WILLIAMS PARTNERS L.P. - FORM 10-Q

WILLIAMS PARTNERS L.P. - FORM 10-Q - October 31, 2016

Attached files

Attached files

WILLIAMS PARTNERS L.P. Reports

file	filename
EX-3.13 - EX-3.13 - WILLIAMS PARTNERS L.P.	wpz_20160930xex313.htm
EX-32 - EX-32 - WILLIAMS PARTNERS L.P.	wpz_20160930xex32.htm
EX-31.2 - EX-31.2 - WILLIAMS PARTNERS L.P.	wpz_20160930xex312.htm
EX-31.1 - EX-31.1 - WILLIAMS PARTNERS L.P.	wpz_20160930xex311.htm
EX-12 - EX-12 - WILLIAMS PARTNERS L.P.	wpz_20160930xex12.htm
EX-10.2 - EX-10.2 - WILLIAMS PARTNERS L.P.	wpz_20160930xex102.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, 2016



¨	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 or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

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 595,916,792 common units and 16,314,835 Class B units outstanding as of October 27, 2016.

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, 2016 and 2015		6
Consolidated Balance Sheet – September 30, 2016 and December 31, 2015		7
Consolidated Statement of Changes in Equity – Nine Months Ended September 30, 2016		8
Consolidated Statement of Cash Flows – Nine Months Ended September 30, 2016 and 2015		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		56
Item 4. Controls and Procedures		57
Part II. Other Information		57
Item 1. Legal Proceedings		57
Item 1A. Risk Factors		58
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		58
Item 6. Exhibits		59

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:


•	Expected levels of cash distributions with respect to general partner interests, incentive distribution rights and limited partner interests;


•	Our and our affiliates’ future credit ratings;


•	Amounts and nature of future capital expenditures;


•	Expansion of our business and operations;


•	Financial condition and liquidity;


•	Business strategy;


•	Cash flow from operations or results of operations;


•	Seasonality of certain business components;


•	Natural gas, natural gas liquids, and olefins 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 have sufficient cash from operations to enable us to pay current and expected levels of cash distributions, if any, following the establishment of cash reserves and payment of fees and expenses, including payments to our general partner;


•	Whether we will be able to effectively execute our financing plan including the receipt of anticipated levels of proceeds from planned asset sales;


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


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


•	Inflation, interest rates, fluctuation in foreign exchange 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 of alternative energy sources;


•	Availability of adequate insurance coverage and the impact of operational and developmental hazards and unforeseen interruptions;


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


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


•	Our allocated 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 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 the risk factors discussed below in addition to the other information in this report. If any of the following risks 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 26, 2016 and in Part II, Item 1A. Risk Factors in our Quarterly Reports on Form 10-Q.

DEFINITIONS

The following is a listing of certain abbreviations, acronyms, and other industry terminology 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:

ACMP: Access Midstream Partners, L.P. prior to its merger with Pre-merger WPZ

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

Pre-merger WPZ: Williams Partners L.P. prior to its merger with ACMP

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, 2016, 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)

DRIP: Distribution Reinvestment Program

Energy Transfer or ETE: Energy Transfer Equity, L.P.

ETC: Energy Transfer Corp LP

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

ETC Merger: Merger wherein Williams was to be merged into ETC

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

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

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,
	2016			2015			2016			2015
	(Millions, except per-unit amounts)
Revenues:
Service revenues	$	1,252		$	1,232		$	3,688		$	3,655
Product sales	655			560			1,613			1,678
Total revenues	1,907			1,792			5,301			5,333
Costs and expenses:
Product costs	463			426			1,183			1,383
Operating and maintenance expenses	385			394			1,153			1,205
Depreciation and amortization expenses	426			423			1,293			1,261
Selling, general, and administrative expenses	147			156			467			513
Net insurance recoveries – Geismar Incident	—			—			—			(126		)
Impairment of long-lived assets	1			2			403			29
Other (income) expense – net	59			5			107			33
Total costs and expenses	1,481			1,406			4,606			4,298
Operating income (loss)	426			386			695			1,035
Equity earnings (losses)	104			92			302			236
Impairment of equity-method investments	—			(461		)	(112		)	(461		)
Other investing income (loss) – net	28			—			29			1
Interest incurred	(236		)	(216		)	(715		)	(640		)
Interest capitalized	7			11			26			40
Other income (expense) – net	16			22			43			70
Income (loss) before income taxes	345			(166		)	268			281
Provision (benefit) for income taxes	(6		)	1			(85		)	4
Net income (loss)	351			(167		)	353			277
Less: Net income (loss) attributable to noncontrolling interests	25			27			67			82
Net income (loss) attributable to controlling interests	$	326		$	(194	)	$	286		$	195
Allocation of net income (loss) for calculation of earnings per common unit:
Net income (loss) attributable to controlling interests	$	326		$	(194	)	$	286		$	195
Allocation of net income (loss) to general partner	72			1			481			412
Allocation of net income (loss) to Class B units	7			(5		)	(6		)	(6		)
Allocation of net income (loss) to Class D units	—			—			—			68
Allocation of net income (loss) to common units	$	247		$	(190	)	$	(189	)	$	(279	)
Basic earnings (loss) per common unit:
Net income (loss) per common unit	$	.42		$	(.32	)	$	(.32	)	$	(.50	)
Weighted-average number of common units outstanding (thousands)	591,304			586,722			589,498			560,432
Diluted earnings (loss) per common unit:
Net income (loss) per common unit	$	.42		$	(.32	)	$	(.32	)	$	(.50	)
Weighted-average number of common units outstanding (thousands)	591,567			586,722			589,498			560,432
Cash distributions per common unit	$	.85		$	.85		$	2.55		$	2.55

Other comprehensive income (loss):
Cash flow hedging activities:
Net unrealized gain (loss) from derivative instruments	$	2		$	6		$	2		$	6
Reclassifications into earnings of net derivative instruments (gain) loss	—			(4		)	—			(4		)
Foreign currency translation activities:
Foreign currency translation adjustments	(16		)	(64		)	61			(137		)
Reclassification into earnings upon sale of foreign entity	108			—			108			—
Other comprehensive income (loss)	94			(62		)	171			(135		)
Comprehensive income (loss)	445			(229		)	524			142
Less: Comprehensive income attributable to noncontrolling interests	25			27			67			82
Comprehensive income (loss) attributable to controlling interests	$	420		$	(256	)	$	457		$	60

See accompanying notes.

Williams Partners L.P.

Consolidated Balance Sheet

(Unaudited)



	September 30, 2016			December 31, 2015
	(Dollars in millions)
ASSETS
Current assets:
Cash and cash equivalents	$	68		$	96
Trade accounts and other receivables (net of allowance of $5 at September 30, 2016 and $3 at December 31, 2015)	837			1,026
Inventories	120			127
Other current assets and deferred charges	381			190
Total current assets	1,406			1,439
Investments	7,084			7,336
Property, plant, and equipment, at cost	37,786			37,833
Accumulated depreciation and amortization	(9,947		)	(9,233		)
Property, plant, and equipment – net	27,839			28,600
Intangible assets – net of accumulated amortization	9,751			10,016
Regulatory assets, deferred charges, and other	458			479
Total assets	$	46,538		$	47,870
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable:
Trade	$	592		$	648
Affiliate	62			141
Accrued interest	187			231
Asset retirement obligations	51			57
Other accrued liabilities	565			469
Commercial paper	2			499
Long-term debt due within one year	785			176
Total current liabilities	2,244			2,221
Long-term debt	18,918			19,001
Asset retirement obligations	792			857
Deferred income tax liabilities	17			119
Regulatory liabilities, deferred income, and other	1,314			1,066
Contingent liabilities (Note 11)
Equity:
Partners’ equity:
Common units (595,916,630 and 588,546,022 units outstanding at September 30, 2016 and December 31, 2015, respectively)	18,354			19,730
Class B units (16,314,835 and 14,784,015 units outstanding at September 30, 2016 and December 31, 2015, respectively)	767			771
General partner	2,383			2,552
Accumulated other comprehensive income (loss)	(1		)	(172		)
Total partners’ equity	21,503			22,881
Noncontrolling interests in consolidated subsidiaries	1,750			1,725
Total equity	23,253			24,606
Total liabilities and equity	$	46,538		$	47,870

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, 2015	$	19,730		$	771		$	2,552		$	(172	)	$	22,881		$	1,725		$	24,606
Net income (loss)	(132		)	(4		)	422			—			286			67			353
Other comprehensive income (loss)	—			—			—			171			171			—			171
Noncash consideration from The Williams Companies, Inc. (Note 2)	—			—			(150		)	—			(150		)	—			(150		)
Sale of common units (Note 9)	250			—			—			—			250			—			250
Cash distributions	(1,501		)	—			(455		)	—			(1,956		)	—			(1,956		)
Contributions from general partner	—			—			14			—			14			—			14
Contributions from noncontrolling interests	—			—			—			—			—			27			27
Distributions to noncontrolling interests	—			—			—			—			—			(69		)	(69		)
Other	7			—			—			—			7			—			7
Net increase (decrease) in equity	(1,376		)	(4		)	(169		)	171			(1,378		)	25			(1,353		)
Balance – September 30, 2016	$	18,354		$	767		$	2,383		$	(1	)	$	21,503		$	1,750		$	23,253

See accompanying notes.

Williams Partners L.P.

Consolidated Statement of Cash Flows

(Unaudited)



	Nine Months Ended September 30,
	2016			2015
	(Millions)
OPERATING ACTIVITIES:
Net income (loss)	$	353		$	277
Adjustments to reconcile to net cash provided (used) by operating activities:
Depreciation and amortization	1,293			1,261
Provision (benefit) for deferred income taxes	(86		)	1
Impairment of equity-method investments	112			461
Impairment of and net (gain) loss on sale of assets and businesses	438			34
Amortization of stock-based awards	17			22
Cash provided (used) by changes in current assets and liabilities:
Accounts and notes receivable	175			206
Inventories	(2		)	76
Other current assets and deferred charges	(9		)	(11		)
Accounts payable	(32		)	(130		)
Accrued liabilities	194			(35		)
Affiliate accounts receivable and payable – net	(84		)	(9		)
Other, including changes in noncurrent assets and liabilities	(28		)	(55		)
Net cash provided (used) by operating activities	2,341			2,098
FINANCING ACTIVITIES:
Proceeds from (payments of) commercial paper – net	(499		)	727
Proceeds from long-term debt	3,663			5,450
Payments of long-term debt	(3,121		)	(4,133		)
Proceeds from sales of common units	250			—
Contributions from general partner	14			11
Distributions to limited partners and general partner	(1,956		)	(2,173		)
Distributions to noncontrolling interests	(69		)	(59		)
Contributions from noncontrolling interests	27			85
Contributions from The Williams Companies, Inc. – net	—			20
Payments for debt issuance costs	(8		)	(30		)
Special distribution from Gulfstream	—			396
Contribution to Gulfstream for repayment of debt	(148		)	—
Other – net	(2		)	(4		)
Net cash provided (used) by financing activities	(1,849		)	290
INVESTING ACTIVITIES:
Property, plant, and equipment:
Capital expenditures (1)	(1,472		)	(2,142		)
Net proceeds from dispositions	5			3
Proceeds from sale of businesses, net of cash divested	510			—
Purchases of businesses, net of cash acquired	—			(112		)
Purchases of and contributions to equity-method investments	(132		)	(528		)
Distributions from unconsolidated affiliates in excess of cumulative earnings	341			251
Other – net	228			79
Net cash provided (used) by investing activities	(520		)	(2,449		)
Increase (decrease) in cash and cash equivalents	(28		)	(61		)
Cash and cash equivalents at beginning of year	96			171
Cash and cash equivalents at end of period	$	68		$	110
_________
(1) Increases to property, plant, and equipment	$	(1,429	)	$	(2,049	)
Changes in related accounts payable and accrued liabilities	(43		)	(93		)
Capital expenditures	$	(1,472	)	$	(2,142	)

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, 2015, in Exhibit 99.1 of our Form 8-K dated May 27, 2016. 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. 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. As of September 30, 2016, Williams owns an approximate 58 percent limited partner interest, a 2 percent general partner interest, and incentive distribution rights (IDRs) in us.

