WILLIAMS COMPANIES, INC. - Quarter Report: 2017 September (Form 10-Q)

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 September 30, 2017



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

For the transition period from _____________ to _____________

Commission file number 1-4174

THE WILLIAMS COMPANIES, INC.

(Exact name of registrant as specified in its charter)



DELAWARE		73-0569878
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

ONE WILLIAMS CENTER
TULSA, OKLAHOMA		74172-0172
(Address of principal executive offices)		(Zip Code)

Registrant’s telephone number, including area code: (918) 573-2000

NO CHANGE

(Former name, former address and former fiscal year, if changed since last report.)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes þ No ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.



Large accelerated filer þ	Accelerated filer ¨	Non-accelerated filer ¨	Smaller reporting company ¨	Emerging growth company ¨
		(Do not check if a smaller reporting company)

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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act.) Yes ¨ No þ

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



Class		Shares Outstanding at October 30, 2017
Common Stock, $1 par value		826,746,549

The Williams Companies, Inc.

Index



		Page
Part I. Financial Information
Item 1. Financial Statements
Consolidated Statement of Operations – Three and Nine Months Ended September 30, 2017 and 2016		6
Consolidated Statement of Comprehensive Income (Loss) – Three and Nine Months Ended September 30, 2017 and 2016		7
Consolidated Balance Sheet – September 30, 2017 and December 31, 2016		8
Consolidated Statement of Changes in Equity – Nine Months Ended September 30, 2017		9
Consolidated Statement of Cash Flows – Nine Months Ended September 30, 2017 and 2016		10
Notes to Consolidated Financial Statements		11
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		37
Item 3. Quantitative and Qualitative Disclosures About Market Risk		61
Item 4. Controls and Procedures		61
Part II. Other Information		61
Item 1. Legal Proceedings		61
Item 6. Exhibits		63

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

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


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


•	Levels of dividends to Williams stockholders;


•	Future credit ratings of Williams, WPZ, and their affiliates;


•	Amounts and nature of future capital expenditures;


•	Expansion and growth of our business and operations;


•	Expected in-service dates for capital projects;


•	Financial condition and liquidity;


•	Business strategy;


•	Cash flow from operations or results of operations;


•	Seasonality of certain business components;


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


•	Demand for our services.

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


•	Whether WPZ will produce sufficient cash flows to provide expected levels of cash distributions;


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


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


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


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


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


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


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


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


•	Whether we are able to successfully identify, evaluate and timely execute our capital projects and other investment opportunities in accordance with our forecasted capital expenditures budget;


•	Our ability to successfully expand our facilities and operations;


•	Development and rate of adoption of alternative energy sources;


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


•	The impact of existing and future laws, 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;


•	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, including cybersecurity threats, and related disruptions;


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

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

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

Because forward-looking statements involve risks and uncertainties, we caution that there are important factors, in addition to those listed above, that may cause actual results to differ materially from those contained in the forward-looking statements. For a detailed discussion of those factors, see Part I, Item 1A. Risk Factors in our Annual Report on Form 10-K filed with the SEC on February 22, 2017.

DEFINITIONS

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

Measurements:

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

Bcf: One billion cubic feet of natural gas

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

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

Fahrenheit

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

Mbbls/d: One thousand barrels per day

Mdth/d: One thousand dekatherms per day

MMcf/d: One million cubic feet per day

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

MMdth/d: One million dekatherms per day

Tbtu: One trillion British thermal units

Consolidated Entities:

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

Constitution: Constitution Pipeline Company, LLC

Gulfstar One: Gulfstar One LLC

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

Northwest Pipeline: Northwest Pipeline LLC

Transco: Transcontinental Gas Pipe Line Company, LLC

WPZ: Williams Partners L.P.

Partially Owned Entities: Entities in which we do not own a 100 percent ownership interest and which, as of September 30, 2017, we account for as an equity-method investment, including principally the following:

Aux Sable: Aux Sable Liquid Products LP

Caiman II: Caiman Energy II, LLC

Discovery: Discovery Producer Services LLC

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

Laurel Mountain: Laurel Mountain Midstream, LLC

OPPL: Overland Pass Pipeline Company LLC

UEOM: Utica East Ohio Midstream LLC

Government and Regulatory:

EPA: Environmental Protection Agency

FERC: Federal Energy Regulatory Commission

SEC: Securities and Exchange Commission

Other:

Merger Agreement: Merger Agreement and Plan of Merger of Williams with Energy Transfer and certain of its affiliates

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

GAAP: U.S. generally accepted accounting principles

IDR: Incentive distribution right

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

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

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

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

PDH facility: Propane dehydrogenation facility

RGP Splitter: Refinery grade propylene splitter

PART I – FINANCIAL INFORMATION

The Williams Companies, Inc.

Consolidated Statement of Operations

(Unaudited)



	Three Months Ended September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016
	(Millions, except per-share amounts)
Revenues:
Service revenues	$	1,310		$	1,247		$	3,853		$	3,678
Product sales	581			658			1,950			1,623
Total revenues	1,891			1,905			5,803			5,301
Costs and expenses:
Product costs	504			461			1,620			1,180
Operating and maintenance expenses	400			394			1,157			1,179
Depreciation and amortization expenses	433			435			1,308			1,326
Selling, general, and administrative expenses	138			177			452			556
Gain on sale of Geismar Interest (Note 3)	(1,095		)	—			(1,095		)	—
Impairment of certain assets (Note 11)	1,210			1			1,236			811
Other (income) expense – net	24			92			34			130
Total costs and expenses	1,614			1,560			4,712			5,182
Operating income (loss)	277			345			1,091			119
Equity earnings (losses)	115			104			347			302
Impairment of equity-method investments (Note 11)	—			—			—			(112		)
Other investing income (loss) – net (Note 4)	4			28			278			64
Interest incurred	(275		)	(304		)	(842		)	(916		)
Interest capitalized	8			7			24			30
Other income (expense) – net	20			20			115			52
Income (loss) before income taxes	149			200			1,013			(461		)
Provision (benefit) for income taxes	24			69			126			(74		)
Net income (loss)	125			131			887			(387		)
Less: Net income (loss) attributable to noncontrolling interests	92			70			400			22
Net income (loss) attributable to The Williams Companies, Inc.	$	33		$	61		$	487		$	(409	)
Amounts attributable to The Williams Companies, Inc.:
Basic earnings (loss) per common share:
Net income (loss)	$	.04		$	.08		$	.59		$	(.55	)
Weighted-average shares (thousands)	826,779			750,754			825,925			750,579
Diluted earnings (loss) per common share:
Net income (loss)	$	.04		$	.08		$	.59		$	(.55	)
Weighted-average shares (thousands)	829,368			751,858			828,150			750,579
Cash dividends declared per common share	$	.30		$	.20		$	.90		$	1.48

See accompanying notes.

The Williams Companies, Inc.

Consolidated Statement of Comprehensive Income (Loss)

(Unaudited)



	Three Months Ended September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016
	(Millions)
Net income (loss)	$	125		$	131		$	887		$	(387	)
Other comprehensive income (loss):
Cash flow hedging activities:
Net unrealized gain (loss) from derivative instruments, net of taxes of $2 and $1 in 2017	(9		)	2			(5		)	2
Reclassifications into earnings of net derivative instruments (gain) loss, net of taxes of $1 and $1 in 2017	2			—			—			—
Foreign currency translation activities:
Foreign currency translation adjustments, net of taxes of ($25) and ($37) in 2016	—			(49		)	—			50
Reclassification into earnings upon sale of foreign entities, net of taxes of ($36) in 2016.	—			119			—			119
Pension and other postretirement benefits:
Amortization of prior service cost (credit) included in net periodic benefit cost, net of taxes of $1 and $2 in 2017 and $0 and $1 in 2016	—			(1		)	(2		)	(3		)
Net actuarial gain (loss) arising during the year, net of taxes of $2 in 2016	—			—			—			(3		)
Amortization of actuarial (gain) loss included in net periodic benefit cost, net of taxes of ($2) and ($7) in 2017 and ($3) and ($9) in 2016	4			5			13			15
Other comprehensive income (loss)	(3		)	76			6			180
Comprehensive income (loss)	122			207			893			(207		)
Less: Comprehensive income (loss) attributable to noncontrolling interests	89			108			398			91
Comprehensive income (loss) attributable to The Williams Companies, Inc.	$	33		$	99		$	495		$	(298	)

See accompanying notes.

The Williams Companies, Inc.

Consolidated Balance Sheet

(Unaudited)



	September 30, 2017			December 31, 2016
	(Millions, except per-share amounts)
ASSETS
Current assets:
Cash and cash equivalents	$	1,172		$	170
Trade accounts and other receivables (net of allowance of $6 at September 30, 2017 and $6 at December 31, 2016)	783			938
Inventories	144			138
Other current assets and deferred charges	194			216
Total current assets	2,293			1,462
Investments	6,615			6,701
Property, plant, and equipment	38,712			38,912
Accumulated depreciation and amortization	(11,003		)	(10,484		)
Property, plant, and equipment – net	27,709			28,428
Intangible assets – net of accumulated amortization	8,873			9,663
Regulatory assets, deferred charges, and other	630			581
Total assets	$	46,120		$	46,835
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	773		$	623
Accrued liabilities	1,079			1,448
Commercial paper	—			93
Long-term debt due within one year	502			785
Total current liabilities	2,354			2,949
Long-term debt	20,567			22,624
Deferred income tax liabilities	5,211			4,238
Regulatory liabilities, deferred income, and other	3,106			2,978
Contingent liabilities (Note 12)
Equity:
Stockholders’ equity:
Common stock (960 million shares authorized at $1 par value; 861 million shares issued at September 30, 2017 and 785 million shares issued at December 31, 2016)	861			785
Capital in excess of par value	18,492			14,887
Retained deficit	(9,872		)	(9,649		)
Accumulated other comprehensive income (loss)	(331		)	(339		)
Treasury stock, at cost (35 million shares of common stock)	(1,041		)	(1,041		)
Total stockholders’ equity	8,109			4,643
Noncontrolling interests in consolidated subsidiaries	6,773			9,403
Total equity	14,882			14,046
Total liabilities and equity	$	46,120		$	46,835

See accompanying notes.

The Williams Companies, Inc.

Consolidated Statement of Changes in Equity

(Unaudited)



	The Williams Companies, Inc., Stockholders
	Common Stock		Capital in Excess of Par Value		Retained Deficit			Accumulated Other Comprehensive Income (Loss)			Treasury Stock			Total Stockholders’ Equity			Noncontrolling Interests			Total Equity
	(Millions)
Balance – December 31, 2016	$	785	$	14,887	$	(9,649	)	$	(339	)	$	(1,041	)	$	4,643		$	9,403		$	14,046
Net income (loss)	—		—		487			—			—			487			400			887
Other comprehensive income (loss)	—		—		—			8			—			8			(2		)	6
Issuance of common stock (Note 10)	75		2,043		—			—			—			2,118			—			2,118
Cash dividends – common stock	—		—		(744		)	—			—			(744		)	—			(744		)
Dividends and distributions to noncontrolling interests	—		—		—			—			—			—			(679		)	(679		)
Stock-based compensation and related common stock issuances, net of tax	1		59		—			—			—			60			—			60
Adoption of ASU 2016-09 (Note 1)	—		1		36			—			—			37			—			37
Sales of limited partner units of Williams Partners L.P.	—		—		—			—			—			—			43			43
Changes in ownership of consolidated subsidiaries, net	—		1,497		—			—			—			1,497			(2,404		)	(907		)
Contributions from noncontrolling interests	—		—		—			—			—			—			15			15
Other	—		5		(2		)	—			—			3			(3		)	—
Net increase (decrease) in equity	76		3,605		(223		)	8			—			3,466			(2,630		)	836
Balance – September 30, 2017	$	861	$	18,492	$	(9,872	)	$	(331	)	$	(1,041	)	$	8,109		$	6,773		$	14,882

See accompanying notes.

The Williams Companies, Inc.

Consolidated Statement of Cash Flows

(Unaudited)



	Nine Months Ended September 30,
	2017			2016
	(Millions)
OPERATING ACTIVITIES:
Net income (loss)	$	887		$	(387	)
Adjustments to reconcile to net cash provided (used) by operating activities:
Depreciation and amortization	1,308			1,326
Provision (benefit) for deferred income taxes	99			(74		)
Net (gain) loss on disposition of equity-method investments	(269		)	—
Impairment of equity-method investments	—			112
Gain on sale of Geismar Interest (Note 3)	(1,095		)	—
Impairment of and net (gain) loss on sale of assets and businesses	1,225			867
Amortization of stock-based awards	61			55
Cash provided (used) by changes in current assets and liabilities:
Accounts and notes receivable	118			172
Inventories	(23		)	(7		)
Other current assets and deferred charges	(11		)	(11		)
Accounts payable	47			(6		)
Accrued liabilities	(161		)	129
Other, including changes in noncurrent assets and liabilities	(349		)	(79		)
Net cash provided (used) by operating activities	1,837			2,097
FINANCING ACTIVITIES:
Proceeds from (payments of) commercial paper – net	(93		)	(499		)
Proceeds from long-term debt	3,013			5,708
Payments of long-term debt	(5,475		)	(4,966		)
Proceeds from issuance of common stock	2,130			8
Dividends paid	(744		)	(1,111		)
Dividends and distributions paid to noncontrolling interests	(636		)	(715		)
Contributions from noncontrolling interests	15			27
Payments for debt issuance costs	(14		)	(8		)
Contribution to Gulfstream for repayment of debt	—			(148		)
Other – net	(87		)	(16		)
Net cash provided (used) by financing activities	(1,891		)	(1,720		)
INVESTING ACTIVITIES:
Property, plant, and equipment:
Capital expenditures (1)	(1,700		)	(1,577		)
Dispositions – net	(27		)	29
Proceeds from sale of businesses, net of cash divested	2,056			712
Proceeds from dispositions of equity-method investments	200			—
Purchases of and contributions to equity-method investments	(103		)	(132		)
Distributions from unconsolidated affiliates in excess of cumulative earnings	394			341
Other – net	236			227
Net cash provided (used) by investing activities	1,056			(400		)
Increase (decrease) in cash and cash equivalents	1,002			(23		)
Cash and cash equivalents at beginning of year	170			100
Cash and cash equivalents at end of period	$	1,172		$	77
_____________
(1) Increases to property, plant, and equipment	$	(1,826	)	$	(1,468	)
Changes in related accounts payable and accrued liabilities	126			(109		)
Capital expenditures	$	(1,700	)	$	(1,577	)

See accompanying notes.

The Williams Companies, Inc.

Notes to Consolidated Financial Statements

(Unaudited)

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

General

Our accompanying interim consolidated financial statements do not include all the notes in our annual financial statements and, therefore, should be read in conjunction with the consolidated financial statements and notes thereto for the year ended December 31, 2016, in Exhibit 99.1 of our Form 8-K dated May 25, 2017. The accompanying unaudited financial statements include all normal recurring adjustments and others that, in the opinion of management, are necessary to present fairly our interim financial statements.

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

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

Financial Repositioning

In January 2017, we announced agreements with Williams Partners L.P. (WPZ), wherein we permanently waived the general partner’s incentive distribution rights (IDRs) and converted our 2 percent general partner interest in WPZ to a noneconomic interest in exchange for 289 million newly issued WPZ common units. Pursuant to this agreement, we also purchased approximately 277 thousand WPZ common units for $10 million. Additionally, we purchased approximately 59 million common units of WPZ at a price of $36.08586 per unit in a private placement transaction, funded with proceeds from our equity offering (see Note 10 – Stockholders’ Equity). According to the terms of this agreement, concurrent with WPZ’s quarterly distributions in February 2017 and May 2017, we paid additional consideration totaling $56 million to WPZ for these units. Subsequent to these transactions and as of September 30, 2017, we own a 74 percent limited partner interest in WPZ.

Description of Business

We are a Delaware corporation whose common stock is listed and traded on the New York Stock Exchange. Our operations are located principally in the United States. We have one reportable segment, Williams Partners. All remaining business activities are included in Other.

Williams Partners

Williams Partners consists of our consolidated master limited partnership, WPZ, and primarily includes gas pipeline and midstream businesses.

WPZ’s gas pipeline businesses primarily consist of two interstate natural gas pipelines, which are Transcontinental Gas Pipe Line Company, LLC (Transco) and Northwest Pipeline LLC (Northwest Pipeline), and several joint venture investments in interstate and intrastate natural gas pipeline systems, including a 50 percent equity-method investment in Gulfstream Natural Gas System, L.L.C. (Gulfstream), and a 41 percent interest in Constitution Pipeline Company, LLC (Constitution) (a consolidated entity), which is under development.

Notes (Continued)

WPZ’s midstream businesses primarily consist of (1) natural gas gathering, treating, compression, and processing; (2) natural gas liquid (NGL) fractionation, storage, and transportation; (3) crude oil production handling and transportation; and (4) olefins production (see Note 3 – Divestitures). The primary service areas are concentrated in major producing basins in Colorado, Texas, Oklahoma, Kansas, New Mexico, Wyoming, the Gulf of Mexico, Louisiana, Pennsylvania, West Virginia, New York, and Ohio which include the Barnett, Eagle Ford, Haynesville, Marcellus, Niobrara, and Utica shale plays as well as the Mid-Continent region.

The midstream businesses include equity-method investments in natural gas gathering and processing assets and NGL fractionation and transportation assets, including a 62 percent equity-method investment in Utica East Ohio Midstream, LLC (UEOM), a 69 percent equity-method investment in Laurel Mountain Midstream, LLC (Laurel Mountain), a 58 percent equity-method investment in Caiman Energy II, LLC (Caiman II), a 60 percent equity-method investment in Discovery Producer Services LLC (Discovery), a 50 percent equity-method investment in Overland Pass Pipeline, LLC (OPPL), and Appalachia Midstream Services, LLC, which owns equity-method investments with an approximate average 66 percent interest in multiple gathering systems in the Marcellus Shale (Appalachia Midstream Investments), as well as our previously owned 50 percent equity-method investment in the Delaware basin gas gathering system (DBJV) in the Mid-Continent region (see Note 4 – Investing Activities).

