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, 2017March 31, 2018
or
¨TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from _____________ to _____________
Commission file number 1-4174
THE WILLIAMS COMPANIES, INC.
(Exact name of registrant as specified in its charter)
DELAWARE 73-0569878
(State or other jurisdiction of incorporation or organization) (I.R.S. Employer Identification No.)
   
ONE WILLIAMS CENTER  
TULSA, OKLAHOMA 74172-0172
(Address of principal executive offices) (Zip Code)
Registrant’s telephone number, including area code: (918) 573-2000
NO CHANGE
 
(Former name, former address and former fiscal year, if changed since last report.)
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No ¨
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). Yes þ No ¨
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer þ
 
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 ¨ No þ
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 OctoberApril 30, 20172018
Common Stock, $1 par value 826,746,549827,610,837
 



The Williams Companies, Inc.
Index


  Page
Part I. Financial Information
  
Item 1. Financial Statements
  
Consolidated Statement of OperationsIncome – Three and Nine Months Ended September 30,March 31, 2018 and 2017 and 2016
 
6
Consolidated Statement of Comprehensive Income (Loss) – Three and Nine Months Ended September 30,March 31, 2018 and 2017 and 2016
 
7
Consolidated Balance Sheet – September 30, 2017March 31, 2018 and December 31, 20162017
 
8
Consolidated Statement of Changes in Equity – NineThree Months Ended September 30, 2017March 31, 2018
 
9
Consolidated Statement of Cash Flows – NineThree Months Ended September 30,March 31, 2018 and 2017 and 2016
 
10
Notes to Consolidated Financial Statements
 
11
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
 
3738
Item 3. Quantitative and Qualitative Disclosures About Market Risk
 
6155
Item 4. Controls and Procedures
 
6155
Part II. Other Information
 
6155
Item 1. Legal Proceedings
 
6155
Item 1A. Risk Factors
57
Item 6. Exhibits
 
6358

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:

Expected levels of cash distributions by Williams Partners L.P. (WPZ) with respect to limited partner interests;

Levels of dividends to Williams stockholders;

Future credit ratings of Williams, WPZ, and their 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 WPZ will produce sufficient cash flows to provide expected levels of cash distributions;

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

Whether WPZ elects to pay expected levels of cash distributions and we elect to pay expected levels of dividends;

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

Whether we will be able to effectively manage the transition in our board of directors and management as well as successfully execute our business restructuring;

Availability of supplies, including lower than anticipated volumes from third parties served by our business, and market demand;

Volatility of pricing including the effect of lower than anticipated energy commodity prices and margins;

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 other investment opportunities in accordance with our forecasted capital expenditures budget;

Our ability to successfully expand our facilities and operations;

Development and rate of adoption of alternative energy sources;



The impact of operational and developmental hazards, unforeseen interruptions, and the availability of adequate insurance coverage;



The impact of existing and future laws (including, but not limited to, the Tax Cuts and Job Acts of 2017), regulations (including, but not limited to, the FERC’s “Revised Policy Statement on Treatment of Income Taxes” in Docket No. PL17-1-000), 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;

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-recognizednationally 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, including cybersecurity threats, 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, 2017.2018, and in Part II, Item 1A. Risk Factors in this Quarterly Report on Form 10-Q.



DEFINITIONS

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

Measurements:
Barrel: One barrel of petroleum products that equals 42 U.S. gallons
Bcf: One billion cubic feet of natural gas
Bcf/d: One billion cubic feet of natural gas per day
British Thermal Unit (Btu): A unit of energy needed to raise the temperature of one pound of water by one degree
Fahrenheit
Dekatherms (Dth): A unit of energy equal to one million British thermal units
Mbbls/d: One thousand barrels per day
Mdth/d: One thousand dekatherms per day
MMcf/d: One million cubic feet per day
MMdth: One million dekatherms or approximately one trillion British thermal units
MMdth/d: One million dekatherms per day
Tbtu: One trillion British thermal units
Consolidated Entities:
Cardinal: Cardinal Gas Services, L.L.C.
Constitution: Constitution Pipeline Company, LLC
Gulfstar One: Gulfstar One LLC
Jackalope: Jackalope Gas Gathering Services, L.L.C.
Northwest Pipeline: Northwest Pipeline LLC
Transco: Transcontinental Gas Pipe Line Company, LLC
WPZ: Williams Partners L.P.
Partially Owned Entities: Entities in which we do not own a 100 percent ownership interest and which, as of September 30, 2017,March 31, 2018, we account for as an equity-method investment, including principally the following:
Aux Sable: Aux Sable Liquid Products LP
Caiman II: Caiman Energy II, LLC
Discovery: Discovery Producer Services LLC
Gulfstream: Gulfstream Natural Gas System, L.L.C.
Laurel Mountain: Laurel Mountain Midstream, LLC
OPPL: Overland Pass Pipeline Company 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:
Merger Agreement: Merger Agreement and Plan of Merger of Williams with Energy Transfer 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
Merger Agreement: Merger Agreement and Plan of Merger of Williams with Energy Transfer Equity, L.P and certain of its affiliates
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
PDH facility: Propane dehydrogenation facility
RGP Splitter:Throughput Refinery grade propylene splitter: The volume of product transported or passing through a pipeline, plant, terminal, or other facility





PART I – FINANCIAL INFORMATION

The Williams Companies, Inc.
Consolidated Statement of OperationsIncome
(Unaudited)
Three Months Ended 
 September 30,		 Nine Months Ended 
 September 30,		Three Months Ended 
 March 31,
2017 2016 2017 20162018 2017
(Millions, except per-share amounts)(Millions, except per-share amounts)
Revenues:          
Service revenues$1,310
 $1,247
 $3,853

$3,678
$1,351

$1,261
Service revenues – commodity consideration (Note 2)101
 —
Product sales581
 658
 1,950

1,623
636

727
Total revenues1,891
 1,905
 5,803

5,301
2,088

1,988
Costs and expenses:  
 





Product costs504
 461
 1,620

1,180
613

579
Processing commodity expenses (Note 2)35
 —
Operating and maintenance expenses400
 394
 1,157

1,179
357

371
Depreciation and amortization expenses433
 435
 1,308

1,326
431

442
Selling, general, and administrative expenses138
 177
 452

556
132

161
Gain on sale of Geismar Interest (Note 3)(1,095) —
 (1,095) —
Impairment of certain assets (Note 11)1,210
 1
 1,236
 811
Other (income) expense – net24
 92
 34

130
29

5
Total costs and expenses1,614
 1,560
 4,712

5,182
1,597

1,558
Operating income (loss)277
 345
 1,091

119
491

430
Equity earnings (losses)115
 104
 347

302
82

107
Impairment of equity-method investments (Note 11)—
 —
 —
 (112)
Other investing income (loss) – net (Note 4)4
 28
 278
 64
4
 272
Interest incurred(275)
(304)
(842)
(916)(282)
(287)
Interest capitalized8

7

24

30
9

7
Other income (expense) – net20
 20
 115

52
21

77
Income (loss) before income taxes149
 200
 1,013

(461)325

606
Provision (benefit) for income taxes24
 69
 126

(74)55

37
Net income (loss)125
 131
 887

(387)270

569
Less: Net income (loss) attributable to noncontrolling interests92
 70
 400

22
118

196
Net income (loss) attributable to The Williams Companies, Inc.$33
 $61
 $487

$(409)$152

$373
Amounts attributable to The Williams Companies, Inc.:          
Basic earnings (loss) per common share:          
Net income (loss)$.04
 $.08
 $.59
 $(.55)$.18
 $.45
Weighted-average shares (thousands)826,779
 750,754
 825,925
 750,579
827,509
 824,548
Diluted earnings (loss) per common share:          
Net income (loss)$.04
 $.08
 $.59
 $(.55)$.18
 $.45
Weighted-average shares (thousands)829,368
 751,858
 828,150
 750,579
830,197
 826,476
Cash dividends declared per common share$.30
 $.20
 $.90
 $1.48
$.34
 $.30

See accompanying notes.


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

Three Months Ended 
 September 30,		 Nine Months Ended 
 September 30,		Three Months Ended 
 March 31,
2017 2016 2017 20162018 2017
(Millions)(Millions)
Net income (loss)$125
 $131
 $887
 $(387)$270
 $569
Other comprehensive income (loss):          
Cash flow hedging activities:          
Net unrealized gain (loss) from derivative instruments, net of taxes of $2 and $1 in 2017(9) 2
 (5) 2
Reclassifications into earnings of net derivative instruments (gain) loss, net of taxes of $1 and $1 in 20172
 —
 —
 —
Foreign currency translation activities:       
Foreign currency translation adjustments, net of taxes of ($25) and ($37) in 2016—
 (49) —
 50
Reclassification into earnings upon sale of foreign entities, net of taxes of ($36) in 2016.—
 119
 —
 119
Net unrealized gain (loss) from derivative instruments, net of taxes of $0 in 2018 and ($1) in 20171
 3
Pension and other postretirement benefits:          
Amortization of prior service cost (credit) included in net periodic benefit cost, net of taxes of $1 and $2 in 2017 and $0 and $1 in 2016—
 (1) (2) (3)
Net actuarial gain (loss) arising during the year, net of taxes of $2 in 2016—

—

—

(3)
Amortization of actuarial (gain) loss included in net periodic benefit cost, net of taxes of ($2) and ($7) in 2017 and ($3) and ($9) in 20164
 5
 13
 15
Amortization of prior service cost (credit) included in net periodic benefit cost (credit)—
 (1)
Amortization of actuarial (gain) loss included in net periodic benefit cost (credit), net of taxes of ($1) in 2018 and ($3) in 20175
 4
Other comprehensive income (loss)(3) 76
 6
 180
6
 6
Comprehensive income (loss)122
 207
 893
 (207)276
 575
Less: Comprehensive income (loss) attributable to noncontrolling interests89
 108
 398
 91
119
 197
Comprehensive income (loss) attributable to The Williams Companies, Inc.$33
 $99
 $495
 $(298)$157
 $378
See accompanying notes.



The Williams Companies, Inc.
Consolidated Balance Sheet
(Unaudited)
 September 30,
2017		 December 31,
2016		 March 31,
2018		 December 31,
2017
 (Millions, except per-share amounts) (Millions, except per-share amounts)
ASSETS    
Current assets:        
Cash and cash equivalents $1,172
 $170
 $1,292
 $899
Trade accounts and other receivables (net of allowance of $6 at September 30, 2017 and $6 at December 31, 2016) 783
 938
Trade accounts and other receivables (net of allowance of $10 at March 31, 2018 and $9 at December 31, 2017) 743
 976
Inventories 144
 138
 160
 113
Other current assets and deferred charges 194
 216
 204
 191
Total current assets 2,293
 1,462
 2,399
 2,179
Investments 6,615
 6,701
 6,513
 6,552
Property, plant, and equipment 38,712
 38,912
 40,467
 39,513
Accumulated depreciation and amortization (11,003) (10,484) (11,620) (11,302)
Property, plant, and equipment – net 27,709
 28,428
 28,847
 28,211
Intangible assets – net of accumulated amortization 8,873
 9,663
 8,644
 8,791
Regulatory assets, deferred charges, and other 630
 581
 649
 619
Total assets $46,120
 $46,835
 $47,052
 $46,352
LIABILITIES AND EQUITY        
Current liabilities:        
Accounts payable $773
 $623
 $776
 $978
Accrued liabilities 1,079
 1,448
 887
 1,167
Commercial paper —
 93
Long-term debt due within one year 502
 785
 501
 501
Total current liabilities 2,354
 2,949
 2,164
 2,646
Long-term debt 20,567
 22,624
 21,379
 20,434
Deferred income tax liabilities 5,211
 4,238
 3,196
 3,147
Regulatory liabilities, deferred income, and other 3,106
 2,978
 4,410
 3,950
Contingent liabilities (Note 12) 
 
 
 
Equity:        
Stockholders’ equity:        
Common stock (960 million shares authorized at $1 par value;
861 million shares issued at September 30, 2017 and 785 million shares
issued at December 31, 2016)		 861
 785
Common stock (960 million shares authorized at $1 par value;
862 million shares issued at March 31, 2018 and 861 million shares
issued at December 31, 2017)		 862
 861
Capital in excess of par value 18,492
 14,887
 18,533
 18,508
Retained deficit (9,872) (9,649) (8,587) (8,434)
Accumulated other comprehensive income (loss) (331) (339) (294) (238)
Treasury stock, at cost (35 million shares of common stock) (1,041) (1,041) (1,041) (1,041)
Total stockholders’ equity 8,109
 4,643
 9,473
 9,656
Noncontrolling interests in consolidated subsidiaries 6,773
 9,403
 6,430
 6,519
Total equity 14,882
 14,046
 15,903
 16,175
Total liabilities and equity $46,120
 $46,835
 $47,052
 $46,352
See accompanying notes.


The Williams Companies, Inc.
Consolidated Statement of Changes in Equity
(Unaudited)

The Williams Companies, Inc., Stockholders    The Williams Companies, Inc., Stockholders    
Common
Stock
 
Capital in
Excess of
Par Value
 
Retained
Deficit
 
Accumulated
Other
Comprehensive
Income (Loss)
 
Treasury
Stock
 
Total
Stockholders’
Equity
 
Noncontrolling
Interests
 Total Equity
Common
Stock
 
Capital in
Excess of
Par Value
 
Retained
Deficit
 
Accumulated
Other
Comprehensive
Income (Loss)
 
Treasury
Stock
 
Total
Stockholders’
Equity
 
Noncontrolling
Interests
 Total Equity
(Millions)(Millions)
Balance – December 31, 2016$785
 $14,887
 $(9,649) $(339) $(1,041) $4,643
 $9,403
 $14,046
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)—
 —
 487
 —
 —
 487
 400
 887
—
 —
 152
 —
 —
 152
 118
 270
Other comprehensive income (loss)—
 —
 —
 8
 —
 8
 (2) 6
—
 —
 —
 5
 —
 5
 1
 6
Issuance of common stock (Note 10)75
 2,043
 —
 —
 —
 2,118
 —
 2,118
Cash dividends – common stock—
 —
 (744) —
 —
 (744) —
 (744)—
 —
 (281) —
 —
 (281) —
 (281)
Dividends and distributions to noncontrolling interests—
 —
 —
 —
 —
 —
 (679) (679)—
 —
 —
 —
 —
 —
 (187) (187)
Stock-based compensation and related common stock issuances, net of tax1
 59
 —
 —
 —
 60
 —
 60
1
 18
 —
 —
 —
 19
 —
 19
Adoption of ASU 2016-09 (Note 1)—
 1
 36
 —
 —
 37
 —
 37
Sales of limited partner units of Williams Partners L.P.—
 —

—

—

—

—

43

43
—
 —
 —
 —
 —
 —
 22
 22
Changes in ownership of consolidated subsidiaries, net—
 1,497
 —
 —
 —
 1,497
 (2,404) (907)—
 7
 —
 —
 —
 7
 (9) (2)
Contributions from noncontrolling interests—
 —
 —
 —
 —
 —
 15
 15
—
 —
 —
 —
 —
 —
 3
 3
Other—
 5
 (2) —
 —
 3
 (3) —
—
 —
 (1) —
 —
 (1) —
 (1)
Net increase (decrease) in equity76
 3,605
 (223) 8
 —
 3,466
 (2,630) 836
1
 25
 (153) (56) —
 (183) (89) (272)
Balance – September 30, 2017$861
 $18,492
 $(9,872) $(331) $(1,041) $8,109
 $6,773
 $14,882
Balance – March 31, 2018$862
 $18,533
 $(8,587) $(294) $(1,041) $9,473
 $6,430
 $15,903
See accompanying notes.



The Williams Companies, Inc.
Consolidated Statement of Cash Flows
(Unaudited)
Nine Months Ended 
 September 30,		Three Months Ended 
 March 31,
2017 20162018 2017
(Millions)(Millions)
OPERATING ACTIVITIES:  
Net income (loss)$887
 $(387)$270
 $569
Adjustments to reconcile to net cash provided (used) by operating activities:      
Depreciation and amortization1,308
 1,326
431
 442
Provision (benefit) for deferred income taxes99
 (74)73
 28
Equity (earnings) losses(82) (107)
Distributions from unconsolidated affiliates140
 190
Net (gain) loss on disposition of equity-method investments(269) —
—
 (269)
Impairment of equity-method investments—
 112
Gain on sale of Geismar Interest (Note 3)(1,095) —
Impairment of and net (gain) loss on sale of assets and businesses1,225
 867
Amortization of stock-based awards61
 55
14
 21
Cash provided (used) by changes in current assets and liabilities:      
Accounts and notes receivable118
 172
238
 29
Inventories(23) (7)(40) (30)
Other current assets and deferred charges(11) (11)(4) 18
Accounts payable47
 (6)(197) 32
Accrued liabilities(161) 129
(166) (133)
Other, including changes in noncurrent assets and liabilities(349) (79)17
 (63)
Net cash provided (used) by operating activities1,837
 2,097
694
 727
FINANCING ACTIVITIES:      
Proceeds from (payments of) commercial paper – net(93) (499)—
 (93)
Proceeds from long-term debt3,013
 5,708
2,048
 470
Payments of long-term debt(5,475) (4,966)(1,060) (2,000)
Proceeds from issuance of common stock2,130
 8
10
 2,122
Dividends paid(744) (1,111)(281) (248)
Dividends and distributions paid to noncontrolling interests(636) (715)(165) (242)
Contributions from noncontrolling interests15
 27
3
 4
Payments for debt issuance costs(14) (8)(18) —
Contribution to Gulfstream for repayment of debt—
 (148)
Other – net(87) (16)(40) (28)
Net cash provided (used) by financing activities(1,891) (1,720)497
 (15)
INVESTING ACTIVITIES:      
Property, plant, and equipment:      
Capital expenditures (1)(1,700) (1,577)(957) (511)
Dispositions – net(27) 29
(1) (2)
Proceeds from sale of businesses, net of cash divested2,056
 712
Contributions in aid of construction190
 131
Proceeds from dispositions of equity-method investments200
 —
—
 200
Purchases of and contributions to equity-method investments(103) (132)(21) (52)
Distributions from unconsolidated affiliates in excess of cumulative earnings394
 341
Other – net236
 227
(9) (9)
Net cash provided (used) by investing activities1,056
 (400)(798) (243)
Increase (decrease) in cash and cash equivalents1,002
 (23)393
 469
Cash and cash equivalents at beginning of year170
 100
899
 170
Cash and cash equivalents at end of period$1,172
 $77
$1,292
 $639
_____________      
(1) Increases to property, plant, and equipment$(1,826) $(1,468)$(934) $(569)
Changes in related accounts payable and accrued liabilities126
 (109)(23) 58
Capital expenditures$(1,700) $(1,577)$(957) $(511)

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, 2016,2017, in Exhibit 99.1 of our Annual Report on Form 8-K dated May 25, 2017.10-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.
Financial Repositioning
In January 2017, we announcedentered into agreements with Williams Partners L.P. (WPZ), wherein we permanently waived the general partner’s incentive distribution rights (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 (see Note 10 – Stockholders’ 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. Subsequent to these transactions and as of September 30, 2017, we own a 74 percent limited partner interest in WPZ.
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. We have one reportable segment, Williams Partners. All remaining business activities as well as corporate activities are included in Other.
Williams Partners
Williams Partners consists of our consolidated master limited partnership, WPZ, and primarily includes gas pipeline and midstream businesses.
WPZ’s gas pipeline businesses primarily consist of two interstate natural gas pipelines, which are Transcontinental Gas Pipe Line Company, LLC (Transco) and Northwest Pipeline LLC (Northwest Pipeline), and several joint venture investments in interstate and intrastate natural gas pipeline systems, including a 50 percent equity-method investment in Gulfstream Natural Gas System, L.L.C. (Gulfstream), and a 41 percent interest in Constitution Pipeline Company, LLC (Constitution) (a consolidated entity), which is under development.developing a pipeline project (see Note 3 – Variable Interest Entities).


