UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended March 31, 2019

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.)

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

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

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. YesþNo¨

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yesþ 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 ¨

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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act.) Yes¨Noþ

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

Class	Shares Outstanding at April 29, 2019
Common Stock, $1.00 par value	1,211,770,224

The Williams Companies, Inc.

Index

	Page
Part I. Financial Information
Item 1. Financial Statements
Consolidated Statement of Income – Three Months Ended March 31, 2019 and 2018	6
Consolidated Statement of Comprehensive Income – Three Months Ended March 31, 2019 and 2018	7
Consolidated Balance Sheet – March 31, 2019 and December 31, 2018	8
Consolidated Statement of Changes in Equity – Three Months Ended March 31, 2019 and 2018	9
Consolidated Statement of Cash Flows – Three Months Ended March 31, 2019 and 2018	10
Notes to Consolidated Financial Statements	11
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	35
Item 3. Quantitative and Qualitative Disclosures About Market Risk	50
Item 4. Controls and Procedures	50
Part II. Other Information	50
Item 1. Legal Proceedings	50
Item 1A. Risk Factors	52
Item 6. Exhibits	53

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

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

• Levels of dividends to Williams stockholders;

• Future credit ratings of Williams and its affiliates;

• Amounts and nature of future capital expenditures;

• Expansion and growth of our business and operations;

1

• Expected in-service dates for capital projects;

• Financial condition and liquidity;

• Business strategy;

• Cash flow from operations or results of operations;

• Seasonality of certain business components;

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

• Demand for our services.

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

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

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

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

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

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

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

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

• Development and rate of adoption of alternative energy sources;

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

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

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

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

2

• Changes in the current geopolitical situation;

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

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

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

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

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

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

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

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

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

3

DEFINITIONS

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

Measurements:

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

Bcf: One billion cubic feet of natural gas

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

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

Fahrenheit

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

Mbbls/d: One thousand barrels per day

Mdth/d: One thousand dekatherms per day

MMcf/d: One million cubic feet per day

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

MMdth/d: One million dekatherms per day

Tbtu: One trillion British thermal units

Consolidated Entities:

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

Constitution: Constitution Pipeline Company, LLC

Gulfstar One: Gulfstar One LLC

Northwest Pipeline: Northwest Pipeline LLC

Transco: Transcontinental Gas Pipe Line Company, LLC

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

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

Partially Owned Entities: Entities in which we do not own a 100 percent ownership interest and which, as of March 31, 2019, we account for as an equity-method investment, including principally the following:

Aux Sable: Aux Sable Liquid Products LP

Brazos Permian II: Brazos Permian II, LLC

Caiman II: Caiman Energy II, LLC

Discovery: Discovery Producer Services LLC

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

Jackalope: Jackalope Gas Gathering Services, L.L.C.

Laurel Mountain: Laurel Mountain Midstream, LLC

OPPL: Overland Pass Pipeline Company LLC

RMM: Rocky Mountain Midstream Holdings LLC

4

Government and Regulatory:

EPA: Environmental Protection Agency

FERC: Federal Energy Regulatory Commission

SEC: Securities and Exchange Commission

Other:

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

GAAP: U.S. generally accepted accounting principles

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

MVC: Minimum volume commitment

NGLs: Natural gas liquids; natural gas liquids result from natural gas processing and crude oil refining and are

used as petrochemical feedstocks, heating fuels, and gasoline additives, among other applications

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

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

5

PART I – FINANCIAL INFORMATION

The Williams Companies, Inc.

Consolidated Statement of Income

(Unaudited)

	Three Months Ended   March 31,
	2019			2018
	(Millions, except per-share amounts)
Revenues:
Service revenues	$	1,440		$	1,351
Service revenues – commodity consideration	64			101
Product sales	550			636
Total revenues	2,054			2,088
Costs and expenses:
Product costs	525			613
Processing commodity expenses	40			35
Operating and maintenance expenses	340			357
Depreciation and amortization expenses	416			431
Selling, general, and administrative expenses	128			132
Other (income) expense – net	44			29
Total costs and expenses	1,493			1,597
Operating income (loss)	561			491
Equity earnings (losses)	80			82
Impairment of equity-method investments (Note 2)	(74		)	—
Other investing income (loss) – net	1			4
Interest incurred	(306		)	(282		)
Interest capitalized	10			9
Other income (expense) – net	11			21
Income (loss) before income taxes	283			325
Provision (benefit) for income taxes	69			55
Net income (loss)	214			270
Less: Net income (loss) attributable to noncontrolling interests	19			118
Net income (loss) attributable to The Williams Companies, Inc.	195			152
Preferred stock dividends	1			—
Net income (loss) available to common stockholders	$	194		$	152
Basic earnings (loss) per common share:
Net income (loss)	$	.16		$	.18
Weighted-average shares (thousands)	1,211,489			827,509
Diluted earnings (loss) per common share:
Net income (loss)	$	.16		$	.18
Weighted-average shares (thousands)	1,213,592			830,197

See accompanying notes.

6

The Williams Companies, Inc.

Consolidated Statement of Comprehensive Income

(Unaudited)

	Three Months Ended   March 31,
	2019		2018
	(Millions)
Net income (loss)	$	214	$	270
Other comprehensive income (loss):
Cash flow hedging activities:
Net unrealized gain (loss) from derivative instruments	—		1
Pension and other postretirement benefits:
Amortization of actuarial (gain) loss included in net periodic benefit cost (credit), net of taxes of ($1) in 2019 and 2018	3		5
Other comprehensive income (loss)	3		6
Comprehensive income (loss)	217		276
Less: Comprehensive income (loss) attributable to noncontrolling interests	19		119
Comprehensive income (loss) attributable to The Williams Companies, Inc.	$	198	$	157

See accompanying notes.

7

The Williams Companies, Inc.

Consolidated Balance Sheet

(Unaudited)

	March 31, 2019			December 31, 2018
	(Millions, except per-share amounts)
ASSETS
Current assets:
Cash and cash equivalents	$	43		$	168
Trade accounts and other receivables (net of allowance of $9 at March 31, 2019 and $9 at December 31, 2018)	929			992
Inventories	129			130
Other current assets and deferred charges	186			174
Total current assets	1,287			1,464
Investments	6,544			7,821
Property, plant, and equipment	40,541			38,661
Accumulated depreciation and amortization	(11,460		)	(11,157		)
Property, plant, and equipment – net	29,081			27,504
Intangible assets – net of accumulated amortization	8,096			7,767
Regulatory assets, deferred charges, and other	962			746
Total assets	$	45,970		$	45,302
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	620		$	662
Accrued liabilities	974			1,102
Commercial paper	1,014			—
Long-term debt due within one year	1,561			47
Total current liabilities	4,169			1,811
Long-term debt	20,703			22,367
Deferred income tax liabilities	1,601			1,524
Regulatory liabilities, deferred income, and other	3,772			3,603
Contingent liabilities (Note 13)
Equity:
Stockholders’ equity:
Preferred stock	35			35
Common stock ($1 par value; 1,470 million shares authorized at March 31, 2019 and December 31, 2018; 1,246 million shares issued at March 31, 2019 and 1,245 million shares issued at December 31, 2018)	1,246			1,245
Capital in excess of par value	24,703			24,693
Retained deficit	(10,270		)	(10,002		)
Accumulated other comprehensive income (loss)	(267		)	(270		)
Treasury stock, at cost (35 million shares of common stock)	(1,041		)	(1,041		)
Total stockholders’ equity	14,406			14,660
Noncontrolling interests in consolidated subsidiaries	1,319			1,337
Total equity	15,725			15,997
Total liabilities and equity	$	45,970		$	45,302

See accompanying notes.

8

The Williams Companies, Inc.

Consolidated Statement of Changes in Equity

(Unaudited)

	The Williams Companies, Inc. Stockholders
	Preferred Stock		Common Stock		Capital in Excess of Par Value		Retained Deficit			AOCI*			Treasury Stock			Total Stockholders’ Equity			Noncontrolling Interests			Total Equity
	(Millions)
Balance – December 31, 2018	$	35	$	1,245	$	24,693	$	(10,002	)	$	(270	)	$	(1,041	)	$	14,660		$	1,337		$	15,997
Net income (loss)	—		—		—		195			—			—			195			19			214
Other comprehensive income (loss)	—		—		—		—			3			—			3			—			3
Cash dividends – common stock ($0.38 per share)	—		—		—		(460		)	—			—			(460		)	—			(460		)
Dividends and distributions to noncontrolling interests	—		—		—		—			—			—			—			(41		)	(41		)
Stock-based compensation and related common stock issuances, net of tax	—		1		10		—			—			—			11			—			11
Contributions from noncontrolling interests	—		—		—		—			—			—			—			4			4
Other	—		—		—		(3		)	—			—			(3		)	—			(3		)
Net increase (decrease) in equity	—		1		10		(268		)	3			—			(254		)	(18		)	(272		)
Balance – March 31, 2019	$	35	$	1,246	$	24,703	$	(10,270	)	$	(267	)	$	(1,041	)	$	14,406		$	1,319		$	15,725

Balance – December 31, 2017	$	—	$	861	$	18,508	$	(8,434	)	$	(238	)	$	(1,041	)	$	9,656		$	6,519		$	16,175
Adoption of new accounting standards	—		—		—		(23		)	(61		)	—			(84		)	(37		)	(121		)
Net income (loss)	—		—		—		152			—			—			152			118			270
Other comprehensive income (loss)	—		—		—		—			5			—			5			1			6
Cash dividends – common stock ($0.34 per share)	—		—		—		(281		)	—			—			(281		)	—			(281		)
Dividends and distributions to noncontrolling interests	—		—		—		—			—			—			—			(187		)	(187		)
Stock-based compensation and related common stock issuances, net of tax	—		1		18		—			—			—			19			—			19
Sales of limited partner units of Williams Partners L.P.	—		—		—		—			—			—			—			22			22
Changes in ownership of consolidated subsidiaries, net	—		—		7		—			—			—			7			(9		)	(2		)
Contributions from noncontrolling interests	—		—		—		—			—			—			—			3			3
Other	—		—		—		(1		)	—			—			(1		)	—			(1		)
Net increase (decrease) in equity	—		1		25		(153		)	(56		)	—			(183		)	(89		)	(272		)
Balance – March 31, 2018	$	—	$	862	$	18,533	$	(8,587	)	$	(294	)	$	(1,041	)	$	9,473		$	6,430		$	15,903

* Accumulated Other Comprehensive Income (Loss)

See accompanying notes.

9

The Williams Companies, Inc.

