WILLIAMS PARTNERS L.P. - FORM 10-Q

Attached files

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EX-31.1 - EX-31.1 - WILLIAMS PARTNERS L.P.	wpz_20170930xex311.htm
EX-32 - EX-32 - WILLIAMS PARTNERS L.P.	wpz_20170930xex32.htm
EX-31.2 - EX-31.2 - WILLIAMS PARTNERS L.P.	wpz_20170930xex312.htm
EX-12 - EX-12 - WILLIAMS PARTNERS L.P.	wpz_20170930xex12.htm

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 1-34831

WILLIAMS PARTNERS L.P.

(Exact name of registrant as specified in its charter)



DELAWARE		20-2485124
(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

The registrant had 956,238,020 common units and 17,583,753 Class B units outstanding as of October 30, 2017.

Williams Partners L.P.

Index



Part I. Financial Information		Page
Item 1. Financial Statements
Consolidated Statement of Comprehensive Income (Loss) – Three and Nine Months Ended September 30, 2017 and 2016		6
Consolidated Balance Sheet – September 30, 2017 and December 31, 2016		7
Consolidated Statement of Changes in Equity – Nine Months Ended September 30, 2017		8
Consolidated Statement of Cash Flows – Nine Months Ended September 30, 2017 and 2016		9
Notes to Consolidated Financial Statements		10
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		29
Item 3. Quantitative and Qualitative Disclosures About Market Risk		55
Item 4. Controls and Procedures		55
Part II. Other Information		55
Item 1. Legal Proceedings		55
Item 6. Exhibits		57

The reports, filings, and other public announcements of Williams Partners L.P. (WPZ) 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.

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


•	Levels of cash distributions with respect to limited partner interests;


•	Our and our affiliates’ future credit ratings;


•	Amounts and nature of future capital expenditures;


•	Expansion and growth of our business and operations;


•	Expected in-service dates for capital projects;


•	Financial condition and liquidity;


•	Business strategy;


•	Cash flow from operations or results of operations;


•	Seasonality of certain business components;


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


•	Demand for our services.

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


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


•	Whether we elect to pay expected levels of cash distributions;


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


•	Whether Williams will be able to effectively manage the transition in its board of directors and management as well as successfully execute its 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 for defined benefit pension plans and other postretirement benefit plans sponsored by our affiliates;


•	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.

Limited partner units are inherently different from the capital stock of a corporation, although many of the business risks to which we are subject are similar to those that would be faced by a corporation engaged in a similar business. You should carefully consider our risk factors in addition to the other information in this report. If any of the risks to which we are exposed were actually to occur, our business, results of operations, and financial condition could be materially adversely affected. In that case, we might not be able to pay distributions on our common units, the trading price of our common units could decline, and unitholders could lose all or part of their investment.

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

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:

Williams: The Williams Companies, Inc. and, unless the context otherwise indicates, its subsidiaries (other than Williams Partners L.P. and its subsidiaries)

GAAP: U.S. generally accepted accounting principles

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

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

RGP Splitter: Refinery grade propylene splitter

PART I – FINANCIAL INFORMATION

Williams Partners L.P.

Consolidated Statement of Comprehensive Income (Loss)

(Unaudited)



	Three Months Ended September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016
	(Millions, except per-unit amounts)
Revenues:
Service revenues	$	1,304		$	1,252		$	3,837		$	3,688
Product sales	581			655			1,950			1,613
Total revenues	1,885			1,907			5,787			5,301
Costs and expenses:
Product costs	504			463			1,620			1,183
Operating and maintenance expenses	396			385			1,141			1,153
Depreciation and amortization expenses	424			426			1,280			1,293
Selling, general, and administrative expenses	140			147			450			467
Gain on sale of Geismar Interest (Note 3)	(1,095		)	—			(1,095		)	—
Impairment of certain assets (Note 10)	1,142			1			1,145			403
Other (income) expense – net	22			59			32			107
Total costs and expenses	1,533			1,481			4,573			4,606
Operating income (loss)	352			426			1,214			695
Equity earnings (losses)	115			104			347			302
Impairment of equity-method investments (Note 10)	—			—			—			(112		)
Other investing income (loss) – net (Note 5)	4			28			277			29
Interest incurred	(210		)	(236		)	(645		)	(715		)
Interest capitalized	8			7			24			26
Other income (expense) – net	14			16			78			43
Income (loss) before income taxes	283			345			1,295			268
Provision (benefit) for income taxes	(1		)	(6		)	3			(85		)
Net income (loss)	284			351			1,292			353
Less: Net income (loss) attributable to noncontrolling interests	25			25			79			67
Net income (loss) attributable to controlling interests	$	259		$	326		$	1,213		$	286
Allocation of net income (loss) for calculation of earnings per common unit:
Net income (loss) attributable to controlling interests	$	259		$	326		$	1,213		$	286
Allocation of net income (loss) to general partner	—			72			—			481
Allocation of net income (loss) to Class B units	4			7			21			(6		)
Allocation of net income (loss) to common units	$	255		$	247		$	1,192		$	(189	)
Basic earnings (loss) per common unit:
Net income (loss) per common unit	$	.27		$	.42		$	1.26		$	(.32	)
Weighted-average number of common units outstanding (thousands)	956,047			591,304			944,008			589,498
Diluted earnings (loss) per common unit:
Net income (loss) per common unit	$	.27		$	.42		$	1.26		$	(.32	)
Weighted-average number of common units outstanding (thousands)	956,365			591,567			944,333			589,498
Cash distributions per common unit	$	.60		$	.85		$	1.80		$	2.55

Other comprehensive income (loss):
Cash flow hedging activities:
Net unrealized gain (loss) from derivative instruments	$	(10	)	$	2		$	(6	)	$	2
Reclassifications into earnings of net derivative instruments (gain) loss	1			—			(1		)	—
Foreign currency translation activities:
Foreign currency translation adjustments	—			(16		)	—			61
Reclassification into earnings upon sale of foreign entity	—			108			—			108
Other comprehensive income (loss)	(9		)	94			(7		)	171
Comprehensive income (loss)	275			445			1,285			524
Less: Comprehensive income attributable to noncontrolling interests	25			25			79			67
Comprehensive income (loss) attributable to controlling interests	$	250		$	420		$	1,206		$	457

See accompanying notes.

Williams Partners L.P.

Consolidated Balance Sheet

(Unaudited)



	September 30, 2017			December 31, 2016
	(Dollars in millions)
ASSETS
Current assets:
Cash and cash equivalents	$	1,165		$	145
Trade accounts and other receivables (net of allowance of $6 at September 30, 2017 and $6 at December 31, 2016)	778			926
Inventories	144			138
Other current assets and deferred charges	183			205
Total current assets	2,270			1,414
Investments	6,615			6,701
Property, plant, and equipment	38,140			38,247
Accumulated depreciation and amortization	(10,729		)	(10,226		)
Property, plant, and equipment – net	27,411			28,021
Intangible assets – net of accumulated amortization	8,872			9,662
Regulatory assets, deferred charges, and other	467			467
Total assets	$	45,635		$	46,265
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable:
Trade	$	751		$	589
Affiliate	79			109
Accrued interest	160			258
Asset retirement obligations	37			61
Other accrued liabilities	621			804
Commercial paper	—			93
Long-term debt due within one year	502			785
Total current liabilities	2,150			2,699
Long-term debt	16,000			17,685
Asset retirement obligations	876			798
Deferred income tax liabilities	14			20
Regulatory liabilities, deferred income, and other	1,986			1,860
Contingent liabilities (Note 11)
Equity:
Partners’ equity:
Common units (956,237,532 and 607,064,550 units outstanding at September 30, 2017 and December 31, 2016, respectively)	22,143			18,300
Class B units (17,583,753 and 16,690,016 units outstanding at September 30, 2017 and December 31, 2016, respectively)	790			769
General partner	—			2,385
Accumulated other comprehensive income (loss)	(8		)	(1		)
Total partners’ equity	22,925			21,453
Noncontrolling interests in consolidated subsidiaries	1,684			1,750
Total equity	24,609			23,203
Total liabilities and equity	$	45,635		$	46,265

See accompanying notes.

Williams Partners L.P.

