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)
þQUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 20182019
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.
THE WILLIAMS COMPANIES, INC.
(Exact name of registrant as specified in its charter)
DELAWAREDelaware 73-0569878
(State or other jurisdiction of incorporation or organization) (I.R.S. Employer Identification No.)
   
ONE WILLIAMS CENTEROne Williams Center  
TULSA, OKLAHOMATulsaOklahoma 74172-0172
(Address    (Address of principal executive offices) (Zip Code)
Registrant’s telephone number, including area code: (918) (918573-2000
NO CHANGE
 
(Former name, former address and former fiscal year, if changed since last report.)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. YesþNo¨
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted 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 and post such files). YesþNo ¨
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 filerþ
 
Accelerated filer¨
 
Non-accelerated filer¨
 
Smaller reporting company¨
 
Emerging growth company¨
(Do not check if a smaller reporting 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¨Noþ
Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.
Class Shares Outstanding at October 29, 201828, 2019
Common Stock, $1$1.00 par value 1,210,542,0311,212,048,836
 







The Williams Companies, Inc.
Index




  Page
  
  
 
 
 
 
 
 
 
 
 
 
 
 


The reports, filings, and other public announcements of The Williams Companies, Inc. (Williams) may contain or incorporate by reference statements that do not directly or exclusively relate to historical facts. Such statements are “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (Securities Act), and Section 21E of the Securities Exchange Act of 1934, as amended (Exchange Act). These forward-looking statements relate to anticipated financial performance, management’s plans and objectives for future operations, business prospects, outcome 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 prices, supply, and demand;


Demand for our services.


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 (including, but not limited to, the Tax Cuts and Job Acts of 2017 and Colorado Proposition 112), 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 costs and funding obligations for defined benefit pension plans and other postretirement benefit plans;


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





Changes in the current geopolitical situation;


Our exposure to the credit risk of our customers and counterparties;


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


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


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


Acts of terrorism, cybersecurity incidents, and related disruptions;


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


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


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


Because forward-looking statements involve risks and uncertainties, we caution that there are important factors, in addition to those listed above, that may cause actual results to differ materially from those contained in the forward-looking statements. For a detailed discussion of those factors, see Part I, Item 1A. Risk Factors in our Annual Report on Form 10-K filed with the SEC on February 22, 2018, as supplemented by the disclosure in Part II, Item 1A. Risk Factors in this Quarterly Report on Form 10-Q.21, 2019.






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
Fahrenheit
Dekatherms (Dth): A unit of energy equal to one million British thermal units
Mbbls/d: One thousand barrels per day
Mdth/d: One thousand dekatherms per day
MMcf/d: One million cubic feet per day
MMdth: One million dekatherms or approximately one trillion British thermal units
MMdth/d: One million dekatherms per day
Tbtu: One trillion British thermal units
Consolidated Entities:
Cardinal: Cardinal Gas Services, L.L.C.
Constitution: Constitution Pipeline Company, LLC
Gulfstar One: Gulfstar One LLC
Northwest Pipeline: Northwest Pipeline LLC
Transco: Transcontinental Gas Pipe Line Company, LLC
UEOM: Utica East Ohio Midstream LLC, previously a Partially Owned Entity until acquiring remaining interest in March 2019
Northeast JV: Ohio Valley Midstream LLC, a partially owned venture that includes our Ohio Valley assets and UEOM
WPZ: Williams Partners L.P. Effective August 10, 2018, we completed our merger with WPZ, pursuant to which we acquired all outstanding common units of WPZ held by others and Williams continued as the surviving entity.
Partially Owned Entities: Entities in which we do not own a 100 percent ownership interest and which, as of September 30, 2018,2019, 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
UEOM: Utica East Ohio Midstream LLC



Government and Regulatory:
EPA: Environmental Protection Agency
FERC: Federal Energy Regulatory Commission
SEC: Securities and Exchange Commission
Other:
ETE Merger Agreement: Merger Agreement and Plan of Merger of Williams with Energy Transfer Equity, L.P and certain of its affiliates
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
IDR: Incentive distribution right
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, and third-party transportation, and fractionation
RGP Splitter: Refinery grade propylene splitter
Throughput: The volume of product transported or passing through a pipeline, plant, terminal, or other facility
WPZ Merger: The August 10, 2018, merger transactions pursuant to which we acquired all outstanding common units of WPZ held by others, merged WPZ into Williams, and Williams continued as the surviving entity






PART I – FINANCIAL INFORMATION


Item 1. Financial Statements

The Williams Companies, Inc.
Consolidated Statement of Income
(Unaudited)
Three Months Ended 
 September 30,
 Nine Months Ended 
 September 30,
Three Months Ended 
 September 30,
 Nine Months Ended 
 September 30,
2018 2017 2018 20172019 2018 2019 2018
(Millions, except per-share amounts)(Millions, except per-share amounts)
Revenues:              
Service revenues$1,371
 $1,310
 $4,062

$3,853
$1,495
 $1,371
 $4,424

$4,062
Service revenues – commodity consideration (Note 2)121
 
 316
 
Service revenues – commodity consideration38
 121
 158
 316
Product sales811
 581
 2,104

1,950
466
 811
 1,512

2,104
Total revenues2,303
 1,891
 6,482

5,803
1,999
 2,303
 6,094

6,482
Costs and expenses:  
 


  
 


Product costs790
 504
 2,039

1,620
434

790

1,442

2,039
Processing commodity expenses (Note 2)30
 
 91
 
Processing commodity expenses19

30

83

91
Operating and maintenance expenses389
 403
 1,134

1,166
364

389

1,091

1,134
Depreciation and amortization expenses425
 433
 1,290

1,308
435

425

1,275

1,290
Selling, general, and administrative expenses174
 138
 436

452
130

174

410

436
Gain on sale of Geismar Interest (Note 4)
 (1,095) 
 (1,095)
Impairment of certain assets (Note 12)
 1,210
 66
 1,236
Impairment of certain assets (Note 13)



76

66
Other (income) expense – net(6) 24
 24

34
(11)
(6)
30

24
Total costs and expenses1,802
 1,617
 5,080

4,721
1,371

1,802

4,407

5,080
Operating income (loss)501
 274
 1,402

1,082
628

501

1,687

1,402
Equity earnings (losses)105
 115
 279

347
93

105

260

279
Other investing income (loss) – net (Note 5)2
 4
 74
 278
(107)
2

(54)
74
Interest incurred(286)
(275)
(856)
(842)(303)
(286)
(915)
(856)
Interest capitalized16

8

38

24
7

16

27

38
Other income (expense) – net52
 23
 99

124
1

52

19

99
Income (loss) before income taxes390
 149
 1,036

1,013
319

390

1,024

1,036
Provision (benefit) for income taxes190
 24
 297

126
77

190

244

297
Net income (loss)200
 125
 739

887
242

200

780

739
Less: Net income (loss) attributable to noncontrolling interests71
 92
 323

400
21

71

54

323
Net income (loss) attributable to The Williams Companies, Inc.129
 33
 416

487
221

129

726

416
Preferred stock dividends (Note 11)
 
 
 
Preferred stock dividends1
 
 2
 
Net income (loss) available to common stockholders$129
 $33
 $416
 $487
$220
 $129
 $724
 $416
Amounts attributable to The Williams Companies, Inc.:       
Basic earnings (loss) per common share:              
Net income (loss)$.13
 $.04
 $.47
 $.59
$.18
 $.13
 $.60
 $.47
Weighted-average shares (thousands)1,023,587
 826,779
 893,706
 825,925
1,212,270
 1,023,587
 1,211,938
 893,706
Diluted earnings (loss) per common share:              
Net income (loss)$.13
 $.04
 $.46
 $.59
$.18
 $.13
 $.60
 $.46
Weighted-average shares (thousands)1,026,504
 829,368
 896,322
 828,150
1,214,165
 1,026,504
 1,213,943
 896,322
Cash dividends declared per common share$.34
 $.30
 $1.02
 $.90


See accompanying notes.




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


Three Months Ended 
 September 30,
 Nine Months Ended 
 September 30,
Three Months Ended 
 September 30,
 Nine Months Ended 
 September 30,
2018 2017 2018 20172019 2018 2019 2018
(Millions)(Millions)
Net income (loss)$200
 $125
 $739
 $887
$242
 $200
 $780
 $739
Other comprehensive income (loss):              
Cash flow hedging activities:              
Net unrealized gain (loss) from derivative instruments, net of taxes of $3 and $6 in 2018, and $2 and $1 in 2017(5) (9) (19) (5)
Reclassifications into earnings of net derivative instruments (gain) loss, net of taxes of ($2) and ($3) in 2018, and $1 and $1 in 20177
 2
 10
 
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:              
Amortization of prior service cost (credit) included in net periodic benefit cost (credit), net of taxes of $1 and $2 in 2017
 
 
 (2)
Net actuarial gain (loss) arising during the year, net of taxes of ($0) and ($1) in 2018



4


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 2018, and ($2) and ($7) in 20174
 4
 14
 13
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
Other comprehensive income (loss)6
 (3) 9
 6
(1) 6
 4
 9
Comprehensive income (loss)206
 122
 748
 893
241
 206
 784
 748
Less: Comprehensive income (loss) attributable to noncontrolling interests72
 89
 321
 398
21
 72
 54
 321
Comprehensive income (loss) attributable to The Williams Companies, Inc.$134
 $33
 $427
 $495
$220
 $134
 $730
 $427
See accompanying notes.






The Williams Companies, Inc.
Consolidated Balance Sheet
(Unaudited)
 September 30,
2018
 December 31,
2017
 September 30,
2019
 December 31,
2018
 (Millions, except per-share amounts) (Millions, except per-share amounts)
ASSETS    
Current assets:        
Cash and cash equivalents $42
 $899
 $247
 $168
Trade accounts and other receivables (net of allowance of $9 at September 30, 2018 and $9 at December 31, 2017) 883
 976
Trade accounts and other receivables (net of allowance of $6 at September 30, 2019 and $9 at December 31, 2018) 875
 992
Inventories 153
 113
 129
 130
Assets held for sale (Note 4) 664
 7
Other current assets and deferred charges 242
 184
 183
 174
Total current assets 1,984
 2,179
 1,434
 1,464
Investments 7,427
 6,552
 6,228
 7,821
Property, plant, and equipment 39,953
 39,513
 41,647
 38,661
Accumulated depreciation and amortization (11,279) (11,302) (12,034) (11,157)
Property, plant, and equipment – net 28,674
 28,211
 29,613
 27,504
Intangible assets – net of accumulated amortization 8,324
 8,791
 8,041
 7,767
Regulatory assets, deferred charges, and other 744
 619
 965
 746
Total assets $47,153
 $46,352
 $46,281
 $45,302
LIABILITIES AND EQUITY        
Current liabilities:        
Accounts payable $739
 $978
 $602
 $662
Liabilities held for sale (Note 4) 49
 
Accrued liabilities 1,117
 1,167
 1,184
 1,102
Commercial paper 823
 
Long-term debt due within one year 33
 501
 1,538
 47
Total current liabilities 2,761
 2,646
 3,324
 1,811
Long-term debt 21,409
 20,434
 20,719
 22,367
Deferred income tax liabilities 1,648
 3,147
 1,651
 1,524
Regulatory liabilities, deferred income, and other 4,376
 3,950
 3,728
 3,603
Contingent liabilities (Note 13) 
 
Contingent liabilities (Note 14) 

 

Equity:        
Stockholders’ equity:        
Preferred stock (Note 11) 35
 
Common stock ($1 par value; 1,470 million shares authorized at September 30, 2018 and 960 million shares authorized at December 31, 2017; 1,245 million shares issued at September 30, 2018 and 861 million shares issued at December 31, 2017) 1,245
 861
Preferred stock 35
 35
Common stock ($1 par value; 1,470 million shares authorized at September 30, 2019 and December 31, 2018; 1,247 million shares issued at September 30, 2019 and 1,245 million shares issued at December 31, 2018) 1,247
 1,245
Capital in excess of par value 24,680
 18,508
 24,310
 24,693
Retained deficit (9,018) (8,434) (10,664) (10,002)
Accumulated other comprehensive income (loss) (291) (238) (266) (270)
Treasury stock, at cost (35 million shares of common stock) (1,041) (1,041) (1,041) (1,041)
Total stockholders’ equity 15,610
 9,656
 13,621
 14,660
Noncontrolling interests in consolidated subsidiaries 1,349
 6,519
 3,238
 1,337
Total equity 16,959
 16,175
 16,859
 15,997
Total liabilities and equity $47,153
 $46,352
 $46,281
 $45,302

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 – December 31, 2017$
 $861
 $18,508
 $(8,434) $(238) $(1,041) $9,656
 $6,519
 $16,175
Adoption of ASC 606 (Note 1)
 
 
 (84) 
 
 (84) (37) (121)
Adoption of ASU 2018-02 (Note 1)
 
 
 61
 (61) 
 
 
 
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 11)35
 
 
 
 
 
 35
 
 35
Cash dividends – common stock
 
 
 (974) 
 
 (974) 
 (974)
Dividends and distributions to noncontrolling interests
 
 
 
 
 
 
 (598) (598)
Stock-based compensation and related common stock issuances
 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 3)
 
 
 
 
 
 
 (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
 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
Net income (loss)
 
 
 129
 
 
 129
 71
 200
Other comprehensive income (loss)
 
 
 
 5
 
 5
 1
 6
WPZ Merger (Note 1)
 382
 6,112
 
 (3) 
 6,491
 (4,629) 1,862
Issuance of preferred stock (Note 12)35
 
 
 
 
 
 35
 
 35
Cash dividends common stock ($0.34 per share)

 
 
 (411) 
 
 (411) 
 (411)
Dividends and distributions to noncontrolling interests
 
 
 
 
 
 
 (196) (196)
Stock-based compensation and related common stock issuances, net of tax
 
 16
 
 
 
 16
 
 16
Changes in ownership of consolidated subsidiaries, net
 
 1
 
 
 
 1
 (1) 
Contributions from noncontrolling interests
 
 
 
 
 
 
 2
 2
Other
 1
 (1) (1) 
 
 (1) (1) (2)
   Net increase (decrease) in equity35
 383
 6,128
 (283) 2
 
 6,265
 (4,753) 1,512
Balance September 30, 2018
$35
 $1,245
 $24,680
 $(9,018) $(291) $(1,041) $15,610
 $1,349
 $16,959


See accompanying notes.














The Williams Companies, Inc.
Consolidated Statement of Changes in Equity (Continued)
(Unaudited)
 The Williams Companies, Inc. Stockholders    
 
Preferred
Stock
 Common
Stock
 
Capital in
Excess of
Par Value
 
Retained
Deficit
 AOCI* 
Treasury
Stock
 
Total
Stockholders’
Equity
 
Noncontrolling
Interests
 Total Equity
 (Millions)
Balance – December 31, 2018$35
 $1,245
 $24,693
 $(10,002) $(270) $(1,041) $14,660
 $1,337
 $15,997
Net income (loss)
 
 
 726
 
 
 726
 54
 780
Other comprehensive income (loss)
 
 
 
 4
 
 4
 
 4
Cash dividends – common stock ($1.14 per share)
 
 
 (1,382) 
 
 (1,382) 
 (1,382)
Dividends and distributions to noncontrolling interests
 
 
 
 
 
 
 (86) (86)
Stock-based compensation and related common stock issuances, net of tax
 2
 43
 
 
 
 45
 
 45
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
Other
 
 
 (6) 
 
 (6) 
 (6)
   Net increase (decrease) in equity
 2
 (383) (662) 4
 
 (1,039) 1,901
 862
Balance – September 30, 2019$35
 $1,247
 $24,310
 $(10,664) $(266) $(1,041) $13,621
 $3,238
 $16,859
Balance – December 31, 2017$
 $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
 
*Accumulated Other Comprehensive Income (Loss)
See accompanying notes.






The Williams Companies, Inc.
Consolidated Statement of Cash Flows
(Unaudited)
Nine Months Ended 
 September 30,
Nine Months Ended 
 September 30,
2018 20172019 2018
(Millions)(Millions)
OPERATING ACTIVITIES:  
Net income (loss)$739
 $887
$780
 $739
Adjustments to reconcile to net cash provided (used) by operating activities:      
Depreciation and amortization1,290
 1,308
1,275
 1,290
Provision (benefit) for deferred income taxes351
 99
268
 351
Equity (earnings) losses(279) (347)(260) (279)
Distributions from unconsolidated affiliates507
 602
458
 507
Net (gain) loss on disposition of equity-method investments
 (269)
Gain on sale of Geismar Interest (Note 4)
 (1,095)
Impairment of and net (gain) loss on sale of assets64
 1,225
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
Amortization of stock-based awards43
 61
44
 43
Cash provided (used) by changes in current assets and liabilities:      
Accounts and notes receivable75
 118
159
 75
Inventories(39) (23)7
 (39)
Other current assets and deferred charges(44) (11)(10) (44)
Accounts payable(76) 47
(76) (76)
Accrued liabilities(62) (161)76
 (62)
Other, including changes in noncurrent assets and liabilities(238) (210)(161) (176)
Net cash provided (used) by operating activities2,331
 2,231
2,702
 2,331
FINANCING ACTIVITIES:      
Proceeds from (payments of) commercial paper – net821
 (93)(4) 821
Proceeds from long-term debt3,745
 3,013
736
 3,745
Payments of long-term debt(3,201) (5,475)(904) (3,201)
Proceeds from issuance of common stock15
 2,130
10
 15
Proceeds from sale of partial interest in consolidated subsidiary (Note 2)1,330
 
Common dividends paid(974) (744)(1,382) (974)
Dividends and distributions paid to noncontrolling interests(552) (636)(86) (552)
Contributions from noncontrolling interests13
 15
32
 13
Payments for debt issuance costs(26) (14)
 (26)
Other – net(46) (87)(11) (46)
Net cash provided (used) by financing activities(205) (1,891)(279) (205)
INVESTING ACTIVITIES:      
Property, plant, and equipment:      
Capital expenditures (1)(2,659) (1,700)(1,705) (2,659)
Dispositions – net(2) (27)(32) (2)
Contributions in aid of construction395
 253
25
 395
Proceeds from sale of businesses, net of cash divested
 2,056
Proceeds from dispositions of equity-method investments
 200
Purchases of businesses, net of cash acquired (Note 2)(728) 
Proceeds from dispositions of equity-method investments (Note 5)485
 
Purchases of and contributions to equity-method investments(803) (103)(361) (803)
Other – net86
 (17)(28) 86
Net cash provided (used) by investing activities(2,983) 662
(2,344) (2,983)
Increase (decrease) in cash and cash equivalents(857) 1,002
79
 (857)
Cash and cash equivalents at beginning of year899
 170
168
 899
Cash and cash equivalents at end of period$42
 $1,172
$247
 $42
_____________      
(1) Increases to property, plant, and equipment$(2,482) $(1,826)$(1,707) $(2,482)
Changes in related accounts payable and accrued liabilities(177) 126
2
 (177)
Capital expenditures$(2,659) $(1,700)$(1,705) $(2,659)


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, 2017,2018, in Exhibit 99.1 of our Annual Report on Form 8-K dated May 3, 2018.10-K. The accompanying unaudited financial statements include all normal recurring adjustments and others that, in the opinion of management, are necessary to present fairly our interim financial statements.
The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes. Actual results could differ from those estimates.
Unless the context clearly indicates otherwise, references in this report to “Williams,” “we,” “our,” “us,” or like terms refer to The Williams Companies, Inc. and its subsidiaries. Unless the context clearly indicates otherwise, references to “Williams,” “we,” “our,” and “us” include the operations in which we own interests accounted for as equity-method investments that are not consolidated in our financial statements. When we refer to our equity investees by name, we are referring exclusively to their businesses and operations.
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 non-cashnoncash 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. Prior to the completion of the WPZ Merger and pursuantSheet. 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.
Financial Repositioning
In January 2017, we entered into agreements with WPZ, wherein we permanently waived the general partner’s incentive distribution rights and converted our 2 percent general partner interest in WPZ to a noneconomic interest in exchange for 289 million newly issued WPZ common units. Pursuant to this agreement, we also purchased approximately 277 thousand WPZ common units for $10 million. Additionally, we purchased approximately 59 million common units of WPZ at a price of $36.08586 per unit in a private placement transaction, funded with proceeds from our equity offering. According to the terms of this agreement, concurrent with WPZ’s quarterly distributions in February 2017 and May 2017, we paid additional consideration totaling $56 million to WPZ for these units.
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 principally in the United States. Prior toStates and are presented within the WPZ Merger, we had onefollowing reportable segment, Williams Partners. Beginning in the third-quarter 2018,segments: Northeast G&P, Atlantic-Gulf, and West, consistent with the manner in which our chief operating decision maker evaluates performance and allocates resources, our operationsresources. All remaining business activities as well as corporate activities are now presented within the following reportable segments: Northeast G&P, Atlantic-Gulf, and West. Prior period segment disclosures have been recast for the new segment presentation.


Notes (Continued)


included in Other.
Northeast G&P is comprised of our midstream gathering, processing, and processingfractionation businesses in the Marcellus Shale region primarily in Pennsylvania, New York, and West Virginia and the Utica Shale region of eastern Ohio, as well asincluding a 66 percent interest in Cardinal Gas Services, L.L.C. (Cardinal) (a consolidated entity), a 62 percent equity-method investment in Utica East Ohio Midstream, LLC,as well as a 69 percent equity-method investment in Laurel Mountain Midstream, LLC (Laurel Mountain), a 58 percent equity-method investment in Caiman Energy II, LLC, and Appalachia Midstream Services, LLC, which owns equity-method investments with an approximate average 66 percent interest in multiple gas gathering systems in the Marcellus Shale (Appalachia Midstream Investments). Northeast G&P includes a 65 percent interest in Ohio Valley Midstream LLC (Northeast JV) (a consolidated entity). The Northeast JV includes our Ohio Valley assets and Utica East Ohio Midstream LLC (UEOM), a former equity-method investment in which we acquired the remaining ownership interest in March 2019 (see Note 2 – Acquisitions).