Consolidated Statement of Cash Flows

(Unaudited)

	Three Months Ended   March 31,
	2019			2018
	(Millions)
OPERATING ACTIVITIES:
Net income (loss)	$	214		$	270
Adjustments to reconcile to net cash provided (used) by operating activities:
Depreciation and amortization	416			431
Provision (benefit) for deferred income taxes	75			73
Equity (earnings) losses	(80		)	(82		)
Distributions from unconsolidated affiliates	172			140
Impairment of equity-method investments (Note 2)	74			—
Amortization of stock-based awards	14			14
Cash provided (used) by changes in current assets and liabilities:
Accounts and notes receivable	97			238
Inventories	1			(40		)
Other current assets and deferred charges	(6		)	(4		)
Accounts payable	(39		)	(197		)
Accrued liabilities	(142		)	(166		)
Other, including changes in noncurrent assets and liabilities	(21		)	17
Net cash provided (used) by operating activities	775			694
FINANCING ACTIVITIES:
Proceeds from (payments of) commercial paper – net	1,014			—
Proceeds from long-term debt	708			2,048
Payments of long-term debt	(864		)	(1,060		)
Proceeds from issuance of common stock	6			10
Common dividends paid	(460		)	(281		)
Dividends and distributions paid to noncontrolling interests	(41		)	(165		)
Contributions from noncontrolling interests	4			3
Payments for debt issuance costs	—			(18		)
Other – net	(9		)	(40		)
Net cash provided (used) by financing activities	358			497
INVESTING ACTIVITIES:
Property, plant, and equipment:
Capital expenditures (1)	(422		)	(957		)
Dispositions – net	(4		)	(1		)
Contributions in aid of construction	10			190
Purchases of businesses, net of cash acquired	(727		)	—
Purchases of and contributions to equity-method investments	(99		)	(21		)
Other – net	(16		)	(9		)
Net cash provided (used) by investing activities	(1,258		)	(798		)
Increase (decrease) in cash and cash equivalents	(125		)	393
Cash and cash equivalents at beginning of year	168			899
Cash and cash equivalents at end of period	$	43		$	1,292
_____________
(1) Increases to property, plant, and equipment	$	(418	)	$	(934	)
Changes in related accounts payable and accrued liabilities	(4		)	(23		)
Capital expenditures	$	(422	)	$	(957	)

See accompanying notes.

10

The Williams Companies, Inc.

Notes to Consolidated Financial Statements

(Unaudited)

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

General

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

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

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

WPZ Merger

On August 10, 2018, we completed our merger with Williams Partners L.P. (WPZ), our previously consolidated master limited partnership, pursuant to which we acquired all of the approximately 256 million publicly held outstanding common units of WPZ in exchange for 382 million shares of our common stock (WPZ Merger). Williams continued as the surviving entity. The WPZ Merger was accounted for as a noncash equity transaction resulting in increases to Common stock of $382 million, Capital in excess of par value of $6.112 billion, and Regulatory assets, deferred charges, and other of $33 million and decreases to Accumulated other comprehensive income (loss) (AOCI) of $3 million, Noncontrolling interests in consolidated subsidiaries of $4.629 billion, and Deferred income tax liabilities of $1.829 billion in the Consolidated Balance Sheet. Pursuant to its distribution reinvestment program, WPZ had issued 576,923 common units to the public in February 2018 associated with reinvested distributions of $22 million.

Description of Business

We are a Delaware corporation whose common stock is listed and traded on the New York Stock Exchange. Our operations are located in the United States. Prior to the WPZ Merger, we had one reportable segment, Williams Partners. Beginning in the third-quarter 2018, consistent with the manner in which our chief operating decision maker evaluates performance and allocates resources, our operations are now presented within the following reportable segments: Northeast G&P, Atlantic-Gulf, and West. Prior period segment disclosures have been recast for the new segment presentation. All remaining business activities as well as corporate activities are included in Other.

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

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Notes (Continued)

Atlantic-Gulf is comprised of our interstate natural gas pipeline, Transcontinental Gas Pipe Line Company, LLC (Transco), and significant natural gas gathering and processing and crude oil production handling and transportation assets in the Gulf Coast region, including a 51 percent interest in Gulfstar One LLC (Gulfstar One) (a consolidated entity), which is a proprietary floating production system, as well as a 50 percent equity-method investment in Gulfstream Natural Gas System, L.L.C., a 60 percent equity-method investment in Discovery Producer Services LLC, and a 41 percent interest in Constitution Pipeline Company, LLC (Constitution) (a consolidated entity), which is developing a pipeline project (see Note 4 – Variable Interest Entities).

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

Basis of Presentation

Significant risks and uncertainties

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

Accounting standards issued and adopted

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

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

12

Notes (Continued)

practical expedient that permits lessors to not separate non-lease components from the associated lease component if certain conditions are present. ASU 2016-02 is effective for interim and annual periods beginning after December 15, 2018. We prospectively adopted ASU 2016-02 effective January 1, 2019, and did not adjust prior periods as permitted by ASU 2018-11 (see Note 9 – Leases).

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

Accounting standards issued but not yet adopted

In June 2016, the FASB issued ASU 2016-13 “Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments” (ASU 2016-13). ASU 2016-13 changes the impairment model for most financial assets and certain other instruments. For trade and other receivables, held-to-maturity debt securities, loans, and other instruments, entities will be required to use a new forward-looking “expected loss” model that generally will result in the earlier recognition of allowances for losses. The guidance also requires increased disclosures. ASU 2016-13 is effective for interim and annual periods beginning after December 15, 2019. We plan to adopt as of January 1, 2020. We anticipate that ASU 2016–13 will primarily apply to our trade receivables. While we do not expect a significant financial impact, we are currently developing additional processes, procedures and internal controls in order to make the necessary credit loss assessments and required disclosures.

Note 2 – Acquisitions

UEOM

As of December 31, 2018, we owned a 62 percent interest in UEOM which we accounted for as an equity-method investment. On March 18, 2019, we signed and closed the acquisition of the remaining 38 percent interest in UEOM for $740 million in cash funded through credit facility borrowings and cash on hand. As a result of acquiring this additional interest, we obtained control of and now consolidate UEOM.

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

The acquisition of UEOM was accounted for as a business combination, which requires, among other things, that identifiable assets acquired and liabilities assumed be recognized at their acquisition date fair values. In March 2019, based on the transaction price for our purchase of the remaining interest in UEOM as finalized just prior to the acquisition, we recognized a $74 million non-cash impairment loss related to our existing 62 percent interest (see Note 12 – Fair Value Measurements and Guarantees). Thus, there was no gain or loss on remeasuring our existing equity-method investment to fair value due to the impairment recognized just prior to closing the acquisition of the additional interest.

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

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

13

Notes (Continued)

existing equity-method investment upon our acquisition of the additional interest. The fair value of accounts receivable acquired, presented in current assets in the table, equals contractual amounts receivable. The allocation is considered preliminary because the valuation work has not been completed due to the ongoing review of the valuation results and validation of significant inputs and assumptions.

	(Millions)
Current assets, including $13 million cash acquired	$	52
Property, plant, and equipment	1,493
Other intangible assets	389
Total identifiable assets acquired	1,934
Current liabilities	4
Total liabilities assumed	4
Net identifiable assets acquired	1,930
Goodwill	19
Net assets acquired	$	1,949

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

Other intangible assets recognized in the acquisition are related to contractual customer relationships from gas gathering, processing, and fractionation agreements with our customers. The basis for determining the value of these intangible assets is estimated future net cash flows to be derived from acquired contractual customer relationships discounted using a risk-adjusted discount rate. These intangible assets are being amortized on a straight-line basis over an initial period of 20 years which represents the term over which the contractual customer relationships are expected to contribute to our cash flows. Approximately 34 percent of the expected future revenues from these contractual customer relationships are impacted by our ability and intent to renew or renegotiate existing customer contracts. We expense costs incurred to renew or extend the terms of our gas gathering, processing, and fractionation contracts with customers. Based on the estimated future revenues during the current contract periods (as estimated at the time of the acquisition), the weighted-average period prior to the next renewal or extension of the existing contractual customer relationships is approximately 10 years.

The following unaudited pro forma Revenues and Net income (loss) attributable to The Williams Companies, Inc. for the three months ended March 31, 2019 and 2018, are presented as if the UEOM acquisition had been completed on January 1, 2018. These pro forma amounts are not necessarily indicative of what the actual results would have been if the acquisition had in fact occurred on the date or for the periods indicated, nor do they purport to project Revenues or Net income (loss) attributable to The Williams Companies, Inc. for any future periods or as of any date. These amounts do not give effect to any potential cost savings, operating synergies, or revenue enhancements to result from the transaction or the potential costs to achieve these cost savings, operating synergies, and revenue enhancements.

14

Notes (Continued)

	Three Months Ended   March 31,
	2019		2018
	(Millions)
Revenues	$	2,086	$	2,121
Net income (loss) attributable to The Williams Companies, Inc.	$	273	$	155

Adjustments to pro forma Net income (loss) attributable to The Williams Companies, Inc. include the removal of the previously described $74 million impairment loss recognized in March 2019 just prior to the acquisition.

During the period from the acquisition date of March 18, 2019 to March 31, 2019, UEOM contributed Revenues of $6 million and Net income (loss) attributable to The Williams Companies, Inc. of $2 million.

Costs related to this acquisition are $3 million and are reported within our Northeast G&P segment and included in Selling, general, and administrative expenses in our Consolidated Statement of Income.

UEOM and OVM Venture

Concurrent with the UEOM acquisition, we executed an agreement whereby we will contribute our consolidated interests in UEOM and our OVM business to a newly formed partnership later this year. Our partner will invest approximately $1.304 billion (subject to closing adjustments) for a 35 percent ownership interest, and we will retain 65 percent ownership of and operate the combined business. The closing of this transaction is subject to customary closing conditions, including regulatory approvals.