Notes (Continued)


WPZ’s midstream businesses primarily consist of (1) natural gas gathering, treating, compression, and processing; (2) natural gas liquid (NGL) fractionation, storage, and transportation; (3) crude oil production handling and


Notes (Continued)


transportation; and (4) olefins production (see Note 3 – Divestitures).production. WPZ sold its olefins operations in July 2017. The primary service areas are concentrated in major producing basins in Colorado, Texas, Oklahoma, Kansas, New Mexico, Wyoming, the Gulf of Mexico, Louisiana, Pennsylvania, West Virginia, New York, and Ohio, which include the Barnett, Eagle Ford, Haynesville, Marcellus, Niobrara, and Utica shale plays as well as the Mid-Continent region.
The midstream businesses include equity-method investments in natural gas gathering and processing assets and NGL fractionation and transportation assets, including a 62 percent equity-method investment in Utica East Ohio Midstream, LLC, (UEOM), a 69 percent equity-method investment in Laurel Mountain Midstream, LLC, (Laurel Mountain), a 58 percent equity-method investment in Caiman Energy II, LLC, (Caiman II), a 60 percent equity-method investment in Discovery Producer Services, LLC, (Discovery), a 50 percent equity-method investment in Overland Pass Pipeline, LLC, (OPPL), and Appalachia Midstream Services, LLC, which owns equity-method investments with an approximate average 66 percent interest in multiple gathering systems in the Marcellus Shale (Appalachia Midstream Investments), as well as our previously owned 50 percent equity-method investment in the Delaware basin gas gathering system (DBJV) in the Mid-Continent region (see Note 4 – Investing Activities).
The midstream businesses also included our Canadian midstream operations, which were comprised of an oil sands offgas processing plant near Fort McMurray, Alberta, and an NGL/olefin fractionation facility at Redwater, Alberta. In September 2016, we completed the sale of our Canadian operations.
Other
Our former Williams NGL & Petchem Services segment included certain domestic olefins pipeline assets as well as certain Canadian assets, which included a liquids extraction plant located near Fort McMurray, Alberta, that began operations in March 2016, and a propane dehydrogenation facility which was under development. In September 2016, the Canadian assets were sold. Considering this, the remaining assets are now reported within Other, effective January 1, 2017. Other also includes business activities that are not operating segments, as well as corporate operations. Prior period segment disclosures have been recast for this segment change.
Basis of Presentation
Consolidated master limited partnership
As of September 30, 2017,March 31, 2018, we own 74 percent of the interests in WPZ, a variable interest entity (VIE) (see Note 23 – Variable Interest Entities). WPZPursuant to WPZ’s distribution reinvestment program, 576,923 common units were issued to usthe public in connectionFebruary 2018 associated with the Financial Repositioning,reinvested distributions of $22 million. This common unit issuance and WPZ’s quarterly distribution of additional paid-in-kind Class B units to us and other equity issuances by WPZ had the combined net impact of decreasing Noncontrolling interests in consolidated subsidiaries by $2.404 billion,$9 million, and increasing Capital in excess of par value by $1.497 billion$7 million and Deferred income tax liabilities by $907$2 million in the Consolidated Balance Sheet.
WPZ is self-funding and maintains separate lines of bank credit and cash management accounts and also has a commercial paper program. (See Note 9 – Debt and Banking Arrangements.) Cash distributions from WPZ to limited partners, including us, including any associated with our previous IDRs, occur through the normalare governed by WPZ’s partnership distributions from WPZ to all partners.


Notes (Continued)


agreement.
Significant risks and uncertainties
We may monetize assets that are not core to our strategy which could result in impairments of certain equity-method investments, property, plant, and equipment, and intangible assets. Such impairments could potentially be caused by indications of fair value implied through the monetization process or, in the case of asset dispositions that are part of a broader asset group, the impact of the loss of future estimated cash flows.
On March 15, 2018, the Federal Energy Regulatory Commission (FERC) issued a policy 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 both an income tax allowance and a return on equity pursuant to the discounted cash flow methodology. 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. The FERC also issued a Notice of Proposed Rulemaking proposing a 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 this policy statement. Furthermore, the FERC 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 accumulated deferred income tax 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 by our interstate natural gas pipelines may be adversely impacted.


Notes (Continued)


Accounting standards issued and adopted
Effective January 1, 2017,During the first quarter of 2018, we early adopted Accounting Standards Update (ASU) 2016-09, “Compensation2018-02 “Income Statement - Stock CompensationReporting Comprehensive Income (Topic 718)220): ImprovementsReclassification 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 Employee Share-Based Payment Accounting” (ASU 2016-09).retained earnings for stranded tax effects resulting from Tax Reform. The adoption of ASU 2016-09 changed the accounting for income taxes such that all excess tax benefits and all tax deficiencies are now recognized as a discrete item2018-02 resulted in the provision forreclassification of $61 million from Accumulated other comprehensive income taxes in the financial reporting period they occur and the recognition of tax benefits is no longer delayed until the tax benefit is realized through a reduction in income taxes payable. These changes are applied prospectively beginning in 2017. We recorded a cumulative-effect adjustment as of January 1, 2017, decreasing(loss) to Retained deficit by $37 million in theon our Consolidated Balance Sheet to recognize tax benefits that were not previously recognized. ASU 2016-09 requires entities to classify excess tax benefits as an operating activity on the statement of cash flows. We are applying this part of the guidance prospectively beginning in 2017; therefore, the cash flows for prior periods were not adjusted. In recognizing compensation cost from share-based payments, ASU 2016-09 allows entities to make an accounting policy election to either recognize forfeitures when they occur or estimate the number of forfeitures expected to occur. We are recognizing forfeitures when they occur and as a result of the change in our accounting policy, we increased our Sheet.Retained deficit for an insignificant cumulative-effect adjustment as of
Effective January 1, 2017. ASU 2016-09 requires entities to classify as a financing activity, on the statement of cash flows, cash paid by an employer to a taxing authority when directly withholding shares from an employee’s award to satisfy the employer’s statutory tax withholding obligation. This guidance must be applied retrospectively and2018, we have adjusted operating and financing activities on the Consolidated Statement of Cash Flows for prior periods.
Accounting standards issued but not yet adopted
In August 2017, the Financial Accounting Standards Board (FASB) issued 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 is effective for interim and annual periods beginning after December 15, 2018. Early adoption is permitted. ASU 2017-12 will bewas 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. We do not expectThe adoption of ASU 2017-12 todid not have a materialsignificant impact on our consolidated financial statements.
In March 2017, the FASB issuedEffective 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 a subtotal ofOperating income from operations, if one is presented.(loss). Only the service cost component is now eligible for capitalization when applicable. ASU 2017-07 is effective beginning January 1, 2018. The presentation aspect of ASU 2017-07 must be applied retrospectively and the capitalization requirement prospectively. In lightaccordance with this adoption, we have conformed the prior year presentation, which resulted in an increase of the settlement charge we expect$3 million to recognize in the fourth quarterOperating and maintenance expenses with a corresponding decrease to Operating income (loss) and an increase of 2017 related$3 million to a program to payout certain deferred vested pension benefits (see Note 8Other income (expense) – Employee Benefit Plans), we continue to evaluate the impact of ASU 2017-07 on our consolidated financial statements.
In January 2017, the FASB issued ASU 2017-04 “Intangibles - Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment” (ASU 2017-04). ASU 2017-04 modifies the concept of goodwill impairment to represent the amount by which a reporting unit’s carrying value exceeds its fair value, not to exceed the carrying amount of goodwill. Under ASU 2017-04, entities will no longer be required to determine the implied fair value of goodwill by assigning the fair value of a reporting unit to its individual assets and liabilities as if that reporting unit had been acquired in a business combination. ASU 2017-04 is effective for goodwill impairment testing for interim and annual periods


Notes (Continued)


beginning after December 15, 2019, and requires a prospective transition. Early adoption is permitted for interim and annual goodwill impairment tests performed after January 1, 2017, and we plan to adopt ASU 2017-04 in the fourth quarter of 2017. Our Williams Partners reportable segment has $47 million of goodwill included in netIntangible assets - net of accumulated amortization below Operating income (loss) in theConsolidated Statement of Income Consolidated Balance Sheet.    for the period ended March 31, 2017.
In August 2016, the FASB issuedEffective 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 provides specific guidance on eight cash flow classification issues, including debt prepayment or debt extinguishment costs andpermits an accounting policy election to classify distributions received from equity methodequity-method investees using either the cumulative earnings approach or the nature of distribution approach. We have elected to reduce diversity apply the nature of distribution approach and have retrospectively conformed the prior year presentation within the Consolidated Statement of Cash Flowsin practice.accordance with ASU 2016-15 is2016-15. For the period ended March 31, 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 $121 million with a corresponding reduction in Net cash provided (used) by investing activities.
In May 2014, 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. Early
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.


Notes (Continued)



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 permitted. ASU 2016-15primarily 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 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 retrospective transition. We doresult of our assessment that it is probable such recognition would not expect ASU 2016-15 to haveresult in a material impact onsignificant revenue reversal in the future. Additionally, under ASC 606, our consolidated financial statements.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. ASU 2016-13The 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 will 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 ASU 2016-02 “Leases (Topic 842)” (ASU 2016-02). ASU 2016-02 establishes a comprehensive new lease accounting model. ASU 2016-02 clarifiesmodifies the definition of a lease, requires a dual approach to lease classification similar to current lease classifications,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.asset, with an exception for leases with a term of one year or less. Additional disclosures will also be 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 ASC Topic 840 “Leases.” ASU 2016-02 is effective for interim and annual periods beginning after December 15, 2018. Early adoption is permitted. We expect to adopt ASU 2016-02 effective January 1, 2019. ASU 2016-02 currently requires a modified retrospective transition for capitalfinancing or operating leases existing at or entered into after the beginning of the earliest comparative period presented in the financial statements.
In January 2018, the FASB proposed an ASU titled “Leases (Topic 842): Targeted Improvements,” which is an update to ASU 2016-02 allowing 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.
We are in the process of reviewing contracts to identify leases as well as evaluating the applicability of ASU 2016-02 to contracts involving easements/rights-of-way.
In May 2014, the 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 is effective for interim and annual reporting periods beginning after December 15, 2017. ASC 606 allows either full retrospective or modified retrospective transition and early adoption is permitted for annual periods beginning after December 15, 2016.
We continue to evaluate the impact ASC 606 may have on our financial statements. For each revenue contract type, we conducted a formal contract review process to evaluate the impact, if any, that ASC 606 may have. As a result of that process, we expect our revenues will increase associated with accounting for noncash consideration, which exists primarily in certain of our gas processing contracts where we receive commodities as full or partial consideration for services provided. We also expect the increase in revenues will be offset by a similar increase in costs when the commodities received are subsequently monetized. We continue to evaluate contracts with a significant financing component, which may exist in situations where the timing of the consideration we receive varies significantly from the timing of when we provide the service, as well as certain contracts with tiered pricing structures, minimum volume commitments, and prepayments for services. As such, we are unable to determine the potential impact upon the amount and timing of revenue recognition. We continue to develop and evaluate disclosures required under ASC 606, with a particular focusbased on the scopemodified definition of contracts subject to disclosure of remaining performance obligations. Additionally, we have identified possiblea lease, implementing a financial lease accounting system, and evaluating internal control changes necessaryto support management in the accounting for adoption. We currently anticipate utilizing a modified retrospective transition uponand disclosure of leasing activities. While we are still in the adoptionprocess of ASC 606 as of January 1, 2018.completing our implementation


Notes (Continued)


Terminationevaluation of WPZ Merger AgreementASU 2016-02, we currently believe the most significant changes to our financial statements relate to the recognition of a lease liability and offsetting right-of-use asset in our consolidated balance sheet for operating leases. We are also evaluating ASU 2016-02’s currently available and proposed practical expedients on adoption.
On May 12, 2015, we
Note 2 – 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 pipelines business 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:


Notes (Continued)


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;
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 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 transfer 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 refunds 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 unit-for-stock transaction whereby we would have acquiredspecified


Notes (Continued)


period (thus not exercising all of the publicly held outstanding common units of WPZ in exchange for shares of our common stock (WPZ Merger Agreement).
On September 28, 2015, we entered into a Termination Agreementcontractual rights to gathering and Release (Termination Agreement)processing services within the specified period, herein referred to as “breakage”), terminating the WPZ Merger Agreement. Under the terms of the Termination Agreement, we were requiredit is obligated to pay a $428 million terminationcontractually 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 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 WPZ,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 whichthe tailgate of the plant. We recognize such commodity consideration as service revenue based on the market value of the NGLs retained at the time we owned approximately 60 percent,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 interestsfact 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 general partner 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 incentive distribution rights (IDRs)at the time the NGLs retained as part of the processing service are sold in Product sales. Such termination feeThe 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
 (Millions)
Three Months Ended March 31, 2018  
Revenues from contracts with customers:               
Service revenues:               
Non-regulated gathering, processing, transportation, and storage:               
Monetary consideration$202
 $137
 $408
 $—
 $—
 $—
 $(18) $729
Commodity consideration4
 15
 82
 —
 —
 —
 —
 101
Regulated interstate natural gas transportation and storage—
 —
 —
 461
 112
 —
 (1) 572
Other21
 6
 11
 —
 —
 8
 (6) 40
Total service revenues227
 158
 501
 461
 112
 8
 (25) 1,442
Product Sales:               
NGL and natural gas98
 68
 521
 25
 —
 —
 (85) 627
Other—
 —
 4
 —
 —
 —
 —
 4
Total product sales98
 68
 525
 25
 —
 —
 (85) 631
Total revenues from contracts with customers325
 226
 1,026
 486
 112
 8
 (110) 2,073
Other revenues (1)5
 2
 5
 3
 —
 —
 —
 15
Total revenues$330
 $228
 $1,031
 $489
 $112
 $8
 $(110) $2,088
(1)
We provide management services to operated joint ventures and other investments for which we receive a management fee that is categorized as Service revenues in our Consolidated Statement of Income. These management fees do not constitute revenue from contracts with customers. Product sales in our Consolidated Statement of Income include amounts associated with our derivative contracts that are not within the scope of ASC 606.
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 reductionshort-fall payment at the end of quarterly incentive distributions we were entitled to receive from WPZ (such reductionthe 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 to exceed $209 million per quarter). The distributions from WPZ in November 2015, February 2016, and May 2016 were reduced by $209 million, $209 million, and $10 million, respectively,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.


Notes (Continued)


The following table presents a reconciliation of the beginning and ending balances of our contract assets for the period ended March 31, 2018:
 2018
 (Millions)
Balance at January 1$4
Revenue recognized in excess of cash received20
Minimum volume commitments invoiced—
Balance at March 31$24
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 the beginning and ending balances of our contract liabilities for the period ended March 31, 2018:
 2018
 (Millions)
Balance at January 1$1,596
Payments received and deferred92
Recognized in revenue(114)
Balance at March 31$1,574
The following table presents the amount of the contract liabilities balance as of March 31, 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)$251
2019252
2020120
2021100
202294
202388
Thereafter669


Notes (Continued)


Remaining Performance Obligations
The following table presents the transaction price allocated to the remaining performance obligations under certain contracts as of March 31, 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 on our gas pipeline firm transportation contracts with customers, as well as storage capacity contracts. Amounts included in the table below for our interstate natural gas pipeline businesses reflect the rates for such services in our current 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 is not currently known. As a practical expedient permitted by ASC 606, this termination fee.table excludes variable consideration as well as consideration in contracts that is recognized in revenue as billed. It also excludes consideration received prior to March 31, 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, certain of our contracts contain evergreen and other renewal provisions for periods beyond the initial term of the contract. The remaining performance obligation as of March 31, 2018, does not consider potential future performance obligations for which the renewal has not been exercised. The table below also does not include contracts with customers for which the underlying facilities have not received FERC authorization to be placed into service.
 (Millions)
2018 (remainder)$1,927
20192,410
20202,210
20211,891
20221,758
20231,566
Thereafter11,679
Total$23,441
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.
The following is a summary of our Trade accounts and other receivables as it relates to contracts with customers:
 March 31, 2018
 (Millions)
Accounts receivable related to revenues from contracts with customers$704
Other accounts receivable39
Total reflected in Trade accounts and other receivables
$743
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.


Notes (Continued)


 As Reported Adjustments resulting from adoption of ASC 606 Balance without adoption of ASC 606
 (Millions)
Consolidated Statement of Income
Three Months Ended March 31, 2018
Service revenues$1,351
 $5
 $1,356
Service revenues – commodity consideration101
 (101) —
Product sales636
 10
 646
Total revenues2,088
 (86) 2,002
Product costs613
 (55) 558
Processing commodity expenses35
 (35) —
Operating and maintenance expenses357
 (1) 356
Depreciation and amortization expenses431
 1
 432
Total costs and expenses1,597
 (90) 1,507
Operating income (loss)491
 4
 495
Interest incurred(282) 3
 (279)
Interest capitalized9
 (2) 7
Income (loss) before income taxes325
 5
 330
Net income (loss)270
 5
 275
Less: Net income (loss) attributable to noncontrolling interests118
 2
 120
Net income (loss) attributable to The Williams Companies, Inc.152
 3
 155
      
Consolidated Statement of Comprehensive income     
Three Months Ended March 31, 2018     
Net income (loss)$270
 $5
 $275
Comprehensive income (loss)276
 5
 281
Less: Comprehensive income (loss) attributable to noncontrolling interests119
 2
 121
Comprehensive income (loss) attributable to The Williams Companies, Inc.157
 3
 160
      
Consolidated Balance Sheet
March 31, 2018
Inventories$160
 $(8) $152
Other current assets and deferred charges204
 (20) 184
Total current assets2,399
 (28) 2,371
Investments6,513
 (1) 6,512
Property, plant, and equipment40,467
 (2) 40,465
Property, plant, and equipment – net28,847
 (2) 28,845
Intangible assets – net of accumulated amortization8,644
 63
 8,707
Regulatory assets, deferred charges, and other649
 (4) 645
Total assets47,052
 28
 47,080
Deferred income tax liabilities3,196
 27
 3,223
Regulatory liabilities, deferred income, and other4,410
 (125) 4,285
Retained deficit(8,587) 87
 (8,500)
Total stockholders’ equity9,473
 87
 9,560
Noncontrolling interests in consolidated subsidiaries6,430
 39
 6,469
Total equity15,903
 126
 16,029
Total liabilities and equity47,052
 28
 47,080
      
Consolidated Statement of Changes in Equity     
March 31, 2018     
Adoption of ASC 606$(121) $121
 $—
Net income (loss)270
 5
 275
Net increase (decrease) in equity(272) 126
 (146)
Balance - March 31, 201815,903
 126
 16,029
Note 23 – Variable Interest Entities
WPZ
We own a 74 percent interest in WPZ, a master limited partnership that is a VIE due to the limited partners’ lack of substantive voting rights, such as either participating rights or kick-out rights that can be exercised with a simple majority of the vote of the limited partners. We are the primary beneficiary of WPZ because we have the power, through our general partner interest, to direct the activities that most significantly impact WPZ’s economic performance.


Notes (Continued)


The following table presents amounts included in our Consolidated Balance Sheet that are for the use or obligation of WPZ and/or its subsidiaries, and which comprise a significant portion of our consolidated assets and liabilities.

September 30,
2017
December 31,
2016
ClassificationMarch 31,
2018
December 31,
2017
Classification

(Millions)

(Millions)

Assets (liabilities):









Cash and cash equivalents$1,165
 $145

Cash and cash equivalents$1,268
 $881

Cash and cash equivalents
Trade accounts and other receivables – net
778
 925
 Trade accounts and other receivables718
 972
 Trade accounts and other receivables
Inventories144
 138
 Inventories160
 113
 Inventories
Other current assets183
 205
 Other current assets and deferred charges198
 176
 Other current assets and deferred charges
Investments6,615
 6,701
 Investments6,513
 6,552
 Investments
Property, plant, and equipment – net
27,411
 28,021

Property, plant, and equipment – net28,547
 27,912

Property, plant, and equipment – net
Intangible assets – net
8,872
 9,662
 Intangible assets – net of accumulated amortization8,643
 8,790
 Intangible assets – net of accumulated amortization
Regulatory assets, deferred charges, and other noncurrent assets467
 467
 Regulatory assets, deferred charges, and other528
 507
 Regulatory assets, deferred charges, and other
Accounts payable(751) (589)
Accounts payable(755) (957)
Accounts payable
Accrued liabilities including current asset retirement obligations(818) (1,122) Accrued liabilities(682) (857) Accrued liabilities
Commercial paper—
 (93) Commercial paper
Long-term debt due within one year(502) (785) Long-term debt due within one year(501) (501) Long-term debt due within one year
Long-term debt(16,000) (17,685) Long-term debt(17,011) (15,996) Long-term debt
Deferred income tax liabilities(14) (20) Deferred income tax liabilities(15) (16) Deferred income tax liabilities
Noncurrent asset retirement obligations(876) (798) Regulatory liabilities, deferred income, and other(987) (944) Regulatory liabilities, deferred income, and other
Regulatory liabilities, deferred income, and other noncurrent liabilities(1,986) (1,860)
Regulatory liabilities, deferred income, and other(3,221) (2,809)
Regulatory liabilities, deferred income, and other
The assets and liabilities presented in the table above also include the consolidated interests of the following individual VIEs within WPZ:
Gulfstar One
WPZ owns a 51 percent interest in Gulfstar One LLC (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. WPZ is the primary beneficiary because it has the power to direct the activities that most significantly impact Gulfstar One’s economic performance.
Constitution
WPZ owns 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. WPZ is the primary beneficiary because it has the power to direct the activities that most significantly impact Constitution’s economic performance. WPZ, as construction manager foroperator of Constitution, is responsible for constructing the proposed pipeline connecting its gathering system in Susquehanna County, Pennsylvania, to the Iroquois Gas Transmission and the Tennessee Gas Pipeline systems. The total remaining cost of the project is estimated to be approximately $691$740 million, which is expected towould be funded with capital contributions from WPZ and the other equity partners on a proportional basis.