WPZ 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.

Williams’ Merger Agreement with Energy Transfer

On September 28, 2015, Williams publicly announced in a press release that it had entered into an Agreement and Plan of Merger (Merger Agreement) with Energy Transfer Equity, L.P. (Energy Transfer) and certain of its affiliates. The Merger Agreement provided that, subject to the satisfaction of customary closing conditions, Williams would be merged with and into the newly formed Energy Transfer Corp LP (ETC) (ETC Merger), with ETC surviving the ETC Merger. Energy Transfer formed ETC as a limited partnership that would be treated as a corporation for U.S. federal income tax purposes. Immediately following the completion of the ETC Merger, ETC would contribute to Energy Transfer all of the assets and liabilities of Williams in exchange for the issuance by Energy Transfer to ETC of a number of Energy Transfer Class E common units equal to the number of ETC common shares issued to Williams stockholders in the ETC Merger.

Notes (Continued)

On June 29, 2016, Energy Transfer provided Williams written notice terminating the Merger Agreement, citing the alleged failure of certain conditions under the Merger Agreement.

ACMP Merger

On February 2, 2015, Williams Partners L.P. merged with and into Access Midstream Partners, L.P. (ACMP Merger). For the purpose of these financial statements and notes, Williams Partners L.P. (WPZ) refers to the renamed merged partnership, while Pre-merger Access Midstream Partners, L.P. (ACMP) and Pre-merger Williams Partners L.P. (Pre-merger WPZ) refer to the separate partnerships prior to the consummation of the ACMP Merger and subsequent name change. The net assets of Pre-merger WPZ and ACMP were combined at Williams’ historical basis. Williams’ basis in ACMP reflected its business combination accounting resulting from acquiring control of ACMP on July 1, 2014.

Description of Business

Our operations are located in North America. Effective January 1, 2016, businesses located in the Marcellus and Utica shale plays within the former Access Midstream segment are now managed, and thus presented, within the Northeast G&P segment. The remaining Access Midstream businesses are now presented as the Central segment. As a result, beginning with the reporting of first quarter 2016, our operations are organized into the following reportable segments: Central, Northeast G&P, Atlantic-Gulf, West, and NGL & Petchem Services. Prior period segment disclosures have been recast for these segment changes.

Central provides domestic gathering, treating, and compression services to producers under long-term, fixed-fee contracts. Its primary operating areas are in 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. Central also includes a 50 percent equity-method investment in the Delaware basin gas gathering system (DBJV) in the Mid-Continent region.

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 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, and Appalachia Midstream Services, LLC, which owns equity-method investments with an approximate average 45 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, 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 gathering, processing, and treating operations in New Mexico, Colorado, and Wyoming, and our interstate natural gas pipeline, Northwest Pipeline LLC (Northwest Pipeline).

NGL & Petchem Services is comprised of our 88.5 percent undivided interest in an olefins production facility in Geismar, Louisiana, along with a refinery grade propylene splitter and pipelines in the Gulf Coast region, 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, we completed the sale of our Canadian operations. (See Note 2 – Divestiture.) This segment also includes our NGL and natural gas marketing business, storage facilities, and 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).

Notes (Continued)

Basis of Presentation

Accumulated other comprehensive income (loss)

Accumulated other comprehensive income (loss) (AOCI) is substantially comprised of foreign currency translation adjustments. The cumulative foreign currency translation adjustment was reclassified into earnings as part of the net loss upon completing the sale of our Canadian operations in September 2016 (see Note 2 – Divestiture). We no longer expect to have any significant foreign currency translation adjustments within AOCI.

Significant risks and uncertainties

At the end of the third quarter of 2016, we became aware of changes involving certain of DBJV’s customer contracts, which impacted our estimates of DBJV’s future cash flows. As such, we evaluated this investment for impairment at September 30, 2016, and through the date of this filing, and determined that no impairment was necessary. The carrying value of our investment in DBJV at September 30, 2016, is $964 million.

We estimated the fair value of this investment using an income approach. The computations considered our estimate of the future cash flows associated with the underlying business. We have recently entered into initial discussions with the system operator regarding the terms and economic assumptions of these contract changes. Depending upon the outcome of these discussions, we may not approve of the contract changes and it is possible that we could exercise our rights pursuant to the operating agreement and move to arbitration proceedings to address these contracts and other matters potentially impacting the future cash flows of DBJV. As a result, it is reasonably possible that the ultimate outcome could adversely affect our estimates of future cash flows and could ultimately result in a future impairment of our investment in DBJV.

Accounting standards issued but not yet adopted

In August 2016, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (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. The new standard is effective for interim and annual periods beginning after December 15, 2017. Early adoption is permitted. The new standard requires a retrospective transition. We are evaluating the impact of the new standard 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. The new standard is effective for interim and annual periods beginning after December 15, 2019. Early adoption is permitted. The new standard requires varying transition methods for the different categories of amendments. We are evaluating the impact of the new standard on our consolidated financial statements.

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. The new standard 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. The new standard is effective for interim and annual periods beginning after December 15, 2018. Early adoption is permitted. The new standard 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 evaluating the impact of the new standard on our consolidated financial statements.

In May 2014, the FASB issued ASU 2014-09 establishing Accounting Standards Codification (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

Notes (Continued)

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 both the impact of this new standard on our consolidated financial statements and the transition method we will utilize for adoption.

Note 2 – Divestiture

In September 2016, we completed the sale of subsidiaries conducting Canadian operations (such subsidiaries, the disposal group) for total consideration of $839 million, including $510 million of cash proceeds, net of $13 million of cash divested and subject to customary working capital adjustments. The total consideration also includes $171 million of escrowed proceeds expected to be fully received in late 2016 or early 2017 pending clearance by the Canadian Revenue Agency and $8 million of other contingent consideration, both reflected in Other current assets and deferred charges in the Consolidated Balance Sheet. Consideration also includes $150 million in the form of a waiver of incentive distributions otherwise payable to Williams in the fourth quarter of 2016. The waiver recognizes certain affiliate contracts wherein our Canadian operations provided services to Williams. This noncash transaction is reflected as a decrease in General partner equity. We used the cash proceeds from the transactions 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 long-lived assets in the Consolidated Statement of Comprehensive Income (Loss). (See Note 10 – Fair Value Measurements and Guarantees.) We recorded an additional loss of $32 million at NGL & Petchem Services upon completion of the sale, 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 disposal group, excluding the impairment and loss noted above.



	Three Months Ended September 30,				Nine Months Ended September 30,
	2016		2015		2016			2015
	(Millions)
Income (loss) before income taxes of disposal group	$	16	$	3	$	(9	)	$	6

Note 3 – Variable Interest Entities

As of September 30, 2016, 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 for the Tubular Bells oil and gas discovery 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. Construction of an expansion project is underway that will provide production handling and gathering services for the Gunflint oil and gas discovery in the eastern deepwater Gulf of Mexico. The expansion project is expected to be completed in two phases. The first phase went into service in July of 2016 and the second phase is expected to go into service in the fourth quarter of 2016. The current estimate of the total remaining construction cost for the expansion project is approximately $19 million, which we expect will be funded with revenues received from customers and capital contributions from us and the other equity partner on a proportional basis.

Notes (Continued)

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 $687 million, which we expect will be funded with capital contributions from us and the other equity partners on a proportional basis.

In December 2014, we received approval from the Federal Energy Regulatory Commission to construct and operate the Constitution pipeline. However, in April 2016, the New York State Department of Environmental Conservation (NYSDEC) denied a necessary water quality certification for the New York portion of the Constitution pipeline. We remain steadfastly committed to the project, and in May 2016, Constitution appealed the NYSDEC's denial of the certification and filed an action in federal court seeking a declaration that the State of New York's authority to exercise permitting jurisdiction over certain other environmental matters is preempted by federal law. In light of the NYSDEC's denial of the water quality certification and the actions taken to challenge the decision, the project in-service date is targeted as early as the second half of 2018, which assumes that the legal challenge process is satisfactorily and promptly concluded. 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, 2016, and are included within Property, plant, and equipment, at cost 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 Gas Services, L.L.C (Cardinal), a subsidiary that provides gathering services for the Utica 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.

Notes (Continued)

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



	September 30, 2016			December 31, 2015			Classification
	(Millions)
Assets (liabilities):
Cash and cash equivalents	$	50		$	70		Cash and cash equivalents
Accounts receivable	81			71			Trade accounts and other receivables – net
Prepaid assets	3			2			Other current assets and deferred charges
Property, plant, and equipment – net	3,055			3,000			Property, plant, and equipment – net
Intangible assets – net	1,444			1,483			Intangible assets – net of accumulated amortization
Accounts payable	(49		)	(59		)	Accounts payable – trade
Accrued liabilities	(4		)	(14		)	Other accrued liabilities
Current deferred revenue	(63		)	(62		)	Other accrued liabilities
Noncurrent asset retirement obligations	(100		)	(93		)	Asset retirement obligations
Noncurrent deferred revenue associated with customer advance payments	(318		)	(331		)	Regulatory liabilities, deferred income, and other

Notes (Continued)

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

The allocation of net income (loss) among our general partner, limited partners, and noncontrolling interests is as follows:



	Three Months Ended September 30,						Nine Months Ended September 30,
	2016			2015			2016			2015
	(Millions)
Allocation of net income to general partner:
Net income (loss)	$	351		$	(167	)	$	353		$	277
Net income applicable to pre-merger operations allocated to general partner	—			—			—			(2		)
Net income applicable to noncontrolling interests	(25		)	(27		)	(67		)	(82		)
Costs charged directly to the general partner	—			1			—			21
Income (loss) subject to 2% allocation of general partner interest	326			(193		)	286			214
General partner’s share of net income	2		%	2		%	2		%	2		%
General partner’s allocated share of net income (loss) before items directly allocable to general partner interest	7			(4		)	6			4
Priority allocations, including incentive distributions, paid to general partner	210			210			416			633
Pre-merger net income allocated to general partner interest	—			—			—			2
Costs charged directly to the general partner	—			(1		)	—			(21		)
Net income allocated to general partner’s equity	$	217		$	205		$	422		$	618

Net income (loss)	$	351		$	(167	)	$	353		$	277
Net income allocated to general partner’s equity	217			205			422			618
Net income (loss) allocated to Class B limited partners’ equity	3			(10		)	(4		)	(12		)
Net income allocated to Class D limited partners’ equity (1)	—			—			—			69
Net income allocated to noncontrolling interests	25			27			67			82
Net income (loss) allocated to common limited partners’ equity	$	106		$	(389	)	$	(132	)	$	(480	)

Adjustments to reconcile Net income (loss) allocated to common limited partners’ equity to Allocation of net income (loss) to common units:
Incentive distributions paid (2)	210			210			411			633
Incentive distributions declared (2) (3)	(63		)	(1		)	(473		)	(422		)
Impact of unit issuance timing and other	(6		)	(10		)	5			(10		)
Allocation of net income (loss) to common units	$	247		$	(190	)	$	(189	)	$	(279	)


(1)	Includes amortization of the beneficial conversion feature associated with the Pre-merger WPZ Class D units of $68 million for the nine months ended September 30, 2015. See following discussion of Class D units.

(2)

Incentive distributions paid for the nine months ended September 30, 2016, and Incentive distributions declared for the three and nine months ended September 30, 2015, reflect the waiver associated with the Termination Agreement. (See Note 1 – General, Description of Business, and Basis of Presentation.) Incentive distributions declared for the three and nine months ended September 30, 2016, reflect the waiver associated with the sale of our Canadian operations. (See Note 2 – Divestiture.)