15

Notes (Continued)

Note 3 – Revenue Recognition

Revenue by Category

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

	Northeast Midstream		Atlantic- Gulf Midstream		West Midstream		Transco		Northwest Pipeline		Other		Intercompany Eliminations			Total
	(Millions)
Three Months Ended March 31, 2019
Revenues from contracts with customers:
Service revenues:
Non-regulated gathering, processing, transportation, and storage:
Monetary consideration	$	239	$	128	$	344	$	—	$	—	$	—	$	(18	)	$	693
Commodity consideration	5		13		46		—		—		—		—			64
Regulated interstate natural gas transportation and storage	—		—		—		570		114		—		—			684
Other	32		4		11		—		—		—		(4		)	43
Total service revenues	276		145		401		570		114		—		(22		)	1,484
Product Sales:
NGL and natural gas product sales	47		58		479		24		—		—		(58		)	550
Total revenues from contracts with customers	323		203		880		594		114		—		(80		)	2,034
Other revenues (1)	5		4		4		3		—		7		(3		)	20
Total revenues	$	328	$	207	$	884	$	597	$	114	$	7	$	(83	)	$	2,054
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 consideration	4		15		82		—		—		—		—			101
Regulated interstate natural gas transportation and storage	—		—		—		461		112		—		(1		)	572
Other	21		6		11		—		—		—		(3		)	35
Total service revenues	227		158		501		461		112		—		(22		)	1,437
Product Sales:
NGL and natural gas	98		68		521		25		—		—		(85		)	627
Other	—		—		4		—		—		—		—			4
Total product sales	98		68		525		25		—		—		(85		)	631
Total revenues from contracts with customers	325		226		1,026		486		112		—		(107		)	2,068
Other revenues (1)	5		2		5		3		—		8		(3		)	20
Total revenues	$	330	$	228	$	1,031	$	489	$	112	$	8	$	(110	)	$	2,088

______________________________

(1) Service revenues in our Consolidated Statement of Income include leasing revenues associated with our headquarters building and management fees that we receive for certain services we provide to operated equity-method investments. The leasing revenues and the management fees do not constitute revenue from contracts with

16

Notes (Continued)

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, “Revenue from Contracts with Customers.”

Contract Assets

The following table presents a reconciliation of our contract assets:

	Year-to-Date  March 31, 2019
	(Millions)
Balance at beginning of period	$	4
Revenue recognized in excess of amounts invoiced	19
Minimum volume commitments invoiced	(1		)
Balance at end of period	$	22

Contract Liabilities

The following table presents a reconciliation of our contract liabilities:

	Year-to-Date   March 31, 2019
	(Millions)
Balance at beginning of period	$	1,397
Payments received and deferred	33
Noncash interest expense for significant financing component	4
Recognized in revenue	(99		)
Balance at end of period	$	1,335

The following table presents the amount of the contract liabilities balance as of March 31, 2019, expected to be recognized as revenue in each of the next five years as performance obligations are expected to be satisfied:

	(Millions)
2019 (remainder)	$	200
2020	148
2021	124
2022	111
2023	101
Thereafter	651
Total	$	1,335

Remaining Performance Obligations

The following table presents the transaction price allocated to the remaining performance obligations under certain contracts as of March 31, 2019. These primarily include long-term contracts containing Minimum Volume Commitments (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 Federal Energy Regulatory Commission (FERC) tariffs, net of estimated reserve for refund, 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. This 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, 2019, that will be recognized in future periods (see above for Contract Liabilities and the expected recognition of those amounts within revenue). Certain of our contracts contain evergreen and other renewal provisions for periods beyond the initial term of the contract. The remaining performance

17

Notes (Continued)

obligation amounts as of March 31, 2019, do 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)
2019 (remainder)	$	2,214
2020	2,831
2021	2,704
2022	2,408
2023	2,149
Thereafter	18,161
Total	$	30,467

Accounts Receivable

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

	March 31, 2019		December 31, 2018
	(Millions)
Accounts receivable related to revenues from contracts with customers	$	794	$	858
Other accounts receivable	135		134
Total reflected in Trade accounts and other receivables	$	929	$	992

Note 4 – Variable Interest Entities

Consolidated VIEs

As of March 31, 2019, we consolidate the following variable interest entities (VIEs):

Gulfstar One

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

Constitution

We own a 41 percent interest in Constitution, a subsidiary that, due to shipper fixed-payment commitments under its long-term firm transportation contracts, is a VIE. We are the primary beneficiary because we have the power to direct the activities that most significantly impact Constitution’s economic performance. We, as operator of Constitution, are responsible for constructing the proposed pipeline connecting its gathering system 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 $740 million, which would be funded with capital contributions from us and the other equity partners on a proportional basis.

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

18

Notes (Continued)

issue lies exclusively with the United States Court of Appeals for the District of Columbia Circuit (D.C. Circuit). As to the denial itself, the court determined that NYSDEC’s action was not arbitrary or capricious. Constitution filed a petition for rehearing with the Second Circuit Court of Appeals, but in October 2017 the court denied our petition.

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

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

The project’s sponsors remain committed to the project. On April 1, 2019, we filed a supplemental pleading with the FERC explaining why we believe the Hoopa Valley Tribe decision requires the FERC to find that NYSDEC waived its authority to issue a Section 401 water quality certification for the Constitution project. An unfavorable resolution of Constitution’s claim for waiver could result in the impairment of a significant portion of the capitalized project costs, which total $376 million on a consolidated basis at March 31, 2019, and are included within Property, plant, and equipment in the Consolidated Balance Sheet. Beginning in April 2016, we discontinued capitalization of development costs related to this project. It is also possible that we could incur certain supplier-related costs in the event of a continued prolonged delay or termination of the project.

Cardinal

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

19

Notes (Continued)

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

	March 31, 2019			December 31, 2018			Classification
	(Millions)
Assets (liabilities):
Cash and cash equivalents	$	26		$	33		Cash and cash equivalents
Trade accounts and other receivables – net	50			62			Trade accounts and other receivables
Other current assets	1			2			Other current assets and deferred charges
Property, plant, and equipment – net	2,333			2,363			Property, plant, and equipment – net
Intangible assets – net	1,166			1,177			Intangible assets – net of accumulated amortization
Regulatory assets, deferred charges, and other noncurrent assets	1			—			Regulatory assets, deferred charges, and other
Accounts payable	(15		)	(15		)	Accounts payable
Accrued liabilities including current asset retirement obligations	(115		)	(115		)	Accrued liabilities
Noncurrent asset retirement obligations	(107		)	(105		)	Regulatory liabilities, deferred income, and other
Regulatory liabilities, deferred income, and other noncurrent liabilities	(137		)	(159		)	Regulatory liabilities, deferred income, and other

Nonconsolidated VIEs

Jackalope

We own a50 percent interest in Jackalope, which provides gathering and processing services for the Powder River basin and is a VIE due to certain risks shared with customers. At March 31, 2019, the carrying value of our investment in Jackalope was $358 million. In April 2019, we sold our interest in Jackalope (see Note 15 – Subsequent Event).

Brazos Permian II

We own a 15 percent interest in Brazos Permian II, which provides gathering and processing services in the Delaware basin and is a VIE due primarily to our limited participating rights as the minority equity holder.  At March 31, 2019, the carrying value of our investment in Brazos Permian II was $190 million. Our maximum exposure to loss is limited to the carrying value of our investment.

20

Notes (Continued)

Note 5 – Other Income and Expenses

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

	Three Months Ended   March 31,
	2019		2018
	(Millions)
Other (income) expense – net within Costs and expenses
West
Impairment of certain assets	$	12	$	—
Other
Change in regulatory asset associated with Transco’s estimated deferred state income tax rate	12		—
Other income (expense) – net below Operating income (loss)
Atlantic-Gulf
Allowance for equity funds used during construction	7		20
Other
Net loss associated with early retirement of debt	—		(7		)

Note 6 – Provision (Benefit) for Income Taxes

The Provision (benefit) for income taxes includes:

	Three Months Ended   March 31,
	2019			2018
	(Millions)
Current:
Federal	$	(6	)	$	(19	)
State	—			1
	(6		)	(18		)
Deferred:
Federal	61			64
State	14			9
	75			73
Provision (benefit) for income taxes	$	69		$	55

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

The effective income tax rate for the total provision for the three months ended 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.

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.

21

Notes (Continued)

Note 7 – Earnings (Loss) Per Common Share

	Three Months Ended   March 31,
	2019		2018
	(Dollars in millions, except per-share amounts; shares in thousands)
Net income (loss) available to common stockholders	$	194	$	152
Basic weighted-average shares	1,211,489		827,509
Effect of dilutive securities:
Nonvested restricted stock units	1,845		2,095
Stock options	258		593
Diluted weighted-average shares	1,213,592		830,197
Earnings (loss) per common share:
Basic	$	.16	$	.18
Diluted	$	.16	$	.18

Note 8 – Employee Benefit Plans

Net periodic benefit cost (credit) is as follows:

	Pension Benefits
	Three Months Ended   March 31,
	2019			2018
	(Millions)
Components of net periodic benefit cost (credit):
Service cost	$	11		$	14
Interest cost	12			11
Expected return on plan assets	(15		)	(16		)
Amortization of net actuarial loss	4			6
Net periodic benefit cost (credit)	$	12		$	15

	Other Postretirement Benefits
	Three Months Ended   March 31,
	2019			2018
	(Millions)
Components of net periodic benefit cost (credit):
Interest cost	$	2		$	2
Expected return on plan assets	(2		)	(3		)
Amortization of prior service credit	—			(1		)
Reclassification to regulatory liability	—			1
Net periodic benefit cost (credit)	$	—		$	(1	)

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

Amortization of prior service credit included in Net periodic benefit cost (credit) for our other postretirement benefit plans associated with Transco and Northwest Pipeline is recorded to regulatory assets/liabilities instead of Other

22

Notes (Continued)

comprehensive income (loss). The amount of Amortization of prior service credit recognized in regulatory liabilities was $1 million for the three months ended March 31, 2018.

During the three months ended March 31, 2019, we contributed $1 million to our other postretirement benefit plans. We presently anticipate making additional contributions of approximately $63 million to our pension plans and approximately $4 million to our other postretirement benefit plans in the remainder of 2019.

Note 9 – Leases

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

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

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

We sublease unused office space when permitted under our lease agreements for fixed periods that extend up to the length of the original lease agreement.

23

Notes (Continued)

	Three Months Ended   March 31, 2019
	(Millions)
Lease Cost:
Operating lease cost	$	10
Short-term lease cost	—
Variable lease cost	6
Sublease income	(1		)
Total lease cost	$	15
Cash paid for amounts included in the measurement of operating lease liabilities	$	9
	March 31, 2019
	(Millions)
Other Information:
Right-of-use asset (included in Regulatory assets, deferred charges, and other in our Consolidated Balance Sheet)	$	223
Operating lease liabilities:
Current (included in Accrued liabilities in our Consolidated Balance Sheet)	$	25
Noncurrent (included in Regulatory liabilities, deferred income, and other in our Consolidated Balance Sheet)	$	198
Weighted-average remaining lease term – operating leases (years)	12
Weighted-average discount rate – operating leases	4.62%

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

	(Millions)
2019 (remainder)	$	27
2020	32
2021	32
2022	27
2023	19
Thereafter	165
Total future lease payments	302
Less amount representing interest	79
Total obligations under operating leases	$	223

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

Note 10 – Debt and Banking Arrangements

Commercial Paper Program

At March 31, 2019, approximately $1.016 billion of Commercial paper, exclusive of unamortized discount, at a weighted-average interest rate of 2.9 percent was outstanding under our $4 billion commercial paper program. At April 30, 2019, $337 million of commercial paper was outstanding.