Consolidated Statement of Changes in Equity

(Unaudited)



	Williams Partners L.P.
	Limited Partners
	Common Units			Class B Units		General Partner			Accumulated Other Comprehensive Income (Loss)			Total Partners’ Equity			Noncontrolling Interests			Total Equity
	(Millions)
Balance – December 31, 2016	$	18,300		$	769	$	2,385		$	(1	)	$	21,453		$	1,750		$	23,203
Net income (loss)	1,192			21		—			—			1,213			79			1,292
Other comprehensive income (loss)	—			—		—			(7		)	(7		)	—			(7		)
Conversion to noneconomic general partner interest (Note 1)	2,385			—		(2,385		)	—			—			—			—
Distributions to The Williams Companies, Inc. - net	(5		)	—		—			—			(5		)	—			(5		)
Sale of common units (Note 9)	2,227			—		—			—			2,227			—			2,227
Distributions to limited partners	(1,959		)	—		—			—			(1,959		)	—			(1,959		)
Contributions from noncontrolling interests	—			—		—			—			—			15			15
Distributions to noncontrolling interests	—			—		—			—			—			(160		)	(160		)
Other	3			—		—			—			3			—			3
Net increase (decrease) in equity	3,843			21		(2,385		)	(7		)	1,472			(66		)	1,406
Balance – September 30, 2017	$	22,143		$	790	$	—		$	(8	)	$	22,925		$	1,684		$	24,609

See accompanying notes.

Williams Partners L.P.

Consolidated Statement of Cash Flows

(Unaudited)



	Nine Months Ended September 30,
	2017			2016
	(Millions)
OPERATING ACTIVITIES:
Net income (loss)	$	1,292		$	353
Adjustments to reconcile to net cash provided (used) by operating activities:
Depreciation and amortization	1,280			1,293
Provision (benefit) for deferred income taxes	(6		)	(86		)
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	1,132			438
Amortization of stock-based awards	6			17
Cash provided (used) by changes in current assets and liabilities:
Accounts and notes receivable	111			175
Inventories	(23		)	(2		)
Other current assets and deferred charges	(11		)	(9		)
Accounts payable	54			(22		)
Accrued liabilities	(90		)	194
Affiliate accounts receivable and payable – net	(30		)	(84		)
Other, including changes in noncurrent assets and liabilities	(248		)	(28		)
Net cash provided (used) by operating activities	2,103			2,351
FINANCING ACTIVITIES:
Proceeds from (payments of) commercial paper – net	(93		)	(499		)
Proceeds from long-term debt	1,698			3,663
Payments of long-term debt	(3,785		)	(3,121		)
Proceeds from sales of common units	2,184			250
Contributions from general partner	—			14
Distributions paid	(1,916		)	(1,956		)
Distributions to noncontrolling interests	(160		)	(69		)
Contributions from noncontrolling interests	15			27
Distributions to The Williams Companies, Inc. – net	(5		)	—
Payments for debt issuance costs	(14		)	(8		)
Contribution to Gulfstream for repayment of debt	—			(148		)
Other – net	(79		)	(12		)
Net cash provided (used) by financing activities	(2,155		)	(1,859		)
INVESTING ACTIVITIES:
Property, plant, and equipment:
Capital expenditures (1)	(1,687		)	(1,472		)
Dispositions – net	(27		)	5
Proceeds from sale of businesses, net of cash divested	2,058			510
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	237			228
Net cash provided (used) by investing activities	1,072			(520		)
Increase (decrease) in cash and cash equivalents	1,020			(28		)
Cash and cash equivalents at beginning of year	145			96
Cash and cash equivalents at end of period	$	1,165		$	68
_________
(1) Increases to property, plant, and equipment	$	(1,815	)	$	(1,429	)
Changes in related accounts payable and accrued liabilities	128			(43		)
Capital expenditures	$	(1,687	)	$	(1,472	)

See accompanying notes.

Williams Partners L.P.

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 “we,” “our,” “us,” or like terms refer to Williams Partners L.P. (WPZ) and its subsidiaries. Unless the context clearly indicates otherwise, references to “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.

We are a Delaware limited partnership whose common units are listed and traded on the New York Stock Exchange. WPZ GP LLC, a Delaware limited liability company wholly owned by The Williams Companies, Inc. (Williams), serves as our general partner. Our operations are located in the United States.

Financial Repositioning

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

Description of Business

Effective January 1, 2017, we implemented organizational changes, consistent with the manner in which our chief operating decision maker evaluates performance and allocates resources. Operations previously reported within the Central segment are now generally managed and presented within the West segment. Certain businesses previously reported within our NGL & Petchem Services segment are now managed and presented within the West, Atlantic-Gulf, and Northeast G&P segments. As a result, beginning with the reporting of first-quarter 2017, our operations are organized into the following reportable segments: Northeast G&P, Atlantic-Gulf, West, and NGL & Petchem Services. Certain other corporate activities are included in Other. Prior period segment disclosures have been recast for these segment changes.

Northeast G&P is comprised of our midstream gathering and processing businesses in the Marcellus Shale region primarily in Pennsylvania, New York, and West Virginia and the Utica Shale region of eastern Ohio, as well as a 66 percent interest in Cardinal Gas Services, L.L.C. (Cardinal) (a consolidated entity), a 62 percent equity-method investment in Utica East Ohio Midstream, LLC (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),

Notes (Continued)

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).

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

West is comprised of our interstate natural gas pipeline, Northwest Pipeline LLC (Northwest Pipeline), and our gathering, processing, and treating operations in New Mexico, Colorado, and Wyoming, as well as the Barnett Shale region of north-central Texas, the Eagle Ford Shale region of south Texas, the Haynesville Shale region of northwest Louisiana, and the Mid-Continent region which includes the Anadarko, Arkoma, Delaware, and Permian basins. This segment also includes our NGL and natural gas marketing business, storage facilities, an undivided 50 percent interest in an NGL fractionator near Conway, Kansas, and a 50 percent equity-method investment in Overland Pass Pipeline, LLC (OPPL), 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 5 – Investing Activities).

NGL & Petchem Services is comprised of previously owned operations, including our 88.5 percent undivided interest in an olefins production facility in Geismar, Louisiana, which was sold in July 2017 (see Note 3 – Divestitures), and our refinery grade propylene splitter in the Gulf region, which was sold in June 2017. This segment also includes our previously owned Canadian assets, which included an oil sands offgas processing plant located near Fort McMurray, Alberta, and a natural gas liquid (NGL)/olefin fractionation facility at Redwater, Alberta. In September 2016, these Canadian operations were sold.

Basis of Presentation

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). Among other changes, 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 the periods presented.

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.

Notes (Continued)

In January 2017, the FASB issued Accounting Standards Update (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 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 West 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

Notes (Continued)

and timing of revenue recognition. We continue to develop and evaluate disclosures required under the new standard, 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.

Public Unit Exchange

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

On September 28, 2015, we entered into a Termination Agreement and Release (Termination Agreement), terminating the WPZ Public Unit Exchange. Under the terms of the Termination Agreement, Williams was required to pay us a $428 million termination fee, which settled through a reduction of quarterly incentive distributions payable to Williams (such reduction not to exceed $209 million per quarter). Our November 2015, February 2016, and May 2016 distributions to Williams were reduced by $209 million, $209 million, and $10 million, respectively, related to this termination fee.

Note 2 – Variable Interest Entities

As of September 30, 2017, we consolidate the following variable interest entities (VIEs):

Gulfstar One

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

Constitution

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

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.

Notes (Continued)

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

We own a 66 percent interest in Cardinal, a subsidiary that provides gathering services for the Utica Shale region and is a VIE due to certain risks shared with customers. We are the primary beneficiary because we have the power to direct the activities that most significantly impact Cardinal’s economic performance. We expect to fund future expansion activity with capital contributions from us and the other equity partner on a proportional basis.

Jackalope

We own 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. We are the primary beneficiary because we have the power to direct the activities that most significantly impact Jackalope’s economic performance. We expect to fund future expansion activity with capital contributions from us and the other equity partner on a proportional basis.

