferred Stock of The Williams Companies, Inc. (filed on March 20, 2020 as Exhibit 3.1 to The Williams Companies, Inc.’s current report on Form 8‑K (File No. 001-04174) and incorporated herein by reference).
4.1—
Rights Agreement, dated as of March 20, 2020, between The Williams Companies, Inc. and Computershare 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 C (filed on March 20, 2020 as Exhibit 4.1 to The Williams Companies, Inc.’s current report on Form 8‑K (File No. 001-04174) and incorporated herein by reference).
4.2—
Indenture, dated as of May 8, 2020, between Transcontinental Gas Pipe Line Company, LLC and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on May 8, 2020 as Exhibit 4.1 to The Williams Companies, Inc.’s current report on Form 8-K (File No. 001-04174) and incorporated herein by reference).
4.3—
Third Supplemental Indenture, dated as of May 14, 2020, between The Williams Companies, Inc. and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on May 14, 2020 as Exhibit 4.1 to The Williams Companies, Inc.’s current report on Form 8-K (File No. 001-04174) and incorporated herein by reference).
10.1—
Registration Rights Agreement, dated May 8, 2020, among Transcontinental Gas Pipe Line Company, LLC and the initial purchasers listed therein (filed on May 8, 2020 as Exhibit 10.1 to The Williams Companies, Inc.’s current report on Form 8-K (File No. 001-04174) and incorporated herein by reference).
31.1* — 
Certification of Chief Executive Officer pursuant to Rules 13a-14(a) and 15d-14(a) promulgated under the Securities Exchange Act of 1934, as amended, and Item 601(b)(31) of Regulation S-K,S‑K, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.


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



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/ TED T. TIMMERMANS
John D. Porter
 Ted T. TimmermansJohn D. Porter
 Vice President, Controller, and Chief Accounting Officer (Duly Authorized Officer and Principal Accounting Officer)
October 31, 2019August 3, 2020