Notes (Continued)


In December 2014, Constitution received approval from the Federal Energy Regulatory Commission (FERC)FERC to construct and operate its proposed pipeline. However, in April 2016, the New York State Department of Environmental Conservation (NYSDEC) denied the


Notes (Continued)


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. As to the denial itself, the court determined that NYSDEC’s action was not arbitrary or capricious. Constitution filed a petition for rehearing ofwith the Second Circuit Court’s decision,Court of Appeals, but in October the court denied our petition.
We remain steadfastly committed to the project, and inIn October 2017, weWPZ 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. In January 2018, the FERC denied WPZ’s 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.
The project’s sponsors remain committed to the project. In lightFebruary 2018, we filed a request with the FERC for rehearing of its finding that the NYSDEC did not waive the Section 401 certification requirement. If the FERC denies such request, we will file a petition for review with the D.C. Circuit Court of Appeals. In January 2018, we filed a petition with the United States Supreme Court to review the decision of the Second Circuit Court of Appeals that upheld the merits of the NYSDEC’s denial of the water qualitySection 401 certification. However, on April 30, 2018, the Court denied our petition. This decision is separate and independent from (and thus has no impact on) our request for rehearing (or appeal) of the FERC’s decision that the NYSDEC did not waive the Section 401 certification andrequirement.
Should any court or FERC decision determine that the actions taken to challengeNYSDEC waived the decision,Section 401 certification requirement, we estimate that the anticipated target in-service date is as early asfor the first half of 2019, which assumes the timely receipt of a Noticeproject would be approximately 10 to Proceed from the FERC.12 months following any such determination. An unfavorable resolution could result in the impairment of a significant portion of the capitalized project costs, which total $381$379 million on a consolidated basis at September 30, 2017,March 31, 2018, 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 prolonged delay or termination of the project.
Cardinal
WPZ owns a 66 percent interest in Cardinal Gas Services, L.L.C. (Cardinal), a subsidiary that provides gathering services for the Utica Shale region and is a VIE due to certain risks shared with customers. WPZ is the primary beneficiary because it has 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 WPZ and the other equity partner on a proportional basis.
Jackalope
WPZ owns a 50 percent interest in Jackalope Gas Gathering Services, L.L.C. (Jackalope), a subsidiary that provides gathering and processing services for the Powder River basin and is a VIE due to certain risks shared with customers. WPZ is the primary beneficiary because it has the power to direct the activities that most significantly impact Jackalope’s economic performance. Future expansion activity is expected to be funded with capital contributions from WPZ and the other equity partner on a proportional basis.
Note 3 – Divestitures
On July 6, 2017, WPZ completed the sale of 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) 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, WPZ entered into a long-term supply and transportation agreement with the purchaser to provide feedstock to the plant via its Bayou Ethane pipeline system. The assets and liabilities of the Geismar olefins plant were designated as held for sale within the Williams Partners segment during the first quarter of 2017. As a result of this sale, we recorded a gain of $1.095 billion in the third quarter of 2017. Following this sale, the cash proceeds were used to repay WPZ’s $850 million term loan. WPZ also plans to use these proceeds to fund a portion of the capital and investment expenditures that are a part of its growth portfolio.


Notes (Continued)


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,
 2017 2016 2017 2016
 (Millions)
Income (loss) before income taxes of the Geismar Interest$1
 $61
 $26
 $109
Income (loss) before income taxes of the Geismar Interest attributable to The Williams Companies, Inc.1
 36
 19
 65
In September 2016, we completed the sale of subsidiaries conducting Canadian operations, including subsidiaries of WPZ, (such subsidiaries, the Canada disposal group). Consideration received totaled $1.020 billion, net of $31 million of cash divested and subject to customary working capital adjustments. In connection with the sale, we waived $150 million of incentive distributions otherwise payable by WPZ to us in the fourth quarter of 2016 in recognition of certain affiliate contracts wherein WPZ’s Canadian operations provided services to certain of our other businesses. The proceeds were primarily used to reduce borrowings on credit facilities.
During the second quarter of 2016, we designated these operations as held for sale. As a result, we measured the fair value of the disposal group as of June 30, 2016, resulting in an impairment charge of $747 million, reflected in Impairment of certain assets in the Consolidated Statement of Operations. (See Note 11 - Fair Value Measurements.) Upon completion of the sale, we recorded an additional loss of $65 million for the three and nine months ended September 30, 2016, primarily reflecting revisions to the sales price and estimated contingent consideration and including a $15 million benefit related to transactions to hedge our foreign currency exchange risk on the Canadian proceeds, reflected in Other (income) expense – net within Costs and expenses in the Consolidated Statement of Operations. The total loss consists of a loss of $32 million and $33 million at Williams Partners and Williams Other segments, respectively.
The following table presents the results of operations for the Canada disposal group, excluding the impairment and loss noted above.
 Three Months Ended September 30, Nine Months Ended September 30,
 2017 2016 2017 2016
 (Millions)
Income (loss) before income taxes of the Canadian disposal group$—
 $(9) $—
 $(98)
Income (loss) before income taxes of the Canadian disposal group attributable to The Williams Companies, Inc.—
 (16) —
 (95)
Note 4 – Investing Activities
Acquisition of Additional Interests in Appalachia Midstream Investments
During the first quarter of 2017, WPZ exchanged all of its 50 percent interest in DBJV for an increased interest in two natural gas gathering systems that are part of the Appalachia Midstream Investments and $155 million in cash. This transaction was recorded based on our estimate of the fair value of the interests received as we have more insight


Notes (Continued)


to this value as we operate the underlying assets. Following this exchange, we haveWPZ has an approximate average 66 percent interest in the Appalachia Midstream Investments. We continue to account for this investment under the equity-method due to the significant participatory rights of our partners such that we do not exercise control. WPZ also sold all of its 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 Operations.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


Notes (Continued)


(a (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.
Impairments
The nine months ended September 30, 2016, includes $59 million and $50 million of other-than-temporary impairment charges related to WPZ’s equity-method investments in DBJV and Laurel Mountain, respectively (see Note 11 – Fair Value Measurements and Guarantees).
Investing Income
The three and nine months ended September 30, 2016, includes a $27 million gain from the sale of an equity-method investment interest in a gathering system that was part of WPZ’s Appalachia Midstream Investments.
Interest Income and Other
The nine months ended September 30, 2016, includes $36 million of income associated with payments received on a receivable related to the sale of certain former Venezuela assets reflected in Other investing income (loss) – net in theConsolidated Statement of Operations.
Note 5 – Other Income and Expenses
The following table presents certain gains or losses reflected in Other (income) expense – net within Costs and expenses in our Consolidated Statement of OperationsIncome:
 Three Months Ended 
 September 30,		 Nine Months Ended 
 September 30,
 2017 2016 2017 2016
 (Millions)
Williams Partners       
Amortization of regulatory assets associated with asset retirement obligations$8
 $8
 $25
 $25
Accrual of regulatory liability related to overcollection of certain employee expenses5
 6
 16
 19
Project development costs related to Constitution (see Note 2)4
 11
 12
 19
Gains on contract settlements and terminations—
 —
 (15) —
Gain on sale of Refinery Grade Propylene Splitter—
 —
 (12) —
Net foreign currency exchange (gains) losses (1)—
 —
 —
 11
Loss on sale of Canadian operations (see Note 3)4
 32
 —
 32
Other       
Gain on sale of unused pipe—
 —
 —
 (10)
Loss on sale of Canadian operations (see Note 3)—
 33
 1
 33
(1)Primarily relates to gains and losses incurred on foreign currency transactions and the remeasurement of U.S. dollar denominated current assets and liabilities within our former Canadian operations.


Notes (Continued)


 Three Months Ended 
 March 31,
 2018 2017
 (Millions)
Williams Partners   
Gains on contract settlements and terminations$—
 $(13)
Additional Items
Certain additional items included in the Consolidated Statement of OperationsIncome are as follows:
Service revenues were reduced by $15 million for the nine months ended September 30, 2016, related to potential refunds associated with a ruling received in certain rate case litigation within the Williams Partners segment.
Selling, general, and administrative expenses includes $5 million and $9 million for the three and nine months ended September 30, 2017, respectively, and $21 million and $40 million for the three and nine months ended September 30, 2016, respectively, of costs associated with our evaluation of strategic alternatives within the Other segment. Selling, general, and administrative expenses also includes $16 million and $61 million for the three and nine months ended September 30, 2016, respectively, of project development costs related to a proposed propane dehydrogenation facility in Alberta, Canada within the Other segment. Beginning in the first quarter of 2016, these costs did not qualify for capitalization.
Selling, general, and administrative expenses and Operating and maintenance expenses include $5 million and $18 million in severance and other related costs for the three and nine months ended September 30, 2017 for the Williams Partners segment. The nine months ended September 30, 2016 included $26 million in severance and other related costs associated with an approximate 10 percent reduction in workforce in the first quarter of 2016, primarily within the Williams Partners segment.
Other income (expense) – net below Operating income (loss) includes $17income of $20 million and $55$18 million for the three and nine months ended September 30,March 31, 2018 and 2017, respectively, and $17 million and $46 million for the three and nine months ended September 30, 2016, respectively, for allowance for equity funds used during construction primarily within the Williams Partners segment. Other income (expense) – net below Operating income (loss) also includes $8income of $5 million and $44$28 million for the three and nine months ended September 30,March 31, 2018 and 2017, respectively, and $6 million and $16 million for the three and nine months ended September 30, 2016, respectively of income associated with a regulatory asset related to deferred taxes on equity funds used during construction.
Other income (expense) – net below Operating income (loss) for the three months ended September 30, 2017March 31, 2018, includes a $7 million net loss of $3 million associated with the July 3, 2017March 28, 2018, early retirement of $1.4 billion$750 million of 4.875 percent senior unsecured notes that were due in 2023.2024. The net loss for the July 3, 2017 early retirement within the Williams Partners segment reflects $51$34 million in premiums paid, partially offset by $27 million of unamortized premium, offset by $54 million in premiums paid. (See Note 9 – Debt and Banking Arrangements.)premium. For the three months ended March 31, 2017,
Other income (expense) – net below Operating income (loss) for the nine months ended September 30, 2017, includes a net gain of $27 million associated with the early retirement of debt. The gain is comprised of a $30 million net gain associated with the February 23, 2017, early retirement of $750 million of 6.125 percent senior unsecured notes that were due in 2022, partially offset by a $3 million net loss associated with the July 3, 2017 early retirement discussed above.2022. The net gain for the February 23, 2017 early retirement within Williams Partners reflects $53 million of unamortized premium, partially offset by $23 million in premiums paid. (See Note 9 – Debt and Banking Arrangements.)


Notes (Continued)


Note 6 – Provision (Benefit) for Income Taxes
The Provision (benefit) for income taxes includes:
Three Months Ended 
 September 30,		 Nine Months Ended 
 September 30,		Three Months Ended 
 March 31,
2017 2016 2017 20162018 2017
(Millions)(Millions)
Current:          
Federal$7
 $—
 $10
 $—
$(19) $3
State9
 1
 17
 1
1
 6
Foreign—
 —
 —
 (1)
16
 1
 27
 —
(18) 9
Deferred:          
Federal(11) 8
 63
 (49)64
 15
State19
 71
 36
 60
9
 13
Foreign—
 (11) —
 (85)
8
 68
 99
 (74)73
 28
Provision (benefit) for income taxes$24
 $69
 $126
 $(74)$55
 $37
The effective income tax rate for the total provision for the three months ended September 30, 2017,March 31, 2018, is less than the federal statutory rate. This is 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).taxes.

The effective income tax rate for the ninetotal provision for the three months ended September 30,March 31, 2017, is less than the federal statutory rate. This israte 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 and the impact of 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). 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.taxes. The sale of the Geismar olefins facility in July 2017 (see Note 3 – Divestitures) generated capital gains sufficient to offset the capital loss carryover, thereby allowing us to reverse the valuation allowance in full.
The effective income tax rate for
On December 22, 2017, Tax Reform was enacted. Under the three months ended September 30, 2016, is less thanguidance provided by Securities and Exchange Commission Staff Accounting Bulletin No. 118, Income Tax Accounting Implications of the federal statutory rate primarily dueTax Cuts and Jobs Act, we recorded provisional adjustments related to the impact of Tax Reform in the allocationfourth quarter of income to nontaxable noncontrolling interests and the effects of taxes on foreign operations, partially offset by the effect of state income taxes, including a $43 million provision2017. We consider all amounts recorded related to an increase in the deferred state income tax rate (net of federal benefit).
Tax Reform to be reasonable estimates. The effective income tax rateamounts recorded continue to be provisional for the nine months ended September 30, 2016, is less than the federal statutory rate primarily due to the effectsreasons disclosed in our Annual Report on Form 10-K filed February 22, 2018, as our interpretation, assessment, and presentation of taxes on foreign operations, which includes the reversal of anticipatory foreign tax credits and a valuation allowance associated with impairments and losses on the sale of our Canadian operations (see Note 3 – Divestitures), and the effect of state income taxes, including a $43 million provision related to an increase in the deferred state income tax rate (net of federal benefit). These decreases are partially offset by the impact of the allocation of incometax law change may be further clarified with additional guidance from regulatory, tax, and accounting authorities. We are continuing to nontaxable noncontrolling interests. The foreign income tax provision includesgather additional information to determine the tax effect offinal impact and should additional guidance be provided by these authorities or other sources, we will review the impairments associated with our Canadian disposition. (See Note 11 – Fair Value Measurementsprovisional amounts and Guarantees.)adjust as appropriate.
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 7 – Earnings (Loss) Per Common Share
Three Months Ended 
 September 30,		 Nine Months Ended 
 September 30,		Three Months Ended 
 March 31,
2017 2016 2017 20162018 2017
(Dollars in millions, except per-share
amounts; shares in thousands)
(Dollars in millions, except per-share
amounts; shares in thousands)
Net income (loss) attributable to The Williams Companies, Inc. available to common stockholders for basic and diluted earnings (loss) per common share$33
 $61
 $487
 $(409)
Net income attributable to The Williams Companies, Inc. available to common stockholders for basic and diluted earnings per common share$152
 $373
Basic weighted-average shares826,779
 750,754
 825,925
 750,579
827,509
 824,548
Effect of dilutive securities:          
Nonvested restricted stock units1,889
 568
 1,567
 —
2,095
 1,305
Stock options700
 536
 658
 —
593
 623
Diluted weighted-average shares829,368
 751,858
 828,150
 750,579
830,197
 826,476
Earnings (loss) per common share:       
Earnings per common share:   
Basic$.04
 $.08
 $.59
 $(.55)$.18
 $.45
Diluted$.04
 $.08
 $.59
 $(.55)$.18
 $.45

Note 8 – Employee Benefit Plans
Net periodic benefit cost (credit) is as follows:

Pension BenefitsPension Benefits

Three Months Ended 
 September 30,
Nine Months Ended 
 September 30,		Three Months Ended 
 March 31,

2017
2016
2017
20162018
2017

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









Service cost$13

$13

$38

$40
$14

$13
Interest cost15

16

44

47
11

15
Expected return on plan assets(21)
(22)
(62)
(64)(16)
(20)
Amortization of net actuarial loss6

8

20

23
6

7
Net actuarial loss from settlements—

—

—

1
Net periodic benefit cost (credit)$13

$15

$40

$47
$15

$15
Other Postretirement BenefitsOther Postretirement Benefits
Three Months Ended 
 September 30,		 Nine Months Ended 
 September 30,		Three Months Ended 
 March 31,
2017 2016 2017 20162018 2017
(Millions)(Millions)
Components of net periodic benefit cost (credit):          
Service cost$—
 $—
 $1
 $1
Interest cost2
 2
 6
 6
$2
 $2
Expected return on plan assets(3) (3) (9) (9)(3) (3)
Amortization of prior service credit(3) (3) (10) (11)(1) (3)
Reclassification to regulatory liability1
 1
 3
 3
1
 1
Net periodic benefit cost (credit)$(3) $(3) $(9) $(10)$(1) $(3)
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 and net actuarial lossincluded in netNet periodic benefitcost (credit) for our other postretirement benefit plans associated with Transco and Northwest Pipeline areis recorded to regulatory assets/liabilities instead of Ootherther comprehensive income (loss). The amounts of amortizationAmortization of prior service credit recognized in regulatory liabilities were $1 million and $2 million for the three months ended September 30,March 31, 2018 and 2017 and 2016, and $6 million and $7 million for the nine months ended September 30, 2017 and 2016, respectively.
During the ninethree months ended September 30, 2017March 31, 2018, we contributed $832 million to our pension plans and $41 million to our other postretirement benefit plans. We presently anticipate making additional contributions of approximately $184 million to our pension plans and approximately $1$5 million to our other postretirement benefit plans in the remainder of 2017.2018.

In September 2017, we initiated a program to pay out certain deferred vested pension benefits to reduce investment risk, cash funding volatility, and administrative costs. Eligible participants had until October 31, 2017, to make elections. We expect to make the lump-sum payments and commence the annuity payments in December 2017, and intend to fund the payments from existing assets in our pension plans. As a result of these payouts and based on current assumptions, we expect to record a pre-tax, non-cash settlement charge in the fourth quarter of 2017 that we estimate will be between $70 million and $100 million. The ultimate amount of the charge will largely depend upon the actual level of participation as well as the actuarial assumptions used to measure the pension plans’ assets and obligations, including the discount rates.
Note 9 – Debt and Banking Arrangements
Long-Term Debt
Issuances and retirements
On July 6, 2017,March 5, 2018, WPZ repaid its $850completed a public offering of $800 million variable interest rate term loan that was due December 2018 using proceeds from the sale of its Geismar Interest.
On June 5, 2017, WPZ issued $1.45 billion of 3.754.85 percent senior unsecured notes due 2027.2048. WPZ used the net proceeds for general partnership purposes, primarily the July 3, 2017March 28, 2018 repayment of $1.4 billion$750 million of 4.875 percent senior unsecured notes that were due in 2023.2024.
On April 3, 2017, Northwest PipelineMarch 15, 2018, Transco issued $250$400 million of 4.04 percent senior unsecured notes due 20272028 and $600 million of 4.6 percent senior unsecured notes due 2048 to investors in a private debt placement. Northwest Pipeline usedTransco intends to use the net proceeds to retire $185$250 million of 5.956.05 percent senior unsecured notes that matured on April 15, 2017,due June 2018, and for general corporate purposes.purposes, including the funding of capital expenditures. As part of the issuance, Northwest PipelineTransco entered into a registration rights agreement with the initial purchasers of the unsecured notes. Northwest PipelineTransco 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 PipelineTransco is required to provide a shelf registration statement to cover resales of the notes under certain circumstances. If Northwest PipelineTransco 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.
Other financing obligation
On February 23, 2017, using proceedsDuring the first quarter of 2018, Transco received from the Financial Repositioning (see Note 1 – General, Description of Business, and Basis of Presentation), WPZ early retired $750an additional $19 million of 6.125 percent senior unsecured notes that were duefunding from a co-owner related to the construction of the Dalton expansion project. This additional funding is reflected as Long-term debt in 2022.the Consolidated Balance Sheet.
WPZ retired $600 millionCommercial Paper Program
As of 7.25 percent senior unsecured notes that matured on February 1, 2017.March 31, 2018, no commercial paper was outstanding under WPZ’s $3 billion commercial paper program.