The midstream businesses also included our Canadian midstream operations, which were comprised of an oil sands offgas processing plant near Fort McMurray, Alberta, and an NGL/olefin fractionation facility at Redwater, Alberta. In September 2016, we completed the sale of our Canadian operations.

Other

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

Basis of Presentation

Consolidated master limited partnership

As of September 30, 2017, we own 74 percent of the interests in WPZ, a variable interest entity (VIE) (see Note 2 – Variable Interest Entities). WPZ units issued to us in connection with the Financial Repositioning, WPZ’s quarterly distribution of additional paid-in-kind Class B units to us, and other equity issuances by WPZ had the combined net impact of decreasing Noncontrolling interests in consolidated subsidiaries by $2.404 billion, and increasing Capital in excess of par value by $1.497 billion and Deferred income tax liabilities by $907 million in the Consolidated Balance Sheet.

WPZ is self-funding and maintains separate lines of bank credit and cash management accounts and also has a commercial paper program. (See Note 9 – Debt and Banking Arrangements.) Cash distributions from WPZ to us, including any associated with our previous IDRs, occur through the normal partnership distributions from WPZ to all partners.

Notes (Continued)

Significant risks and uncertainties

We may monetize assets that are not core to our strategy which could result in impairments of certain equity-method investments, property, plant, and equipment, and intangible assets. Such impairments could potentially be caused by indications of fair value implied through the monetization process or, in the case of asset dispositions that are part of a broader asset group, the impact of the loss of future estimated cash flows.

Accounting standards issued and adopted

Effective January 1, 2017, we adopted Accounting Standards Update (ASU) 2016-09, “Compensation - Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting” (ASU 2016-09). ASU 2016-09 changed the accounting for income taxes such that all excess tax benefits and all tax deficiencies are now recognized as a discrete item in the provision for income taxes in the financial reporting period they occur and the recognition of tax benefits is no longer delayed until the tax benefit is realized through a reduction in income taxes payable. These changes are applied prospectively beginning in 2017. We recorded a cumulative-effect adjustment as of January 1, 2017, decreasing Retained deficit by $37 million in the Consolidated Balance Sheet to recognize tax benefits that were not previously recognized. ASU 2016-09 requires entities to classify excess tax benefits as an operating activity on the statement of cash flows. We are applying this part of the guidance prospectively beginning in 2017; therefore, the cash flows for prior periods were not adjusted. In recognizing compensation cost from share-based payments, ASU 2016-09 allows entities to make an accounting policy election to either recognize forfeitures when they occur or estimate the number of forfeitures expected to occur. We are recognizing forfeitures when they occur and as a result of the change in our accounting policy, we increased our Retained deficit for an insignificant cumulative-effect adjustment as of January 1, 2017. ASU 2016-09 requires entities to classify as a financing activity, on the statement of cash flows, cash paid by an employer to a taxing authority when directly withholding shares from an employee’s award to satisfy the employer’s statutory tax withholding obligation. This guidance must be applied retrospectively and we have adjusted operating and financing activities on the Consolidated Statement of Cash Flows for prior periods.

Accounting standards issued but not yet adopted

In August 2017, the Financial Accounting Standards Board (FASB) issued ASU 2017-12 “Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities” (ASU 2017-12). ASU 2017-12 applies to entities that elect hedge accounting in accordance with Accounting Standards Codification (ASC) 815. The ASU affects both the designation and measurement guidance for hedging relationships and the presentation of hedging results. ASU 2017-12 is effective for interim and annual periods beginning after December 15, 2018. Early adoption is permitted. ASU 2017-12 will be applied using a modified retrospective approach for cash flow and net investment hedges existing at the date of adoption and prospectively for the presentation and disclosure guidance. We do not expect ASU 2017-12 to have a material impact on our consolidated financial statements.

In March 2017, the FASB issued ASU 2017-07 “Compensation - Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost” (ASU 2017-07). ASU 2017-07 requires employers to report the service cost component of net benefit cost in the same line item or items as other compensation costs arising from employee services. The other components of net benefit cost must be presented in the income statement separately from the service cost component and outside a subtotal of income from operations, if one is presented. Only the service cost component is now eligible for capitalization when applicable. ASU 2017-07 is effective beginning January 1, 2018. The presentation aspect of ASU 2017-07 must be applied retrospectively and the capitalization requirement prospectively. In light of the settlement charge we expect to recognize in the fourth quarter of 2017 related to a program to payout certain deferred vested pension benefits (see Note 8 – Employee Benefit Plans), we continue to evaluate the impact of ASU 2017-07 on our consolidated financial statements.

In January 2017, the FASB issued ASU 2017-04 “Intangibles - Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment” (ASU 2017-04). ASU 2017-04 modifies the concept of goodwill impairment to represent the amount by which a reporting unit’s carrying value exceeds its fair value, not to exceed the carrying amount of goodwill. Under ASU 2017-04, entities will no longer be required to determine the implied fair value of goodwill by assigning the fair value of a reporting unit to its individual assets and liabilities as if that reporting unit had been acquired in a business combination. ASU 2017-04 is effective for goodwill impairment testing for interim and annual periods

Notes (Continued)

beginning after December 15, 2019, and requires a prospective transition. Early adoption is permitted for interim and annual goodwill impairment tests performed after January 1, 2017, and we plan to adopt ASU 2017-04 in the fourth quarter of 2017. Our Williams Partners reportable segment has $47 million of goodwill included in Intangible assets - net of accumulated amortization in the Consolidated Balance Sheet.

In August 2016, the FASB issued ASU 2016-15 “Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments” (ASU 2016-15). ASU 2016-15 provides specific guidance on eight cash flow classification issues, including debt prepayment or debt extinguishment costs and distributions received from equity method investees, to reduce diversity in practice. ASU 2016-15 is effective for interim and annual periods beginning after December 15, 2017. Early adoption is permitted. ASU 2016-15 requires a retrospective transition. We do not expect ASU 2016-15 to have a material impact on our consolidated financial statements.

In June 2016, the FASB issued ASU 2016-13 “Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments” (ASU 2016-13). ASU 2016-13 changes the impairment model for most financial assets and certain other instruments. For trade and other receivables, held-to-maturity debt securities, loans, and other instruments, entities will be required to use a new forward-looking “expected loss” model that generally will result in the earlier recognition of allowances for losses. The guidance also requires increased disclosures. ASU 2016-13 is effective for interim and annual periods beginning after December 15, 2019. Early adoption is permitted. ASU 2016-13 requires varying transition methods for the different categories of amendments. Although we do not expect ASU 2016-13 to have a significant impact, it will impact our trade receivables as the related allowance for credit losses will be recognized earlier under the expected loss model.

In February 2016, the FASB issued ASU 2016-02 “Leases (Topic 842)” (ASU 2016-02). ASU 2016-02 establishes a comprehensive new lease accounting model. ASU 2016-02 clarifies the definition of a lease, requires a dual approach to lease classification similar to current lease classifications, and causes lessees to recognize leases on the balance sheet as a lease liability with a corresponding right-of-use asset. ASU 2016-02 is effective for interim and annual periods beginning after December 15, 2018. Early adoption is permitted. ASU 2016-02 requires a modified retrospective transition for capital or operating leases existing at or entered into after the beginning of the earliest comparative period presented in the financial statements. We are in the process of reviewing contracts to identify leases, as well as evaluating the applicability of ASU 2016-02 to contracts involving easements/rights-of-way.

In May 2014, the FASB issued ASU 2014-09 establishing ASC Topic 606, “Revenue from Contracts with Customers” (ASC 606). ASC 606 establishes a comprehensive new revenue recognition model designed to depict the transfer of goods or services to a customer in an amount that reflects the consideration the entity expects to be entitled to receive in exchange for those goods or services and requires significantly enhanced revenue disclosures. In August 2015, the FASB issued ASU 2015-14 “Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date” (ASU 2015-14). Per ASU 2015-14, the standard is effective for interim and annual reporting periods beginning after December 15, 2017. ASC 606 allows either full retrospective or modified retrospective transition and early adoption is permitted for annual periods beginning after December 15, 2016.

We continue to evaluate the impact ASC 606 may have on our financial statements. For each revenue contract type, we conducted a formal contract review process to evaluate the impact, if any, that ASC 606 may have. As a result of that process, we expect our revenues will increase associated with accounting for noncash consideration, which exists primarily in certain of our gas processing contracts where we receive commodities as full or partial consideration for services provided. We also expect the increase in revenues will be offset by a similar increase in costs when the commodities received are subsequently monetized. We continue to evaluate contracts with a significant financing component, which may exist in situations where the timing of the consideration we receive varies significantly from the timing of when we provide the service, as well as certain contracts with tiered pricing structures, minimum volume commitments, and prepayments for services. As such, we are unable to determine the potential impact upon the amount and timing of revenue recognition. We continue to develop and evaluate disclosures required under ASC 606, with a particular focus on the scope of contracts subject to disclosure of remaining performance obligations. Additionally, we have identified possible financial system and internal control changes necessary for adoption. We currently anticipate utilizing a modified retrospective transition upon the adoption of ASC 606 as of January 1, 2018.

Notes (Continued)

Termination of WPZ Merger Agreement

On May 12, 2015, we entered into an agreement for a unit-for-stock transaction whereby we would have acquired all of the publicly held outstanding common units of WPZ in exchange for shares of our common stock (WPZ Merger Agreement).

On September 28, 2015, we entered into a Termination Agreement and Release (Termination Agreement), terminating the WPZ Merger Agreement. Under the terms of the Termination Agreement, we were required to pay a $428 million termination fee to WPZ, at which time we owned approximately 60 percent, including the interests of the general partner and incentive distribution rights (IDRs). Such termination fee settled through a reduction of quarterly incentive distributions we were entitled to receive from WPZ (such reduction not to exceed $209 million per quarter). The distributions from WPZ in November 2015, February 2016, and May 2016 were reduced by $209 million, $209 million, and $10 million, respectively, related to this termination fee.

Note 2 – Variable Interest Entities

WPZ

We own a 74 percent interest in WPZ, a master limited partnership that is a VIE due to the limited partners’ lack of substantive voting rights, such as either participating rights or kick-out rights that can be exercised with a simple majority of the vote of the limited partners. We are the primary beneficiary of WPZ because we have the power, through our general partner interest, to direct the activities that most significantly impact WPZ’s economic performance.

Notes (Continued)

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



	September 30, 2017			December 31, 2016			Classification
	(Millions)
Assets (liabilities):
Cash and cash equivalents	$	1,165		$	145		Cash and cash equivalents
Trade accounts and other receivables – net	778			925			Trade accounts and other receivables
Inventories	144			138			Inventories
Other current assets	183			205			Other current assets and deferred charges
Investments	6,615			6,701			Investments
Property, plant, and equipment – net	27,411			28,021			Property, plant, and equipment – net
Intangible assets – net	8,872			9,662			Intangible assets – net of accumulated amortization
Regulatory assets, deferred charges, and other noncurrent assets	467			467			Regulatory assets, deferred charges, and other
Accounts payable	(751		)	(589		)	Accounts payable
Accrued liabilities including current asset retirement obligations	(818		)	(1,122		)	Accrued liabilities
Commercial paper	—			(93		)	Commercial paper
Long-term debt due within one year	(502		)	(785		)	Long-term debt due within one year
Long-term debt	(16,000		)	(17,685		)	Long-term debt
Deferred income tax liabilities	(14		)	(20		)	Deferred income tax liabilities
Noncurrent asset retirement obligations	(876		)	(798		)	Regulatory liabilities, deferred income, and other
Regulatory liabilities, deferred income, and other noncurrent liabilities	(1,986		)	(1,860		)	Regulatory liabilities, deferred income, and other

The assets and liabilities presented in the table above also include the consolidated interests of the following individual VIEs within WPZ:

Gulfstar One

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

Constitution

WPZ owns a 41 percent interest in Constitution, a subsidiary that, due to shipper fixed-payment commitments under its long-term firm transportation contracts, is a VIE. WPZ is the primary beneficiary because it has the power to direct the activities that most significantly impact Constitution’s economic performance. WPZ, as construction manager for Constitution, is responsible for constructing the proposed pipeline connecting its gathering system in Susquehanna County, Pennsylvania, to the Iroquois Gas Transmission and the Tennessee Gas Pipeline systems. The total remaining cost of the project is estimated to be approximately $691 million, which is expected to be funded with capital contributions from WPZ and the other equity partners on a proportional basis.

Notes (Continued)

In December 2014, Constitution received approval from the Federal Energy Regulatory Commission (FERC) 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 issue lies exclusively with the United States Court of Appeals for the District of Columbia Circuit. As to the denial itself, the court determined that NYSDEC’s action was not arbitrary or capricious. Constitution filed a petition for rehearing of the Second Circuit Court’s decision, but in October the court denied our petition.

We remain steadfastly committed to the project, and 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.

In light of the NYSDEC’s denial of the water quality certification and the actions taken to challenge the decision, the anticipated target in-service date is as early as the first half of 2019, which assumes the timely receipt of a Notice to Proceed from the FERC. An unfavorable resolution could result in the impairment of a significant portion of the capitalized project costs, which total $381 million on a consolidated basis at September 30, 2017, and are included within Property, plant, and equipment in the Consolidated Balance Sheet. Beginning in April 2016, we discontinued capitalization of development costs related to this project. It is also possible that we could incur certain supplier-related costs in the event of a prolonged delay or termination of the project.

Cardinal

WPZ owns a 66 percent interest in Cardinal Gas Services, L.L.C. (Cardinal), a subsidiary that provides gathering services for the Utica Shale region and is a VIE due to certain risks shared with customers. WPZ is the primary beneficiary because it has the power to direct the activities that most significantly impact Cardinal’s economic performance. Future expansion activity is expected to be funded with capital contributions from WPZ and the other equity partner on a proportional basis.

Jackalope

WPZ owns a 50 percent interest in Jackalope Gas Gathering Services, L.L.C. (Jackalope), a subsidiary that provides gathering and processing services for the Powder River basin and is a VIE due to certain risks shared with customers. WPZ is the primary beneficiary because it has the power to direct the activities that most significantly impact Jackalope’s economic performance. Future expansion activity is expected to be funded with capital contributions from WPZ and the other equity partner on a proportional basis.

Note 3 – Divestitures

On July 6, 2017, WPZ completed the sale of Williams Olefins, L.L.C., a wholly owned subsidiary which owned our 88.5 percent undivided interest in the Geismar, Louisiana, olefins plant (Geismar Interest) for total consideration of $2.084 billion in cash. We received a final working capital adjustment of $12 million in October 2017. Upon closing of the sale, WPZ entered into a long-term supply and transportation agreement with the purchaser to provide feedstock to the plant via its Bayou Ethane pipeline system. The assets and liabilities of the Geismar olefins plant were designated as held for sale within the Williams Partners segment during the first quarter of 2017. As a result of this sale, we recorded a gain of $1.095 billion in the third quarter of 2017. Following this sale, the cash proceeds were used to repay WPZ’s $850 million term loan. WPZ also plans to use these proceeds to fund a portion of the capital and investment expenditures that are a part of its growth portfolio.

Notes (Continued)

The following table presents the results of operations for the Geismar Interest, excluding the gain noted above.



	Three Months Ended September 30,				Nine Months Ended September 30,
	2017		2016		2017		2016
	(Millions)
Income (loss) before income taxes of the Geismar Interest	$	1	$	61	$	26	$	109
Income (loss) before income taxes of the Geismar Interest attributable to The Williams Companies, Inc.	1		36		19		65

In September 2016, we completed the sale of subsidiaries conducting Canadian operations, including subsidiaries of WPZ, (such subsidiaries, the Canada disposal group). Consideration received totaled $1.020 billion, net of $31 million of cash divested and subject to customary working capital adjustments. In connection with the sale, we waived $150 million of incentive distributions otherwise payable by WPZ to us in the fourth quarter of 2016 in recognition of certain affiliate contracts wherein WPZ’s Canadian operations provided services to certain of our other businesses. The proceeds were primarily used to reduce borrowings on credit facilities.

During the second quarter of 2016, we designated these operations as held for sale. As a result, we measured the fair value of the disposal group as of June 30, 2016, resulting in an impairment charge of $747 million, reflected in Impairment of certain assets in the Consolidated Statement of Operations. (See Note 11 - Fair Value Measurements.) Upon completion of the sale, we recorded an additional loss of $65 million for the three and nine months ended September 30, 2016, primarily reflecting revisions to the sales price and estimated contingent consideration and including a $15 million benefit related to transactions to hedge our foreign currency exchange risk on the Canadian proceeds, reflected in Other (income) expense – net within Costs and expenses in the Consolidated Statement of Operations. The total loss consists of a loss of $32 million and $33 million at Williams Partners and Williams Other segments, respectively.

The following table presents the results of operations for the Canada disposal group, excluding the impairment and loss noted above.



	Three Months Ended September 30,					Nine Months Ended September 30,
	2017		2016			2017		2016
	(Millions)
Income (loss) before income taxes of the Canadian disposal group	$	—	$	(9	)	$	—	$	(98	)
Income (loss) before income taxes of the Canadian disposal group attributable to The Williams Companies, Inc.	—		(16		)	—		(95		)

Note 4 – Investing Activities

Acquisition of Additional Interests in Appalachia Midstream Investments

During the first quarter of 2017, WPZ exchanged all of its 50 percent interest in DBJV for an increased interest in two natural gas gathering systems that are part of the Appalachia Midstream Investments and $155 million in cash. This transaction was recorded based on our estimate of the fair value of the interests received as we have more insight to this value as we operate the underlying assets. Following this exchange, we have an approximate average 66 percent interest in the Appalachia Midstream Investments. We continue to account for this investment under the equity-method due to the significant participatory rights of our partners such that we do not exercise control. WPZ also sold all of its interest in Ranch Westex JV LLC for $45 million. These transactions resulted in a total gain of $269 million reflected in Other investing income (loss) – net in the Consolidated Statement of Operations.