24

Notes (Continued)

Credit Facilities

	March 31, 2019
	Stated Capacity		Outstanding
	(Millions)
Long-term credit facility (1)	$	4,500	$	—
Letters of credit under certain bilateral bank agreements			14

(1) In managing our available liquidity, we do not expect a maximum outstanding amount in excess of the capacity of our credit facility inclusive of any outstanding amounts under our commercial paper program.

Note 11 – Stockholders’ Equity

AOCI

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

	Cash Flow Hedges			Foreign Currency Translation			Pension and Other Postretirement Benefits			Total
	(Millions)
Balance at December 31, 2018	$	(2	)	$	(1	)	$	(267	)	$	(270	)
Amounts reclassified from accumulatedother comprehensive income (loss)	—			—			3			3
Balance at March 31, 2019	$	(2	)	$	(1	)	$	(264	)	$	(267	)

Reclassifications out of AOCI are presented in the following table by component for the three months ended March 31, 2019:

Component	Reclassifications			Classification
	(Millions)
Pension and other postretirement benefits:
Amortization of actuarial (gain) loss included in net periodic benefit cost (credit)	$	4		Note 8 – Employee Benefit Plans
Income tax benefit	(1		)	Provision (benefit) for income taxes
Reclassifications during the period	$	3

25

Notes (Continued)

Note 12 – Fair Value Measurements and Guarantees

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

							Fair Value Measurements Using
	Carrying Amount			Fair Value			Quoted Prices In Active Markets for Identical Assets (Level 1)			Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
	(Millions)
Assets (liabilities) at March 31, 2019:
Measured on a recurring basis:
ARO Trust investments	$	173		$	173		$	173		$	—		$	—
Energy derivatives assets not designated as hedging instruments	2			2			2			—			—
Energy derivatives liabilities not designated as hedging instruments	(9		)	(9		)	(6		)	—			(3		)
Additional disclosures:
Long-term debt, including current portion	(22,264		)	(24,449		)	—			(24,449		)	—
Guarantees	(42		)	(29		)	—			(13		)	(16		)
Assets (liabilities) at December 31, 2018:
Measured on a recurring basis:
ARO Trust investments	$	150		$	150		$	150		$	—		$	—
Energy derivatives assets not designated as hedging instruments	3			3			3			—			—
Energy derivatives liabilities not designated as hedging instruments	(7		)	(7		)	(4		)	—			(3		)
Additional disclosures:
Long-term debt, including current portion	(22,414		)	(23,330		)	—			(23,330		)	—
Guarantees	(43		)	(30		)	—			(14		)	(16		)

Fair Value Methods

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

Assets and liabilities measured at fair value on a recurring basis

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

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

26

Notes (Continued)

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

Reclassifications of fair value between Level 1, Level 2, and Level 3 of the fair value hierarchy, if applicable, are made at the end of each quarter. No transfers between Level 1 and Level 2 occurred during the three months ended March 31, 2019 or 2018.

Additional fair value disclosures

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

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

To estimate the fair value of the WilTel guarantee, an estimated default rate is applied to the sum of the future contractual lease payments using an income approach. The estimated default rate is determined by obtaining the average cumulative issuer-weighted corporate default rate based on the credit rating of WilTel’s current owner and the term of the underlying obligation. The default rate is published by Moody’s Investors Service. The carrying value of the WilTel guarantee is reported in Accrued liabilities in the Consolidated Balance Sheet. The maximum potential undiscounted exposure is approximately $29 millionat March 31, 2019. Our exposure declines systematically through the remaining term of WilTel’s obligation.

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

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

27

Notes (Continued)

Nonrecurring fair value measurements

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

						Impairments
						Three Months Ended March 31,
	Classification	Segment	Date of Measurement	Fair Value		2019		2018
				(Millions)
Impairment of assets (1)	Property, plant, and equipment – net	West	March 31, 2019	$	—	$	12
Equity-method investments (2)	Investments	Northeast G&P	March 17, 2019	$	1,209	$	74

_______________

(1) Reflects impairment of assets that are no longer in use for which the fair value was determined to be lower than the carrying value. This impairment is reported in Other (income) expense – net within Costs and expenses in the Consolidated Statement of Income.

(2) Relates to Northeast G&P’s equity-method investment in UEOM. The estimated fair value was determined by a market approach based on the transaction price for the purchase of the remaining interest in UEOM as finalized just prior to the signing and closing of the acquisition in March 2019 (see Note 2 – Acquisitions). This impairment is reported in Impairment of equity-method investments in the Consolidated Statement of Income.

Note 13 – Contingent Liabilities

Reporting of Natural Gas-Related Information to Trade Publications

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

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

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

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

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

28

Notes (Continued)

Alaska Refinery Contamination Litigation

We are involved in litigation arising from our ownership and operation of the North Pole Refinery in North Pole, Alaska, from 1980 until 2004, through our wholly owned subsidiaries, Williams Alaska Petroleum Inc. (WAPI) and MAPCO Inc. We sold the refinery to Flint Hills Resources Alaska, LLC (FHRA), a subsidiary of Koch Industries, Inc., in 2004. The litigation involves three cases, with filing dates ranging from 2010 to 2014. The actions arise from sulfolane contamination allegedly emanating from the refinery. A putative class action lawsuit was filed by James West in 2010 naming us, WAPI, and FHRA as defendants. We and FHRA filed claims against each other seeking, among other things, contractual indemnification alleging that the other party caused the sulfolane contamination. In 2011, we and FHRA settled the claim with James West. Certain claims by FHRA against us were resolved by the Alaska Supreme Court in our favor. FHRA’s claims against us for contractual indemnification and statutory claims for damages related to off-site sulfolane remain pending. The State of Alaska filed its action in March 2014, seeking damages. The City of North Pole (North Pole) filed its lawsuit in November 2014, seeking past and future damages, as well as punitive damages. Both we and WAPI asserted counterclaims against the State of Alaska and North Pole, and cross-claims against FHRA. FHRA has also filed cross-claims against us.

The underlying factual basis and claims in the cases are similar and may duplicate exposure. As such, in February 2017, the three cases were consolidated into one action in state court containing the remaining claims from the James West case and those of the State of Alaska and North Pole. Several trial dates encompassing all three cases have been scheduled and stricken. Currently, a four-week trial is scheduled to commence on October 7, 2019. Due to the ongoing assessment of the level and extent of sulfolane contamination, the lack of an articulated cleanup level for sulfolane, and the lack of a concrete remedial proposal and cost estimate, we are unable to estimate a range of exposure to the State of Alaska or North Pole at this time. We currently estimate that our reasonably possible loss exposure to FHRA could range from an insignificant amount up to $32 million, although uncertainties inherent in the litigation process, expert evaluations, and jury dynamics might cause our exposure to exceed that amount.

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

Royalty Matters

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

Litigation Against Energy Transfer and Related Parties

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

29

Notes (Continued)

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

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

On September 16, 2016, we filed an amended complaint with the Court of Chancery seeking damages for breaches of the ETE Merger Agreement by defendants.  On September 23, 2016, Energy Transfer filed a second amended and supplemental affirmative defenses and verified counterclaim with the Court of Chancery seeking, among other things, payment of the $1.48 billion termination fee due to our alleged breaches of the ETE Merger Agreement. On December 1, 2017, the court granted our motion to dismiss certain of Energy Transfer’s counterclaims, including its claim seeking payment of the $1.48 billion termination fee. On December 8, 2017, Energy Transfer filed a motion for reargument, which the Court of Chancery denied on April 16, 2018. The Court of Chancery previously scheduled trial for May 20 through May 24, 2019; the court has stricken the trial setting and indicated that it will be re-scheduled for a later date.

Former Olefins Business

The other interest owner in our former Geismar, Louisiana, olefins facility, which we sold in July 2017, is seeking recovery from us for losses it allegedly suffered, including its share of personal injury settlements in which it was a co-defendant, as well as amounts related to lost income, defense costs, and property damage associated with an explosion and fire at the plant in June 2013. Due to the complexity of the various claims and available defenses, we are unable to reliably estimate any reasonably possible losses at this time. Trial is currently scheduled to begin in October 2019. We believe that certain losses incurred arising directly from the explosion and fire will be covered by our general liability policy and any uninsured losses are not expected to be material.

Other

On August 31, 2018, Transco submitted to the FERC a general rate filing principally designed to recover increased costs and to comply with the terms of the settlement in its prior rate proceeding. The new rates became effective March 1, 2019, subject to refund and the outcome of a hearing. We have provided a reserve for rate refunds which we believe is adequate for any refunds that may be required.

Environmental Matters

We are a participant in certain environmental activities in various stages including assessment studies, cleanup operations, and/or remedial processes at certain sites, some of which we currently do not own. We are monitoring these sites in a coordinated effort with other potentially responsible parties, the U.S. Environmental Protection Agency (EPA), or other governmental authorities. We are jointly and severally liable along with unrelated third parties in some of these activities and solely responsible in others. Certain of our subsidiaries have been identified as potentially responsible parties at various Superfund and state waste disposal sites. In addition, these subsidiaries have incurred, or are alleged to have incurred, various other hazardous materials removal or remediation obligations under environmental laws. As

30

Notes (Continued)

of March 31, 2019, we have accrued liabilities totaling $34 million for these matters, as discussed below. Estimates of the most likely costs of cleanup are generally based on completed assessment studies, preliminary results of studies, or our experience with other similar cleanup operations. At March 31, 2019, certain assessment studies were still in process for which the ultimate outcome may yield different estimates of most likely costs. Therefore, the actual costs incurred will depend on the final amount, type, and extent of contamination discovered at these sites, the final cleanup standards mandated by the EPA or other governmental authorities, and other factors.

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

Continuing operations

Our interstate gas pipelines are involved in remediation activities related to certain facilities and locations for polychlorinated biphenyls, mercury, and other hazardous substances. These activities have involved the EPA and various state environmental authorities, resulting in our identification as a potentially responsible party at various Superfund waste sites. At March 31, 2019, we have accrued liabilities of $5 million for these costs. We expect that these costs will be recoverable through rates.

We also accrue environmental remediation costs for natural gas underground storage facilities, primarily related to soil and groundwater contamination. At March 31, 2019, we have accrued liabilities totaling $7 million for these costs.

Former operations

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

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

• Former petroleum products and natural gas pipelines;

• Former petroleum refining facilities;

• Former exploration and production and mining operations;

• Former electricity and natural gas marketing and trading operations.