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



	September 30, 2017			December 31, 2016			Classification
	(Millions)
Assets (liabilities):
Cash and cash equivalents	$	42		$	82		Cash and cash equivalents
Accounts receivable	77			91			Trade accounts and other receivables
Prepaid assets	1			3			Other current assets and deferred charges
Property, plant, and equipment – net	2,921			3,024			Property, plant, and equipment – net
Intangible assets – net	1,394			1,431			Intangible assets – net of accumulated amortization
Accounts payable	(18		)	(44		)	Accounts payable – trade
Accrued liabilities	(3		)	(3		)	Other accrued liabilities
Current deferred revenue	(58		)	(63		)	Other accrued liabilities
Noncurrent asset retirement obligations	(102		)	(99		)	Asset retirement obligations
Noncurrent deferred revenue associated with customer advance payments	(313		)	(324		)	Regulatory liabilities, deferred income, and other

Note 3 – Divestitures

On July 6, 2017, we completed the sale of Williams Olefins, L.L.C., a wholly owned subsidiary which owned our 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. The assets and liabilities of the Geismar olefins plant were designated as held for sale within the NGL & Petchem Services segment during the first quarter of 2017. Upon closing of the sale, we entered into a long-term supply and transportation agreement with the purchaser to provide feedstock to the plant via our Bayou Ethane pipeline system. As a result of this sale, we recorded a gain of $1.095 billion in the third quarter of 2017. Following this sale, the cash proceeds were used to repay our $850 million term loan. We also plan to use these proceeds to fund a portion of the capital and investment expenditures that are a part of our 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

In September 2016, we completed the sale of subsidiaries conducting Canadian operations (such subsidiaries, the Canadian disposal group). Consideration received totaled $672 million, net of $13 million of cash divested and subject to customary working capital adjustments. Consideration also included $150 million in the form of a waiver of incentive distributions otherwise payable to Williams in the fourth quarter of 2016. The waiver recognized certain affiliate contracts wherein our Canadian operations provided services to Williams. 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 $341 million, reflected in Impairment of certain assets in the Consolidated Statement of Comprehensive Income (Loss). (See Note 10 - Fair Value Measurements.) Upon completion of the sale, we recorded an additional loss of $32 million at our NGL & Petchem Services segment for the three and nine months ended September 30, 2016, primarily reflecting revisions to the sales price and including an $11 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 Comprehensive Income (Loss).

The following table presents the results of operations for the Canadian 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	$	—	$	16	$	—	$	(9	)

Note 4 – Allocation of Net Income (Loss) and Distributions

The components of Net income (loss) within Equity are as follows:



	Three Months Ended September 30,				Nine Months Ended September 30,
	2017		2016		2017		2016
	(Millions)
Net income (loss) allocated to common limited partners’ equity (1)	$	255	$	106	$	1,192	$	(132	)
Net income (loss) allocated to Class B limited partners’ equity	4		3		21		(4		)
Net income (loss) allocated to general partner’s equity (1) (2)	—		217		—		422
Net income (loss) attributable to noncontrolling interests	25		25		79		67
Net income (loss)	$	284	$	351	$	1,292	$	353

(1)

Net income (loss) allocated to equity accounts above considers distributions paid to partners during the current reporting period, while Net income (loss) allocated within the Consolidated Statement of Comprehensive Income (Loss) considers distributions declared for the current reporting period, but paid in the subsequent period. The differences between Net income (loss) allocated to equity accounts and Net income (loss) allocated within the

Notes (Continued)

Consolidated Statement of Comprehensive Income (Loss) for the three and nine months ended September 30, 2016, are primarily due to the timing of the waiver of IDRs associated with the sale of our Canadian operations (See Note 3 – Divestitures.) The nine months ended September 30, 2016, differences are also due to the timing of the waiver of IDRs associated with the Termination Agreement. (See Note 1 – General, Description of Business, and Basis of Presentation.)


(2)	As part of the first quarter 2017 Financial Repositioning (see Note 1 – General, Description of Business, and Basis of Presentation), our general partner interest in us was converted to a noneconomic interest and therefore no longer receives an allocation of net income.

Common Units

The Board of Directors of our general partner declared a cash distribution of $0.60 per common unit on October 23, 2017, to be paid on November 10, 2017, to unitholders of record at the close of business on November 3, 2017.

Class B Units

The Class B units are not entitled to cash distributions. Instead, prior to conversion into common units, the Class B units receive quarterly distributions of additional paid-in-kind Class B units. Effective February 10, 2015, each Class B unit became convertible at the election of either us or the holders of such Class B unit into a common unit on a one-for-one basis. The Board of Directors of our general partner has authorized the issuance of 269,335 Class B units associated with the third-quarter distribution, to be issued on November 10, 2017.

Note 5 – Investing Activities

Acquisition of Additional Interests in Appalachia Midstream Investments

During the first quarter of 2017, we exchanged all of our 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. We also sold all of our interest in Ranch Westex JV LLC for $45 million. These transactions resulted in a total gain of $269 million reflected in Other investing income (loss) – net in the Consolidated Statement of Comprehensive Income (Loss).

The fair value of the increased interests in the Appalachia Midstream Investments received as consideration was estimated to be $1.1 billion using an income approach based on expected cash flows and an appropriate discount rate (a Level 3 measurement within the fair value hierarchy). The determination of estimated future cash flows involved significant assumptions regarding gathering volumes, rates, and related capital spending. A 9.5 percent discount rate was utilized and reflected our estimate of the cost of capital as impacted by market conditions and risks associated with the underlying business.

Impairments

The nine months ended September 30, 2016, includes other-than-temporary impairment charges of $59 million and $50 million related to certain equity-method investments in DBJV and Laurel Mountain, respectively (see Note 10 – 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 our Appalachia Midstream Investments.

Notes (Continued)

Summarized Results of Operations for Certain Equity-Method Investments

The table below presents aggregated selected income statement data for our investments in Discovery, Gulfstream, and Appalachia Midstream Investments, which were considered significant as of September 30, 2016, in accordance with Regulation S‑X 4‑08(g).



	Nine Months Ended
	September 30,
	2017		2016
	(Millions)
Gross revenue	$	760	$	648
Operating income	439		376
Net income	393		321

Note 6 – 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 Comprehensive Income (Loss):



	Three Months Ended September 30,				Nine Months Ended September 30,
	2017		2016		2017			2016
	(Millions)
Atlantic-Gulf
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
West
Gains on contract settlements and terminations	—		—		(15		)	—
NGL & Petchem Services
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


(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.

Additional Items

Certain additional items included in the Consolidated Statement of Comprehensive Income (Loss) 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 Atlantic-Gulf segment.

•

Selling, general, and administrative expenses and Operating and maintenance expenses for the three and nine months ended September 30, 2017 includes severance and other related costs. The nine months ended September 30, 2016, includes $25 million in severance and other related costs associated with an approximate 10 percent reduction in workforce in the first quarter of 2016. The amounts by segment are as follows:

Notes (Continued)



	Three Months Ended September 30,				Nine Months Ended September 30,
	2017		2016		2017		2016
	(Millions)
Northeast G&P	$	—	$	—	$	—	$	3
Atlantic-Gulf	—		—		—		8
West	—		—		—		10
NGL & Petchem Services	—		—		—		4
Other	5		—		18		—


•	Other income (expense) – net below Operating income (loss) includes $17 million and $54 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 within the Atlantic-Gulf segment.

•

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 Other segment reflects $51 million of unamortized premium, offset by $54 million in premiums paid. (See Note 8 – 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 the Other segment reflects $53 million of unamortized premium, partially offset by $23 million in premiums paid. (See Note 8 – Debt and Banking Arrangements.)

Note 7 – 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:
State	$	4		$	(1	)	$	9		$	—
Foreign	—			1			—			1
	4			—			9			1

Deferred:
State	(5		)	—			(6		)	(4		)
Foreign	—			(6		)	—			(82		)
	(5		)	(6		)	(6		)	(86		)
Provision (benefit) for income taxes	$	(1	)	$	(6	)	$	3		$	(85	)

We are not a taxable entity for U.S. federal income tax purposes. However, our income apportionable to Texas is subject to Texas margin tax. For the three and nine months ended September 30, 2017, the variance from the federal statutory rate, which is zero percent as a non-taxable entity, was primarily due to our allocable share of Texas margin tax.

The variance for the three months ended September 30, 2016, from the federal statutory rate was primarily due to taxes on foreign operations and our allocable share of Texas margin tax.

Notes (Continued)

The variance for the nine months ended September 30, 2016, from the federal statutory rate was primarily due to taxes on foreign operations, which includes the tax effect of a $341 million impairment associated with our Canadian operations (see Note 10 – Fair Value Measurements and Guarantees) and our allocable share of Texas margin tax.

Note 8 – Debt and Banking Arrangements

Long-Term Debt

Issuances and retirements

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

On June 5, 2017, we issued $1.45 billion of 3.75 percent senior unsecured notes due 2027. We 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), we early retired $750 million of 6.125 percent senior unsecured notes that were due in 2022.

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

Other financing obligation

During the construction of Transco’s Dalton expansion project, we 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, we 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 our partner from noncurrent liabilities to debt to reflect the financing obligation payable to our partner over an expected term of 35 years.

Commercial Paper Program

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

Notes (Continued)

Credit Facilities



	September 30, 2017
	Stated Capacity		Outstanding
	(Millions)
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 our credit facility inclusive of any outstanding amounts under our commercial paper program.