(3)	The Board of Directors of our general partner declared a cash distribution of $0.85 per common unit on October 25, 2016, to be paid on November 14, 2016, to unitholders of record at the close of business on November 4, 2016.

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

Notes (Continued)

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 375,181 Class B units associated with the third-quarter distribution, to be issued on November 14, 2016.

Class D Units

The Pre-merger WPZ Class D units, issued in February 2014 in conjunction with our acquisition of certain Canadian operations, were issued at a discount to the market price of Pre-merger WPZ’s common units, into which they were convertible. The remaining unamortized balance was recognized in the first quarter of 2015 due to the ACMP Merger. All Pre-merger WPZ Class D units were converted into common units in conjunction with the ACMP Merger.

Note 5 – Investing Activities

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 within the Northeast G&P segment.

During the third quarter of 2015, we recognized a loss of $16 million within Equity earnings (losses) in the Consolidated Statement of Comprehensive Income (Loss) associated with our share of underlying property impairments at certain of the Appalachia Midstream Investments. This item is reported within the Northeast G&P segment.

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) within the Central and Northeast G&P segments, respectively.

During the third quarter of 2015, we recognized other-than-temporary impairment charges of $458 million and $3 million related to our equity-method investments in DBJV and certain of the Appalachia Midstream Investments, respectively (see Note 10 – Fair Value Measurements and Guarantees.) These items are reported within the Central and Northeast G&P segments, respectively.

Investments

On September 24, 2015, we received a special distribution of $396 million from Gulfstream reflecting our proportional share of the proceeds from new debt issued by Gulfstream. The new debt was issued to refinance Gulfstream’s debt maturities. Subsequently, we contributed $248 million and $148 million to Gulfstream for our proportional share of amounts necessary to fund debt maturities of $500 million due on November 1, 2015 and $300 million due on June 1, 2016, respectively.

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 are considered significant.



	Three Months Ended September 30,				Nine Months Ended September 30,
	2016		2015		2016		2015
	(Millions)
Gross revenue	$	226	$	241	$	648	$	658
Operating income	132		131		376		334
Net income	117		113		321		281

Notes (Continued)

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,
	2016		2015			2016		2015
	(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	6		5			19		15
Project development costs related to Constitution (see Note 3)	11		—			19		—
NGL & Petchem Services
Net foreign currency exchange (gains) losses (1)	—		(4		)	11		(8		)
Loss on sale of Canadian operations (see Note 2)	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 (see Note 2 – Divestiture).

ACMP Merger and Transition

Nine months ended September 30, 2016

Selling, general, and administrative expenses includes $5 million for the nine months ended September 30, 2016, associated with the ACMP Merger and transition. These costs are primarily reflected within the Central segment.

Three and nine months ended September 30, 2015

Selling, general, and administrative expenses includes $1 million and $35 million for the three and nine months ended September 30, 2015, respectively, primarily related to professional advisory fees and employee transition costs associated with the ACMP Merger and transition. These costs are primarily reflected within the Central segment.

Operating and maintenance expenses includes $10 million for the nine months ended September 30, 2015, of transition costs from the ACMP Merger primarily within the Central segment.

Interest incurred includes transaction-related financing costs of $2 million for the nine months ended September 30, 2015, from the ACMP Merger.

Geismar Incident

On June 13, 2013, an explosion and fire occurred at our Geismar olefins plant. The incident rendered the facility temporarily inoperable (Geismar Incident). We received $126 million of insurance recoveries during the nine months ended September 30, 2015, reported within the NGL & Petchem Services segment and reflected as gains in Net insurance recoveries - Geismar Incident.

Additional Items

Three and nine months ended September 30, 2016

Service revenues have been 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.

Notes (Continued)

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



	Nine Months Ended September 30, 2016
	(Millions)
Central	$	6
Northeast G&P	3
Atlantic-Gulf	8
West	4
NGL & Petchem Services	4

Other income (expense) – net below Operating income (loss) includes $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.

Three and nine months ended September 30, 2015

Other income (expense) – net below Operating income (loss) includes $20 million and $56 million for the three and nine months ended September 30, 2015, respectively, for allowance for equity funds used during construction within the Atlantic-Gulf segment. Other income (expense) – net below Operating income (loss) also includes a $14 million gain for the nine months ended September 30, 2015, resulting from the early retirement of certain debt.

Note 7 – Provision (Benefit) for Income Taxes

The Provision (benefit) for income taxes includes:



	Three Months Ended September 30,						Nine Months Ended September 30,
	2016			2015			2016			2015
	(Millions)
Current:
State	$	(1	)	$	2		$	—		$	3
Foreign	1			—			1			—
	—			2			1			3
Deferred:
State	—			—			(4		)	(6		)
Foreign	(6		)	(1		)	(82		)	7
	(6		)	(1		)	(86		)	1

Provision (benefit) for income taxes	$	(6	)	$	1		$	(85	)	$	4

The effective income tax rate for the three months ended September 30, 2016, is less than the federal statutory rate primarily due to income not subject to U.S. federal tax and taxes on foreign operations.

The effective income tax rate for the nine months ended September 30, 2016, is less than the federal statutory rate primarily due to income not subject to U.S. federal tax and 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).

The effective income tax rate for the three months ended September 30, 2015, is less than the federal statutory rate primarily due to income not subject to U.S. federal tax, partially offset by taxes on foreign operations.

The effective income tax rate for the nine months ended September 30, 2015, is less than the federal statutory rate primarily due to income not subject to U.S. federal tax, partially offset by taxes on foreign operations. The 2015 state

Notes (Continued)

deferred benefit includes $7 million related to the impact of a Texas franchise tax rate decrease. The 2015 foreign deferred provision includes $8 million related to the impact of an Alberta provincial tax rate increase.

Note 8 – Debt and Banking Arrangements

Long-Term Debt

Issuances and retirements

On January 22, 2016, Transco issued $1 billion of 7.85 percent senior unsecured notes due 2026 to investors in a private debt placement. Transco used the net proceeds to repay debt and to fund capital expenditures. As part of the new issuance, Transco entered into a registration rights agreement with the initial purchasers of the unsecured notes. Transco 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. Transco is required to provide a shelf registration statement to cover resales of the notes under certain circumstances. If Transco 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 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 defaults of 0.5 percent annually. Following the cure of any registration defaults, the accrual of additional interest will cease.

Transco retired $200 million of 6.4 percent senior unsecured notes that matured on April 15, 2016.

Northwest Pipeline retired $175 million of 7 percent senior unsecured notes that matured on June 15, 2016.

Commercial Paper Program

As of September 30, 2016, we had $2 million of Commercial paper outstanding under our $3 billion commercial paper program with a weighted average interest rate of 1.30 percent.

Credit Facilities



	September 30, 2016
	Stated Capacity		Outstanding
	(Millions)
Long-term credit facility (1)	$	3,500	$	1,230
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

In September 2016, we filed a Form S-3D registration statement with the Securities and Exchange Commission for our new distribution reinvestment program (DRIP). The DRIP is expected to commence with the quarterly distribution for the quarter ending September 30, 2016. Under the DRIP, registered unitholders may invest all or a portion of their cash distributions in our common units. The price for newly issued common units purchased under the DRIP will be the average of the high and low trading prices of our common units for the five trading days immediately preceding the distribution, less a discount rate currently set at 2.5 percent.

In August 2016, we completed an equity issuance of 6,975,446 common units sold to Williams in a private placement. The units were sold for an aggregate purchase price of approximately $250 million. In addition, Williams contributed the proportionate share necessary to maintain its 2 percent general partner interest. The proceeds were used to repay amounts outstanding under our credit facility and for general partnership purposes.

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, 2016:
Measured on a recurring basis:
ARO Trust investments	$	93		$	93		$	93		$	—		$	—
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	(7		)	(7		)	(1		)	—			(6		)
Additional disclosures:
Contingent consideration (see Note 2)	8			8			—			—			8
Other receivables	14			14			14			—			—
Long-term debt, including current portion (1)	(19,703		)	(20,455		)	—			(20,455		)	—

Assets (liabilities) at December 31, 2015:
Measured on a recurring basis:
ARO Trust investments	$	67		$	67		$	67		$	—		$	—
Energy derivatives assets not designated as hedging instruments	5			5			—			3			2
Energy derivatives liabilities not designated as hedging instruments	(2		)	(2		)	—			—			(2		)
Additional disclosures:
Other receivables	12			12			10			2			—
Long-term debt, including current portion (1)	(19,176		)	(15,988		)	—			(15,988		)	—

___________________________________

(1) Excludes capital leases.

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

Notes (Continued)

under the terms of our master netting arrangements. Further, the amounts do not include cash held on deposit in margin accounts that we have received or remitted to collateralize certain derivative positions. Energy derivatives assets are reported in Other current assets and deferred charges and Regulatory assets, deferred charges, and other in the Consolidated Balance Sheet. Energy derivatives liabilities are reported in 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, 2016 or 2015.

Additional fair value disclosures

Other receivables: Other receivables primarily consists 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: The disclosed fair value of our long-term debt is determined 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.

Nonrecurring fair value measurements

The following table presents impairments 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		2016		2015
				(Millions)
Surplus equipment (1)	Property, plant, and equipment – net	Northeast G&P	June 30, 2015	$	17			$	20
Canadian operations (2)	Assets held for sale	NGL & Petchem Services	June 30, 2016	924		$	341
Certain gathering operations (3)	Property, plant, and equipment – net	Central	June 30, 2016	18		48
Level 3 fair value measurements of long-lived assets						389		20
Other impairments (4)						14		9
Impairment of long-lived assets						$	403	$	29

Equity-method investments (5)	Investments	Central and Northeast G&P	September 30, 2015	$	1,203			$	461
Equity-method investments (6)	Investments	Central and Northeast G&P	March 31, 2016	1,294		$	109
Other equity-method investment	Investments	Central	March 31, 2016	—		3
Impairment of equity-method investments						$	112	$	461

_________________


(1)	Relates to certain surplus equipment. The estimated fair value was determined by a market approach based on our analysis of observable inputs in the principal market.


(2)	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

Notes (Continued)

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. See Note 2 – Divestiture.


(3)	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.


(4)	Reflects multiple individually insignificant impairments 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 zero or an insignificant salvage value.

(5)

Relates to equity-method investments in DBJV at Central and certain of the Appalachia Midstream Investments in Northeast G&P. The historical carrying value of these investments was initially recorded based on estimated fair value during the third quarter of 2014 in conjunction with our acquisition of ACMP. We estimated the fair value of these 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 were 11.8 percent and 8.8 percent for DBJV and certain of the Appalachia Midstream Investments, respectively, and reflected our cost of capital as impacted by market conditions, and risks associated with the underlying businesses.

(6)

Relates to Central’s equity-method investment in DBJV and Northeast G&P’s 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 investments, along with lower natural gas prices for Laurel Mountain. We estimated the fair value of these 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 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 agreements to indemnify lenders for certain taxes required to be withheld from payments due to the lenders and for certain tax payments made by the lenders. The maximum potential amount of future payments under these indemnifications is based on the related borrowings and such future payments cannot currently be determined. These indemnifications generally continue indefinitely unless limited by the underlying tax regulations and have no carrying value. We have never been called upon to perform under these indemnifications and have no current expectation of a future claim.

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, 2016, we have accrued liabilities totaling $14 million for these matters, as discussed below. Our accrual reflects the most likely costs of cleanup, which are generally based on completed assessment studies, preliminary results of studies, or our experience with other similar cleanup operations. Certain assessment studies are still in process for which the ultimate outcome may yield significantly different estimates of most likely costs. Any incremental amount in excess of amounts currently accrued cannot be reasonably estimated at this time due to uncertainty about the actual number of contaminated sites ultimately identified, the actual amount and extent of contamination discovered, and the final cleanup standards mandated by the EPA and other governmental authorities.