At March 31, 2019, we have accrued environmental liabilities of $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

31

Notes (Continued)

incurring liabilities that are not otherwise recoverable from third parties. The indemnities generally relate to breach of warranties, tax, historic litigation, personal injury, property damage, environmental matters, right of way, and other representations that we have provided.

At March 31, 2019, other than as previously disclosed, we are not aware of any material claims against us involving the indemnities; thus, we do not expect any of the indemnities provided pursuant to the sales agreements to have a material impact on our future financial position. Any claim for indemnity brought against us in the future may have a material adverse effect on our results of operations in the period in which the claim is made.

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

Summary

We have disclosed our estimated range of reasonably possible losses for certain matters above, as well as all significant matters for which we are unable to reasonably estimate a range of possible loss. We estimate that for all other matters for which we are able to reasonably estimate a range of loss, our aggregate reasonably possible losses beyond amounts accrued are immaterial to our expected future annual results of operations, liquidity, and financial position. These calculations have been made without consideration of any potential recovery from third parties.

Note 14 – Segment Disclosures

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

Performance Measurement

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

We define Modified EBITDA as follows:

•Net income (loss) before:

◦Provision (benefit) for income taxes;

◦Interest incurred, net of interest capitalized;

◦Equity earnings (losses);

◦Impairment of equity-method investments;

◦Other investing income (loss) – net;

◦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.

32

Notes (Continued)

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

	Northeast G&P		Atlantic-Gulf		West		Other		Eliminations			Total
	(Millions)
Three Months Ended March 31, 2019
Segment revenues:
Service revenues
External	$	266	$	697	$	473	$	4	$	—		$	1,440
Internal	10		12		—		3		(25		)	—
Total service revenues	276		709		473		7		(25		)	1,440
Total service revenues – commodity consideration	5		13		46		—		—			64
Product sales
External	36		52		462		—		—			550
Internal	11		30		17		—		(58		)	—
Total product sales	47		82		479		—		(58		)	550
Total revenues	$	328	$	804	$	998	$	7	$	(83	)	$	2,054
Three Months Ended March 31, 2018
Segment revenues:
Service revenues
External	$	219	$	596	$	531	$	5	$	—		$	1,351
Internal	9		13		—		3		(25		)	—
Total service revenues	228		609		531		8		(25		)	1,351
Total service revenues – commodity consideration	4		15		82		—		—			101
Product sales
External	89		35		512		—		—			636
Internal	9		58		18		—		(85		)	—
Total product sales	98		93		530		—		(85		)	636
Total revenues	$	330	$	717	$	1,143	$	8	$	(110	)	$	2,088
March 31, 2019
Total assets	$	15,301	$	16,441	$	13,834	$	782	$	(388	)	$	45,970
December 31, 2018
Total assets	$	14,526	$	16,346	$	13,948	$	849	$	(367	)	$	45,302

33

Notes (Continued)

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

	Three Months Ended   March 31,
	2019			2018
	(Millions)
Modified EBITDA by segment:
Northeast G&P	$	299		$	250
Atlantic-Gulf	560			451
West	332			413
Other	(4		)	6
	1,187			1,120
Accretion expense associated with asset retirement obligations for nonregulated operations	(9		)	(8		)
Depreciation and amortization expenses	(416		)	(431		)
Equity earnings (losses)	80			82
Impairment of equity-method investments	(74		)	—
Other investing income (loss) – net	1			4
Proportional Modified EBITDA of equity-method investments	(190		)	(169		)
Interest expense	(296		)	(273		)
(Provision) benefit for income taxes	(69		)	(55		)
Net income (loss)	$	214		$	270

Note 15 – Subsequent Event

In April 2019, we sold our 50 percent interest in Jackalope for $485 million in cash. As of March 31, 2019, the carrying value of this investment within the West segment was $358 million, included within Investments in the Consolidated Balance Sheet.

34

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 natural gas liquids (NGLs) through our gas pipeline and midstream business. Our operations are located in the United States.

Our interstate natural gas pipeline strategy is to create value by maximizing the utilization of our pipeline capacity by providing high quality, low cost transportation of natural gas to large and growing markets. Our gas pipeline businesses’ interstate transmission and storage activities are subject to regulation by the FERC and as such, our rates and charges for the transportation of natural gas in interstate commerce, and the extension, expansion or abandonment of jurisdictional facilities and accounting, among other things, are subject to regulation. The rates are established through the FERC’s ratemaking process. Changes in commodity prices and volumes transported have limited near-term impact on these revenues because the majority of cost of service is recovered through firm capacity reservation charges in transportation rates.

The ongoing strategy of our midstream operations is to safely and reliably operate large-scale midstream infrastructure where our assets can be fully utilized and drive low per-unit costs. We focus on consistently attracting new business by providing highly reliable service to our customers. These services include natural gas gathering, processing, treating, and compression, NGL fractionation and transportation, crude oil production handling and transportation, marketing services for NGL, crude oil and natural gas, as well as storage facilities.

Prior to our merger with Williams Partners L.P., our previously consolidated master limited partnership, in August 2018, we had one reportable segment, Williams Partners. Beginning in the third-quarter 2018, consistent with the manner in which our chief operating decision maker evaluates performance and allocates resources, our operations are now presented within the following reportable segments: Northeast G&P, Atlantic-Gulf, and West. Prior period segment disclosures have been recast for the new segment presentation. All remaining business activities as well as corporate activities are included in Other. Our reportable segments are comprised of the following businesses:

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

• Atlantic-Gulf is comprised of our interstate natural gas pipeline, Transcontinental Gas Pipe Line Company, LLC (Transco), and significant natural gas gathering and processing and crude oil production handling and transportation assets in the Gulf Coast region, including a 51 percent interest in Gulfstar One LLC (Gulfstar One) (a consolidated entity), which is a proprietary floating production system, as well as a 50 percent equity-method investment in Gulfstream Natural Gas System, L.L.C., a 60 percent equity-method investment in Discovery Producer Services LLC (Discovery), and a 41 percent interest in Constitution Pipeline Company, LLC (Constitution) (a consolidated entity), which is developing a pipeline project (see Note 4 – Variable Interest Entities of Notes to Consolidated Financial Statements).

• West is comprised of our interstate natural gas pipeline, Northwest Pipeline LLC (Northwest Pipeline), and our gathering, processing, and treating operations in Colorado, Wyoming, the Barnett Shale region of north-central Texas, the Eagle Ford Shale region of south Texas, the Permian Shale region of west Texas, the

35

Management’s Discussion and Analysis (Continued)

Haynesville Shale region of northwest Louisiana, and the Mid-Continent region which includes the Anadarko and Arkoma basins. This segment also includes our NGL and natural gas marketing business, storage facilities, an undivided 50 percent interest in an NGL fractionator near Conway, Kansas, and a 50 percent equity-method investment in Overland Pass Pipeline LLC, a 50 percent interest in Jackalope Gas Gathering Services, L.L.C. (Jackalope) (an equity-method investment following deconsolidation as of June 30, 2018) (see Note 15 – Subsequent Event of Notes to Consolidated Financial Statements regarding the sale of our Jackalope interest), a 50 percent equity-method investment in Rocky Mountain Midstream Holdings LLC, and a 15 percent equity-method investment in Brazos Permian II, LLC (Brazos Permian II). West also included our former natural gas gathering and processing assets in the Four Corners area of New Mexico and Colorado, which was sold during the fourth quarter of 2018.

Dividends

In March 2019, we paid a regular quarterly dividend of $0.38 per share. This represents an approximate 12 percent increase from our first-quarter 2018 quarterly dividend of $0.34 per share.

Overview of Three Months EndedMarch 31, 2019

Net income (loss) attributable to The Williams Companies, Inc., for the three months ended March 31, 2019, increased $43 millioncompared to the three months ended March 31, 2018, reflecting $89 million of increased service revenues and a $99 million decrease to Net income (loss) attributable to noncontrolling interests primarily due to the WPZ Merger, partially offset by a $74 million first-quarter 2019 impairment of an equity-method investment, lower commodity margins, and the absence of the Four Corners area business which was sold in October 2018.

Unless indicated otherwise, the following discussion and analysis ofresults of operations and financial condition and liquidity should be read in conjunction with the consolidated financial statements and notes thereto of this Form 10‑Q and our Annual Report on Form 10-K dated February 21, 2019.

Acquisition of UEOM

As of December 31, 2018, we owned a 62 percent interest in UEOM which we accounted for as an equity-method investment. On March 18, 2019, we signed and closed the acquisition of the remaining 38 percent interest in UEOM for $740 million in cash funded through credit facility borrowings and cash on hand. As a result of acquiring this additional interest, we obtained control of and now consolidate UEOM. (See Note 2 – Acquisitions of Notes to Consolidated Financial Statements.)

UEOM and OVM Venture

Concurrent with the UEOM acquisition, we executed an agreement whereby we will contribute our consolidated interests in UEOM and our Ohio Valley Midstream (OVM) business to a newly formed partnership later this year. Our partner will invest approximately $1.304 billion (subject to closing adjustments) for a 35 percent ownership interest, and we will retain 65 percent ownership of and operate the combined business. We expect to consolidate these operations in our consolidated financial statements. The closing of this transaction is subject to customary closing conditions, including regulatory approvals.

Sale of Jackalope

In April 2019, we sold our 50 percent interest in Jackalope for $485 million in cash. As of March 31, 2019, the carrying value of this investment within the West segment was $358 million. We plan to use the cash proceeds from the transaction to help fund capital expenditures and debt reduction.

Filing of Rate Case

On August 31, 2018, Transco filed a general rate case with the FERC for an overall increase in rates. In September 2018, with the exception of certain rates that reflected a rate decrease, the FERC accepted and suspended our general rate filing to be effective March 1, 2019, subject to refund and the outcome of a hearing. The specific rates that reflected a rate decrease were accepted, without suspension, to be effective October 1, 2018, as requested by Transco, and will

36

Management’s Discussion and Analysis (Continued)

not be subject to refund. In March 2019, the FERC accepted our motion to place the rates that were suspended by the September 2018 order into effect on March 1, 2019, subject to refund. We have provided a reserve for rate refunds which we believe is adequate for any refunds that may be required.

Commodity Prices

NGL per-unit margins were approximately 47 percent lower in the first three months of 2019 compared to the same period of 2018 primarily due to a 19 percent decrease in per-unit non-ethane prices and an approximate 26 percent increase in per-unit natural gas feedstock prices.

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

The potential impact of commodity prices on our business for the remainder of 2019 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 2019 includes a continued focus on growing our fee-based businesses, executing growth projects, including through joint ventures, and accomplishing cost discipline initiatives to ensure operations support our strategy. We anticipate operating results will increase through organic business growth driven by continued expansion in the Northeast region and Transco expansion projects.