Notes (Continued)


Other financing obligation
During the construction of Transco’s Dalton expansion project, WPZ received funding from a partner for its proportionate share of construction costs related to its undivided ownership interest in the project. Amounts received were recorded within noncurrent liabilities. Upon placing the project in service during the third quarter of 2017, WPZ began leasing this partner’s undivided interest in the lateral, including the associated pipeline capacity, and reclassified approximately $237 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 35 years.
Commercial Paper Program
As of September 30, 2017, no Commercial paper was outstanding under WPZ’s $3 billion commercial paper program.
Credit Facilities
September 30, 2017March 31, 2018
Stated Capacity OutstandingStated Capacity Outstanding
(Millions)(Millions)
WMB      
Long-term credit facility$1,500
 $400
$1,500
 $200
Letters of credit under certain bilateral bank agreements  13
  13
WPZ      
Long-term credit facility (1)3,500
 —
3,500
 —
Letters of credit under certain bilateral bank agreements  1
  1
 
(1)In managing our available liquidity, we do not expect a maximum outstanding amount in excess of the capacity of WPZ’s credit facility inclusive of any outstanding amounts under its commercial paper program.
Note 10 – Stockholders’ Equity
In January 2017, we issued 65 million shares of common stock in a public offering at a price of $29.00 per share. In February 2017, we issued 9.75 million shares of common stock pursuant to the full exercise of the underwriter’s option to purchase additional shares. The net proceeds of approximately $2.1 billion were used to purchase newly issued common units in WPZ as part of our Financial Repositioning. (See Note 1 – General, Description of Business, and Basis of Presentation.)
AOCI
The following table presents the changes in Accumulated other comprehensive income (loss) (AOCI) by component, net of income taxes:
 
Cash
Flow
Hedges
 
Foreign
Currency
Translation
 
Pension and
Other Post
Retirement
Benefits
 Total
 (Millions)
Balance at December 31, 2016$—
 $(2) $(337) $(339)
Other comprehensive income (loss) before reclassifications
(3) —
 —
 (3)
Amounts reclassified from accumulated other comprehensive income (loss)
—
 —
 11
 11
Other comprehensive income (loss)(3) —
 11
 8
Balance at September 30, 2017$(3) $(2) $(326) $(331)


Notes (Continued)


 
Cash
Flow
Hedges
 
Foreign
Currency
Translation
 
Pension and
Other Postretirement
Benefits
 Total
 (Millions)
Balance at December 31, 2017$(2) $(1) $(235) $(238)
Adoption of ASU 2018-02 (Note 1)—
 —
 (61) (61)
Amounts reclassified from accumulated other comprehensive income (loss)
—
 —
 5
 5
Balance at March 31, 2018$(2) $(1) $(291) $(294)
Reclassifications out of AOCI are presented in the following table by component for the ninethree months ended September 30, 2017:March 31, 2018:
Component Reclassifications Classification
  (Millions)  
Cash flow hedges:    
Energy commodity contracts $(1) Product sales
     
Pension and other postretirement benefits:    
Amortization of prior service cost (credit) included in net periodic benefit cost (4) Note 8 – Employee Benefit Plans
Amortization of actuarial (gain) loss included in net periodic benefit cost 20
 Note 8 – Employee Benefit Plans
     
Total before tax 15
  
Income tax benefit (4) Provision (benefit) for income taxes
Reclassifications during the period $11
  
Component Reclassifications Classification
  (Millions)  
Pension and other postretirement benefits:    
Amortization of actuarial (gain) loss included in net periodic benefit cost (credit) $6
 Note 8 – Employee Benefit Plans
Income tax benefit (1) Provision (benefit) for income taxes
Reclassifications during the period $5
  


Notes (Continued)


Note 11 – Fair Value Measurements and Guarantees
The following table presents, by level within the fair value hierarchy, certain of our financial assets and liabilities. The carrying values of cash and cash equivalents, accounts receivable, commercial paper, and accounts payable approximate fair value because of the short-term nature of these instruments. Therefore, these assets and liabilities are not presented in the following table.
     Fair Value Measurements Using     Fair Value Measurements Using
 
Carrying
Amount
 
Fair
Value
 
Quoted
Prices In
Active
Markets for
Identical
Assets
(Level 1)
 
Significant
Other
Observable
Inputs
(Level 2)
 
Significant
Unobservable
Inputs
(Level 3)
 
Carrying
Amount
 
Fair
Value
 
Quoted
Prices In
Active
Markets for
Identical
Assets
(Level 1)
 
Significant
Other
Observable
Inputs
(Level 2)
 
Significant
Unobservable
Inputs
(Level 3)
 (Millions) (Millions)
Assets (liabilities) at September 30, 2017:          
Assets (liabilities) at March 31, 2018:          
Measured on a recurring basis:                    
ARO Trust investments $127
 $127
 $127
 $—
 $—
 $145
 $145
 $145
 $—
 $—
Energy derivatives assets designated as hedging instruments 2
 2
 2
 —
 —
Energy derivatives assets not designated as hedging instruments 2
 2
 1
 —
 1
 4
 4
 4
 —
 —
Energy derivatives liabilities designated as hedging instruments (6) (6) (5) (1) —
 (3) (3) (3) —
 —
Energy derivatives liabilities not designated as hedging instruments (5) (5) (2) —
 (3) (4) (4) (1) —
 (3)
Additional disclosures:                    
Other receivables 12
 12
 12
 —
 —
 7
 7
 7
 —
 —
Long-term debt, including current portion (21,069) (22,979) —
 (22,979) —
 (21,880) (23,061) —
 (23,061) —
Guarantees (44) (30) —
 (14) (16) (43) (30) —
 (14) (16)
                    
Assets (liabilities) at December 31, 2016:          
Assets (liabilities) at December 31, 2017:          
Measured on a recurring basis:                    
ARO Trust investments $96
 $96
 $96
 $—
 $—
 $135
 $135
 $135
 $—
 $—
Energy derivatives assets designated as hedging instruments 2
 2
 —
 2
 —
Energy derivatives assets not designated as hedging instruments 1
 1
 —
 —
 1
Energy derivatives liabilities designated as hedging instruments (3) (3) (2) (1) —
Energy derivatives liabilities not designated as hedging instruments (6) (6) —
 —
 (6) (3) (3) —
 —
 (3)
Additional disclosures:                    
Other receivables 15
 15
 15
 —
 —
 7
 7
 7
 —
 —
Long-term debt, including current portion (23,409) (24,090) —
 (24,090) —
 (20,935) (23,005) —
 (23,005) —
Guarantees (44) (30) —
 (14) (16) (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 is classified as available-for-sale, 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.


Notes (Continued)


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 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 ninethree months ended September 30, 2017March 31, 2018 or 20162017.
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 value of the financing obligation associated with our Dalton lateral, which is included within long-term debt, was determined using an income approach (see Note 9 - Debt and Banking Arrangements).
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 disclosed 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 $31$30 million at September 30, 2017.March 31, 2018. 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 agreements 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 no 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 investments associated with certain nonrecurring fair value measurements within Level 3 of the fair value hierarchy.
         Impairments
         Nine Months Ended September 30,
 Classification Segment Date of Measurement Fair Value 2017 2016
       (Millions)
Certain gathering operations (1)
Property, plant, and equipment - net and Intangible assets - net of accumulated amortization
 Williams Partners September 30, 2017 $439
 $1,019
  
Certain gathering operations (2)
Property, plant, and equipment - net and Intangible assets - net of accumulated amortization
 Williams Partners September 30, 2017 21
 115
  
Certain NGL pipeline (3)Property, plant, and equipment – net Other September 30, 2017 32
 68
  
Certain olefins pipeline project (4)Property, plant, and equipment – net Other June 30, 2017 18
 23
 

Canadian operations (5)Assets held for sale Williams Partners June 30, 2016 924
 
 $341
Canadian operations (5)Assets held for sale Other June 30, 2016 206
 
 406
Certain gathering operations (6)Property, plant, and equipment – net Williams Partners June 30, 2016 18
 
 48
Level 3 fair value measurements of certain assets        1,225
 795
Other impairments and write-downs (7)        11
 16
Impairment of certain assets        $1,236
 $811
            
Equity-method investments (8)Investments Williams Partners March 31, 2016 $1,294
 
 $109
Other equity-method investmentInvestments Williams Partners March 31, 2016 —
 
 3
Impairment of equity-method investments        
 $112
_______________
(1)Relates to certain gathering operations in the Mid-Continent region. During the third quarter of 2017, we received solicitations and engaged in negotiations for the sale of certain of these assets which led to our impairment evaluation. 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, we utilized a discount rate of 10.2 percent, reflecting an estimate of our cost of capital and risks associated with the underlying assets.

(2)Relates to certain gathering operations in the Marcellus South region resulting from an anticipated decline in future volumes following a third-quarter 2017 shut-in by the primary producer. The estimated fair value was


Notes (Continued)


determined by the income approach utilizing a discount rate of 11.1 percent, reflecting an estimate of our cost of capital and risks associated with the underlying assets.

(3)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.
(4)Relates primarily to project development costs associated with an olefins pipeline project in the Gulf Coast region, the likelihood of completion of which is now considered remote. The estimated fair value of the remaining pipe and equipment considered a market approach based on our analysis of observable inputs in the principal market, as well as an estimate of replacement cost.
(5)Relates to our Canadian operations. We designated these operations as held for sale as of June 30, 2016. As a result, we measured the fair value of the disposal group, resulting in an impairment charge. The estimated fair value was determined by a market approach based primarily on inputs received in the marketing process and reflected our estimate of the potential assumed proceeds. We disposed of our Canadian operations through a sale during the third quarter of 2016.
(6)Relates to certain gathering assets within the Mid-Continent region. The estimated fair value was determined by a market approach based on our analysis of observable inputs in the principal market.
(7)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 than the carrying value.
(8)Relates to Williams Partners’ previously owned interest in DBJV and current equity-method investment in Laurel Mountain. Our carrying values in these equity-method investments had been written down to fair value at December 31, 2015. Our first-quarter 2016 analysis reflected higher discount rates for both of these equity-method investments, along with lower natural gas prices for Laurel Mountain. We estimated the fair value of these equity-method investments using an income approach based on expected future cash flows and appropriate discount rates. The determination of estimated future cash flows involved significant assumptions regarding gathering volumes and related capital spending. Discount rates utilized ranged from 13.0 percent to 13.3 percent and reflected increases in our estimated cost of capital, revised estimates of expected future cash flows, and risks associated with the underlying businesses.
Note 12 – Contingent Liabilities
Reporting of Natural Gas-Related Information to Trade Publications
Direct and indirect purchasers of natural gas in various states filed an 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


Notes (Continued)


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 has 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.
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, and the appeal is now pending.
Because of the uncertainty around the remaining pending unresolved issues, we cannot reasonably estimate a range of potential exposure at this time. However, it is reasonably possible that the ultimate resolution of these actions and our related indemnification obligation could result in a potential loss that may be material to our results of operations.


Notes (Continued)


In connection with this indemnification, we have an accrued liability balance associated with this matter, and as a result, have exposure to future developments in this matter.
Geismar Incident
On June 13, 2013, an explosion and fire occurred at our formerly owned Geismar olefins plant and rendered the facility temporarily inoperable (Geismar Incident). As a result, there were two fatalities and numerous individuals (including employees and contractors) reported injuries. We are addressing the following contingent liabilities in connection with the Geismar Incident.
On October 21, 2013, the U.S. Environmental Protection Agency (EPA) 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. The EPA could issue penalties pertaining to final determinations. Multiple lawsuits, including class actions for alleged offsite impacts, property damage, customer claims, and personal injury, have been filed against us. The first two trials, for nine plaintiffs claiming personal injury, were held in Louisiana state court in Iberville Parish, Louisiana in September and November 2016. The juries returned adverse verdicts against us, our subsidiary Williams Olefins, LLC, and other defendants. To date, we have settled those cases as well as settled or agreed in principle to settle numerous other personal injury claims, and such aggregate amount greater than our $2 million retention (deductible) value has been or will be recovered from our insurers. We believe these settlements to date substantially resolve any material exposure to such claims arising from the Geismar Incident. We believe that any additional losses arising from our alleged liability will be immaterial to our expected future annual results of operations, liquidity, and financial position and will be substantially covered by our general liability insurance policy, which has an aggregate limit of $610 million applicable to this event.developments.
Alaska Refinery Contamination Litigation
In 2010, James West filed a class action lawsuitWe are involved in state court in Fairbanks, Alaska on behalflitigation arising from our ownership and operation of individual property owners whose water contained sulfolane contamination allegedly emanating from the Flint Hills OilNorth Pole Refinery in North Pole, Alaska. The suit namedAlaska, from 1980 until 2004, through our subsidiary,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 owned and operated the refinery until 2004 when we sold it to FHRA. We and FHRA made claims under the pollution liability insurance policy issued in connection with the sale of the North Pole refinery to FHRA. We and FHRA also filed claims against each other seeking, among other things, contractual indemnification alleging that the other party caused the sulfolane contamination. In 2011, we and FHRA settled the claim with James West claim.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.
On March 6, 2014, the The State of Alaska filed suit against FHRA, WAPI, and usits action in state court in FairbanksMarch 2014, seeking injunctive relief and damages in connection with sulfolane contamination of the water supply near the Flint Hills Oil Refinery in North Pole, Alaska. On May 5, 2014, FHRA filed cross-claims against us in the State of Alaska suit for contractual indemnification and statutory claims for damages related to off-site sulfolane.
On November 26, 2014, thedamages. The City of North Pole (North Pole) filed suitits lawsuit in Alaska state court in Fairbanks against FHRA, WAPI, and us alleging nuisance and violations of municipal ordinances and state statutes based upon the same alleged sulfolane contamination of the water supply. North Pole claims an unspecified amount ofNovember 2014, seeking past and future damages, as well as punitive damages against WAPI. FHRA filed cross-claims against us.
In October of 2015, the court consolidated the State of Alaska and North Pole cases.damages. Both we and WAPI asserted counterclaims against both 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 consolidated State of Alaska and North Pole actioncases are similar to and may duplicate exposure in the James West case.exposure. As such, onin February 9, 2017, the three cases were consolidated into one action in state court containing the remaining claims infrom the James West case were consolidated intoand those of the State of Alaska and North Pole action.Pole. A trial encompassing all three consolidated cases was originally scheduled


Notes (Continued)


to commence in May 2017 but has been continued. A new trial date has not been scheduled. 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 intended 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, and the ultimate cost of remediation and division of costs among the potentially responsible parties, and the previously described separate litigation, we are unable to estimate a range of exposure at this time.


Notes (Continued)


Royalty Matters
Certain of our customers, including one major customer, 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 and Oklahoma based on allegations that we improperly participated with that major customer in causing the alleged royalty underpayments. The Oklahoma case was transferred to Texas and, on October 2, 2017, voluntarily dismissed by the plaintiff. We believe that the claims asserted are subject to indemnity obligations owed to us by that major customer. Due to the preliminary status of the cases, we are unable to estimate a range of potential loss at this time.
Shareholder Litigation
Between October 2015 and December 2015, purported shareholders of us filed six putative class action lawsuits in the Delaware Court of Chancery that were consolidated into a single suit on January 13, 2016. This consolidated putative class action lawsuit relates to our terminated merger with Energy Transfer Equity, L.P. (Energy Transfer). The complaint asserts various claims against the individual members of our Board of Directors, including that they breached their fiduciary duties by agreeing to sell us through an allegedly unfair process and for an allegedly unfair price and by allegedly failing to disclose allegedly material information about the merger. The complaint seeks, among other things, an injunction against the merger and an award of costs and attorneys’ fees. On March 22, 2016, the court granted the parties’ proposed order in the consolidated action to stay the proceedings pending the close of the transaction with Energy Transfer. The plaintiffs have not filed an amended complaint. On July 19, 2017, the court dismissed the action with prejudice as to plaintiffs and without prejudice as to all other shareholders of us.
A purported shareholder filed a separate class action lawsuit in the Delaware Court of Chancery on January 15, 2016. The putative class action complaint alleged that the individual members of our Board of Directors breached their fiduciary duties by, among other things, agreeing to the WPZ Merger Agreement, which purportedly reduced the merger consideration to have been received in the subsequently proposed but now terminated merger with Energy Transfer. The plaintiff filed a motion to voluntarily dismiss, which the court granted on January 13, 2017. On September 2, 2016, the same purported shareholder filed a derivative action claiming that the members of our Board of Directors breached their fiduciary duties by executing the WPZ Merger Agreement as a defensive measure against Energy Transfer. On September 28, 2016, we requested the court dismiss this action, and on May 15, 2017, the court dismissed the action. On June 6, 2017, the plaintiff filed a notice of appeal.
On March 7, 2016, a purported unitholder of WPZ filed a putative class action on behalf of certain purchasers of WPZ units in U.S. District Court in Oklahoma. The action names as defendants us, WPZ, Williams Partners GP LLC, Alan S. Armstrong, and former Chief Financial Officer Donald R. Chappel and alleges violations of certain federal securities laws for failure to disclose Energy Transfer’sTransfer Equity, L.P.’s (Energy Transfer) intention to pursue a purchase of us conditioned on us not closing the May 2015 agreement for a unit-for-stock transaction whereby we would have acquired all of the publicly held outstanding common units of WPZ in exchange for shares of our common stock (WPZ Merger AgreementAgreement) when announcing the WPZ Merger Agreement. The complaint seeks, among other things, damages and an award of costs and attorneys’ fees. The plaintiff filed an amended complaint on August 31, 2016. On October 17, 2016, we requested the court dismiss the action, and on March 8, 2017, the court dismissed the complaint with prejudice. On April 7, 2017, the plaintiff filed a notice of appeal.


Notes (Continued)


We cannot reasonably estimate a range of potential loss related to these matters at this time.
Litigation Against Energy Transfer and Related Parties
On April 6, 2016, we filed suit in Delaware Chancery Court against Energy Transfer and LE GP, LLC (the general partner for Energy Transfer) alleging willful and material breaches of the Agreement and Plan of Merger (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 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 Merger Agreement, alleging material breaches of the Merger Agreement for failing to cooperate and use necessary efforts to obtain a tax opinion required under the Merger Agreement (Tax Opinion) and for otherwise failing to use necessary efforts to consummate the merger under the 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 Merger Agreement due to any failure to obtain the Tax Opinion.
The Court of Chancery coordinated the Special Offering and Tax Opinion suits. On May 20, 2016, the Energy Transfer defendants filed amended affirmative defenses and verified counterclaims in the Special Offering and Tax Opinion suits, alleging certain breaches of the Merger Agreement by us and seeking, among other things, a declaration that we were not entitled to specific performance, that Energy Transfer could terminate the ETC Merger, and that Energy Transfer is entitled to a $1.48 billion termination fee. On June 24, 2016, following a two-day trial, the court issued a Memorandum Opinion and Order denying our requested relief in the Tax Opinion suit. The court did not rule on the substance of our claims related to the Special Offering or on the substance of Energy Transfer’s counterclaims. On June 27, 2016, we filed an appeal of the court’s decision with the Supreme Court of Delaware, seeking reversal and remand to pursue damages. On March 23, 2017, the Supreme Court of Delaware affirmed the Court of Chancery’s ruling. On March 30, 2017, we filed a motion for reargument with the Supreme Court of Delaware, which was denied on April 5, 2017.


Notes (Continued)


On September 16, 2016, we filed an amended complaint with the Court of Chancery seeking damages for breaches of the 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 Merger Agreement. WeOn 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 to dismiss Energy Transfer’s counterclaims,for reargument, which was fully briefedthe Court of Chancery denied on November 14, 2016, and oral argument occurred on November 30, 2016.April 16, 2018. The Court of Chancery scheduled trial for May 20 through May 24, 2019.
Environmental Matters
We are a participant in certain environmental activities in various stages including assessment studies, cleanup operations, andand/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 EPA, andU.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, 2017,March 31, 2018, we have accrued liabilities totaling $40$39 million for these matters, as discussed below. Our accrual reflectsEstimates of the most likely costs of cleanup which are generally based on completed assessment studies, preliminary results of studies, or our experience with other similar cleanup operations. CertainAt March 31, 2018, certain assessment studies arewere still in process for which the ultimate outcome may yield significantly different estimates of most likely costs. Any incremental amount in excess of amounts currently accrued cannot be reasonably estimated at this time due to uncertainty aboutTherefore, the actual number of contaminated sites ultimately


Notes (Continued)


identified,costs incurred will depend on the actualfinal amount, type, and extent of contamination discovered andat these sites, the final cleanup standards mandated by the EPA or other governmental authorities, and other governmental authorities.factors.
The EPA and various state regulatory agencies routinely promulgate and propose new rules, and issue updated guidance to existing rules. More recent rules and 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, the EPA issued its rule regarding National Ambient Air Quality Standards for ground-level ozone, setting a stricter standard of 70 parts per billion. We are monitoring the rule’s implementation as the reduction will trigger additional federal and evaluating potentialstate regulatory actions that may impact our operations. Implementation of the regulations is expected to result in impacts to our operations. For theseoperations and otherincrease the cost of additions to Property, plant, and equipment – net in the Consolidated Balance Sheet for both new regulations, weand existing facilities in affected areas. We are unable to reasonably estimate the costscost of asset additions or modifications necessarythat may be required to complymeet the regulations at this time due to uncertainty created by the 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, 2017March 31, 2018, we have accrued liabilities of $8$7 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, 2017March 31, 2018, we have accrued liabilities totaling $8$10 million for these costs.
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


Notes (Continued)


at the time the sale was consummated. Our responsibilities relate to the operations of the assets and businesses described below.
Former agricultural fertilizer and chemical operations and former retail petroleum and refining operations;
Former petroleum products and natural gas pipelines;
Former petroleum refining facilities;
Former exploration and production and mining operations;
Former electricity and natural gas marketing and trading operations.
At September 30, 2017March 31, 2018, we have accrued environmental liabilities of $24$22 million related to these matters.
Other Divestiture Indemnifications
Pursuant to various purchase and sale agreements relating to divested businesses and assets, we have indemnified certain purchasers against liabilities that they may incur with respect to the businesses and assets acquired from us. The indemnities provided to the purchasers are customary in sale transactions and are contingent upon the purchasers incurring liabilities that are not otherwise recoverable from third parties. The indemnities generally relate to breach of warranties, tax, historic litigation, personal injury, property damage, environmental matters, right of way, and other representations that we have provided.
At September 30, 2017March 31, 2018, 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


Notes (Continued)


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 13 – Segment Disclosures
We have one reportable segment, Williams Partners. All remaining business activities are included in Other. (See Note 1 – General, Description of Business, and Basis of Presentation.)
Our segment presentation of Williams Partners, which includes our consolidated master limited partnership, is reflective of the parent-level focus by our chief operating decision-maker, considering the resource allocation and governance provisions associated with the master limited partnership structure. This partnership maintains capital and cash management structures that are separate from ours. It is self-funding and maintains its own lines of bank credit and cash management accounts. These factors serve to differentiate the management of this entity as a whole.
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


Notes (Continued)


performance measure used by our chief operating decision maker in measuring performance and allocating resources among our reportable segments.
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.