Notes (Continued)


Atlantic-Gulf is comprised of our interstate natural gas pipeline, Transcontinental Gas Pipe Line Company, LLC (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 LLC (Gulfstar One) (a consolidated entity), which is a proprietary floating production system, and various petrochemical and feedstock pipelines in the Gulf Coast region, as well as a 50 percent equity-method investment in Gulfstream Natural Gas System, L.L.C., a 60 percent equity-method investment in Discovery Producer Services LLC, and a 41 percent interest in Constitution Pipeline Company, LLC (Constitution) (a consolidated entity), which is developing a pipeline project (see Note 34 – Variable Interest Entities), and a 60 percent equity-method investment in Discovery Producer Services LLC..
West is comprised of our interstate natural gas pipeline, Northwest Pipeline LLC (Northwest Pipeline), and our gathering, processing, and treating operations in New Mexico, Colorado, and Wyoming, as well as 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, Delaware, and PermianArkoma 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, and a 50 percent equity-method investment in Overland Pass Pipeline Company LLC, a 50 percent equity-method investment in Rocky Mountain Midstream Holdings LLC, and a 15 percent equity-method investment in Brazos Permian II, LLC (Brazos Permian II). West also included our former natural gas gathering and processing assets in the Four Corners area of New Mexico and Colorado, which were sold during the fourth quarter of 2018, and our former 50 percent interest in Jackalope Gas Gathering Services, L.L.C. (Jackalope) (an equity-method investment following deconsolidation as of June 30, 2018), a 43 percent equity-method investmentwhich was sold in Rocky Mountain Midstream Holdings LLC (RMM), and our previously owned 50 percent equity-method investment in the Delaware basin gas gathering system (DBJV) in the Mid-Continent region (see Note 5 – Investing Activities).
All remaining business activities, including our former Williams Olefins, L.L.C., a wholly owned subsidiary which owned our 88.5 percent undivided interest in the Geismar, Louisiana, olefins plant (Geismar Interest) (see Note 4 – Divestitures and Assets Held for Sale), as well as corporate activities, are included in Other.April 2019.
Basis of Presentation
Significant risks and uncertainties
We may monetize assetsbelieve that are not core to our strategy which could result in impairmentsthe carrying value of certain equity-method investments,of our property, plant, and equipment and other identifiable intangible assets. Such impairments could potentiallyassets, notably certain acquired assets accounted for as business combinations between 2012 and 2014, may be caused by indicationsin excess of current fair value. However, the carrying value implied through the monetization process or,of these assets, in the caseour judgment, continues to be recoverable based on our evaluation of asset dispositions that are part of a broader asset group, the impact of the loss ofundiscounted future estimated cash flows.
Proposition 112
On November 6, 2018, citizens of Colorado will vote on Proposition 112, a ballot measure that could significantly increase setback distances from occupied structures or other vulnerable areas, as defined or designated, for any new oil and gas development in the state, critically restricting or banning such activities. If the measure is approved, it could still be subject to modification or amendment by the Colorado legislature. An unfavorable outcome could adversely impact the operations, and ultimately the value, of our businesses and investments in Colorado, notably our recent investment in RMM (see Note 5 – Investing Activities).
FERC Income Tax Policy Revision
On March 15, 2018, the Federal Energy Regulatory Commission (FERC) issued a revised policy statement (the March 15 Statement) regarding the recovery of income tax costs in rates of natural gas pipelines. The FERC found that an impermissible double recovery results from granting a Master Limited Partnership (MLP) pipeline


Notes (Continued)


both an income tax allowance and a return on equity pursuant to the discounted cash flow methodology. As a result, the FERC will no longer permit an MLP pipeline to recover an income tax allowance in its cost of service. The FERC further stated it will address the application of this policy to non-MLP partnership forms as those issues arise in subsequent proceedings. One of the benefits of the recent WPZ Merger is to allow our FERC-regulated pipelines to continue to recover an income tax allowance in their cost of service rates.
On July 18, 2018, the FERC issued an order dismissing the requests for rehearing and clarification of the revised policy statement. In addition, the FERC provided guidance that an MLP pipeline (or other pass-through entity) no longer recovering an income tax allowance pursuant to the revised policy may eliminate previously accumulated deferred income taxes (ADIT) from its cost of service instead of flowing these ADIT balances to ratepayers. This guidance, if implemented, would significantly mitigate the impact of the March 15 Statement. However, the FERC stated that the revised policy statement and such guidance do not establish a binding rule but are instead expressions of general policy intent designed to provide guidance by notifying entities of the course of action the FERC intends to follow in future adjudications. To the extent the FERC addresses these issues in future proceedings, it will consider any arguments regarding not only the application of the revised policy to the facts of the case, but also any arguments regarding the underlying validity of the policy itself. The FERC’s guidance on ADIT likely will be challenged by customers and state commissions, which would result in a long period of revenue uncertainty for pipelines eliminating ADIT from their cost of service. The WPZ Merger has the additional benefit of eliminating this uncertainty.
On March 15, 2018, the FERC also issued a Notice of Proposed Rulemaking proposing a filing process that will allow it to determine which natural gas pipelines may be collecting unjust and unreasonable rates in light of the recent reduction in the corporate income tax rate in the Tax Cuts and Jobs Act (Tax Reform) and the revised policy statement. On July 18, 2018, the FERC issued a Final Rule, retaining the filing requirement and reaffirming the options that pipelines have to either reflect the reduced tax rate or explain why no rate change is necessary. The FERC also clarified that a natural gas company organized as a pass-through entity and all of whose income or losses are consolidated on the federal income tax return of its corporate parent is considered to be subject to the federal corporate income tax and is thus eligible for a tax allowance. We believe this Final Rule and the previously discussed WPZ Merger allow for the continued recovery of income tax allowances in Transco’s and Northwest Pipeline’s rates. Further, Transco’s August 31, 2018 general rate case filing reflects a tax allowance based on this clarification, and the FERC’s September 28, 2018 order in the rate case proceeding finds that Transco is exempt from the Final Rule’s Form 501-G filing requirement. In addition, on October 19, 2018, Northwest Pipeline filed a petition requesting that the FERC waive its Form 501-G filing requirement under this Final Rule because the reduction in the corporate income tax in Tax Reform is already addressed in its settlement.
On March 15, 2018, the FERC also issued a Notice of Inquiry seeking comments on the additional impacts of Tax Reform on jurisdictional rates, particularly whether, and if so how, the FERC should address changes relating to ADIT amounts after the corporate income tax rate reduction and bonus depreciation rules, as well as whether other features of Tax Reform require FERC action. We are evaluating the impact of these developments on our interstate natural gas pipelines and currently expect any associated impacts would be prospective and determined through subsequent rate proceedings. We also continue to monitor developments that may impact our regulatory liabilities resulting from Tax Reform. It is reasonably possible that future tariff-based rates collected bystrategic 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 could impact our interstate natural gas pipelinesassumptions and ultimately result in impairments of these assets. Such transactions or developments may be adversely impacted.also indicate that certain of our equity-method investments have experienced other-than-temporary declines in value, which could result in impairment, or that the fair value of the reporting unit for our goodwill is less than its carrying amount, which would result in impairment.
Accounting standards issued and adopted
During the first quarter of 2018, we early adopted Accounting Standards Update (ASU) 2018-02 “Income Statement - Reporting Comprehensive Income (Topic 220): Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income” (ASU 2018-02). As a result of Tax Reform lowering the federal income tax rate, the tax effects of items within accumulated other comprehensive income may not reflect the appropriate tax rate. ASU 2018-02 allows for the reclassification from accumulated other comprehensive income to retained earnings for stranded tax effects resulting from Tax Reform. The adoption of ASU 2018-02 resulted in the reclassification of $61 million from Accumulated other comprehensive income (loss) to Retained deficit on our Consolidated Balance Sheet.


Notes (Continued)


Effective January 1, 2018, we adopted ASU 2017-12 “Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities” (ASU 2017-12). ASU 2017-12 applies to entities that elect hedge accounting in accordance with Accounting Standards Codification (ASC) 815. The ASU affects both the designation and measurement guidance for hedging relationships and the presentation of hedging results. ASU 2017-12 was applied using a modified retrospective approach for cash flow and net investment hedges existing at the date of adoption and prospectively for the presentation and disclosure guidance. The adoption of ASU 2017-12 did not have a significant impact on our consolidated financial statements.
Effective January 1, 2018, we adopted ASU 2017-07 “Compensation - Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost” (ASU 2017-07). ASU 2017-07 requires employers to report the service cost component of net benefit cost in the same line item or items as other compensation costs arising from employee services. The other components of net benefit cost must be presented in the income statement separately from the service cost component and outside Operating income (loss). Only the service cost component is now eligible for capitalization when applicable. The presentation aspect of ASU 2017-07 must be applied retrospectively and the capitalization requirement prospectively. In accordance with this adoption, we have conformed the prior year presentation, which resulted in increases of $3 million and $9 million to Operating and maintenance expenses with corresponding decreases to Operating income (loss) and increases of $3 million and $9 million to Other income (expense) – net below Operating income (loss) in the Consolidated Statement of Incomefor the three- and nine-month periods ended September 30, 2017, respectively.
Effective January 1, 2018, we adopted ASU 2016-15 “Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments” (ASU 2016-15). Among other things, ASU 2016-15 permits an accounting policy election to classify distributions received from equity-method investees using either the cumulative earnings approach or the nature of distribution approach. We have elected to apply the nature of distribution approach and have retrospectively conformed the prior year presentation within the Consolidated Statement of Cash Flowsin accordance with ASU 2016-15. For the period ended September 30, 2017, amounts previously presented as Distributions from unconsolidated affiliates in excess of cumulative earnings within Investing Activities are now presented as part of Distributions from unconsolidated affiliates within Operating Activities, resulting in an increase to Net cash provided (used) by operating activities of $394 million with a corresponding reduction in Net cash provided (used) by investing activities.
In May 2014,February 2016, the Financial Accounting Standards Board (FASB) issued ASU 2014-09 establishing ASC Topic 606, “Revenue from Contracts with Customers” (ASC 606). ASC 606 establishes a comprehensive new revenue recognition model designed to depict the transfer of goods or services to a customer in an amount that reflects the consideration the entity expects to be entitled to receive in exchange for those goods or services and requires significantly enhanced revenue disclosures. In August 2015, the FASB issued ASU 2015-14 “Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date” (ASU 2015-14). Per ASU 2015-14, the standard became effective for interim and annual reporting periods beginning after December 15, 2017.
We adopted the provisions of ASC 606 effective January 1, 2018, utilizing the modified retrospective transition method for all contracts with customers, which included applying the provisions of ASC 606 beginning January 1, 2018, to all contracts not completed as of that date with the cumulative effect of applying the standard for periods prior to January 1, 2018, as an adjustment to Total equity, net of tax, upon adoption. As a result of our adoption, the cumulative impact to our Total equity, net of tax, at January 1, 2018, was a decrease of $121 million in the Consolidated Balance Sheet.
For each revenue contract type, we conducted a formal contract review process to evaluate the impact of ASC 606. The adjustment to Total equity upon adoption of ASC 606 is primarily comprised of the impact to the timing of recognition of deferred revenue (contract liabilities) associated with certain contracts which underwent modifications in periods prior to January 1, 2018. Under the provisions of ASC 606, when a contract modification does not increase both the scope and price of the contract, and the remaining goods and services are distinct from the goods and services transferred prior to the modification, the modification is treated as a termination of the existing contract and the creation of a new contract. ASC 606 requires that the transaction price, including any remaining contract liabilities from the old contract, be allocated to the performance obligations over the term of the new contract. The contract modification adjustments are partially offset by the impact of changes to the timing of recognizing revenue which is subject to the constraint on


Notes (Continued)


estimates of variable consideration of certain contracts. The constraint of variable consideration will result in the acceleration of revenue recognition and corresponding de-recognition of contract liabilities for certain contracts (as compared to the previous revenue recognition model) as a result of our assessment that it is probable such recognition would not result in a significant revenue reversal in the future. Additionally, under ASC 606, our revenues will increase in situations where we receive noncash consideration, which exists primarily in certain of our gas processing contracts where we receive commodities as full or partial consideration for services provided. This increase in revenues will be offset by a similar increase in costs and expenses when the commodities received are subsequently sold. Financial systems and internal controls necessary for adoption were implemented effective January 1, 2018. (See Note 2 – Revenue Recognition.)
Accounting standards issued but not yet adopted
In June 2016, the FASB issued ASU 2016-13 “Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments” (ASU 2016-13). ASU 2016-13 changes the impairment model for most financial assets and certain other instruments. For trade and other receivables, held-to-maturity debt securities, loans, and other instruments, entities will be 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. ASU 2016-13 is effective for interim and annual periods beginning after December 15, 2019. Early adoption is permitted. The standard requires varying transition methods for the different categories of amendments. Although we do not expect ASU 2016-13 to have a significant impact, it could impact our trade receivables as the related allowance for credit losses will be recognized earlier under the expected loss model.
In February 2016, the FASB issued ASUStandards 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 currentprior lease accounting, and causes lessees to recognize operating leases on the balance sheet as a lease liability measured as the present value of the future lease payments with a corresponding right-of-use asset, with an exception for leases with a term of one year or less. Additional disclosures will also beare required regarding the amount, timing, and uncertainty of cash flows arising from leases. In January 2018, the FASB issued ASU 2018-01 “Leases (Topic 842): Land Easement Practical Expedient for Transition to Topic 842” (ASU 2018-01). Per ASU 2018-01, land easements and rights-of-way are required to be assessed under ASU 2016-02 to determine whether the arrangements are or contain a lease. ASU 2018-01 permits an entity to elect a transition practical expedient to not apply ASU 2016-02 to land easements that exist or expired before the effective date of ASU 2016-02 and that were not previously assessed under the previous lease guidance in ASCAccounting Standards Codification (ASC) Topic 840 “Leases.”
In July 2018, the FASB issued ASU 2018-11 “Leases (Topic 842): Targeted Improvements” (ASU 2018-11). Prior to ASU 2018-11, a modified retrospective transition was required for financing or operating leases existing at or entered into after the beginning of the earliest comparative period presented in the financial statements. ASU 2018-11 allows entities an additional transition method to the existing requirements whereby an entity could adopt the provisions of ASU 2016-02 by recognizing a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption without adjustment to the financial statements for periods prior to adoption. ASU 2018-11 also allows a


Notes (Continued)


practical expedient that permits lessors to not separate non-leasenonlease 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. Early adoption is permitted. We will adoptprospectively adopted ASU 2016-02 effective January 1, 2019.2019, and did not adjust prior periods as permitted by ASU 2018-11 (see Note 10 – Leases).
We are in the process of finalizingcompleted our review of contracts to identify leases based on the modified definition of a lease and identifyingimplemented 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. While we are still in the process of completing our implementation evaluation of ASU 2016-02, we currently believe theThe 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 are also evaluatingevaluated ASU 2016-02’s available practical expedients on adoption and have generally elected to adopt the practical expedients, which includes the practical expedient to not separate lease and nonlease components by both lessees and lessors by class of underlying assets and the land easements practical expedient.
Accounting standards issued but not yet adopted
In June 2016, the FASB issued ASU 2016-13 “Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments” (ASU 2016-13). ASU 2016-13 changes the impairment model for most financial assets and certain other instruments. For trade and other receivables, held-to-maturity debt securities, loans, and other instruments, entities will be 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. ASU 2016-13 is effective for us for interim and annual periods beginning after December 15, 2019. We plan to adopt as of January 1, 2020. We anticipate that ASU 2016-13 will primarily apply to our trade receivables. While we generallydo not expect a significant financial impact, we have analyzed our historical credit loss experience and continue to elect.develop and implement processes, procedures, and internal controls in order to make the necessary credit loss assessments and required disclosures upon adoption.

Note 2 – Acquisitions
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.
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 13 – 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 million, and decreased Capital in excess of par value by $426 million and Deferred income tax liabilities by $142 million in the Consolidated Balance Sheet. Costs related to this transaction are $6 million and are reported within our Northeast G&P segment and included in Selling, general, and administrative expenses in our Consolidated Statement of Income.



Notes (Continued)


Note 23 – Revenue Recognition
Customers in our gas pipeline businesses are comprised of public utilities, municipalities, gas marketers and producers, intrastate pipelines, direct industrial users, and electrical generators. Customers in our midstream businesses are comprised of oil and natural gas producer counterparties. Customers for our product sales are comprised of public utilities, gas marketers, and direct industrial users.
A performance obligation is a promise in a contract to transfer a distinct good or service (or integrated package of goods or services) to the customer. A contract’s transaction price is allocated to each distinct performance obligation and recognized as revenue, when, or as, the performance obligation is satisfied. A performance obligation is distinct if the service is separately identifiable from other items in the integrated package of services and if a customer can benefit from it on its own or with other resources that are readily available to the customer. An integrated package of services typically represents a single performance obligation if the services are contained within the same contract or within multiple contracts entered into in contemplation with one another that are highly interdependent or highly interrelated, meaning each of the services is significantly affected by one or more of the other services in the contract. Service revenue contracts from our gas pipeline and midstream businesses contain a series of distinct services, with the majority of our contracts having a single performance obligation that is satisfied over time as the customer simultaneously receives and consumes the benefits provided by our performance. Most of our product sales contracts have a single performance obligation with revenue recognized at a point in time when the products have been sold and delivered to the customer.
Certain customers reimburse us for costs we incur associated with construction of property, plant, and equipment utilized in our operations. For our rate-regulated gas pipeline businesses that apply ASC 980. "Regulated Operations" (Topic 980), we follow FERC guidelines with respect to reimbursement of construction costs. FERC tariffs only allow for cost reimbursement and are non-negotiable in nature; thus, the construction activities do not represent an ongoing major and central operation of our gas pipeline businesses and are not within the scope of ASC 606. Accordingly, cost reimbursements are treated as a reduction to the cost of the constructed asset. For our midstream businesses, reimbursement and service contracts with customers are viewed together as providing the same commercial objective, as we have the ability to negotiate the mix of consideration between reimbursements and amounts billed over time. Accordingly, we generally recognize reimbursements of construction costs from customers on a gross basis as a contract liability separate from the associated costs included within property, plant, and equipment. The contract liability is recognized into service revenues as the underlying performance obligations are satisfied.
Service Revenues
Gas pipeline businesses
Revenues from our interstate natural gas pipeline businesses, which are included within the caption “Regulated interstate natural gas transportation and storage” in the revenue by category table below and are subject to regulation by certain state and federal authorities, including the FERC, include both firm and interruptible transportation and storage contracts. Firm transportation and storage agreements provide for a reservation charge based on the pipeline or storage capacity reserved, and a commodity charge based on the volume of natural gas delivered/stored, each at rates specified in our FERC tariffs or based on negotiated contractual rates, with contract terms that are generally long-term in nature. Most of our long-term contracts contain an evergreen provision, which allows the contracts to be extended for periods primarily up to one year in length an indefinite number of times following the specified contract term and until terminated generally by either us or the customer. Interruptible transportation and storage agreements provide for a volumetric charge based on actual commodity transportation or storage utilized in the period in which those services are provided, and the contracts are generally limited to one-month periods or less. Our performance obligations related to our interstate natural gas pipeline businesses include the following:
Guaranteed transportation or storage under firm transportation and storage contracts—an integrated package of services typically constituting a single performance obligation, which includes standing ready to provide such services and receiving, transporting or storing (as applicable), and redelivering commodities;


Notes (Continued)


Interruptible transportation and storage under interruptible transportation and storage contracts—an integrated package of services typically constituting a single performance obligation, which includes receiving, transporting or storing (as applicable), and redelivering commodities upon nomination by the customer.
In situations where we consider the integrated package of services as a single performance obligation, which represents a majority of our interstate natural gas pipeline contracts with customers, we do not consider there to be multiple performance obligations because the nature of the overall promise in the contract is to stand ready (with regard to firm transportation and storage contracts), receive, transport or store, and redeliver natural gas to the customer; therefore, revenue is recognized at the completion of the integrated package of services which represents a single performance obligation.
We recognize revenues for reservation charges over the performance obligation period, which is the contract term, regardless of the volume of natural gas that is transported or stored. Revenues for commodity charges from both firm and interruptible transportation services and storage services are recognized when natural gas is delivered at the agreed upon delivery point or when natural gas is injected or withdrawn from the storage facility because they specifically relate to our efforts to provide these distinct services. Generally, reservation charges and commodity charges in our interstate natural gas pipeline businesses are recognized as revenue in the same period they are invoiced to our customers. As a result of the ratemaking process, certain amounts collected by us may be subject to refund upon the issuance of final orders by the FERC in pending rate proceedings. We record estimates of rate refund liabilities considering our and other third-party regulatory proceedings, advice of counsel, and other risks.
Midstream businesses
Revenues from our midstream businesses, which are included in the caption titled “Non-regulated gathering, processing, transportation, and storage” in the revenue by category table below, include contracts for natural gas gathering, processing, treating, compression, transportation, and other related services with contract terms that are generally long-term in nature and may extend up to the production life of the associated reservoir. Additionally, our midstream businesses generate revenues from fees charged for storing customers’ natural gas and NGLs, generally under prepaid contracted storage capacity contracts. In situations where we provide an integrated package of services combined into a single performance obligation, which represents a majority of this class of contracts with customers, we do not consider there to be multiple performance obligations because the nature of the overall promise in the contract is to provide gathering, processing, transportation, storage, and related services resulting in the delivery, or redelivery in the context of storage services, of pipeline-quality natural gas and NGLs to the customer. As such, revenue is recognized at the daily completion of the integrated package of services as the integrated package represents a single performance obligation. Additionally, certain contracts in our midstream businesses contain fixed or upfront payment terms that result in the deferral of revenues until such services have been performed or such capacity has been made available.
We also earn revenues from offshore crude oil and natural gas gathering and transportation and offshore production handling. These services represent an integrated package of services and are considered a single distinct performance obligation for which we recognize revenues as the services are provided to the customer.
We generally earn a contractually stated fee per unit for the volume of product transported, gathered, processed, or stored. The rate is generally fixed; however, certain contracts contain variable rates that are subject to change based on commodity prices, levels of throughput, or an annual adjustment based on a formulaic cost of service calculation. In addition, we have contracts with contractually stated fees that decline over the contract term, such as declines based on the passage of time periods or achievement of cumulative throughput amounts. For all of our contracts, we allocate the transaction price to each performance obligation based on the relative standalone selling price. The excess of consideration received over revenue recognized results in the deferral of those amounts until future periods based on a units of production or straight-line methodology. Certain of our gas gathering and processing agreements have minimum volume commitments (MVC). If a customer under such an agreement fails to meet its MVC for a specified period (thus not exercising all the contractual rights to gathering and processing services within the specified period, herein referred to as “breakage”), it is obligated to pay a contractually determined fee based upon the shortfall between the actual gathered or processed volumes and the MVC for the period contained in the contract. When we conclude it


Notes (Continued)


is probable that the customer will not exercise all or a portion of its remaining rights, we recognize revenue associated with such breakage amount in proportion to the pattern of exercised rights within the respective MVC period.
Under keep-whole and percent-of-liquids processing contracts, we receive commodity consideration in the form of NGLs and take title to the NGLs at the tailgate of the plant. We recognize such commodity consideration as service revenue based on the market value of the NGLs retained at the time the processing is provided. The current market value, as opposed to the market value at the contract inception date, is used due to a combination of factors, including the fact that the volume, mix, and market price of NGL consideration to be received is unknown at the time of contract execution and is not specified in our contracts with customers. Additionally, product sales revenue (discussed below) is recognized upon the sale of the NGLs to a third party based on the sales price at the time of sale. As a result, revenue is recognized both at the time the processing service is provided in Service revenues – commodity consideration and at the time the NGLs retained as part of the processing service are sold in Product sales. The recognition of revenue related to commodity consideration has the impact of increasing the book value of NGL inventory, resulting in higher cost of goods sold at the time of sale. Given that most inventory is sold in the same period that it is generated, the impact of these transactions is expected to have little impact to operating income.
Product Sales
In the course of providing transportation services to customers of our gas pipeline businesses and gathering and processing services to customers of our midstream businesses, we may receive different quantities of natural gas from customers than the quantities delivered on behalf of those customers. The resulting imbalances are primarily settled through the purchase or sale of natural gas with each customer under terms provided for in our FERC tariffs or gathering and processing agreements, respectively. Revenue is recognized from the sale of natural gas upon settlement of imbalances.
In certain instances, we purchase NGLs, crude oil, and natural gas from our oil and natural gas producer customers. In addition, we retain NGLs as consideration in certain processing arrangements, as discussed above in the Service Revenues - Midstream businesses section. We recognize revenue from the sale of these commodities when the products have been sold and delivered. Our product sales contracts are primarily short-term contracts based on prevailing market rates at the time of the transaction.


Notes (Continued)


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  Total
Northeast
Midstream
 
Atlantic-
Gulf Midstream
 West Midstream Transco Northwest Pipeline Other Intercompany Eliminations  Total
(Millions)
Three Months Ended September 30, 2019Three Months Ended September 30, 2019  
Revenues from contracts with customers:               
Service revenues:               
Non-regulated gathering, processing, transportation, and storage:               
Monetary consideration$310
 $117
 $308
 $
 $
 $
 $(19) $716
Commodity consideration1
 7
 30
 
 
 
 
 38
Regulated interstate natural gas transportation and storage
 
 
 601
 111
 
 (2) 710
Other38
 8
 12
 
 
 
 (5) 53
Total service revenues349
 132
 350
 601
 111
 
 (26) 1,517
Product Sales:               
NGL and natural gas product sales30
 34
 391
 41
 
 
 (28) 468
Total revenues from contracts with customers379
 166
 741
 642
 111
 
 (54) 1,985
Other revenues (1)5
 2
 
 3
 
 7
 (3) 14
Total revenues$384
 $168
 $741
 $645
 $111
 $7
 $(57) $1,999
(Millions)               
Three Months Ended September 30, 2018Three Months Ended September 30, 2018  Three Months Ended September 30, 2018
Revenues from contracts with customers:                              
Service revenues:                              
Non-regulated gathering, processing, transportation, and storage:                              
Monetary consideration$219
 $139
 $409
 $
 $
 $1
 $(19) $749
$219
 $139
 $409
 $
 $
 $1
 $(19) $749
Commodity consideration5
 19
 97
 
 
 
 
 121
5
 19
 97
 
 
 
 
 121
Regulated interstate natural gas transportation and storage
 
 
 457
 110
 
 (1) 566

 
 
 457
 110
 
 (1) 566
Other23
 4
 11
 
 
 
 (4) 34
23
 4
 11
 
 
 
 (4) 34
Total service revenues247
 162
 517
 457
 110
 1
 (24) 1,470
247
 162
 517
 457
 110
 1
 (24) 1,470
Product Sales:                              
NGL and natural gas69
 88
 720
 41
 
 
 (117) 801
69
 88
 720
 41
 
 
 (117) 801
Other
 
 12
 
 
 
 (3) 9

 
 12
 
 
 
 (3) 9
Total product sales69
 88
 732
 41
 
 
 (120) 810
69
 88
 732
 41
 
 
 (120) 810
Total revenues from contracts with customers316
 250
 1,249
 498
 110
 1
 (144) 2,280
316
 250
 1,249
 498
 110
 1
 (144) 2,280
Other revenues (1)6
 5
 3
 3
 
 9
 (3) 23
6
 5
 3
 3
 
 9
 (3) 23
Total revenues$322
 $255
 $1,252
 $501
 $110
 $10
 $(147) $2,303
$322
 $255
 $1,252
 $501
 $110
 $10
 $(147) $2,303
                              
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



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

(1)
Service revenues in our Consolidated StatementRevenues not within the scope of Income includeASC 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 joint ventures and other investments. The leasingequity-method investments, which are reported in Service revenues and the management fees do not constitute revenue from contracts with customers. Product sales in our Consolidated Statement of Income, includeand amounts associated with our derivative contracts, thatwhich are not within the scopereported in Product sales in our Consolidated Statement of ASC 606.Income.