The fair value of the increased interests in the Appalachia Midstream Investments received as consideration was estimated to be $1.1 billion using an income approach based on expected cash flows and an appropriate discount rate

Notes (Continued)

(a Level 3 measurement within the fair value hierarchy). The determination of estimated future cash flows involved significant assumptions regarding gathering volumes, rates, and related capital spending. A 9.5 percent discount rate was utilized and reflected our estimate of the cost of capital as impacted by market conditions and risks associated with the underlying business.

Impairments

The nine months ended September 30, 2016, includes $59 million and $50 million of other-than-temporary impairment charges related to WPZ’s equity-method investments in DBJV and Laurel Mountain, respectively (see Note 11 – Fair Value Measurements and Guarantees).

Investing Income

The three and nine months ended September 30, 2016, includes a $27 million gain from the sale of an equity-method investment interest in a gathering system that was part of WPZ’s Appalachia Midstream Investments.

Interest Income and Other

The nine months ended September 30, 2016, includes $36 million of income associated with payments received on a receivable related to the sale of certain former Venezuela assets reflected in Other investing income (loss) – net in the Consolidated Statement of Operations.

Note 5 – Other Income and Expenses

The following table presents certain gains or losses reflected in Other (income) expense – net within Costs and expenses in our Consolidated Statement of Operations:



	Three Months Ended September 30,				Nine Months Ended September 30,
	2017		2016		2017			2016
	(Millions)
Williams Partners
Amortization of regulatory assets associated with asset retirement obligations	$	8	$	8	$	25		$	25
Accrual of regulatory liability related to overcollection of certain employee expenses	5		6		16			19
Project development costs related to Constitution (see Note 2)	4		11		12			19
Gains on contract settlements and terminations	—		—		(15		)	—
Gain on sale of Refinery Grade Propylene Splitter	—		—		(12		)	—
Net foreign currency exchange (gains) losses (1)	—		—		—			11
Loss on sale of Canadian operations (see Note 3)	4		32		—			32
Other
Gain on sale of unused pipe	—		—		—			(10		)
Loss on sale of Canadian operations (see Note 3)	—		33		1			33


(1)	Primarily relates to gains and losses incurred on foreign currency transactions and the remeasurement of U.S. dollar denominated current assets and liabilities within our former Canadian operations.

Notes (Continued)

Additional Items

Certain additional items included in the Consolidated Statement of Operations are as follows:


•	Service revenues were reduced by $15 million for the nine months ended September 30, 2016, related to potential refunds associated with a ruling received in certain rate case litigation within the Williams Partners segment.

•

Selling, general, and administrative expenses includes $5 million and $9 million for the three and nine months ended September 30, 2017, respectively, and $21 million and $40 million for the three and nine months ended September 30, 2016, respectively, of costs associated with our evaluation of strategic alternatives within the Other segment. Selling, general, and administrative expenses also includes $16 million and $61 million for the three and nine months ended September 30, 2016, respectively, of project development costs related to a proposed propane dehydrogenation facility in Alberta, Canada within the Other segment. Beginning in the first quarter of 2016, these costs did not qualify for capitalization.

•

Selling, general, and administrative expenses and Operating and maintenance expenses include $5 million and $18 million in severance and other related costs for the three and nine months ended September 30, 2017 for the Williams Partners segment. The nine months ended September 30, 2016 included $26 million in severance and other related costs associated with an approximate 10 percent reduction in workforce in the first quarter of 2016, primarily within the Williams Partners segment.

•

Other income (expense) – net below Operating income (loss) includes $17 million and $55 million for the three and nine months ended September 30, 2017, respectively, and $17 million and $46 million for the three and nine months ended September 30, 2016, respectively, for allowance for equity funds used during construction primarily within the Williams Partners segment. Other income (expense) – net below Operating income (loss) also includes $8 million and $44 million, for the three and nine months ended September 30, 2017, respectively, and $6 million and $16 million for the three and nine months ended September 30, 2016, respectively, of income associated with a regulatory asset related to deferred taxes on equity funds used during construction.

•

Other income (expense) – net below Operating income (loss) for the three months ended September 30, 2017 includes a net loss of $3 million associated with the July 3, 2017 early retirement of $1.4 billion of 4.875 percent senior unsecured notes that were due in 2023. The net loss for the July 3, 2017 early retirement within the Williams Partners segment reflects $51 million of unamortized premium, offset by $54 million in premiums paid. (See Note 9 – Debt and Banking Arrangements.)

•

Other income (expense) – net below Operating income (loss) for the nine months ended September 30, 2017, includes a net gain of $27 million associated with the early retirement of debt. The gain is comprised of a $30 million net gain associated with the February 23, 2017 early retirement of $750 million of 6.125 percent senior unsecured notes that were due in 2022, partially offset by a $3 million net loss associated with the July 3, 2017 early retirement discussed above. The net gain for the February 23, 2017 early retirement within Williams Partners reflects $53 million of unamortized premium, partially offset by $23 million in premiums paid. (See Note 9 – Debt and Banking Arrangements.)

Notes (Continued)

Note 6 – Provision (Benefit) for Income Taxes

The Provision (benefit) for income taxes includes:



	Three Months Ended September 30,						Nine Months Ended September 30,
	2017			2016			2017		2016
	(Millions)
Current:
Federal	$	7		$	—		$	10	$	—
State	9			1			17		1
Foreign	—			—			—		(1		)
	16			1			27		—
Deferred:
Federal	(11		)	8			63		(49		)
State	19			71			36		60
Foreign	—			(11		)	—		(85		)
	8			68			99		(74		)
Provision (benefit) for income taxes	$	24		$	69		$	126	$	(74	)

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

The effective income tax rate for the nine months ended September 30, 2017, is less than the federal statutory rate. This is primarily due to the impact of the allocation of income to nontaxable noncontrolling interests and releasing a $127 million valuation allowance on a deferred tax asset associated with a capital loss carryover, partially offset by the effect of state income taxes, including an $18 million provision related to an increase in the deferred state income tax rate (net of federal benefit). In 2016, we recorded a valuation allowance on a deferred tax asset associated with a capital loss that was incurred with the sale of our Canadian operations. The sale of the Geismar olefins facility in July 2017 (see Note 3 – Divestitures) generated capital gains sufficient to offset the capital loss carryover, thereby allowing us to reverse the valuation allowance in full.

The effective income tax rate for the three months ended September 30, 2016, is less than the federal statutory rate primarily due to the impact of the allocation of income to nontaxable noncontrolling interests and the effects of taxes on foreign operations, partially offset by the effect of state income taxes, including a $43 million provision related to an increase in the deferred state income tax rate (net of federal benefit).

The effective income tax rate for the nine months ended September 30, 2016, is less than the federal statutory rate primarily due to the effects of taxes on foreign operations, which includes the reversal of anticipatory foreign tax credits and a valuation allowance associated with impairments and losses on the sale of our Canadian operations (see Note 3 – Divestitures), and the effect of state income taxes, including a $43 million provision related to an increase in the deferred state income tax rate (net of federal benefit). These decreases are partially offset by the impact of the allocation of income to nontaxable noncontrolling interests. The foreign income tax provision includes the tax effect of the impairments associated with our Canadian disposition. (See Note 11 – Fair Value Measurements and Guarantees.)

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

Notes (Continued)

Note 7 – Earnings (Loss) Per Common Share



	Three Months Ended September 30,				Nine Months Ended September 30,
	2017		2016		2017		2016
	(Dollars in millions, except per-share amounts; shares in thousands)
Net income (loss) attributable to The Williams Companies, Inc. available to common stockholders for basic and diluted earnings (loss) per common share	$	33	$	61	$	487	$	(409	)
Basic weighted-average shares	826,779		750,754		825,925		750,579
Effect of dilutive securities:
Nonvested restricted stock units	1,889		568		1,567		—
Stock options	700		536		658		—
Diluted weighted-average shares	829,368		751,858		828,150		750,579
Earnings (loss) per common share:
Basic	$	.04	$	.08	$	.59	$	(.55	)
Diluted	$	.04	$	.08	$	.59	$	(.55	)

Note 8 – Employee Benefit Plans

Net periodic benefit cost (credit) is as follows:



	Pension Benefits
	Three Months Ended September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016
	(Millions)
Components of net periodic benefit cost (credit):
Service cost	$	13		$	13		$	38		$	40
Interest cost	15			16			44			47
Expected return on plan assets	(21		)	(22		)	(62		)	(64		)
Amortization of net actuarial loss	6			8			20			23
Net actuarial loss from settlements	—			—			—			1
Net periodic benefit cost (credit)	$	13		$	15		$	40		$	47



	Other Postretirement Benefits
	Three Months Ended September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016
	(Millions)
Components of net periodic benefit cost (credit):
Service cost	$	—		$	—		$	1		$	1
Interest cost	2			2			6			6
Expected return on plan assets	(3		)	(3		)	(9		)	(9		)
Amortization of prior service credit	(3		)	(3		)	(10		)	(11		)
Reclassification to regulatory liability	1			1			3			3
Net periodic benefit cost (credit)	$	(3	)	$	(3	)	$	(9	)	$	(10	)

Notes (Continued)

Amortization of prior service credit and net actuarial loss included in net periodic benefit cost (credit) for our other postretirement benefit plans associated with Transco and Northwest Pipeline are recorded to regulatory assets/liabilities instead of other comprehensive income (loss). The amounts of amortization of prior service credit recognized in regulatory liabilities were $2 million for the three months ended September 30, 2017 and 2016, and $6 million and $7 million for the nine months ended September 30, 2017 and 2016, respectively.

During the nine months ended September 30, 2017, we contributed $83 million to our pension plans and $4 million to our other postretirement benefit plans. We presently anticipate making additional contributions of approximately $1 million to our pension plans and approximately $1 million to our other postretirement benefit plans in the remainder of 2017.

In September 2017, we initiated a program to pay out certain deferred vested pension benefits to reduce investment risk, cash funding volatility, and administrative costs. Eligible participants had until October 31, 2017, to make elections. We expect to make the lump-sum payments and commence the annuity payments in December 2017, and intend to fund the payments from existing assets in our pension plans. As a result of these payouts and based on current assumptions, we expect to record a pre-tax, non-cash settlement charge in the fourth quarter of 2017 that we estimate will be between $70 million and $100 million. The ultimate amount of the charge will largely depend upon the actual level of participation as well as the actuarial assumptions used to measure the pension plans’ assets and obligations, including the discount rates.

Note 9 – Debt and Banking Arrangements

Long-Term Debt

Issuances and retirements

On July 6, 2017, WPZ repaid its $850 million variable interest rate term loan that was due December 2018 using proceeds from the sale of its Geismar Interest.

On June 5, 2017, WPZ issued $1.45 billion of 3.75 percent senior unsecured notes due 2027. WPZ used the proceeds for general partnership purposes, primarily the July 3, 2017 repayment of $1.4 billion of 4.875 percent senior unsecured notes that were due in 2023.

On April 3, 2017, Northwest Pipeline issued $250 million of 4.0 percent senior unsecured notes due 2027 to investors in a private debt placement. Northwest Pipeline used the net proceeds to retire $185 million of 5.95 percent senior unsecured notes that matured on April 15, 2017, and for general corporate purposes. As part of the issuance, Northwest Pipeline entered into a registration rights agreement with the initial purchasers of the unsecured notes. Northwest Pipeline is obligated to file and consummate a registration statement for an offer to exchange the notes for a new issue of substantially identical notes registered under the Securities Act of 1933, as amended, within 365 days from closing and to use commercially reasonable efforts to complete the exchange offer. Northwest Pipeline is required to provide a shelf registration statement to cover resales of the notes under certain circumstances. If Northwest Pipeline fails to fulfill these obligations, additional interest will accrue on the affected securities. The rate of additional interest will be 0.25 percent per annum on the principal amount of the affected securities for the first 90-day period immediately following the occurrence of a registration default, increasing by an additional 0.25 percent per annum with respect to each subsequent 90-day period thereafter, up to a maximum amount for all such registration defaults of 0.5 percent annually. Following the cure of any registration defaults, the accrual of additional interest will cease.

On February 23, 2017, using proceeds received from the Financial Repositioning (see Note 1 – General, Description of Business, and Basis of Presentation), WPZ early retired $750 million of 6.125 percent senior unsecured notes that were due in 2022.

WPZ retired $600 million of 7.25 percent senior unsecured notes that matured on February 1, 2017.

Notes (Continued)

Other financing obligation

During the construction of Transco’s Dalton expansion project, WPZ received funding from a partner for its proportionate share of construction costs related to its undivided ownership interest in the project. Amounts received were recorded within noncurrent liabilities. Upon placing the project in service during the third quarter of 2017, WPZ began leasing this partner’s undivided interest in the lateral, including the associated pipeline capacity, and reclassified approximately $237 million of funding previously received from its partner from noncurrent liabilities to debt to reflect the financing obligation payable to its partner over an expected term of 35 years.

Commercial Paper Program

As of September 30, 2017, no Commercial paper was outstanding under WPZ’s $3 billion commercial paper program.

Credit Facilities



	September 30, 2017
	Stated Capacity		Outstanding
	(Millions)
WMB
Long-term credit facility	$	1,500	$	400
Letters of credit under certain bilateral bank agreements			13
WPZ
Long-term credit facility (1)	3,500		—
Letters of credit under certain bilateral bank agreements			1


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

Note 10 – Stockholders’ Equity

In January 2017, we issued 65 million shares of common stock in a public offering at a price of $29.00 per share. In February 2017, we issued 9.75 million shares of common stock pursuant to the full exercise of the underwriter’s option to purchase additional shares. The net proceeds of approximately $2.1 billion were used to purchase newly issued common units in WPZ as part of our Financial Repositioning. (See Note 1 – General, Description of Business, and Basis of Presentation.)

AOCI

The following table presents the changes in Accumulated other comprehensive income (loss) (AOCI) by component, net of income taxes:



	Cash Flow Hedges			Foreign Currency Translation			Pension and Other Post Retirement Benefits			Total
	(Millions)
Balance at December 31, 2016	$	—		$	(2	)	$	(337	)	$	(339	)
Other comprehensive income (loss) before reclassifications	(3		)	—			—			(3		)
Amounts reclassified from accumulated other comprehensive income (loss)	—			—			11			11
Other comprehensive income (loss)	(3		)	—			11			8
Balance at September 30, 2017	$	(3	)	$	(2	)	$	(326	)	$	(331	)

Notes (Continued)

Reclassifications out of AOCI are presented in the following table by component for the nine months ended September 30, 2017:



Component	Reclassifications			Classification
	(Millions)
Cash flow hedges:
Energy commodity contracts	$	(1	)	Product sales

Pension and other postretirement benefits:
Amortization of prior service cost (credit) included in net periodic benefit cost	(4		)	Note 8 – Employee Benefit Plans
Amortization of actuarial (gain) loss included in net periodic benefit cost	20			Note 8 – Employee Benefit Plans

Total before tax	15
Income tax benefit	(4		)	Provision (benefit) for income taxes
Reclassifications during the period	$	11

Notes (Continued)

Note 11 – Fair Value Measurements and Guarantees

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



							Fair Value Measurements Using
	Carrying Amount			Fair Value			Quoted Prices In Active Markets for Identical Assets (Level 1)			Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
	(Millions)
Assets (liabilities) at September 30, 2017:
Measured on a recurring basis:
ARO Trust investments	$	127		$	127		$	127		$	—		$	—
Energy derivatives assets not designated as hedging instruments	2			2			1			—			1
Energy derivatives liabilities designated as hedging instruments	(6		)	(6		)	(5		)	(1		)	—
Energy derivatives liabilities not designated as hedging instruments	(5		)	(5		)	(2		)	—			(3		)
Additional disclosures:
Other receivables	12			12			12			—			—
Long-term debt, including current portion	(21,069		)	(22,979		)	—			(22,979		)	—
Guarantees	(44		)	(30		)	—			(14		)	(16		)

Assets (liabilities) at December 31, 2016:
Measured on a recurring basis:
ARO Trust investments	$	96		$	96		$	96		$	—		$	—
Energy derivatives assets designated as hedging instruments	2			2			—			2			—
Energy derivatives assets not designated as hedging instruments	1			1			—			—			1
Energy derivatives liabilities not designated as hedging instruments	(6		)	(6		)	—			—			(6		)
Additional disclosures:
Other receivables	15			15			15			—			—
Long-term debt, including current portion	(23,409		)	(24,090		)	—			(24,090		)	—
Guarantees	(44		)	(30		)	—			(14		)	(16		)

Fair Value Methods

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

Assets and liabilities measured at fair value on a recurring basis

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

Notes (Continued)

Energy derivatives: Energy derivatives include commodity-based exchange-traded contracts and over-the-counter contracts, which consist of physical forwards, futures, and swaps that are measured at fair value on a recurring basis. The fair value amounts are presented on a gross basis and do not reflect the netting of asset and liability positions permitted under the terms of our master netting arrangements. Further, the amounts do not include cash held on deposit in margin accounts that we have received or remitted to collateralize certain derivative positions. Energy derivatives assets are reported in Other current assets and deferred charges and Regulatory assets, deferred charges, and other in the Consolidated Balance Sheet. Energy derivatives liabilities are reported in Accrued liabilities and Regulatory liabilities, deferred income, and other in the Consolidated Balance Sheet.

Reclassifications of fair value between Level 1, Level 2, and Level 3 of the fair value hierarchy, if applicable, are made at the end of each quarter. No transfers between Level 1 and Level 2 occurred during the nine months ended September 30, 2017 or 2016.