Notes (Continued)

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, new 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 new rule regarding National Ambient Air Quality Standards for ground-level ozone, setting a new 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, 2016, we have accrued liabilities of $7 million for these costs. We expect that these costs will be recoverable through rates.

We also accrue environmental remediation costs for natural gas underground storage facilities, primarily related to soil and groundwater contamination. At September 30, 2016, we have accrued liabilities totaling $7 million for these costs.

Geismar Incident

On June 13, 2013, an explosion and fire occurred at our Geismar olefins plant and rendered the facility temporarily inoperable. 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. To date, we have settled certain of the personal injury claims for an aggregate immaterial amount that we have recovered from our insurers. The first trial, for four plaintiffs claiming personal injury, began on September 6, 2016, in Louisiana state court in Iberville Parish, Louisiana. On September 26, 2016, the jury returned a verdict against Williams, our subsidiary Williams Olefins, LLC, and two individual defendants, awarding damages of approximately $13.6 million, a portion of which was paid in a prior partial settlement and recovered from our insurers and the remainder of which has been charged to expense in the third quarter of 2016 along with an equal offsetting amount reflecting probable insurance recovery. We and the other defendants intend to appeal the verdict. Trial dates for additional plaintiffs are scheduled in November 2016, January 2017, April 2017, and August 2017. We believe it is probable that additional losses will be incurred on some lawsuits, while for others we believe it is only reasonably possible that losses will be incurred. However, due to ongoing litigation involving defenses to liability, the number of individual plaintiffs, limited information as to the nature and extent of all plaintiffs’ damages, and the ultimate outcome of all appeals, we are unable to reliably estimate any such losses at this time. We believe that it is probable that any ultimate losses incurred will be covered by our general liability insurance policy, which has an aggregate limit of $610 million applicable to this event and retention (deductible) of $2 million per occurrence.

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 in Texas, Pennsylvania, and Ohio based on allegations that we improperly participated with that major customer in causing the alleged royalty underpayments. We have also received subpoenas from the United States Department of Justice and the Pennsylvania

Notes (Continued)

Attorney General requesting documents relating to the agreements between us and our major customer and calculations of the major customer’s royalty payments. On December 9, 2015, the Pennsylvania Attorney General filed a civil suit against one of our major customers and us alleging breaches of the Pennsylvania Unfair Trade Practices and Consumer Protection Law, and on February 8, 2016, the Pennsylvania Attorney General filed an amended complaint in such civil suit, which omitted us as a party. We believe that the claims asserted are subject to indemnity obligations owed to us by that major customer. Our customer and plaintiffs in the Texas cases reached a settlement, and therefore all claims asserted (or possibly asserted) by any such plaintiffs against us in the Texas cases have been fully dismissed with prejudice. Due to the preliminary status of the remaining cases, we are unable to estimate a range of potential loss at this time.

Stockholder Litigation

On March 7, 2016, a purported unitholder of us filed a putative class action on behalf of certain purchasers of our units in the U.S. District Court in Oklahoma. The action names as defendants, us, Williams, Williams Partners GP LLC, Alan S. Armstrong, and Donald R. Chappel and alleges violations of certain federal securities laws for failure to disclose Energy Transfer’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. We cannot reasonably estimate a range of potential loss at this time.

Opal 2014 Incident Subpoena

On July 14, 2016, our subsidiary, Williams Field Services Company, LLC (WFS), received a grand jury subpoena from the U.S. District Court for the District of Wyoming. The subpoena requests documents and information from WFS relating to, among other things, the April 23, 2014, explosion and fire at its natural gas processing facility in Lincoln County, Wyoming, near the town of Opal. We and WFS intend to cooperate fully with this investigation. It is not possible at this time to predict the outcome of this investigation, including whether the investigation will result in any action or proceeding against WFS, or to reasonably estimate any potential loss related thereto. We currently believe that this matter will not have a material adverse effect on our consolidated results of operations, financial position, or liquidity.

Other

In addition to the foregoing, various other proceedings are pending against us which are incidental to our operations.

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 Central, Northeast G&P, Atlantic-Gulf, West, and NGL & Petchem Services. (See Note 1 – General, Description of Business, and Basis of Presentation.)

Performance Measurement

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

Notes (Continued)

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;


◦	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).



	Central		Northeast G&P		Atlantic- Gulf		West		NGL & Petchem Services		Eliminations			Total
	(Millions)
Three Months Ended September 30, 2016
Segment revenues:
Service revenues
External	$	252	$	196	$	503	$	256	$	45	$	—		$	1,252
Internal	3		11		6		—		—		(20		)	—
Total service revenues	255		207		509		256		45		(20		)	1,252
Product sales
External	—		36		77		4		538		—			655
Internal	—		7		59		66		50		(182		)	—
Total product sales	—		43		136		70		588		(182		)	655
Total revenues	$	255	$	250	$	645	$	326	$	633	$	(202	)	$	1,907

Three Months Ended September 30, 2015
Segment revenues:
Service revenues
External	$	264	$	192	$	476	$	263	$	37	$	—		$	1,232
Internal	6		2		1		—		—		(9		)	—
Total service revenues	270		194		477		263		37		(9		)	1,232
Product sales
External	—		21		77		11		451		—			560
Internal	—		6		41		51		41		(139		)	—
Total product sales	—		27		118		62		492		(139		)	560
Total revenues	$	270	$	221	$	595	$	325	$	529	$	(148	)	$	1,792

Nine Months Ended September 30, 2016
Segment revenues:
Service revenues
External	$	759	$	603	$	1,415	$	774	$	137	$	—		$	3,688
Internal	9		23		8		—		—		(40		)	—
Total service revenues	768		626		1,423		774		137		(40		)	3,688
Product sales
External	—		82		177		12		1,342		—			1,613
Internal	—		18		133		188		125		(464		)	—
Total product sales	—		100		310		200		1,467		(464		)	1,613
Total revenues	$	768	$	726	$	1,733	$	974	$	1,604	$	(504	)	$	5,301

Nine Months Ended September 30, 2015
Segment revenues:
Service revenues
External	$	769	$	602	$	1,398	$	783	$	103	$	—		$	3,655
Internal	18		4		3		—		—		(25		)	—
Total service revenues	787		606		1,401		783		103		(25		)	3,655
Product sales
External	—		88		228		27		1,335		—			1,678
Internal	—		12		136		167		113		(428		)	—
Total product sales	—		100		364		194		1,448		(428		)	1,678
Total revenues	$	787	$	706	$	1,765	$	977	$	1,551	$	(453	)	$	5,333

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,
	2016			2015			2016			2015
	(Millions)
Modified EBITDA by segment:
Central	$	176		$	163		$	467		$	456
Northeast G&P	208			189			638			557
Atlantic-Gulf	416			414			1,149			1,138
West	166			169			479			480
NGL & Petchem Services	104			85			(104		)	249
Other	—			1			—			11
	1,070			1,021			2,629			2,891
Accretion expense associated with asset retirement obligations for nonregulated operations	(8		)	(5		)	(24		)	(21		)
Depreciation and amortization expenses	(426		)	(423		)	(1,293		)	(1,261		)
Equity earnings (losses)	104			92			302			236
Impairment of equity-method investments	—			(461		)	(112		)	(461		)
Other investing income (loss) – net	28			—			29			1
Proportional Modified EBITDA of equity-method investments	(194		)	(185		)	(574		)	(504		)
Interest expense	(229		)	(205		)	(689		)	(600		)
(Provision) benefit for income taxes	6			(1		)	85			(4		)
Net income (loss)	$	351		$	(167	)	$	353		$	277

The following table reflects Total assets by reportable segment.



	Total Assets
	September 30, 2016			December 31, 2015
	(Millions)
Central	$	13,234		$	13,914
Northeast G&P	13,646			13,827
Atlantic-Gulf	13,416			12,171
West	4,733			5,035
NGL & Petchem Services	2,493			3,306
Other corporate assets	141			350
Eliminations (1)	(1,125		)	(733		)
Total	$	46,538		$	47,870


(1)	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, NGLs, and olefins 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, olefin production, marketing services for NGL, oil and natural gas, as well as storage facilities.

Effective January 1, 2016, businesses located in the Marcellus and Utica shale plays within the former Access Midstream segment are now managed, and thus presented, within the Northeast G&P segment. The remaining Access Midstream businesses are now presented as the Central segment. Prior period segment disclosures have been recast for these segment changes. As a result, beginning with the reporting of first-quarter 2016, our reportable segments are Central, Northeast G&P, Atlantic-Gulf, West, and NGL & Petchem Services, which are comprised of the following businesses:

•

Central provides domestic gathering, treating, and compression services to producers under long-term, fixed-fee contracts. Its primary operating areas are in 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. Central also includes a 50 percent equity-method investment in the Delaware basin gas gathering system (DBJV) in the Mid-Continent region.

•

Northeast G&P is comprised of 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 69 percent equity-method investment in Laurel Mountain and a 58 percent equity-method investment in Caiman II. Northeast G&P also includes a 62 percent equity-method investment in UEOM and Appalachia Midstream Services, LLC, which owns equity-method investments with an approximate average 45 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, 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.

Management’s Discussion and Analysis (Continued)


•	West is comprised of our gathering, processing and treating operations in New Mexico, Colorado, and Wyoming, and our interstate natural gas pipeline, Northwest Pipeline.

•

NGL & Petchem Services is comprised of our 88.5 percent undivided interest in an olefins production facility in Geismar, Louisiana (see Geismar Olefins Facility Monetization below), along with a refinery grade propylene splitter and various petrochemical and feedstock pipelines in the Gulf Coast region, an oil sands offgas processing plant near Fort McMurray, Alberta, and an NGL/olefin fractionation facility at Redwater, Alberta. In September 2016, these Canadian operations were sold. (See Note 2 – Divestiture of Notes to Consolidated Financial Statements.) This segment also includes an NGL and natural gas marketing business, storage facilities, and an undivided 50 percent interest in an NGL fractionator near Conway, Kansas, and a 50 percent equity-method investment in OPPL.

As of September 30, 2016, Williams holds an approximate 60 percent interest in us, comprised of an approximate 58 percent limited partner interest and all of our 2 percent general partner interest and IDRs.

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 27, 2016.

Distributions

On October 25, 2016, our general partner’s Board of Directors approved a quarterly distribution to unitholders of $0.85 per common unit on November 14, 2016, on our outstanding common units to unitholders of record at the close of business on November 4, 2016.

Overview of Nine Months Ended September 30, 2016

Net income (loss) attributable to controlling interests for the nine months ended September 30, 2016, increased $91 million compared to the nine months ended September 30, 2015, reflecting lower impairments of equity-method investments, an increase in olefins margins associated with our Geismar plant, decreases in operating and maintenance and selling, general, and administrative expenses, and higher equity earnings. These favorable changes were partially offset by increased impairment charges and loss on sale associated with our Canadian operations, the absence of $126 million of insurance recoveries, and higher interest incurred. See additional discussion in Results of Operations.

Sale of Canadian Operations

In September 2016, we completed the sale of our Canadian operations for total consideration of $839 million, including $510 million of cash proceeds, net of $13 million of cash divested and subject to customary working capital adjustments. In connection with the sale, Williams agreed to waive $150 million of incentive distributions in the fourth quarter of 2016. We recognized an impairment charge of $341 million during the second quarter of 2016 related to these operations and an additional loss of $32 million upon completion of the sale. (See Note 2 – Divestiture of Notes to Consolidated Financial Statements.)

Organizational Realignment

In September 2016, Williams announced organizational changes aiming to simplify our structure, increase direct operational alignment to advance our natural gas-focused strategy, and drive continued focus on customer service and execution. Effective beginning in 2017, we plan to implement the changes, which will combine the management of certain of our operations and reduce the overall number of operating areas managed within our business.