Notes (Continued)




Contract Assets
Our contract assets primarily consist of revenue recognized under contracts containing MVC features whereby management has concluded it is probable there will be a short-fall payment at the end of the current MVC period, which typically follows the calendar year, and that a significant reversal of revenue recognized currently for the future MVC payment will not occur. As a result, our contract assets related to our future MVC payments are generally expected to be collected within the next 12 months and are included within Other current assets and deferred charges in our Consolidated Balance Sheet until such time as the MVC short-fall payments are invoiced to the customer.
The following table presents a reconciliation of our contract assets:
 Three Months Ended 
 September 30,
 Nine Months Ended 
 September 30,
 2019 2018 2019 2018
 (Millions)
Balance at beginning of period$17
 $39
 $4
 $4
Revenue recognized in excess of amounts invoiced14
 17
 53
 53
Minimum volume commitments invoiced
 
 (26) (1)
Balance at end of period$31
 $56
 $31
 $56
 Quarter-to-Date September 30, 2018 Year-to-Date September 30, 2018
 (Millions)
Balance at beginning of period$39
 $4
Revenue recognized in excess of cash received17
 53
Minimum volume commitments invoiced
 (1)
Balance at end of period$56
 $56

Contract Liabilities
Our contract liabilities consist of advance payments primarily from midstream business customers which include construction reimbursements, prepayments, and other billings for which future services are to be provided under the contract. These amounts are deferred until recognized in revenue when the associated performance obligation has been satisfied, which is primarily based on a units of production methodology over the remaining contractual service periods, and are classified as current or noncurrent according to when such amounts are expected to be recognized. Current and noncurrent contract liabilities are included within Accrued liabilities and Regulatory liabilities, deferred income, and other, respectively, in our Consolidated Balance Sheet.
Contracts requiring advance payments and the recognition of contract liabilities are evaluated to determine whether the advance payments provide us with a significant financing benefit. This determination is based on the combined effect of the expected length of time between when we transfer the promised good or service to the customer, when the customer pays for those goods or services, and the prevailing interest rates. We have assessed our contracts for significant financing components and determined that one group of contracts entered into in contemplation of one another for certain capital reimbursements contains a significant financing component. As a result, we recognize noncash interest expense based on the effective interest method and revenue (noncash) is recognized when the underlying asset is placed into service utilizing a units of production or straight-line methodology over the life of the corresponding customer contract.
The following table presents a reconciliation of our contract liabilities:
 Three Months Ended 
 September 30,
 Nine Months Ended 
 September 30,
 2019 2018 2019 2018
 (Millions)
Balance at beginning of period$1,331
 $1,535
 $1,397
 $1,596
Payments received and deferred12
 58
 138
 269
Deconsolidation of Jackalope interest (Note 5)
 
 
 (52)
Significant financing component3
 4
 10
 11
Recognized in revenue(77) (112) (276) (339)
Balance at end of period$1,269
 $1,485
 $1,269
 $1,485
 Quarter-to-Date September 30, 2018 Year-to-Date September 30, 2018
 (Millions)
Balance at beginning of period$1,535
 $1,596
Payments received and deferred62
 280
Deconsolidation of Jackalope interest (Note 3)
 (52)
Recognized in revenue(112) (339)
Balance at end of period$1,485
 $1,485


Notes (Continued)


The following table presents the amount of the contract liabilities balance as of September 30, 2018, expected to be recognized as revenue in each of the next five years as performance obligations are expected to be satisfied:
 (Millions)
2018 (remainder)$191
2019257
2020129
2021110
2022103
2023100
Thereafter595
   Total$1,485

Remaining Performance Obligations
The following table presents the transaction price allocated to the remainingRemaining performance obligations under certain contracts as of September 30, 2018. These primarily include long-term contracts containing MVCs associated with our midstream businesses, fixed payments associated with offshore production handling, and reservation charges on contracted capacity onfor our gas pipeline firm transportation contracts with customers, as well as storage capacity contracts. Amounts included in the table below forcontracts, 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 FERCFederal Energy Regulatory Commission (FERC) tariffs for the life of the related contracts; however, these rates may change based on future tariffs approved by the FERC and the amount and timing of these changes isare not currently known. As a
Our remaining performance obligations exclude variable consideration, including contracts with variable consideration for which we have elected the practical expedient permitted by ASC 606, this table excludes variablefor consideration as well as consideration in contracts that is recognized in revenue as billed. It also excludes consideration received prior to September 30, 2018, that will be recognized in future periods (see above for Contract Liabilities and the expected recognition of those amounts within revenue). As noted above, certainCertain of our contracts contain evergreen and other renewal provisions for periods beyond the initial term of the contract. The remaining performance obligation amounts as of September 30, 2018,2019, do not consider potential future performance obligations for which the renewal has not been exercised. The table below also does not includeexercised and excludes contracts with customers for which the underlying facilities have not received FERC authorization to be placed into service.
 (Millions)
2018 (remainder)$624
20192,465
20202,274
20212,106
20221,830
20231,650
Thereafter12,471
Total$23,420
The table above excludes Consideration received prior to September 30, 2019, that will be recognized in future periods is also excluded from our remaining performance obligations associated withand is instead reflected in contract liabilities.
The following table presents the Atlantic Sunrise expansion project for which we received FERC authorizationamount of the contract liabilities balance as of September 30, 2019, expected to place into service in October 2018. We anticipate annualbe recognized as revenue as performance obligations are satisfied and the transaction price allocated to the remaining performance obligations under certain contracts as of approximately $420 million associated with Atlantic Sunrise over the term of the contracts.September 30, 2019.


Notes (Continued)


 Contract Liabilities Remaining Performance Obligations
 (Millions)
2019 (remainder)$70
 $762
2020167
 3,028
2021126
 2,873
2022112
 2,705
2023103
 2,244
Thereafter691
 19,840
Total$1,269
 $31,452

Accounts Receivable
We do not offer extended payment terms and typically receive payment within one month. We consider receivables past due if full payment is not received by the contractual due date. Interest income related to past due accounts receivable is generally recognized at the time full payment is received or collectability is assured.


Notes (Continued)


The following is a summary of our Trade accounts and other receivablesas it relates to contracts with customers::
 September 30, 2019 December 31, 2018
 (Millions)
Accounts receivable related to revenues from contracts with customers$791
 $858
Other accounts receivable84
 134
Total reflected in Trade accounts and other receivables
$875
 $992
 September 30, 2018 January 1, 2018
 (Millions)
Accounts receivable related to revenues from contracts with customers$795
 $958
Other accounts receivable88
 18
Total reflected in Trade accounts and other receivables
$883
 $976

Impact of Adoption of ASC 606
The following table depicts the impact of the adoption of ASC 606 on our 2018 financial statements. The adjustment to Intangible assets – net of accumulated amortization in the table below relates to the recognition under ASC 606 of contract assets for MVC-related contracts associated with a 2014 acquisition. The recognition of these contract assets resulted in a lower purchase price allocation to intangible assets. The adoption of ASC 606 did not result in adjustments to total operating, investing, or financing cash flows.
 As Reported Adjustments resulting from adoption of ASC 606 Balance without adoption of ASC 606
 (Millions)
Consolidated Statement of Income
Three Months Ended September 30, 2018
Service revenues$1,371
 $5
 $1,376
Service revenues – commodity consideration121
 (121) 
Product sales811
 44
 855
Total revenues2,303
 (72) 2,231
Product costs790
 (48) 742
Processing commodity expenses30
 (30) 
Depreciation and amortization expenses425
 1
 426
Total costs and expenses1,802
 (77) 1,725
Operating income (loss)501
 5
 506
Interest incurred(286) 4
 (282)
Interest capitalized16
 (2) 14
Income (loss) before income taxes390
 7
 397
Provision (benefit) for income taxes190
 1
 191
Net income (loss)200
 6
 206
Less: Net income (loss) attributable to noncontrolling interests71
 (1) 70
Net income (loss) attributable to The Williams Companies, Inc.129
 7
 136
Basic earnings (loss) per common share$0.13
 $0.01
 $0.14
Diluted earnings (loss) per common share$0.13
 $0.01
 $0.14
      
Nine Months Ended September 30, 2018     
Service revenues$4,062
 $16
 $4,078
Service revenues – commodity consideration316
 (316) 
Product sales2,104
 86
 2,190
Total revenues6,482
 (214) 6,268
Product costs2,039
 (143) 1,896
Processing commodity expenses91
 (91) 
Operating and maintenance expenses1,134
 3
 1,137
Depreciation and amortization expenses1,290
 2
 1,292
Total costs and expenses5,080
 (229) 4,851


Notes (Continued)


 As Reported Adjustments resulting from adoption of ASC 606 Balance without adoption of ASC 606
 (Millions)
Operating income (loss)$1,402
 $15
 $1,417
Equity earnings (losses)279
 1
 280
Other investing income (loss) - net74
 (9) 65
Interest incurred(856) 11
 (845)
Interest capitalized38
 (6) 32
Income (loss) before income taxes1,036
 12
 1,048
Provision (benefit) for income taxes297
 1
 298
Net income (loss)739
 11
 750
Net income (loss) attributable to The Williams Companies, Inc.416
 11
 427
Basic earnings (loss) per common share$0.47
 $0.01
 $0.48
Diluted earnings (loss) per common share$0.46
 $0.01
 $0.47
      
Consolidated Statement of Comprehensive Income     
Three Months Ended September 30, 2018     
Net income (loss)$200
 $6
 $206
Comprehensive income (loss)206
 6
 212
Less: Comprehensive income (loss) attributable to noncontrolling interests72
 (1) 71
Comprehensive income (loss) attributable to The Williams Companies, Inc.134
 7
 141
      
Nine Months Ended September 30, 2018     
Net income (loss)$739
 $11
 $750
Comprehensive income (loss)748
 11
 759
Comprehensive income (loss) attributable to The Williams Companies, Inc.427
 11
 438
      
Consolidated Balance Sheet
September 30, 2018
Inventories$153
 $(8) $145
Other current assets and deferred charges242
 (53) 189
Total current assets1,984
 (61) 1,923
Investments7,427
 (1) 7,426
Property, plant, and equipment39,953
 (6) 39,947
Property, plant, and equipment – net28,674
 (6) 28,668
Intangible assets – net of accumulated amortization8,324
 63
 8,387
Regulatory assets, deferred charges, and other744
 (4) 740
Total assets47,153
 (9) 47,144
Deferred income tax liabilities1,648
 27
 1,675
Regulatory liabilities, deferred income, and other4,376
 (159) 4,217
Retained deficit(9,018) 95
 (8,923)
Total stockholders’ equity15,610
 95
 15,705
Noncontrolling interests in consolidated subsidiaries$1,349
 $28
 $1,377
Total equity16,959
 123
 17,082
Total liabilities and equity47,153
 (9) 47,144
      


Notes (Continued)


 As Reported Adjustments resulting from adoption of ASC 606 Balance without adoption of ASC 606
 (Millions)
Consolidated Statement of Changes in Equity     
September 30, 2018     
Adoption of ASC 606$(121) $121
 $
Net income (loss)739
 11
 750
Deconsolidation of subsidiary(267) (9) (276)
Net increase (decrease) in equity784
 123
 907
Balance at September 30, 201816,959
 123
 17,082
Note 34 – Variable Interest Entities
Consolidated VIEs
As of September 30, 2018,2019, 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, connecting its gathering system inwhich will extend from Susquehanna County, Pennsylvania, to the Iroquois Gas Transmission and the Tennessee Gas Pipeline systems. Thesystems in New York. While we previously estimated the total remaining cost of the project is estimated to be approximately $740 million, whichthis 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, andbut in August 2017 the court issued a decision denying in part and dismissing in part Constitution’s appeal. The court expressly declined to rule on Constitution’s argument that the delay in theupholding NYSDEC’s decision on Constitution’s Section 401 application constitutes a waiver of the certification requirement. The court determined that it lacked jurisdiction to address that contention and found that jurisdiction over the waiver issue lies exclusively with the United States Court of Appeals for the District of Columbia Circuit (D.C. Circuit). As to the denial itself, the court determined that NYSDEC’s action was not arbitrary or capricious.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. InBy 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. We filed a request for rehearing of the FERC’s decision, but in July 2018 the FERC denied our request.


Notes (Continued)


The project’s sponsors remain committed to the project, and in September 2018Thereafter, we filed a petition withpetitioned the D.C. Circuit for review of the FERC’s decision. An unfavorable resolution could resultIn 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 impairmentHoopa 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 significant portionClean 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 total $377 million on a consolidated basis at September 30, 2018,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 also 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.
Northeast JV
As a result of the June 2019 sale of a 35 percent interest in the Northeast JV (see Note 2 – Acquisitions), we now 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.


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

(Millions)
Assets (liabilities):


Cash and cash equivalents$90
 $33
Trade accounts and other receivables – net152
 62
Other current assets and deferred charges5
 2
Property, plant, and equipment – net6,167
 2,363
Intangible assets – net of accumulated amortization2,697
 1,177
Regulatory assets, deferred charges, and other13
 
Accounts payable(54) (15)
Accrued liabilities(100) (115)
Regulatory liabilities, deferred income, and other(268) (264)


September 30,
2018

December 31, 2017 (1)


Classification

(Millions)

Assets (liabilities):




Cash and cash equivalents$32
 $881

Cash and cash equivalents
Trade accounts and other receivables  net
57
 972
 Trade accounts and other receivables
Inventories
 113
 Inventories
Other current assets1
 176
 Other current assets and deferred charges
Investments
 6,552
 Investments
Property, plant, and equipment  net
2,398
 27,912

Property, plant, and equipment – net
Intangible assets – net
1,189
 8,790
 Intangible assets – net of accumulated amortization
Regulatory assets, deferred charges, and other noncurrent assets
 507
 Regulatory assets, deferred charges, and other
Accounts payable(16) (957)
Accounts payable
Accrued liabilities including current asset retirement obligations(98) (857) Accrued liabilities
Long-term debt due within one year
 (501) Long-term debt due within one year
Long-term debt
 (15,996) Long-term debt
Deferred income tax liabilities
 (16) Deferred income tax liabilities
Noncurrent asset retirement obligations(104) (944) Regulatory liabilities, deferred income, and other
Regulatory liabilities, deferred income, and other noncurrent liabilities(189) (2,809)
Regulatory liabilities, deferred income, and other

_________________
(1)
Includes WPZ, which was a consolidated VIE at December 31, 2017 (see Note 1 – General, Description of Business, and Basis of Presentation).
Nonconsolidated VIEs
Jackalope
We ownAt December 31, 2018, we owned a50 percent interest in Jackalope, which provides gathering and processing services for the Powder River basin and iswas a VIE due to certain risks shared with customers. Prior to the second quarter of 2018In April 2019, we were the primary beneficiary of Jackalope. During the second quarter of 2018, the scope of Jackalope’s planned future activities changed,


Notes (Continued)


resulting in a VIE reconsideration event. Upon evaluation, we determined that we are no longer the primary beneficiary, most notably due to changes in the activities that most significantly impact Jackalope’s economic performance and our determination that we do not control the power to direct such activities. These activities are primarily related to the capital decision making process. As a result, we deconsolidated Jackalope on June 30, 2018 and now account forsold our interest using the equity method of accounting as we exert significant influence over the financial and operational policies ofin 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, 2018,2019, the carrying value of our equity-method investment in JackalopeBrazos Permian II was $316$197 million. Our maximum exposure to loss is limited to the carrying value of our investment. Jackalope is undertaking an expansion project that is estimated to cost up to approximately $400 million, which will be funded on a proportional basis.
Note 4 – Divestitures and Assets Held for Sale
Divestment of Four Corners Assets
On October 1, 2018, we completed the sale of our natural gas gathering and processing assets in the Four Corners area of New Mexico and Colorado for total consideration of $1.125 billion, subject to customary working capital adjustments, of which a $113 million deposit was received in the third quarter. At September 30, 2018, these assets were designated as held for sale within the West segment. As a result of this sale, we expect to record a gain of approximately $0.6 billion in the fourth quarter of 2018.
The following table presents the carrying amounts of the major classes of the Four Corners area assets and liabilities, which are presented within Assets held for sale and Liabilities held for sale in the Consolidated Balance Sheet:
  Carrying Amount
  September 30, 2018
  (Millions)
Assets:  
Current assets $23
Property, plant, and equipment – net 539
Other noncurrent assets 12
  $574
   
Liabilities:  
Current liabilities $22
Other noncurrent liabilities 23
  $45

The following table presents the results of operations for the Four Corners area:
 Three Months Ended September 30, Nine Months Ended September 30,
 2018 2017 2018 2017
 (Millions)
Income (loss) before income taxes of Four Corners area$25
 $14
 $52
 $31
Income (loss) before income taxes of Four Corners area attributable to The Williams Companies, Inc.23
 10
 43
 23
Other Assets Held for Sale
Certain assets and operations from our former petchem services are designated as held for sale within the Atlantic-Gulf and Other segments as of September 30, 2018. Included as part of the disposal group and presented within Assets held for sale and Liabilities held for sale in the Consolidated Balance Sheet, are Current assets and Property, plant, and equipment - net, of approximately $2 million and $84 million, respectively, and Current liabilities and Noncurrent


Notes (Continued)


liabilities of approximately $1 million and $3 million, respectively. Assets held for sale also includes certain other insignificant assets unrelated to these disposal groups.
Divestment of Geismar Interest
In July 2017, we completed the sale of Williams Olefins, L.L.C., a wholly owned subsidiary which owned our Geismar Interest for total consideration of $2.084 billion in cash. We received a final working capital adjustment of $12 million in October 2017. Upon closing of the sale, we entered into a long-term supply and transportation agreement with the purchaser to provide feedstock to the plant via our Bayou Ethane pipeline system. As a result of this sale, we recorded a gain of $1.095 billion in the third quarter of 2017 in our Other segment. Following this sale, the cash proceeds were used to repay our $850 million term loan. Proceeds were also used to fund a portion of the capital and investment expenditures that were a part of our growth portfolio.
The following table presents the results of operations for the Geismar Interest, excluding the gain noted above:
 Three Months Ended September 30, Nine Months Ended September 30,
 2018 2017 2018 2017
 (Millions)
Income (loss) before income taxes of the Geismar Interest$
 $1
 $
 $26
Income (loss) before income taxes of the Geismar Interest attributable to The Williams Companies, Inc.
 1
 
 19
Note 5 – Investing Activities
RMM Equity-Method InvestmentThe following table presents certain items reflected in Other investing income (loss) – netin the Consolidated Statement of Income:
During the third quarter of 2018, our joint venture, RMM, purchased a natural gas and oil gathering and natural gas processing business in Colorado’s Denver-Julesburg basin. Our initial economic ownership was 40 percent, which is expected to increase to 50 percent as we provide additional capital contributions. At September 30, 2018, our carrying value was $569 million reflecting our 43 percent economic ownership. We are committed to fund up to an additional $177 million to reach 50 percent economic ownership, to the extent RMM needs funding for capital expenditures. We account for this investment under the equity method of accounting.
 Three Months Ended 
 September 30,
 Nine Months Ended 
 September 30,
 2019 2018 2019 2018
 (Millions)
Impairment of equity-method investments (Note 13)$(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 (see Note 3 – Variable Interest Entities).Jackalope. We recorded our interest in Jackalope as an equity-method investment at its estimated fair value, resulting in a deconsolidation gain of $62 million reflected in Other investing income (loss) – net in the Consolidated Statement of Income.


Notes (Continued)


$62 million. We estimated the fair value of our interest to be $310 million using an income approach based on expected future cash flows and an appropriate discount rate (a Level 3 measurement within the fair value hierarchy). The determination of expected future cash flows involved significant assumptions regarding gathering and processing volumes and related capital spending. A 10.9 percent discount rate was utilized and reflected our estimate of the cost of capital as impacted by market conditions and risks associated with the underlying business. The deconsolidated carrying value of the net assets of Jackalope included $47 million of goodwill.
AcquisitionSale of Additional Interests in Appalachia Midstream InvestmentsJackalope
During the first quarter of 2017,In April 2019, we exchanged all ofsold our 50 percent equity-method interest in DBJVJackalope for an increased interest in two natural gas gathering systems that are part of the Appalachia Midstream Investments and $155$485 million in cash. This transaction was recorded basedcash, resulting in a gain on our estimatethe disposition of the fair value of the interests received as we have more insight to this value as we operate the underlying assets. Following this exchange, we have an approximate average 66 percent interest in the Appalachia Midstream Investments. We continue to account for this investment under the equity method of accounting due to the significant participatory rights of our partners such that we do not exercise control. We also$122 million.