Notes (Continued)


The following table reflects the reconciliation of Segment revenues to Total revenues as reported in the Consolidated Statement of OperationsIncome and Total assets by reportable segment.
Williams
Partners
 Other Eliminations Total
Williams
Partners
 Other Eliminations Total
(Millions)(Millions)
Three Months Ended September 30, 2017
Three Months Ended March 31, 2018Three Months Ended March 31, 2018
Segment revenues:       
Service revenues       
External$1,346
 $5
 $—
 $1,351
Internal—
 3
 (3) —
Total service revenues1,346
 8
 (3) 1,351
Total service revenues – commodity consideration (external only)101
 —
 —
 101
Product sales       
External636
 —
 —
 636
Internal—
 —
 —
 —
Total product sales636
 —
 —
 636
Total revenues$2,083
 $8
 $(3) $2,088
       
Three Months Ended March 31, 2017Three Months Ended March 31, 2017
Segment revenues:              
Service revenues              
External$1,304
 $6
 $—
 $1,310
$1,256
 $5
 $—
 $1,261
Internal—
 2
 (2) —
—
 3
 (3) —
Total service revenues1,304
 8
 (2) 1,310
1,256
 8
 (3) 1,261
Product sales              
External581
 —
 —
 581
727
 —
 —
 727
Internal—
 —
 —
 —
—
 —
 —
 —
Total product sales581
 —
 —
 581
727
 —
 —
 727
Total revenues$1,885
 $8
 $(2) $1,891
$1,983
 $8
 $(3) $1,988
              
Three Months Ended September 30, 2016
Segment revenues:       
Service revenues       
External$1,241
 $6
 $—
 $1,247
Internal11
 3
 (14) —
Total service revenues1,252
 9
 (14) 1,247
Product sales       
External655
 3
 —
 658
Internal—
 6
 (6) —
Total product sales655
 9
 (6) 658
Total revenues$1,907
 $18
 $(20) $1,905
       
Nine Months Ended September 30, 2017
Segment revenues:       
Service revenues       
External$3,836
 $17
 $—
 $3,853
Internal1
 8
 (9) —
Total service revenues3,837
 25
 (9) 3,853
Product sales       
External1,950
 —
 —
 1,950
Internal—
 —
 —
 —
Total product sales1,950
 —
 —
 1,950
Total revenues$5,787
 $25
 $(9) $5,803
       
Nine Months Ended September 30, 2016
Segment revenues:       
Service revenues       
External$3,656
 $22
 $—
 $3,678
Internal32
 17
 (49) —
Total service revenues3,688
 39
 (49) 3,678
Product sales       
External1,613
 10
 —
 1,623
Internal—
 16
 (16) —
Total product sales1,613
 26
 (16) 1,623
Total revenues$5,301
 $65
 $(65) $5,301
       
September 30, 2017       
March 31, 2018       
Total assets$45,635
 $570
 $(85) $46,120
$46,575
 $541
 $(64) $47,052
December 31, 2016       
December 31, 2017       
Total assets$46,265
 $685
 $(115) $46,835
$45,903
 $589
 $(140) $46,352


Notes (Continued)


The following table reflects the reconciliation of Modified EBITDA to Net income (loss) as reported in the Consolidated Statement of OperationsIncome.
Three Months Ended 
 September 30,		 Nine Months Ended 
 September 30,		Three Months Ended 
 March 31,
2017 2016 2017 20162018 2017
(Millions)(Millions)
Modified EBITDA by segment:          
Williams Partners$1,000
 $1,070
 $3,208
 $2,629
$1,107
 $1,132
Other(61) (67) (60) (534)13
 18
939
 1,003
 3,148
 2,095
1,120
 1,150
Accretion expense associated with asset retirement obligations for nonregulated operations(7) (9) (23) (24)(8) (7)
Depreciation and amortization expenses(433) (435) (1,308) (1,326)(431) (442)
Equity earnings (losses)115
 104
 347
 302
82
 107
Impairment of equity-method investments—
 —
 —
 (112)
Other investing income (loss) – net4
 28
 278
 64
4
 272
Proportional Modified EBITDA of equity-method investments(202) (194) (611) (574)(169) (194)
Interest expense(267) (297) (818) (886)(273) (280)
(Provision) benefit for income taxes(24) (69) (126) 74
(55) (37)
Net income (loss)$125
 $131
 $887
 $(387)$270
 $569


Item 2
Management’s Discussion and Analysis of
Financial Condition and Results of Operations
General
We are an energy infrastructure company focused on connecting North America’s significant hydrocarbon resource plays to growing markets for natural gas and NGLs. Our operations are located principally in the United States. We have one reportable segment, Williams Partners. All remaining business activities and corporate operations are included in Other.
Williams Partners
Williams Partners consists of our consolidated master limited partnership, WPZ, which includes gas pipeline and midstream businesses. The gas pipeline businesses include interstate natural gas pipelines and pipeline joint project investments; and the midstream businesses provide natural gas gathering, treating, and processing services; NGL production, fractionation, storage, marketing, and transportation; deepwater production handling and crude oil transportation services; and isare comprised of several wholly owned and partially owned subsidiaries and joint project investments. As of September 30, 2017,March 31, 2018, we own 74 percent of the interests in WPZ.
Williams Partners’ gas pipeline businesses consist primarily of Transco and Northwest Pipeline. The gas pipeline business also holds interests in joint venture interstate and intrastate natural gas pipeline systems including a 50 percent equity-method investment in Gulfstream and a 41 percent interest in Constitution (a consolidated entity), which is under development.developing a pipeline project (See Note 3 – Variable Interest Entitiesof Notes to Consolidated Financial Statements). As of December 31, 2016,2017, Transco and Northwest Pipeline owned and operated a combined total of approximately 13,600 miles of pipelines with a total annual throughput of approximately 4,2304,533 Tbtu of natural gas and peak-day delivery capacity of approximately 15.518.8 MMdth of natural gas.
Williams Partners’ midstream businesses primarily consist of (1) natural gas gathering, treating, compression, and processing; (2) NGL fractionation, storage, and transportation; (3) crude oil production handling and transportation; and (4) olefins production. (See Note 3 – Divestitures of Notes to Consolidated Financial Statements.)WPZ sold its olefins operations in July 2017. The primary service areas are concentrated in major producing basins in Colorado, Texas, Oklahoma, Kansas, New Mexico, Wyoming, the Gulf of Mexico, Louisiana, Pennsylvania, West Virginia, New York, and Ohio which include the Barnett, Eagle Ford, Haynesville, Marcellus, Niobrara, and Utica shale plays as well as the Mid-Continent region.
The midstream businesses include equity-method investments in natural gas gathering and processing assets and NGL fractionation and transportation assets, including a 62 percent equity-method investment in UEOM, a 69 percent equity-method investment in Laurel Mountain, a 58 percent equity-method investment in Caiman II, a 60 percent equity-method investment in Discovery, a 50 percent equity-method investment in OPPL, and Appalachia Midstream Services, LLC, which owns an approximate average 66 percent equity-method investment interest in multiple gas gathering systems in the Marcellus Shale (Appalachia Midstream Investments), as well as our previously owned 50 percent equity-method investment in the Delaware basin gas gathering system (DBJV) in the Mid-Continent region (see Note 4 – Investing Activities of Notes to Consolidated Financial Statements).
The midstream businesses previously included Canadian midstream operations, which were comprised of an oil sands offgas processing plant near Fort McMurray, Alberta and an NGL/olefin fractionation facility at Redwater, Alberta. In September 2016, these Canadian operations were sold.
Williams Partners’ ongoing strategy is to safely and reliably operate large-scale, interstate natural gas transmission and midstream infrastructures 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 and investing in growing markets and areas of increasing natural gas demand.
Williams Partners’ interstate transmission and related 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


Management’s Discussion and Analysis (Continued)

limited near-term impact on these revenues because the majority of cost of service is recovered through firm capacity reservation charges in transportation rates.
Other

Our former NGL & Petchem Services segment included certain domestic olefins pipeline assets as well as certain Canadian assets, which included a liquids extraction plant located near Fort McMurray, Alberta, that began operations in March 2016,
Management’s Discussion and a propane dehydrogenation facility which was under development. In September 2016, the Canadian assets were sold. Considering this, the remaining assets are now reported within Other, effective January 1, 2017. Other also includes business activities that are not operating segments, as well as corporate operations. Prior period segment disclosures have been recast for this segment change.Analysis (Continued)

Financial Repositioning
In January 2017, we announcedentered 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 (see Note 10 – Stockholders’ Equity of Notes to Consolidated Financial Statements).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. Subsequent to these transactions and as of September 30, 2017, we own a 74 percent limited partner interest in WPZ.
Termination of WPZ Merger Agreement
On May 12, 2015, we entered into an agreement for a unit-for-stock transaction whereby we would have acquired all of the publicly held outstanding common units of WPZ in exchange for shares of our common stock (WPZ Merger Agreement).
On September 28, 2015, prior to our entry into the Merger Agreement, we entered into a Termination Agreement and Release (Termination Agreement), terminating the WPZ Merger Agreement. Under the terms of the Termination Agreement, we were required to pay a $428 million termination fee to WPZ, at which time we owned approximately 60 percent, including the interests of the general partner and IDRs. Such termination fee settled through a reduction of quarterly incentive distributions we were entitled to receive from WPZ (such reduction not to exceed $209 million per quarter). The distributions from WPZ in November 2015, February 2016, and May 2016 were reduced by $209 million, $209 million, and $10 million, respectively, related to this termination fee.
Dividends
In September 2017,March 2018, we paid a regular quarterly dividend of $0.30$0.34 per share.
Overview of NineThree Months Ended September 30, 2017March 31, 2018
Net income (loss) attributable to The Williams Companies, Inc., for the ninethree months ended September 30, 2017, changed favorably by $896March 31, 2018, decreased $221 million compared to the ninethree months ended September 30, 2016, reflecting an increaseMarch 31, 2017, primarily due to the absence of $972a $269 million in operating income, a $214 million increase in Other investing income (loss) – net primarilygain associated with the disposition of certain equity-method investments in 2017 the absence of $112 million of impairments of equity-method investments incurred in 2016, and reduced interest expense, partially offset by a $200 millionmodest increase in the provision for income taxes driven by higher pre-tax income, partially offset bywhich reflects the absence of a prior year $127 million benefit associated with the release of a valuation allowance on a capital loss carryover and a $378 million increase in net income attributable to noncontrolling interests primarily due to increased income at WPZ. The improvement in operating income reflects a gain of $1.095 billion from the sale of our Geismar Interest, increase service revenue from expansion projects, and lower costs and expenses, partially offset by a $113 million decrease in product margins primarily due to the loss of olefins volumes as a result of the sale of our Gulf Olefins and Canadian operations, and a $425 million increase in impairments of certain assets.carryover.


Management’s Discussion and Analysis (Continued)

Unless indicated otherwise, the following discussion and analysis of results of operations and financial condition and liquidity should be read in conjunction with the consolidated financial statements and notes thereto of this Form 10‑Q and our annual consolidated financial statementsAnnual Report on Form 10-K dated February 22, 2018.
FERC Income Tax Policy Revision
On March 15, 2018, the FERC issued a policy 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 both an income tax allowance and notes theretoa return on equity pursuant to the discounted cash flow methodology. The FERC will no longer permit an MLP pipeline to recover an income tax allowance in Exhibit 99.1its 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. The FERC also issued a Notice of Proposed Rulemaking proposing a 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 this policy statement. Furthermore, the FERC 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 accumulated deferred income tax 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 Form 8-K dated May 25, 2017.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 by our interstate natural gas pipelines may be adversely impacted.
Pension Deferred Vested Benefit Early Payout ProgramRevenue Recognition
In September 2017, we initiated a program to pay out certain deferred vested pension benefits to reduce investment risk, cash funding volatility, and administrative costs. Eligible participants had until October 31, 2017, to make elections. We expect to make the lump-sum payments and commence the annuity payments in December 2017, and intend to fund the payments from existing assets in our pension plans. As a result of these payouts and based on current assumptions,the adoption of Accounting Standards Update 2014-09, Revenues from Contracts with Customers (ASC 606), we expect tonow record a pre-tax, non-cash settlement chargerevenues 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 fourth quarterConsolidated Statement of 2017Income. 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 estimate will be between $70 millionhave historically characterized as commodity margin. This presentation is being reflected prospectively


Management’s Discussion and $100 million. The ultimate amountAnalysis (Continued)

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 chargenew 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 allocated to the performance obligations over the term of the new contract. As a result, we will largely depend uponrecognize the actual leveldeferred revenue over longer periods than application of participation as well asrevenue 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 actuarial assumptions used to measureprevious guidance, offset by increased revenues in later reporting periods given the pension plans’ assets and obligations,longer period of recognition.
Expansion Project Updates
Significant expansion project updates for the period, including the discount rates.projects placed into service are described below. Ongoing major expansion projects are discussed later in Company Outlook.
Williams Partners
New York Bay ExpansionGarden State
In October 2017,March 2018, Phase 2 of the New York BayGarden State Expansion to the Transco systemproject was placed into service. TheThis project expanded 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 and the Narrows meter station in New York. The project increased capacity by 115 Mdth/d.
Dalton
In August 2017, the Dalton expansion to the Transco system was placed into service. This project expanded Transco’s existing natural gas transmission system together with greenfield facilities to provide incremental firm transportation capacity from our Station 210 in New Jersey to marketsa new interconnection on our Trenton Woodbury Lateral in northwest Georgia. On AprilNew Jersey. Phase 1 2017, we began providing firm transportation service through the mainline portion of the project on an interim basis and wewas placed the full project into service in August 2017. The projectSeptember 2017, and together they increased capacity by 448180 Mdth/d.
Susquehanna Supply Hub
During the first quarter of 2018, the remaining facilities 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 is expected to increase gathering capacity, allowing a certain producer to fulfill its commitment to deliver 850 Mdth/d to our Atlantic Sunrise development.
Hillabee
In July 2017, Phase I of the Hillabee Expansion Project was placed into service. The project involves an expansion of Transco’s existing natural gas transmission system from our Station 85 in west central Alabama to a new interconnection with the Sabal Trail pipeline in Alabama. The project will be constructed in phases, and all of the project expansion capacity will be leasedis dedicated to Sabal Trail.Trail pursuant to a capacity lease agreement. We placed a portion of Phase I into service in June of 2017 and the remainder of Phase I into service in July of 2017. Phase I increased capacity by 818 Mdth/d. The in-service date of Phase II is planned for the second quarter of 2020 and together they are expected to increase capacity by 1,025 Mdth/d.
In March 2016, WPZ entered into an agreement with the member-sponsors of Sabal Trail to resolve several matters. In accordance with the agreement, the member-sponsors paid us an aggregate amount of $240 million in three equal installments as certain milestones of the project were met. The first $80 million payment was received in March 2016, the second installment was received in September 2016 and the third installment was received in July 2017. WPZ expects to recognize income associated with these receipts over the term of the capacity lease agreement.
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). We, alongIn compliance with other intervenors,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 have filed petitionsauthorization for rehearing with the court to overturnproject.


Management’s Discussion and Analysis (Continued)

the remedy that would involve vacating the FERC certificate order. If the court’s mandate is issued prior to the FERC re-issuing certificate authority for the projects, we believe that the FERC will take the necessary steps (which may include issuing temporary certificate authority) to avoid any lapse in federal authorization for the projects.
Hurricanes Harvey and Irma
We are not aware of any major damage to our facilities as a result of Hurricanes Harvey and Irma.
Geismar olefins facility monetization
In July 2017, WPZ completed the sale of its Geismar Interest for $2.084 billion in cash. WPZ received a final working capital adjustment of $12 million in October 2017. Additionally, WPZ entered into a long-term supply and transportation agreement with the purchaser to provide feedstock to the plant via its Bayou Ethane pipeline system, which is expected to provide a long-term, fee-based revenue stream. (SeeNote 3 – Divestitures of Notes to Consolidated Financial Statements.)
Following this sale, the cash proceeds were used to repay WPZ’s $850 million term loan. WPZ also plans to use these proceeds to fund a portion of the capital and investment expenditures that are a part of its growth portfolio.
Acquisition of additional interests in Appalachia Midstream Investments
During the first quarter of 2017, WPZ exchanged all of its 50 percent interest in DBJV for an increased interest in two natural gas gathering systems that are part of the Appalachia Midstream Investments and $155 million in cash. Following this exchange, WPZ has an approximate average 66 percent interest in the Appalachia Midstream Investments. WPZ also sold all of its 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 Operations within the Williams Partners segment. (See Note 4 – Investing Activities of Notes to Consolidated Financial Statements.)
Commodity Prices
NGL per-unit margins were approximately 646 percent higher in the first ninethree months of 20172018 compared to the same period of 20162017 primarily due to a 4219 percent increase in per-unit non-ethane prices. The per-unit margin increase also reflects the absence of our former Canadian operations which had lower per-unit non-ethane margins in the prior year compared to our domestic operations. These favorable impacts were partially offset byprices and an approximate 3721 percent increasedecrease 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.


Management’s Discussion and Analysis (Continued)

The following graph illustrates the NGL production and sales volumes, as well as the margin differential between ethane and non-ethane products and the relative mix of those products.
chart3qtr2017rev1.jpg
The potential impact of commodity prices on our business for the remainder of 20172018 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.
Our business plan for 20172018 includes a continued focus on growing our fee-based businesses, executing growth projects 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 growth in the previously discussed financial repositioning transactionsNortheast region. WPZ intends to fund planned growth capital with retained cash flow and the monetization of our Geismar Interest. For WPZ, these transactions serve to improve its cost of capital, remove its needdebt, and based on currently forecasted projects, does not expect to access the public equity markets for the next several years, enhance growth, and provide for debt reduction, solidifying WPZ as an attractive financing vehicle. The transactions also facilitate a reduction of our parent-level debt and provide for dividend growth flexibility, while retaining strategic and financing flexibility.years.
Our growth capital and investment expenditures in 20172018 are currently expected to be between $2.1 billion and $2.8at least $2.7 billion. Approximately $1.4 billion to $1.9$1.7 billion of our growth capital funding needs include Transco expansions and other interstate pipeline growth projects, most of which are fully contracted with firm transportation agreements. The remaining growth capital spending in 20172018 primarily reflects investment in gathering and processing systems in the Northeast region limited primarily to known new producer volumes, including volumes that support Transco expansion projects including our Atlantic Sunrise project. In addition to growth capital and investment expenditures, we also


Management’s Discussion and Analysis (Continued)

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 expansions and fee-based gathering and processing projects, as well as the sale of our Canadian operations and Geismar Interest, fee-based businesses are becoming an even morea 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 the remainder of 2017,2018, current forward market prices indicate oil prices are expected to be higher compared to 2017 and NGL prices are expected to be slightly higher or comparable with 2017, while natural gas prices are expected to be relativelylower or comparable with 2017. We continue to address certain pricing risks through the same period in 2016, while NGL prices are expected to be higher.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. The credit profiles of certain of our producer customers have been, and may continue tocould be challenged as a result of lower energy commodity prices. Unfavorable changes in energy commodity prices or the credit profile of our producer customers may also result in noncash impairments of our assets.
In 2017,2018, 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-service in 2017.2018 including the Atlantic Sunrise project. For our non-regulated businesses, we anticipate increases in fee-based revenue due to expanded capacity in the Eastern Gulf areaNortheast region,


Management’s Discussion and a slight increase inAnalysis (Continued)

partially offset by lower fee-based revenue in the NortheastWest region. Partially offsetting these increases are expected declinesAs previously discussed, under the new accounting guidance for revenue recognition, deferred revenue under certain contracts will be recognized over longer periods than under the prior guidance, contributing to the decrease in fee-basedannual revenue infor the WesternWest region. We expect overall gathering and processing volumes to remain steadygrow in 20172018 and increase thereafter to meet the growing demand for natural gas and natural gas products. We also anticipate lower general and administrative expenses due to the full year impact of prior year cost reduction initiativesinitiatives.
In accordance with the timing prescribed by its previous rate case settlement, Transco is required to file a rate case no later than August 31, 2018.  If the case is filed on August 31, 2018, Transco expects the FERC to suspend rate increases to be effective March 1, 2019, subject to refund and asset monetizations.the outcome of a hearing, and accept rate decreases to be effective October 1, 2018, not subject to refund. The final rates will be subject to a settlement agreement with customers and the FERC or the outcome of a hearing.
Potential risks and obstacles that could impact the execution of our plan include:
Certain aspects of Tax Reform, including regulatory liabilities relating to reduced corporate federal income tax rates, and the recent FERC income tax policy revision could adversely impact the rates we can charge on our regulated pipelines (see Note 1 – General, Description of Business, and Basis of Presentation of Notes to Consolidated Financial Statements);
Opposition to 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 Corporation and its affiliates;
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;
Lower than expected distributions from WPZ;
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, as filed with the SEC on February 22, 2017.2018 and in Part II, Item 1A. Risk Factors in this Quarterly Report on Form 10-Q.
We seek to maintain a strong financial position and liquidity, as well as manage a diversified portfolio of energy infrastructure assets which continue to serve key growth markets and supply basins in the United States.
Expansion Projects
Williams Partners’ ongoing major expansion projects include the following:
Appalachian Basin Expansion
We recently agreed to expand our services to a customer to provide 660 MMcf/d of processing wet gas capacity in the Marcellus and Upper Devonian Shale in West Virginia. Associated with this agreement, we expect to further