Williams’ Merger Agreement with Energy Transfer

On September 28, 2015, Williams publicly announced in a press release that it had entered into a Merger Agreement with Energy Transfer and certain of its affiliates. The Merger Agreement provided that, subject to the satisfaction of customary closing conditions, Williams would merge with and into the newly formed ETC, with ETC surviving the

Management’s Discussion and Analysis (Continued)

ETC Merger. Energy Transfer formed ETC as a limited partnership that would be treated as a corporation for U.S. federal income tax purposes. Immediately following the completion of the ETC Merger, ETC would contribute to Energy Transfer all of the assets and liabilities of Williams in exchange for the issuance by Energy Transfer to ETC of a number of Energy Transfer Class E common units equal to the number of ETC common shares issued to Williams stockholders in the ETC Merger.

On June 29, 2016, Energy Transfer provided Williams written notice terminating the Merger Agreement, citing the alleged failure of certain conditions under the Merger Agreement.

Central

Barnett Shale and Mid-Continent Contract Restructurings

In August 2016, we conditionally committed to execute a new gas gathering agreement in the Barnett Shale. The agreement was executed in the fourth quarter of 2016, in conjunction with our existing customer, Chesapeake Energy Corporation, closing the sale of its Barnett Shale properties to another producer. That other producer, which has an investment grade credit rating, is now our customer under the new gas gathering agreement. The restructured agreement provided a $754 million up-front cash payment to us primarily in exchange for eliminating future minimum volume commitments. The restructured agreement also provides for revised gathering rates. Based on current commodity price assumptions, we generally expect the up-front cash proceeds and the ongoing cash flows generated by gathering services, to represent equivalent net present value of cash flows as compared to expected performance under the existing agreement. Additionally, we agreed to a revised contract in the Mid-Continent region, also with Chesapeake Energy Corporation. The revised contract was executed in the third quarter of 2016 and provided an up-front cash payment to us of $66 million primarily in exchange for changing from a cost of service contract to fixed-fee terms. We expect the majority of the up-front cash proceeds from both these agreements will be recognized as deferred revenue and amortized into income in future periods. In the near term, we do not expect that our trend of reported results will be significantly impacted by the effect of the discount associated with the up-front cash proceeds relative to the original minimum volume commitments and reduced gathering rates. It is anticipated that both agreements will reduce customer concentration risk and provide support to realize additional drilling and improved volumes in these regions.

West

Powder River Basin Contract Restructuring

In October 2016, in conjunction with our partner in the Bucking Horse natural gas processing plant and Jackalope Gas Gathering System, we announced an agreement with Chesapeake Energy Corporation to restructure gathering and processing contracts in the Powder River Basin. The restructured contracts become effective in January 2017, subject to final approvals, and are expected to replace the current cost-of-service arrangement with minimum annual revenue guarantees that support the transition to a new fixed-fee structure over the next five to seven years. In the near term, we do not expect that our trend of reported results will be significantly impacted by the restructured terms.

NGL & Petchem Services

Geismar Olefins Facility Monetization

In September 2016, we announced we have initiated a process to explore monetization of our ownership interest in the Geismar, Louisiana olefins plant and complex. The potential monetization process may result in a sale or a long-term, fee-for-service tolling agreement and would be consistent with our strategy to narrow our focus and allocate capital to our natural gas-focused business.

Redwater Expansion

In March 2016, we completed the expansion of our Redwater facilities to provide NGL transportation and fractionation services to Williams associated with its long-term agreement to provide gas processing services to a second bitumen upgrader in Canada’s oil sands near Fort McMurray, Alberta. With this capacity increase, additional NGL/olefins mixtures from Williams are fractionated into an ethane/ethylene mix, propane, polymer grade propylene, normal

Management’s Discussion and Analysis (Continued)

butane, an alkylation feed and condensate under a long-term, fee-based agreement. We sold these operations in September 2016. (See Note 2 – Divestiture of Notes to Consolidated Financial Statements.)

Atlantic-Gulf

Rock Springs Expansion

In August 2016, our Rock Springs expansion was placed into service. The project expanded Transco’s existing natural gas transmission system from New Jersey to a generation facility in Maryland and increased capacity by 192 Mdth/d.

Volatile Commodity Prices

NGL per-unit margins were approximately 18 percent lower in the first nine months of 2016 compared to the same period of 2015. The primary drivers for the nine-month comparative period decrease were a 9 percent decline in per-unit non-ethane prices, a 39 percent decline in ethane prices, and a change in the relative mix of NGL products produced, which has shifted to a higher proportion of lower-margin ethane products. These unfavorable impacts were partially offset by an approximate 25 percent decline in per-unit natural gas feedstock prices. NGL per-unit margins were approximately 7 percent lower for the quarter ending September 30, 2016, compared to the quarter ending June 30, 2016. The decline in NGL per-unit margins between the third and second quarter of 2016 was due primarily to an increase in natural gas prices of approximately 40 percent in the quarter ending September 30, 2016, compared to the quarter ending June 30, 2016.

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

Management’s Discussion and Analysis (Continued)

The following graph illustrates the effects of margin volatility and 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 price volatility on our business for the remainder of 2016 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 seek to accomplish this through further developing our scale positions in current key markets and basins and entering new demand driven growth markets and basins where we can become the large-scale service provider. We will 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.

In response to challenging market conditions, our business plan announced in January of 2016 included significant actions to reduce costs and funding needs, such as reductions in capital investment, a reduction in workforce, and the sale of our Canadian operations. Furthermore, we have also recently announced additional measures, including the previously discussed organizational realignment and the process to explore the monetization of our ownership interest in the Geismar olefins facility.

Our growth capital and investment expenditures in 2016 are expected to total $1.9 billion. Approximately $1.3 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 non-interstate pipeline growth capital spending in 2016 primarily reflects investment in gathering and processing systems limited primarily to known new producer volumes, including volumes that support Transco expansion projects in addition to wells drilled and

Management’s Discussion and Analysis (Continued)

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

As previously discussed, we have announced a quarterly distribution of $0.85 per common unit, or $3.40 annually. Additionally, Williams plans to reinvest approximately $1.7 billion in us through 2017, primarily through the recently implemented DRIP. Williams has already invested $250 million of the planned $1.7 billion in the third quarter of 2016 through a private placement offering. The program is expected to enhance our ability to maintain our distribution, while providing us with the flexibility to reduce debt and maintain our investment grade ratings.

Fee-based businesses are a significant component of our portfolio and serve to somewhat reduce the influence of commodity price fluctuations on our operating results and cash flows. However, producer activities have been impacted by lower energy commodity prices, which have affected our gathering volumes. The credit profiles of certain of our producer customers are increasingly challenged by the current market conditions. These conditions as well as further or prolonged declines in energy commodity prices may also result in noncash impairments of our assets.

We continue to be approached by certain customers seeking to revise certain of our gathering and processing contracts, due in part to the low energy commodity price environment. In these situations, we generally seek to reasonably consider customer needs while maintaining or improving the overall value of our contracts. Any such revisions may impact the level and timing of expected future cash flows, requiring that we evaluate the recoverability of the underlying assets, which could result in noncash impairments.

Commodity NGL margins are highly dependent upon regional supply/demand balances of natural gas while olefins are impacted by global supply and demand fundamentals. We anticipate the following trends in energy commodity prices for 2016, compared to 2015, that may impact our operating results and cash flows:


•	Natural gas prices are expected to be lower;


•	NGL prices are expected to be somewhat consistent;


•	Olefins prices, including propylene, ethylene, and the overall ethylene crack spread, are expected to be lower.

In 2016, our operating results include increases from our fee-based businesses placed in service over the last two years, increases in our olefins volumes associated with a full year of operations at our Geismar plant following its 2015 repair and expansion, and lower operating and general and administrative expenses associated with cost reduction initiatives.

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


•	Downgrade of our investment grade credit ratings and associated increase in cost of borrowings;


•	Higher cost of capital and/or limited availability of capital due to a change in our financial condition, interest rates, and/or market or industry conditions;


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


•	Lower than anticipated energy commodity prices and margins;


•	Lower than anticipated volumes from third parties served by our midstream business;


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


•	Changes in the political and regulatory environments including the risk of delay in permits needed for regulatory projects;


•	General economic, financial markets, or further industry downturn;

Management’s Discussion and Analysis (Continued)


•	Lower than expected levels of cash flow from operations;


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


•	Reduced availability of insurance coverage.

We continue to address these risks through maintaining a strong financial position and liquidity, as well as through managing a diversified portfolio of energy infrastructure assets which continue to serve key markets and basins in the United States.

Expansion Projects

Our ongoing major expansion projects include the following:

Central

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 new facilities, well connections, and gathering pipeline to the existing systems.

Northeast G&P

Oak Grove Expansion

We plan to expand our processing capacity at our Oak Grove facility by adding a second 200 MMcf/d cryogenic natural gas processing plant, which, based on our customers’ needs, is expected to be placed into service in 2020.

Gathering System Expansion

We will continue to expand the gathering systems in the Marcellus and Utica shale regions that are needed to meet our customers’ production plans. The expansion of the gathering infrastructure includes additional compression and gathering pipeline to the existing system.

Atlantic-Gulf

Constitution Pipeline

In December 2014, we received approval from the FERC to construct and operate the jointly owned Constitution 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 a necessary water quality certification for the New York portion of the pipeline. We remain steadfastly committed to the project, and in May 2016, Constitution appealed the NYSDEC’s denial of the certification and filed an action in federal court seeking a declaration that the State of New York’s authority to exercise permitting jurisdiction over certain other environmental matters is preempted by federal law. (See Note 3 – Variable Interest Entities of Notes to Consolidated Financial Statements.) 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 light of the NYSDEC’s denial of the water quality certification and the actions taken to challenge the decision, the target in-service date has been revised to as early as the second half of 2018, which assumes that the legal challenge process is satisfactorily and promptly concluded.

Management’s Discussion and Analysis (Continued)

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 plan to place the initial phase of the project into service during the first half of 2017 and the remaining portion in the fourth quarter of 2017, assuming timely receipt of all necessary regulatory approvals.

Norphlet Project

In March 2016, we announced that we have reached an agreement to provide deepwater gas gathering services to the Appomattox development in the Gulf of Mexico. The project will provide offshore gas gathering services to our existing Transco lateral, which will provide transmission services onshore to our Mobile Bay processing facility. We also plan to make modifications to our Main Pass 261 Platform to install an alternate delivery route from the platform, as well as modifications to our Mobile Bay processing facility. The project is scheduled to go into service during the second quarter of 2020.

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 proposed new interconnection with the Sabal Trail project in Alabama. The project will be constructed in phases, and all of the project expansion capacity will be leased to Sabal Trail. We plan to place the initial phase of the project into service concurrent with the in-service date of the Sabal Trail project, which is planned to occur as early as the second quarter of 2017. The in-service date of the second phase of the project 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 will pay us an aggregate amount of $240 million in three equal installments as certain milestones of the project are met. The first $80 million payment was received in March 2016 and the second installment was received in September 2016. We expect to recognize income associated with these receipts over the term of the capacity lease agreement.

Gulf Trace

In October 2015, 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 Station 65 in St. Helena Parish, Louisiana to a new interconnection with Sabine Pass Liquefaction in Cameron Parish, Louisiana. We plan to place the project into service during the first quarter of 2017 and it is expected to increase capacity by 1,200 Mdth/d.

New York Bay Expansion

In July 2016, we received approval from the FERC to expand Transco’s existing natural gas transmission system to provide incremental firm transportation capacity from Pennsylvania to the Rockaway Delivery Lateral transfer point and the Narrows meter station in Richmond County, New York. We plan to place the project into service during the fourth quarter of 2017, and it is expected to increase capacity by 115 Mdth/d.