Notes (Continued)




sold all of our interest in Ranch Westex JV LLC for $45 million. These transactions resulted in a total gain of $269 million reflected in Other investing income (loss) – net in the Consolidated Statement of Income.
The fair value of the increased interests in the Appalachia Midstream Investments received as consideration was estimated to be $1.1 billion using an income approach based on expected cash flows and an appropriate discount rate (a Level 3 measurement within the fair value hierarchy). The determination of estimated future cash flows involved significant assumptions regarding gathering volumes, rates, and related capital spending. A 9.5 percent discount rate was utilized and reflected our estimate of the cost of capital as impacted by market conditions and risks associated with the underlying business.
Note 6 – Other Income and Expenses
The following table presents, by segment, certain gains or losses reflected in Other (income) expense – net within Costs and expenses other items included in our Consolidated Statement of Income:
 Three Months Ended 
 September 30,
 Nine Months Ended 
 September 30,
 2019 2018 2019 2018
 (Millions)
Selling, general, and administrative expenses       
Other       
Charitable contribution of preferred stock to The Williams Companies Foundation, Inc. (see Note 12)$
 $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)

 Three Months Ended 
 September 30,
 Nine Months Ended 
 September 30,
 2018 2017 2018 2017
 (Millions)
Atlantic-Gulf       
Amortization of regulatory assets associated with asset retirement obligations$8
 $8
 $24
 $25
Accrual of regulatory liability related to overcollection of certain employee expenses5
 5
 16
 16
Project development costs related to Constitution (see Note 3)1
 4
 4
 12
Adjustments to regulatory liability related to Tax Reform
 
 (10) 
Gain on asset retirement(10) (5) (10) (5)
West       
Gains on contract settlements and terminations
 
 
 (15)
Adjustments to regulatory liability related to Tax Reform
 
 (7) 
Regulatory charge per approved rates related to Tax Reform6
 
 18
 
Charge for regulatory liability associated with the decrease in Northwest Pipeline’s estimated deferred state income tax rates following WPZ Merger12
 
 12
 
Other       
Benefit of regulatory asset associated with increase in Transco’s estimated deferred state income tax rate following WPZ Merger(37) 
 (37) 
Gain on sale of Refinery Grade Propylene Splitter
 
 
 (12)
Additional Items
Certain additional items includedIn conjunction with a previously announced organizational realignment and considering asset sales in the Consolidated Statement of Incomerecent years, we are as follows:
Selling, general,evaluating our cost structure and administrativehave implemented a voluntary separation program (VSP) for certain eligible employees. Operating and maintenance expenses for the three and nine months ended September 30, 2018 includes a $352019, reflect charges of $7 million charge associated with a charitable contribution of preferred stock to The Williams Companies Foundation, Inc. (a not-for-profit corporation) within the Other segment. (See Note 11 – Stockholders’ Equity.) and $30 million, respectively, and Selling, general, and administrative expenses for the three and


Notes (Continued)


nine months ended September 30, 2019, reflect charges of $3 million and $23 million, respectively, for estimated severance and related costs, primarily associated with the VSP. The severance and related costs by segment are as follows:
 Three Months Ended September 30, Nine Months Ended September 30,
 2019
 (Millions)
Northeast G&P$(3) $7
Atlantic-Gulf11
 30
West2
 16
Total$10
 $53

Note 7 – Provision (Benefit) for Income Taxes
The Provision (benefit) for income taxes includes:
 Three Months Ended 
 September 30,
 Nine Months Ended 
 September 30,
 2019 2018 2019 2018
 (Millions)
Current:       
Federal$(10) $(19) $(25) $(55)
State
 
 
 1
Foreign1
 
 1
 
 (9) (19) (24) (54)
Deferred:       
Federal73
 188
 225
 312
State13
 21
 43
 39
 86
 209
 268
 351
Provision (benefit) for income taxes$77
 $190
 $244
 $297

The effective income tax rates for the total provision for the three and nine months ended September 30, 2018 also includes $15 million and $19 million, respectively, for WPZ Merger related costs within2019, are greater than the Other segment. Selling, general, and administrative expenses forfederal statutory rate, primarily due to the three and nine months ended September 30, 2017 includes $5 million and $18 million, respectively,effect of severance and other related costs within the Other segment.
Otherstate income (expense) – net below Operating income (loss) includes income of $33 million and $80 million for the three and nine months ended September 30, 2018, respectively, and $17 million and $55 million for


Notes (Continued)


the three and nine months ended September 30, 2017, respectively, for allowance for equity funds used during construction primarily within the Atlantic-Gulf segment. Other income (expense) – net below Operating income (loss) also includes income of $22 million and $31 million for the three and nine months ended September 30, 2018, respectively, and $8 million and $44 million for the three and nine months ended September 30, 2017, respectively of income associated with a regulatory asset related to deferred taxes on equity funds used during construction. These items are reported primarily within the Other segment.
Other income (expense) – net below Operating income (loss) for the nine months ended September 30, 2018, includes a $7 million net loss associated with the March 28, 2018, early retirement of $750 million of 4.875 percent senior unsecured notes that were due in 2024. The net loss within the Other segment reflects $34 million in premiums paid, partially offset by $27 million of unamortized premium. (See Note 10 – Debt and Banking Arrangements.) Other income (expense) – net below Operating income (loss) for the three months ended September 30, 2017 includes a net loss of $3 million associated with the July 3, 2017 early retirement of $1.4 billion of 4.875 percent senior unsecured notes that were due in 2023. The net loss for the July 3, 2017 early retirement reflects $54 million in premiums paid, offset by $51 million of unamortized premium. For the nine months ended September 30, 2017, Other income (expense) – net below Operating income (loss) also includes a net gain of $30 million associated with the February 23, 2017, early retirement of $750 million of 6.125 percent senior unsecured notes that were due in 2022. The net gain within the Other segment reflects $53 million of unamortized premium, partially offset by $23 million in premiums paid.
Note 7 – Provision (Benefit) for Income Taxes
The Provision (benefit) for income taxes includes:
 Three Months Ended 
 September 30,
 Nine Months Ended 
 September 30,
 2018 2017 2018 2017
 (Millions)
Current:       
Federal$(19) $7
 $(55) $10
State
 9
 1
 17
 (19) 16
 (54) 27
Deferred:       
Federal188
 (11) 312
 63
State21
 19
 39
 36
 209
 8
 351
 99
Provision (benefit) for income taxes$190
 $24
 $297
 $126
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.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.



Notes (Continued)


The effective income tax rate for the three months ended September 30, 2017, is less than the federal statutory rate primarily due to the impact of the allocation of income to nontaxable noncontrolling interests, partially offset by the effect of state income taxes, including an $18 million provision related to an increase in the deferred state income tax rate (net of federal benefit).

The effective income tax rate for the nine months ended September 30, 2017, is less than the federal statutory rate. This is primarily due to the impact of the allocation of income to nontaxable noncontrolling interests and releasing a $127 million valuation allowance on a deferred tax asset associated with a capital loss carryover, partially offset by the effect of state income taxes, including an $18 million provision related to an increase in the deferred state income tax rate (net of federal benefit). In 2016, we recorded a valuation allowance on a deferred tax asset associated with a capital loss that was incurred with the sale of our Canadian operations. The sale of the Geismar olefins facility in 2017 (see Note 4 – Divestitures and Assets Held for Sale) generated capital gains sufficient to offset the capital loss carryover, thereby allowing us to reverse the valuation allowance in full.

On December 22, 2017, Tax Reform was enacted. Under the guidance provided by Securities and Exchange Commission Staff Accounting Bulletin No. 118, Income Tax Accounting Implications of the Tax Cuts and Jobs Act, we recorded provisional adjustments related to the impact of Tax Reform in the fourth quarter of 2017. We consider all amounts recorded related to Tax Reform to be reasonable estimates. The amounts recorded continue to be provisional as our interpretation, assessment, and presentation of the impact of the tax law change may be further clarified with additional guidance from regulatory, tax, and accounting authorities. We anticipate that additional guidance from the Internal Revenue Service will be released to guide us in determining what assets are eligible for direct expensing. We are also recording provisional adjustments for valuation allowances associated with losses and credits since, at this time, we cannot assess the impact that the interest expense disallowance will have on our estimated future taxable income. We are not reducing our minimum tax credit for sequestration until we receive further guidance provided by these authorities or other sources.
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,
 2019 2018 2019 2018
 
(Dollars in millions, except per-share
amounts; shares in thousands)
Net income (loss) available to common stockholders$220
 $129
 $724
 $416
Basic weighted-average shares1,212,270
 1,023,587
 1,211,938
 893,706
Effect of dilutive securities:       
Nonvested restricted stock units1,790
 2,387
 1,809
 2,102
Stock options105
 530
 196
 514
Diluted weighted-average shares1,214,165
 1,026,504
 1,213,943
 896,322
Earnings (loss) per common share:       
Basic$.18
 $.13
 $.60
 $.47
Diluted$.18
 $.13
 $.60
 $.46

 Three Months Ended 
 September 30,
 Nine Months Ended 
 September 30,
 2018 2017 2018 2017
 
(Dollars in millions, except per-share
amounts; shares in thousands)
Net income available to common stockholders$129
 $33
 $416
 $487
        
Basic weighted-average shares1,023,587
 826,779
 893,706
 825,925
Effect of dilutive securities:       
Nonvested restricted stock units2,387
 1,889
 2,102
 1,567
Stock options530
 700
 514
 658
Diluted weighted-average shares1,026,504
 829,368
 896,322
 828,150
        
Earnings per common share:       
Basic$.13
 $.04
 $.47
 $.59
Diluted$.13
 $.04
 $.46
 $.59




Notes (Continued)


Note 9 – Employee Benefit Plans
Net periodic benefit cost (credit) is as follows:

Pension Benefits

Three Months Ended 
 September 30,

Nine Months Ended 
 September 30,

2019
2018
2019
2018

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






Service cost$11

$12

$33

$37
Interest cost13

12

38

35
Expected return on plan assets(15)
(16)
(46)
(47)
Amortization of net actuarial loss3

6

11

17
Net actuarial loss from settlements1

1

1

2
Net periodic benefit cost (credit)$13

$15

$37

$44

Pension Benefits

Three Months Ended 
 September 30,

Nine Months Ended 
 September 30,

2018
2017
2018
2017

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






Service cost$12

$13

$37

$38
Interest cost12

15

35

44
Expected return on plan assets(16)
(21)
(47)
(62)
Amortization of net actuarial loss6

6

17

20
Net actuarial loss from settlements1



2


Net periodic benefit cost (credit)$15

$13

$44

$40

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

 Other Postretirement Benefits
 Three Months Ended 
 September 30,
 Nine Months Ended 
 September 30,
 2018 2017 2018 2017
 (Millions)
Components of net periodic benefit cost (credit):       
Service cost$1
 $
 $1
 $1
Interest cost1
 2
 5
 6
Expected return on plan assets(2) (3) (8) (9)
Amortization of prior service credit
 (3) (1) (10)
Reclassification to regulatory liability
 1
 1
 3
Net periodic benefit cost (credit)$
 $(3) $(2) $(9)
The components of Net periodic benefit cost (credit) other than the Service cost component are included in Other income (expense) – net below Operating income (loss) in the Consolidated Statement of Income.


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 amountsamount of Amortization of prior service credit recognized in regulatory liabilities were $2 million for the three months ended September 30, 2017, andwas $1 million and $6 million for the nine months ended September 30, 2018 and 2017, respectively.2018.
During the nine months ended September 30, 20182019, we contributed $87$63 million to our pension plans and $4 million to our other postretirement benefit plans. We presently anticipate making additional contributions of approximately $1 million to our pension plans and approximately $2$1 million to our other postretirement benefit plans in the remainder of 2018.2019.
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 1011 – Debt and Banking Arrangements
Long-Term Debt
Issuances and retirementsRetirements
On August 24, 2018, Northwest Pipeline issued $250We retired approximately $32 million of 4 percent senior unsecured notes to investors in a private debt placement. The notes are an additional issuance of Northwest Pipeline’s existing 4 percent senior unsecured


Notes (Continued)


notes due 2027. As part of the issuance, Northwest Pipeline entered into a registration rights agreement with the initial purchasers of the unsecured notes. Northwest Pipeline 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. Northwest Pipeline is required to provide a shelf registration statement to cover resales of the notes under certain circumstances. If Northwest Pipeline 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.
Northwest Pipeline retired $250 million of 6.057.625 percent senior unsecured notes that matured on JuneJuly 15, 2018.
On March 5, 2018, WPZ completed a public offering of $800 million of 4.85 percent senior unsecured notes due 2048. WPZ used the net proceeds for general partnership purposes, primarily the March 28, 2018 repayment of $750 million of 4.875 percent senior unsecured notes that were due in 2024.
On March 15, 2018, Transco issued $400 million of 4 percent senior unsecured notes due 2028 and $600 million of 4.6 percent senior unsecured notes due 2048 to investors in a private debt placement. Transco used the net proceeds to retire $250 million of 6.05 percent senior unsecured notes that matured on June 15, 2018, and for general corporate purposes, including the funding of capital expenditures. In September 2018, Transco completed an exchange of these notes for substantially identical new notes that are registered under the Securities Act of 1933, as amended.
Other financing obligations
During the first three quarters of 2018, Transco received an additional $29 million of funding from a co-owner related to the construction of the Dalton expansion project. This additional funding is reflected as Long-term debt in the Consolidated Balance Sheet.
During the construction of the Atlantic Sunrise project, Transco received funding from a partner for its proportionate share of construction costs related to an undivided ownership interest in certain parts of the project. Amounts received were recorded within noncurrent liabilities and 100 percent of the costs associated with construction were capitalized in our Consolidated Balance Sheet. Upon placing the project in service during October 2018, Transco began utilizing this partner’s undivided interest in the lateral, including the associated pipeline capacity, and expects to reclassify approximately $790 million of funding previously received from its partner from noncurrent liabilities to debt to reflect the financing obligation payable to its partner over an expected term of 20 years. As this transaction did not meet the criteria for sale leaseback accounting due to our continued involvement, it will be accounted for as a financing arrangement over the course of the capacity agreement.2019.
Commercial Paper Program
On August 10, 2018, following the consummation of the WPZ Merger, WPZ’s $3 billionAt September 30, 2019, 0 commercial paper program was discontinued and we entered into a newoutstanding under our $4 billion commercial paper program. The maturities of the commercial paper notes vary but may not exceed 397 days from the date of issuance. The commercial paper notes are sold under customary terms in the commercial paper market and are issued at a discount from par, or, alternatively, are sold at par and bear varying interest rates on a fixed or floating basis. The net proceeds of issuances of the commercial paper notes are expected to be used to fund planned capital expenditures and for other general corporate purposes. At September 30, 2018, approximately $824 million of Commercial paper at a weighted-average interest rate of 2.73 percent was outstanding. At October 30, 2018, no commercial paper was outstanding.




Notes (Continued)




Credit Facilities
September 30, 2018September 30, 2019
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
  14
 
(1)In managing our available liquidity, we do not expect a maximum outstanding amount in excess of the capacity of our credit facility inclusive of any outstanding amounts under our commercial paper program.
Revolving credit facility
On July 13, 2018, we along with Transco and Northwest Pipeline, the lenders named therein, and an administrative agent entered into a new credit agreement (Credit Agreement) with aggregate commitments available of $4.5 billion, with up to an additional $500 million increase in aggregate commitments available under certain circumstances. On August 10, 2018, following the completion of the WPZ Merger, the Credit Agreement became effective and we terminated both our and WPZ’s existing credit facilities. The maturity date of the new credit facility is August 10, 2023. However, the co-borrowers may request up to two extensions of the maturity date each for an additional one-year period to allow a maturity date as late as August 10, 2025, under certain circumstances. The Credit Agreement allows for swing line loans up to an aggregate of $200 million, subject to available capacity under the new credit facility, and letters of credit commitments of $1 billion. Transco and Northwest Pipeline are each able to borrow up to $500 million under this credit facility to the extent not otherwise utilized by the other co-borrowers.
The Credit Agreement contains the following terms and conditions:
Various covenants may limit, among other things, a borrower's and its material subsidiaries' ability to grant certain liens supporting indebtedness, merge or consolidate, sell all or substantially all of its assets, make certain distributions during an event of default, and enter into certain restrictive agreements.
If an event of default with respect to a borrower occurs under the credit facility, the lenders will be able to terminate the commitments and accelerate the maturity of the loans and exercise other rights and remedies.
Other than swing line loans, each time funds are borrowed, the applicable borrower may choose from two methods of calculating interest: a fluctuating base rate equal to Citibank N.A.'s adjusted base rate plus an applicable margin or a periodic fixed rate equal to the London Interbank Offered Rate plus an applicable margin. We are required to pay a commitment fee based on the unused portion of the credit facility. The applicable margin and the commitment fee are determined by reference to a pricing schedule based on the applicable borrower’s senior unsecured long-term debt ratings.
Significant financial covenants under the Credit Agreement require the ratio of debt to EBITDA (earnings before interest, taxes, depreciation, and amortization), each as defined in the credit facility, to be no greater than:
5.75 to 1 for each fiscal quarter end through June 30, 2019;
5.5 to 1 for the fiscal quarters ending September 30, 2019, and December 31, 2019;
5.0 to 1 for the fiscal quarter ending March 31, 2020, and each subsequent fiscal quarter end, except for the fiscal quarter and the two following fiscal quarters in which one or more acquisitions with a total aggregate purchase price of $25 million or more has been executed, in which case the ratio of debt to EBITDA is to be no greater than 5.5 to 1.


Notes (Continued)


The ratio of debt to capitalization (defined as net worth plus debt) must be no greater than 65 percent for each of Transco and Northwest Pipeline.
At September 30, 2018, we are in compliance with these covenants.
Note 1112 – Stockholders’ Equity
Issuance of Preferred Shares
In July 2018, through a wholly owned subsidiary, we contributed 35,000 shares of newly issued Series B Non-Voting Perpetual 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. We paid dividends totaling $0.4 million on the shares of Preferred Stock in September 2018. Our certificate of incorporation authorizes 30 million shares of Preferred Stock, $1 par value per share.shares.
AOCI
The following table presents the changes in Accumulated other comprehensive income (loss)(AOCI) AOCI by component, net of income taxes:
 
Cash
Flow
Hedges
 
Foreign
Currency
Translation
 
Pension and
Other Postretirement
Benefits
 Total
 (Millions)
Balance at December 31, 2018$(2) $(1) $(267) $(270)
Other comprehensive income (loss) before reclassifications

 
 (5) (5)
Amounts reclassified from accumulated other comprehensive income (loss)

 
 9
 9
Other comprehensive income (loss)
 
 4
 4
Balance at September 30, 2019$(2) $(1) $(263) $(266)

 
Cash
Flow
Hedges
 
Foreign
Currency
Translation
 
Pension and
Other Postretirement
Benefits
 Total
 (Millions)
Balance at December 31, 2017$(2) $(1) $(235) $(238)
Adoption of ASU 2018-02 (Note 1)
 
 (61) (61)
WPZ Merger (Note 1)(3) 
 
 (3)
Other comprehensive income (loss):       
Other comprehensive income (loss) before reclassifications
(14) 
 4
 (10)
Amounts reclassified from accumulated other comprehensive income (loss)
7
 
 14
 21
Other comprehensive income (loss)(7) 
 18
 11
Balance at September 30, 2018$(12) $(1) $(278) $(291)


Notes (Continued)


Reclassifications out of AOCI are presented in the following table by component for the nine months ended September 30, 2018:2019:
Component Reclassifications Classification
  (Millions)  
Pension and other postretirement benefits:    
Amortization of actuarial (gain) loss and net actuarial loss from settlements included in net periodic benefit cost (credit) $12
 Note 9 – Employee Benefit Plans
Income tax benefit (3) Provision (benefit) for income taxes
Reclassifications during the period $9
  

Component Reclassifications Classification
  (Millions)  
Cash flow hedges:    
Energy commodity contracts $13
 Product sales
     
Pension and other postretirement benefits:    
Amortization of actuarial (gain) loss and net actuarial loss from settlements included in net periodic benefit cost (credit) 19
 Note 9 – Employee Benefit Plans
Total before tax 32
  
Income tax benefit (8) Provision (benefit) for income taxes
Net of income tax 24
  
Noncontrolling interest (3) Net income (loss) attributable to noncontrolling interests
Reclassifications during the period $21
  




Notes (Continued)




Note 1213 – 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, commercial paper,margin deposits, and accounts payable approximate fair value because of the short-term nature of these instruments. Therefore, these assets and liabilities are not presented in the following table.
      Fair Value Measurements Using
  
Carrying
Amount
 
Fair
Value
 
Quoted
Prices In
Active
Markets for
Identical
Assets
(Level 1)
 
Significant
Other
Observable
Inputs
(Level 2)
 
Significant
Unobservable
Inputs
(Level 3)
  (Millions)
Assets (liabilities) at September 30, 2019:          
Measured on a recurring basis:          
ARO Trust investments $187
 $187
 $187
 $
 $
Energy derivatives assets not designated as hedging instruments 4
 4
 4
 
 
Energy derivatives liabilities not designated as hedging instruments (5) (5) (2) 
 (3)
Additional disclosures:          
Long-term debt, including current portion (22,257) (25,234) 
 (25,234) 
Guarantees (42) (29) 
 (13) (16)
           
Assets (liabilities) at December 31, 2018:          
Measured on a recurring basis:          
ARO Trust investments $150
 $150
 $150
 $
 $
Energy derivatives assets not designated as hedging instruments 3
 3
 3
 
 
Energy derivatives liabilities not designated as hedging instruments (7) (7) (4) 
 (3)
Additional disclosures:          
Long-term debt, including current portion (22,414) (23,330) 
 (23,330) 
Guarantees (43) (30) 
 (14) (16)
      Fair Value Measurements Using
  
Carrying
Amount
 
Fair
Value
 
Quoted
Prices In
Active
Markets for
Identical
Assets
(Level 1)
 
Significant
Other
Observable
Inputs
(Level 2)
 
Significant
Unobservable
Inputs
(Level 3)
  (Millions)
Assets (liabilities) at September 30, 2018:          
Measured on a recurring basis:          
ARO Trust investments $157
 $157
 $157
 $
 $
Energy derivatives assets not designated as hedging instruments 6
 6
 6
 
 
Energy derivatives liabilities designated as hedging instruments (14) (14) (13) (1) 
Energy derivatives liabilities not designated as hedging instruments (9) (9) (6) 
 (3)
Additional disclosures:          
Other receivables 21
 21
 21
 
 
Long-term debt, including current portion (21,442) (22,532) 
 (22,532) 
Guarantees (43) (30) 
 (14) (16)
           
Assets (liabilities) at December 31, 2017:          
Measured on a recurring basis:          
ARO Trust investments $135
 $135
 $135
 $
 $
Energy derivatives liabilities designated as hedging instruments (3) (3) (2) (1) 
Energy derivatives liabilities not designated as hedging instruments (3) (3) 
 
 (3)
Additional disclosures:          
Other receivables 7
 7
 7
 
 
Long-term debt, including current portion (20,935) (23,005) 
 (23,005) 
Guarantees (43) (30) 
 (14) (16)

Fair Value Methods
We use the following methods and assumptions in estimating the fair value of our financial instruments:
Assets and liabilities measured at fair value on a recurring basis
ARO Trust investments: Transco deposits a portion of its collected rates, pursuant to its rate case settlement, into an external trust (ARO Trust) that is specifically designated to fund future asset retirement obligations (ARO). The ARO Trust invests in a portfolio of actively traded mutual funds that are measured at fair value on a recurring basis based on quoted prices in an active market and is reported in Regulatory assets, deferred charges, and other in the Consolidated Balance Sheet. Both realized and unrealized gains and losses are ultimately recorded as regulatory assets or liabilities.
Energy derivatives: Energy derivatives include commodity-based exchange-traded contracts and over-the-counter contracts, which consist of physical forwards, futures, and swaps that are measured at fair value on a recurring basis. The fair value amounts are presented on a gross basis and do not reflect the netting of asset and liability positions




Notes (Continued)




permitted under the terms of our master netting arrangements. Further, the amounts do not include cash held on deposit in margin accounts that we have received or remitted to collateralize certain derivative positions. Energy derivatives assets are reported in Other current assets and deferred charges and Regulatory assets, deferred charges, and other in the Consolidated Balance Sheet. Energy derivatives liabilities are reported in Accrued liabilities and Regulatory liabilities, deferred income, and other in the Consolidated Balance Sheet.
Reclassifications of fair value between Level 1, Level 2, and Level 3 of the fair value hierarchy, if applicable, are made at the end of each quarter. No transfers between Level 1 and Level 2 occurred during the nine months ended September 30, 20182019 or 20172018.
Additional fair value disclosures
Other receivables:  Other receivables consist of margin deposits, which are reported in Other current assets and deferred charges in the Consolidated Balance Sheet. The disclosed fair value of our margin deposits is considered to approximate the carrying value generally due to the short-term nature of these items.
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 $29$28 millionat September 30, 2018.2019. 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 no0 carrying value. We have never been called upon to perform under these indemnifications and have no current expectation of a future claim.


Notes (Continued)


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


Notes (Continued)


         Impairments
         Nine Months Ended September 30,
 Classification Segment Date of Measurement Fair Value 2018 2017
       (Millions)
Certain idle pipeline assets (1)Property, plant, and equipment – net Other June 30, 2018 $25
 $66
  
Certain gathering operations (2)
Property, plant, and equipment – net and Intangible assets - net of accumulated amortization
 West September 30, 2017 439
   $1,019
Certain gathering operations (3)
Property, plant, and equipment – net and Intangible assets - net of accumulated amortization
 Northeast G&P September 30, 2017 21
   115
Certain NGL pipeline (4)Property, plant, and equipment – net Other September 30, 2017 32
   68
Certain olefins pipeline project (5)Property, plant, and equipment – net Other June 30, 2017 18
   23
Fair value measurements of certain assets        66
 1,225
Other impairments and write-downs (6)        
 11
Impairment of certain assets        $66
 $1,236
            
        Impairments
        Nine Months Ended 
 September 30,
  Segment Date of Measurement Fair Value 2019 2018
      (Millions)
Impairment of certain assets:          
Certain gathering assets (1) West June 30, 2019 $40
 $59
  
Certain idle gathering assets (2) West March 31, 2019 
 12
  
Certain idle pipeline assets (3) Other June 30, 2018 25
 
 $66
Other impairments and write-downs       5
 
Impairment of certain assets       $76
 $66
Impairment of equity-method investments:          
Laurel Mountain (4) Northeast G&P September 30, 2019 $242
 $79
  
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
  
Other       (1)  
Impairment of equity-method investments       $186
  
_______________
(1)
Relates to a gas gathering system in the Eagle Ford 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 of the Property, plant, and equipment – net was determined by a market approach incorporating information derived from bids received for these assets, which are currently beingwe marketed for sale together with certain other assets. These inputs resultresulted in a fair value measurement within Level 2 of the fair value hierarchy. We sold these assets in the fourth quarter of 2018.


(2)(4)
Relates to certaina gas gathering operationssystem in the Mid-Continent region. During the third quarter of 2017, we received solicitationsMarcellus region that was adversely impacted by lower sustained forward natural gas price expectations and engagedchanges in negotiations for the sale of certain of these assets which led to our impairment evaluation.expected producer activity. The estimated fair value was determined using an income approach and incorporated market inputs based on ongoing negotiations for a potential sale of a portion of the underlying assets. For the income approach, weapproach. We utilized a discount rate of 10.2 percent reflecting an estimated costin our analysis. This impairment is reported in Other investing income (loss) – net in the Consolidated Statement of capital and risks associated with the underlying assets.Income.