Additional fair value disclosures

Other receivables: Other receivables consist of margin deposits, which are reported in Other current assets and deferred charges in the Consolidated Balance Sheet. The disclosed fair value of our margin deposits is considered to approximate the carrying value generally due to the short-term nature of these items.

Long-term debt, including current portion: The disclosed fair value of our long-term debt is determined primarily by a market approach using broker quoted indicative period-end bond prices. The quoted prices are based on observable transactions in less active markets for our debt or similar instruments. The fair value of the financing obligation associated with our Dalton lateral, which is included within long-term debt, was determined using an income approach (see Note 9 - Debt and Banking Arrangements).

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

To estimate the disclosed fair value of the WilTel guarantee, an estimated default rate is applied to the sum of the future contractual lease payments using an income approach. The estimated default rate is determined by obtaining the average cumulative issuer-weighted corporate default rate based on the credit rating of WilTel’s current owner and the term of the underlying obligation. The default rate is published by Moody’s Investors Service. The carrying value of the WilTel guarantee is reported in Accrued liabilities in the Consolidated Balance Sheet. The maximum potential undiscounted exposure is approximately $31 million at September 30, 2017. Our exposure declines systematically through the remaining term of WilTel’s obligation.

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

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

Notes (Continued)

Nonrecurring fair value measurements

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



						Impairments
						Nine Months Ended September 30,
	Classification	Segment	Date of Measurement	Fair Value		2017		2016
				(Millions)
Certain gathering operations (1)	Property, plant, and equipment - net and Intangible assets - net of accumulated amortization	Williams Partners	September 30, 2017	$	439	$	1,019
Certain gathering operations (2)	Property, plant, and equipment - net and Intangible assets - net of accumulated amortization	Williams Partners	September 30, 2017	21		115
Certain NGL pipeline (3)	Property, plant, and equipment – net	Other	September 30, 2017	32		68
Certain olefins pipeline project (4)	Property, plant, and equipment – net	Other	June 30, 2017	18		23
Canadian operations (5)	Assets held for sale	Williams Partners	June 30, 2016	924				$	341
Canadian operations (5)	Assets held for sale	Other	June 30, 2016	206				406
Certain gathering operations (6)	Property, plant, and equipment – net	Williams Partners	June 30, 2016	18				48
Level 3 fair value measurements of certain assets						1,225		795
Other impairments and write-downs (7)						11		16
Impairment of certain assets						$	1,236	$	811

Equity-method investments (8)	Investments	Williams Partners	March 31, 2016	$	1,294			$	109
Other equity-method investment	Investments	Williams Partners	March 31, 2016	—				3
Impairment of equity-method investments								$	112

_______________

(1)

Relates to certain gathering operations in the Mid-Continent region. During the third quarter of 2017, we received solicitations and engaged in negotiations for the sale of certain of these assets which led to our impairment evaluation. The estimated fair value was determined using an income approach and incorporated market inputs based on ongoing negotiations for a potential sale of a portion of the underlying assets. For the income approach, we utilized a discount rate of 10.2 percent, reflecting an estimate of our cost of capital and risks associated with the underlying assets.


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

Notes (Continued)

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


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


(4)	Relates primarily to project development costs associated with an olefins pipeline project in the Gulf Coast region, the likelihood of completion of which is now considered remote. The estimated fair value of the remaining pipe and equipment considered a market approach based on our analysis of observable inputs in the principal market, as well as an estimate of replacement cost.

(5)

Relates to our Canadian operations. We designated these operations as held for sale as of June 30, 2016. As a result, we measured the fair value of the disposal group, resulting in an impairment charge. The estimated fair value was determined by a market approach based primarily on inputs received in the marketing process and reflected our estimate of the potential assumed proceeds. We disposed of our Canadian operations through a sale during the third quarter of 2016.


(6)	Relates to certain gathering assets within the Mid-Continent region. The estimated fair value was determined by a market approach based on our analysis of observable inputs in the principal market.


(7)	Reflects multiple individually insignificant impairments and write-downs of other certain assets that may no longer be in use or are surplus in nature for which the fair value was determined to be lower than the carrying value.

(8)

Relates to Williams Partners’ previously owned interest in DBJV and current equity-method investment in Laurel Mountain. Our carrying values in these equity-method investments had been written down to fair value at December 31, 2015. Our first-quarter 2016 analysis reflected higher discount rates for both of these equity-method investments, along with lower natural gas prices for Laurel Mountain. We estimated the fair value of these equity-method investments using an income approach based on expected future cash flows and appropriate discount rates. The determination of estimated future cash flows involved significant assumptions regarding gathering volumes and related capital spending. Discount rates utilized ranged from 13.0 percent to 13.3 percent and reflected increases in our estimated cost of capital, revised estimates of expected future cash flows, and risks associated with the underlying businesses.

Note 12 – Contingent Liabilities

Reporting of Natural Gas-Related Information to Trade Publications

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

In the individual action, filed by Farmland Industries Inc. (Farmland), the court issued an order on May 24, 2016, granting one of our co-defendant’s motion for summary judgment as to Farmland’s claims. On January 5, 2017, the court extended such ruling to us, entering final judgment in our favor. Farmland has appealed.

In the putative class actions, on March 30, 2017, the court issued an order denying the plaintiffs’ motions for class certification. On June 13, 2017, the United States Court of Appeals for the Ninth Circuit granted the plaintiffs’ petition for permission to appeal the order, and the appeal is now pending.

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

Notes (Continued)

In connection with this indemnification, we have an accrued liability balance associated with this matter, and as a result, have exposure to future developments in this matter.

Geismar Incident

On June 13, 2013, an explosion and fire occurred at our formerly owned Geismar olefins plant and rendered the facility temporarily inoperable (Geismar Incident). As a result, there were two fatalities and numerous individuals (including employees and contractors) reported injuries. We are addressing the following contingent liabilities in connection with the Geismar Incident.

On October 21, 2013, the U.S. Environmental Protection Agency (EPA) issued an Inspection Report pursuant to the Clean Air Act’s Risk Management Program following its inspection of the facility on June 24 through June 28, 2013. The report notes the EPA’s preliminary determinations about the facility’s documentation regarding process safety, process hazard analysis, as well as operating procedures, employee training, and other matters. On June 16, 2014, we received a request for information related to the Geismar Incident from the EPA under Section 114 of the Clean Air Act to which we responded on August 13, 2014. The EPA could issue penalties pertaining to final determinations. Multiple lawsuits, including class actions for alleged offsite impacts, property damage, customer claims, and personal injury, have been filed against us. The first two trials, for nine plaintiffs claiming personal injury, were held in Louisiana state court in Iberville Parish, Louisiana in September and November 2016. The juries returned adverse verdicts against us, our subsidiary Williams Olefins, LLC, and other defendants. To date, we have settled those cases as well as settled or agreed in principle to settle numerous other personal injury claims, and such aggregate amount greater than our $2 million retention (deductible) value has been or will be recovered from our insurers. We believe these settlements to date substantially resolve any material exposure to such claims arising from the Geismar Incident. We believe that any additional losses arising from our alleged liability will be immaterial to our expected future annual results of operations, liquidity, and financial position and will be substantially covered by our general liability insurance policy, which has an aggregate limit of $610 million applicable to this event.

Alaska Refinery Contamination Litigation

In 2010, James West filed a class action lawsuit in state court in Fairbanks, Alaska on behalf of individual property owners whose water contained sulfolane contamination allegedly emanating from the Flint Hills Oil Refinery in North Pole, Alaska. The suit named our subsidiary, Williams Alaska Petroleum Inc. (WAPI), and Flint Hills Resources Alaska, LLC (FHRA), a subsidiary of Koch Industries, Inc., as defendants. We owned and operated the refinery until 2004 when we sold it to FHRA. We and FHRA made claims under the pollution liability insurance policy issued in connection with the sale of the North Pole refinery to FHRA. We and FHRA also filed claims against each other seeking, among other things, contractual indemnification alleging that the other party caused the sulfolane contamination. In 2011, we and FHRA settled the James West claim. Certain claims by FHRA against us were resolved by the Alaska Supreme Court in our favor. FHRA’s claims against us for contractual indemnification and statutory claims for damages related to off-site sulfolane remain pending.

On March 6, 2014, the State of Alaska filed suit against FHRA, WAPI, and us in state court in Fairbanks seeking injunctive relief and damages in connection with sulfolane contamination of the water supply near the Flint Hills Oil Refinery in North Pole, Alaska. On May 5, 2014, FHRA filed cross-claims against us in the State of Alaska suit for contractual indemnification and statutory claims for damages related to off-site sulfolane.

On November 26, 2014, the City of North Pole (North Pole) filed suit in Alaska state court in Fairbanks against FHRA, WAPI, and us alleging nuisance and violations of municipal ordinances and state statutes based upon the same alleged sulfolane contamination of the water supply. North Pole claims an unspecified amount of past and future damages as well as punitive damages against WAPI. FHRA filed cross-claims against us.

In October of 2015, the court consolidated the State of Alaska and North Pole cases. Both we and WAPI asserted counterclaims against both the State of Alaska and North Pole, and cross-claims against FHRA. The underlying factual basis and claims in the consolidated State of Alaska and North Pole action are similar to and may duplicate exposure in the James West case. As such, on February 9, 2017, the remaining claims in the James West case were consolidated into the State of Alaska and North Pole action. A trial encompassing all three consolidated cases was originally scheduled

Notes (Continued)

to commence in May 2017, but has been continued. A new trial date has not been scheduled. Due to the ongoing assessment of the level and extent of sulfolane contamination, the lack of an articulated cleanup level for sulfolane, and the lack of a concrete remedial proposal and cost estimate, we are unable to estimate a range of exposure to the State of Alaska or North Pole at this time. We currently estimate that our reasonably possible loss exposure to FHRA could range from an insignificant amount up to $32 million, although uncertainties inherent in the litigation process, expert evaluations, and jury dynamics might cause our exposure to exceed that amount.

Independent of the litigation matter described in the preceding paragraphs, in 2013, the Alaska Department of Environmental Conservation indicated that it views FHRA and us as responsible parties, and that it intended to enter a compliance order to address the environmental remediation of sulfolane and other possible contaminants including cleanup work outside the refinery’s boundaries. Due to the ongoing assessment of the level and extent of sulfolane contamination and the ultimate cost of remediation and division of costs among the potentially responsible parties, 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 and Oklahoma based on allegations that we improperly participated with that major customer in causing the alleged royalty underpayments. The Oklahoma case was transferred to Texas and, on October 2, 2017, voluntarily dismissed by the plaintiff. We believe that the claims asserted are subject to indemnity obligations owed to us by that major customer. Due to the preliminary status of the cases, we are unable to estimate a range of potential loss at this time.

Shareholder Litigation

Between October 2015 and December 2015, purported shareholders of us filed six putative class action lawsuits in the Delaware Court of Chancery that were consolidated into a single suit on January 13, 2016. This consolidated putative class action lawsuit relates to our terminated merger with Energy Transfer Equity, L.P. (Energy Transfer). The complaint asserts various claims against the individual members of our Board of Directors, including that they breached their fiduciary duties by agreeing to sell us through an allegedly unfair process and for an allegedly unfair price and by allegedly failing to disclose allegedly material information about the merger. The complaint seeks, among other things, an injunction against the merger and an award of costs and attorneys’ fees. On March 22, 2016, the court granted the parties’ proposed order in the consolidated action to stay the proceedings pending the close of the transaction with Energy Transfer. The plaintiffs have not filed an amended complaint. On July 19, 2017, the court dismissed the action with prejudice as to plaintiffs and without prejudice as to all other shareholders of us.

A purported shareholder filed a separate class action lawsuit in the Delaware Court of Chancery on January 15, 2016. The putative class action complaint alleged that the individual members of our Board of Directors breached their fiduciary duties by, among other things, agreeing to the WPZ Merger Agreement, which purportedly reduced the merger consideration to have been received in the subsequently proposed but now terminated merger with Energy Transfer. The plaintiff filed a motion to voluntarily dismiss, which the court granted on January 13, 2017. On September 2, 2016, the same purported shareholder filed a derivative action claiming that the members of our Board of Directors breached their fiduciary duties by executing the WPZ Merger Agreement as a defensive measure against Energy Transfer. On September 28, 2016, we requested the court dismiss this action, and on May 15, 2017, the court dismissed the action. On June 6, 2017, the plaintiff filed a notice of appeal.

On March 7, 2016, a purported unitholder of WPZ filed a putative class action on behalf of certain purchasers of WPZ units in U.S. District Court in Oklahoma. The action names as defendants us, WPZ, Williams Partners GP LLC, Alan S. Armstrong, and former Chief Financial Officer Donald R. Chappel and alleges violations of certain federal securities laws for failure to disclose Energy Transfer’s intention to pursue a purchase of us conditioned on us not closing the WPZ Merger Agreement when announcing the WPZ Merger Agreement. The complaint seeks, among other things, damages and an award of costs and attorneys’ fees. The plaintiff filed an amended complaint on August 31, 2016. On October 17, 2016, we requested the court dismiss the action, and on March 8, 2017, the court dismissed the complaint with prejudice. On April 7, 2017, the plaintiff filed a notice of appeal.

Notes (Continued)

We cannot reasonably estimate a range of potential loss related to these matters at this time.

Litigation Against Energy Transfer and Related Parties

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

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

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

On September 16, 2016, we filed an amended complaint with the Court of Chancery seeking damages for breaches of the Merger Agreement by defendants. On September 23, 2016, Energy Transfer filed a second amended and supplemental affirmative defenses and verified counterclaim with the Court of Chancery seeking, among other things, payment of the $1.48 billion termination fee due to our alleged breaches of the Merger Agreement. We filed a motion to dismiss Energy Transfer’s counterclaims, which was fully briefed on November 14, 2016, and oral argument occurred on November 30, 2016.

Environmental Matters

We are a participant in certain environmental activities in various stages including assessment studies, cleanup operations, and remedial processes at certain sites, some of which we currently do not own. We are monitoring these sites in a coordinated effort with other potentially responsible parties, the EPA, and other governmental authorities. We are jointly and severally liable along with unrelated third parties in some of these activities and solely responsible in others. Certain of our subsidiaries have been identified as potentially responsible parties at various Superfund and state waste disposal sites. In addition, these subsidiaries have incurred, or are alleged to have incurred, various other hazardous materials removal or remediation obligations under environmental laws. As of September 30, 2017, we have accrued liabilities totaling $40 million for these matters, as discussed below. Our accrual reflects the most likely costs of cleanup, which are generally based on completed assessment studies, preliminary results of studies, or our experience with other similar cleanup operations. Certain assessment studies are still in process for which the ultimate outcome may yield significantly different estimates of most likely costs. Any incremental amount in excess of amounts currently accrued cannot be reasonably estimated at this time due to uncertainty about the actual number of contaminated sites ultimately

Notes (Continued)

identified, the actual amount and extent of contamination discovered, and the final cleanup standards mandated by the EPA and other governmental authorities.

The EPA and various state regulatory agencies routinely promulgate and propose new rules, and issue updated guidance to existing rules. More recent rules and rulemakings include, but are not limited to, rules for reciprocating internal combustion engine maximum achievable control technology, air quality standards for one hour nitrogen dioxide emissions, and volatile organic compound and methane new source performance standards impacting design and operation of storage vessels, pressure valves, and compressors. On October 1, 2015, the EPA issued its rule regarding National Ambient Air Quality Standards for ground-level ozone, setting a standard of 70 parts per billion. We are monitoring the rule’s implementation and evaluating potential impacts to our operations. For these and other new regulations, we are unable to estimate the costs of asset additions or modifications necessary to comply due to uncertainty created by the various legal challenges to these regulations and the need for further specific regulatory guidance.

Continuing operations

Our interstate gas pipelines are involved in remediation activities related to certain facilities and locations for polychlorinated biphenyls, mercury, and other hazardous substances. These activities have involved the EPA and various state environmental authorities, resulting in our identification as a potentially responsible party at various Superfund waste sites. At September 30, 2017, we have accrued liabilities of $8 million for these costs. We expect that these costs will be recoverable through rates.

We also accrue environmental remediation costs for natural gas underground storage facilities, primarily related to soil and groundwater contamination. At September 30, 2017, we have accrued liabilities totaling $8 million for these costs.

Former operations, including operations classified as discontinued

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


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


•	Former petroleum products and natural gas pipelines;


•	Former petroleum refining facilities;


•	Former exploration and production and mining operations;


•	Former electricity and natural gas marketing and trading operations.

At September 30, 2017, we have accrued environmental liabilities of $24 million related to these matters.

Other Divestiture Indemnifications

Pursuant to various purchase and sale agreements relating to divested businesses and assets, we have indemnified certain purchasers against liabilities that they may incur with respect to the businesses and assets acquired from us. The indemnities provided to the purchasers are customary in sale transactions and are contingent upon the purchasers incurring liabilities that are not otherwise recoverable from third parties. The indemnities generally relate to breach of warranties, tax, historic litigation, personal injury, property damage, environmental matters, right of way, and other representations that we have provided.

At September 30, 2017, other than as previously disclosed, we are not aware of any material claims against us involving the indemnities; thus, we do not expect any of the indemnities provided pursuant to the sales agreements to

Notes (Continued)

have a material impact on our future financial position. Any claim for indemnity brought against us in the future may have a material adverse effect on our results of operations in the period in which the claim is made.

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

Summary

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

Note 13 – Segment Disclosures

We have one reportable segment, Williams Partners. All remaining business activities are included in Other. (See Note 1 – General, Description of Business, and Basis of Presentation.)

Our segment presentation of Williams Partners, which includes our consolidated master limited partnership, is reflective of the parent-level focus by our chief operating decision-maker, considering the resource allocation and governance provisions associated with the master limited partnership structure. This partnership maintains capital and cash management structures that are separate from ours. It is self-funding and maintains its own lines of bank credit and cash management accounts. These factors serve to differentiate the management of this entity as a whole.