Atlantic Sunrise

In March 2015, we filed an application with 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 expect to place a portion of the project facilities into service during the second half of 2017 and are targeting a full

Management’s Discussion and Analysis (Continued)

in-service during mid-2018, assuming timely receipt of all necessary regulatory approvals. The project is expected to increase capacity by 1,700 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 Station 210 in New Jersey and Station 165 in Virginia to a new lateral extending from our Brunswick Lateral in Virginia. We plan to place the project into service during the fourth quarter of 2017, assuming timely receipt of all necessary regulatory approvals, and it is expected to increase capacity by 250 Mdth/d.

Dalton

In August 2016, we obtained approval from the FERC to expand Transco’s existing natural gas transmission system together with greenfield facilities to provide incremental firm transportation capacity from Station 210 in New Jersey to markets in northwest Georgia. We plan to place the project into service in 2017 and it is expected to increase capacity by 448 Mdth/d.

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 phases, with the initial phase of the project expected to be in service during the second half of 2018 and the remaining phase in 2019, assuming timely receipt of all necessary regulatory approvals. The project is expected to increase capacity by 475 Mdth/d.

Critical Accounting Estimates

Goodwill

During the first quarter of 2016 we observed a significant decline in the market value of WPZ. As a result, we evaluated our goodwill associated with the West G&P reporting unit for impairment. Goodwill for the West G&P reporting unit was $47 million at both September 30, 2016 and December 31, 2015. We estimated the fair value of the West G&P reporting unit based on an income approach utilizing discount rates specific to the underlying business. These discount rates considered variables unique to each business, including equity yields of comparable midstream businesses, expectations for future growth, and customer performance considerations. The weighted-average discount rate utilized was 11.6 percent. Our analysis indicated that the fair value of the West G&P reporting unit exceeded its book value by approximately $262 million, or 10 percent, at the end of the first quarter. We estimated that an overall increase in the discount rate utilized of 250 basis points would have resulted in a potential impairment of goodwill for this reporting unit.

We did not perform an interim assessment at the end of the third quarter of 2016 as our weighted-average cost of capital and equity yields of comparable midstream businesses, which drive discount rates, decreased compared to first quarter.

Judgments and assumptions are inherent in our estimates of future cash flows, discount rates, and market measures utilized. 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.

Equity-Method Investments

In response to declining market conditions in the first quarter of 2016, we assessed whether the carrying amounts of certain of our equity-method investments exceeded their fair value. As a result, we recognized other-than-temporary impairment charges of $59 million and $50 million in the first quarter related to our equity-method investments in the DBJV and Laurel Mountain (LMM), respectively. Our carrying values in these equity-method investments had been written down to fair value at December 31, 2015. Our first-quarter analysis reflected higher discount rates for both DBJV and LMM, along with lower natural gas prices for LMM.

Management’s Discussion and Analysis (Continued)

We estimated the fair value of these investments using an income approach and discount rates ranging from 13.0 percent to 13.3 percent. These discount rates considered variables unique to each business area, including equity yields of comparable midstream businesses, expectations for future growth and customer performance considerations.

We estimated that an overall increase in the discount rates utilized of 50 basis points would have resulted in additional impairment charges on our at-risk equity-method investments of approximately $107 million.

Judgments and assumptions are inherent in our estimates of future cash flows, discount rates, and market measures utilized. The use of alternate judgments and assumptions could result in a different calculation of fair value, which could ultimately result in the recognition of a different impairment charge in the consolidated financial statements.

Subsequent to the first quarter the discount rates decreased significantly and no additional impairments have been recognized.

At the end of the third quarter of 2016, we became aware of changes involving certain of DBJV’s customer contracts, which impacted our estimates of DBJV’s future cash flows. As such, we evaluated this investment for impairment at September 30, 2016, and through the date of this filing and determined that no impairment was necessary. The carrying value of our investment in DBJV at September 30, 2016, is $964 million.

We estimated the fair value of this investment using an income approach and applied a discount rate of 10.9 percent. The computations considered our estimate of the future cash flows associated with the underlying business. We have recently entered into initial discussions with the system operator regarding the terms and economic assumptions of these contract changes. Depending upon the outcome of these discussions, we may not approve of the contract changes and it is possible that we could exercise our rights pursuant to the operating agreement and move to arbitration proceedings to address these contracts and other matters potentially impacting the future cash flows of DBJV. As a result, it is reasonably possible that the ultimate outcome could adversely affect our estimates of future cash flows and could ultimately result in a future impairment of our investment in DBJV.

At September 30, 2016, our Consolidated Balance Sheet includes approximately $7.1 billion of investments that are accounted for under the equity-method of accounting. We evaluate these investments for impairment when events or changes in circumstances indicate, in our management’s judgment, that the carrying value of such investments may have experienced an other-than-temporary decline in value. We continue to monitor our equity-method investments for any indications that the carrying value may have experienced an other-than-temporary decline in value. When evidence of a loss in value has occurred, we compare our estimate of the fair value of the investment to the carrying value of the investment to determine whether an impairment has occurred. We generally estimate the fair value of our investments using an income approach where significant judgments and assumptions include expected future cash flows and the appropriate discount rate. In some cases, we may utilize a form of market approach to estimate the fair value of our investments.

If the estimated fair value is less than the carrying value and we consider the decline in value to be other-than-temporary, the excess of the carrying value over the fair value is recognized in the consolidated financial statements as an impairment charge. Events or changes in circumstances that may be indicative of an other-than-temporary decline in value will vary by investment, but may include:


•	A significant or sustained decline in the market value of an investee;


•	Lower than expected cash distributions from investees;


•	Significant asset impairments or operating losses recognized by investees;


•	Significant delays in or lack of producer development or significant declines in producer volumes in markets served by investees;

Management’s Discussion and Analysis (Continued)


•	Significant delays in or failure to complete significant growth projects of investees.

Constitution Pipeline Capitalized Project Costs

As of September 30, 2016, Property, plant, and equipment, at cost 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. In December 2014, we received approval from the FERC to construct and operate this jointly owned pipeline. However, in April 2016, the New York State Department of Environmental Conservation (NYSDEC) denied a necessary water quality certification for the New York portion of the Constitution pipeline. We remain steadfastly committed to the project, and in May 2016, Constitution appealed the NYSDEC's denial of the certification and filed an action in federal court seeking a declaration that the State of New York's authority to exercise permitting jurisdiction over certain other environmental matters is preempted by federal law.

As a result of the denial by the NYSDEC, we evaluated the capitalized project costs for impairment as of March 31, 2016, and determined that no impairment was necessary. Our evaluation considered probability-weighted scenarios of undiscounted future net cash flows, including a scenario assuming successful resolution with the NYSDEC and 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.

Long-lived 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.

During the second quarter of 2016, certain Mid-Continent gas gathering systems were assessed for impairment due to a potential disposition of those systems in the future. Based on market observed information for these gas gathering systems, these assets were written down to their fair value. As a result, we recognized an impairment of $48 million in the Central segment.

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, 2016, compared to the three and nine months ended September 30, 2015. 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,
	2016			2015			$ Change*	% Change*		2016			2015			$ Change*	% Change*
	(Millions)									(Millions)
Revenues:
Service revenues	$	1,252		$	1,232		+20	+2	%	$	3,688		$	3,655		+33	+1	%
Product sales	655			560			+95	+17	%	1,613			1,678			-65	-4	%
Total revenues	1,907			1,792						5,301			5,333
Costs and expenses:
Product costs	463			426			-37	-9	%	1,183			1,383			+200	+14	%
Operating and maintenance expenses	385			394			+9	+2	%	1,153			1,205			+52	+4	%
Depreciation and amortization expenses	426			423			-3	-1	%	1,293			1,261			-32	-3	%
Selling, general, and administrative expenses	147			156			+9	+6	%	467			513			+46	+9	%
Net insurance recoveries – Geismar Incident	—			—			—	NM		—			(126		)	-126	-100	%
Impairment of long-lived assets	1			2			+1	+50	%	403			29			-374	NM
Other (income) expense – net	59			5			-54	NM		107			33			-74	NM
Total costs and expenses	1,481			1,406						4,606			4,298
Operating income (loss)	426			386						695			1,035
Equity earnings (losses)	104			92			+12	+13	%	302			236			+66	+28	%
Impairment of equity-method investments	—			(461		)	+461	+100	%	(112		)	(461		)	+349	+76	%
Other investing income (loss) – net	28			—			+28	NM		29			1			+28	NM
Interest expense	(229		)	(205		)	-24	-12	%	(689		)	(600		)	-89	-15	%
Other income (expense) – net	16			22			-6	-27	%	43			70			-27	-39	%
Income (loss) before income taxes	345			(166		)				268			281
Provision (benefit) for income taxes	(6		)	1			+7	NM		(85		)	4			+89	NM
Net income (loss)	351			(167		)				353			277
Less: Net income attributable to noncontrolling interests	25			27			+2	+7	%	67			82			+15	+18	%
Net income (loss) attributable to controlling interests	$	326		$	(194	)				$	286		$	195


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

Management’s Discussion and Analysis (Continued)

Three months ended September 30, 2016 vs. three months ended September 30, 2015

Service revenues improved due to growth associated with expansion projects placed in service in 2015 and 2016, including projects in the eastern Gulf Coast region, Transco’s natural gas transportation system, our Redwater facility in Canada, and in the Appalachian basin. These increases were partially offset by lower gathering rates in the Eagle Ford Shale.

Product sales increased due to higher marketing revenues, higher olefins sales, and increased revenues from our equity NGLs primarily due to higher volumes. The increase in marketing revenues are driven by higher NGL and natural gas prices and crude oil volumes, partially offset by lower NGL and natural gas volumes and crude oil prices. The increase in olefin sales are primarily associated with higher ethylene prices at our Geismar plant.

The increase in Product costs includes higher marketing purchases primarily due to the same factors that increased marketing revenues. In addition, natural gas purchases associated with the production of equity NGLs increased, partially offset by lower olefin feedstock purchases. Natural gas purchases increased reflecting higher volumes. The decline in olefin feedstock purchases is primarily due to lower propylene production volumes.

Operating and maintenance expenses reflect decreases in primarily outside service and labor-related costs resulting from our cost containment efforts and first-quarter 2016 workforce reductions, substantially offset by higher pipeline testing and general maintenance at Transco.

Other (income) expense – net within Operating income (loss) includes a loss on the sale of our Canadian operations that were sold in September 2016 (see Note 2 – Divestiture of Notes to Consolidated Financial Statements), as well as project development costs at Constitution as we discontinued capitalization of these costs in April 2016. (See Note 3 – Variable Interest Entities of Notes to Consolidated Financial Statements.)

Operating income (loss) changed favorably primarily due to higher olefin margins associated with improved ethylene prices at our Geismar plant, higher service revenues driven by higher volumes, and lower costs and expenses primarily related to cost containment efforts and workforce reductions, partially offset by the loss on sale of our Canadian operations and project development costs at Constitution.

Equity earnings (losses) changed favorably primarily due to a $7 million increase at UEOM. Additionally, lower impairments recognized within our Appalachia Midstream Investments were substantially offset by lower operating results.

Impairment of equity-method investments reflects 2015 impairment charges associated with certain equity-method investments. (See Note 10 – Fair Value Measurements and Guarantees of Notes to Consolidated Financial Statements.)

Other investing income (loss) - net reflects 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 increased due to higher Interest incurred of $20 million primarily attributable to new debt issuances in 2016 and 2015. (See Note 8 – Debt and Banking Arrangements of Notes to Consolidated Financial Statements.)

Nine months ended September 30, 2016 vs. nine months ended September 30, 2015

Service revenues increased primarily due to expansion projects placed in service in 2015 and 2016, including Transco’s natural gas transportation system, new transportation and fractionation revenue associated with Williams’ Horizon liquids extraction plant in Canada, as well as higher rates and volumes in the Haynesville area primarily attributable to a new contract executed in 2015. These increases were partially offset by a decrease related to lower volumes attributable to suspending operations in order to facilitate the tie-in of the Gunflint expansion at Gulfstar One, a decrease in storage revenues at Transco, and lower gathering rates in the Eagle Ford Shale.