(3)(5)
Relates to a certain gathering operationssystem held in Appalachia Midstream Investments that was adversely impacted by changes in the Marcellus South region resulting fromtiming of expected producer activity. The estimated fair value was determined using an anticipated declineincome approach. We utilized a discount rate of 9.0 percent in future volumes followingour analysis. This impairment is reported in Other investing income (loss) – net in the Consolidated Statement of Income.



Notes (Continued)


(6)
The estimated fair value of Pennant Midstream, LLC (“Pennant”) was determined by a third-quarter 2017 shut-in bymarket approach based on recent observable third-party transactions. These inputs resulted in a fair value measurement within Level 2 of the primary producer. fair value hierarchy. This impairment is reported in Other investing income (loss) – net in the Consolidated Statement of Income.

(7)
The estimated fair value was determined by the income approach utilizing a discount rate of 11.1 percent, reflecting an estimated cost of capital and risks associated with the underlying assets.

(4)Relates to an NGL pipeline near the Houston Ship Channel region which we anticipate will be underutilized for the foreseeable future. The estimated fair value was primarily determined by using a market approach based on our analysis of observable inputs in the principal market.




Notes (Continued)


(5)Relates primarily to project development costs associated with an olefins pipeline project intransaction price for the Gulf Coast region, the likelihood of completion of which is now considered remote. The estimated fair valuepurchase of the remaining pipeinterest in UEOM as finalized just prior to the signing and equipment consideredclosing of the acquisition in March 2019 (see Note 2 – Acquisitions). These inputs resulted in a market approach based on our analysisfair value measurement within Level 2 of observable inputs in the principal market, as well as an estimate of replacement cost.

(6)Reflects multiple individually insignificant impairments and write-downs of other certain assets that may no longer be in use or are surplus in nature for which the fair value was determined to be lower thanhierarchy. This impairment is reported in Other investing income (loss) - net in the carrying value.Consolidated Statement of Income.
Note 1314 – 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 NevadaKansas 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.
Because of the uncertainty around the remaining pending unresolved issues, we cannot reasonably estimate a range of potential exposure at this time. However, it is reasonably possible that the ultimate resolution of these actions and our related indemnification obligation could result in a potential loss that may be material to our results of operations. In connection with this indemnification, we have an accrued liability balance associated with this matter, and as a result, have exposure to future developments.
Alaska Refinery Contamination Litigation
We are involved in litigation arising from our ownership and operation of the North Pole Refinery in North Pole, Alaska, from 1980 until 2004, through our wholly owned subsidiaries, Williams Alaska Petroleum Inc. (WAPI) and MAPCO Inc. We sold the refinery to Flint Hills Resources Alaska, LLC (FHRA), a subsidiary of Koch Industries, Inc., in 2004. The litigation involves three cases, with filing dates ranging from 2010 to 2014. The actions 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. 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


Notes (Continued)


the James West case and those of the State of Alaska and North Pole. ASeveral trial dates encompassing all three cases was originallyhave been scheduled to commenceand stricken. Trial commenced in May 2017 but has been rescheduled for MarchOctober 2019. Due to the ongoing assessment of the level and extent 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 or North Pole at this time. We currently estimate that our reasonably possible loss exposure to FHRA could range from an insignificant amount up to $32 million, although uncertainties inherent in the litigation process, expert evaluations, and jury dynamics might cause our exposure to exceed that amount.
Independent of the litigation matter described in the preceding paragraphs, in 2013, the Alaska Department of Environmental Conservation indicated that it views FHRA and us as responsible parties, and that it intends to enter a compliance order to address the environmental remediation of sulfolane and other possible contaminants including cleanup work outside the refinery’s boundaries. To date, no compliance order has been issued. Due to the ongoing assessment of the level and extent of sulfolane contamination, the ultimate cost of remediation and division of costs among the potentially responsible parties, and the previously described separate litigation, we are unable to estimate a range of exposure at this time.
Royalty Matters
Certain of our customers, including one major customer, have been named in various lawsuits alleging underpayment of royalties and claiming, among other things, violations of anti-trust laws and the Racketeer Influenced and Corrupt Organizations Act. We have also been named as a defendant in certain of these cases filed in Pennsylvania based on allegations that we improperly participated with that major customer in causing the alleged royalty underpayments. We believe that the claims asserted are subject to indemnity obligations owed to us by that major customer. That customer has reached a tentative settlement to resolve substantially all Pennsylvania royalty cases pending, which settlement would apply to both the customer and us. The settlement as reported would not require any contribution from us.
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


Notes (Continued)


remand to pursue damages. On March 23, 2017, the Supreme Court of Delaware affirmed the Court of Chancery’s ruling. On March 30, 2017, we filed a motion for reargument with the Supreme Court of Delaware, which was denied on April 5, 2017.
On September 16, 2016, we filed an amended complaint with the Court of Chancery seeking damages for breaches of the ETE Merger Agreement by defendants. On September 23, 2016, Energy Transfer filed a second amended and supplemental affirmative defenses and verified counterclaim with the Court of Chancery seeking, among other things, payment of the $1.48 billion termination fee due to our alleged breaches of the ETE Merger Agreement. On December 1, 2017, the court granted our motion to dismiss certain of Energy Transfer’s counterclaims, including its claim seeking payment of the $1.48 billion termination fee. On December 8, 2017, Energy Transfer filed a motion for reargument, which the Court of Chancery denied on April 16, 2018. The Court of Chancery previously scheduled trial for May 20 through May 24, 2019.2019; the court struck the trial setting and has re-scheduled trial for June 8 through June 11 and June 15, 2020.
Former Olefins Business
SABIC Petrochemicals, the other interest owner in our former Geismar, Louisiana, olefins facility we sold in July 2017, is seeking recovery from us for losses it allegedly suffered, including its share of personal injury settlements in which it was a co-defendant, as well as amounts related to lost income, defense costs, and property damage associated with an explosion and fire at the plant in June 2013. Due to the complexity of the various claims and available defenses, we are unable to reliably estimate any reasonably possible losses at this time. Trial began on October 14, 2019, as scheduled, but on October 21, 2019, the Court declared a mistrial due to the conduct of an officer of SABIC Petrochemicals and SABIC Petrochemicals’ expert witness. No new trial date has been set. We believe that certain losses incurred arising directly from the explosion and fire will be covered by our general liability policy and any uninsured losses are not expected to be material.
Other
On August 31, 2018, Transco submitted to the FERC a general rate filing principally designed to recover increased costs and to comply with the terms of the settlement in its prior rate proceeding. The new rates became effective March 1, 2019, subject to refund and the outcome of a hearing. In October 2019, we reached an agreement on the terms of a settlement with the participants that would resolve all issues in the rate case without the need for a hearing. Final resolution of the rate case is subject to the filing of a formal stipulation and agreement with, and subsequent approval by, the FERC. As of September 30, 2019, we have provided a $131 million reserve for rate refunds which we believe is adequate for any refunds that may be required.
Environmental Matters
We are a participant in certain environmental activities in various stages including assessment studies, cleanup operations, and/or remedial processes at certain sites, some of which we currently do not own. We are monitoring these sites in a coordinated effort with other potentially responsible parties, the U.S. Environmental Protection Agency (EPA), or other governmental authorities. We are jointly and severally liable along with unrelated third parties in some of these activities and solely responsible in others. Certain of our subsidiaries have been identified as potentially responsible parties at various Superfund and state waste disposal sites. In addition, these subsidiaries have incurred, or are alleged to have incurred, various other hazardous materials removal or remediation obligations under environmental laws. As of September 30, 2018,2019, we have accrued liabilities totaling $36$33 million for these matters, as discussed below. Estimates of the most likely costs of cleanup are generally based on completed assessment studies, preliminary results of studies,


Notes (Continued)


or our experience with other similar cleanup operations. At September 30, 2018,2019, 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 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. On October 1, 2015, theThe EPA previously issued its rule regarding National Ambient Air Quality Standards for ground-level ozone, setting a stricter standard of 70 parts per billion.ozone. We are monitoring the rule’s implementation as the reductionit 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 September 30, 20182019, we have accrued liabilities of $7$5 million for these costs. We expect that these costs will be recoverable through rates.
We also accrue environmental remediation costs for natural gas underground storage facilities, primarily related to soil and groundwater contamination. At September 30, 20182019, we have accrued liabilities totaling $7$8 million for these costs.


Notes (Continued)


Former operations including operations classified as discontinued
We have potential obligations in connection with assets and businesses we no longer operate. These potential obligations include remediation activities at the direction of federal and state environmental authorities and the indemnification of the purchasers of certain of these assets and businesses for environmental and other liabilities existing at the time the sale was consummated. Our responsibilities relate to the operations of the assets and businesses described below.
Former agricultural fertilizer and chemical operations and former retail petroleum and refining operations;
Former petroleum products and natural gas pipelines;
Former petroleum refining facilities;
Former exploration and production and mining operations;
Former electricity and natural gas marketing and trading operations.
At September 30, 20182019, we have accrued environmental liabilities of $22$20 million related to these matters.
Other Divestiture Indemnifications
Pursuant to various purchase and sale agreements relating to divested businesses and assets, we have indemnified certain purchasers against liabilities that they may incur with respect to the businesses and assets acquired from us. The indemnities provided to the purchasers are customary in sale transactions and are contingent upon the purchasers incurring liabilities that are not otherwise recoverable from third parties. The indemnities generally relate to breach of


Notes (Continued)


warranties, tax, historic litigation, personal injury, property damage, environmental matters, right of way, and other representations that we have provided.
At September 30, 20182019, 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 1415 – Segment Disclosures
Our reportable segments are 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


Notes (Continued)


measuring performance and allocating resources among our reportable segments. Intersegment revenues primarily represent the sale of NGLs from our natural gas processing plants to our marketing business.
We define Modified EBITDA as follows:
Net income (loss) before:
Income (loss) from discontinued operations;
Provision (benefit) for income taxes;
Interest incurred, net of interest capitalized;
Equity earnings (losses);
Gain on remeasurement of equity-method investment;
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.

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



Notes (Continued)




The following table reflects the reconciliation of Segment revenues to Total revenues as reported in the Consolidated Statement of Income and Total assets by reportable segment.
 Northeast G&P Atlantic-Gulf West Other Eliminations Total
 (Millions)
Three Months Ended September 30, 2019
Segment revenues:           
Service revenues           
External$340
 $718
 $433
 $4
 $
 $1,495
Internal13
 13
 
 3
 (29) 
Total service revenues353
 731
 433
 7
 (29) 1,495
Total service revenues – commodity consideration1
 7
 30
 
 
 38
Product sales           
External22
 66
 378
 
 
 466
Internal8
 10
 11
 
 (29) 
Total product sales30
 76
 389
 
 (29) 466
Total revenues$384
 $814
 $852
 $7
 $(58) $1,999
            
Three Months Ended September 30, 2018
Segment revenues:           
Service revenues           
External$236
 $595
 $533
 $7
 $
 $1,371
Internal11
 12
 
 3
 (26) 
Total service revenues247
 607
 533
 10
 (26) 1,371
Total service revenues – commodity consideration6
 18
 97
 
 
 121
Product sales           
External59
 46
 706
 
 
 811
Internal10
 85
 26
 
 (121) 
Total product sales69
 131
 732
 
 (121) 811
Total revenues$322
 $756
 $1,362
 $10
 $(147) $2,303
            
Nine Months Ended September 30, 2019
Segment revenues:           
Service revenues           
External$925
 $2,102
 $1,384
 $13
 $
 $4,424
Internal34
 36
 
 9
 (79) 
Total service revenues959
 2,138
 1,384
 22
 (79) 4,424
Total service revenues – commodity consideration9
 33
 116
 
 
 158
Product sales           
External87
 169
 1,256
 
 
 1,512
Internal27
 57
 46
 
 (130) 
Total product sales114
 226
 1,302
 
 (130) 1,512
Total revenues$1,082
 $2,397
 $2,802
 $22
 $(209) $6,094
            
            
 Northeast G&P Atlantic-Gulf West Other (1) Eliminations (2) Total
 (Millions)
Three Months Ended September 30, 2018
Segment revenues:           
Service revenues           
External$236
 $595
 $533
 $7
 $
 $1,371
Internal11
 12
 
 3
 (26) 
Total service revenues247
 607
 533
 10
 (26) 1,371
Total service revenues – commodity consideration (external only)6
 18
 97
 
 
 121
Product sales           
External59
 46
 706
 
 
 811
Internal10
 85
 26
 
 (121) 
Total product sales69
 131
 732
 
 (121) 811
Total revenues$322
 $756
 $1,362
 $10
 $(147) $2,303
            
Three Months Ended September 30, 2017
Segment revenues:           
Service revenues           
External$207
 $553
 $544
 $6
 $
 $1,310
Internal7
 11
 
 3
 (21) 
Total service revenues214
 564
 544
 9
 (21) 1,310
Product sales           
External56
 57
 459
 9
 
 581
Internal5
 49
 26
 
 (80) 
Total product sales61
 106
 485
 9
 (80) 581
Total revenues$275
 $670
 $1,029
 $18
 $(101) $1,891
            
Nine Months Ended September 30, 2018
Segment revenues:           
Service revenues           
External$677
 $1,769
 $1,599
 $17
 $
 $4,062
Internal30
 37
 
 9
 (76) 
Total service revenues707
 1,806
 1,599
 26
 (76) 4,062
Total service revenues – commodity consideration (external only)14
 45
 257
 
 
 316
Product sales           
External214
 131
 1,759
 
 
 2,104
Internal28
 198
 63
 
 (289) 
Total product sales242
 329
 1,822
 
 (289) 2,104
Total revenues$963
 $2,180
 $3,678
 $26
 $(365) $6,482
            





Notes (Continued)




 Northeast G&P Atlantic-Gulf West Other Eliminations Total
 (Millions)
Nine Months Ended September 30, 2018
Segment revenues:           
Service revenues           
External$677
 $1,769
 $1,599
 $17
 $
 $4,062
Internal30
 37
 
 9
 (76) 
Total service revenues707
 1,806
 1,599
 26
 (76) 4,062
Total service revenues – commodity consideration14
 45
 257
 
 
 316
Product sales           
External214
 131
 1,759
 
 
 2,104
Internal28
 198
 63
 
 (289) 
Total product sales242
 329
 1,822
 
 (289) 2,104
Total revenues$963
 $2,180
 $3,678
 $26
 $(365) $6,482
            
September 30, 2019           
Total assets$15,445
 $16,888
 $13,550
 $928
 $(530) $46,281
December 31, 2018           
Total assets$14,526
 $16,346
 $13,948
 $849
 $(367) $45,302

 Northeast G&P Atlantic-Gulf West Other (1) Eliminations (2) Total
 (Millions)
Nine Months Ended September 30, 2017
Segment revenues:           
Service revenues           
External$621
 $1,620
 $1,589
 $23
 $
 $3,853
Internal27
 27
 
 9
 (63) 
Total service revenues648
 1,647
 1,589
 32
 (63) 3,853
Product sales           
External159
 201
 1,233
 357
 
 1,950
Internal22
 164
 143
 8
 (337) 
Total product sales181
 365
 1,376
 365
 (337) 1,950
Total revenues$829
 $2,012
 $2,965
 $397
 $(400) $5,803
            
September 30, 2018           
Total assets$14,482
 $16,361
 $16,169
 $748
 $(607) $47,153
December 31, 2017           
Total assets$14,397
 $14,989
 $16,143
 $1,449
 $(626) $46,352
___________
(1) Decrease in Other Total assets due primarily to decreased cash balance.
(2) Total assets Eliminations primarily relate to the intercompany notes and accounts receivable generated by our cash management program.
The following table reflects the reconciliation of Modified EBITDA to Net income (loss) as reported in the Consolidated Statement of Income.
 Three Months Ended 
 September 30,
 Nine Months Ended 
 September 30,
 2019 2018 2019 2018
 (Millions)
Modified EBITDA by segment:       
Northeast G&P$345
 $281
 $947
 $786
Atlantic-Gulf599
 492
 1,683
 1,418
West311
 412
 921
 1,214
Other(2) 6
 1
 (49)
 1,253
 1,191
 3,552
 3,369
Accretion expense associated with asset retirement obligations for nonregulated operations(8) (8) (25) (26)
Depreciation and amortization expenses(435) (425) (1,275) (1,290)
Equity earnings (losses)93
 105
 260
 279
Other investing income (loss) – net(107) 2
 (54) 74
Proportional Modified EBITDA of equity-method investments(181) (205) (546) (552)
Interest expense(296) (270) (888) (818)
(Provision) benefit for income taxes(77) (190) (244) (297)
Net income (loss)$242
 $200
 $780
 $739


 Three Months Ended 
 September 30,
 Nine Months Ended 
 September 30,
 2018 2017 2018 2017
 (Millions)
Modified EBITDA by segment:       
Northeast$281
 $115
 $786
 $588
Atlantic-Gulf492
 430
 1,418
 1,334
West412
 (615) 1,214
 126
Other6
 1,009
 (49) 1,100
 1,191
 939
 3,369
 3,148
Accretion expense associated with asset retirement obligations for nonregulated operations(8) (7) (26) (23)
Depreciation and amortization expenses(425) (433) (1,290) (1,308)
Equity earnings (losses)105
 115
 279
 347
Other investing income (loss) – net2
 4
 74
 278
Proportional Modified EBITDA of equity-method investments(205) (202) (552) (611)
Interest expense(270) (267) (818) (818)
(Provision) benefit for income taxes(190) (24) (297) (126)
Net income (loss)$200
 $125
 $739
 $887



Item 2
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 businesses.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.
Prior toOur operations are presented within the WPZ Merger, we had onefollowing reportable segment, Williams Partners. Beginning in the third-quarter 2018,segments: Northeast G&P, Atlantic-Gulf, and West, consistent with the manner in which our chief operating decision maker evaluates performance and allocates resources, our operationsresources. All remaining business activities as well as corporate activities are now presented within the following reportable segments: Northeast G&P, Atlantic-Gulf, and West. Prior period segment disclosures have been recast for the new segment presentation.included in Other. Our reportable segments are comprised of the following businesses:
Northeast G&P is comprised of our midstream gathering, processing, and processingfractionation businesses in the Marcellus Shale region primarily in Pennsylvania, New York, and West Virginia and the Utica Shale region of eastern Ohio, as well asincluding a 66 percent interest in Cardinal (a consolidated entity), a 62 percent equity-method investment in UEOM,as well as 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, and various petrochemical and feedstock pipelines in the Gulf Coast region, 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 34 – Variable Interest Entities of Notes to Consolidated Financial Statements).


Management’s Discussion and Analysis (Continued)

West is comprised of our interstate natural gas pipeline, Northwest Pipeline, and our gathering, processing, and treating operations in New Mexico, Colorado, and Wyoming, as well as 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, Delaware, and PermianArkoma 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, and a 50 percent equity-method investment in OPPL, a 50 percent equity-method investment in RMM, and a 15 percent equity-method investment in Brazos Permian II. West also included our former natural gas gathering and processing assets in the Four Corners area of New Mexico and Colorado, which were sold during the fourth quarter of 2018, and our former 50 percent interest in Jackalope (an equity-method investment following deconsolidation as of June 30, 2018), a 43 percent equity-method investmentwhich was sold in RMM,and our previously owned 50 percent equity-method investment in the Delaware basin gas gathering system (DBJV) in the Mid-Continent region (see Note 5 – Investing Activities of Notes to Consolidated Financial Statements).
All remaining business activities, including our former Geismar Interest (see Note 4 – Divestitures and Assets Held for Sale of Notes to Consolidated Financial Statements), as well as corporate activities, are included in Other.
Financial Repositioning
In January 2017, we entered into agreements with WPZ, wherein we permanently waived the general partner’s IDRs and converted our 2 percent general partner interest in WPZ to a noneconomic interest in exchange for 289 million newly issued WPZ common units. Pursuant to this agreement, we also purchased approximately 277 thousand WPZ common units for $10 million. Additionally, we purchased approximately 59 million common units of WPZ at a price of $36.08586 per unit in a private placement transaction, funded with proceeds from our equity offering. According to the terms of this agreement, concurrent with WPZ’s quarterly distributions in February 2017 and May 2017, we paid additional consideration totaling $56 million to WPZ for these units.April 2019.


Management’s Discussion and Analysis (Continued)

Dividends
In September 2018,2019, we paid a regular quarterly dividend of $0.34$0.38 per share.
Overview of Nine Months Ended September 30, 20182019
Net income (loss) attributable to The Williams Companies, Inc., for the nine months ended September 30, 2018, decreased $712019, increased $310 millioncompared to the nine months ended September 30, 2017,2018, reflecting $362 million of increased service revenues primarily associated with expansion projects, a $204$269 million decrease in Other investingto 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 $2692018 charge for a valuation allowance on foreign tax credits. These increases are partially offset by $186 million gain associated with the disposition of certainimpairments of equity-method investments in 2017, a $171 million increase to2019, lower commodity margins, the provision for income taxesabsence of the Four Corners area business which reflects a $105 million valuation allowance on certain deferred tax assets that may not be realized following the WPZ Merger andwas sold in October 2018, higher interest expense, the absence of a prior year $127$62 million benefit associated withgain 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 release of a valuation allowance on a capital loss carryover, and a $68 million decrease in Equity earnings (losses). These decreasescurrent year were partiallysubstantially offset by an increasesimilar levels of $320 millionimpairments in operating income and a $77 million decrease to Net income (loss) attributable to noncontrolling interests primarily due to the WPZ Merger.prior year.
The improvement in operating income reflects a decrease of $1.170 billion in Impairment of certain assets, a $209 million increase in service revenues primarily resulting from expansion projects placed into service in 2017 and 2018, and a $64 million increase in NGL margins. These favorable changes were partially offset by the absence of a $1.095 billion gain from the sale of our Geismar Interest in 2017.
Unless indicated otherwise, the following discussion and analysis ofresults of operations and financial condition and liquidity should be read in conjunction with the consolidated financial statements and notes thereto of this Form 10‑Q and our annual consolidated financial statements and notes thereto in Exhibit 99.1Annual Report on Form 10-K dated February 21, 2019.
Acquisition of our Form 8-K dated May 3, 2018.UEOM
WPZ Merger
On August 10,As of December 31, 2018, we completed our merger with Williams Partners L.P. (WPZ), pursuant toowned a 62 percent interest in UEOM which we acquired allaccounted for as an equity-method investment. On March 18, 2019, we signed and closed the acquisition of the approximately 256remaining 38 percent interest in UEOM. Total consideration paid, including post-closing adjustments, was $741 million publicly held outstanding common unitsin cash funded through credit facility borrowings and cash on hand. As a result of WPZ in exchange for 382 million sharesacquiring this additional interest, we obtained control of our common stock in a non-cash equity transaction. Williams continued as the surviving entity.and now consolidate UEOM. (See Note 12General, Description of Business, and Basis of PresentationAcquisitions 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.
Expansion Project Update
Rivervale South to Market
In August 2018, we received approval from the FERC to expand Transco’s existing natural gas transmission system to provide incremental firm transportation capacity from the existing Rivervale interconnection with Tennessee Gas Pipeline on Transco’s North New Jersey Extension to other existing Transco locations within New Jersey. The project was placed into partial service on July 1, 2019. The remaining portion of the project was placed into service on September 1, 2019. The full project increased capacity by 190 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)