Note 9 – Partners’ Capital

Financial Repositioning

See Note 1 – General, Description of Business, and Basis of Presentation for information regarding units that were issued during the first quarter of 2017 related to the Financial Repositioning.

Distribution Reinvestment Program

The August 2017 distribution resulted in 378,631 common units issued to the public at a discounted average price of $38.24 per unit associated with the reinvested distributions of $14 million.

The May 2017 distribution resulted in 311,279 common units issued to the public at a discounted average price of $39.69 per unit associated with the reinvested distributions of $12 million.

The February 2017 distribution resulted in 395,395 common units issued to the public at a discounted average price of $39.76 per unit associated with the reinvested distributions of $16 million.

Notes (Continued)

Note 10 – 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	(16,502		)	(17,973		)	—			(17,973		)	—

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	(18,470		)	(18,907		)	—			(18,907		)	—

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.

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

Notes (Continued)

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 Other 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 8 - Debt and Banking Arrangements).

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	West	September 30, 2017	$	439	$	1,019
Certain gathering operations (2)	Property, plant, and equipment – net and Intangible assets - net of accumulated amortization	Northeast G&P	September 30, 2017	21		115
Canadian operations (3)	Assets held for sale	NGL & Petchem Services	June 30, 2016	924				$	341
Certain gathering operations (4)	Property, plant, and equipment – net	West	June 30, 2016	18				48
Level 3 fair value measurements of certain assets						1,134		389
Other impairments and write-downs (5)						11		14
Impairment of certain assets						$	1,145	$	403

Equity-method investments (6)	Investments	West and Northeast G&P	March 31, 2016	$	1,294			$	109
Other equity-method investment	Investments	West	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

Notes (Continued)

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 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 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.


(4)	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.


(5)	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.

(6)

Relates to West’s previously owned interest in DBJV and Northeast G&P’s 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.

Guarantees

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

Note 11 – Contingent Liabilities

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 U.S. Environmental Protection Agency (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 $16 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

Notes (Continued)

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 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.

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.

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 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 Williams, 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.

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

Notes (Continued)

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.

Unitholder Litigation

On March 7, 2016, a purported unitholder of us filed a putative class action on behalf of certain purchasers of our units in U.S. District Court in Oklahoma. The action names as defendants us, Williams, 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 Equity, L.P.’s intention to pursue a purchase of Williams conditioned on Williams not closing the WPZ Public Unit Exchange when announcing the WPZ Public Unit Exchange. 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. We cannot reasonably estimate a range of potential loss at this time.

Other

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 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 12 – Segment Disclosures

Our reportable segments are Northeast G&P, Atlantic-Gulf, West, and NGL & Petchem Services. (See Note 1 – General, Description of Business, and Basis of Presentation.) Certain other corporate activities are included in Other.

Performance Measurement

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

We define Modified EBITDA as follows:


•	Net income (loss) before:


◦	Provision (benefit) for income taxes;


◦	Interest incurred, net of interest capitalized;


◦	Equity earnings (losses);


◦	Impairment of equity-method investments;


◦	Other investing income (loss) – net;


◦	Impairment of goodwill;


◦	Depreciation and amortization expenses;

Notes (Continued)


◦	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 Comprehensive Income (Loss).



	Northeast G&P		Atlantic- Gulf		West		NGL & Petchem Services		Eliminations			Total
	(Millions)
Three Months Ended September 30, 2017
Segment revenues:
Service revenues
External	$	207	$	553	$	544	$	—	$	—		$	1,304
Internal	7		11		—		—		(18		)	—
Total service revenues	214		564		544		—		(18		)	1,304
Product sales
External	56		57		459		9		—			581
Internal	5		49		26		—		(80		)	—
Total product sales	61		106		485		9		(80		)	581
Total revenues	$	275	$	670	$	1,029	$	9	$	(98	)	$	1,885

Three Months Ended September 30, 2016
Segment revenues:
Service revenues
External	$	204	$	508	$	524	$	16	$	—		$	1,252
Internal	10		14		—		—		(24		)	—
Total service revenues	214		522		524		16		(24		)	1,252
Product sales
External	36		78		302		239		—			655
Internal	7		59		64		3		(133		)	—
Total product sales	43		137		366		242		(133		)	655
Total revenues	$	257	$	659	$	890	$	258	$	(157	)	$	1,907

Nine Months Ended September 30, 2017
Segment revenues:
Service revenues
External	$	621	$	1,620	$	1,589	$	7	$	—		$	3,837
Internal	27		27		—		—		(54		)	—
Total service revenues	648		1,647		1,589		7		(54		)	3,837
Product sales
External	159		201		1,233		357		—			1,950
Internal	22		164		143		8		(337		)	—
Total product sales	181		365		1,376		365		(337		)	1,950
Total revenues	$	829	$	2,012	$	2,965	$	372	$	(391	)	$	5,787

Nine Months Ended September 30, 2016
Segment revenues:
Service revenues
External	$	627	$	1,431	$	1,583	$	47	$	—		$	3,688
Internal	22		27		—		—		(49		)	—
Total service revenues	649		1,458		1,583		47		(49		)	3,688
Product sales
External	82		177		785		569		—			1,613
Internal	18		134		129		14		(295		)	—
Total product sales	100		311		914		583		(295		)	1,613
Total revenues	$	749	$	1,769	$	2,497	$	630	$	(344	)	$	5,301

Notes (Continued)

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



	Three Months Ended September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016
	(Millions)
Modified EBITDA by segment:
Northeast G&P	$	115		$	214		$	588		$	656
Atlantic-Gulf	430			423			1,334			1,165
West	(615		)	363			126			1,002
NGL & Petchem Services	1,084			70			1,165			(194		)
Other	(14		)	—			(5		)	—
	1,000			1,070			3,208			2,629
Accretion expense associated with asset retirement obligations for nonregulated operations	(8		)	(8		)	(25		)	(24		)
Depreciation and amortization expenses	(424		)	(426		)	(1,280		)	(1,293		)
Equity earnings (losses)	115			104			347			302
Impairment of equity-method investments	—			—			—			(112		)
Other investing income (loss) – net	4			28			277			29
Proportional Modified EBITDA of equity-method investments	(202		)	(194		)	(611		)	(574		)
Interest expense	(202		)	(229		)	(621		)	(689		)
(Provision) benefit for income taxes	1			6			(3		)	85
Net income (loss)	$	284		$	351		$	1,292		$	353

The following table reflects Total assets by reportable segment.



	Total Assets
	September 30, 2017			December 31, 2016
	(Millions)
Northeast G&P	$	14,395		$	13,436
Atlantic-Gulf	14,531			14,176
West	16,014			18,479
NGL & Petchem Services	33			1,112
Other (1)	1,210			161
Eliminations (2)	(548		)	(1,099		)
Total	$	45,635		$	46,265


(1)	Increase in Other due to increased cash balance.


(2)	Eliminations primarily relate to the intercompany accounts and notes receivable generated by our cash management program.

Item 2

Management’s Discussion and Analysis of

Financial Condition and Results of Operations

General

We are an energy infrastructure master limited partnership focused on connecting North America’s significant hydrocarbon resource plays to growing markets for natural gas and NGLs through our gas pipeline and midstream businesses. WPZ GP LLC, a Delaware limited liability company wholly owned by Williams, is our general partner.

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

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

Effective January 1, 2017, we implemented organizational changes, consistent with the manner in which our chief operating decision maker evaluates performance and allocates resources. Operations previously reported within the Central segment are now generally managed and presented within the West segment. Certain businesses previously within our NGL & Petchem Services segment are now managed and presented within the West, Atlantic-Gulf, and Northeast G&P segments. Certain other corporate activities are included in Other. Prior period segment disclosures have been recast for these segment changes. As a result, beginning with the reporting of first-quarter 2017, our reportable segments are Northeast G&P, Atlantic-Gulf, West, and NGL & Petchem Services, which are comprised of the following businesses:

•

Northeast G&P is comprised of our midstream gathering and processing businesses in the Marcellus Shale region primarily in Pennsylvania, New York, and West Virginia and the Utica Shale region of eastern Ohio, as well as a 66 percent interest in Cardinal (a consolidated entity), 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, and Appalachia Midstream Services, LLC, which owns equity-method investments with an approximate average 66 percent interest in multiple gas gathering systems in the Marcellus Shale (Appalachia Midstream Investments).

•

Atlantic-Gulf is comprised of our interstate natural gas pipeline, Transco, and significant natural gas gathering and processing and crude oil production handling and transportation assets in the Gulf Coast region, including a 51 percent interest in Gulfstar One (a consolidated entity), which is a proprietary floating production system, and various petrochemical and feedstock pipelines in the Gulf Coast region, as well as a 50 percent equity-method investment in Gulfstream, a 60 percent equity-method investment in Discovery, and a 41 percent interest in Constitution (a consolidated entity), which is under development.