Product sales decreased due to reduced marketing revenues primarily associated with lower NGL volumes and lower crude oil, non-ethane, and natural gas prices, partially offset by higher crude oil and natural gas volumes. Olefins

Management’s Discussion and Analysis (Continued)

sales increased primarily due to the increased volumes at our Geismar plant as a result of the plant operating at higher production levels in 2016, partially offset by lower olefin sales from other olefin operations associated with lower volumes and per-unit sales prices.

The decrease in Product costs includes lower marketing purchases primarily associated with a decline in per-unit costs across most products and lower volumes in addition to lower olefin feedstock purchases. The decline in olefin feedstock purchases is primarily associated with lower per-unit feedstock costs and volumes at our other olefin operations, partially offset by an increase in olefin feedstock purchases at our Geismar plant reflecting increased volumes resulting from higher production levels in 2016.

Operating and maintenance expenses decreased primarily due to lower labor-related and outside service costs resulting from our first-quarter 2016 workforce reductions and cost containment efforts, as well as the absence of ACMP transition-related costs recognized in 2015, partially offset by $14 million of severance and related costs recognized in 2016 and higher pipeline testing and general maintenance costs at Transco.

Depreciation and amortization expenses increased primarily due to depreciation on new assets placed in-service, including Transco pipeline projects.

Selling, general, and administrative expenses decreased primarily due to the absence of ACMP merger and transition- related costs recognized in 2015 and lower labor-related costs resulting from our first-quarter 2016 workforce reductions and cost containment efforts, partially offset by $11 million of severance and related costs recognized in 2016.

Net insurance recoveries – Geismar Incident changed unfavorably reflecting the absence of $126 million of insurance proceeds received in the second quarter of 2015.

Impairment of long-lived assets reflects 2016 impairments of our Canadian operations and certain Mid-Continent assets. (See Note 10 – Fair Value Measurements and Guarantees of Notes to Consolidated Financial Statements.) Impairments recognized in 2015 relate primarily to surplus equipment write-offs.

Other (income) expense – net within Operating income (loss) includes a loss on the sale of our Canadian operations that were sold in September 2016, project development costs at Constitution as we discontinued capitalization of these costs in April 2016, and an unfavorable change in foreign currency exchange that primarily relates to losses incurred on foreign currency transactions and the remeasurement of the U.S. dollar-denominated current assets and liabilities within our Canadian operations.

Operating income (loss) changed unfavorably primarily due impairments in 2016, the absence of insurance proceeds received in the second quarter of 2015, and higher depreciation expenses related to new projects placed in service. These decreases were partially offset by higher olefin margins related to the Geismar plant operating at higher production levels in 2016, lower costs related to the merger and integration of ACMP, lower costs and expenses associated with cost containment efforts, and higher service revenues reflecting new projects placed in service in 2015 and 2016.

Equity earnings (losses) changed favorably primarily due to a $23 million increase at Discovery driven by the completion of the Keathley Canyon Connector in the first quarter of 2015. Additionally, UEOM and OPPL increased $16 million and $14 million, respectively.

Impairment of equity-method investments reflects first-quarter 2016 impairment charges associated with our DBJV and Laurel Mountain equity-method investments, while the 2015 impairment charge relates to our equity-method investment in DBJV. (See Note 5 – Investing Activities of Notes to Consolidated Financial Statements.)

Interest expense increased due to higher Interest incurred of $75 million primarily attributable to new debt issuances in 2016 and 2015, as well as lower Interest capitalized of $14 million primarily related to construction projects that

Management’s Discussion and Analysis (Continued)

have been placed into service, partially offset by lower interest due to 2015 and 2016 debt retirements. (See Note 8 – Debt and Banking Arrangements of Notes to Consolidated Financial Statements.)

Other income (expense) – net below Operating income (loss) changed unfavorably primarily due to the absence of a $14 million gain on early debt retirement in 2015 and a decrease in allowance for equity funds used during construction (AFUDC) due to decreased spending on Constitution.

Provision (benefit) for income taxes changed favorably due to lower foreign pretax income, including a foreign tax benefit associated with our 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.

Net income attributable to noncontrolling interests changed favorably primarily due to project development costs expensed for Constitution and the reduction of Gulfstar One earnings, partially offset by higher earnings from Cardinal.

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.

Central



	Three Months Ended September 30,						Nine Months Ended September 30,
	2016			2015			2016			2015
	(Millions)
Service revenues	$	255		$	270		$	768		$	787

Segment costs and expenses	(91		)	(116		)	(287		)	(355		)
Impairment of long-lived assets	(1		)	—			(48		)	(3		)
Proportional Modified EBITDA of equity-method investments	13			9			34			27
Central Modified EBITDA	$	176		$	163		$	467		$	456

Three months ended September 30, 2016 vs. three months ended September 30, 2015

Modified EBITDA increased primarily due to a decrease in Segment costs and expenses related to the decrease in labor-related and outside service costs resulting from our first quarter workforce reductions and ongoing cost containment efforts, partially offset by a decrease in Service revenues.

Service revenues decreased primarily due to lower volumes in the Barnett area, lower rates in the Eagle Ford area as a result of the redetermination of a cost of service contract, and lower volumes partially offset by higher rates in the Anadarko area. These decreases were partially offset by higher rates and volumes in the Haynesville area primarily attributable to a new contract executed in 2015.

Segment costs and expenses decreased primarily due to a decrease in labor-related and outside service costs resulting from our first quarter workforce reductions and ongoing cost containment efforts, as well as the absence of ACMP Merger and transition expenses in 2016.

Nine months ended September 30, 2016 vs. nine months ended September 30, 2015

Modified EBITDA increased primarily due to a decrease in Segment costs and expenses related to a decrease in ACMP Merger and transition expenses in 2016 as well as lower labor-related and outside service costs resulting from

Management’s Discussion and Analysis (Continued)

our first quarter workforce reductions and ongoing cost containment efforts, partially offset by a $48 million impairment of certain Mid-Continent gathering assets in 2016 and lower Service revenues.

Service revenues decreased primarily due to lower volumes in the Barnett area, lower volumes partially offset by higher rates in the Anadarko area, and lower rates in the Eagle Ford area as a result of the redetermination of a cost of service contract. These decreases were partially offset by higher rates and volumes in the Haynesville area primarily attributable to a new contract executed in 2015.

Segment costs and expenses decreased primarily due to a $42 million decrease in ACMP Merger and transition expenses and lower labor-related and outside service costs resulting from our first quarter workforce reductions and ongoing cost containment efforts.

Impairment of long-lived assets increased primarily due to a $48 million impairment of certain Mid-Continent gathering assets in 2016.

Northeast G&P



	Three Months Ended September 30,						Nine Months Ended September 30,
	2016			2015			2016			2015
	(Millions)
Service revenues	$	207		$	194		$	626		$	606
Product sales	43			27			100			100
Segment revenues	250			221			726			706

Product costs	(42		)	(25		)	(97		)	(95		)
Other segment costs and expenses	(89		)	(86		)	(265		)	(279		)
Impairment of long-lived assets	—			(2		)	(8		)	(26		)
Proportional Modified EBITDA of equity-method investments	89			81			282			251
Northeast G&P Modified EBITDA	$	208		$	189		$	638		$	557

Three months ended September 30, 2016 vs. three months ended September 30, 2015

Modified EBITDA increased primarily due to higher gathering revenues driven by higher volumes in the Susquehanna Supply Hub and the Utica Shale.

Service revenues increased primarily due to $12 million higher gathering revenues, reflecting higher volumes in the Susquehanna Supply Hub from fewer producer shut-ins associated with improved regional natural gas prices and higher volumes in the Utica Shale from new well connections and additional compression. These increases were partially offset by a $6 million decrease in our Ohio Valley Midstream operations associated with lower volumes and rates from the impact of producer shut-ins and temporarily reduced gathering and processing rates with certain producers, partially offset by new well connections.

Product sales increased primarily due to $17 million higher marketing sales due primarily to higher non-ethane prices. The changes in marketing revenues are offset by similar changes in marketing purchases, reflected above as Product costs.

Product costs increased primarily due to $18 million higher marketing costs due primarily to higher non-ethane prices. The changes in marketing purchases are offset by similar changes in marketing revenues, reflected above as Product sales.

Management’s Discussion and Analysis (Continued)

Proportional Modified EBITDA of equity-method investments changed favorably due to improved results at UEOM associated with higher processing volumes. Appalachia Midstream Investments reflect lower operating results, offset by lower impairments in 2016.

Nine months ended September 30, 2016 vs. nine months ended September 30, 2015

Modified EBITDA increased primarily due to improvements in Proportional Modified EBITDA of equity-method investments driven by higher volumes and the absence of certain impairments from 2015, higher service revenues, lower impairment charges, and lower operating and maintenance expenses.

Service revenues include a $17 million increase in Utica Shale gathering revenues primarily due to growth in volumes associated with new well connects, and a $16 million increase in Susquehanna Supply Hub gathering revenues resulting from fewer producer shut-ins associated with improved regional natural gas prices. In addition, fee-based revenues increased due to higher reimbursements for management services from certain equity-method investees. The increase in service revenues was partially offset by a $32 million decrease from our Ohio Valley Midstream operations associated with lower volumes and rates driven by producer shut-ins and temporarily reduced gathering and processing rates with certain producers.

Other segment costs and expenses decreased primarily due to a $25 million decrease in operating and maintenance expenses primarily resulting from lower costs related to supplies, outside services, and repairs, partially offset by slightly higher general and administrative expenses.

Impairment of long-lived assets changed favorably primarily due to lower impairment charges associated with certain surplus equipment within our Ohio Valley Midstream business. (See Note 10 – Fair Value Measurements and Guarantees of Notes to Consolidated Financial Statements.)

Proportional Modified EBITDA of equity-method investments changed favorably due to a $20 million increase from UEOM associated with higher processing volumes and an increase in our ownership percentage, and a $14 million increase from Caiman II resulting from higher volumes due to assets placed into service in 2015. These increases were partially offset by a $12 million decrease from Appalachia Midstream Investments primarily due to lower fee revenues driven by lower rates, partially offset by lower impairments in 2016 and higher volumes.

Atlantic-Gulf



	Three Months Ended September 30,						Nine Months Ended September 30,
	2016			2015			2016			2015
	(Millions)
Service revenues	$	509		$	477		$	1,423		$	1,401
Product sales	136			118			310			364
Segment revenues	645			595			1,733			1,765

Product costs	(124		)	(111		)	(285		)	(343		)
Other segment costs and expenses	(180		)	(148		)	(507		)	(467		)
Impairment of long-lived assets	—			—			(1		)	—
Proportional Modified EBITDA of equity-method investments	75			78			209			183
Atlantic-Gulf Modified EBITDA	$	416		$	414		$	1,149		$	1,138

NGL margin	$	10		$	8		$	22		$	20

Three months ended September 30, 2016 vs. three months ended September 30, 2015

Modified EBITDA increased slightly primarily due to higher service revenues, substantially offset by higher segment costs and expenses.

Service revenues increased primarily due to a $26 million increase in eastern Gulf Coast region fee revenues primarily due to higher volumes, including a temporary increase related to disrupted operations of a competitor, the impact of new volumes at Gulfstar One related to the Gunflint expansion being placed in service in the third quarter of 2016, and higher volumes at Devils Tower related to Kodiak field production which began earlier this year, partially

Management’s Discussion and Analysis (Continued)

offset by lower volumes from the Tubular Bells development due primarily to well outages. Additionally, Transco’s natural gas transportation fee revenues increased $12 million primarily associated with expansion projects placed in service in 2015 and 2016.