Our growth capital and investment expenditures in 2019 are expected to be in a range from $2.3 billion to $2.5 billion. Growth capital spending in 2019 includes Transco expansions, all of which are fully contracted with firm transportation agreements, and continuing to develop our gathering and processing infrastructure in the Northeast G&P and West segments. In addition to growth capital and investment expenditures, we also remain committed to projects that maintain our assets for safe and reliable operations, as well as projects that meet legal, regulatory, and/or contractual commitments.

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

In 2019, our operating results are expected to include increases from our regulated Transco fee-based business, primarily related to projects placed in-service beginning early 2018. For our non-regulated businesses, we anticipate increases in fee-based revenue in the Northeast G&P segment associated with recent expansion projects, partially offset with a decrease in the West segment primarily due to asset divestitures in 2018. We expect overall gathering and processing volumes to grow in 2019 for our continuing businesses and anticipate an increase in our equity earnings primarily associated with new investments. Additionally, we believe general and administrative expenses will be slightly lower due to asset divestitures in 2018 and the effect of the WPZ merger.

37

Management’s Discussion and Analysis (Continued)

Potential risks and obstacles that could impact the execution of our plan include:

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

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

• Counterparty credit and performance risk;

• Unexpected changes in customer drilling and production activities, which could negatively impact gathering and processing volumes;

• Lower than anticipated demand for natural gas and natural gas products which could result in lower than expected volumes, energy commodity prices, and margins;

• General economic, financial markets, or further industry downturn, including increased interest rates;

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

• Other risks set forth under Part I, Item 1A. Risk Factors in our Annual Report on Form 10-K for the year ended December 31, 2018, as filed with the SEC on February 21, 2019.

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

Expansion Projects

Our ongoing major expansion projects include the following:

Northeast G&P

Ohio River Supply Hub Expansion

We agreed to expand our services for certain customers to provide additional rich gas processing capacity in the Marcellus and Upper Devonian Shale in West Virginia and Pennsylvania. Associated with these agreements, we are expanding the processing capacity of our Oak Grove facility up to 400 MMcf/d. With one of these customers, we secured a gathering dedication agreement to gather dry gas in this same region. Additionally, we are constructing a new NGL pipeline from Moundsville to the Harrison Hub fractionation facility to provide a new outlet for NGLs. These expansions will be supported by long-term, fee-based agreements and volumetric commitments.

Susquehanna Supply Hub Expansion

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

Atlantic-Gulf

Constitution Pipeline

We currently own 41 percent of Constitution with three other parties holding 25 percent, 24 percent, and 10 percent, respectively. We are the operator of Constitution. The 126-mile Constitution pipeline is proposed to connect our gathering system in Susquehanna County, Pennsylvania, to the Iroquois Gas Transmission and Tennessee Gas Pipeline systems in New York, as well as to a local distribution company serving New York and Pennsylvania.

In December 2014, Constitution received approval from 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

38

Management’s Discussion and Analysis (Continued)

Department of Environmental Conservation (NYSDEC) denied the necessary water quality certification under Section 401 of the Clean Water Act for the New York portion of the pipeline. In May 2016, Constitution appealed the NYSDEC’s denial of the Section 401 certification to the United States Court of Appeals for the Second Circuit and in August 2017, the court issued a decision denying in part and dismissing in part Constitution’s appeal. The court expressly declined to rule on Constitution’s argument that the delay in the NYSDEC’s decision on Constitution’s Section 401 application constitutes a waiver of the certification requirement. The court determined that it lacked jurisdiction to address that contention and found that jurisdiction over the waiver issue lies exclusively with the United States Court of Appeals for the District of Columbia Circuit (D.C. Circuit). As to the denial itself, the court determined that NYSDEC’s action was not arbitrary or capricious. Constitution filed a petition for rehearing with the Second Circuit Court of Appeals, but in October 2017 the court denied our petition.

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

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

The project’s sponsors remain committed to the project, and on April 1, 2019, we filed a supplemental pleading with the FERC explaining why we believe the Hoopa Valley Tribe decision requires the FERC to find that NYSDEC waived its authority to issue a Section 401 water quality certification for the Constitution project.(See Note 4 – Variable Interest Entities of Notes to Consolidated Financial Statements.)

Gateway

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

Hillabee

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

39

Management’s Discussion and Analysis (Continued)

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 completed modifications to our Main Pass 261 Platform to install an alternate delivery route from the platform, as well as modifications to our Mobile Bay processing facility. The project is scheduled to go into service during the second quarter of 2019.

In March 2019, we signed an agreement to purchase the Norphlet pipeline for $200 million. We expect the transaction to close in the second quarter of 2019.

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 addressed the technical issues identified by NYSDEC and in May 2018, we refiled our application for the permits. We plan to place the project into service in the fourth quarter of 2020, assuming timely receipt of all necessary regulatory approvals. The project is expected to increase capacity by 400 Mdth/d.

Rivervale South to Market

In August 2018, we received approval from the FERC to expand Transco’s existing natural gas transmission system to provide incremental firm transportation capacity from the existing Rivervale interconnection with Tennessee Gas Pipeline on Transco’s North New Jersey Extension to other existing Transco locations within New Jersey. We plan to place the project into service as early as the fourth quarter of 2019, assuming timely receipt of all necessary regulatory approvals. The project is expected to increase capacity by 190 Mdth/d.

Southeastern Trail

In April 2018, we filed an application with the FERC to expand Transco’s existing natural gas transmission system to provide incremental firm transportation capacity from the Pleasant Valley interconnect with Dominion’s Cove Point Pipeline in Virginia to the Station 65 pooling point in Louisiana. We plan to place the project into service in late 2020, assuming timely receipt of all necessary regulatory approvals. The project is expected to increase capacity by 296 Mdth/d.

West

North Seattle Lateral Upgrade

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

Wamsutter Expansion

We are expanding our gathering and processing infrastructure in the Wamsutter region of Wyoming in order to meet our customers’ production plans. The expansion includes the addition of approximately 60 miles of gathering pipelines and compression, and modifications to existing treating and processing facilities. Due to extreme weather conditions in Wyoming during the first quarter and the impact on construction, the first phase of the project is expected to be placed into service in the second quarter of 2019.

40

Management’s Discussion and Analysis (Continued)

Project Bluestem

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

Critical Accounting Estimates

Constitution Pipeline Capitalized Project Costs

As of March 31, 2019, Property, plant, and equipmentinour Consolidated Balance Sheet includes approximately $376 million of capitalized project costs for Constitution, for which we are the construction manager and own a 41 percent consolidated interest. As a result of the events discussed in Company Outlook, we evaluated the capitalized project costs for impairment at December 31, 2017, and determined that no impairment was necessary. Our evaluation considered probability-weighted scenarios of undiscounted future net cash flows, including scenarios assuming construction of the pipeline, as well as a scenario where the project does not proceed. These scenarios included our most recent estimate of total construction costs. Subsequently there have been no events or changes in circumstances that impact our conclusion. It is reasonably possible that future unfavorable developments, such as a reduced likelihood of success, increased estimates of construction costs, or further significant delays, could result in a future impairment.

Regulatory Liabilities Resulting from Tax Reform

In December 2017, the Tax Cuts and Jobs Act (Tax Reform) was enacted, which, among other things, reduced the corporate income tax rate from 35 percent to 21 percent. Rates charged to customers of our regulated natural gas pipelines are subject to the rate-making policies of the FERC, which have historically permitted the recovery of an income tax allowance that includes a deferred income tax component. Due to the reduced income tax rate from Tax Reform and the collection of historical rates that reflected historical federal income tax rates, we expect that our regulated natural gas pipelines will be required to return amounts to certain customers through future rates. As a result, we established regulatory liabilities during 2017 and at March 31, 2019, these liabilities total $655 million. The timing and actual amount of such return related to Transco will be subject to the outcome of the rate case discussed in Overview while the amount of such return related to Northwest Pipeline will be subject to future negotiations regarding this matter and many other elements of cost-of-service rate proceedings, including other costs of providing service.

41

Management’s Discussion and Analysis (Continued)

Results of Operations

Consolidated Overview

The following table and discussion is a summary of our consolidated results of operations for the three months ended March 31, 2019, compared to the three months ended March 31, 2018. The results of operations by segment are discussed in further detail following this consolidated overview discussion.

	Three Months Ended   March 31,
	2019			2018			$ Change*	% Change*
	(Millions)
Revenues:
Service revenues	$	1,440		$	1,351		+89	+7	%
Service revenues – commodity consideration	64			101			-37	-37	%
Product sales	550			636			-86	-14	%
Total revenues	2,054			2,088
Costs and expenses:
Product costs	525			613			+88	+14	%
Processing commodity expenses	40			35			-5	-14	%
Operating and maintenance expenses	340			357			+17	+5	%
Depreciation and amortization expenses	416			431			+15	+3	%
Selling, general, and administrative expenses	128			132			+4	+3	%
Other (income) expense – net	44			29			-15	-52	%
Total costs and expenses	1,493			1,597
Operating income (loss)	561			491
Equity earnings (losses)	80			82			-2	-2	%
Impairment of equity-method investments	(74		)	—			-74	NM
Other investing income (loss) – net	1			4			-3	-75	%
Interest expense	(296		)	(273		)	-23	-8	%
Other income (expense) – net	11			21			-10	-48	%
Income (loss) before income taxes	283			325
Provision (benefit) for income taxes	69			55			-14	-25	%
Net income (loss)	214			270
Less: Net income (loss) attributable to noncontrolling interests	19			118			+99	+84	%
Net income (loss) attributable to The Williams Companies, Inc.	$	195		$	152

* + = 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, 2019 vs. three months ended March 31, 2018

Service revenuesincreased primarily due to higher transportation fee revenues at Transco associated with expansion projects placed in service in 2019 and 2018, as well as higher volumes at the Susquehanna Supply Hub and in the Utica Shale region. These increases are partially offset by the absence of revenues associated with asset divestitures and deconsolidations during 2018, including our former Four Corners area operations.

Service revenues – commodity consideration decreased due to lower volumes primarily from our former Four Corners area operations and lower non-ethane prices. These revenues represent consideration we receive in the form of commodities as full or partial payment for gathering and processing services provided. Most of these NGL volumes are sold within the month processed and therefore are offset in Product costs below.

42

Management’s Discussion and Analysis (Continued)

Product salesdecreased primarily due to lower volumes impacting the production of our equity NGLs and system management gas sales, primarily reflecting the absence of our former Four Corners area operations, partially offset by an improvement associated with higher marketing volumes. The decrease in Product sales also reflects lower prices. Marketing revenues and system management gas sales are substantially offset in Product costs.