•

West is comprised of our interstate natural gas pipeline, Northwest Pipeline, and our gathering, processing and treating operations in New Mexico, Colorado, and Wyoming, as well as the Barnett Shale region of north-central Texas, the Eagle Ford Shale region of south Texas, the Haynesville Shale region of northwest Louisiana, and the Mid-Continent region which includes the Anadarko, Arkoma, Delaware, and Permian basins. This segment also includes our NGL and natural gas marketing business, storage facilities, an undivided 50 percent

Management’s Discussion and Analysis (Continued)

interest in an NGL fractionator near Conway, Kansas and a 50 percent equity-method investment in OPPL, 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 5 – Investing Activities of Notes to Consolidated Financial Statements).

•

NGL & Petchem Services is comprised of previously owned operations, including an 88.5 percent undivided interest in an olefins production facility in Geismar, Louisiana, which was sold in July 2017 (see Note 3 – Divestitures of Notes to Consolidated Financial Statements), and a refinery grade propylene splitter in the Gulf region, which was sold in June 2017. This segment also includes our previously owned Canadian assets which included an oil sands offgas processing plant near Fort McMurray, Alberta, and a NGL/olefin fractionation facility at Redwater, Alberta. In September 2016, these Canadian operations were sold.

Financial Repositioning

In January 2017, we announced agreements with Williams, wherein Williams permanently waived the general partner’s IDRs and converted its 2 percent general partner interest in us to a noneconomic interest in exchange for 289 million newly issued common units. Pursuant to this agreement, Williams also purchased approximately 277 thousand common units for $10 million. Additionally, Williams purchased approximately 59 million common units at a price of $36.08586 per unit in a private placement transaction. According to the terms of this agreement, concurrent with our quarterly distributions in February 2017 and May 2017, Williams paid additional consideration totaling $56 million to us for these units. Following these transactions and as of September 30, 2017, Williams owns a 74 percent limited partner interest in us.

Distributions

On October 23, 2017, our general partner’s Board of Directors approved a quarterly distribution to unitholders of $0.60 per common unit on November 10, 2017, on our outstanding common units to unitholders of record at the close of business on November 3, 2017.

Overview of Nine Months Ended September 30, 2017

Net income (loss) attributable to controlling interests for the nine months ended September 30, 2017, changed favorably by $927 million compared to the nine months ended September 30, 2016, reflecting a $519 million improvement in operating income, a gain of $269 million associated with the disposition of certain equity-method investments in 2017, and the absence of $112 million of impairments of equity-method investments incurred in 2016. The improvement in operating income is primarily due to a gain of $1.095 billion from the sale of our Geismar Interest, increased service revenue associated with expansion projects, and lower costs and expenses, partially offset by $100 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 $742 million increase in Impairments of certain assets.

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

In September 2017, Williams 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. As a result of these payouts and based on current assumptions, Williams expects to record a pre-tax, non-cash settlement charge in the fourth quarter of 2017. Williams estimates the charge will be between $70 million and $100 million, largely dependent 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. We expect to be charged by and pay Williams for a portion of this expense.

Management’s Discussion and Analysis (Continued)

Atlantic-Gulf

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, we 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. We expect 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 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.

West

Acquisition of additional interests in Appalachia Midstream Investments

During the first quarter of 2017, we exchanged all of our 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, we have an approximate average 66 percent interest in the Appalachia Midstream Investments. We also sold all of our interest in Ranch Westex JV LLC for $45 million. These transactions resulted in a total gain of

Management’s Discussion and Analysis (Continued)

$269 million reflected in Other investing income (loss) – net in the Consolidated Statement of Comprehensive Income (Loss) within the West segment. (See Note 5 – Investing Activities of Notes to Consolidated Financial Statements.)

NGL & Petchem Services

Geismar olefins facility monetization

In July 2017, we completed the sale of our Geismar Interest for $2.084 billion in cash. We received a final working capital adjustment of $12 million in October 2017. Additionally, we entered into a long-term supply and transportation agreement with the purchaser to provide feedstock to the plant via our Bayou Ethane pipeline system, 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 our $850 million term loan. We also plan to use these proceeds to fund a portion of the capital and investment expenditures that are a part of our growth portfolio.

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 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 unitholders.

Our business plan for 2017 includes the previously discussed financial repositioning transactions and the monetization of our Geismar Interest. These transactions serve to improve our cost of capital, remove our need to access the public equity markets for the next several years, enhance our growth, and provide for debt reduction.

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 G&P segment 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.

Management’s Discussion and Analysis (Continued)

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 G&P segment. Partially offsetting these increases are expected declines in fee-based revenue in the West segment. 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;


•	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

Our ongoing major expansion projects include the following:

Northeast G&P

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 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.

Management’s Discussion and Analysis (Continued)

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.

Atlantic-Gulf

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 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.

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 Atlantic-Gulf 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.

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.

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.

West

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.

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 up approximately 5.9 miles of 8-

Management’s Discussion and Analysis (Continued)

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.

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.

Management’s Discussion and Analysis (Continued)

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. 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	$	1,304		$	1,252		+52	+4	%	$	3,837		$	3,688		+149	+4	%
Product sales	581			655			-74	-11	%	1,950			1,613			+337	+21	%
Total revenues	1,885			1,907						5,787			5,301
Costs and expenses:
Product costs	504			463			-41	-9	%	1,620			1,183			-437	-37	%
Operating and maintenance expenses	396			385			-11	-3	%	1,141			1,153			+12	+1	%
Depreciation and amortization expenses	424			426			+2	—	%	1,280			1,293			+13	+1	%
Selling, general, and administrative expenses	140			147			+7	+5	%	450			467			+17	+4	%
Gain on sale of Geismar Interest	(1,095		)	—			+1,095	NM		(1,095		)	—			+1,095	NM
Impairment of certain assets	1,142			1			-1,141	NM		1,145			403			-742	-184	%
Other (income) expense – net	22			59			+37	+63	%	32			107			+75	+70	%
Total costs and expenses	1,533			1,481						4,573			4,606
Operating income (loss)	352			426						1,214			695
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	%	277			29			+248	NM
Interest expense	(202		)	(229		)	+27	+12	%	(621		)	(689		)	+68	+10	%
Other income (expense) – net	14			16			-2	-13	%	78			43			+35	+81	%
Income (loss) before income taxes	283			345						1,295			268
Provision (benefit) for income taxes	(1		)	(6		)	-5	-83	%	3			(85		)	-88	NM
Net income (loss)	284			351						1,292			353
Less: Net income attributable to noncontrolling interests	25			25			—	—	%	79			67			-12	-18	%
Net income (loss) attributable to controlling interests	$	259		$	326					$	1,213		$	286


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

Three months ended 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 reflecting 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

Management’s Discussion and Analysis (Continued)

restructuring. The increase in Service revenues is 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 sales 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 costs associated with our former Canadian and Gulf Olefins operations, partially offset by higher severance and organizational realignment costs primarily associated with our Other segment.

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 primarily reflects the 2017 impairment of certain gathering operations in the Mid-Continent and Marcellus South regions, (see Note 10 – 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 project 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 absence of a 2016 loss on the sale of our Canadian operations, higher service revenues associated with certain projects placed in-service in 2016 and 2017, and the gain on the sale of our Geismar Interest.

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 5 – Investing Activities of Notes to Consolidated Financial Statements.)

Interest expense decreased due to lower Interest incurred primarily attributable to debt retirements and the absence of borrowings on our credit facility in 2017. (See Note 8 – Debt and Banking Arrangements 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

Management’s Discussion and Analysis (Continued)

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. The sale of our former Canadian and Gulf Olefins operations also contributed to declines in Service revenues.

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, offset by new assets placed in-service.

Selling, general, and administrative expenses decreased primarily due to the absence of costs associated with our former Canadian operations, 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 higher costs related to our organizational realignment and severance, primarily associated with our Other segment.

The unfavorable change in Impairment of certain assets primarily reflects the 2017 impairment of certain gathering operations in the Mid-Continent and Marcellus South regions, partially offset by the absence of 2016 impairments of our former Canadian operations and certain Mid-Continent assets (see Note 10 – 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 are partially offset by the accrual of additional expenses in 2017 related to the Geismar Incident.