FERC Income Tax Policy Revision
On March 15, 2018, the FERC issued a revised policy statement (the March 15 Statement) regarding the recovery of income tax costs in rates of natural gas pipelines. The FERC found that an impermissible double recovery resultsnew NGL pipeline from granting a Master Limited Partnership (MLP) pipeline both an income tax allowance and a return on equity pursuantMoundsville to the discounted cash flow methodology. As a result, the FERC will no longer permitHarrison Hub fractionation facility to provide an MLP pipelineadditional outlet for NGLs. These expansions are supported by long-term, fee-based agreements and volumetric commitments.
Norphlet Project
In March 2016, we announced that we reached an agreement to recover an income tax allowance in its cost of service. The FERC further stated it will address the application of this policy to non-MLP partnership forms as those issues arise in subsequent proceedings. One of the benefits of the recent WPZ Merger is to allow our FERC-regulated pipelines to continue to recover an income tax allowance in their cost of service rates.
On July 18, 2018, the FERC issued an order dismissing the requests for rehearing and clarification of the revised policy statement. In addition, the FERC provided guidance that an MLP pipeline (or other pass-through entity) no longer recovering an income tax allowance pursuantprovide deepwater gas gathering services to the revised policy may eliminate previously accumulated deferred income taxes (ADIT) from its cost of service instead of flowing these ADIT balances to ratepayers. This guidance, if implemented, would significantly mitigate the impact of the March 15 Statement. However, the FERC stated that the revised policy statement and such guidance do not establish a binding rule but are instead expressions of general policy intent designed to provide guidance by notifying entities of the course of action the FERC intends to follow in future adjudications. To the extent the FERC addresses these issues in future proceedings, it will consider any arguments regarding not only the application of the revised policy to the facts of the case, but also any arguments regarding the underlying validity of the policy itself. The FERC’s guidance on ADIT likely will be challenged by customers and state commissions, which would result in a long period of revenue uncertainty for pipelines eliminating ADIT from their cost of service. The WPZ Merger has the additional benefit of eliminating this uncertainty.
On March 15, 2018, the FERC also issued a Notice of Proposed Rulemaking proposing a filing process that will allow it to determine which natural gas pipelines may be collecting unjust and unreasonable rates in light of the recent reductionAppomattox development in the corporate income tax rate in the Tax Cuts and Jobs Act (Tax Reform) and the revised policy statement. On July 18, 2018, the FERC issued a Final Rule, retaining the filing requirement and reaffirming the options that pipelines haveGulf of Mexico. We completed modifications to either reflect the reduced tax rate or explain why no rate change is necessary. The FERC also clarified that a natural gas company organized as a pass-through entity and all of whose income or losses are consolidated on the federal income tax return of its corporate parent is consideredinstall an alternate delivery route to be subject to the federal corporate income tax and is thus eligible for a tax allowance. We believe this Final Rule and the previously discussed WPZ Merger allow for the continued recovery of income tax allowances in Transco’s and Northwest Pipeline’s rates. Further, Transco’s August 31, 2018 general rate case filing reflects a tax allowance based on this clarification, and the FERC’s September 28, 2018 order in the rate case proceeding finds that Transco is exempt from the Final Rule’s Form 501-G filing requirement. In addition, on October 19, 2018, Northwest Pipeline filed a petition requesting that the FERC waive its Form 501-G filing requirement under this Final Rule because the reduction in the corporate income tax in Tax Reform is already addressed in its settlement.
On March 15, 2018, the FERC also issued a Notice of Inquiry seeking comments on the additional impacts of Tax Reform on jurisdictional rates, particularly whether, and if so how, the FERC should address changes relating to ADIT amounts after the corporate income tax rate reduction and bonus depreciation rules,our Main Pass 261 Platform, as well as whether other features of Tax Reform require FERC action. We are evaluating the impact of these developments onmodifications to our interstate naturalonshore Mobile Bay processing facility. The project went in service early in July 2019, at which time we also purchased a 54-mile-long, 16-inch-diameter pipeline (the Norphlet Pipeline) for $200 million. This pipeline transports gas pipelines and currently expect any associated impacts would be prospective and determined through subsequent rate proceedings. We also continue to monitor developments that may impact our regulatory liabilities resulting from Tax Reform. It is reasonably possible that future tariff-based rates collected by our interstate natural gas pipelines may be adversely impacted.
Proposition 112
On November 6, 2018, citizens of Colorado will vote on Proposition 112, a ballot measure that could significantly increase setback distances from occupied structures or other vulnerable areas, as defined or designated, for any new oil and gas development in the state, critically restricting or banning such activities. If the measure is approved, it could still be subject to modification or amendment by the Colorado legislature. An unfavorable outcome could adversely


Management’s Discussion and Analysis (Continued)

impact the operations, and ultimately the value, of our businesses and investments in Colorado, notably our recent investment in RMM.
Revenue Recognition
As a result of the adoption of Accounting Standards Update 2014-09, Revenues from Contracts with Customers (ASC 606), we now record revenues for transactions where we receive noncash consideration, primarily in certain of our gas processing contracts that provide commodities as full or partial consideration for services provided. These revenues are reflected as Service revenues – commodity consideration in the Consolidated Statement of Income. The costs associated with these revenues, primarily related to natural gas shrink replacement, are reported as Processing commodity expenses. The revenues and costs associated with the subsequent sale of the commodity consideration received is reflected within Product sales and Product costs in the Consolidated Statement of Income. Service revenues – commodity consideration plus Product sales, less Product costs and Processing commodity expenses represents the margin that we have historically characterized as commodity margin. This presentation is being reflected prospectively in the Consolidated Statement of Income. (See Note 2 – Revenue Recognition of Notes to Consolidated Financial Statements.)
Additionally, future revenues are impacted by application of the new accounting standard to certain contracts for which we received prepayments for services and have recorded deferred revenue (contract liabilities). For these contracts, which underwent modifications in periods prior to January 1, 2018, the modification is treated as a termination of the existing contract and the creation of a new contract. The new accounting guidance requires that the transaction price, including any remaining deferred revenue from the old contract, be allocatedAppomattox development to the performance obligations over the term of the new contract. As a result, we will recognize the deferred revenue over longer periods than application of revenue recognition under accounting guidance prior to January 1, 2018. The application of ASC 606 to prior periods related to these contracts would have resulted in lower revenues in 2017. Annual revenues will also be lower in 2018 and 2019 than what would have been recorded under the previous guidance, offset by increased revenues in later reporting periods given the longer period of recognition.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. The impactIn 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 these specific new ratesa 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 expected to reduce revenues by approximately $2.5 million per month beginning October 1, 2018.
RMM Equity-Method Investment
During the third quarter of 2018, our joint venture, RMM, purchased a natural gas and oil gathering and natural gas processing business in Colorado’s Denver-Julesburg basin. Our initial economic ownership was 40 percent, which is expected to increase to 50 percent as we provide additional capital contributions. At September 30, 2018, our carrying value was $569 million reflecting our 43 percent economic ownership. We are committed to fund up to an additional $177 million to reach 50 percent economic ownership,subject to the extent RMM needs fundingfiling of a formal stipulation and agreement with, and subsequent approval by, the FERC. We have provided a reserve of $131 million for capital expenditures. We accountrate refunds which we believe is adequate for this investment under the equity method of accounting.
Divestment of Four Corners Assets
On October 1, 2018, we completed the sale of our natural gas gathering and processing assets in the Four Corners area of New Mexico and Colorado for total consideration of $1.125 billion, subject to customary working capital adjustments, of which a $113 million deposit was received in the third quarter. At September 30, 2018, these assets were designated as held for sale within the West segment. As a result of this sale, we expect to record a gain of approximately $0.6 billion in the fourth quarter of 2018 (see Note 4 – Divestitures and Assets Held for Sale of Notes to Consolidated Financial Statements).


Management’s Discussion and Analysis (Continued)

Expansion Project Updates
Significant expansion project updates for the period, including projects placed into service are described below. Ongoing major expansion projects are discussed later in Company Outlook.
Northeast G&P
Susquehanna Supply Hub
During the first quarter of 2018, the remaining facilitiesany refunds that comprise the Susquehanna Supply Hub Expansion were fully commissioned. The project added two new compression facilities with an additional 49,000 horsepower and 59 miles of 12- to 24-inch pipeline, and increased gathering capacity, allowing a certain producer to fulfill its commitment to deliver 850 Mdth/d to our Atlantic Sunrise development.
Atlantic-Gulf
Atlantic Sunrise
In October 2018, the Atlantic Sunrise project was placed into service. This project expanded Transco’s existing natural gas transmission system along with greenfield facilities to provide incremental firm transportation capacity from the northeastern Marcellus producing area to markets along Transco’s mainline as far south as Station 85 in west central Alabama. We placed a portion of the mainline project facilities into service in September 2017, which increased capacity by 400 Mdth/d. We placed additional mainline facilities into service in June 2018, which increased capacity by an additional 150 Mdth/d. The full project increased Transco’s capacity by 1,700 Mdth/d.
Garden State
In March 2018, Phase 2 of the Garden State Expansion project was placed into service. This project expanded Transco’s existing natural gas transmission system to provide incremental firm transportation capacity from Station 210 in New Jersey to a new interconnection on our Trenton Woodbury Lateral in New Jersey. Phase 1 of the project was placed into service in September 2017, and together Phases 1 and 2 increased capacity by 180 Mdth/d.may be required.
Commodity Prices
NGL per-unit margins were approximately 4451 percent higherlower in the first nine months of 20182019 compared to the same period of 20172018 primarily due to a 2832 percent increasedecrease in per-unit non-ethane prices and an approximate 223 percent decreaseincrease in 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 20182019 is further discussed in the following Company Outlook.
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.


Management’s Discussion and Analysis (Continued)

Our business plan for 20182019 includes a continued focus on growing our fee-based businesses, executing growth projects, including through joint ventures, and accomplishing cost discipline initiatives to ensure operations support our strategy. We anticipate operating results will increase through organic business growth driven primarily by Transco expansion projects and continued growthexpansion in the Northeast region. We intend to fund planned growth capital with retained cash flow, debt,


Management’s Discussion and proceeds from asset sales.Analysis (Continued)

Our updated growth capital and investment expenditures in 20182019 are expected to be at least $3.9in a range from $2.3 billion to $2.5 billion. Approximately $1.8 billion of our growthGrowth capital funding needs includespending in 2019 includes Transco expansions, and other interstate pipeline growth projects, mostall of which are fully contracted with firm transportation agreements. The remaining growth capital spending in 2018 primarily reflects investment inagreements, and continuing to develop our gathering and processing systemsinfrastructure in the Northeast G&P segment limited primarily to known new producer volumes, including volumes that support Transco expansion projects including our Atlantic Sunrise project, and funding for growth investment opportunities as they arise such as our investment in RMM in the West segment.segments. 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 expansionsexpansion 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 2018,2019, current forward market prices indicate crude oil, natural gas, and NGL prices are expected to be higherlower compared to 2017, while natural gas prices are expected to be lower as compared to 2017.2018. We continue to address certain pricing risks through the utilization of commodity hedging strategies. However, some of our customers may continue to curtail or delay drilling plans until there is a more sustained recovery in prices, which may negatively impact our gathering and processing volumes. Reductions in drilling activity or lower energy commodity prices could also adversely affect the credit profiles of certain of our producer customers. Unfavorable changes in energy commodity prices or the credit profile of our producer customers may also result in noncash impairments of our assets.
In 2018,2019, our operating results are expected to include increases from our regulated Transco fee-based business, primarily related to projects recently placed in-service or expected to be placed in-servicebeginning early 2018 and 2019, as well as the favorable impact from Transco’s agreement on the terms of a settlement in 2018 including the Atlantic Sunrise project.its general rate case as previously discussed. For our non-regulated businesses, we anticipate a reduction in fee-based revenue in the West segment, partially offset by increases in fee-based revenue in the Northeast G&P segment. As previously discussed, undersegment driven by expansion projects, partially offset with a decrease in the new accounting guidance for revenueWest 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 under certain contracts will be recognized over longer periods than underassociated with the prior guidance, contributing to the decrease in annual revenue for the West region.end of a contractual MVC period. We expect overall gathering and processing volumes to grow in 20182019 for our continuing businesses. Additionally, we believe our expenses will be impacted by the changes in our asset portfolio, including the UEOM acquisition and increase thereafter to meet the growing demand for natural gasasset divestitures, as well as severance charges and natural gas products. We also anticipate slightly lower general and administrative expenses due to the full year impact of prior year cost reduction initiatives and lower equity earnings fromother costs associated with our investment in Discovery due to production ending on certain wells.previously announced organizational realignment.
Potential risks and obstacles that could impact the execution of our plan include:
Opposition to, and legal regulations affecting, our infrastructure projects, including the risk of delay or denial in permits and approvals needed for our projects;
Unexpected significant increases in capital expenditures or delays in capital project execution;
Counterparty credit and performance risk, including that of Chesapeake Energy Corporationrisk;
Unexpected changes in customer drilling and its affiliates;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;


Management’s Discussion and Analysis (Continued)

Production issues impacting offshore gathering volumes;
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, 2017,2018, as filed with the SEC on February 22, 2018 as supplemented by the disclosure in Part II, Item 1A. Risk Factors in this Quarterly Report on Form 10-Q.21, 2019.
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
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 plan to further expand the processing capacity of our Oak Grove facility by 400 MMcf/d. With one of these customers, we secured a gathering dedication agreement to gather dry gas in this same region. Additionally, we will be constructing a new NGL pipeline from Moundsville to the Harrison Hub fractionation facility to provide a new outlet for NGLs. These expansions will be supported by long-term, fee-based agreements and volumetric commitments.
Susquehanna Supply Hub Expansion
We continue to expand the gathering systems in the Susquehanna Supply Hub that are needed to meet our customers’ production plans by 2020. This next expansion 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.
In December 2014, Constitution received approval from For further discussion on the FERC to construct and operate its proposed pipeline, which will have an expected capacitystatus of 650 Mdth/d. 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 and in August 2017, the court issued a decision denying in part and dismissing in part Constitution’s appeal. The court expressly declined to rule on Constitution’s argument that the delay in the NYSDEC’s decision on Constitution’s Section 401 application constitutes a waiver of the certification requirement. The court determined that it lacked jurisdiction to address that contention and found that jurisdiction over the waiver issue lies exclusively with the United States Court of Appeals for the District of Columbia Circuit (D.C. Circuit). As to the denial itself, the court determined that NYSDEC’s action was not arbitrary or capricious. Constitution filed a petition for rehearing with the Second Circuit Court of Appeals, but in October 2017 the court denied our petition.
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 pipelinethis 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. In January 2018, the FERC denied our petition,


Management’s Discussion and Analysis (Continued)

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. We filed a request for rehearing of the FERC’s decision, but in July 2018 the FERC denied our request.
The project’s sponsors remain committed to the project, and in September 2018 we filed a petition with the D.C. Circuit for review of the FERC’s decision.(Seesee Note 34 – Variable Interest Entities of Notes to Consolidated Financial Statements.)
Gateway
In November 2017,December 2018, we filed an application withreceived approval from the FERC to expand Transco’s existing natural gas transmission system to provide incremental firm transportation capacity from PennEast Pipeline Company'sCompany’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 quarterhalf of 2021,2020, assuming timely receipt of all necessary regulatory approvals. The project is expected to increase capacity by 65 Mdth/d.
Gulf Connector
In November 2017, we received approval from the FERC allowing Transco to expand its existing natural gas transmission system to provide incremental firm transportation capacity from Station 65 in Louisiana to delivery points in Wharton and San Patricio Counties, Texas. We plan to place the project into service during the first quarter of 2019, assuming timely receipt of all necessary regulatory approvals. The project is expected to increase capacity by 475 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. We placed a portion of Phase I into servicewas completed in June of 2017 and the remainder of Phase I into service in July of 2017. Phase Iit 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.
In August 2017, the Court of Appeals for the District of Columbia Circuit granted an appeal of the FERC certificate order for the Southeast Market Pipelines projects (a group of related projects, including the Hillabee Expansion Project) filed by certain non-governmental organizations. In doing so, the court (i) remanded the matter to the FERC for preparation of an Environmental Impact Statement (EIS) that conforms with the court’s opinion regarding quantifying certain greenhouse gas emissions, and (ii) vacated the FERC’s certificate order for the projects, which would be effective following the court’s mandate (by court order, the mandate will not issue until after disposition of all petitions for rehearing). In compliance with the court's directive, on February 5, 2018, the FERC issued a Final Supplemental EIS for the projects, reaffirming that while the projects would result in temporary and permanent impacts on the environment, those impacts would not be significant. On March 14, 2018, the FERC issued an order on remand reinstating the certificate and abandonment authorizations for the Hillabee Expansion Project and the other Southeast Market Pipelines projects. As this order was issued prior to the court’s mandate (which was issued on March 30, 2018), we experienced no lapse in FERC authorization for the project.
Norphlet Project
In March 2016, we announced that we have reached an agreement to provide deepwater gas gathering services to the Appomattox development in the Gulf of Mexico. The project will provide offshore gas gathering services to our existing Transco lateral, which will provide transmission services onshore to our Mobile Bay processing facility. We also plan to make modifications to our Main Pass 261 Platform to install an alternate delivery route from the platform, as well as modifications to our Mobile Bay processing facility. The project is scheduled to go into service during the second quarter of 2019.


Management’s Discussion and Analysis (Continued)

Northeast Supply Enhancement
In March 2017,May 2019, we filed an application withreceived 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. On April 20, 2018,Approvals required for the NYSDECproject from the New York State Department of Environmental Conservation and the New Jersey Department of Environmental Protection remain pending, with each such agency having denied, without prejudice, Transco’s applicationapplications for certain permits requiredsuch approvals. We have refiled our applications for the project. Wethose approvals and have addressed the technical issues identified by NYSDEC and in May 2018, we refiled our application for the permits.agencies. We plan to place the project into service in the fourth quarter of 2020, assuming timely receipt of all necessary regulatorythese remaining approvals. The project is expected to increase capacity by 400 Mdth/d.
Rivervale South to MarketSoutheastern Trail
In August 2018,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 existing Rivervale interconnection with Tennessee Gas Pipeline on Transco’s North New Jersey Extension to other existing Transco locations within New Jersey. We plan to place the project into service as early as the fourth quarter of 2019, assuming timely receipt of all necessary regulatory approvals. The project is expected to increase capacity by 190 Mdth/d.
Southeastern Trail
In April 2018, we filed an application with the FERC to expand Transco’s existing natural gas transmission system to provide incremental firm transportation capacity from the Pleasant Valley interconnect with Dominion’s Cove Point Pipeline in Virginia to the Station 65 pooling point in Louisiana. We plan to place the project into


Management’s Discussion and Analysis (Continued)

service in late 2020, assuming timely receipt of all remaining necessary regulatory approvals. The project is expected to increase capacity by 296 Mdth/d.
Leidy South
In July 2019, we filed an application with the FERC for approval of the project to expand Transco’s existing natural gas transmission system and also extend its system through a capacity lease with National Fuel Gas Supply Corporation that will enable us to provide incremental firm transportation from Clermont, Pennsylvania and from the Zick interconnection on Transco’s Leidy Line to the River Road regulating station in Lancaster County, Pennsylvania. We plan to place the project into service in the second half of 2022, assuming timely receipt of all necessary regulatory approvals. The project is expected to increase capacity by 296582 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 as early asduring the fourth quarter of 2019, assuming timely receipt of all necessary regulatory approvals.2019. The project is expected to increase delivery capacity by approximately 159 Mdth/d.
Wamsutter Expansion
We are expandinghave 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 includes the addition ofadded approximately 5420 miles of gathering pipelines and compression,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 pipeline from our fractionator near Conway, Kansas to an interconnect with a third-party NGL pipeline system in Oklahoma, providing us with firm access to Mt. Belvieu pricing. As part of the project, the third-party intends to construct a 110-mile pipeline extension of their existing NGL pipeline system that will have an initial capacity of 120 Mbbls/d. Further, during the first quarter of 2019, we exercised an option to purchase a 20 percent equity interest in a Mt. Belvieu fractionation train developed by the third party. The pipeline and modificationsextension projects are expected to existing treating and processing facilities. We plan to place the projectbe placed into service during the first quarter of 2019.2021.
Critical Accounting Estimates
Constitution Pipeline Capitalized Project Costs
As of September 30, 2018, 2019, Property, plant, and equipmentinour Consolidated Balance Sheet includes approximately $377$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 Company Outlook,Note 4 – Variable Interest Entities of Notes to Consolidated Financial Statements, we have evaluated the capitalized project costs for impairment as recently as December 31, 2017, 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. These scenarios included our most recent estimate of total construction costs. The probability-weighted scenarios also considered our assessment of the likelihood of success of the path to obtain necessary certification, as described in Company Outlook. It is reasonably possible that future unfavorable developments, such as a reduced likelihood of success,failure to successfully renegotiate associated customer contracts, increased estimates of construction costs, or further significant delays, could result in a future impairment.


Management’s Discussion and Analysis (Continued)

Equity-Method Investments
As of September 30, 2018, the carrying value of our equity-method investment in Discovery is $514 million. During the fourth quarter of 2017, certain customers of Discovery terminated a significant offshore gas gathering agreement following the shut-in of production after the associated wells ceased flowing. As a result, we evaluated this investment for impairment in the fourth quarter of 2017 and determined that no impairment was necessary.
This evaluation included probability-weighted assumptions of additional commercial development, assigning higher probabilities to those commercial development opportunities that were more advanced in the discussion and contracting process, that utilized existing infrastructure due to producer capital constraints, and/or that we believe Discovery has a competitive advantage due to geographical proximity to the prospect. We continue to monitor this investment as it is reasonably possible that an impairment could be required in the future if commercial development activities are not as successful or as timely as assumed.
Regulatory Liabilities Resulting from Tax Reform
In December 2017, the Tax ReformCuts 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. As a result ofDue 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 and have accordinglyrates. As a result, we established regulatory liabilities totaling $657 million as ofduring 2017 and at September 30, 2018.2019, 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–servicecost-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 of a loss in value has occurred, we compare our estimate of the fair value of the investment to the carrying value of the investment to determine whether an impairment has occurred. We generally estimate 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 value of our investments. During 2019, we have recognized impairments totaling $186 million related to our equity-method investments. (See Note 13 – Fair Value Measurements and Guarantees of Notes to Consolidated Financial Statements.)