The decrease in Product costsis primarily due to decreases in costs associated with volumes acquired as commodity consideration for NGL processing services, marketing purchases, and system management gas costs.

Operating and maintenance expensesdecreased primarily due to the absence of our former Four Corners area operations.

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

The unfavorable change in Other (income) expense – net within Operating income (loss) includes a $12 million unfavorable change to a regulatory asset associated with Transco's estimated deferred state income tax rate and a $12 million impairment of certain assets.

The favorable change in Operating income (loss) includes an increase in Service revenues primarily associated with Transco projects placed in-service in 2018, and higher gathering volumes in the Northeast region, partially offset by unfavorable NGL commodity margins reflecting lower volumes, lower NGL sales prices, and the absence of our former Four Corners area operations.

The Impairment of equity-method investments reflects a non-cash impairment of our existing interest in UEOM (see Note 12 – Fair Value Measurements and Guarantees of Notes to Consolidated Financial Statements).

The unfavorable change in Interest expense is primarily due to an increase in other financing obligations associated with Transco’s Atlantic Sunrise project.

The unfavorable change in Other income (expense) – net below Operating income (loss)is primarily due to a decrease in the allowance for equity funds used during construction (AFUDC), partially offset by the absence of a 2018 loss on early retirement of debt.

Provision (benefit) for income taxes changed unfavorably primarily due to the absence of allocation of income to nontaxable noncontrolling interests from WPZ, partially offset by lower pre-tax income. See Note 6 – Provision (Benefit) for Income Taxes of Notes to Consolidated Financial Statements for a discussion of the effective tax rate compared to the federal statutory rate for both periods.

The favorable change in Net income (loss) attributable to noncontrolling interests is primarily due to our third- quarter 2018 acquisition of the publicly held interests in WPZ associated with the WPZ Merger.

Period-Over-Period Operating Results - Segments

We evaluate segment operating performance based upon Modified EBITDA. Note 14 – 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.

43

Management’s Discussion and Analysis (Continued)

Northeast G&P

	Three Months Ended   March 31,
	2019			2018
	(Millions)
Service revenues	$	276		$	228
Service revenues – commodity consideration	5			4
Product sales	47			98
Segment revenues	328			330
Product costs	(47		)	(99		)
Processing commodity expenses	(3		)	(2		)
Other segment costs and expenses	(101		)	(87		)
Proportional Modified EBITDA of equity-method investments	122			108
Northeast G&P Modified EBITDA	$	299		$	250

Three months ended March 31, 2019 vs. three months ended March 31, 2018

Northeast G&P Modified EBITDA increased primarily due to higher Service revenues.

Service revenues increased primarily due to $33 million higher gathering revenues at Susquehanna Supply Hub reflecting 25 percent higher gathering volumes due to increased production from customers and higher rates. Additionally, gathering, processing, and fractionation revenues increased in the Utica Shale region due to higher volumes from new wells and from UEOM, which is now a consolidated entity after the remaining ownership interest was purchased in March 2019.

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

Other segment costs and expenses increased due to multiple factors, including higher costs related to various maintenance and repairs.

Proportional Modified EBITDA of equity-method investments increased primarily due to a $9 million increase at Appalachia Midstream Investments, reflecting higher volumes.

44

Management’s Discussion and Analysis (Continued)

Atlantic-Gulf

	Three Months Ended   March 31,
	2019			2018
	(Millions)
Service revenues	$	709		$	609
Service revenues – commodity consideration	13			15
Product sales	82			93
Segment revenues	804			717
Product costs	(82		)	(92		)
Processing commodity expenses	(5		)	(5		)
Other segment costs and expenses	(199		)	(212		)
Proportional Modified EBITDA of equity-method investments	42			43
Atlantic-Gulf Modified EBITDA	$	560		$	451
NGL margin	$	7		$	10

Three months ended March 31, 2019 vs. three months ended March 31, 2018

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

Service revenues increased primarily due to a $108 million increase in Transco’s natural gas transportation revenues driven by expansion projects placed in service in 2018 and 2019.

The decrease in Product sales includes a $6 million decrease in system management gas sales and a $5 million decrease in commodity marketing sales. System management gas sales and marketing sales are substantially offset in Product costs and therefore have little impact to Modified EBITDA.

Other segment costs and expenses decreased primarily due to the absence of a first-quarter 2018 $11 million unfavorable adjustment of regulatory liabilities associated with Tax Reform, $6 million lower general pipeline maintenance and other testing, and $5 million favorable changes in other charges and credits related to regulatory assets and liabilities. These favorable changes were partially offset by a $13 million decrease in Transco’s equity AFUDC.

West

	Three Months Ended   March 31,
	2019			2018
	(Millions)
Service revenues	$	473		$	531
Service revenues – commodity consideration	46			82
Product sales	479			530
Segment revenues	998			1,143
Product costs	(475		)	(526		)
Processing commodity expenses	(31		)	(30		)
Other segment costs and expenses	(186		)	(192		)
Proportional Modified EBITDA of equity-method investments	26			18
West Modified EBITDA	$	332		$	413
NGL margin	$	14		$	52

45

Management’s Discussion and Analysis (Continued)

Three months ended March 31, 2019 vs. three months ended March 31, 2018

West Modified EBITDA decreased primarily due to $27 million associated with the absence of our former Four Corners area assets sold in fourth-quarter 2018, as well as lower Service revenues and $24 million lower commodity margins associated with our equity NGLs, excluding the Four Corners area assets.

Service revenues decreased primarily due to:

• A $65 million decrease associated with asset divestitures and deconsolidations during 2018, including our former Four Corners area assets, our Jackalope assets, and certain Delaware basin assets that were contributed to our Brazos Permian II equity-method investment;

• A $15 million decrease driven by lower gathering volumes due to more severe weather conditions in 2019 primarily in Wyoming;

• An $11 million increase associated with higher other fee revenue, primarily in the Conway area mainly associated with higher fractionation volumes and new contracts with higher prices;

• A $7 million increase associated with higher gathering rates primarily in the Barnett Shale region.

The net sum of Service revenues – commodity consideration, Product sales, Product costs, andProcessing commodity expensescomprise our commodity product margins. Our commodity product margins associated with our equity NGLs decreased $38 million as follows:

• $23 million of the decrease is due to lower volumes, consisting of $14 million associated with the divestiture of our former Four Corners area assets and $13 million associated with 19 percent lower non-ethane sales volumes due to well freeze-offs and temporary shut-ins related to more severe weather conditions in 2019 and natural decline, partially offset by a $4 million decrease in natural gas purchases associated with the production of equity NGLs;

• $15 million of the decrease is due to unfavorable commodity prices. Natural gas costs associated with the production of equity NGLs increased $8 million due to 34 percent higher average per-unit natural gas prices, and sales revenues decreased $7 million primarily due to 17 percent lower average per-unit non-ethane prices.

Additionally, the decrease in Product sales includes a $12 million decrease in system management gas sales, which are substantially offset in Product costs.

Other segment costs and expenses decreased primarily due to the sale of our former Four Corners area assets, partially offset by a $12 million impairment of assets and the absence of a $7 million favorable adjustment to the regulatory charge associated with the impact of Tax Reform at Northwest Pipeline in first-quarter 2018.

Proportional Modified EBITDA of equity-method investments increased primarily due to the deconsolidation of Jackalope in the second quarter of 2018, such that it became an equity-method investment, as well as the addition of the Brazos Permian II equity-method investment in December 2018.

46

Management’s Discussion and Analysis (Continued)

Management’s Discussion and Analysis of Financial Condition and Liquidity

Outlook

Fee-based businesses are a significant component of our portfolio and serve to reduce the influence of commodity price fluctuations on our cash flows. We expect to benefit as continued growth in demand for low-cost natural gas is driven by increases in LNG exports, industrial demand, and power generation.

As previously discussed in Company Outlook, our growth capital and investment expenditures in 2019 are currently expected to be in a range from $2.3 billion to $2.5 billion. Growth capital spending in 2019 includes Transco expansions, all of which are fully contracted with firm transportation agreements, and continuing to develop our gathering and processing infrastructure in the Northeast G&P and West segments. In addition to growth capital and investment expenditures, we also remain committed to projects that maintain our assets for safe and reliable operations, as well as projects that meet legal, regulatory, and/or contractual commitments. We intend to fund our planned 2019 growth capital with retained cash flow and certain sources of available liquidity described below. We retain the flexibility to adjust planned levels of growth capital and investment expenditures in response to changes in economic conditions or business opportunities.

In March 2019, we funded our acquisition of the remaining interest in UEOM with credit facility borrowings and cash on hand. In 2019, we expect to receive approximately $1.304 billion from our partner upon closing the UEOM and OVM transaction. Also in April 2019, we received $485 million from the sale of our 50 percent interest in Jackalope. These funds will be used to reduce debt and commercial paper outstanding and fund growth capital.

Liquidity

Based on our forecasted levels of cash flow from operations and other sources of liquidity, we expect to have sufficient liquidity to manage our businesses in 2019. Our potential material internal and external sources and uses of liquidity for 2019 are as follows:

Sources:
	Cash and cash equivalents on hand
	Cash generated from operations
	Distributions from our equity-method investees
	Utilization of our credit facility and/or commercial paper program
	Cash proceeds from issuance of debt and/or equity securities
	Proceeds from asset monetizations
	Contributions from noncontrolling interests
Uses:
	Working capital requirements
	Capital and investment expenditures
	Quarterly dividends to our shareholders
	Debt service payments, including payments of long-term debt
	Distributions to noncontrolling interests

Potential risks associated with our planned levels of liquidity discussed above include those previously discussed in Company Outlook.

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Management’s Discussion and Analysis (Continued)

As of March 31, 2019, we had a working capital deficit of $2.882 billion, including cash and cash equivalents and commercial paper outstanding. Our available liquidity is as follows:

Available Liquidity	March 31, 2019
	(Millions)
Cash and cash equivalents	$	43
Capacity available under our $4.5 billion credit facility, less amounts outstanding under our $4 billion commercial paper program (1)	3,484
	$	3,527

(1) In managing our available liquidity, we do not expect a maximum outstanding amount in excess of the capacity of our credit facility inclusive of any outstanding amounts under our commercial paper program. We had $1.016 billion of Commercial paper, exclusive of unamortized discount, outstanding as of March 31, 2019. Through March 31, 2019, the highest amount outstanding under our commercial paper program and credit facility during 2019 was $1.226 billion. At March 31, 2019, we were in compliance with the financial covenants associated with our credit facility. Borrowing capacity available under our credit facility as of April 30, 2019, was $4.163 billion.