Management’s Discussion and Analysis (Continued)

expand the processing capacity of our Oak Grove facility, which has the ability to increase capacity by an additional 1.8 Bcf/d. Additionally, with the same customer, we secured a gathering dedication agreement to gather dry gas in this same region. These expansions will be supported by long-term, fee-based agreements and volumetric commitments.
Atlantic Sunrise
In February 2017, we received approval from the FERC to expand 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 onin September 1, 2017 and it increased capacity by


Management’s Discussion and Analysis (Continued)

400 Mdth/d. We plan to place the full project into service during mid-2018, assuming timely receipt of all remaining regulatory approvals. The full project is expected to increase capacity by 1,700 Mdth/d.
Constitution Pipeline
We currently own 41 percent of Constitution with three other parties holding 25 percent, 24 percent, and 10 percent, respectively. We will beare the operator of Constitution. The 126-mile Constitution pipeline willis 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 the FERC to construct and operate its proposed pipeline, which will have an expected capacity 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. As to the denial itself, the court determined that NYSDEC’s action was not arbitrary or capricious. Constitution filed a petition for rehearing ofwith the Second Circuit Court’s decision,Court of Appeals, but in October the court denied our petition.
We remain steadfastly committed to the project and inIn 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. In January 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.
The project’s sponsors remain committed to the project. In lightFebruary 2018, we filed a request with the FERC for rehearing of its finding that the NYSDEC did not waive the Section 401 certification requirement. If the FERC denies such request, we will file a petition for review with the D.C. Circuit Court of Appeals. In January 2018, we filed a petition with the United States Supreme Court to review the decision of the Second Circuit Court of Appeals that upheld the merits of the NYSDEC’s denial of the water qualitySection 401 certification. However, on April 30, 2018, the Court denied our petition. This decision is separate and independent from (and thus has no impact on) our request for rehearing (or appeal) of the FERC’s decision that the NYSDEC did not waive the Section 401 certification andrequirement.
Should any court or FERC decision determine that the actions taken to challengeNYSDEC waived the decision,Section 401 certification requirement, we estimate that the anticipated target in-service date is as early asfor the first half of 2019, which assumes the timely receipt of a Noticeproject would be approximately 10 to Proceed from the FERC. (See12 months following any such determination. (See Note 23 – Variable Interest Entities of Notes to Consolidated Financial Statements.)
Eagle Ford
We plan to expand our gathering infrastructure in the Eagle Ford region in order to meet our customers’ production plans. The expansion of the gathering infrastructure includes the addition of well connections and gathering pipeline to the existing systems.
Garden StateGateway
In April 2016, we received approval from the FERC to expand 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. The project will be constructed in phases and is expected to increase capacity by 180 Mdth/d. We placed the initial phase of the project into service on September 9,November 2017, and plan to place the remaining portion of the project into service during the second quarter of 2018.


Management’s Discussion and Analysis (Continued)

Gulf Connector
In August 2016, we filed an application with the FERC to expand Transco’s existing natural gas transmission system to provide incremental firm transportation capacity from PennEast Pipeline Company's proposed interconnection with Transco’s mainline south of Station 205 in New Jersey to other existing Transco meter stations within New Jersey. We plan to place the project into service in the first quarter of 2021, 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


Management’s Discussion and Analysis (Continued)

points in Wharton and San Patricio Counties, Texas. The project will be constructed in two phases and we plan to place both phases into service during the first half 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 will be constructed in phases, and all of the project expansion capacity will be leasedis dedicated to Sabal Trail.Trail pursuant to a capacity lease agreement. We placed a portion of Phase I into service in June of 2017 and the remainder of Phase I into service in July of 2017. Phase I increased capacity by 818 Mdth/d. The in-service date of Phase II is planned for the second quarter of 2020 and together they are expected to increase capacity by 1,025 Mdth/d. See Williams PartnersExpansion Project Updates within Overview of Nine Months Ended September 30, 2017.Overview.
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 half of 2019.
North Seattle Lateral Upgrade
In May 2017, we filed an application with 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 as the fourth quarter of 2019. The project is expected to increase capacity by up toapproximately 159 Mdth/d.
Northeast Supply Enhancement
In March 2017, we filed an application with 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, the NYSDEC denied, without prejudice, Transco’s application for certain permits required for the project. We have addressed the technical issues identified by NYSDEC and will refile our application for the permits. We plan to place the project into service in late 2019 or during the first half of 2020, assuming timely receipt of all necessary regulatory approvals. The project is expected to increase capacity by 400 Mdth/d.
SusquehannaOhio River Supply Hub Expansion
The Susquehanna Supply Hub Expansion, which involves two new compression facilitiesWe agreed to expand our services for certain customers to provide additional processing wet gas capacity in the Marcellus and Upper Devonian Shale in West Virginia and Pennsylvania. Associated with an additional 49,000 horsepower and 59 milesthese agreements, we plan to further expand the processing capacity of 12 inchour Oak Grove facility by 400 MMcf/d. Additionally, with one of these customers, we secured a gathering dedication agreement to 24 inch pipeline, is expected to increase gathering capacity, allowing a certain producer to fulfill its commitment to deliver 850 Mdth/d to our Atlantic Sunrise development. We anticipategather dry gas in this expansionsame region. These expansions will be completedsupported by the end of 2017.long-term, fee-based agreements and volumetric commitments.
Virginia Southside IIRivervale South to Market
In July 2016,August 2017, we received approval fromfiled an application with the FERC to expand Transco’s existing natural gas transmission system together with greenfield facilities to provide incremental firm transportation capacity from our Station 210 inthe existing Rivervale interconnection with Tennessee Gas Pipeline on Transco’s North New Jersey and our Station 165 in VirginiaExtension to a proposed delivery point on a new lateral extending from our Brunswick Lateral in Virginia.other existing Transco locations within New Jersey. We plan to place the project into service duringas early as the fourth quarter of 2017 and it2019, assuming timely receipt of all necessary regulatory approvals. The project is expected to increase capacity by 250190 Mdth/d.


Management’s Discussion and Analysis (Continued)

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 service in late 2020, assuming timely receipt of all necessary regulatory approvals. The project is expected to increase capacity by 296 Mdth/d.
Critical Accounting Estimates
Constitution Pipeline Capitalized Project Costs
As of September 30, 2017,March 31, 2018, Property, plant, and equipmentinour Consolidated Balance Sheet includes approximately $381$379 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, we evaluated the capitalized project costs for impairment as recently as September 30,December 31, 2017, and determined that no impairment was necessary. Our evaluation considered probability-weighted scenarios of undiscounted future net cash flows, including a scenarioscenarios assuming construction of the pipeline, as well as a scenario where the project does not proceed. We continue to monitor the capitalized project costs associated with Constitution for potential impairment.

Property, Plant, and Equipment and Other Identifiable Intangible Assets
We evaluateThese scenarios included our property, plant, and equipment and other identifiable intangible assets for impairment when events or changes in circumstances indicate, in our judgment, that the carrying value of such assets may not be recoverable. When an indicator of impairment has occurred, we compare ourmost recent estimate of undiscounted future cash flows attributable to the assets to the carrying valuetotal construction costs. The probability-weighted scenarios also considered our assessment of the assets to determine whether an impairment has occurred and we may apply a probability-weighted approach to consider the likelihood of different cash flow assumptions and possible outcomes including selling in the near term or holding for the remaining estimated useful life. If an impairmentsuccess of the carrying value has occurred, we determine the amount of the impairment recognized by estimating the fair value of the assets and recordingpath to obtain necessary certification, as described in Company Outlook. It is reasonably possible that future unfavorable developments, such as a loss for the amount that the carrying value exceeds the estimated fair value. This evaluation is performed at the lowest level for which separately identifiable cash flows exist.
As disclosed in our 2016 Annual Report on Form 10–K and subsequent Quarterly Reports on Form 10–Q, we may monetize assets that are not core to our strategy which could result in impairments of certain equity–method investments, property, plant, and equipment, and intangible assets. Such impairments could potentially be caused by indications of fair value implied through the monetization process or, in the case of asset dispositions that are part of a broader asset group, the impact of the loss of future estimated cash flows.
During the third quarter of 2017, we received solicitations and engaged in negotiations for the sale of certain gas gathering assets within the Mid-Continent region. As a result of these events, we evaluated the Mid-Continent asset group, which includes property, plant, and equipment and intangible assets, for impairment. Our evaluation considered thereduced likelihood of divesting certain assets within the Mid-Continent region as well as information developed from the negotiation process that impacted our estimatesuccess, increased estimates of future cash flows associated with these assets. The estimated undiscounted future cash flows were determined to be below the carrying amount for these assets. We computed the estimated fair value using an income approach and incorporated market inputs based on ongoing negotiations for the potential sale of a portion of the underlying assets. For the income approach, we utilized a discount rate of 10.2 percent, reflecting an estimate of our cost of capital and risks associated with the underlying assets. As a result of this evaluation, we recorded an impairment charge of $1.019 billion for the difference between the estimated fair value and carrying amount of these assets.
Judgments and assumptions are inherent in estimating undiscounted future cash flows, fair values, and the probability-weighting of possible outcomes. The use of alternate judgments and assumptionsconstruction costs, or further significant delays, could result in a different determination affecting the consolidated financial statements.

future impairment.
Equity-Method Investment in UEOMInvestments
As of September 30, 2017,March 31, 2018, the carrying value of our equity-method investment in UEOMDiscovery is $1.4 billion.$524 million. During the thirdfourth quarter of 2017, we became awarecertain customers of potential changes toDiscovery terminated a significant offshore gas gathering agreement following the future drilling plansshut-in of a certain producer which could delay and/or reduce volumes available for processing at UEOM.production after the associated wells ceased flowing. As a result, we evaluated this investment for impairment at September 30,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 estimatedcontinue to monitor this investment as it is reasonably possible that an impairment could be required in the fair valuefuture if commercial development activities are not as successful or as timely as assumed.
Regulatory Liabilities Resulting from Tax Reform
In December 2017, 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 investment in UEOM usingregulated natural gas pipelines are subject to the rate-making policies of the FERC, which have historically permitted the recovery of an income approachtax allowance that included probability-weighted scenarios assuming varying levels of volume declines, as well asincludes a scenario with less volume degradation asdeferred income tax component. As a result of an assumed salethe reduced income tax rate from Tax Reform and the collection of the underlying reserveshistorical rates that reflected historical federal income tax rates, we expect that our regulated natural gas pipelines will be required to another producer. We utilized a discount rate of 10.8 percent.


Management’s Discussion and Analysis (Continued)

The estimated fair value of our investment in UEOM exceeded its carrying value by more than 10 percent. Judgments and assumptions are inherent in our estimates ofreturn amounts to certain customers through future cash flows, discount rates and scenario probabilities.have accordingly established regulatory liabilities totaling $678 million as of March 31, 2018. The usetiming and actual amount of alternate judgmentssuch return will be subject to future negotiations regarding this matter and assumptions could result in a different calculationmany other elements of fair value, which could ultimately result in the recognitioncost–of–service rate proceedings, including other costs of an impairment charge in the consolidated financial statements.

providing service.



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, 2017,March 31, 2018, compared to the three and nine months ended September 30, 2016.March 31, 2017. 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 
 March 31,		    
2017 2016 $ Change* % Change* 2017 2016 $ Change* % Change*2018 2017 $ Change* % Change*
(Millions)     (Millions)    (Millions)    
Revenues:                      
Service revenues$1,310
 $1,247
 +63
 +5 % $3,853
 $3,678
 +175
 +5 %$1,351
 $1,261
 +90
 +7 %
Service revenues – commodity consideration101
 —
 +101
 NM
Product sales581
 658
 -77
 -12 % 1,950
 1,623
 +327
 +20 %636
 727
 -91
 -13 %
Total revenues1,891
 1,905
     5,803
 5,301
    2,088
 1,988
    
Costs and expenses:                      
Product costs504
 461
 -43
 -9 % 1,620
 1,180
 -440
 -37 %613
 579
 -34
 -6 %
Processing commodity expenses35
 —
 -35
 NM
Operating and maintenance expenses400
 394
 -6
 -2 % 1,157
 1,179
 +22
 +2 %357
 371
 +14
 +4 %
Depreciation and amortization expenses433
 435
 +2
 — % 1,308
 1,326
 +18
 +1 %431
 442
 +11
 +2 %
Selling, general, and administrative expenses138
 177
 +39
 +22 % 452
 556
 +104
 +19 %132
 161
 +29
 +18 %
Gain on sale of Geismar Interest(1,095) —
 +1,095
 NM
 (1,095) —
 +1,095
 NM
Impairment of certain assets1,210
 1
 -1,209
 NM
 1,236
 811
 -425
 -52 %
Other (income) expense – net24
 92
 +68
 +74 % 34
 130
 +96
 +74 %29
 5
 -24
 NM
Total costs and expenses1,614
 1,560
     4,712
 5,182
    1,597
 1,558
    
Operating income (loss)277
 345
     1,091
 119
    491
 430
    
Equity earnings (losses)115
 104
 +11
 +11 % 347
 302
 +45
 +15 %82
 107
 -25
 -23 %
Impairment of equity-method investments—
 —
 —
 NM
 —
 (112) +112
 +100 %
Other investing income (loss) – net4
 28
 -24
 -86 % 278
 64
 +214
 NM
4
 272
 -268
 -99 %
Interest expense(267) (297) +30
 +10 % (818) (886) +68
 +8 %(273) (280) +7
 +3 %
Other income (expense) – net20
 20
 —
 — % 115
 52
 +63
 +121 %21
 77
 -56
 -73 %
Income (loss) before income taxes149
 200
     1,013
 (461)    325
 606
    
Provision (benefit) for income taxes24
 69
 +45
 +65 % 126
 (74) -200
 NM
55
 37
 -18
 -49 %
Net income (loss)125
 131
     887
 (387)    270
 569
    
Less: Net income (loss) attributable to noncontrolling interests92
 70
 -22
 -31 % 400
 22
 -378
 NM
118
 196
 +78
 +40 %
Net income (loss) attributable to The Williams Companies, Inc.$33
 $61
     $487
 $(409)    $152
 $373
    

*+ = Favorable change; - = Unfavorable change; NM = A percentage calculation is not meaningful due to a change in signs, a zero-value denominator, or a percentage change greater than 200.
Three months ended March 31, 2018 vs. three months ended March 31, 2017
Service revenuesincreased primarily due to higher transportation fee revenues at Transco associated with expansion projects placed in-service in 2017 and 2018, as well as higher gathering volumes across certain of our operating locations.
Service revenues – commodity considerationincreased as the result of implementing ASC 606 using a modified retrospective approach, effective January 1, 2018. Therefore, prior periods have not been recast under the new guidance. 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.


Management’s Discussion and Analysis (Continued)

Three months ended September 30, 2017 vs. three months ended September 30, 2016
Service revenuesincreased due to higher revenues from the Barnett Shale related to the amortization of deferred revenue associated with the restructuring of contracts in the fourth quarter of 2016, as well as higher volumes primarily associated with Transco’s natural gas transportation fee revenues associated with expansion projects placed in-service during 2016 and 2017, partially offset by lower rates in the western region also associated with the fourth quarter 2016 contract restructuring. The increase inProduct sales Service revenues was also partially offset by lower volumes in most of the Utica Shale and western regions, driven by natural declines.
Product salesdecreased primarily due to $146 million lower olefin sales associated with decreasedthe absence of volumes relateddue to the salesales of our Geismar Interest in July 2017, our Canadianolefin operations in September 2016, and our RGP Splitter in June 2017. The decrease in Product sales is2017, partially offset by higher marketing sales primarily due to significantly higher prices, partially offset by lower volumes.system management gas sales.
The increase in Product costs is primarily due to the same factors that increased marketing sales,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 system management gas costs. This increase is partially offset by lowerthe absence of $75 million of olefin feedstock andvolumes associated with the sales of our olefin operations, as well as the absence of 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 decreased volumes.the production of equity NGLs as previously described in conjunction with the implementation of ASC 606.
Operating and maintenance expenses increaseddecreased primarily due to an increase in Transco pipeline integrity testing and costs, and general maintenance. These increases are partially offset by the absence of $23 million of costs associated with our former Canadian and Gulf Olefinsolefin operations and ongoing cost containment efforts.efforts, partially offset by higher operating and maintenance expenses at Transco primarily associated with pipeline integrity, general maintenance, and other testing.
Depreciation and amortization expenses decreased primarily due to the absence of costs associated with our former Canadian and Gulf Olefinsolefin operations, partially offset by new assets placed in-service.
Selling, general, and administrative expenses decreased primarily due to the absence of project developmentseverance and organizational realignment costs incurred in the third quarter of 2016 associated with our former Canadian PDH facility, lower strategic alternatives costs, and2017, the absence of costs associated with our former Canadianolefin operations, and Gulf Olefins operations. These decreases were partially offset by higher organizational realignment and severance costs. (See Note 5 – Other Income and Expenses of Notes to Consolidated Financial Statements.)
The Gain on sale of Geismar Interest reflects the gain recognized on the sale of our Geismar Interest in July 2017. (See Note 3 – Divestitures of Notes to Consolidated Financial Statements.)ongoing cost containment efforts.
The unfavorable change in Impairment of certain assets reflects the 2017 impairments of certain gathering operations in the Mid-Continent and Marcellus South regions and certain NGL pipeline assets (see Note 11 – Fair Value Measurements and Guarantees of Notes to Consolidated Financial Statements).
The favorable change in Other (income) expense – net within Operating income (loss) includes the absence of the 2016 loss on the sale of our Canadian operations, as well as lower product development costs at Constitution.gains from certain contract settlements and terminations in 2017, and certain regulatory charges associated with Tax Reform in 2018.
The favorable change in Operating income (loss) changed unfavorablyincludes an increase in Service revenues primarily associated with Transco projects placed in-service in 2017 and 2018, and lower Selling, general, and administrative expenses due to the 2017 impairmentabsence of certain gathering operationscosts incurred in the Mid-Continent and Marcellus South regions and lower olefin product margins resulting from the sale of our Geismar Interest and Canadian operations,2017, partially offset by the gain on sale of our Geismar Interest, higher service revenues associated with certain projects placed in-service, and the absence of a 2016 loss on the sale ofoperating income related to our Canadian operations.former olefin operations, and higher operating costs at Transco.
The favorableunfavorable change in Equity earnings (losses) is due to a decrease in volumes at Discovery, partially offset by an increase in ownership of our Appalachian Midstream Investments, partially offset by lower Discovery results due to lower fee revenues, and lower UEOM results driven by lower processing volumes from the Utica gathering system.
Other investing income (loss) – net decreased due to the absence of a 2016 gain on the sale of an equity-method investment interest in a gathering system that was part of our Appalachia Midstream Investments gathering system.Investments. (See Note 4 – Investing Activities of Notes to Consolidated Financial Statements.)