Performance Measurement

We evaluate segment operating performance based upon Modified EBITDA (earnings before interest, taxes, depreciation, and amortization). This measure represents the basis of our internal financial reporting and is the primary performance measure used by our chief operating decision maker in measuring performance and allocating resources among our reportable segments.

We define Modified EBITDA as follows:

•Net income (loss) before:

◦Income (loss) from discontinued operations;

◦Provision (benefit) for income taxes;

◦Interest incurred, net of interest capitalized;

◦Equity earnings (losses);

◦Gain on remeasurement of equity-method investment;

◦Impairment of equity-method investments;

◦Other investing income (loss) – net;

◦Impairment of goodwill;

◦Depreciation and amortization expenses;

◦Accretion expense associated with asset retirement obligations for nonregulated operations.


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

Notes (Continued)

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



	Williams Partners		Other		Eliminations			Total
	(Millions)
Three Months Ended September 30, 2017
Segment revenues:
Service revenues
External	$	1,304	$	6	$	—		$	1,310
Internal	—		2		(2		)	—
Total service revenues	1,304		8		(2		)	1,310
Product sales
External	581		—		—			581
Internal	—		—		—			—
Total product sales	581		—		—			581
Total revenues	$	1,885	$	8	$	(2	)	$	1,891

Three Months Ended September 30, 2016
Segment revenues:
Service revenues
External	$	1,241	$	6	$	—		$	1,247
Internal	11		3		(14		)	—
Total service revenues	1,252		9		(14		)	1,247
Product sales
External	655		3		—			658
Internal	—		6		(6		)	—
Total product sales	655		9		(6		)	658
Total revenues	$	1,907	$	18	$	(20	)	$	1,905

Nine Months Ended September 30, 2017
Segment revenues:
Service revenues
External	$	3,836	$	17	$	—		$	3,853
Internal	1		8		(9		)	—
Total service revenues	3,837		25		(9		)	3,853
Product sales
External	1,950		—		—			1,950
Internal	—		—		—			—
Total product sales	1,950		—		—			1,950
Total revenues	$	5,787	$	25	$	(9	)	$	5,803

Nine Months Ended September 30, 2016
Segment revenues:
Service revenues
External	$	3,656	$	22	$	—		$	3,678
Internal	32		17		(49		)	—
Total service revenues	3,688		39		(49		)	3,678
Product sales
External	1,613		10		—			1,623
Internal	—		16		(16		)	—
Total product sales	1,613		26		(16		)	1,623
Total revenues	$	5,301	$	65	$	(65	)	$	5,301

September 30, 2017
Total assets	$	45,635	$	570	$	(85	)	$	46,120
December 31, 2016
Total assets	$	46,265	$	685	$	(115	)	$	46,835

Notes (Continued)

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



	Three Months Ended September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016
	(Millions)
Modified EBITDA by segment:
Williams Partners	$	1,000		$	1,070		$	3,208		$	2,629
Other	(61		)	(67		)	(60		)	(534		)
	939			1,003			3,148			2,095
Accretion expense associated with asset retirement obligations for nonregulated operations	(7		)	(9		)	(23		)	(24		)
Depreciation and amortization expenses	(433		)	(435		)	(1,308		)	(1,326		)
Equity earnings (losses)	115			104			347			302
Impairment of equity-method investments	—			—			—			(112		)
Other investing income (loss) – net	4			28			278			64
Proportional Modified EBITDA of equity-method investments	(202		)	(194		)	(611		)	(574		)
Interest expense	(267		)	(297		)	(818		)	(886		)
(Provision) benefit for income taxes	(24		)	(69		)	(126		)	74
Net income (loss)	$	125		$	131		$	887		$	(387	)

Item 2

Management’s Discussion and Analysis of

Financial Condition and Results of Operations

General

We are an energy infrastructure company focused on connecting North America’s significant hydrocarbon resource plays to growing markets for natural gas and NGLs. Our operations are located principally in the United States. We have one reportable segment, Williams Partners. All remaining business activities are included in Other.

Williams Partners

Williams Partners consists of our consolidated master limited partnership, WPZ, which includes gas pipeline and midstream businesses. The gas pipeline businesses include interstate natural gas pipelines and pipeline joint project investments; and the midstream businesses provide natural gas gathering, treating, and processing services; NGL production, fractionation, storage, marketing, and transportation; deepwater production handling and crude oil transportation services; and is comprised of several wholly owned and partially owned subsidiaries and joint project investments. As of September 30, 2017, we own 74 percent of the interests in WPZ.

Williams Partners’ gas pipeline businesses consist primarily of Transco and Northwest Pipeline. The gas pipeline business also holds interests in joint venture interstate and intrastate natural gas pipeline systems including a 50 percent equity-method investment in Gulfstream and a 41 percent interest in Constitution (a consolidated entity), which is under development. As of December 31, 2016, Transco and Northwest Pipeline owned and operated a combined total of approximately 13,600 miles of pipelines with a total annual throughput of approximately 4,230 Tbtu of natural gas and peak-day delivery capacity of approximately 15.5 MMdth of natural gas.

Williams Partners’ midstream businesses primarily consist of (1) natural gas gathering, treating, compression, and processing; (2) NGL fractionation, storage, and transportation; (3) crude oil production handling and transportation; and (4) olefins production. (See Note 3 – Divestitures of Notes to Consolidated Financial Statements.) The primary service areas are concentrated in major producing basins in Colorado, Texas, Oklahoma, Kansas, New Mexico, Wyoming, the Gulf of Mexico, Louisiana, Pennsylvania, West Virginia, New York, and Ohio which include the Barnett, Eagle Ford, Haynesville, Marcellus, Niobrara, and Utica shale plays as well as the Mid-Continent region.

The midstream businesses include equity-method investments in natural gas gathering and processing assets and NGL fractionation and transportation assets, including a 62 percent equity-method investment in UEOM, a 69 percent equity-method investment in Laurel Mountain, a 58 percent equity-method investment in Caiman II, a 60 percent equity-method investment in Discovery, a 50 percent equity-method investment in OPPL, and Appalachia Midstream Services, LLC, which owns an approximate average 66 percent equity-method investment interest in multiple gas gathering systems in the Marcellus Shale (Appalachia Midstream Investments), as well as our previously owned 50 percent equity-method investment in the Delaware basin gas gathering system (DBJV) in the Mid-Continent region (see Note 4 – Investing Activities of Notes to Consolidated Financial Statements).

The midstream businesses previously included Canadian midstream operations, which were comprised of an oil sands offgas processing plant near Fort McMurray, Alberta and an NGL/olefin fractionation facility at Redwater, Alberta. In September 2016, these Canadian operations were sold.

Williams Partners’ ongoing strategy is to safely and reliably operate large-scale, interstate natural gas transmission and midstream infrastructures where our assets can be fully utilized and drive low per-unit costs. We focus on consistently attracting new business by providing highly reliable service to our customers and investing in growing markets and areas of increasing natural gas demand.

Williams Partners’ interstate transmission and related storage activities are subject to regulation by the FERC and as such, our rates and charges for the transportation of natural gas in interstate commerce, and the extension, expansion or abandonment of jurisdictional facilities and accounting, among other things, are subject to regulation. The rates are established through the FERC’s ratemaking process. Changes in commodity prices and volumes transported have

Management’s Discussion and Analysis (Continued)

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

Other

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

Financial Repositioning

In January 2017, we announced agreements with WPZ, wherein we permanently waived the general partner’s IDRs and converted our 2 percent general partner interest in WPZ to a noneconomic interest in exchange for 289 million newly issued WPZ common units. Pursuant to this agreement, we also purchased approximately 277 thousand WPZ common units for $10 million. Additionally, we purchased approximately 59 million common units of WPZ at a price of $36.08586 per unit in a private placement transaction, funded with proceeds from our equity offering (see Note 10 – Stockholders’ Equity of Notes to Consolidated Financial Statements). According to the terms of this agreement, concurrent with WPZ’s quarterly distributions in February 2017 and May 2017, we paid additional consideration totaling $56 million to WPZ for these units. Subsequent to these transactions and as of September 30, 2017, we own a 74 percent limited partner interest in WPZ.

Termination of WPZ Merger Agreement

On September 28, 2015, prior to our entry into the Merger Agreement, we entered into a Termination Agreement and Release (Termination Agreement), terminating the WPZ Merger Agreement. Under the terms of the Termination Agreement, we were required to pay a $428 million termination fee to WPZ, at which time we owned approximately 60 percent, including the interests of the general partner and IDRs. Such termination fee settled through a reduction of quarterly incentive distributions we were entitled to receive from WPZ (such reduction not to exceed $209 million per quarter). The distributions from WPZ in November 2015, February 2016, and May 2016 were reduced by $209 million, $209 million, and $10 million, respectively, related to this termination fee.

Dividends

In September 2017, we paid a regular quarterly dividend of $0.30 per share.

Overview of Nine Months Ended September 30, 2017

Net income (loss) attributable to The Williams Companies, Inc., for the nine months ended September 30, 2017, changed favorably by $896 million compared to the nine months ended September 30, 2016, reflecting an increase of $972 million in operating income, a $214 million increase in Other investing income (loss) – net primarily associated with the disposition of certain equity-method investments in 2017, the absence of $112 million of impairments of equity-method investments incurred in 2016, and reduced interest expense, partially offset by a $200 million increase in the provision for income taxes, driven by higher pre-tax income, partially offset by a $127 million benefit associated with the release of a valuation allowance on a capital loss carryover and a $378 million increase in net income attributable to noncontrolling interests primarily due to increased income at WPZ. The improvement in operating income reflects a gain of $1.095 billion from the sale of our Geismar Interest, increase service revenue from expansion projects, and lower costs and expenses, partially offset by a $113 million decrease in product margins primarily due to the loss of olefins volumes as a result of the sale of our Gulf Olefins and Canadian operations, and a $425 million increase in impairments of certain assets.

Management’s Discussion and Analysis (Continued)

Unless indicated otherwise, the following discussion and analysis of results of operations and financial condition and liquidity should be read in conjunction with the consolidated financial statements and notes thereto of this Form 10‑Q and our annual consolidated financial statements and notes thereto in Exhibit 99.1 of our Form 8-K dated May 25, 2017.

Pension Deferred Vested Benefit Early Payout Program

Williams Partners

New York Bay Expansion

In October 2017, the New York Bay Expansion to the Transco system was placed into service. The project expanded Transco’s existing natural gas transmission system to provide incremental firm transportation capacity from Station 195 in Pennsylvania to the Rockaway Delivery Lateral transfer point and the Narrows meter station in New York. The project increased capacity by 115 Mdth/d.

Dalton

In August 2017, the Dalton expansion to the Transco system was placed into service. This project expanded Transco’s existing natural gas transmission system together with greenfield facilities to provide incremental firm transportation capacity from our Station 210 in New Jersey to markets in northwest Georgia. On April 1, 2017, we began providing firm transportation service through the mainline portion of the project on an interim basis and we placed the full project into service in August 2017. The project increased capacity by 448 Mdth/d.

Hillabee

In July 2017, Phase I of the Hillabee Expansion Project was placed into service. The project involves an expansion of Transco’s existing natural gas transmission system from our Station 85 in west central Alabama to a new interconnection with the Sabal Trail pipeline in Alabama. The project will be constructed in phases, and all of the project expansion capacity will be leased to Sabal Trail. We placed a portion of Phase I into service in June of 2017 and the remainder of Phase I into service in July of 2017. Phase I increased capacity by 818 Mdth/d. The in-service date of Phase II is planned for the second quarter of 2020 and together they are expected to increase capacity by 1,025 Mdth/d.

In March 2016, WPZ entered into an agreement with the member-sponsors of Sabal Trail to resolve several matters. In accordance with the agreement, the member-sponsors paid us an aggregate amount of $240 million in three equal installments as certain milestones of the project were met. The first $80 million payment was received in March 2016, the second installment was received in September 2016 and the third installment was received in July 2017. WPZ expects to recognize income associated with these receipts over the term of the capacity lease agreement.

In August 2017, the Court of Appeals for the District of Columbia Circuit granted an appeal of the FERC certificate order for the Southeast Market Pipelines projects (a group of related projects, including the Hillabee Expansion Project) filed by certain non-governmental organizations. In doing so, the court (i) remanded the matter to the FERC for preparation of an Environmental Impact Statement that conforms with the court’s opinion regarding quantifying certain greenhouse gas emissions, and (ii) vacated the FERC’s certificate order for the projects, which would be effective following the court’s mandate (by court order, the mandate will not issue until after disposition of all petitions for rehearing). We, along with other intervenors, and the FERC have filed petitions for rehearing with the court to overturn

Management’s Discussion and Analysis (Continued)

the remedy that would involve vacating the FERC certificate order. If the court’s mandate is issued prior to the FERC re-issuing certificate authority for the projects, we believe that the FERC will take the necessary steps (which may include issuing temporary certificate authority) to avoid any lapse in federal authorization for the projects.

Hurricanes Harvey and Irma

We are not aware of any major damage to our facilities as a result of Hurricanes Harvey and Irma.

Geismar olefins facility monetization

In July 2017, WPZ completed the sale of its Geismar Interest for $2.084 billion in cash. WPZ received a final working capital adjustment of $12 million in October 2017. Additionally, WPZ entered into a long-term supply and transportation agreement with the purchaser to provide feedstock to the plant via its Bayou Ethane pipeline system, which is expected to provide a long-term, fee-based revenue stream. (See Note 3 – Divestitures of Notes to Consolidated Financial Statements.)

Following this sale, the cash proceeds were used to repay WPZ’s $850 million term loan. WPZ also plans to use these proceeds to fund a portion of the capital and investment expenditures that are a part of its growth portfolio.

Acquisition of additional interests in Appalachia Midstream Investments

During the first quarter of 2017, WPZ exchanged all of its 50 percent interest in DBJV for an increased interest in two natural gas gathering systems that are part of the Appalachia Midstream Investments and $155 million in cash. Following this exchange, WPZ has an approximate average 66 percent interest in the Appalachia Midstream Investments. WPZ also sold all of its interest in Ranch Westex JV LLC for $45 million. These transactions resulted in a total gain of $269 million reflected in Other investing income (loss) – net in the Consolidated Statement of Operations within the Williams Partners segment. (See Note 4 – Investing Activities of Notes to Consolidated Financial Statements.)

Commodity Prices

NGL per-unit margins were approximately 64 percent higher in the first nine months of 2017 compared to the same period of 2016 due to a 42 percent increase in per-unit non-ethane prices. The per-unit margin increase also reflects the absence of our former Canadian operations which had lower per-unit non-ethane margins in the prior year compared to our domestic operations. These favorable impacts were partially offset by an approximate 37 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.

Management’s Discussion and Analysis (Continued)

The following graph illustrates the NGL production and sales volumes, as well as the margin differential between ethane and non-ethane products and the relative mix of those products.

The potential impact of commodity prices on our business for the remainder of 2017 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 2017 includes the previously discussed financial repositioning transactions and the monetization of our Geismar Interest. For WPZ, these transactions serve to improve its cost of capital, remove its need to access the public equity markets for the next several years, enhance growth, and provide for debt reduction, solidifying WPZ as an attractive financing vehicle. The transactions also facilitate a reduction of our parent-level debt and provide for dividend growth flexibility, while retaining strategic and financing flexibility.

Our growth capital and investment expenditures in 2017 are expected to be between $2.1 billion and $2.8 billion. Approximately $1.4 billion to $1.9 billion of our growth capital funding needs include Transco expansions and other interstate pipeline growth projects, most of which are fully contracted with firm transportation agreements. The remaining growth capital spending in 2017 primarily reflects investment in gathering and processing systems in the Northeast region limited primarily to known new producer volumes, including volumes that support Transco expansion projects including our Atlantic Sunrise project. In addition to growth capital and investment expenditures, we also

Management’s Discussion and Analysis (Continued)

remain committed to projects that maintain our assets for safe and reliable operations, as well as projects that meet legal, regulatory, and/or contractual commitments.

As a result of our significant continued capital and investment expenditures on Transco expansions and fee-based gathering and processing projects, as well as the sale of our Canadian operations and Geismar Interest, fee-based businesses are becoming an even more significant component of our portfolio and serve to reduce the influence of commodity price fluctuations on our operating results and cash flows. We expect to benefit as continued growth in demand for low-cost natural gas is driven by increases in LNG exports, industrial demand and power generation. For the remainder of 2017, current forward market prices indicate oil and natural gas prices are expected to be relatively comparable to the same period in 2016, while NGL prices are expected to be higher. However, some of our customers may continue to curtail or delay drilling plans until there is a more sustained recovery in prices, which may negatively impact our gathering and processing volumes. The credit profiles of certain of our producer customers have been, and may continue to be, challenged as a result of lower energy commodity prices. Unfavorable changes in energy commodity prices or the credit profile of our producer customers may also result in noncash impairments of our assets.

In 2017, our operating results are expected to include increases from our regulated Transco fee-based business, primarily related to projects recently placed in-service or expected to be placed in-service in 2017. For our non-regulated businesses, we anticipate increases in fee-based revenue due to expanded capacity in the Eastern Gulf area and a slight increase in fee-based revenue in the Northeast region. Partially offsetting these increases are expected declines in fee-based revenue in the Western region. We expect overall gathering and processing volumes to remain steady in 2017 and increase thereafter to meet the growing demand for natural gas and natural gas products. We also anticipate lower general and administrative expenses due to cost reduction initiatives and asset monetizations.

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


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


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


•	Counterparty credit and performance risk, including that of Chesapeake Energy Corporation and its affiliates;


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


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


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


•	Lower than expected distributions from WPZ;


•	Other risks set forth under Part I, Item 1A. Risk Factors in our Annual Report on Form 10-K filed with the SEC on February 22, 2017.