Operating income (loss) changed favorably primarily due to the Gain on sale of 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 the workforce reductions in first-quarter 2016. Operating income (loss) also improved due to absence of the 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 the 2017 impairment of certain gathering operations in the Mid-Continent and Marcellus South regions, and 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

Management’s Discussion and Analysis (Continued)

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 10 – 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, partially offset by 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 5 – Investing Activities 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, which is included in our Other segment. (See Note 6 – Other Income and Expenses of Notes to Consolidated Financial Statements.)

Provision (benefit) for income taxes changed unfavorably primarily due to the absence of a 2016 income tax benefit associated with the impairment of our former Canadian operations. See Note 7 – Provision (Benefit) for Income Taxes of Notes to Consolidated Financial Statements for a discussion of the effective tax rates compared to the federal statutory rate for both periods.

The unfavorable change in Net income (loss) attributable to noncontrolling interests is primarily due to improved results in our Gulfstar operations, 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 12 – 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.

Northeast G&P



	Three Months Ended September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016
	(Millions)
Service revenues	$	214		$	214		$	648		$	649
Product sales	61			43			181			100
Segment revenues	275			257			829			749

Product costs	(61		)	(42		)	(179		)	(97		)
Other segment costs and expenses	(98		)	(91		)	(273		)	(271		)
Impairment of certain assets	(121		)	—			(123		)	(8		)
Proportional Modified EBITDA of equity-method investments	120			90			334			283
Northeast G&P Modified EBITDA	$	115		$	214		$	588		$	656

Management’s Discussion and Analysis (Continued)

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

Modified EBITDA decreased primarily due to higher Impairment of certain assets, partially offset by higher Proportional Modified EBITDA of equity-method investments.

Service revenues remained consistent, but reflect:


•	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;


•	A $10 million increase in fee revenues in the Susquehanna Supply Hub driven by 10 percent higher gathered volumes reflecting increased customer production.

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

Impairment of certain assets increased primarily due to a $115 million impairment of certain gathering operations in the Marcellus South region and $6 million of write-downs of certain assets that are no longer in use or are surplus in nature in the third quarter of 2017.

Proportional Modified EBITDA of equity-method investments increased primarily due to a $31 million increase at Appalachian Midstream Investments reflecting our increased ownership acquired late in the first quarter of 2017, higher gathering volumes reflecting the absence of shut-in volumes from 2016 and increased customer production, partially offset by an $8 million decrease at UEOM driven by lower processing volumes from the wet gas areas of the Utica gathering system as noted above.

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

Modified EBITDA decreased primarily due to higher Impairment of certain assets, partially offset by higher Proportional Modified EBITDA of equity-method investments.

Service revenues decreased slightly reflecting:


•	A $52 million decrease in the Utica gathering fee revenues 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;


•	A $32 million increase in gathering fee revenue at Susquehanna Supply Hub driven by 12 percent higher gathered volumes reflecting increased customer production;


•	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 higher non-ethane and ethane prices and volumes within our marketing activities. The changes in marketing revenues are offset by similar changes in marketing purchases, reflected above as Product costs.

Impairment of certain assets increased primarily due to a $115 million impairment of certain gathering operations in the Marcellus South region.

Proportional Modified EBITDA of equity-method investments changed favorably primarily due to a $60 million increase at Appalachian Midstream Investments reflecting our increased ownership acquired 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

Management’s Discussion and Analysis (Continued)

higher rates reflecting higher natural gas prices, partially offset by a $29 million decrease at UEOM driven by lower processing volumes from the wet gas areas of the Utica gathering system as noted above.

Atlantic-Gulf



	Three Months Ended September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016
	(Millions)
Service revenues	$	564		$	522		$	1,647		$	1,458
Product sales	106			137			365			311
Segment revenues	670			659			2,012			1,769

Product costs	(97		)	(124		)	(328		)	(286		)
Other segment costs and expenses	(207		)	(187		)	(566		)	(525		)
Impairment of certain assets	—			—			—			(2		)
Proportional Modified EBITDA of equity-method investments	64			75			216			209
Atlantic-Gulf Modified EBITDA	$	430		$	423		$	1,334		$	1,165

NGL margin	$	7		$	9		$	30		$	21

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

Modified EBITDA increased primarily due to higher Service revenues, partially offset by higher Other segment costs and expenses and lower Proportional Modified EBITDA of equity-method investments.

Service revenues increased primarily due to:


•	A $43 million increase in Transco’s natural gas transportation fee revenues primarily due to a $46 million increase associated with expansion projects placed in service in 2016 and 2017;


•	A $20 million increase in eastern Gulf Coast region fee revenues primarily related to 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 shut-down and subsequent ramp up of Gulfstar One in the second and third quarters of 2016 to tie-in Gunflint;


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

Product sales decreased primarily due to:


•	A $12 million decrease in revenues associated with our equity NGLs primarily due to lower volumes as a result of a temporary increase in 2016 due to disrupted operations of a competitor, partially offset by 45 percent higher non-ethane prices;


•	A $12 million decrease in crude marketing revenue primarily due to 48 percent lower crude volumes and 29 percent lower non-ethane NGL volumes driven by shut-ins of certain wells behind Devils Tower as a result of production issues and temporary hurricane-related shut-ins, partially offset by high crude and NGL prices (more than offset by lower Product Costs).

Product costs decreased primarily due to:


•	A $14 million decrease in marketing purchases (substantially offset in Product sales);

Management’s Discussion and Analysis (Continued)


•	A $9 million decrease in natural gas purchases associated with the production of equity NGLs primarily due to lower volumes.

Other segment costs and expenses increased primarily due to higher Transco pipeline integrity testing and costs, partially offset by lower project development costs at Constitution and favorable impacts related to gains on asset retirements.

The decrease in Proportional Modified EBITDA of equity-method investments includes a $9 million decrease from Discovery primarily due to production issues on certain wells and temporary hurricane-related shut-ins.

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

Modified EBITDA increased primarily due to higher Service revenues, partially offset by higher Other segment costs and expenses.

Service revenues increased primarily due to:

•

A $114 million increase in eastern Gulf Coast region fee revenues primarily related to 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, the absence of producers’ operational issues in the Tubular Bells field during the first quarter of 2016, and higher volumes at Devils Tower related to the Kodiak field (although certain wells in this field are now shut-in due to production issues), partially offset by lower volumes as a result of a temporary increase in 2016 due to disrupted operations of a competitor;


•	A $74 million increase in Transco’s natural gas transportation fee revenues 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 related to the absence of an accrual for potential refunds associated with a ruling received in certain rate case litigation in 2016;


•	A $17 million decrease in western Gulf Coast region fee revenues due primarily to producer maintenance.

Product sales increased primarily due to:


•	A $33 million increase in crude oil and NGL marketing revenues primarily due to 32 percent higher crude prices and 43 percent higher non-ethane NGL prices, partially offset by lower volumes driven by shut-ins of certain wells behind Devils Tower as a result of production issues and temporary hurricane-related shut-ins (substantially offset by higher Product costs);


•	A $12 million increase in revenues from our equity NGLs primarily due to a 40 percent increase in realized non-ethane prices, partially offset by 5 percent lower non-ethane volumes related to temporary keep-whole volumes in 2016 due to disrupted operations of a competitor and to lower volumes of processed gas driven by producer maintenance;


•	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.

Product costs increased primarily due to:


•	A $30 million increase in marketing purchases (more than offset in Product sales);


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

Management’s Discussion and Analysis (Continued)

Other segment costs and expenses increased primarily due to higher costs associated with Transco pipeline integrity testing and general maintenance, as well as higher general and administrative costs due to an increased share of allocated support costs. These increases are partially offset by a $17 million favorable change in equity allowance for funds used during construction (AFUDC) associated with an increase in Transco’s capital spending which is offset by an $8 million decrease in Constitution’s equity AFUDC. Other favorable changes include lower project development costs at Constitution and favorable impacts related to gains on asset retirements.

The increase in Proportional Modified EBITDA of equity-method investments includes an $8 million increase from Discovery primarily associated with a $12 million increase due to the accelerated recognition of previously deferred revenue and higher NGL margins driven by higher non-ethane prices, 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.

West



	Three Months Ended September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016
	(Millions)
Service revenues	$	544		$	524		$	1,589		$	1,583
Product sales	485			366			1,376			914
Segment revenues	1,029			890			2,965			2,497

Product costs	(438		)	(337		)	(1,263		)	(835		)
Other segment costs and expenses	(203		)	(218		)	(615		)	(691		)
Impairment of certain assets	(1,021		)	(1		)	(1,022		)	(51		)
Proportional modified EBITDA of equity-method investments	18			29			61			82
West Modified EBITDA	$	(615	)	$	363		$	126		$	1,002

NGL margin	$	37		$	27		$	104		$	79

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

Modified EBITDA decreased primarily due to higher Impairment of certain assets and lower gathering rates, partially offset by new amortization of deferred revenue associated with the up-front cash payment received in conjunction with the fourth quarter 2016 Barnett Shale contract restructuring, higher margins associated with our equity NGL’s, and results from marketing activities driven by higher non-ethane product prices and lower segment costs and expenses.