Dividends

We increased our regular quarterly cash dividend to common stockholders by approximately 12 percent from the previous quarterly cash dividends of $0.34 per share paid in each quarter of 2018, to $0.38 per share for the quarterly cash dividends paid in March 2019.

Registrations

In February 2018, we filed a shelf registration statement, as a well-known seasoned issuer. In August 2018, we filed a prospectus supplement for the offer and sale from time to time of shares of our common stock having an aggregate offering price of up to $1 billion. These sales are to be made over a period of time and from time to time in transactions at then-current prices. Such sales are to be made pursuant to an equity distribution agreement between us and certain entities who may act as sales agents or purchase for their own accounts as principals at a price agreed upon at the time of the sale.

Distributions from Equity-Method Investees

The organizational documents of entities in which we have an equity-method investment generally require distribution of their available cash to their members on a quarterly basis. In each case, available cash is reduced, in part, by reserves appropriate for operating their respective businesses.

Credit Ratings

The interest rates at which we are able to borrow money is impacted by our credit ratings. The current ratings are as follows:

Rating Agency	Outlook	Senior Unsecured Debt Rating	Corporate Credit Rating
S&P Global Ratings	Negative	BBB	BBB
Moody’s Investors Service	Stable	Baa3	N/A
Fitch Ratings	Positive	BBB-	N/A

These credit ratings are included for informational purposes and are not recommendations to buy, sell, or hold our securities, and each rating should be evaluated independently of any other rating. No assurance can be given that the credit rating agencies will continue to assign us investment-grade ratings even if we meet or exceed their current criteria for investment-grade ratios. A downgrade of our credit ratings might increase our future cost of borrowing and would require us to provide additional collateral to third parties, negatively impacting our available liquidity.

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Management’s Discussion and Analysis (Continued)

Sources (Uses) of Cash

The following table summarizes the sources (uses) of cash and cash equivalents for each of the periods presented (see Notes to Consolidated Financial Statements for the Notes referenced in the table):

	Cash Flow	Three Months Ended   March 31,
	Category	2019			2018
		(Millions)
Sources of cash and cash equivalents:
Operating activities – net	Operating	$	775		$	694
Proceeds from commercial paper – net	Financing	1,014			—
Proceeds from credit-facility borrowings	Financing	700			240
Contributions in aid of construction	Investing	10			190
Proceeds from long-term debt	Financing	8			1,808
Uses of cash and cash equivalents:
Payments on credit-facility borrowings	Financing	(860		)	(310		)
Purchase of business, net of cash acquired (see Note 2)	Investing	(727		)	—
Common dividends paid	Financing	(460		)	(281		)
Capital expenditures	Investing	(422		)	(957		)
Purchases of and contributions to equity-method investments	Investing	(99		)	(21		)
Dividends and distributions paid to noncontrolling interests	Financing	(41		)	(165		)
Payments of long-term debt	Financing	(4		)	(750		)
Other sources / (uses) – net	Financing and Investing	(19		)	(55		)
Increase (decrease) in cash and cash equivalents		$	(125	)	$	393

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 Impairment of equity-method investments. Our Net cash provided (used) by operating activities for the three months ended March 31, 2019, increased from the same period in 2018 primarily due to the net favorable changes in operating working capital in 2019 as well as the impact of increased distributions from unconsolidated affiliates in 2019.

Off-Balance Sheet Arrangements and Guarantees of Debt or Other Commitments

We have various other guarantees and commitments which are disclosed in Note 4 – Variable Interest Entities, Note 10 – Debt and Banking Arrangements, Note 12 – Fair Value Measurements and Guarantees, and Note 13 – 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.

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Item 3

Quantitative and Qualitative Disclosures About Market Risk

Interest Rate Risk

Our current interest rate risk exposure is related primarily to our debt portfolio and has not materially changed during the first three months of 2019.

Item 4

Controls and Procedures

Our management, including our Chief Executive Officer and Chief Financial Officer, does not expect that our disclosure controls and procedures (as defined in Rules 13a - 15(e) and 15d - 15(e) of the Securities Exchange Act of 1934, as amended) (Disclosure Controls) or our internal control over financial reporting (Internal Controls) will prevent all errors and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within the company have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty, and that breakdowns can occur because of simple error or mistake. Additionally, controls can be circumvented by the individual acts of some persons, by collusion of two or more people, or by management override of the control. The design of any system of controls also is based in part upon certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions. Because of the inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and not be detected. We monitor our Disclosure Controls and Internal Controls and make modifications as necessary; our intent in this regard is that the Disclosure Controls and Internal Controls will be modified as systems change and conditions warrant.

Evaluation of Disclosure Controls and Procedures

An evaluation of the effectiveness of the design and operation of our Disclosure Controls was performed as of the end of the period covered by this report. This evaluation was performed under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer. Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that these Disclosure Controls are effective at a reasonable assurance level.

Changes in Internal Control Over Financial Reporting

There have been no changes during the first quarter of 2019 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.

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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. On July 23, 2018, we received an offer from the DOJ to globally settle the government’s claim for civil penalties associated with the alleged violations at both the Moundsville and the Oak Grove facilities for $1.6 million. We are continuing to work with the agencies to resolve this matter.

On May 5, 2017, we entered into a Consent Order with the Georgia Department of Natural Resources, Environmental Protection Division (GADNR) pertaining to alleged violations of the Georgia Water Quality Control Act and associated rules arising from a permit issued by GADNR for construction of Transco’s Dalton expansion project. Pursuant to the Consent Order, we paid a fine of $168,750 and agreed to perform a Corrective Action Plan, the completion of which is pending.

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 have responded to the alleged violations and continue to work with the agencies to resolve this matter.

On March 20, 2018, we also received a Notice of Violation from the EPA, Region 8, regarding certain alleged violations of the Clean Air Act at our Parachute Creek Gas Plant in Parachute, Colorado, following a previous on-site inspection of the facility. We were informed that this matter has been referred to the DOJ for handling. The Notice of Violation does not contain an initial penalty assessment. We have responded to the alleged violations and continue to work with the agencies to resolve this matter.

On August 27, 2018, Northwest Pipeline LLC received a Notice of Violation/Cease and Desist Order from the Colorado Department of Public Health & Environment (CDPHE) regarding certain alleged violations of the Colorado Water Quality Control Act and its General Permit under the Colorado Discharge Permit System related to its stormwater management practices at two construction sites. On March 4, 2019, the CDPHE provided us with its initial penalty calculation, proposing a penalty of $81,000 in settlement of all violations alleged in its notice. We have responded to the alleged violations and continue to work with the agency to resolve this matter.

Other environmental matters called for by this Item are described under the caption “Environmental Matters” in Note 13 – Contingent Liabilities of Notes to Consolidated Financial Statements included under Part I, Item 1. Financial Statements of this report, which information is incorporated by reference into this Item.

Other Litigation

The additional information called for by this Item is provided in Note 13 – 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.

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Item 1A. Risk Factors

Part I, Item 1A. Risk Factors in our Annual Report on Form 10-K for the year ended December 31, 2018, includes risk factors that could materially affect our business, financial condition, or future results. Those risk factors have not materially changed.

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Item 6. Exhibits

Exhibit No.		Description
2.1+	—	Agreement and Plan of Merger dated as of May 16, 2018, by and among The Williams Companies, Inc., SCMS LLC, Williams Partners L.P., and WPZ GP LLC (filed on May 17, 2018 as Exhibit 2.1 to The Williams Companies, Inc.’s current report on Form 8-K (File No. 001-04174) and incorporated herein by reference).
2.2	—	Amendment No 1. to Agreement and Plan of Merger dated as of May 1, 2016, by and among The Williams Companies, Inc., Energy Transfer Corp LP, Energy Transfer Corp GP, LLC, Energy Transfer Equity, L.P., LE GP, LLC and Energy Transfer Equity GP, LLC (filed on May 3, 2016 as Exhibit 2.1 to The Williams Companies, Inc.’s current report on Form 8-K (File No. 001-04174) and incorporated herein by reference).
2.3+	—	Agreement and Plan of Merger dated as of September 28, 2015, by and among The Williams Companies, Inc., Energy Transfer Corp LP, Energy Transfer Corp GP, LLC, Energy Transfer Equity, L.P., LE GP, LLC and Energy Transfer Equity GP, LLC (filed on October 1, 2015 as Exhibit 2.1 to The Williams Companies, Inc.’s current report on Form 8-K (File No. 001-04174) and incorporated herein by reference).
3.1	—	Amended and Restated Certificate of Incorporation as supplemented (filed on May 26, 2010, as Exhibit 3.1 to The Williams Companies, Inc.’s current report on Form 8-K (File No. 001-04174) and incorporated herein by reference).
3.2	—	Certificate of Designations of Series B Preferred Stock of The Williams Companies, Inc. (filed on July 17, 2018 as Exhibit 3.1 to The Williams Companies, Inc. current report on Form 8-K (File No. 001-04174) and incorporated herein by reference).
3.3	—	Certificate of Amendment dated August 10, 2018 (filed on August 10, 2018 as Exhibit 3.1 to The Williams Companies, Inc.’s current report on Form 8-K (File No. 001-04174) and incorporated herein by reference).
3.4	—	By-Laws (filed on January 20, 2017, as Exhibit 3.1 to The Williams Companies, Inc.’s current report on Form 8-K (File No. 001-04174) and incorporated herein by reference).
10.1§*	—	Form of 2019 Executive Performance-Based Restricted Stock Unit Agreement among The Williams Companies, Inc. and certain employees and officers.
10.2§*	—	Form of 2019 Performance-Based Restricted Stock Unit Agreement among The Williams Companies, Inc. and certain employees and officers.
10.3§*	—	Form of 2019 Time-Based Restricted Stock Unit Agreement among The Williams Companies, Inc. and certain employees and officers.
10.4§*	—	Form of 2019 Time-Based Restricted Stock Unit Agreement among The Williams Companies, Inc. and certain non-management directors.
31.1*	—	Certification of Chief Executive Officer pursuant to Rules 13a-14(a) and 15d-14(a) promulgated under the Securities Exchange Act of 1934, as amended, and Item 601(b)(31) of Regulation S-K, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*	—	Certification of Chief Financial Officer pursuant to Rules 13a-14(a) and 15d-14(a) promulgated under the Securities Exchange Act of 1934, as amended, and Item 601(b)(31) of Regulation S-K, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32**	—	Certification of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS*	—	XBRL Instance Document.
101.SCH*	—	XBRL Taxonomy Extension Schema.
101.CAL*	—	XBRL Taxonomy Extension Calculation Linkbase.

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Exhibit No.		Description
101.DEF*	—	XBRL Taxonomy Extension Definition Linkbase.
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.

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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)

May 2, 2019