Management’s Discussion and Analysis (Continued)




Results of Operations
Consolidated Overview
The following table and discussion is a summary of our consolidated results of operations for the three and nine months ended September 30, 2018,2019, compared to the three and nine months ended September 30, 2017.2018. 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 
 September 30,
     Nine Months Ended 
 September 30,
    
2018 2017 $ Change* % Change* 2018 2017 $ Change* % Change*2019 2018 $ Change* % Change* 2019 2018 $ Change* % Change*
(Millions)     (Millions)    (Millions)     (Millions)    
Revenues:                              
Service revenues$1,371
 $1,310
 +61
 +5 % $4,062
 $3,853
 +209
 +5 %$1,495
 $1,371
 +124
 +9 % $4,424
 $4,062
 +362
 +9 %
Service revenues – commodity consideration121
 
 +121
 NM
 316
 
 +316
 NM
38
 121
 -83
 -69 % 158
 316
 -158
 -50 %
Product sales811
 581
 +230
 +40 % 2,104
 1,950
 +154
 +8 %466
 811
 -345
 -43 % 1,512
 2,104
 -592
 -28 %
Total revenues2,303
 1,891
     6,482
 5,803
    1,999
 2,303
     6,094
 6,482
    
Costs and expenses:                              
Product costs790
 504
 -286
 -57 % 2,039
 1,620
 -419
 -26 %434
 790
 +356
 +45 % 1,442
 2,039
 +597
 +29 %
Processing commodity expenses30
 
 -30
 NM
 91
 
 -91
 NM
19
 30
 +11
 +37 % 83
 91
 +8
 +9 %
Operating and maintenance expenses389
 403
 +14
 +3 % 1,134
 1,166
 +32
 +3 %364
 389
 +25
 +6 % 1,091
 1,134
 +43
 +4 %
Depreciation and amortization expenses425
 433
 +8
 +2 % 1,290
 1,308
 +18
 +1 %435
 425
 -10
 -2 % 1,275
 1,290
 +15
 +1 %
Selling, general, and administrative expenses174
 138
 -36
 -26 % 436
 452
 +16
 +4 %130
 174
 +44
 +25 % 410
 436
 +26
 +6 %
Gain on sale of Geismar Interest
 (1,095) -1,095
 -100 % 
 (1,095) -1,095
 -100 %
Impairment of certain assets
 1,210
 +1,210
 +100 % 66
 1,236
 +1,170
 +95 %
 
 
 
 76
 66
 -10
 -15 %
Other (income) expense – net(6) 24
 +30
 NM
 24
 34
 +10
 +29 %(11) (6) +5
 +83 % 30
 24
 -6
 -25 %
Total costs and expenses1,802
 1,617
     5,080
 4,721
    1,371
 1,802
     4,407
 5,080
    
Operating income (loss)501
 274
     1,402
 1,082
    628
 501
     1,687
 1,402
    
Equity earnings (losses)105
 115
 -10
 -9 % 279
 347
 -68
 -20 %93
 105
 -12
 -11 % 260
 279
 -19
 -7 %
Other investing income (loss) – net2
 4
 -2
 -50 % 74
 278
 -204
 -73 %(107) 2
 -109
 NM
 (54) 74
 -128
 NM
Interest expense(270) (267) -3
 -1 % (818) (818) 
  %(296) (270) -26
 -10 % (888) (818) -70
 -9 %
Other income (expense) – net52
 23
 +29
 +126 % 99
 124
 -25
 -20 %1
 52
 -51
 -98 % 19
 99
 -80
 -81 %
Income (loss) before income taxes390
 149
     1,036
 1,013
    319
 390
     1,024
 1,036
    
Provision (benefit) for income taxes190
 24
 -166
 NM
 297
 126
 -171
 -136 %77
 190
 +113
 +59 % 244
 297
 +53
 +18 %
Net income (loss)200
 125
     739
 887
    242
 200
     780
 739
    
Less: Net income (loss) attributable to noncontrolling interests71
 92
 +21
 +23 % 323
 400
 +77
 +19 %21
 71
 +50
 +70 % 54
 323
 +269
 +83 %
Net income (loss) attributable to The Williams Companies, Inc.$129
 $33
     $416
 $487
    $221
 $129
     $726
 $416
    


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




Management’s Discussion and Analysis (Continued)


Three months ended September 30, 20182019 vs. three months ended September 30, 20172018
Service revenuesincreased primarily due to higher transportation fee revenues at Transco associated with expansion projects placed in-service in 2017service in 2019 and 2018, as well asfrom UEOM, which is now a consolidated entity after the remaining ownership interest was purchased in March 2019, and from higher gathering volumes at the Susquehanna Supply Hub. These increases are 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 considerationincreased as decreased primarily due to lower NGL prices, and lower volumes due to the resultabsence of implementing ASC 606 using a modified retrospective approach, effective January 1, 2018. Therefore, prior periods have not been recast under the new guidance.our former Four Corners area operations and ethane rejection. These revenues represent consideration we receive in the form of commodities as full or partial payment for gathering and processing services provided. (See Note 2 – Revenue Recognition of Notes to Consolidated Financial Statements.) Most of these NGL volumes are sold within the month processed and therefore are offset in Product costs below.
Product salesincreaseddecreased primarily due to higherlower NGL and natural gas prices associated with our marketing revenues and higherequity NGL sales activities. This decrease also includes lower volumes from our equity NGL sales primarily reflecting the productionabsence of our equity NGLs, both reflecting higher NGL prices. Higherformer Four Corners area operations and lower system management gas sales, whichpartially offset by higher marketing volumes. Marketing revenues and system management gas sales are substantially offset in Product costs, also contributed to the increase..
The increase in Product costsis decreased primarily due to the impact of ASC 606 in which costs reflected in this line item for 2018 includelower 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 as well as higher marketing costsreflecting the absence of our former Four Corners area operations and lower system management gas costs. This increase iscosts, partially offset by higher volumes for marketing activities.
Operating and maintenance expenses decreased primarily due to the absence of our former Four Corners area operations and a decrease in Transco’s contracted services mainly due to the timing of required engine overhauls and integrity testing, partially offset by the absenceconsolidation of natural gas purchases associated with the production of equity NGLs, which are now reported in Processing commodity expenses in conjunction with the implementation of ASC 606.
Processing commodity expenses presents the natural gas purchases associated with the production of equity NGLs as previously described in conjunction with the implementation of ASC 606.
OperatingUEOM, and maintenance expenses decreased primarily due to lowerby an accrual for estimated severance and related costs including reduced hydrotesting related to certain compliance projects that occurred in 2017.
Selling, general, and administrative expenses increased primarily due to a charitable contribution of preferred stock to The Williams Companies Foundation, Inc. (see Note 11 – Stockholders’ Equity of Notes to Consolidated Financial Statements) and fees associated with the WPZ Merger, partially offset by the absence of severance-related and organizational realignment costs incurred in 2017.
The unfavorable change in Gain on sale of Geismar Interest reflects the absence of the gain recognized on the sale of our Geismar Interest in July 2017 (see Note 4 – Divestitures and Assets Held for Sale of Notes to Consolidated Financial Statements.)
The favorable change in Impairment of certain assets includes the absence of 2017 impairments associated with certain assets in the Marcellus South, Mid-Continent, and Houston Ship Channel areas (see Note 12 – Fair Value Measurements and Guarantees of Notes to Consolidated Financial Statements.)
The favorable change inOther (income) expense – net within Operating income (loss) includes the benefit of establishing a regulatory asset associated with an increase in Transco’s estimated deferred state income tax rate following the WPZ Merger, partially offset by charges establishing a regulatory liability associated with a decrease in Northwest Pipeline's estimated deferred state income tax rate following the WPZ Merger.
The favorable change in Operating income (loss) includes the absence of Impairment of certain assets incurred in 2017, and the benefit of establishing a regulatory asset associated with an increase in Transco’s estimated deferred state income tax rate following the WPZ Merger. Also included are an increase in Service revenues primarily associated with Transco projects placed in-service in 2017 and 2018, higher gathering volumes, and favorable NGL and marketing commodity margins reflecting higher NGL prices and volumes. The favorable change was partially offset by the absence of the 2017 Gain on sale of Geismar Interest and higher costs associated with our charitable contribution of preferred stock, and WPZ Merger-related fees.
The unfavorable change in Equity earnings (losses) is primarily due to a decrease in volumes at Discovery, partially offset by improved results at our Appalachia Midstream Investments.


Management’s Discussion and Analysis (Continued)

The favorable change in Other income (expense) – net below Operating income (loss)is primarily due to an increase in equity funds used during construction (AFUDC). (Seevoluntary separation program (VSP) (see Note 6 – Other Income and Expenses of Notes to Consolidated Financial Statements.)Statements).
Depreciation and amortization expenses increased primarily due to the consolidation of UEOM and new assets placed in service, substantially offset by the 2018 impairment of certain assets in the Barnett Shale region.
Selling, general, and administrative expenses decreased primarily due to the absences of a charge for a 2018 charitable contribution of preferred stock to The Williams Companies Foundation, Inc. and fees associated with the WPZ Merger.
The favorable change in Other (income) expense – net within Operating income (loss) includes net favorable changes to charges and credits to regulatory assets and liabilities, partially offset by the absence of a 2018 gain on asset retirement (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 absence of a charge for a charitable contribution of preferred stock to the Williams Foundation, Inc., and the absence of fees associated with the WPZ Merger, partially offset by unfavorable commodity margins primarily reflecting lower NGL sales prices and lower volumes.
The unfavorable change in Other investing income (loss) – net is primarily due to 2019 impairments to 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 increase in financing obligations associated with Transco’s Atlantic Sunrise project and lower capitalized interest due to projects placed in service.


Management’s Discussion and Analysis (Continued)

The unfavorable change in Other income (expense) – net below Operating income (loss) is primarily due to a decrease in equity AFUDC associated with reduced capital expenditures on projects and 2019 charges for loss contingencies associated with former operations.
Provision (benefit) for income taxes changed unfavorablyfavorably 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 andmerger, partially offset by higher pre-tax income partially offset by the decrease in the federal statutory rate from 35 percentattributable to 21 percent with the enactment of Tax Reform.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.
Nine months ended September 30, 20182019 vs. nine months ended September 30, 20172018
Service revenuesincreased primarily due to higher transportation fee revenues at Transco primarily associated with expansion projects placed in-service in 2017service in 2019 and 2018 and the consolidation of UEOM, as well as higher gatheringvolumes at the Susquehanna Supply Hub, and processinghigher rates and volumes across most of our operating locations.from new wells in the Utica Shale region. These increases wereare 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 decrease due to a reduction of rates resulting from a Northwest Pipeline rate case settlement.contractual MVC period.
Service revenues – commodity considerationincreased as decreased due to lower NGL prices and lower volumes primarily due to the resultabsence of implementing ASC 606 using a modified retrospective approach, effective January 1, 2018. Therefore, prior periods have not been recast under the new guidance.our former Four Corners area operations. These revenues represent consideration we receive in the form of commodities as full or partial payment for gathering and processing services provided. (See Note 2 – Revenue Recognition of Notes to Consolidated Financial Statements.) Most of these NGL volumes are sold within the month processed and therefore are offset in Product costs below.
Product salesincreaseddecreased primarily due to higherlower NGL and natural gas prices associated with our marketing revenues and higherequity 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 the absence of $268 millionhigher marketing volumes. Marketing revenues and system management gas sales are substantially offset in olefin revenueProduct costs.
Product costs decreased primarily due to lower NGL and natural gas prices associated with our former olefin operations in 2017. The increase in marketing revenue is driven by higherand equity NGL prices and volumes, partially offset byproduction activities. This decrease also includes lower crude oil and olefin-related volumes.
The increase in Product costs is primarily due to the impact of ASC 606 in which costs reflected in this line item for 2018 include volumes acquired as commodity consideration for NGL processing services as well as higher marketingreflecting the absence of our former Four Corners area operations and lower system management gas costs. This increase iscosts, partially offset by the absence of $147 million of olefin feedstockhigher volumes associated with our former olefin operations, as well as the absence of natural gas purchases associated with the production of equity NGLs, which are now reported in Processing commodity expenses in conjunction with the implementation of ASC 606.for marketing activities.
Processing commodity expenses presents the natural gas purchases associated with the production of equity NGLs as previously described in conjunction with the implementation of ASC 606.
Operating and maintenance expensesdecreased primarily due to the absence of $52 million of costs associated with our former olefinFour Corners area operations, partially offset by higher operatingthe consolidation of UEOM, and maintenance expenses at Transcoby an accrual for estimated severance and related costs primarily associated with general maintenance and other testing and labor costs.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 costs associated with our former olefinFour Corners area operations, partially offset by new assets placed in-service.in service and by the consolidation of UEOM.
Selling, general, and administrative expenses decreased primarily due to the absenceabsences of severance-related, organizational realignment, the absence of $17 million in costs associated with our former olefin operations, Financial Repositioning costs incurred in 2017, and ongoing cost containment efforts. These decreases are partially offset by a charitable contribution of preferred stock to the Williams Foundation, Inc. and fees associated with the WPZ Merger.Merger, partially offset by an accrual for estimated severance and related costs primarily associated with our VSP, and transaction expenses associated with the acquisition of UEOM and the formation of the Northeast JV.
The unfavorable change in Gain on saleImpairment of Geismar Interest reflectscertain 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 recognized on asset retirement, a 2019 charge for the salereversal of our Geismar Interest in July 2017 (see Note 4 – Divestituresexpenditures previously capitalized, and Assets Held for Sale of Notes to Consolidated Financial Statements.)net unfavorable




Management’s Discussion and Analysis (Continued)


The favorable change in Impairment of certainchanges to charges and credits to regulatory assets includes the absence of 2017 impairments associated with certain assets in the Marcellus South, Mid-Continent, and Houston Ship Channel areas, partially offset by the impairment of certain idle pipelines in 2018liabilities (see Note 12 – Fair Value Measurements and Guarantees of Notes to Consolidated Financial Statements.)
The favorable change inOther (income) expense – net within Operating income (loss) includes the benefit of establishing a regulatory asset associated with an increase in Transco’s estimated deferred state income tax rate following the WPZ Merger and favorable adjustments to certain regulatory charges associated with Tax Reform. These favorable adjustments are partially offset by the absence of gains from certain contract settlements and terminations in 2017, the absence of a gain on the sale of our RGP Splitter in 2017, and 2018 regulatory charges associated with both Northwest Pipeline’s approved rates related to Tax Reform and establishing a regulatory liability associated with a decrease in Northwest Pipeline's estimated deferred state income tax rate following the WPZ Merger.
The favorable change in Operating income (loss) includes the absence of Impairment of certain assets, an increase in Service revenues primarily associated with Transco projects placed in-service in 2017 and 2018, higher gathering and processing volumes across most of our operating locations, the benefit of establishing a regulatory asset associated with an increase in Transco’s estimated deferred state income tax rate following the WPZ Merger, as well as higher NGL and marketing margins, and lower severance-related, organizational realignment, and Financial Repositioning costs. These favorable changes are partially offset by the absence of the 2017 Gain on sale of Geismar Interest, the absence of operating income related to our former olefin operations, a charitable contribution of preferred stock, 2018 regulatory charges associated with both Northwest Pipeline’s approved rates related to Tax Reform and establishing a regulatory liability associated with a decrease in Northwest Pipeline's estimated deferred state income tax rate following the WPZ Merger, and higher operating costs at Transco.
The unfavorable change in Equity earnings (losses) is primarily due to a decrease in volumes at Discovery, partially offset by improved results at our Appalachia Midstream Investments.
The unfavorable change in Other investing income (loss) – net is due to the absence of a gain on disposition of our investments in DBJV and Ranch Westex JV LLC in 2017, partially offset by a gain on the deconsolidation of our interest in Jackalope in 2018. (See Note 5 – Investing Activities of Notes to Consolidated Financial Statements.)
The unfavorable change in Other income (expense) – net below Operating income (loss) is primarily due to the absence of a net gain on early retirement of debt in 2017 and a loss on early retirement of debt in 2018. (See Note 6 – Other Income and Expenses of Notes to Consolidated Financial Statements.) This unfavorableStatements).
The favorable change isin 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.AFUDC associated with reduced capital expenditures on projects.
Provision (benefit) for income taxes changed unfavorablyfavorably primarily due to the absence of releasing a $127 million valuation allowance on a capital loss carryover in 2017, a $105 million 2018 valuation allowance on certain deferred tax assets that may not be realized following the WPZ Merger, andmerger, partially offset by higher pre-tax income partially offset by the decrease in the federal statutory rate from 35 percentattributable to 21 percent with the enactment of Tax Reform.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 operating results at WPZ and the subsequent WPZ Merger.Gulfstar.
Period-Over-Period Operating Results - Segments
We evaluate segment operating performance based upon Modified EBITDA. Note 1415 – Segment Disclosures of Notes to Consolidated Financial Statements includes a reconciliation of this non-GAAP measure to Net income (loss). Management uses Modified EBITDA because it is an accepted financial indicator used by investors to compare company performance. In addition, management believes that this measure provides investors an enhanced perspective of the operating performance of our assets. Modified EBITDA should not be considered in isolation or as a substitute for a measure of performance prepared in accordance with GAAP.




Management’s Discussion and Analysis (Continued)


Northeast G&P
Three Months Ended 
 September 30,
 Nine Months Ended 
 September 30,
Three Months Ended 
 September 30,
 Nine Months Ended 
 September 30,
2018 2017 2018 20172019 2018 2019 2018
(Millions)(Millions)
Service revenues$247
 $214
 $707
 $648
$353
 $247
 $959
 $707
Service revenues commodity consideration
6
 
 14
 
1
 6
 9
 14
Product sales69
 61
 242
 181
30
 69
 114
 242
Segment revenues322
 275
 963
 829
384
 322
 1,082
 963
              
Product costs(69) (61) (245) (179)(29) (69) (114) (245)
Processing commodity expenses(3) 
 (7) 
(1) (3) (6) (7)
Other segment costs and expenses(100) (98) (279) (273)(117) (100) (348) (279)
Impairment of certain assets
 (121) 
 (123)
Proportional Modified EBITDA of equity-method investments131
 120
 354
 334
108
 131
 333
 354
Northeast G&P Modified EBITDA$281
 $115
 $786
 $588
$345
 $281
 $947
 $786
       
Commodity margins$1
 $3
 $3
 $4
Three months ended September 30, 20182019 vs. three months ended September 30, 20172018
Northeast G&P Modified EBITDA increased primarily due to the absence of Impairment of certain assets in 2018 and higher Service revenues.
Service revenues increased primarily due to higher Service revenues due to increased gathering volumes and the favorable impact of acquiring the additional interest of UEOM, which is a consolidated entity after the remaining ownership interest was purchased in March 2019.
Service revenues increased primarily due to:
A $50 million increase associated with the consolidation of UEOM, as previously discussed;
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.customers;
Product sales increased primarily due to higher system management gas sales. System management gas sales are offset in Product costs and therefore have little impact to Modified EBITDA.
Impairment of certain assets changed favorably primarily due to the absence of a $115 million impairment of certain gathering operations in the Marcellus South region and $6 million of write-downs of certain assets that were no longer in use or were surplus in nature in the third quarter of 2017.
Proportional Modified EBITDA of equity-method investments increased primarily due to a $7An $18 million increase at AppalachiaOhio Valley Midstream Investments reflecting higher volumes.
Nine months ended September 30, 2018 vs. nine months ended September 30, 2017
Modified EBITDA increased primarily due to the absence of Impairment of certain assets in 2018 and higher Service revenues.
Service revenues increased primarily due to higher gathering volumes at Susquehanna Supply Hub reflecting increased production from customers, as well as higherand processing revenues;
A $9 million increase in gathering revenues in the Utica Shale region due to volumes from new wells and higher fractionation revenues at Ohio Valley Midstream, and higher compression revenue in the Marcellus South region.rates.
Service revenues commodity consideration increased as a result of implementing ASC 606 using a modified retrospective approach. These revenues represent consideration we receive in the form of commodities as full or partial payment for gathering and processing services provided. Most of these NGL volumes are sold within the month processed and therefore are offset in Processing commodity expenses below.
Product sales increased decreased primarily due to $42 million in higher marketing sales, driven by higherlower non-ethane prices and volumes.volumes within our marketing activities. The changes in marketing revenues are offset by similar changes in marketing purchases, reflected above as Product costs. The increase in Product sales also includes $16 million in
Other segment costs and expenses increased primarily due to expenses associated with the consolidation of UEOM.
Proportional Modified EBITDA of equity-method investments decreased primarily due to the consolidation of UEOM.
Nine months ended September 30, 2019 vs. nine months ended September 30, 2018
Northeast G&P Modified EBITDA increased primarily due to higher system management gas sales. System management gas sales areService revenues due to increased gathering volumes and the favorable impact of acquiring the additional interest of UEOM, partially offset in Product costsby 2019 severance and therefore have little impact on Modified EBITDA.related costs.




Management’s Discussion and Analysis (Continued)


ImpairmentService revenues increased primarily due to:
A $98 million increase associated with the consolidation of certain assets changed favorablyUEOM;
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 absenceconsolidation of a $115UEOM;
A $10 million impairmentincrease related to transaction expenses associated with the acquisition of certain gathering operationsUEOM and the formation of the Northeast JV;
A $7 million accrual in the Marcellus South region.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 increased primarily due to decreased $37 million as a $26result of the consolidation of UEOM. This decrease was partially offset by a $20 million increase at Appalachia Midstream Investments, reflecting our increased ownership acquired in late first-quarter 2017 and higher volumes.
Atlantic-Gulf
Three Months Ended 
 September 30,
 Nine Months Ended 
 September 30,
Three Months Ended 
 September 30,
 Nine Months Ended 
 September 30,
2018 2017 2018 20172019 2018 2019 2018
(Millions)(Millions)
Service revenues$607
 $564
 $1,806
 $1,647
$731
 $607
 $2,138
 $1,806
Service revenues commodity consideration
18
 
 45
 
7
 18
 33
 45
Product sales131
 106
 329
 365
76
 131
 226
 329
Segment revenues756
 670
 2,180
 2,012
814
 756
 2,397
 2,180
              
Product costs(134) (97) (332) (328)(75) (134) (226) (332)
Processing commodity expenses(3) 
 (10) 
(2) (3) (12) (10)
Other segment costs and expenses(176) (207) (556) (566)(182) (176) (606) (556)
Proportional Modified EBITDA of equity-method investments49
 64
 136
 216
44
 49
 130
 136
Atlantic-Gulf Modified EBITDA$492
 $430
 $1,418
 $1,334
$599
 $492
 $1,683
 $1,418
              
NGL margin$12
 $7
 $30
 $30
Commodity margins$6
 $12
 $21
 $32


Management’s Discussion and Analysis (Continued)

Three months ended September 30, 20182019 vs. three months ended September 30, 20172018
Atlantic-Gulf Modified EBITDA increased primarily due to higher Service revenues and lower Other segment costs and expenses, partially offset by lower Proportional Modified EBITDA of equity-method investments.
Service revenues increased primarily due to a $34$143 million increase in Transco’s natural gas transportation fee revenues primarily driven by a $116 million increase related to expansion projects placed in service in 20172018 and 2018.
Service revenues commodity consideration increased2019, as a result of implementing ASC 606 using a modified retrospective approach. These revenues represent consideration we receive in the form of commoditieswell as full or partial paymentan adjustment associated with Transco’s reserve for gathering and processing services provided. Most of these NGL volumes are sold within the month processed and therefore are offset in Product costs below.
The increase in Product sales includes:
A $20 million increase in system management gas sales. System management gas sales are offset in Product costs and therefore have little impact to Modified EBITDA;
A $1 million increase in commodity marketing revenues driven by a $30 million increase in NGL marketing revenues reflecting 38 percent higher non-ethane prices and a 24 percent increase in non-ethane volumes, partially offset by a $29 million decrease in crude oil revenues as this activity is now presented on a net basis within Product costs in 2018 in conjunction with the adoption of ASC 606.
Product costs increased primarily due to a $21 million increase in system management gas costs (offset in Product sales) and the impact of ASC 606 in which costs reflected in this line item for 2018 include volumes acquired as commodity consideration for NGL processing services.rate refunds. This increase was partially offset by $21 million lower gathering and processing fees primarily due to maintenance downtime at Gulfstar, lower volumes at our Perdido Norte system in the absenceWestern Gulf of Mexico, and the sale of certain Gulf Coast pipeline assets in the fourth quarter of 2018. Additionally, certain of Transco’s natural gas purchases associated with the production of equity NGLs,transportation revenues, which are now reported in Processing commodity expenses in conjunction with the implementation of ASC 606.decreased due to lower rates effective October 2018, were substantially offset by higher revenue related to reimbursable power and storage expenses.


Management’s Discussion and Analysis (Continued)

Processing commodity expenses presents the natural gas purchases associated with the production of equity NGLs as previously described in conjunction with the implementation of ASC 606.
The net sum of Service revenues commodity consideration, Product sales, Product costs,, andProcessing commodity expenses comprise our commodity product margins.
Other segment costs and expenses decreased primarily due to a $16 million increase in Transco’s equity AFUDC and lower operating and maintenance costs including reduced hydrotesting related to certain compliance projects that occurred in 2017.
The decrease in Proportional Modified EBITDA of equity-method investments is due to an $18 million decrease at Discovery, primarily associated with production ending on certain wells.
Nine months ended September 30, 2018 vs. nine months ended September 30, 2017
Modified EBITDA increased primarily due to higher Service revenues, partially offset by lower Proportional Modified EBITDA of equity-method investments.
Service revenues increased primarily due to a $148 million increase in Transco’s natural gas transportation fee revenues driven by a $133 million increase associated with expansion projects placed in service in 2017 and 2018.
Service revenues commodity consideration increased as a result of implementing ASC 606 using a modified retrospective approach. These revenues represent consideration we receive in the form of commodities as full or partial payment for gathering and processing services provided. Most of these NGL volumes are sold within the month processed and therefore are offset in Product costs below.
The decrease in Product sales includes:
A $62 million decrease in commodity marketing revenues driven by a $119 million decrease in crude oil revenues as this activity is now presented on a net basis within Product costs in 2018 in conjunction with the adoption of ASC 606, partially offset by a $57 million increase in NGL marketing revenues reflecting 38 percent higher non-ethane prices and a 10 percent increase in non-ethane volumes;
A $43 million increase in system management gas sales. System management gas sales are offset in Product costs and therefore have little impact to Modified EBITDA.
Product costs increased primarily due to a $44 million increase in system management gas costs (offset in Product sales) and the impact of ASC 606 in which costs reflected in this line item for 2018 include volumes acquired as commodity consideration for NGL processing services. This increase was partially offset by a $59 million decrease in marketing purchases (more than offset in Product sales) and the absence of natural gas purchases associated with the production of equity NGLs, which are now reported in Processing commodity expenses in conjunction with the implementation of ASC 606.
Processing commodity expenses presents the natural gas purchases associated with the production of equity NGLs as previously described in conjunction with the implementation of ASC 606.
The net sum of Service revenues commodity consideration, Product sales, Product costs, and Processing commodity expenses comprise our commodity product margins.
Other segment costs and expenses decreased primarily due to a $25 million increase in Transco’s equity AFUDC and a net favorable adjustment to deferred–tax related regulatory liabilities associated with Tax Reform. These decreases are partially offset by higher operating and maintenance expense driven by a $15 million increase primarily associated with general maintenance and other testing and labor costs.
The decrease in Proportional Modified EBITDA of equity-method investments is due to an $81 million decrease at Discovery, primarily related to a $71 million decrease associated with production ending on certain wells.