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

Expansion Projects

Williams Partners’ ongoing major expansion projects include the following:

Appalachian Basin Expansion

We recently agreed to expand our services to a customer to provide 660 MMcf/d of processing wet gas capacity in the Marcellus and Upper Devonian Shale in West Virginia. Associated with this agreement, we expect to further

Management’s Discussion and Analysis (Continued)

expand the processing capacity of our Oak Grove facility, which has the ability to increase capacity by an additional 1.8 Bcf/d. Additionally, with the same customer, we secured a gathering dedication agreement to gather dry gas in this same region. These expansions will be supported by long-term, fee-based agreements and volumetric commitments.

Atlantic Sunrise

In February 2017, we received approval from the FERC to expand Transco’s existing natural gas transmission system along with greenfield facilities to provide incremental firm transportation capacity from the northeastern Marcellus producing area to markets along Transco’s mainline as far south as Station 85 in west central Alabama. We placed a portion of the mainline project facilities into service on September 1, 2017 and it increased capacity by 400 Mdth/d. We plan to place the full project into service during mid-2018, assuming timely receipt of all remaining regulatory approvals. The full project is expected to increase capacity by 1,700 Mdth/d.

Constitution Pipeline

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

In December 2014, Constitution received approval from the FERC to construct and operate its proposed pipeline, which will have an expected capacity of 650 Mdth/d. However, in April 2016, the New York State Department of Environmental Conservation (NYSDEC) denied the necessary water quality certification under Section 401 of the Clean Water Act for the New York portion of the pipeline. In May 2016, Constitution appealed the NYSDEC’s denial of the Section 401 certification to the United States Court of Appeals for the Second Circuit and in August 2017, the court issued a decision denying in part and dismissing in part Constitution’s appeal. The court expressly declined to rule on Constitution’s argument that the delay in the NYSDEC’s decision on Constitution’s Section 401 application constitutes a waiver of the certification requirement. The court determined that it lacked jurisdiction to address that contention, and found that jurisdiction over the waiver issue lies exclusively with the United States Court of Appeals for the District of Columbia Circuit. As to the denial itself, the court determined that NYSDEC’s action was not arbitrary or capricious. Constitution filed a petition for rehearing of the Second Circuit Court’s decision, but in October the court denied our petition.

We remain steadfastly committed to the project and 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.

Eagle Ford

We plan to expand our gathering infrastructure in the Eagle Ford region in order to meet our customers’ production plans. The expansion of the gathering infrastructure includes the addition of well connections and gathering pipeline to the existing systems.

Garden State

In April 2016, we received approval from the FERC to expand Transco’s existing natural gas transmission system to provide incremental firm transportation capacity from Station 210 in New Jersey to a new interconnection on our Trenton Woodbury Lateral in New Jersey. The project will be constructed in phases and is expected to increase capacity by 180 Mdth/d. We placed the initial phase of the project into service on September 9, 2017 and plan to place the remaining portion of the project into service during the second quarter of 2018.

Management’s Discussion and Analysis (Continued)

Gulf Connector

In August 2016, we filed an application with the FERC to expand Transco’s existing natural gas transmission system to provide incremental firm transportation capacity from Station 65 in Louisiana to delivery points in Wharton and San Patricio Counties, Texas. The project will be constructed in two phases and we plan to place both phases into service during the first half of 2019, assuming timely receipt of all necessary regulatory approvals. The project is expected to increase capacity by 475 Mdth/d.

Hillabee

In February 2016, the FERC issued a certificate order for the initial phases of Transco’s Hillabee Expansion Project. The project involves an expansion of Transco’s existing natural gas transmission system from Station 85 in west central Alabama to a new interconnection with the Sabal Trail pipeline in Alabama. The project will be constructed in phases, and all of the project expansion capacity will be leased to Sabal Trail. We placed a portion of Phase I into service in June of 2017 and the remainder of Phase I into service in July of 2017. Phase I increased capacity by 818 Mdth/d. The in-service date of Phase II is planned for the second quarter of 2020 and together they are expected to increase capacity by 1,025 Mdth/d. See Williams Partners within Overview of Nine Months Ended September 30, 2017.

Norphlet Project

In March 2016, we announced that we have reached an agreement to provide deepwater gas gathering services to the Appomattox development in the Gulf of Mexico. The project will provide offshore gas gathering services to our existing Transco lateral, which will provide transmission services onshore to our Mobile Bay processing facility. We also plan to make modifications to our Main Pass 261 Platform to install an alternate delivery route from the platform, as well as modifications to our Mobile Bay processing facility. The project is scheduled to go into service during the second half of 2019.

North Seattle Lateral Upgrade

In May 2017, we filed an application with the FERC to expand delivery capabilities on Northwest Pipeline’s North Seattle Lateral. The project consists of the removal and replacement of approximately 5.9 miles of 8-inch diameter pipeline with new 20-inch diameter pipeline. We plan to place the project into service as early as the fourth quarter of 2019. The project is expected to increase capacity by up to 159 Mdth/d.

Northeast Supply Enhancement

In March 2017, we filed an application with the FERC to expand Transco’s existing natural gas transmission system to provide incremental firm transportation capacity from Station 195 in Pennsylvania to the Rockaway Delivery Lateral transfer point in New York. We plan to place the project into service in late 2019 or during the first half of 2020, assuming timely receipt of all necessary regulatory approvals. The project is expected to increase capacity by 400 Mdth/d.

Susquehanna Supply Hub Expansion

The Susquehanna Supply Hub Expansion, which involves two new compression facilities with an additional 49,000 horsepower and 59 miles of 12 inch to 24 inch pipeline, is expected to increase gathering capacity, allowing a certain producer to fulfill its commitment to deliver 850 Mdth/d to our Atlantic Sunrise development. We anticipate this expansion will be completed by the end of 2017.

Virginia Southside II

In July 2016, we received approval from the FERC to expand Transco’s existing natural gas transmission system together with greenfield facilities to provide incremental firm transportation capacity from our Station 210 in New Jersey and our Station 165 in Virginia to a proposed delivery point on a new lateral extending from our Brunswick Lateral in Virginia. We plan to place the project into service during the fourth quarter of 2017 and it is expected to increase capacity by 250 Mdth/d.

Management’s Discussion and Analysis (Continued)

Critical Accounting Estimates

Constitution Pipeline Capitalized Project Costs

As of September 30, 2017, Property, plant, and equipment in our Consolidated Balance Sheet includes approximately $381 million of capitalized project costs for Constitution, for which we are the construction manager and own a 41 percent consolidated interest. As a result of the events discussed in Company Outlook, we evaluated the capitalized project costs for impairment as recently as September 30, 2017, and determined that no impairment was necessary. Our evaluation considered probability-weighted scenarios of undiscounted future net cash flows, including a scenario assuming construction of the pipeline, as well as a scenario where the project does not proceed. We continue to monitor the capitalized project costs associated with Constitution for potential impairment.

Property, Plant, and Equipment and Other Identifiable Intangible Assets

We evaluate our property, plant, and equipment and other identifiable intangible assets for impairment when events or changes in circumstances indicate, in our judgment, that the carrying value of such assets may not be recoverable. When an indicator of impairment has occurred, we compare our estimate of undiscounted future cash flows attributable to the assets to the carrying value of the assets to determine whether an impairment has occurred and we may apply a probability-weighted approach to consider the likelihood of different cash flow assumptions and possible outcomes including selling in the near term or holding for the remaining estimated useful life. If an impairment of the carrying value has occurred, we determine the amount of the impairment recognized by estimating the fair value of the assets and recording a loss for the amount that the carrying value exceeds the estimated fair value. This evaluation is performed at the lowest level for which separately identifiable cash flows exist.

As disclosed in our 2016 Annual Report on Form 10–K and subsequent Quarterly Reports on Form 10–Q, we may monetize assets that are not core to our strategy which could result in impairments of certain equity–method investments, property, plant, and equipment, and intangible assets. Such impairments could potentially be caused by indications of fair value implied through the monetization process or, in the case of asset dispositions that are part of a broader asset group, the impact of the loss of future estimated cash flows.

During the third quarter of 2017, we received solicitations and engaged in negotiations for the sale of certain gas gathering assets within the Mid-Continent region. As a result of these events, we evaluated the Mid-Continent asset group, which includes property, plant, and equipment and intangible assets, for impairment. Our evaluation considered the likelihood of divesting certain assets within the Mid-Continent region as well as information developed from the negotiation process that impacted our estimate of future cash flows associated with these assets. The estimated undiscounted future cash flows were determined to be below the carrying amount for these assets. We computed the estimated fair value using an income approach and incorporated market inputs based on ongoing negotiations for the potential sale of a portion of the underlying assets. For the income approach, we utilized a discount rate of 10.2 percent, reflecting an estimate of our cost of capital and risks associated with the underlying assets. As a result of this evaluation, we recorded an impairment charge of $1.019 billion for the difference between the estimated fair value and carrying amount of these assets.

Judgments and assumptions are inherent in estimating undiscounted future cash flows, fair values, and the probability-weighting of possible outcomes. The use of alternate judgments and assumptions could result in a different determination affecting the consolidated financial statements.

Equity-Method Investment in UEOM

As of September 30, 2017, the carrying value of our equity-method investment in UEOM is $1.4 billion. During the third quarter of 2017, we became aware of potential changes to the future drilling plans of a certain producer which could delay and/or reduce volumes available for processing at UEOM. As a result, we evaluated this investment for impairment at September 30, 2017, and determined that no impairment was necessary.

We estimated the fair value of our investment in UEOM using an income approach that included probability-weighted scenarios assuming varying levels of volume declines, as well as a scenario with less volume degradation as a result of an assumed sale of the underlying reserves to another producer. We utilized a discount rate of 10.8 percent.

Management’s Discussion and Analysis (Continued)

The estimated fair value of our investment in UEOM exceeded its carrying value by more than 10 percent. Judgments and assumptions are inherent in our estimates of future cash flows, discount rates, and scenario probabilities. The use of alternate judgments and assumptions could result in a different calculation of fair value, which could ultimately result in the recognition of an impairment charge in the consolidated financial statements.

Management’s Discussion and Analysis (Continued)

Results of Operations

Consolidated Overview

The following table and discussion is a summary of our consolidated results of operations for the three and nine months ended September 30, 2017, compared to the three and nine months ended September 30, 2016. The results of operations by segment are discussed in further detail following this consolidated overview discussion.



	Three Months Ended September 30,									Nine Months Ended September 30,
	2017			2016			$ Change*	% Change*		2017			2016			$ Change*	% Change*
	(Millions)									(Millions)
Revenues:
Service revenues	$	1,310		$	1,247		+63	+5	%	$	3,853		$	3,678		+175	+5	%
Product sales	581			658			-77	-12	%	1,950			1,623			+327	+20	%
Total revenues	1,891			1,905						5,803			5,301
Costs and expenses:
Product costs	504			461			-43	-9	%	1,620			1,180			-440	-37	%
Operating and maintenance expenses	400			394			-6	-2	%	1,157			1,179			+22	+2	%
Depreciation and amortization expenses	433			435			+2	—	%	1,308			1,326			+18	+1	%
Selling, general, and administrative expenses	138			177			+39	+22	%	452			556			+104	+19	%
Gain on sale of Geismar Interest	(1,095		)	—			+1,095	NM		(1,095		)	—			+1,095	NM
Impairment of certain assets	1,210			1			-1,209	NM		1,236			811			-425	-52	%
Other (income) expense – net	24			92			+68	+74	%	34			130			+96	+74	%
Total costs and expenses	1,614			1,560						4,712			5,182
Operating income (loss)	277			345						1,091			119
Equity earnings (losses)	115			104			+11	+11	%	347			302			+45	+15	%
Impairment of equity-method investments	—			—			—	NM		—			(112		)	+112	+100	%
Other investing income (loss) – net	4			28			-24	-86	%	278			64			+214	NM
Interest expense	(267		)	(297		)	+30	+10	%	(818		)	(886		)	+68	+8	%
Other income (expense) – net	20			20			—	—	%	115			52			+63	+121	%
Income (loss) before income taxes	149			200						1,013			(461		)
Provision (benefit) for income taxes	24			69			+45	+65	%	126			(74		)	-200	NM
Net income (loss)	125			131						887			(387		)
Less: Net income (loss) attributable to noncontrolling interests	92			70			-22	-31	%	400			22			-378	NM
Net income (loss) attributable to The Williams Companies, Inc.	$	33		$	61					$	487		$	(409	)


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

Management’s Discussion and Analysis (Continued)

Three months ended September 30, 2017 vs. three months ended September 30, 2016

Service revenues increased due to higher revenues from the Barnett Shale related to the amortization of deferred revenue associated with the restructuring of contracts in the fourth quarter of 2016, as well as higher volumes primarily associated with Transco’s natural gas transportation fee revenues associated with expansion projects placed in-service during 2016 and 2017, partially offset by lower rates in the western region also associated with the fourth quarter 2016 contract restructuring. The increase in Service revenues was also partially offset by lower volumes in most of the Utica Shale and western regions, driven by natural declines.

Product sales decreased primarily due to lower olefin sales associated with decreased volumes related to the sale of our Geismar Interest in July 2017, our Canadian operations in September 2016, and our RGP Splitter in June 2017. The decrease in Product sales is partially offset by higher marketing sales primarily due to significantly higher prices, partially offset by lower volumes.

The increase in Product costs is primarily due to the same factors that increased marketing sales, partially offset by lower olefin feedstock and natural gas purchases associated with decreased volumes.

Operating and maintenance expenses increased primarily due to an increase in Transco pipeline integrity testing and costs, and general maintenance. These increases are partially offset by the absence of costs associated with our former Canadian and Gulf Olefins operations and ongoing cost containment efforts.

Depreciation and amortization expenses decreased primarily due to the absence of our former Canadian and Gulf Olefins operations, offset by new assets placed in-service.

Selling, general, and administrative expenses decreased primarily due to the absence of project development costs incurred in the third quarter of 2016 associated with our former Canadian PDH facility, lower strategic alternatives costs, and the absence of costs associated with our former Canadian and Gulf Olefins operations. These decreases were partially offset by higher organizational realignment and severance costs. (See Note 5 – Other Income and Expenses of Notes to Consolidated Financial Statements.)

The Gain on sale of Geismar Interest reflects the gain recognized on the sale of our Geismar Interest in July 2017. (See Note 3 – Divestitures of Notes to Consolidated Financial Statements.)

The unfavorable change in Impairment of certain assets reflects the 2017 impairments of certain gathering operations in the Mid-Continent and Marcellus South regions and certain NGL pipeline assets (see Note 11 – Fair Value Measurements and Guarantees of Notes to Consolidated Financial Statements).

The favorable change in Other (income) expense – net within Operating income (loss) includes the absence of the 2016 loss on the sale of our Canadian operations, as well as lower product development costs at Constitution.

Operating income (loss) changed unfavorably primarily due to the 2017 impairment of certain gathering operations in the Mid-Continent and Marcellus South regions and lower olefin product margins resulting from the sale of our Geismar Interest and Canadian operations, partially offset by the gain on sale of our Geismar Interest, higher service revenues associated with certain projects placed in-service, and the absence of a 2016 loss on the sale of our Canadian operations.

The favorable change in Equity earnings (losses) is due to an increase in ownership of our Appalachian Midstream Investments, partially offset by lower Discovery results due to lower fee revenues, and lower UEOM results driven by lower processing volumes from the Utica gathering system.

Other investing income (loss) – net decreased due to the absence of a 2016 gain on the sale of an equity-method investment interest in a gathering system that was part of our Appalachia Midstream Investments gathering system. (See Note 4 – Investing Activities of Notes to Consolidated Financial Statements.)

Management’s Discussion and Analysis (Continued)

Interest expense decreased due to lower Interest incurred primarily attributable to debt retirements and lower borrowings on our credit facilities in 2017. (See Note 9 – Debt and Banking Arrangements of Notes to Consolidated Financial Statements.)

Provision (benefit) for income taxes changed favorably primarily due to lower pretax income. See Note 6 – Provision (Benefit) for Income Taxes of Notes to Consolidated Financial Statements for a discussion of the effective tax rate compared to the federal statutory rate for both periods.

The unfavorable change in Net income (loss) attributable to noncontrolling interests is primarily due to the impact of decreased income allocated to the WPZ general partner driven by the permanent waiver of IDRs, partially offset by a decrease in the ownership of the noncontrolling interests and lower operating results at WPZ. Both the permanent waiver of IDRs and the change in ownership are associated with the first-quarter 2017 Financial Repositioning (see Note 1 – General, Description of Business, and Basis of Presentation of Notes to Consolidated Financial Statements).

Nine months ended September 30, 2017 vs. nine months ended September 30, 2016

Service revenues increased due to the recognition of deferred revenue in the Barnett Shale region associated with the restructuring of contracts in the fourth quarter of 2016. Service revenues also increased due to higher volumes primarily in the eastern Gulf Coast region, including the impact of new volumes at Gulfstar One related to the Gunflint expansion placed in-service in the third quarter of 2016, the absence of the temporary shut-down of Gulfstar One in the second quarter of 2016 to tie into Gunflint, the absence of producers’ 2016 operational issues in the Tubular Bells field in the first quarter of 2016, and higher volumes at Devils Tower related to Kodiak field production. Additionally, Transco experienced higher natural gas transportation fee revenues reflecting expansion projects placed in-service in 2016 and 2017, as well as an increase in storage revenues due to the absence of an accrual for potential refunds associated with a ruling received in certain rate case litigation in 2016. These increases were partially offset by lower rates primarily in the Barnett Shale region associated with the previously discussed contract restructure, as well as lower volumes in most of the Utica Shale and western regions driven by natural declines and extreme weather conditions in the Rocky Mountains in 2017. Service revenues increases were also partially offset by the absence of our former Canadian and Gulf Olefins operations.

Product sales increased due to higher marketing revenues primarily associated with significantly higher prices and volumes. Revenues from the sale of our equity NGLs increased primarily due to higher non-ethane NGL prices, partially offset by lower volumes. These increases were partially offset by lower olefin production sales due to lower volumes resulting from the sale of our former Gulf Olefins and Canadian operations.