Management’s Discussion and Analysis (Continued)

Interest expenseThe unfavorable change in Other investing income (loss) – net decreasedis due to lower Interest incurred primarily attributable to debt retirementsthe absence of a gain on disposition of our investments in DBJV and lower borrowings on our credit facilitiesRanch Westex JV LLC in 2017. (See Note 94 – Debt and Banking ArrangementsInvesting 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 5 – Other Income and Expenses of Notes to Consolidated Financial Statements.) The unfavorable change also includes the absence of a benefit in 2017 related to equity funds used during construction (AFUDC).
Provision (benefit) for income taxes changed favorablyunfavorably primarily due to the absence of releasing a $127 million valuation allowance on a capital loss carryover in 2017, partially offset by lower pretax income. See Note 6 – Provision (Benefit) for Income Taxes of Notes to Consolidated Financial Statements for a discussion of the effective tax rate compared to the federal statutory rate for both periods.
The unfavorablefavorable change in Net income (loss) attributable to noncontrolling interests is primarily due to the impact of decreased income allocated to the WPZ general partner driven by the permanent waiver of IDRs, partially offset by a decrease in the ownership of the noncontrolling interests and lower operating results at WPZ. Both the permanent waiver of IDRs and the change in ownership are associated with the first-quarter 2017 Financial Repositioning (see Note 1 – General, Description of Business, and Basis of Presentation of Notes to Consolidated Financial Statements).
Nine months ended September 30, 2017 vs. nine months ended September 30, 2016
Service revenuesincreased due to the recognition of deferred revenue in the Barnett Shale region associated with the restructuring of contracts in the fourth quarter of 2016. Service revenues also increased due to higher volumes primarily in the eastern Gulf Coast region, including the impact of new volumes at Gulfstar One related to the Gunflint expansion placed in-service in the third quarter of 2016, the absence of the temporary shut-down of Gulfstar One in the second quarter of 2016 to tie into Gunflint, the absence of producers’ 2016 operational issues in the Tubular Bells field in the first quarter of 2016, and higher volumes at Devils Tower related to Kodiak field production. Additionally, Transco experienced higher natural gas transportation fee revenues reflecting expansion projects placed in-service in 2016 and 2017, as well as an increase in storage revenues due to the absence of an accrual for potential refunds associated with a ruling received in certain rate case litigation in 2016. These increases were partially offset by lower rates primarily in the Barnett Shale region associated with the previously discussed contract restructure, as well as lower volumes in most of the Utica Shale and western regions driven by natural declines and extreme weather conditions in the Rocky Mountains in 2017. Service revenues increases were also partially offset by the absence of our former Canadian and Gulf Olefins operations.
Product sales increased due to higher marketing revenues primarily associated with significantly higher prices and volumes. Revenues from the sale of our equity NGLs increased primarily due to higher non-ethane NGL prices, partially offset by lower volumes. These increases were partially offset by lower olefin production sales due to lower volumes resulting from the sale of our former Gulf Olefins and Canadian operations.
The increase in Product costs is primarily due to the same factors that increased marketing sales, partially offset by lower olefin feedstock purchases associated with the sale of our Gulf Olefins and Canadian operations.
Operating and maintenance expenses decreased primarily due to the absence of costs associated with our former Canadian and Gulf Olefins operations and lower labor-related costs resulting from our workforce reductions that occurred late in first-quarter 2016, and ongoing cost containment efforts. These decreases are partially offset by an increase in pipeline integrity testing on Transco, and general maintenance.
Depreciation and amortization expenses decreased primarily due to the absence of our former Canadian and Gulf Olefins operations, partially offset by new assets placed in-service.
Selling, general, and administrative expenses decreased primarily due to the absence of certain project development costs associated with the Canadian PDH facility that we expensed in 2016, lower labor-related costs resulting from our workforce reductions that occurred late in first-quarter 2016, ongoing cost containment efforts, the absence of costs associated with our former Canadian operations, as well as lower strategic development costs. These decreases were partially offset by higher severance and organizational realignment costs. (See Note 5 – Other Income and Expenses of Notes to Consolidated Financial Statements.)
The Gain on sale of Geismar Interest reflects the gain recognized on the sale of our Geismar Interest in July 2017. (See Note 3 – Divestitures of Notes to Consolidated Financial Statements.)


Management’s Discussion and Analysis (Continued)

The unfavorable change in Impairment of certain assetsreflects 2017 impairments of certain gathering operations in the Mid-Continent and Marcellus South regions, certain NGL pipeline assets, and an olefins pipeline project in the Gulf coast region. These 2017 impairments are partially offset by the absence of 2016 impairments of our former Canadian operations and certain Mid-Continent assets (see Note 11 – Fair Value Measurements and Guarantees of Notes to Consolidated Financial Statements).
The favorable change in Other (income) expense – net within Operating income (loss) includes the absence of the 2016 loss on the sale of our Canadian operations, gains from certain contract settlements and terminations in 2017, a gain on the sale of our RGP Splitter in 2017, the absence of an unfavorable change in foreign currency exchange associated with our former Canadian operations, insurance proceeds received in 2017 associated with the Geismar Incident, and lower project development costs at Constitution. These favorable changes were partially offset by the accrual of additional expenses in 2017 related to the Geismar Incident, as well as the absence of a gain in first-quarter 2016 associated with the sale of unused pipe.
Operating income (loss) changed favorably primarily due to the gain on sale of our Geismar Interest, the absence of the 2016 impairments of our former Canadian operations and certain Mid-Continent assets, higher service revenues from expansion projects placed in-service in 2016 and 2017, as well as ongoing cost containment efforts, including workforce reductions in first-quarter 2016. Operating income (loss) also improved due to the absence of a 2016 loss on the sale of our Canadian operations, the absence of an operating loss associated with our former Canadian operations, gains from certain contract settlements, and the sale of our RGP Splitter. These favorable changes were partially offset by a 2017 impairment of certain gathering operations in the Mid-Continent and Marcellus South regions, and certain NGL pipeline assets, as well as the absence of operating income associated with our former Gulf Olefins operations.
The favorable change in Equity earnings (losses) is due to an increase in ownership of our Appalachian Midstream Investments, improved results at Laurel Mountain Midstream due to higher rates, and improved results at Discovery attributable to the accelerated recognition of previously deferred revenue, partially offset by lower UEOM results driven by lower processing volumes from the Utica gathering system.
The decrease in Impairment of equity-method investments reflects the absence of first-quarter 2016 impairment charges associated with our DBJV and Laurel Mountain equity-method investments. (See Note 11 – Fair Value Measurements and Guarantees of Notes to Consolidated Financial Statements.)
Other investing income (loss) – net reflects the gain on disposition of our investments in DBJV and Ranch Westex JV LLC in 2017 (see Note 4 – Investing Activities of Notes to Consolidated Financial Statements), partially offset by the absence of interest income received in 2016 associated with a receivable related to the sale of certain former Venezuelan assets and the absence of a 2016 gain on the sale of an equity-method investment interest in a gathering system that was part of our Appalachia Midstream Investments gathering system.
Interest expense decreased primarily due to lower Interest incurred primarily attributable to debt retirements and lower borrowings on our credit facilities in the first quarter of 2017. (See Note 9 – Debt and Banking Arrangements of Notes to Consolidated Financial Statements.)
Other income (expense) – net below Operating income (loss) changed favorably primarily due to a net gain on early debt retirements in 2017, and favorable changes related to equity funds used during construction (AFUDC). (See Note 5 – Other Income and Expenses of Notes to Consolidated Financial Statements.)
Provision (benefit) for income taxes changed unfavorably primarily due to higher pretax income. See Note 6 – Provision (Benefit) for Income Taxes of Notes to Consolidated Financial Statements for a discussion of the effective tax rate compared to the federal statutory rate for both periods.
The unfavorable change in Net income (loss) attributable to noncontrolling interests is primarily due to higher operating results at WPZ, the impact of decreased income allocated to the WPZ general partner driven by the permanent waiver of IDRs, partially offset by a decrease in the ownership of the noncontrolling interests. Both the permanent waiver of IDRs and the change in ownership are associated with the first-quarter 2017 Financial Repositioning (see Note 1 – General, Description of Business, and Basis of Presentation of Notes to Consolidated Financial Statements).


Management’s Discussion and Analysis (Continued)

In addition, improved results in our Gulfstar operations also contributed to the unfavorable change in Net income (loss) attributable to noncontrolling interests, partially offset by lower results for our Cardinal gathering system.
Period-Over-Period Operating Results - Segments
We evaluate segment operating performance based upon Modified EBITDA. Note 13 – Segment Disclosures of Notes to Consolidated Financial Statements includes a reconciliation of this non-GAAP measure to Net income (loss). Management uses Modified EBITDA because it is an accepted financial indicator used by investors to compare company performance. In addition, management believes that this measure provides investors an enhanced perspective of the operating performance of our assets. Modified EBITDA should not be considered in isolation or as a substitute for a measure of performance prepared in accordance with GAAP.
Williams Partners
Three Months Ended 
 September 30,		 Nine Months Ended 
 September 30,		Three Months Ended 
 March 31,
2017 2016 2017 20162018 2017
(Millions)(Millions)
Service revenues$1,304
 $1,252
 $3,837
 $3,688
$1,346
 $1,256
Service revenues - commodity consideration101
 —
Product sales581
 655
 1,950
 1,613
636
 727
Segment revenues1,885
 1,907
 5,787
 5,301
2,083
 1,983
          
Product costs(504) (463) (1,620) (1,183)(613) (579)
Processing commodity expenses(35) —
Other segment costs and expenses(536) (567) (1,520) (1,660)(497) (466)
Gain on sale of Geismar Interest1,095
 —
 1,095
 —
Impairment of certain assets(1,142) (1) (1,145) (403)
Proportional Modified EBITDA of equity-method investments202
 194
 611
 574
169
 194
Williams Partners Modified EBITDA$1,000
 $1,070
 $3,208
 $2,629
$1,107
 $1,132
          
NGL margin$46
 $45
 $139
 $119
$65
 $51
Olefin margin2
 122
 126
 267
—
 71
Three months ended September 30, 2017March 31, 2018 vs. three months ended September 30, 2016March 31, 2017
Modified EBITDA decreased primarily due to impairmentsthe absence of certain gathering$51 million of Modified EBITDA from our olefin operations that were sold in July 2017, higher Other segment costs and expenses, and lower olefin margins due to the sale ofProportional Modified EBITDA from our Gulf Olefins (Geismar olefin and RGP Splitter plants) operations in 2017 and our Canadian operations in 2016,equity-method investments, partially offset by a $1.095 billion gain on the sale of our Geismar Interest in third-quarter 2017, the absence of the $32 million loss on the sale of our former Canadian operations in third-quarter 2016, and higher serviceService revenues primarily driven by expansions of our Transco pipeline and our Gulfstar One facilities.pipeline.
Service revenues increased primarily due to:
A $53$64 million increase in Transco’s natural gas transportation fee revenues primarily due to a $58 million increase associated with expansion projects placed in service in 2017 and 2018;
A $20 million increase primarily related to higher gathering volumes in the Haynesville Shale region, as well as higher gathering volumes across most other areas;
A $5 million increase in fractionation revenues at Ohio Valley Midstream;
Earlier recognition of revenues associated with MVC’s and other deferred revenue due to implementing the new revenue recognition guidance under ASC 606, offset by a $25 million decrease related to lower amortization of deferred revenue associated with the up-front cash payment received in conjunction with the fourth quarter 2016 Barnett Shale contract restructuring;
A $43$9 million increase in Transco’s natural gas transportation fee revenuesdecrease at Northwest Pipeline primarily due to the reduction of its rates as a $45 million increase associated with expansion projects placed in-service in 2016 and 2017;
A $20 million increase in fee revenues in the eastern Gulf Coast region associated primarily with higher volumes, including the impactresult of new volumes at Gulfstar One from the Gunflint expansion placed in service in the third quarter of 2016, and the absence of the temporary shutdown and subsequent ramp-up of Gulfstar One in the second and third quarters of 2016 to tie-in Gunflint;a recent rate case settlement that became effective January 1, 2018.


Management’s Discussion and Analysis (Continued)

A $29 million decrease related to lower gathering rates in the Barnett Shale related to the fourth quarter 2016 contract restructuring, along with lower rates recognized in the Niobrara and Eagle Ford Shale regions. Rates recognized in the Niobrara region represent a portion of the total contractual rate, with the difference reflected as deferred revenue;
An $18 million decrease in feeService revenues in the eastern Gulf Coast region- commodity considerationincreased as a result of implementing ASC 606 using a temporary increase during 2016 related to disrupted operations of a competitor and shut-ins of certain wells behind Devils Tower as a result of production issues;
A decrease of $15 million primarily due to the absence ofmodified retrospective approach. These revenues associated with our former Canadian operations that were sold in September 2016;
In the Northeast region, a $10 million increase in fee revenuesrepresent consideration we receive in the Susquehanna Supply Hub driven by 10 percent higher gatheredform of commodities as full or partial payment for gathering and processing services provided. Most of these NGL volumes reflecting increased customer production,are sold within the month processed and therefore are offset by a $10 million decrease in the Utica gathering system associated with 6 percent lower gathered volumes driven by natural declines in the wet gas areas, partially offset by higher volumes from new development in the dry gas areas.Product costs below.
Product sales decreased primarily due to:
A $196$146 million decrease in olefin sales associated with the absence of volumes due to the absencesale of our olefin operations;
A $39 million increase in system management gas sales, associated with the Gulf Olefins operations that were sold in July 2017 and June 2017, respectively, and our former Canadian operations that were sold in September 2016;
A $12 million decrease in revenues from our equity NGLs primarilypartially due to the absenceimplementation of ASC 606. System management gas sales associated with our former Canadian operationsare offset in Product costs and, the absence of a temporary increase in 2016 duetherefore, have no impact to disrupted operations of a competitor, partially offset by higher NGL prices;Modified EBITDA;
A $142$5 million increase in marketing revenues primarily due to significantly$98 million higher NGL marketing revenues reflecting both higher prices and NGL volumes, partiallysignificantly offset by lowera $50 million decrease in crude natural gas,oil marketing revenues, as well as a $39 million decrease in propylene and propylene volumes (offsetethylene marketing revenues due to the sale of our olefin operations. Crude oil marketing revenues decreased as this activity is presented on a net basis within Product costs in marketing purchases).2018 in conjunction with the adoption of ASC 606.
Product costs increased primarily due to:
A $141 million increase in marketing purchases primarily due to the same factors that increasedimpact of ASC 606 in which costs reflected in this line item for 2018 include volumes acquired as commodity considerations for NGL processing services, as well as $39 million in higher system management gas costs and $8 million in higher marketing sales (offset in marketing revenues). Thecosts. This increase in marketing costs does not reflectis partially offset by the intercompany costsabsence of $75 million of olefin feedstock volumes associated with certain gathering and processing services performed by an affiliate;
An $81 million decrease in olefin feedstock purchases reflecting the salesales of our Gulf Olefins and Canadian operations;olefin operations, as well as the absence of 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.
A $13 million decrease inProcessing commodity expenses presents the natural gas purchases associated with the production of equity NGLs reflecting lower volumes as previously discussed, partially offset by a slightdescribed 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 decreased primarily due to:
A $71 million decrease in olefin product margins due to the absence of volumes resulting from the 2017 sales of our olefin operations;
A $14 million increase in per-unit natural gasNGL product margins, which is substantially due to $13 million in higher non-ethane margins, driven by higher non-ethane prices.
The favorableunfavorable change in Other segment costs and expenses includes the absence of the $32a $30 million net gain on early retirement of debt in 2017 and a $7 million net loss on the saleearly retirement of our former Canadian operationsdebt in third-quarter 2016,2018, $14 million of increased operating costs at Transco primarily for pipeline integrity testing, general maintenance and other testing, and $13 million related to the absence of $39 millionfavorable contract settlements and terminations in the first quarter of operating and other expenses associated with our Gulf Olefins and Canadian operations, favorable impacts related to gains on asset retirements, and ongoing cost containment efforts.2017. These decreasesunfavorable changes are partially offset by an increase in pipeline integrity testing on Transco andthe absence of $27 million of costs associated with the closure of our office in Oklahoma City.
Gain on sale of Geismar Interest reflects the gain recognized on the sale of our Geismar Interest in July 2017. (See Note 3 – Divestitures of Notes to Consolidated Financial Statements.)
Impairment of certain assets increased primarily due to a $1.019 billion impairment of certain gatheringformer olefin operations, in the Mid-Continent region, a $115 million impairment of certain gathering operations in the Marcellus South region,as well as ongoing cost containment efforts.


Management’s Discussion and Analysis (Continued)

and write-downs of certain assets that are no longer in use or are surplus in nature. (See Note 11 – Fair Value Measurements and Guarantees of Notes to Consolidated Financial Statements.)
The increasedecrease in Proportional Modified EBITDA of equity-method investments includes a $31 million increase at Appalachian Midstream Investments reflecting our increased ownership and higher gathering volumes reflecting the absence of shut-in volumes from 2016 and increased customer production. This increase is partially offset by a $9$28 million decrease fromat Discovery primarily due to production issuesending on certain wells, and temporary hurricane related shut-ins, an $8a $9 million decrease at UEOM driven by lower processing volumes from the Utica gathering system, as noted above, anddue to the divestiture of our interests in DBJV and Ranch Westex JV LLC late in the first quarter of 2017.
Nine months ended September 30, 2017, vs. nine months ended September 30, 2016
Modified EBITDA increased primarily due to a $1.095 billion gain on the sale of our Geismar Interest in third-quarter 2017, the absence of impairments of our Canadian operations and certain gathering assets in the Mid-Continent region in the second quarter of 2016, the absence of a loss on the sale of our former Canadian operations in third-quarter 2016, lower segment costs and expenses, higher service revenues, and higher Proportional Modified EBITDA of equity-method investments. These increases are partially offset by the impairments of certain gathering operations in 2017 and lower olefin margins due to the sale of our Gulf Olefins operations early in the third quarter of 2017.
Service revenues increased primarily due to:
A $158 million increase related to the amortization of deferred revenue associated with the up-front cash payment received in conjunction with the fourth quarter 2016 Barnett Shale contract restructuring;
Higher eastern Gulf Coast region revenue of $114 million associated primarily with higher volumes, including the impact of new volumes at Gulfstar One related to the Gunflint expansion placed in-service in the third quarter of 2016, the absence of the temporary shut-down and subsequent ramp-up of Gulfstar One in the second and third quarters of 2016 to tie-in Gunflint, and the absence of producers’ operational issues in the Tubular Bells field during the first quarter of 2016, along with higher volumes at Devils Tower related to Kodiak field production (although certain wells in this field are now shut-in due to production issues). This increase is partially offset by a $17 million decrease in western Gulf Coast region fee revenues due primarily to producer maintenance.
Transco’s natural gas transportation fee revenues increased $74 million primarily due to an $88$22 million increase associated with expansion projects placed in-service in 2016 and 2017, partially offset by lower volume-based transportation services revenues;
A $14 million increase in Transco’s storage revenue primarilyat Appalachian Midstream Investments reflecting the absence of an accrual for potential refunds associated with a ruling received in certain rate case litigation in 2016;
A $75 million decrease related to lower gathering rates in the West region including lower rates in the Barnett Shale area primarily due to the fourth quarter 2016 contract restructuring, along with lower rates recognized in the Niobrara, Eagle Ford Shale, and Haynesville Shale regions. Rates recognized in the Niobrara region represent a portion of the total contractual rate that is received, with the difference reflected as deferred revenue;
A $72 million decrease driven by lower volumes in the West region primarily as a result of natural declines and more extreme weather conditions in the Rocky Mountains in the first quarter of 2017;
A $36 million decrease due to the absence of revenue generated by our former Canadian operations that were sold in September 2016;increased ownership.
In the Northeast region, a slight decline reflecting a $52 million decrease in the Utica gathering system primarily due to 20 percent lower gathered volumes driven by natural declines in the wet gas areas which are partially offset by higher volumes from new development in the dry gas areas. This decrease is mostly offset by a $32


Management’s Discussion and Analysis (Continued)

million increase in gathering fee revenue at Susquehanna Supply Hub driven by 12 percent higher gathered volumes reflecting increased customer production, and a $22 million increase in fee revenue at Ohio Valley Midstream reflecting the absence of shut-in volumes from the first half of 2016, as well as new production coming online.
Product sales increased primarily due to:
A $520 million increase in marketing revenues primarily due to significantly higher prices and volumes (substantially offset in marketing purchases);
A $26 million increase in revenues from our equity NGLs including a $76 million increase driven by higher non-ethane prices, the effect of which is partially offset by a $36 million decrease due to the absence of NGL production revenues associated with our former Canadian operations and a $14 million decrease related to lower volumes at our domestic plants driven by severe winter conditions in the first quarter of 2017, the absence of temporary volumes in 2016 related to disrupted operations of a competitor and natural declines;
A $7 million increase in system management gas sales from Transco. System management gas sales are offset in Product costs and, therefore, have no impact on Modified EBITDA;
A $217 million decrease in olefin sales primarily due to a $180 million decrease reflecting the sale of our Gulf Olefins operations, a $29 million decrease due to the sale of the Canadian operations in 2016 and a $16 million decrease at our Geismar plant in the first half of 2017 due primarily to lower volumes associated with the electrical outage in second-quarter 2017, as well as planned maintenance downtime in first-quarter 2017. These items were partially offset by $8 million higher sales at the RGP Splitter in the first half 2017 due primarily to higher propylene prices.
Product costs increased primarily due to:
A $501 million increase in marketing purchases primarily due to the same factors that increased marketing sales (more than offset in marketing revenues). The increase in marketing costs does not reflect the intercompany costs associated with certain gathering and processing services performed by an affiliate;
A $7 million increase in system management gas costs (offset in Product sales);
A $5 million increase in natural gas purchases associated with the production of equity NGLs reflecting a significant increase in per-unit natural gas prices and increased sales from inventory, partially offset by a $24 million decrease due to the sale of our Canadian operations;
A $79 million decrease in olefin feedstock purchases primarily due to the absence of $76 million in feedstock purchases in third-quarter 2017 reflecting the sale of the Gulf Olefins operations as well as the absence of $9 million in costs associated with our former Canadian operations, partially offset by $6 million higher feedstock costs in the first half of 2017.
The favorable change in Other segment costs and expenses includes the absence of the $32 million loss on the sale of our former Canadian operations in third-quarter 2016, a reduction of $75 million of operating and other expenses associated with our Gulf Olefins and Canadian operations, a $27 million net gain associated with early debt retirement, a decrease in labor-related expenses resulting from our first quarter 2016 workforce reduction, favorable contract settlements and terminations in the first quarter of 2017, a $12 million gain on the sale of the RGP Splitter, and a favorable change in equity AFUDC, primarily associated with an increase in Transco’s capital spending, which is partially offset by a decrease in capital spending at Constitution. These decreases in expenses are partially offset by an increase in pipeline integrity testing on Transco, higher Geismar selling expenses, repairs related to the Geismar electrical outage, and expenses associated with the closure of our office in Oklahoma City.