Management’s Discussion and Analysis (Continued)

West
 Three Months Ended 
 September 30,
 Nine Months Ended 
 September 30,
 2018 2017 2018 2017
 (Millions)
Service revenues$533
 $544
 $1,599
 $1,589
Service revenues  commodity consideration
97
 
 257
 
Product sales732
 485
 1,822
 1,376
Segment revenues1,362
 1,029
 3,678
 2,965
        
Product costs(730) (438) (1,813) (1,263)
Processing commodity expenses(26) 
 (76) 
Other segment costs and expenses(219) (203) (637) (615)
Impairment of certain assets
 (1,021) 
 (1,022)
Proportional modified EBITDA of equity-method investments25
 18
 62
 61
West Modified EBITDA$412
 $(615) $1,214
 $126
        
NGL margin$60
 $37
 $165
 $104
Three months ended September 30, 2018 vs. three months ended September 30, 2017
Modified EBITDA increased primarily due to the absence of Impairment of certain assets in 2017 and higher commodity margins associated with our equity NGLs.
Service revenues decreased primarily due to:
A $12 million decrease related to the deconsolidation of Jackalope in second quarter 2018;
An $8 million decrease related to lower gathering volumes primarily in the Eagle Ford and Haynesville Shale regions;
A $6 million decrease at Northwest Pipeline primarily due to the reduction of its rates as a result of a rate case settlement that became effective January 1, 2018;
Offsetting changes primarily associated with implementing the new revenue guidance under ASC 606 including a $30 million decrease related to lower amortization of deferred revenue associated with the up-front cash payments received in conjunction with the fourth quarter 2016 Barnett Shale and Mid-Continent contract restructurings, offset by a $15 million increase related to the earlier recognition of revenues associated with MVCs and a $15 million increase related to other deferred revenue amortization primarily in the Permian basin;
A $9 million increase related to higher gathering and processing rates driven by higher NGL prices primarily in the Piceance region.
Service revenues commodity consideration increased as a result of implementing ASC 606 using a modified retrospective approach. These revenues represent consideration we receive in the form of commodities as full or partial payment for gathering and processing services provided. Most of these NGL volumes are sold within the month processed and therefore are offset in Product costs below.
The increase in Product sales includes:
A $207 million increase in marketing revenues primarily due to increases in realized product prices and volumes including a 29 percent increase in average non-ethane per-unit sales prices and a 41 percent increase in ethane prices, in addition to a 20 percent increase in NGL volumes (offset by higher Product costs);


Management’s Discussion and Analysis (Continued)

A $11 million increase in system management gas sales due to a change in presentation in accordance with ASC 606, which are offset in Product costs and, therefore, have no impact on Modified EBITDA.
The increase in Product costs includes the impact of ASC 606 in which costs reflected in this line item for 2018 include volumes acquired as commodity consideration for NGL processing services, as well as a $208 million increase in marketing purchases (offset in Product sales). The increase also includes a $12 million increase in system management gas costs (substantially offset in Product sales), partially offset by the absence of natural gas purchases associated with the production of equity NGLs, which are now reported in Processing commodity expenses in conjunction with the implementation of ASC 606.
Processing commodity expenses presents the natural gas purchases    associated with the production of equity NGLs as previously described in conjunction with the implementation of ASC 606.
The net sum of Service revenues commodity consideration, Product sales, Product costs, and Processing commodity expenses comprise our commodity product margins. Our commodity product margins associated with our equity NGLs decreased $7 million driven by unfavorable NGL prices. Additionally, the decrease in Product sales includes a $44 million decrease in commodity marketing sales due to lower NGL prices and volumes. Marketing sales are substantially offset in Product costs and therefore have little impact to Modified EBITDA.
Other segment costs and expensesincreased primarily due to a $23 million increaseunfavorable change in NGL product marginsequity AFUDC due to lower construction activity, an $11 million accrual in 2019 for estimated severance and related costs primarily associated with our VSP (see Note 6 – Other Income and Expenses of Notes to Consolidated Financial Statements), the absence of a $10 million 2018 gain on asset retirements, and higher reimbursable power and storage expenses at Transco. These unfavorable changes were partially offset by $33 million of net favorable changes to charges and credits associated with regulatory assets and liabilities, which were significantly driven by $16the previously mentioned agreement to the terms of a settlement in Transco’s general rate case (see Note 6 – Other Income and Expenses of Notes to Consolidated Financial Statements), and a $21 million decrease in Transco’s contracted services compared to 2018 mainly due to the timing of required engine overhauls and integrity testing.
Nine months ended September 30, 2019 vs. nine months ended September 30, 2018
Atlantic-Gulf Modified EBITDA increased primarily due to higher non-ethane margins, reflecting 19 percentService revenues, partially offset by higher realized non-ethane prices and 20 percent lower realized natural gas prices.
Other segment costs and expensesexpenses.
Service revenues increased primarily due to a $361 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.
The net sum of Service revenues commodity consideration, Product sales, Product costs, and Processing commodity expenses comprise our commodity product margins. Our commodity product margins associated with our equity NGLs decreased $12 million driven by unfavorable NGL prices, partially offset by higher volumes. Additionally, the decrease in 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 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 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 by


Management’s Discussion and Analysis (Continued)

A $13 million increase related to a decrease in natural gas purchases associated with lower equity NGL production volumes and lower natural gas prices.
Additionally, the decrease in Product sales includes a $263 million decrease in marketing sales, which is due to lower sales prices, partially offset by higher sales volumes, a $14 million decrease related to the sale of other products, and a $7 million decrease in system management gas sales. 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.
ImpairmentProportional Modified EBITDA of certain assetsequity-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 a $1.019 billion impairmentEBITDA of certain gatheringof 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 Mid-Continent region in 2017.
Proportional modified EBITDA of equity-method investments increased primarily due to the deconsolidation of Jackalope in the second quarter of 2018, such that we now use the equity method of accounting for this investment.
Nine months ended September 30, 2018 vs. nine months ended September 30, 2017
Modified EBITDA increased primarily due to the absence of Impairment of certain assets in 2017 and higher commodity margins driven by an increase in equity NGL margins, partially offset by higher Other segment costs and expenses.
Service revenues increased primarily due to:
A $23 million increase associated with an increase in gathering and processing rates driven by higher NGL prices primarily in the Piceance region as well as higher average gathering and processing rates across most other areas, partially offset by declining contract rates primarily in the HaynesvilleBarnett Shale region;
A $17$19 million increasedecrease driven by higherlower gathering volumes primarily in the HaynesvilleMid-Continent, Barnett Shale, and Wamsutter regions;
An $18 million decrease associated with lower rates primarily driven by lower commodity pricing in the Piceance Niobrara,region and Permian regions,the transition from a cost-of-service to fixed-fee rate for a certain customer contract in the Mid-Continent region; partially offset by lower volumes
A $26 million increase in the Eagle Fordother fee revenues driven by higher fractionation and Barnett Shale regions;storage fees;
Offsetting changes primarily associated with implementing the new revenue guidance under ASC 606 including an $89An $11 million decrease related to lower amortization of deferred revenueincrease associated with the up-front cash payments received in conjunction with the fourth quarter 2016 Barnett Shale and Mid-Continent contract restructurings, offset byexpected resolution of a $49prior period performance obligation;
An $11 million increase related to the earlier recognition of revenues associated with MVCs and a $40 million increase related tohigher other deferred revenue amortization primarily in the Permian basin;MVC deficiency fee revenues.
A $22 million decrease at Northwest Pipeline primarily due to the reduction of its rates as a result of a rate case settlement that became effective January 1, 2018;
A $12 million decrease related to the Jackalope deconsolidation in second quarter 2018.


Management’s Discussion and Analysis (Continued)

Service revenues commodity consideration increased as a result of implementing ASC 606 using a modified retrospective approach. These revenues represent consideration we receive in the form of commodities as full or partial payment for gathering and processing services provided. Most of these NGL volumes are sold within the month processed and therefore are offset in Product costs below.
The increase in Product sales includes:
A $336 million increase in marketing revenues primarily due to increases in realized NGL prices including a 29 percent increase in average non-ethane per-unit sales prices and a 23 percent increase in ethane prices, in addition to a 19 percent increase in ethane volumes (substantially offset by higher Product costs);
A $36 million increase in system management gas sales due to a change in presentation in accordance with ASC 606, which are offset in Product costs and, therefore, have no impact on Modified EBITDA.
The increase in Product costs includes the impact of ASC 606 in which costs reflected in this line item for 2018 include volumes acquired as commodity consideration for NGL processing services, a $323 million increase in marketing purchases (more than offset in Product sales), a $38 million increase in system management gas costs (substantially offset in Product sales), partially offset by the absence of natural gas purchases associated with the production of equity NGLs, which are now reported in Processing commodity expenses in conjunction with the implementation of ASC 606.
Processing commodity expenses presents the natural gas purchases associated with the production of equity NGLs as previously described in conjunction with the implementation of ASC 606.
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 increasedassociated 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 $61$124 million increase in NGL product margins and a $13 million increase in marketing margins. NGL margins are driven by $52 million in higher non-ethane margins, reflecting 19 percent higher realized non-ethane prices and 25 percent lower realized natural gas prices.
Other segment costs and expenses increased primarily due to an $18 million regulatory chargereduction associated with Northwest Pipeline’s approved rates related to Tax Reform,the absences of our former Four Corners area assets and from the Jackalope deconsolidation in second-quarter 2018, as well as the absence of a $15 million gain from contract settlements and terminations in 2017, and a2018 unfavorable charge of $12 million charge 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 $20an unfavorable accrual in 2019 for estimated severance and related costs of $16 million lower operatingprimarily associated with our VSP (see Note 6 – Other Income and maintenanceExpensesof Notes to Consolidated Financial Statements) and general and administrative costs reflecting ongoing cost containment efforts.the absence of a $7 million favorable adjustment to the regulatory liability associated with Tax Reform at Northwest Pipeline in first-quarter 2018.
Impairment of certain assets decreased increased primarily due to the absence of a $1.019 billion$59 million impairment of certain Eagle Ford Shale gathering operationsassets 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).
Proportional Modified EBITDA of equity-method investments increased primarily due to the additions of the RMM and Brazos Permian II equity-method investments in the Mid-Continent region in 2017.second half of 2018.
Other
 Three Months Ended September 30, Nine Months Ended September 30,
 2018 2017 2018 2017
 (Millions)
Other Modified EBITDA$6
 $1,009
 $(49) $1,100
 Three Months Ended September 30, Nine Months Ended September 30,
 2019 2018 2019 2018
 (Millions)
Other Modified EBITDA$(2) $6
 $1
 $(49)
Three months ended September 30, 20182019 vs. three months ended September 30, 20172018
Other Modified EBITDA decreased primarily due to:
The absence of a $1.095 billion gain$37 million benefit from establishing 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 the sale of our Geismar Interest in 2017;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 1112 – 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)


$15Nine months ended September 30, 2019 vs. nine months ended September 30, 2018
Other Modified EBITDA increased primarily due to:
The absence of the $66 million impairment of certain idle pipelines in the second quarter of 2018 (see Note 13 – Fair Value Measurements and Guarantees of Notes to Consolidated Financial Statements);
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.Merger in 2018;
The absence of a 2018 loss on early retirement of debt of $7 million in the first quarter of 2018.
These decreasesincreases were partially offset by:
The absence of a $68$37 million impairment forbenefit associated with a certain NGL pipelineregulatory asset in the third quarter of 2017;2018 as detailed above;
A $37 million increase associated with the benefit of establishing a regulatory asset associated with an increase in Transco’s estimated deferred state income tax rate following the WPZ Merger;
A $14 million increase in income associated with a regulatory asset related to deferred taxes on equity funds used during construction;
The absence of $10 million of severance-related and strategic alternative costs in 2017;
The absence of $8 million of costs in 2017 associated with our former Geismar olefins plant.
Nine Months Ended September 30, 2018 vs. nine months ended September 30, 2017
Modified EBITDA decreased primarily due to:
The absence of a $1.095 billion gain on the sale of our Geismar Interest in 2017;
The absence of $70 million of Modified EBTIDA associated with the olefin operations that were sold in 2017;
A $35 million charge associated with a charitable contribution of preferred stock to The Williams Companies Foundation, Inc. (a not-for-profit corporation) (see Note 11 – Stockholders’ Equity of Notes to Consolidated Financial Statements);
A $34 million decrease due to the absence of a net gain on early retirement of debt in 2017 and a loss on early retirement of debt in 2018 (see Note 6 – Other Income and Expenses of Notes to Consolidated Financial Statements);
$19 million in costs associated with the WPZ Merger (see Note 6 – Other Income and Expenses of Notes to Consolidated Financial Statements);
A $13$21 million decrease in income associated with a regulatory asset related to deferred taxes on equity funds used during construction;
The absence of aA $12 million gain on the sale of the Refinery Grade Propylene Splitter in 2017 (see Note 6 – Other Income and Expenses of Notesunfavorable change to Consolidated Financial Statements).
These decreases were partially offset by:
The absence of a $68 million impairment for a certain NGL pipeline asset in the third quarter of 2017 and a$23 million impairment of an olefins pipeline project in the Gulf Coast region in the second quarter of 2017, partially offset by a $66 million impairment of certain idle pipelines in the second quarter of 2018 (see Note 12 – Fair Value Measurements and Guarantees of Notes to Consolidated Financial Statements);
A $37 million increase associated with the benefit of establishing a regulatory asset associated with an increase in Transco’s estimated deferred state income tax rate followingin the WPZ Merger;first quarter of 2019;
$37A $9 million accrual in the third quarter of lower costs, driven by the absence of expenses associated with severance and related costs, Financial Repositioning, and strategic alternative costs (see Note 1 – General, Description of Business, and Basis of Presentation of Notes to Consolidated Financial Statements).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 consolidated growth capital and investment expenditures in 20182019 are currently expected to be at least $3.9in a range from $2.3 billion to $2.5 billion. Approximately $1.8 billion of our growthGrowth capital funding needs includespending in 2019 includes Transco expansions, and other interstate pipeline growth projects, mostall of which are fully contracted with firm transportation agreements. The remaining growth capital spending in 2018 primarily reflects investment inagreements, and continuing to develop our gathering and processing systemsinfrastructure in the Northeast G&P segment limited primarily to known new producer volumes, including volumes that support Transco expansion projects including our Atlantic Sunrise project, and funding for growth investment opportunities as they arise such as our investment in RMM in the West segment.segments. 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 theour planned 20182019 growth capital with retained cash flow debt, and proceeds from asset sales.certain sources of available liquidity described below. 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 funded the $741 million total consideration paid, including post-closing adjustments, for our March 2019 acquisition of the remaining interest in UEOM with credit facility borrowings and cash on hand. In June 2019, we received approximately $1.33 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 reduce debt and fund capital growth.
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 2018.2019. Our potential material internal and external sources and uses of consolidated liquidity for 20182019 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 September 30, 2018,2019, we had a working capital deficit of $777 million.$1.89 billion, including cash and cash equivalents. Our available liquidity is as follows:
Available LiquiditySeptember 30, 2018September 30, 2019
(Millions)(Millions)
Cash and cash equivalents$42
$247
Capacity available under our $4.5 billion credit facility, less amounts outstanding under our $4 billion commercial paper program (1)3,676
4,500
$3,718
$4,747
 
(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. Through completion of the WPZ Merger on August 10, 2018, the highest combined amount outstanding under WPZ’sWe had no commercial paper program and credit facility and our former credit facility during 2018 was $1.325 billion. In July 2018, we along with Transco and Northwest Pipeline entered into a new unsecured revolving credit agreement with aggregate commitments availableoutstanding as of $4.5 billion under the credit facility, which became effective upon completion of the WPZ Merger.September 30, 2019. Through September 30, 2018,2019, the highest amount outstanding under our current commercial paper program and credit facility during 20182019 was $886 million.$1.226 billion. At September 30, 2018,2019, we were in compliance with the financial covenants associated with our credit facility. Borrowing capacity available under our credit facility as of October 30, 2018, was $4.5 billion.
Dividends
We increased our regular quarterly cash dividend to common stockholders by approximately 1312 percent from the previous quarterly cash dividends of $0.30$0.34 per share paid in each quarter of 2017,2018, to $0.34$0.38 per share for the quarterly cash dividends paid in March, June, and September 2018.2019.
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.
In February 2018, WPZ filed a shelf registration statement, as a well-known seasoned issuer, registering common units representing limited partner interests and debt securities. Also in February 2018, WPZ filed a shelf registration statement for the offer and sale from time to time of common units representing limited partner interests in WPZ having an aggregate offering price of up to $1 billion. In August 2018, these registration statements were terminated in conjunction with the WPZ Merger.
In September 2016, WPZ filed a registration statement for its distribution reinvestment program. In August 2018, this registration statement was terminated in conjunction with the WPZ Merger.
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.


Management’s Discussion and Analysis (Continued)

Credit Ratings
Our abilityThe interest rates at which we are able to borrow money isare 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 NegativeStable BBB BBB
Moody’s Investors Service Stable Baa3 N/A
Fitch Ratings Rating Watch Positive BBB- N/A
Following the completion of the WPZ Merger, in August 2018, all three credit rating agencies upgraded the ratings as noted in the table above.In July 2019, S&P Global Ratings changed its Outlook from Negative 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,
 Category 2018 2017
   (Millions)
Sources of cash and cash equivalents:     
Operating activities – netOperating $2,331
 $2,231
Proceeds from long-term debt (see Note 10)Financing 2,065
 1,698
Proceeds from credit-facility borrowingsFinancing 1,680
 1,315
Proceeds from commercial paper – netFinancing 821
 
Contributions in aid of constructionInvesting 395
 253
Proceeds from equity issuancesFinancing 15
 2,130
Proceeds from sale of businesses, net of cash divested (see Note 4)Investing 
 2,056
Proceeds from dispositions of equity-method investments (see Note 5)Investing 
 200
      
Uses of cash and cash equivalents:     
Capital expendituresInvesting (2,659) (1,700)
Payments on credit-facility borrowingsFinancing (1,950) (1,690)
Payments of long-term debt (see Note 10)Financing (1,251) (3,785)
Common dividends paidFinancing (974) (744)
Purchases of and contributions to equity-method investmentsInvesting (803) (103)
Dividends and distributions paid to noncontrolling interestsFinancing (552) (636)
Payments of commercial paper – netFinancing 
 (93)
      
Other sources / (uses) – netFinancing and Investing 25
 (130)
Increase (decrease) in cash and cash equivalents  $(857) $1,002


Management’s Discussion and Analysis (Continued)

 Cash Flow Nine Months Ended 
 September 30,
 Category 2019 2018
   (Millions)
Sources of cash and cash equivalents:     
Operating activities – netOperating $2,702
 $2,331
Proceeds from sale of partial interest in consolidated subsidiary (see Note 2)Financing 1,330
 
Proceeds from credit-facility borrowingsFinancing 700
 1,680
Proceeds from dispositions of equity-method investments (see Note 5)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:     
Capital expendituresInvesting (1,705) (2,659)
Common dividends paidFinancing (1,382) (974)
Payments on credit-facility borrowingsFinancing (860) (1,950)
Purchases of businesses, net of cash acquired (see Note 2)Investing (728) 
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
Increase (decrease) in cash and cash equivalents  $79
 $(857)
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) loss on disposition of equity-method investments, GainImpairment of equity-method investments, (Gain) loss on saledeconsolidation of Geismar Interestbusinesses, and Impairment of and net (gain) loss on sale of certain assets. Our Net cash provided (used) by operating activities for the nine months ended September 30, 2018,2019, increased from the same period in 20172018 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 2018,2019, partially offset by the impact of net unfavorable changes in operating working capital and decreased distributions from unconsolidated affiliates in 2018.2019.
Off-Balance Sheet Arrangements and Guarantees of Debt or Other Commitments
We have various other guarantees and commitments which are disclosed in Note 34 – Variable Interest Entities, Note 1011 – Debt and Banking Arrangements, Note 1213 – Fair Value Measurements and Guarantees, and Note 1314 – 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
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 nine months of 2018.2019.


Item 4
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 third quarter of 20182019 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 recently 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 EPA could issue penalties pertaining to final determinations.Court set a fairness hearing on the settlement for December 11, 2019.
On February 21, 2017, we received notice from the Environmental Enforcement Section of the United States Department of Justice (DOJ) regarding certain alleged violations of the Clean Air Act at our Moundsville facility as set forth in 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 evaluatingcontinuing to work with the agencies’ offer.agencies to resolve this matter.
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 theTransco’s Dalton Project.expansion project. Pursuant to the Consent Order, we paid a fine of $168,750 and agreed to perform a Corrective Action Plan, the completion of which is pending.
On January 19, 2018, we received notice from the United States Department of Transportation Pipeline and Hazardous Materials Safety Administration (PHMSA) regarding certain alleged violations of PHMSA regulations in connection with a fire and release of liquid ethane that occurred at our Houston Meter Station located near Houston, Washington County, Pennsylvania, on December 24, 2014. The Notice of Probable Violation and Proposed Civil Penalty issued by PHMSA alleges failure to timely notify the National Response Center of a release of a hazardous liquid resulting in a fire or explosion and failure to verify that the facility was constructed, inspected, tested, and calibrated in accordance with comprehensive written specifications or standards and proposes a total civil penalty of $174,100. We have since paid the proposed civil penalty and have resolved this matter.
On March 19, 2018, we received a Notice of Violation from the EPA, Region 8, regarding certain alleged violations of the Clean Air Act at our former Ignacio Gas Plant in Durango, Colorado, following a previous 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, regarding certain alleged violations of the Clean Air Act at our Parachute Creek Gas Plant in Parachute, Colorado, following a previous on-site inspection 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 the alleged violations and continue to work with the agencies to resolve this matter.
On August 27, 2018, Northwest Pipeline LLC received a Notice of Violation/Cease 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.
Other environmental matters called for by this Item are described under the caption “Environmental Matters” in Note 1314 – 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 Litigationlitigation
The additional information called for by this Item is provided in Note 1314 – 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, 2017 and Part II, Item 1A. Risk Factors in our Quarterly Report on Form 10-Q for the quarter ended June 30, 2018, includeincludes risk factors that could materially affect our business, financial condition, or future results. Those risk factors have not materially changed, except, as stated below:changed.


The following risk factor is now applicable:


A current ballot measure in Colorado may adversely impact our financial condition and results of operations if passed.

On November 6, 2018, citizens of Colorado will vote on Proposition 112, a ballot measure that could significantly increase setback distances from occupied structures or other vulnerable areas, as defined or designated, for any new oil and gas development in the state, critically restricting or banning such activities.  If the measure is approved, it could still be subject to modification or amendment by the Colorado legislature. An unfavorable outcome could adversely impact the operations, and ultimately the value, of our businesses and investments in Colorado, including our recent investment in RMM.  Any such impact may have an adverse effect on our business, financial condition, results of operations and our cash flows.

With the August 10, 2018 consummation of the WPZ Merger, certain risk factors, identified by the captions stated below, are no longer applicable:

Our cash flow is heavily dependent on the earnings and distributions of WPZ.

One of our subsidiaries acts as the general partner of a publicly traded limited partnership, Williams Partners L.P. As such, this subsidiary’s operations may involve a greater risk of liability than ordinary business operations.

Our ability to obtain credit in the future could be affected by WPZ’s credit ratings.

The FERC recently issued a policy statement that reversed its 2005 income tax policy that permitted master limited partnership (MLP) interstate oil and natural gas pipelines to recover an income tax allowance in cost of service rates, which if implemented, may adversely impact our financial condition and future results of operations.

The WPZ Merger is subject to closing conditions that, if not satisfied or waived, will result in the WPZ Merger not being consummated, which may cause the market price of our common stock and/or the WPZ Units to decline.

The WPZ Merger Agreement contains provisions that limit our ability to pursue alternatives to the WPZ Merger, could discourage a potential competing acquirer of us from making a favorable alternative acquisition proposal and, in specified circumstances under the WPZ Merger Agreement, require us to pay a termination fee of $410 million to Williams Partners.

If the Charter Amendment is approved, we will be able to issue more shares of Williams common stock than are expected to be outstanding immediately after the WPZ Merger is completed. Any future issuances of our common stock may have a dilutive effect on the earnings per share and voting power of our stockholders.




Item 6.  Exhibits

Exhibit
No.
   Description
     
2.1+  
2.2  
2.3+  
2.4+
3.1  
3.2 

 
3.3 

 
3.4  
4.1
4.2
10.1
10.2


Exhibit
No.
Description
31.1*  
31.2*  
32**  
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.
*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
 Ted T. Timmermans
 Vice President, Controller and Chief Accounting Officer (Duly Authorized Officer and Principal Accounting Officer)
November 1, 2018October 31, 2019