The increase in Product costs is primarily due to the same factors that increased marketing sales, partially offset by lower olefin feedstock purchases associated with the sale of our Gulf Olefins and Canadian operations.

Operating and maintenance expenses decreased primarily due to the absence of costs associated with our former Canadian and Gulf Olefins operations and lower labor-related costs resulting from our workforce reductions that occurred late in first-quarter 2016, and ongoing cost containment efforts. These decreases are partially offset by an increase in pipeline integrity testing on Transco, and general maintenance.

Depreciation and amortization expenses decreased primarily due to the absence of our former Canadian and Gulf Olefins operations, partially offset by new assets placed in-service.

Selling, general, and administrative expenses decreased primarily due to the absence of certain project development costs associated with the Canadian PDH facility that we expensed in 2016, lower labor-related costs resulting from our workforce reductions that occurred late in first-quarter 2016, ongoing cost containment efforts, the absence of costs associated with our former Canadian operations, as well as lower strategic development costs. These decreases were partially offset by higher severance and organizational realignment costs. (See Note 5 – Other Income and Expenses of Notes to Consolidated Financial Statements.)

The Gain on sale of Geismar Interest reflects the gain recognized on the sale of our Geismar Interest in July 2017. (See Note 3 – Divestitures of Notes to Consolidated Financial Statements.)

Management’s Discussion and Analysis (Continued)

The unfavorable change in Impairment of certain assets reflects 2017 impairments of certain gathering operations in the Mid-Continent and Marcellus South regions, certain NGL pipeline assets, and an olefins pipeline project in the Gulf coast region. These 2017 impairments are partially offset by the absence of 2016 impairments of our former Canadian operations and certain Mid-Continent assets (see Note 11 – Fair Value Measurements and Guarantees of Notes to Consolidated Financial Statements).

The favorable change in Other (income) expense – net within Operating income (loss) includes the absence of the 2016 loss on the sale of our Canadian operations, gains from certain contract settlements and terminations in 2017, a gain on the sale of our RGP Splitter in 2017, the absence of an unfavorable change in foreign currency exchange associated with our former Canadian operations, insurance proceeds received in 2017 associated with the Geismar Incident, and lower project development costs at Constitution. These favorable changes were partially offset by the accrual of additional expenses in 2017 related to the Geismar Incident, as well as the absence of a gain in first-quarter 2016 associated with the sale of unused pipe.

Operating income (loss) changed favorably primarily due to the gain on sale of our Geismar Interest, the absence of the 2016 impairments of our former Canadian operations and certain Mid-Continent assets, higher service revenues from expansion projects placed in-service in 2016 and 2017, as well as ongoing cost containment efforts, including workforce reductions in first-quarter 2016. Operating income (loss) also improved due to the absence of a 2016 loss on the sale of our Canadian operations, the absence of an operating loss associated with our former Canadian operations, gains from certain contract settlements, and the sale of our RGP Splitter. These favorable changes were partially offset by a 2017 impairment of certain gathering operations in the Mid-Continent and Marcellus South regions, and certain NGL pipeline assets, as well as the absence of operating income associated with our former Gulf Olefins operations.

The favorable change in Equity earnings (losses) is due to an increase in ownership of our Appalachian Midstream Investments, improved results at Laurel Mountain Midstream due to higher rates, and improved results at Discovery attributable to the accelerated recognition of previously deferred revenue, partially offset by lower UEOM results driven by lower processing volumes from the Utica gathering system.

The decrease in Impairment of equity-method investments reflects the absence of first-quarter 2016 impairment charges associated with our DBJV and Laurel Mountain equity-method investments. (See Note 11 – Fair Value Measurements and Guarantees of Notes to Consolidated Financial Statements.)

Other investing income (loss) – net reflects the gain on disposition of our investments in DBJV and Ranch Westex JV LLC in 2017 (see Note 4 – Investing Activities of Notes to Consolidated Financial Statements), partially offset by the absence of interest income received in 2016 associated with a receivable related to the sale of certain former Venezuelan assets and the absence of a 2016 gain on the sale of an equity-method investment interest in a gathering system that was part of our Appalachia Midstream Investments gathering system.

Interest expense decreased primarily due to lower Interest incurred primarily attributable to debt retirements and lower borrowings on our credit facilities in the first quarter of 2017. (See Note 9 – Debt and Banking Arrangements of Notes to Consolidated Financial Statements.)

Other income (expense) – net below Operating income (loss) changed favorably primarily due to a net gain on early debt retirements in 2017, and favorable changes related to equity funds used during construction (AFUDC). (See Note 5 – Other Income and Expenses of Notes to Consolidated Financial Statements.)

Provision (benefit) for income taxes changed unfavorably primarily due to higher pretax income. See Note 6 – Provision (Benefit) for Income Taxes of Notes to Consolidated Financial Statements for a discussion of the effective tax rate compared to the federal statutory rate for both periods.

The unfavorable change in Net income (loss) attributable to noncontrolling interests is primarily due to higher operating results at WPZ, the impact of decreased income allocated to the WPZ general partner driven by the permanent waiver of IDRs, partially offset by a decrease in the ownership of the noncontrolling interests. Both the permanent waiver of IDRs and the change in ownership are associated with the first-quarter 2017 Financial Repositioning (see Note 1 – General, Description of Business, and Basis of Presentation of Notes to Consolidated Financial Statements).

Management’s Discussion and Analysis (Continued)

In addition, improved results in our Gulfstar operations also contributed to the unfavorable change in Net income (loss) attributable to noncontrolling interests, partially offset by lower results for our Cardinal gathering system.

Period-Over-Period Operating Results - Segments

We evaluate segment operating performance based upon Modified EBITDA. Note 13 – Segment Disclosures of Notes to Consolidated Financial Statements includes a reconciliation of this non-GAAP measure to Net income (loss). Management uses Modified EBITDA because it is an accepted financial indicator used by investors to compare company performance. In addition, management believes that this measure provides investors an enhanced perspective of the operating performance of our assets. Modified EBITDA should not be considered in isolation or as a substitute for a measure of performance prepared in accordance with GAAP.

Williams Partners



	Three Months Ended September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016
	(Millions)
Service revenues	$	1,304		$	1,252		$	3,837		$	3,688
Product sales	581			655			1,950			1,613
Segment revenues	1,885			1,907			5,787			5,301

Product costs	(504		)	(463		)	(1,620		)	(1,183		)
Other segment costs and expenses	(536		)	(567		)	(1,520		)	(1,660		)
Gain on sale of Geismar Interest	1,095			—			1,095			—
Impairment of certain assets	(1,142		)	(1		)	(1,145		)	(403		)
Proportional Modified EBITDA of equity-method investments	202			194			611			574
Williams Partners Modified EBITDA	$	1,000		$	1,070		$	3,208		$	2,629

NGL margin	$	46		$	45		$	139		$	119
Olefin margin	2			122			126			267

Three months ended September 30, 2017 vs. three months ended September 30, 2016

Modified EBITDA decreased primarily due to impairments of certain gathering operations and lower olefin margins due to the sale of our Gulf Olefins (Geismar olefin and RGP Splitter plants) operations in 2017 and our Canadian operations in 2016, partially offset by a $1.095 billion gain on the sale of our Geismar Interest in third-quarter 2017, the absence of the $32 million loss on the sale of our former Canadian operations in third-quarter 2016, and higher service revenues primarily driven by expansions of our Transco pipeline and our Gulfstar One facilities.

Service revenues increased primarily due to:


•	A $53 million increase related to the amortization of deferred revenue associated with the up-front cash payment received in conjunction with the fourth quarter 2016 Barnett Shale contract restructuring;


•	A $43 million increase in Transco’s natural gas transportation fee revenues primarily due to a $45 million increase associated with expansion projects placed in-service in 2016 and 2017;


•	A $20 million increase in fee revenues in the eastern Gulf Coast region associated primarily with higher volumes, including the impact of new volumes at Gulfstar One from the Gunflint expansion placed in service in the third quarter of 2016, and the absence of the temporary shutdown and subsequent ramp-up of Gulfstar One in the second and third quarters of 2016 to tie-in Gunflint;

Management’s Discussion and Analysis (Continued)


•	A $29 million decrease related to lower gathering rates in the Barnett Shale related to the fourth quarter 2016 contract restructuring, along with lower rates recognized in the Niobrara and Eagle Ford Shale regions. Rates recognized in the Niobrara region represent a portion of the total contractual rate, with the difference reflected as deferred revenue;


•	An $18 million decrease in fee revenues in the eastern Gulf Coast region as a result of a temporary increase during 2016 related to disrupted operations of a competitor and shut-ins of certain wells behind Devils Tower as a result of production issues;


•	A decrease of $15 million primarily due to the absence of revenues associated with our former Canadian operations that were sold in September 2016;

•

In the Northeast region, a $10 million increase in fee revenues in the Susquehanna Supply Hub driven by 10 percent higher gathered volumes reflecting increased customer production, offset by a $10 million decrease in the Utica gathering system associated with 6 percent lower gathered volumes driven by natural declines in the wet gas areas, partially offset by higher volumes from new development in the dry gas areas.

Product sales decreased primarily due to:


•	A $196 million decrease in olefin sales due to the absence of sales associated with the Gulf Olefins operations that were sold in July 2017 and June 2017, respectively, and our former Canadian operations that were sold in September 2016;


•	A $12 million decrease in revenues from our equity NGLs primarily due to the absence of sales associated with our former Canadian operations and the absence of a temporary increase in 2016 due to disrupted operations of a competitor, partially offset by higher NGL prices;


•	A $142 million increase in marketing revenues primarily due to significantly higher prices and NGL volumes, partially offset by lower crude, natural gas, and propylene volumes (offset in marketing purchases).

Product costs increased primarily due to:


•	A $141 million increase in marketing purchases primarily due to the same factors that increased marketing sales (offset in marketing revenues). The increase in marketing costs does not reflect the intercompany costs associated with certain gathering and processing services performed by an affiliate;


•	An $81 million decrease in olefin feedstock purchases reflecting the sale of our Gulf Olefins and Canadian operations;


•	A $13 million decrease in natural gas purchases associated with the production of equity NGLs reflecting lower volumes as previously discussed, partially offset by a slight increase in per-unit natural gas prices.

The favorable change in Other segment costs and expenses includes the absence of the $32 million loss on the sale of our former Canadian operations in third-quarter 2016, the absence of $39 million of operating and other expenses associated with our Gulf Olefins and Canadian operations, favorable impacts related to gains on asset retirements, and ongoing cost containment efforts. These decreases are partially offset by an increase in pipeline integrity testing on Transco and costs associated with the closure of our office in Oklahoma City.

Gain on sale of Geismar Interest reflects the gain recognized on the sale of our Geismar Interest in July 2017. (See Note 3 – Divestitures of Notes to Consolidated Financial Statements.)

Impairment of certain assets increased primarily due to a $1.019 billion impairment of certain gathering operations in the Mid-Continent region, a $115 million impairment of certain gathering operations in the Marcellus South region,

Management’s Discussion and Analysis (Continued)

and write-downs of certain assets that are no longer in use or are surplus in nature. (See Note 11 – Fair Value Measurements and Guarantees of Notes to Consolidated Financial Statements.)

The increase in Proportional Modified EBITDA of equity-method investments includes a $31 million increase at Appalachian Midstream Investments reflecting our increased ownership and higher gathering volumes reflecting the absence of shut-in volumes from 2016 and increased customer production. This increase is partially offset by a $9 million decrease from Discovery primarily due to production issues on certain wells and temporary hurricane related shut-ins, an $8 million decrease at UEOM driven by lower processing volumes from the Utica gathering system, as noted above, and the divestiture of our interests in DBJV and Ranch Westex JV LLC late in the first quarter of 2017.

Nine months ended September 30, 2017 vs. nine months ended September 30, 2016

Modified EBITDA increased primarily due to a $1.095 billion gain on the sale of our Geismar Interest in third-quarter 2017, the absence of impairments of our Canadian operations and certain gathering assets in the Mid-Continent region in the second quarter of 2016, the absence of a loss on the sale of our former Canadian operations in third-quarter 2016, lower segment costs and expenses, higher service revenues, and higher Proportional Modified EBITDA of equity-method investments. These increases are partially offset by the impairments of certain gathering operations in 2017 and lower olefin margins due to the sale of our Gulf Olefins operations early in the third quarter of 2017.

Service revenues increased primarily due to:


•	A $158 million increase related to the amortization of deferred revenue associated with the up-front cash payment received in conjunction with the fourth quarter 2016 Barnett Shale contract restructuring;

•

Higher eastern Gulf Coast region revenue of $114 million associated primarily with higher volumes, including the impact of new volumes at Gulfstar One related to the Gunflint expansion placed in-service in the third quarter of 2016, the absence of the temporary shut-down and subsequent ramp-up of Gulfstar One in the second and third quarters of 2016 to tie-in Gunflint, and the absence of producers’ operational issues in the Tubular Bells field during the first quarter of 2016, along with higher volumes at Devils Tower related to Kodiak field production (although certain wells in this field are now shut-in due to production issues). This increase is partially offset by a $17 million decrease in western Gulf Coast region fee revenues due primarily to producer maintenance.


•	Transco’s natural gas transportation fee revenues increased $74 million primarily due to an $88 million increase associated with expansion projects placed in-service in 2016 and 2017, partially offset by lower volume-based transportation services revenues;


•	A $14 million increase in Transco’s storage revenue primarily reflecting the absence of an accrual for potential refunds associated with a ruling received in certain rate case litigation in 2016;

•

A $75 million decrease related to lower gathering rates in the West region including lower rates in the Barnett Shale area primarily due to the fourth quarter 2016 contract restructuring, along with lower rates recognized in the Niobrara, Eagle Ford Shale, and Haynesville Shale regions. Rates recognized in the Niobrara region represent a portion of the total contractual rate that is received, with the difference reflected as deferred revenue;


•	A $72 million decrease driven by lower volumes in the West region primarily as a result of natural declines and more extreme weather conditions in the Rocky Mountains in the first quarter of 2017;


•	A $36 million decrease due to the absence of revenue generated by our former Canadian operations that were sold in September 2016;


•	In the Northeast region, a slight decline reflecting a $52 million decrease in the Utica gathering system primarily due to 20 percent lower gathered volumes driven by natural declines in the wet gas areas which are partially offset by higher volumes from new development in the dry gas areas. This decrease is mostly offset by a $32

Management’s Discussion and Analysis (Continued)

million increase in gathering fee revenue at Susquehanna Supply Hub driven by 12 percent higher gathered volumes reflecting increased customer production, and a $22 million increase in fee revenue at Ohio Valley Midstream reflecting the absence of shut-in volumes from the first half of 2016, as well as new production coming online.

Product sales increased primarily due to:


•	A $520 million increase in marketing revenues primarily due to significantly higher prices and volumes (substantially offset in marketing purchases);

•

A $26 million increase in revenues from our equity NGLs including a $76 million increase driven by higher non-ethane prices, the effect of which is partially offset by a $36 million decrease due to the absence of NGL production revenues associated with our former Canadian operations and a $14 million decrease related to lower volumes at our domestic plants driven by severe winter conditions in the first quarter of 2017, the absence of temporary volumes in 2016 related to disrupted operations of a competitor and natural declines;


•	A $7 million increase in system management gas sales from Transco. System management gas sales are offset in Product costs and, therefore, have no impact on Modified EBITDA;

•

A $217 million decrease in olefin sales primarily due to a $180 million decrease reflecting the sale of our Gulf Olefins operations, a $29 million decrease due to the sale of the Canadian operations in 2016 and a $16 million decrease at our Geismar plant in the first half of 2017 due primarily to lower volumes associated with the electrical outage in second-quarter 2017, as well as planned maintenance downtime in first-quarter 2017. These items were partially offset by $8 million higher sales at the RGP Splitter in the first half 2017 due primarily to higher propylene prices.

Product costs increased primarily due to:


•	A $501 million increase in marketing purchases primarily due to the same factors that increased marketing sales (more than offset in marketing revenues). The increase in marketing costs does not reflect the intercompany costs associated with certain gathering and processing services performed by an affiliate;


•	A $7 million increase in system management gas costs (offset in Product sales);


•	A $5 million increase in natural gas purchases associated with the production of equity NGLs reflecting a significant increase in per-unit natural gas prices and increased sales from inventory, partially offset by a $24 million decrease due to the sale of our Canadian operations;


•	A $79 million decrease in olefin feedstock purchases primarily due to the absence of $76 million in feedstock purchases in third-quarter 2017 reflecting the sale of the Gulf Olefins operations as well as the absence of $9 million in costs associated with our former Canadian operations, partially offset by $6 million higher feedstock costs in the first half of 2017.

The favorable change in Other segment costs and expenses includes the absence of the $32 million loss on the sale of our former Canadian operations in third-quarter 2016, a reduction of $75 million of operating and other expenses associated with our Gulf Olefins and Canadian operations, a $27 million net gain associated with early debt retirement, a decrease in labor-related expenses resulting from our first quarter 2016 workforce reduction, favorable contract settlements and terminations in the first quarter of 2017, a $12 million gain on the sale of the RGP Splitter, and a favorable change in equity AFUDC, primarily associated with an increase in Transco’s capital spending, which is partially offset by a decrease in capital spending at Constitution. These decreases in expenses are partially offset by an increase in pipeline integrity testing on Transco, higher Geismar selling expenses, repairs related to the Geismar electrical outage, and expenses associated with the closure of our office in Oklahoma City.

Management’s Discussion and Analysis (Continued)

Gain on sale of Geismar Interest reflects the gain recognized on the sale of our Geismar Interest in July 2017. (See Note 3 – Divestitures of Notes to Consolidated Financial Statements.)