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 $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 that is received, with the difference reflected as deferred revenue;


•	A $6 million decrease driven by lower volumes, primarily in the Barnett Shale and Southwest Wyoming, as a result of natural declines and contract changes, partially offset by higher volumes in the Eagle Ford Shale as a result of new wells connected.

Management’s Discussion and Analysis (Continued)

Product sales increased primarily due to:

•

A $97 million increase in marketing revenues primarily due to increases in product prices including a 48 percent increase in average non-ethane per-unit sales prices and a 41 percent increase in ethane prices, partially offset by a 42 percent decrease in natural gas volumes as a result of a temporary increase in 2016 related to disrupted operations of a competitor (substantially offset by higher Product costs);


•	A $15 million increase in revenues associated with our equity NGLs primarily due to 42 percent higher non-ethane prices.

Product costs increased primarily due to:


•	A $90 million increase in marketing purchases (more than offset in Product sales);


•	A $5 million increase in natural gas purchases associated with the production of equity NGLs primarily due to a six percent increase in per-unit natural gas prices.

Other segment costs and expenses decreased primarily due to lower operating expenses that include lower compression costs and reductions related to ongoing cost containment efforts.

Impairment of certain assets increased due to the $1.019 billion impairment of certain gathering operations in the Mid-Continent region in 2017.

Proportional modified EBITDA of equity-method investments decreased primarily due to the divestiture of our interests in DBJV and Ranch Westex JV LLC late in the first quarter of 2017.

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

Modified EBITDA decreased primarily due to higher Impairment of certain assets, lower gathering rates, and lower volumes as a result of natural declines, partially offset by new amortization of deferred revenue associated with the up-front cash payment received in conjunction with the fourth quarter 2016 Barnett Shale contract restructuring, lower segment costs and expenses, and higher per-unit NGL margins.

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;

•

A $75 million decrease related to lower gathering 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 most gathering and processing regions primarily as a result of natural declines and more extreme weather conditions in the Rocky Mountains in the first quarter of 2017;


•	A $10 million decrease at our Conway Storage & Fractionation facility reflecting lower rail loading terminal, storage, and fractionation volumes.

Product sales increased primarily due to:


•	A $402 million increase in marketing revenues primarily due to a 45 percent increase in average non-ethane per-unit sales prices, a 39 percent increase in ethane prices, and a 26 percent increase in natural gas prices. In addition, non-ethane and ethane sales volumes were 6 percent and 25 percent higher, respectively (substantially offset by higher Product costs);

Management’s Discussion and Analysis (Continued)


•	A $48 million increase in revenues associated with our equity NGLs primarily due to 42 percent higher non-ethane prices, partially offset by eight percent lower non-ethane volumes primarily due to severe winter conditions in the first quarter of 2017 and natural declines.

Product costs increased primarily due to:


•	A $396 million increase in marketing purchases (more than offset in Product sales);


•	A $23 million increase in natural gas purchases associated with the production of equity NGLs primarily due to a 37 percent increase in per-unit natural gas prices.

The decrease in Other segment costs and expenses reflects a $39 million decline in operating expenses and a $20 million reduction in general and administrative expenses, primarily due to the 2016 workforce reductions, ongoing cost containment efforts, lower compression expenses, and a reduced share of allocated support costs. In addition, the decrease in Other segment costs and expenses reflects gains from contract settlements and terminations.

Impairment of certain assets increased primarily due to the $1.019 billion impairment of certain gathering operations in the Mid-Continent region in 2017, partially offset by the absence of a $48 million impairment of certain Mid-Continent gathering assets in 2016.

Proportional modified EBITDA of equity-method investments decreased primarily due to the divestiture of our interests in DBJV and Ranch Westex JV LLC late in the first quarter of 2017.

NGL & Petchem Services



	Three Months Ended September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016
	(Millions)
Service revenues	$	—		$	16		$	7		$	47
Product sales	9			242			365			583
Segment revenues	9			258			372			630

Product costs	(7		)	(115		)	(238		)	(306		)
Other segment costs and expenses	(13		)	(73		)	(64		)	(176		)
Gain on sale of Geismar Interest	1,095			—			1,095			—
Impairment of certain assets	—			—			—			(342		)
NGL & Petchem Services Modified EBITDA	$	1,084		$	70		$	1,165		$	(194	)

Olefins margin	$	2		$	118		$	125		$	263
NGL margin	—			6			—			12

On July 6, 2017, we completed the sale of Williams Olefins, L.L.C., a wholly owned subsidiary which owned our Geismar Interest. As a result, our third-quarter 2017 results only include results for the period we owned the Geismar plant.

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

Modified EBITDA changed favorably primarily due to a $1.095 billion gain on the sale of our Geismar Interest and the absence of a $32 million loss on the sale of our former Canadian operations in third-quarter 2016, partially offset by the absence of $102 million in Modified EBITDA from our former Gulf Olefins (Geismar olefins and RGP Splitter plants) and Canadian operations.

Management’s Discussion and Analysis (Continued)

Service revenues, Product sales, and Product costs declined due to the absence of revenues and costs associated with the Geismar and RGP Splitter plants that were sold in July 2017 and June 2017, respectively, and our former Canadian operations that were sold in September 2016.

The favorable change in Other segment costs and expenses is primarily due to the absence of a $32 million loss on the sale of our former Canadian operations in third-quarter 2016 and a reduction of third-quarter 2017 segment costs associated with the Gulf Olefins and Canadian operations.

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.)

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

Modified EBITDA increased primarily due to the $1.095 billion gain on the sale of our Geismar Interest, the absence of a $341 million impairment of our former Canadian operations in second-quarter 2016, partially offset by the absence of $102 million in Modified EBITDA from our former Gulf Olefins and Canadian operations.

Service revenues declined due primarily to the absence of revenues associated with our former Canadian operations.

Product sales decreased primarily due to:

•

A $217 million decrease in olefin sales primarily due to a $180 million decrease reflecting the absence of third-quarter sales 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 primarily due 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 primarily due to higher propylene prices;


•	A $36 million decrease due to the absence of NGL production revenues associated with our former Canadian operations;


•	A $37 million increase in marketing revenues primarily due to a $58 million increase in the first half of 2017 due to higher olefin volumes and prices, partially offset by a $21 million decrease in third-quarter 2017 reflecting the sale of our Geismar Interest (more than offset by higher Product costs).

Product costs decreased primarily due to:

•

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 our 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 associated with our Gulf Olefins operations in the first half of 2017;


•	A $24 million decrease due to the absence of NGL product costs associated with our former Canadian operations;


•	A $38 million increase in marketing product costs primarily due to a $54 million increase in the first half of 2017 primarily due to higher olefin feedstock prices and volumes, partially offset by a $16 million decrease in third-quarter 2017 reflecting the sale of our Geismar plant (substantially offset by higher Product sales).

The favorable change in Other segment costs and expenses is primarily due to the absence of $63 million in operating and other expenses associated with our former Canadian operations, the absence of a $32 million loss on the sale of our former Canadian operations in 2016, a reduction of $17 million in operating and other expenses in third-quarter 2016 associated with the sale of our Gulf Olefins operations, a $12 million gain on the sale of the RGP Splitter, partially offset by $12 million higher operating and other expenses in the first half of 2017 primarily due to selling

Management’s Discussion and Analysis (Continued)

expenses associated with our Geismar Interest and higher operating expenses associated with repairs of the electrical outage noted above.

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 decrease in Impairment of certain assets primarily reflects the absence of the 2016 impairment of our former Canadian operations (see Note 10 – 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 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 G&P segment 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. Our expected material internal and external sources of liquidity for 2017 are as follows:


•	Cash and cash equivalents on hand;


•	Cash generated from operations;


•	Distributions from our equity-method investees;


•	Cash proceeds from the January 2017 and February 2017 purchase of common units by Williams (see Note 1 – General, Description of Business, and Basis of Presentation of Notes to Consolidated Financial Statements);


•	Utilization of our credit facility and/or commercial paper program;


•	Proceeds from asset monetizations.

We expect our material internal and external uses of liquidity to be:


•	Working capital requirements;


•	Capital and investment expenditures;


•	Debt service payments, including payments of long-term debt;


•	Quarterly distributions to our unitholders.