Management’s Discussion and Analysis (Continued)

Gain on sale of Geismar Interest reflects the gain recognized on the sale of our Geismar Interest in July 2017. (See Note 3 – Divestitures of Notes to Consolidated Financial Statements.)
Impairment of certain assets increased primarily due to a $1.019 billion impairment of certain gathering operations in the Mid-Continent and a $115 million impairment of certain gathering operations in the Marcellus South region, partially offset by the absence of a $341 million impairment of our former Canadian operations and a $48 million impairment of certain Mid-Continent gathering assets in the second quarter of 2016. (See Note 11 – Fair Value Measurements and Guarantees of Notes to Consolidated Financial Statements.)
The increase in Proportional Modified EBITDA of equity-method investments includes a $60 million increase at Appalachia Midstream Investments primarily due to our increased ownership late in the first quarter of 2017 and higher gathering volumes reflecting the absence of shut-in volumes from 2016 and increased customer production; a $10 million increase at Laurel Mountain Midstream associated with higher gathering revenue due to higher rates reflecting higher natural gas prices; an $8 million increase from Discovery primarily attributable to the accelerated recognition of previously deferred revenue and higher NGL margins, partially offset by lower fee revenue driven by production issues at certain wells, higher turbine maintenance expenses, temporary hurricane-related shut-ins, and maintenance on the Keathley Canyon Connector pipeline. These increases are partially offset by a $29 million decrease at UEOM reflecting lower processing volumes from the wet gas areas of the Utica gathering system as noted above and the divestiture of our interests in DBJV and Ranch Westex JV LLC late in the first quarter of 2017.
Other
 Three Months Ended September 30, Nine Months Ended September 30,
 2017 2016 2017 2016
 (Millions)
Service revenues$8
 $9
 $25
 $39
Product sales—
 9
 —
 26
Segment revenues8
 18
 25
 65
        
Product costs—
 (4) —
 (13)
Other segment costs and expenses(1) (81) 6
 (178)
Impairment of certain assets(68) —
 (91) (408)
Other Modified EBITDA$(61) $(67) $(60) $(534)
 Three Months Ended March 31,
 2018 2017
 (Millions)
Other Modified EBITDA$13
 $18
Three months ended September 30, 2017March 31, 2018 vs. three months ended September 30, 2016March 31, 2017
Modified EBITDA improved primarily due to lower Other segment costs and expenses, partially offset by the impairment of a certain NGL pipeline.
Other segment costs and expenses improved primarily due to:
The absence of a $33 million loss on the sale of our Canadian operations in September 2016;
The absence of $16 million of certain project development costs associated with the Canadian PDH facility that we expensed in 2016;
A $16 million decrease in costs related to our evaluation of strategic alternatives;
The absence of $11 million of transportation and fractionation fees incurred in 2016 related to the Redwater fractionation facility, which was included in the sale of our Canadian operations in September 2016.
Impairment of certain assets increased due to the impairment of a certain NGL pipeline asset in the third quarter of 2017. (See Note 11 – Fair Value Measurements and Guarantees of Notes to Consolidated Financial Statements.)


Management’s Discussion and Analysis (Continued)

Nine months ended September 30, 2017 vs. nine months ended September 30, 2016
Modified EBITDA improved primarily due to the absence of a second-quarter 2016 impairment of our former Canadian operations and improved Other segment costs and expenses.
Service revenues decreased primarily due to a reduction in Canadian construction management revenues.
Product sales and Product costs decreased due to the sale of the Horizon liquids extraction plant in September 2016.
Other segment costs and expenses changed favorably primarily due to:
The absence of $61$23 million of certain project development costs associated with the Canadian PDH facility that we expensed in 2016;
A $32 million favorable change in the loss on the sale of our Canadian operations in September 2016;
The absence of $32 million of transportation and fractionation fees incurred in 2016 related to the Redwater fractionation facility, which was included in the sale of our Canadian operations in September 2016;
A $31 million decrease in costs related to our evaluation of strategic alternatives;
A $28 million increase in income associated with an increase in a regulatory asset primarilyrelated to deferred taxes on equity funds used during construction, partially offset by lower general and administrative costs, driven by our increased ownership in WPZ. (Seethe absence of expenses associated with the first-quarter 2017 Financial Repositioning (see Note 51 – Other IncomeGeneral, Description of Business, and ExpensesBasis of Presentation of Notes to Consolidated Financial Statements).
Impairment of certain assets decreased primarily due to the absence of the 2016 impairment of our Canadian operations, partially offset by the impairment of an olefins pipeline project in the Gulf Coast region in the second quarter of 2017 and the impairment of a certain NGL pipeline asset in the third quarter of 2017. (See Note 11 – Fair Value Measurements and Guarantees of Notes to Consolidated Financial Statements.)



Management’s Discussion and Analysis (Continued)

Management’s Discussion and Analysis of Financial Condition and Liquidity
Outlook
Fee-based businesses are becoming an even morea 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 2018 are currently expected to be between $2.1 billion and $2.8 billion in 2017.at least $2.7 billion. Approximately $1.4 billion to $1.9$1.7 billion of our growth capital funding needs include Transco expansions and other interstate pipeline growth projects, most of which are fully contracted with firm transportation agreements. The remaining growth capital spending in 20172018 primarily reflects investment in gathering and processing systems in the Northeast region limited primarily to known new producer volumes, including volumes that support Transco expansion projects including our Atlantic Sunrise project. 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. WPZ intends to fund its planned 2018 growth capital with retained cash flow and debt. We retain the flexibility to adjust planned levels of growth capital and investment expenditures in response to changes in economic conditions or business opportunities.
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 2017.2018. WPZ expects to be self-funding and maintain separate bank accounts and credit facilities, including its commercial paper program. Our expectedpotential material internal and external sources and uses of consolidated liquidity for 20172018 are as follows:
   Applicable To:
   WPZ WMB
Sources:     
 Cash and cash equivalents on hand ü ü
 Cash generated from operations ü  
 Distributions from investment in WPZ   ü
 Distributions from equity-method investees ü  
 Utilization of credit facilities and/or commercial paper program ü ü
 Cash proceeds from issuance of debt and/or equity securities ü ü
 Proceeds from asset monetizations ü ü
      
Uses:     
 Working capital requirements ü ü
 Capital and investment expenditures ü  
 Investment in WPZ   ü
 Quarterly distributions to unitholders ü  
 Quarterly dividends to shareholders   ü
 Debt service payments, including payments of long-term debt ü ü
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, 2017,March 31, 2018, we had a working capital deficitsurplus of $61$235 million. Our available liquidity is as follows:
September 30, 2017March 31, 2018
Available LiquidityWPZ WMB TotalWPZ WMB Total
(Millions)(Millions)
Cash and cash equivalents$1,165
 $7
 $1,172
$1,268
 $24
 $1,292
Capacity available under our $1.5 billion credit facility (1)  1,100
 1,100
  1,300
 1,300
Capacity available to WPZ under its $3.5 billion credit facility, less amounts outstanding under its $3 billion commercial paper program (2)3,500
   3,500
3,500
   3,500
$4,665
 $1,107
 $5,772
$4,768
 $1,324
 $6,092
 
(1)Through September 30, 2017,March 31, 2018, the highest amount outstanding under our credit facility during 20172018 was $805$290 million. At September 30, 2017,March 31, 2018, we were in compliance with the financial covenants associated with this credit facility. Borrowing capacity available under this facility as of October 31, 2017,May 1, 2018, was $1.125$1.3 billion.
(2)
In managing our available liquidity, we do not expect a maximum outstanding amount in excess of the capacity of WPZ’s credit facility inclusive of any outstanding amounts under its commercial paper program. As of September 30, 2017,Through March 31, 2018, no Commercial paperamount was outstanding under WPZ’s commercial paper program. Through September 30, 2017, the highest amount outstanding under WPZ’s commercial paper program and credit facility during 2017 was $178 million.2018. At September 30, 2017March 31, 2018, WPZ was in compliance with the financial covenants associated with this credit facility. Borrowing capacity available under WPZ’s $3.5 billion credit facility as of October 31, 2017,May 1, 2018, was $3.5 billion.
Dividends
As part of the Financial Repositioning announced in January 2017, weWe increased our regular quarterly cash dividend by 50approximately 13 percent from the previous quarterly cash dividend of $0.20$0.30 per share paid in December 2016,each quarter of 2017, to $0.30$0.34 per share for the dividendsquarterly cash dividend paid in March 2017, June 2017, and September 2017.2018.
Registrations
In September 2016, WPZ filed a registration statement for its distribution reinvestment program.
In May 2015,February 2018, we filed a shelf registration statement, as a well-known seasoned issuer.
In February 2015,2018, 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 2015,2018, 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. These sales are to be made over a period of time and from time to time in transactions at prices which are market prices prevailing at the time of sale, prices related to market price, or at negotiated prices. Such sales are to be made pursuant to an equity
In September 2016, WPZ filed a registration statement for its distribution agreement between WPZ and certain banks who may act as sales agents or purchase for their own accounts as principals.reinvestment program.
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 ability to borrow money is impacted by our credit ratings and the credit ratings of WPZ. The current ratings are as follows:
 Rating Agency Outlook 
Senior Unsecured
Debt Rating
 
Corporate
Credit Rating
WMB:S&P Global Ratings Stable BB+ BB+
 Moody’s Investors Service Positive Ba2 N/A
 Fitch Ratings Stable BB+ N/A
        
WPZ:S&P Global Ratings Stable BBB BBB
 Moody’s Investors Service Positive Baa3 N/A
 Fitch Ratings Positive BBB- N/A

During March 2017, S&P Global Ratings upgraded its rating for both WMB and WPZ. In July 2017, Fitch Ratings changed its Outlook for WPZ to Positive, and in September 2017, Moody’s Investors Service changed its Outlook for both WMB and WPZ to Positive. These credit ratings are included for informational purposes and are not recommendations to buy, sell, or hold our stock,or WPZ’s 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 or WPZ the ratings shown above even if we or WPZ meet or exceed their current criteria. A downgrade of our credit ratings or the credit ratings of WPZ might increase our future cost of borrowing and would require us to provide additional collateral to third parties, negatively impacting our available liquidity.


Management’s Discussion and Analysis (Continued)

Sources (Uses) of Cash
The following table summarizes the sources (uses) of cash and cash equivalents for each of the periods presented (see Notes to Consolidated Financial Statements for the Notes referenced in the table):
Cash Flow Nine Months Ended 
 September 30,		Cash Flow Three Months Ended 
 March 31,
Category 2017 2016Category 2018 2017
 (Millions) (Millions)
Sources of cash and cash equivalents:        
Operating activities – netOperating $1,837
 $2,097
Operating $694
 $727
Proceeds from equity offeringsFinancing 2,130
 8
Proceeds from sale of businesses, net of cash divested (see Note 3)Investing 2,056
 712
Proceeds from long-term debt (see Note 9)Financing 1,698
 998
Financing 1,808
 —
Proceeds from our credit-facility borrowingsFinancing 1,315
 2,045
Financing 240
 470
Distributions from unconsolidated affiliates in excess of cumulative earningsInvesting 394
 341
Contributions in aid of constructionInvesting 190
 131
Proceeds from equity issuancesFinancing 10
 2,122
Proceeds from dispositions of equity-method investments (see Note 4)Investing 200
 —
Investing —
 200
Proceeds from WPZ’s credit-facility borrowingsFinancing —
 2,665
        
Uses of cash and cash equivalents:        
Capital expendituresInvesting (957) (511)
Payments of long-term debt (see Note 9)Financing (3,785) (375)Financing (750) (1,350)
Capital expendituresInvesting (1,700) (1,577)
Payments on our credit-facility borrowingsFinancing (1,690) (1,845)Financing (310) (650)
Quarterly dividends on common stockFinancing (744) (1,111)
Dividends and distributions to noncontrolling interestsFinancing (636) (715)
Dividends paidFinancing (281) (248)
Dividends and distributions paid to noncontrolling interestsFinancing (165) (242)
Purchases of and contributions to equity-method investmentsInvesting (103) (132)Investing (21) (52)
Payments of WPZ’s commercial paper – netFinancing (93) (499)Financing —
 (93)
Payments on WPZ’s credit-facility borrowingsFinancing —
 (2,745)
Contribution to Gulfstream for repayment of debtFinancing —
 (148)
        
Other sources / (uses) – netFinancing and Investing 123
 258
Financing and Investing (65) (35)
Increase (decrease) in cash and cash equivalents $1,002
 $(23) $393
 $469


Management’s Discussion and Analysis (Continued)

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, and Net (gain) loss on disposition of equity-method investments, Impairment of equity-method investments, Gain on sale of Geismar Interest, and Impairment of and net (gain) loss on sale of assets and businesses.investments. Our Net cash provided (used) by operating activities for the ninethree months ended September 30, 2017,March 31, 2018, decreased from the same period in 20162017 primarily due to the absenceimpact of net unfavorable changes in 2017 of certain minimum volume commitment receipts due to contract restructurings, partially offset by higher operating incomeworking capital and decreased distributions from unconsolidated affiliates in 2017.2018.
Off-Balance Sheet Arrangements and Guarantees of Debt or Other Commitments
We have various other guarantees and commitments which are disclosed in Note 23 – Variable Interest Entities, Note 9 – Debt and Banking Arrangements, Note 11 – Fair Value Measurements and Guarantees, and Note 12 – Contingent Liabilities of Notes to Consolidated Financial Statements. We do not believe these guarantees and commitments or the possible fulfillment of them will prevent us from meeting our liquidity needs.


Item 3
Quantitative and Qualitative Disclosures About Market Risk
Interest Rate Risk
Our current interest rate risk exposure is related primarily to our debt portfolio and has not materially changed during the first ninethree months of 2017.2018.

Item 4
Controls and Procedures
Our management, including our Chief Executive Officer and Chief Financial Officer, does not expect that our disclosure controls and procedures (as defined in Rules 13a - 15(e) and 15d - 15(e) of the Securities Exchange Act)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 thirdfirst quarter of 20172018 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. The EPA could issue penalties pertaining to final determinations.
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. We have requestedOn January 19, 2018, we received an assessment of proposedoffer 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 violations alleged at$1.955 million. In March 2018, we made a counter-offer to settle the government’s claims as to both the Moundsville and Oak Grove. Once we have receivedGrove facilities. We are awaiting the new demand, we will evaluate the penalty assessment and any proposed global settlement and will respond to the agencies.agencies’ response.
On May 5, 2017, we entered into a Consent Order with the Georgia Department of Natural Resources, Environmental Protection Division (GEPD)(GADNR) pertaining to alleged violations of the Georgia Water Quality Control Act and associated rules arising from a permit issued by GEPDGADNR for construction of the Dalton Project. Pursuant to the Consent Order, we paid a fine of $168,750 and agreed to perform a Corrective Action OrderPlan, 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 remedytimely 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 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 are evaluating the alleged violations.violations and will respond to the agency.
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 are evaluating the alleged violations and will respond to the agency.
Other environmental matters called for by this Item are described under the caption “Environmental Matters” in Note 12 – Contingent Liabilities of Notes to Consolidated Financial Statements included under Part I, Item 1. Financial Statements of this report, which information is incorporated by reference into this Item.
Other Litigation
The additional information called for by this itemItem is provided in Note 12 – 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.


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, includes certain risk factors that could materially affect our business, financial condition, or future results. Those Risk Factors have not materially changed, except as set forth below:

On March 15, 2018, the FERC 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.

In May 2005, the FERC issued a statement of general policy permitting a pipeline to include in its cost-of-service computations an income tax allowance provided that an entity or individual has an actual or potential income tax liability on income from the pipeline’s public utility assets. Pursuant to that policy, the extent to which owners of pipelines have such actual or potential income tax liability will be reviewed by the FERC on a case-by-case basis in rate cases where the amounts of the allowances will be established. On March 15, 2018, the FERC found that an impermissible double recovery results from granting a MLP pipeline 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 and further stated it will address the application of this policy to non-MLP partnership forms as those issues arise in subsequent proceedings. The FERC also issued a Notice of Proposed Rulemaking proposing a process that will allow it to consider costs and revenues in the context of the recent reduction in the corporate income tax rate as a result of Tax Reform and the FERC’s revised policy statement regarding MLPs. Furthermore, the FERC issued a Notice of Inquiry seeking comments on the additional impacts of Tax Reform on jurisdictional rates, and whether other features of Tax Reform require FERC action.  Due to the foregoing, it is reasonably possible that future tariff-based rates collected by our interstate natural gas pipelines may be negatively impacted by such actions, which may have a material adverse effect on our business, financial condition, results of operations, and cash flows.





Item 6. Exhibits


Exhibit
No.
   Description
     
2.1+ — 
Agreement and Plan of Merger dated as of May 12, 2015, by and among The Williams Companies, Inc., SCMS LLC, Williams Partners L.P., and WPZ GP LLC (filed on May 13, 2015 as Exhibit 2.1 to The Williams Companies, Inc.’s current report on Form 8-K (File No. 001-04174) and incorporated herein by reference).
2.2 — 
Amendment No 1. to Agreement and Plan of Merger dated as of May 1, 2016, by and among The Williams Companies, Inc., Energy Transfer Corp LP, Energy Transfer Corp GP, LLC, Energy Transfer Equity, L.P., LE GP, LLC and Energy Transfer Equity GP, LLC (filed on May 3, 2016 as Exhibit 2.1 to The Williams Companies, Inc.’s current report on Form 8-K (File No. 001-04174) and incorporated herein by reference).
2.3+ — 
Agreement and Plan of Merger dated as of September 28, 2015, by and among The Williams Companies, Inc., Energy Transfer Corp LP, Energy Transfer Corp GP, LLC, Energy Transfer Equity, L.P., LE GP, LLC and Energy Transfer Equity GP, LLC (filed on October 1, 2015 as Exhibit 2.1 to The Williams Companies, Inc.’s current report on Form 8-K (File No. 001-04174) and incorporated herein by reference).
2.4+ — 
Membership Interest Purchase Agreement, dated as of April 13, 2017, among Williams Field Services Group, LLC, Williams Partners L.P., Williams Olefins, L.L.C., NOVA Chemicals Inc., and NOVA Chemicals Corporation (filed on August 3, 2017 as Exhibit 2.2 to Williams Partners L.P.’s quarterly report on Form 10-Q (File No. 001-34831) and incorporated herein by reference).
3.1 — 
Amended and Restated Certificate of Incorporation as supplemented (filed on May 26, 2010, as Exhibit 3.1 to The Williams Companies, Inc.’s current report on Form 8-K (File No. 001-04174) and incorporated herein by reference).
3.2 — 
By-Laws (filed on January 20, 2017, as Exhibit 3.1 to The Williams Companies, Inc.’s current report on Form 8-K (File No. 001-04174) and incorporated herein by reference).
4.1—
Indenture, dated as of March 15, 2018, between Transcontinental Gas Pipe Line Company, LLC and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on March 15, 2018 as Exhibit 4.1 to The Williams Companies, Inc.’s current report on Form 8-K (File No. 001-04174) and incorporated by reference).
10.1 — 
Termination Agreement and Release, dated as of September 28, 2015, by and among The Williams Companies, Inc., SCMS LLC, Williams Partners L.P. and WPZ GP LLC (filed on September 28, 2015 as Exhibit 10.1 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-34831) and incorporated herein by reference).
10.2—
Registration Rights Agreement, dated March 15, 2018, among Transcontinental Gas Pipe Line Company LLC and the initial purchasers listed therein (filed on March 15, 2018 as Exhibit 10.1 to the Williams Companies, Inc.’s current report on Form 8-K (File No. 001-04174) and incorporated herein by reference).
10.3*§—
Form of 2018 Time-Based Restricted Stock Unit Agreement among Williams and Certain employees and officers.
10.4*§—
Form of 2018 Performance-Based Restricted Stock Unit Agreement among Williams and certain employees and officers.
10.5*§—
Form of 2018 Nonqualified Stock Option Agreement among Williams and certain employees and officers.
12* — 
Computation of Ratio of Earnings to Fixed Charges.
31.1* — 
Certification of Chief Executive Officer pursuant to Rules 13a-14(a) and 15d-14(a) promulgated under the Securities Exchange Act of 1934, as amended, and Item 601(b)(31) of Regulation S-K, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.


Exhibit
No.
Description
31.2* — 
Certification of Chief Financial Officer pursuant to Rules 13a-14(a) and 15d-14(a) promulgated under the Securities Exchange Act of 1934, as amended, and Item 601(b)(31) of Regulation S-K, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32** — 
Certification of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS* — XBRL Instance Document.
101.SCH* — XBRL Taxonomy Extension Schema.
101.CAL* — XBRL Taxonomy Extension Calculation Linkbase.
101.DEF* — XBRL Taxonomy Extension Definition Linkbase.


Exhibit
No.
Description
101.LAB* — XBRL Taxonomy Extension Label Linkbase.
101.PRE* — XBRL Taxonomy Extension Presentation Linkbase.
 
*    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 2, 2017May 3, 2018