Impairment of certain assets increased primarily due to a $1.019 billion impairment of certain gathering operations in the Mid-Continent and a $115 million impairment of certain gathering operations in the Marcellus South region, partially offset by the absence of a $341 million impairment of our former Canadian operations and a $48 million impairment of certain Mid-Continent gathering assets in the second quarter of 2016. (See Note 11 – Fair Value Measurements and Guarantees of Notes to Consolidated Financial Statements.)

The increase in Proportional Modified EBITDA of equity-method investments includes a $60 million increase at Appalachia Midstream Investments primarily due to our increased ownership late in the first quarter of 2017 and higher gathering volumes reflecting the absence of shut-in volumes from 2016 and increased customer production; a $10 million increase at Laurel Mountain Midstream associated with higher gathering revenue due to higher rates reflecting higher natural gas prices; an $8 million increase from Discovery primarily attributable to the accelerated recognition of previously deferred revenue and higher NGL margins, partially offset by lower fee revenue driven by production issues at certain wells, higher turbine maintenance expenses, temporary hurricane-related shut-ins, and maintenance on the Keathley Canyon Connector pipeline. These increases are partially offset by a $29 million decrease at UEOM reflecting lower processing volumes from the wet gas areas of the Utica gathering system as noted above and the divestiture of our interests in DBJV and Ranch Westex JV LLC late in the first quarter of 2017.

Other



	Three Months Ended September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016
	(Millions)
Service revenues	$	8		$	9		$	25		$	39
Product sales	—			9			—			26
Segment revenues	8			18			25			65

Product costs	—			(4		)	—			(13		)
Other segment costs and expenses	(1		)	(81		)	6			(178		)
Impairment of certain assets	(68		)	—			(91		)	(408		)
Other Modified EBITDA	$	(61	)	$	(67	)	$	(60	)	$	(534	)

Three months ended September 30, 2017 vs. three months ended September 30, 2016

Modified EBITDA improved primarily due to lower Other segment costs and expenses, partially offset by the impairment of a certain NGL pipeline.

Other segment costs and expenses improved primarily due to:


•	The absence of a $33 million loss on the sale of our Canadian operations in September 2016;


•	The absence of $16 million of certain project development costs associated with the Canadian PDH facility that we expensed in 2016;


•	A $16 million decrease in costs related to our evaluation of strategic alternatives;


•	The absence of $11 million of transportation and fractionation fees incurred in 2016 related to the Redwater fractionation facility, which was included in the sale of our Canadian operations in September 2016.

Impairment of certain assets increased due to the impairment of a certain NGL pipeline asset in the third quarter of 2017. (See Note 11 – Fair Value Measurements and Guarantees of Notes to Consolidated Financial Statements.)

Management’s Discussion and Analysis (Continued)

Nine months ended September 30, 2017 vs. nine months ended September 30, 2016

Modified EBITDA improved primarily due to the absence of a second-quarter 2016 impairment of our former Canadian operations and improved Other segment costs and expenses.

Service revenues decreased primarily due to a reduction in Canadian construction management revenues.

Product sales and Product costs decreased due to the sale of the Horizon liquids extraction plant in September 2016.

Other segment costs and expenses changed favorably primarily due to:


•	The absence of $61 million of certain project development costs associated with the Canadian PDH facility that we expensed in 2016;


•	A $32 million favorable change in the loss on the sale of our Canadian operations in September 2016;


•	The absence of $32 million of transportation and fractionation fees incurred in 2016 related to the Redwater fractionation facility, which was included in the sale of our Canadian operations in September 2016;


•	A $31 million decrease in costs related to our evaluation of strategic alternatives;


•	A $28 million increase in income associated with an increase in a regulatory asset primarily driven by our increased ownership in WPZ. (See Note 5 – Other Income and Expenses of Notes to Consolidated Financial Statements).

Impairment of certain assets decreased primarily due to the absence of the 2016 impairment of our Canadian operations, partially offset by the impairment of an olefins pipeline project in the Gulf Coast region in the second quarter of 2017 and the impairment of a certain NGL pipeline asset in the third quarter of 2017. (See Note 11 – Fair Value Measurements and Guarantees of Notes to Consolidated Financial Statements.)

Management’s Discussion and Analysis (Continued)

Management’s Discussion and Analysis of Financial Condition and Liquidity

Outlook

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

As previously discussed in Company Outlook, our consolidated growth capital and investment expenditures are expected to be between $2.1 billion and $2.8 billion in 2017. Approximately $1.4 billion to $1.9 billion of our growth capital funding needs include Transco expansions and other interstate pipeline growth projects, most of which are fully contracted with firm transportation agreements. The remaining growth capital spending in 2017 primarily reflects investment in gathering and processing systems in the Northeast region limited primarily to known new producer volumes, including volumes that support Transco expansion projects including our Atlantic Sunrise project. In addition to growth capital and investment expenditures, we also remain committed to projects that maintain our assets for safe and reliable operations, as well as projects that meet legal, regulatory, and/or contractual commitments. We retain the flexibility to adjust planned levels of capital and investment expenditures in response to changes in economic conditions or business opportunities.

Liquidity

Based on our forecasted levels of cash flow from operations and other sources of liquidity, we expect to have sufficient liquidity to manage our businesses in 2017. WPZ expects to be self-funding and maintain separate bank accounts and credit facilities, including its commercial paper program. Our expected material internal and external sources and uses of consolidated liquidity for 2017 are as follows:



		Applicable To:
		WPZ	WMB
Sources:
	Cash and cash equivalents on hand	ü	ü
	Cash generated from operations	ü
	Distributions from investment in WPZ		ü
	Distributions from equity-method investees	ü
	Utilization of credit facilities and/or commercial paper program	ü	ü
	Cash proceeds from issuance of debt and/or equity securities	ü	ü
	Proceeds from asset monetizations	ü

Uses:
	Working capital requirements	ü	ü
	Capital and investment expenditures	ü
	Investment in WPZ		ü
	Quarterly distributions to unitholders	ü
	Quarterly dividends to shareholders		ü
	Debt service payments, including payments of long-term debt	ü	ü

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

Management’s Discussion and Analysis (Continued)

As of September 30, 2017, we had a working capital deficit of $61 million. Our available liquidity is as follows:



	September 30, 2017
Available Liquidity	WPZ		WMB		Total
	(Millions)
Cash and cash equivalents	$	1,165	$	7	$	1,172
Capacity available under our $1.5 billion credit facility (1)			1,100		1,100
Capacity available to WPZ under its $3.5 billion credit facility, less amounts outstanding under its $3 billion commercial paper program (2)	3,500				3,500
	$	4,665	$	1,107	$	5,772


(1)	Through September 30, 2017, the highest amount outstanding under our credit facility during 2017 was $805 million. At September 30, 2017, we were in compliance with the financial covenants associated with this credit facility. Borrowing capacity available under this facility as of October 31, 2017, was $1.125 billion.

(2)

In managing our available liquidity, we do not expect a maximum outstanding amount in excess of the capacity of WPZ’s credit facility inclusive of any outstanding amounts under its commercial paper program. As of September 30, 2017, no Commercial paper was outstanding under WPZ’s commercial paper program. Through September 30, 2017, the highest amount outstanding under WPZ’s commercial paper program and credit facility during 2017 was $178 million. At September 30, 2017, WPZ was in compliance with the financial covenants associated with this credit facility. Borrowing capacity available under WPZ’s $3.5 billion credit facility as of October 31, 2017, was $3.5 billion.

Dividends

As part of the Financial Repositioning announced in January 2017, we increased our regular quarterly cash dividend by 50 percent from the previous quarterly dividend of $0.20 per share paid in December 2016, to $0.30 per share for the dividends paid in March 2017, June 2017, and September 2017.

Registrations

In September 2016, WPZ filed a registration statement for its distribution reinvestment program.

In May 2015, we filed a shelf registration statement, as a well-known seasoned issuer.

In February 2015, WPZ filed a shelf registration statement, as a well-known seasoned issuer, registering common units representing limited partner interests and debt securities. Also in February 2015, WPZ filed a shelf registration statement for the offer and sale from time to time of common units representing limited partner interests in WPZ having an aggregate offering price of up to $1 billion. These sales are to be made over a period of time and from time to time in transactions at prices which are market prices prevailing at the time of sale, prices related to market price, or at negotiated prices. Such sales are to be made pursuant to an equity distribution agreement between WPZ and certain banks who may act as sales agents or purchase for their own accounts as principals.

Distributions from Equity-Method Investees

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

Management’s Discussion and Analysis (Continued)

Credit Ratings

Our ability to borrow money is impacted by our credit ratings and the credit ratings of WPZ. The current ratings are as follows:



	Rating Agency	Outlook	Senior Unsecured Debt Rating	Corporate Credit Rating
WMB:	S&P Global Ratings	Stable	BB+	BB+
	Moody’s Investors Service	Positive	Ba2	N/A
	Fitch Ratings	Stable	BB+	N/A

WPZ:	S&P Global Ratings	Stable	BBB	BBB
	Moody’s Investors Service	Positive	Baa3	N/A
	Fitch Ratings	Positive	BBB-	N/A

During March 2017, S&P Global Ratings upgraded its rating for both WMB and WPZ. In July 2017, Fitch Ratings changed its Outlook for WPZ to Positive, and in September 2017, Moody’s Investors Service changed its Outlook for both WMB and WPZ to Positive. These credit ratings are included for informational purposes and are not recommendations to buy, sell, or hold our stock, and each rating should be evaluated independently of any other rating. No assurance can be given that the credit rating agencies will continue to assign us or WPZ the ratings shown above even if we or WPZ meet or exceed their current criteria. A downgrade of our credit ratings or the credit ratings of WPZ might increase our future cost of borrowing and would require us to provide additional collateral to third parties, negatively impacting our available liquidity.

Management’s Discussion and Analysis (Continued)

Sources (Uses) of Cash

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



	Cash Flow	Nine Months Ended September 30,
	Category	2017			2016
		(Millions)
Sources of cash and cash equivalents:
Operating activities – net	Operating	$	1,837		$	2,097
Proceeds from equity offerings	Financing	2,130			8
Proceeds from sale of businesses, net of cash divested (see Note 3)	Investing	2,056			712
Proceeds from long-term debt (see Note 9)	Financing	1,698			998
Proceeds from our credit-facility borrowings	Financing	1,315			2,045
Distributions from unconsolidated affiliates in excess of cumulative earnings	Investing	394			341
Proceeds from dispositions of equity-method investments (see Note 4)	Investing	200			—
Proceeds from WPZ’s credit-facility borrowings	Financing	—			2,665

Uses of cash and cash equivalents:
Payments of long-term debt (see Note 9)	Financing	(3,785		)	(375		)
Capital expenditures	Investing	(1,700		)	(1,577		)
Payments on our credit-facility borrowings	Financing	(1,690		)	(1,845		)
Quarterly dividends on common stock	Financing	(744		)	(1,111		)
Dividends and distributions to noncontrolling interests	Financing	(636		)	(715		)
Purchases of and contributions to equity-method investments	Investing	(103		)	(132		)
Payments of WPZ’s commercial paper – net	Financing	(93		)	(499		)
Payments on WPZ’s credit-facility borrowings	Financing	—			(2,745		)
Contribution to Gulfstream for repayment of debt	Financing	—			(148		)

Other sources / (uses) – net	Financing and Investing	123			258
Increase (decrease) in cash and cash equivalents		$	1,002		$	(23	)

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, Net (gain) loss on disposition of equity-method investments, Impairment of equity-method investments, Gain on sale of Geismar Interest, and Impairment of and net (gain) loss on sale of assets and businesses. Our Net cash provided (used) by operating activities for the nine months ended September 30, 2017, decreased from the same period in 2016 primarily due to the absence in 2017 of certain minimum volume commitment receipts due to contract restructurings, partially offset by higher operating income in 2017.

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

We have various other guarantees and commitments which are disclosed in Note 2 – Variable Interest Entities, Note 9 – Debt and Banking Arrangements, Note 11 – Fair Value Measurements and Guarantees, and Note 12 – Contingent Liabilities of Notes to Consolidated Financial Statements. We do not believe these guarantees and commitments or the possible fulfillment of them will prevent us from meeting our liquidity needs.

Item 3

Quantitative and Qualitative Disclosures About Market Risk

Interest Rate Risk

Our current interest rate risk exposure is related primarily to our debt portfolio and has not materially changed during the first nine months of 2017.

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

Evaluation of Disclosure Controls and Procedures

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

Changes in Internal Control Over Financial Reporting

There have been no changes during the third quarter of 2017 that have materially affected, or are reasonably likely to materially affect, our Internal Control over Financial Reporting.

PART II. OTHER INFORMATION

Item 1. Legal Proceedings

Environmental

Certain reportable legal proceedings involving governmental authorities under federal, state, and local laws regulating the discharge of materials into the environment are described below. While it is not possible for us to predict the final outcome of the proceedings which are still pending, we do not anticipate a material effect on our consolidated financial position if we receive an unfavorable outcome in any one or more of such proceedings.

On February 21, 2017, we received notice from the Environmental Enforcement Section of the United States Department of Justice (DOJ) regarding certain alleged violations of the Clean Air Act at our Moundsville facility as set forth in a Notice of Noncompliance issued by the EPA on January 14, 2016. The notice includes an offer to avoid further legal action on the alleged violations by paying $2 million. In discussion with the DOJ and the EPA, the EPA has indicated its belief that additional similar violations have occurred at our Oak Grove facility and has expressed interest in pursuing a global settlement. We have requested an assessment of proposed civil penalties for violations alleged at Oak Grove. Once we have received the new demand, we will evaluate the penalty assessment and any proposed global settlement and will respond to the agencies.

On May 5, 2017, we entered into a Consent Order with the Georgia Department of Natural Resources, Environmental Protection Division (GEPD) pertaining to alleged violations of the Georgia Water Quality Control Act and associated rules arising from a permit issued by GEPD for construction of the Dalton Project. Pursuant to the Consent Order, we paid a fine of $168,750 and agreed to perform a Corrective Action Order to remedy the alleged violations.

Other

The additional information called for by this item is provided in Note 12 – Contingent Liabilities of Notes to Consolidated Financial Statements included under Part I, Item 1. Financial Statements of this report, which information is incorporated by reference into this item.

Item 6. Exhibits



Exhibit No.		Description

2.1+	—	Agreement and Plan of Merger dated as of May 12, 2015, by and among The Williams Companies, Inc., SCMS LLC, Williams Partners L.P., and WPZ GP LLC (filed on May 13, 2015 as Exhibit 2.1 to The Williams Companies, Inc.’s current report on Form 8-K (File No. 001-04174) and incorporated herein by reference).
2.2	—	Amendment No 1. to Agreement and Plan of Merger dated as of May 1, 2016, by and among The Williams Companies, Inc., Energy Transfer Corp LP, Energy Transfer Corp GP, LLC, Energy Transfer Equity, L.P., LE GP, LLC and Energy Transfer Equity GP, LLC (filed on May 3, 2016 as Exhibit 2.1 to The Williams Companies, Inc.’s current report on Form 8-K (File No. 001-04174) and incorporated herein by reference).
2.3+	—	Agreement and Plan of Merger dated as of September 28, 2015, by and among The Williams Companies, Inc., Energy Transfer Corp LP, Energy Transfer Corp GP, LLC, Energy Transfer Equity, L.P., LE GP, LLC and Energy Transfer Equity GP, LLC (filed on October 1, 2015 as Exhibit 2.1 to The Williams Companies, Inc.’s current report on Form 8-K (File No. 001-04174) and incorporated herein by reference).
2.4+	—	Membership Interest Purchase Agreement, dated as of April 13, 2017, among Williams Field Services Group, LLC, Williams Partners L.P., Williams Olefins, L.L.C., NOVA Chemicals Inc., and NOVA Chemicals Corporation (filed on August 3, 2017 as Exhibit 2.2 to Williams Partners L.P.’s quarterly report on Form 10-Q (File No. 001-34831) and incorporated herein by reference).
3.1	—	Amended and Restated Certificate of Incorporation as supplemented (filed on May 26, 2010, as Exhibit 3.1 to The Williams Companies, Inc.’s current report on Form 8-K (File No. 001-04174) and incorporated herein by reference).
3.2	—	By-Laws (filed on January 20, 2017, as Exhibit 3.1 to The Williams Companies, Inc.’s current report on Form 8-K (File No. 001-04174) and incorporated herein by reference).
10.1	—	Termination Agreement and Release, dated as of September 28, 2015, by and among The Williams Companies, Inc., SCMS LLC, Williams Partners L.P. and WPZ GP LLC (filed on September 28, 2015 as Exhibit 10.1 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-34831) and incorporated herein by reference).
12*	—	Computation of Ratio of Earnings to Fixed Charges.
31.1*	—	Certification of Chief Executive Officer pursuant to Rules 13a-14(a) and 15d-14(a) promulgated under the Securities Exchange Act of 1934, as amended, and Item 601(b)(31) of Regulation S-K, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*	—	Certification of Chief Financial Officer pursuant to Rules 13a-14(a) and 15d-14(a) promulgated under the Securities Exchange Act of 1934, as amended, and Item 601(b)(31) of Regulation S-K, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32**	—	Certification of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS*	—	XBRL Instance Document.
101.SCH*	—	XBRL Taxonomy Extension Schema.
101.CAL*	—	XBRL Taxonomy Extension Calculation Linkbase.
101.DEF*	—	XBRL Taxonomy Extension Definition Linkbase.



Exhibit No.		Description

101.LAB*	—	XBRL Taxonomy Extension Label Linkbase.
101.PRE*	—	XBRL Taxonomy Extension Presentation Linkbase.

* Filed herewith.

** Furnished herewith.


§	Management contract or compensatory plan or arrangement.


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

SIGNATURE

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



	THE WILLIAMS COMPANIES, INC.
	(Registrant)

	/s/ TED T. TIMMERMANS
	Ted T. Timmermans
	Vice President, Controller and Chief Accounting Officer (Duly Authorized Officer and Principal Accounting Officer)

November 2, 2017