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 surplus of $120 million. Our available liquidity is as follows:



Available Liquidity	September 30, 2017
	(Millions)
Cash and cash equivalents	$	1,165
Capacity available under our $3.5 billion credit facility, less amounts outstanding under our $3 billion commercial paper program (1)	3,500
	$	4,665

(1)

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

Registrations

In September 2016, we filed a registration statement for our distribution reinvestment program. (See Note 9 – Partners’ Capital of Notes to Consolidated Financial Statements.)

In February 2015, we 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, we filed a shelf registration statement for the offer and sale from time to time of common units representing limited partner interests in us 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 us 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.

Credit Ratings

Our ability to borrow money is impacted by our credit ratings. Our current ratings are as follows:



Rating Agency	Outlook	Senior Unsecured Debt Rating	Corporate Credit Rating
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 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 WPZ to Positive. These credit ratings are included for informational purposes and are not recommendations to buy, sell, or hold our units, and each rating should be evaluated independently of any other rating. No assurance can be given that the credit rating agencies will continue to assign us investment-grade ratings even if we meet or exceed their current criteria for investment-grade ratios. A downgrade of our credit rating 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)

Cash Distributions to Unitholders

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	$	2,103		$	2,351
Proceeds from sales of common units (see Note 1)	Financing	2,184			250
Proceeds from sale of businesses, net of cash divested (see Note 3)	Investing	2,058			510
Proceeds from long-term debt (see Note 8)	Financing	1,698			998
Distributions from unconsolidated affiliates in excess of cumulative earnings	Investing	394			341
Proceeds from dispositions of equity-method investments (see Note 5)	Investing	200			—
Proceeds from credit-facility borrowings	Financing	—			2,665

Uses of cash and cash equivalents:
Payments of long-term debt (see Note 8)	Financing	(3,785		)	(375		)
Distributions paid (1)	Financing	(1,916		)	(1,956		)
Capital expenditures	Investing	(1,687		)	(1,472		)
Dividends and distributions to noncontrolling interests	Financing	(160		)	(69		)
Purchases of and contributions to equity-method investments	Investing	(103		)	(132		)
Payments of commercial paper – net	Financing	(93		)	(499		)
Payments on credit-facility borrowings	Financing	—			(2,745		)
Contribution to Gulfstream for repayment of debt	Financing	—			(148		)

Other sources / (uses) – net	Financing and Investing	127			253
Increase (decrease) in cash and cash equivalents		$	1,020		$	(28	)

____________


(1)	Includes $1.440 billion and $1.321 billion to Williams in 2017 and 2016, respectively.

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, 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 8 – Debt and Banking Arrangements, Note 10 – Fair Value Measurements and Guarantees, and Note 11 – Contingent

Management’s Discussion and Analysis (Continued)

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 general partner’s 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 partnership 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 general partner’s Chief Executive Officer and Chief Financial Officer. Based upon that evaluation, our general partner’s 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 11 – 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 Williams Partners L.P.’s current report on Form 8-K (File No. 001-34831) and incorporated herein by reference).
2.2§	—	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	—	Certificate of Limited Partnership of Chesapeake Midstream Partners, L.P. (filed on February 16, 2010 as Exhibit 3.1 to Williams Partners L.P.’s registration statement on Form S-1 (File No. 333-164905) and incorporated herein by reference).
3.2	—	Amendment to Certificate of Limited Partnership of Chesapeake Midstream Partners, L.P. (filed on July 30, 2012 as Exhibit 3.1 to Williams Partners L.P.’s current report on Form 8‑K (File No. 001-34831) and incorporated herein by reference).
3.3	—	Amendment to Certificate of Limited Partnership of Access Midstream Partners, L.P. (filed on February 3, 2015 as Exhibit 3.5 to Williams Partners L.P.’s current report on Form 8‑K (File No. 001-34831) and incorporated herein by reference).
3.4	—	Composite Certificate of Limited Partnership of Williams Partners L.P. (filed on February 25, 2015 as Exhibit 3.4 to Williams Partners L.P.’s annual report on Form 10-K (File No. 001-34831) and incorporated herein by reference).
3.5	—	First Amended and Restated Agreement of Limited Partnership of Chesapeake Midstream Partners, L.P., dated August 3, 2010 (filed on August 5, 2010 as Exhibit 3.1 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-34831) and incorporated herein by reference).
3.6	—	Amendment No. 1 to the First Amended and Restated Agreement of Limited Partnership of Chesapeake Midstream Partners, L.P. dated as of July 24, 2012 (filed on July 30, 2012 as Exhibit 3.3 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-34831) and incorporated herein by reference).
3.7	—	Amendment No. 2 to the First Amended and Restated Agreement of Limited Partnership of Access Midstream Partners, L.P. dated as of December 20, 2012 (filed on December 26, 2012 as Exhibit 3.1 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-34831) and incorporated herein by reference).
3.8	—	Amendment No. 3 to the First Amended and Restated Agreement of Limited Partnership of Access Midstream Partners, L.P. dated as of January 29, 2015 (filed on February 3, 2015 as Exhibit 3.1 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-34831) and incorporated herein by reference).
3.9	—	Amendment No. 4 to the First Amended and Restated Agreement of Limited Partnership of Access Midstream Partners, L.P. dated as of January 29, 2015 (filed on February 3, 2015 as Exhibit 3.4 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-34831) and incorporated herein by reference).
3.10	—	Amendment No. 5 to the First Amended and Restated Agreement of Limited Partnership of Williams Partners L.P., dated as of June 10, 2015 (filed on June 12, 2015 as Exhibit 3 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-34831) and incorporated herein by reference).



Exhibit No.		Description

3.11	—	Amendment No. 6 to the First Amended and Restated Agreement of Limited Partnership of Williams Partners L.P., dated September 28, 2015 (filed on September 28, 2015 as Exhibit 3.1 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-34831) and incorporated herein by reference).
3.12	—	Amendment No. 7 to the First Amended and Restated Agreement of Limited Partnership of Williams Partners L.P., dated October 12, 2016 (filed on October 13, 2016 as Exhibit 3 to Williams Partners L.P’s current report on Form 8-K (File No. 001-34831) and incorporated herein by reference).
3.13	—	Amendment No. 8 to the First Amended and Restated Agreement of Limited Partnership of Williams Partners L.P., dated January 9, 2017 (filed on January 10, 2017 as Exhibit 3.1 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-34831) and incorporated herein by reference).
3.14	—	Composite Agreement of Limited Partnership of Williams Partners L.P. (filed on February 22, 2017 as Exhibit 3.14 to Williams Partners L.P.’s annual report on Form 10-K (File No. 001-34831) and incorporated herein by reference).
3.15	—	Certificate of Formation of Chesapeake Midstream GP, L.L.C. (filed on February 16, 2010 as Exhibit 3.3 to Williams Partners L.P.’s registration statement on Form S-1 (File No. 333-164905) and incorporated herein by reference).
3.16	—	Certificate of Amendment to Certificate of Formation of Chesapeake Midstream GP, L.L.C. (filed on July 30, 2012 as Exhibit 3.5 to Williams Partners L.P.’s current report on Form 8‑K (File No. 001-34831) and incorporated herein by reference).
3.17	—	Certificate of Amendment of Certificate of Formation of Access Midstream Partners GP, L.L.C. (filed on February 3, 2015 as Exhibit 3.2 to Williams Partners L.P.’s current report on Form 8‑K (File No. 001-34831) and incorporated herein by reference).
3.18	—	Composite Certificate of Formation of WPZ GP LLC (filed on February 25, 2015 as Exhibit 3.14 to Williams Partners L.P.’s annual report on Form 10-K (File No. 001-34831) and incorporated herein by reference).
3.19	—	Eighth Amended and Restated Limited Liability Company Agreement of WPZ GP LLC (filed on August 2, 2016 as Exhibit 3.17 to Williams Partners L.P.’s quarterly report on Form 10-Q (File No. 001-34831) 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.



Exhibit No.		Description

101.CAL*	—	XBRL Taxonomy Extension Calculation Linkbase.
101.DEF*	—	XBRL Taxonomy Extension Definition Linkbase.
101.LAB*	—	XBRL Taxonomy Extension Label Linkbase.
101.PRE*	—	XBRL Taxonomy Extension Presentation Linkbase.


*	Filed herewith.


**	Furnished herewith.


§	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.



	WILLIAMS PARTNERS L.P.
	(Registrant)
	By: WPZ GP LLC, its general partner

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

November 2, 2017

WILLIAMS PARTNERS L.P. - FORM 10-Q - November 2, 2017

Attached files

WILLIAMS PARTNERS L.P. Reports