Product sales increased primarily due to:

•

A $14 million increase in crude oil and NGL marketing revenues. Crude oil marketing sales increased $11 million primarily due to higher volumes, partially offset by 23 percent lower crude oil per barrel sales prices. NGL marketing sales increased $3 million primarily due to a 21 percent increase in non-ethane per-unit sales prices. These changes in marketing revenues are offset by similar changes in marketing purchases;


•	A $14 million increase in revenues from our equity NGLs primarily due to higher volumes driven by a temporary increase in volumes due to disrupted operations of a competitor;


•	A $13 million decrease 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 $15 million increase in marketing purchases (offset in Product sales);


•	A $12 million increase in natural gas purchases associated with the production of equity NGLs primarily due to higher volumes;


•	A $13 million decrease in system management gas costs (offset in Product sales).

Other segment costs and expenses increased due to higher operating expenses primarily related to higher contract services for pipeline testing and general maintenance at Transco. In addition, project development costs at Constitution are higher as we discontinued capitalization of these costs in April 2016, and AFUDC also changed unfavorably associated with a decrease in spending on Constitution.

Nine months ended September 30, 2016 vs. nine months ended September 30, 2015

Modified EBITDA increased primarily due to higher earnings at Discovery due to the completion of the Keathley Canyon Connector in the first quarter of 2015 and higher service revenues, partially offset by higher segment costs and expenses.

Service revenues increased primarily due to:


•	A $66 million increase in Transco’s natural gas transportation fee revenues primarily associated with expansion projects placed in service in 2015 and 2016, partially offset by lower volume-based transportation services revenues;


•	A $15 million decrease in Transco’s storage revenue related to potential refunds associated with a ruling received in certain rate case litigation in 2016;

•

A $15 million decrease in eastern Gulf Coast region fee revenues primarily related to lower volumes, including the impact of 2016 producers’ operational issues and suspending operations in order to facilitate the tie-in of the Gunflint expansion at Gulfstar One. This decrease was partially offset by new volumes at Gulfstar One related to the Gunflint expansion placed in service in the third quarter of 2016, a temporary increase in volumes related to disrupted operations of a competitor, and higher volumes at Devils Tower related to Kodiak field production which began earlier this year;


•	A $13 million decrease in western Gulf Coast region fee revenues primarily related to lower volumes associated with producer maintenance in 2016 and natural declines in certain production areas.

Management’s Discussion and Analysis (Continued)

Product sales decreased primarily due to:


•	A $34 million decrease in system management gas sales from Transco. System management gas sales are offset in Product costs and, therefore, have no impact on Modified EBITDA;

•

A $33 million decrease in crude oil and NGL marketing revenues. Crude oil marketing sales decreased $17 million primarily due to 27 percent lower crude oil per barrel sales prices, partially offset by higher volumes. NGL marketing sales also decreased $16 million primarily due to a lower non-ethane volumes and per-unit sales prices. These changes in marketing revenues are offset by similar changes in marketing purchases;


•	A $15 million increase in revenues from our equity NGLs primarily due to higher volumes driven by a temporary increase in volumes due to disrupted operations of a competitor, partially offset by lower prices.

Product costs decreased primarily due to:


•	A $34 million decrease in system management gas costs (offset in Product sales);


•	A $36 million decrease in marketing purchases (substantially offset in Product sales);


•	A $13 million increase in natural gas purchases associated with the production of equity NGLs primarily due to higher volumes.

The increase in Other segment costs and expenses includes $24 million higher operating expenses primarily due to higher contract services for pipeline testing and general maintenance, as well as higher operating taxes, at Transco, and $19 million higher Constitution project development costs as we discontinued capitalization of these costs beginning in April 2016. AFUDC also changed unfavorably by $12 million associated with a decrease in spending on Constitution, and $8 million was incurred in first-quarter 2016 for severance and related costs associated with workforce reductions. These increases are partially offset by $19 million lower general and administrative expenses driven by first-quarter 2016 workforce reductions and ongoing cost containment efforts, as well as a favorable change in the deferral of asset retirement obligation-related depreciation to a regulatory asset.

The increase in Proportional Modified EBITDA of equity-method investments includes a $25 million increase from Discovery primarily due to higher fee revenues attributable to the completion of the Keathley Canyon Connector in the first quarter of 2015.

West



	Three Months Ended September 30,						Nine Months Ended September 30,
	2016			2015			2016			2015
	(Millions)
Service revenues	$	256		$	263		$	774		$	783
Product sales	70			62			200			194
Segment revenues	326			325			974			977

Product costs	(42		)	(38		)	(116		)	(111		)
Other segment costs and expenses	(118		)	(118		)	(376		)	(386		)
Impairment of long-lived assets	—			—			(3		)	—
West Modified EBITDA	$	166		$	169		$	479		$	480

NGL margin	$	27		$	23		$	80		$	77

Three months ended September 30, 2016 vs. three months ended September 30, 2015

Modified EBITDA decreased slightly primarily due to reduced fee revenues.

Management’s Discussion and Analysis (Continued)

Service revenues decreased primarily due to $7 million in reduced gathering and processing fees in the Four Corners region associated with system downtime and lower gathering volumes in the Piceance region due to reduced producer activity.

Product sales increased primarily due to a $9 million increase in revenues associated with our equity NGLs due to increased sales from inventory and higher non-ethane prices.

Product costs increased primarily due to a $5 million increase in natural gas volumes attributable to sales from inventory.

Nine months ended September 30, 2016 vs. nine months ended September 30, 2015

Modified EBITDA decreased slightly primarily due to lower fee revenues associated with lower volumes and rates, offset by lower operational costs.

Service revenues decreased primarily due to a $19 million reduction associated with lower gathering volumes in the Piceance region attributable to reduced producer activity and lower gathering and processing fees in the Four Corners region associated with system downtime and a natural decline in producer volumes. These reductions are partially offset by increased gathering and processing revenues of $14 million associated with higher gathering and processing rates in our Niobrara operations.

Product sales increased primarily due to a $7 million increase in marketing revenues due to higher non-ethane volumes (offset in Product costs) and an increase in revenues from our equity NGLs associated with higher NGL volumes, partially offset by lower NGL prices and a reduction in other sales.

Product costs increased primarily due to a $7 million increase in NGL marketing purchases due to higher non-ethane volumes (offset in Product sales).

Other segment costs and expenses decreased due to lower labor-related costs driven by first-quarter 2016 workforce reductions and lower major maintenance and operating charges.

NGL & Petchem Services



	Three Months Ended September 30,						Nine Months Ended September 30,
	2016			2015			2016			2015
	(Millions)
Service revenues	$	45		$	37		$	137		$	103
Product sales	588			492			1,467			1,448
Segment revenues	633			529			1,604			1,551

Product costs	(451		)	(395		)	(1,173		)	(1,267		)
Other segment costs and expenses	(95		)	(61		)	(241		)	(193		)
Net insurance recoveries – Geismar Incident	—			—			—			126
Impairment of long-lived assets	—			—			(343		)	—
Proportional Modified EBITDA of equity-method investments	17			12			49			32
NGL & Petchem Services Modified EBITDA	$	104		$	85		$	(104	)	$	249

Olefins margin	$	118		$	85		$	263		$	155
NGL margin	6			5			12			16

Three months ended September 30, 2016 vs. three months ended September 30, 2015

Modified EBITDA increased primarily due to higher olefin margins associated with favorable prices at our Geismar facility and higher service revenues due to the expansion of our Redwater facilities in Canada, partially offset by a $32 million loss on sale of our Canadian operations. (See Note 2 – Divestiture of Notes to Consolidated Financial Statements.)

Management’s Discussion and Analysis (Continued)

Service revenues improved primarily due to the expansion of our Redwater facilities in March 2016 to provide transportation and fractionation services associated with the Williams Horizon liquids extraction plant. These operations were sold in late September 2016.

Product sales increased primarily due to:


•	A $71 million increase in marketing revenues primarily due to higher natural gas and non-ethane volumes, partially offset by lower natural gas prices (substantially offset by higher Product costs);


•	A $28 million increase in olefin sales primarily due to a $27 million increase from our Geismar plant reflecting $24 million in primarily higher ethylene prices.

Product costs increased primarily due to:


•	A $64 million increase in marketing product costs primarily due to higher natural gas and non-ethane volumes, partially offset by lower per-unit natural gas costs (more than offset by higher Product sales);


•	A $5 million decrease in olefin feedstock purchases primarily due to lower propylene production volumes.

The increase in Other segment costs and expenses is primarily due to a $32 million loss on the sale of our Canadian operations in September 2016.

Nine months ended September 30, 2016 vs. nine months ended September 30, 2015

Modified EBITDA decreased primarily due to the impairment of our Canadian operations, lower insurance proceeds related to the Geismar Incident, and a $32 million loss on the sale of the Canadian operations, partially offset by higher olefin margins driven by higher production levels at the Geismar facility in 2016 than in 2015 and higher service revenues associated with the expansion of our Redwater facilities in Canada.

Product sales increased primarily due to:

•

An $82 million increase in olefin sales comprised of a $152 million increase from our Geismar plant that returned to service in late March 2015, partially offset by a $70 million decrease from our other olefin operations. The increase at Geismar includes $189 million associated with increased volumes as a result of the plant operating at higher production levels in 2016 than when production resumed in March 2015, partially offset by $37 million in lower per-unit sales prices. The decrease in other olefin sales are associated with both lower volumes and lower per-unit sales prices;


•	A $30 million decrease in marketing revenues primarily due to lower prices across all products, particularly non-ethane, partially offset by higher natural gas and non-ethane volumes (more than offset in Product costs);

•

A $29 million decrease in Canadian NGL production revenues comprised of a $19 million decrease associated with lower volumes and a $10 million decrease associated with lower prices across all products. The lower volumes are associated with the shut-down and evacuation of our liquids extraction plant because of wild fires in the Fort McMurray area during the second quarter of 2016, as well as a longer period of planned maintenance in 2016.

Management’s Discussion and Analysis (Continued)

Product costs decreased primarily due to:


•	A $37 million decrease in marketing product costs primarily due to lower per-unit costs associated with all products, partially offset by higher natural gas and non-ethane volumes (substantially offset by lower Product sales);

•

A $26 million decrease in olefin feedstock purchases is primarily comprised of $81 million in lower purchases at our other olefins operations, partially offset by $55 million of higher purchases due primarily to increased volumes at our Geismar plant resulting from higher productions levels. The lower costs at our other olefin operations are comprised of $57 million in lower per-unit feedstock costs and $24 million in primarily lower propylene volumes;


•	A $25 million decrease in NGL product costs due to a $14 million decrease in primarily propane and ethane volumes and an $11 million decrease reflecting the decline in the price of natural gas associated with the production of equity NGLs.

The increase in Other segment costs and expenses is primarily due to a $32 million loss on the sale of our Canadian operations in September 2016, as well as a $19 million unfavorable change in foreign currency exchange that primarily relates to losses on foreign currency transactions and the remeasurement of U.S. dollar denominated current assets and liabilities within our Canadian operations.

Net insurance recoveries - Geismar Incident decreased $126 million as insurance proceeds were received in 2015, while no proceeds were received in 2016.

Impairment of long-lived assets reflects the second-quarter 2016 impairment of our Canadian operations (see Note 10 – Fair Value Measurements and Guarantees).

The increase in Proportional modified EBITDA of equity-method investments reflects a $14 million improvement at OPPL due primarily to higher transportation volumes, as well as lower expenses in 2016 due to cost reduction efforts.

Management’s Discussion and Analysis (Continued)

Management’s Discussion and Analysis of Financial Condition and Liquidity

Outlook

We continue to transition to an overall business mix that is increasingly fee-based. Although our cash flows are impacted by fluctuations in energy commodity prices, that impact is somewhat mitigated by certain of our cash flow streams that are not directly impacted by short-term commodity price movements, including:


•	Firm demand and capacity reservation transportation revenues under long-term contracts;


•	Fee-based revenues from certain gathering and processing services.

However, we are indirectly exposed to longer duration depressed energy commodity prices and the related impact on drilling activities and volumes available for gathering and processing services.

We believe we have, or have access to, the financial resources and liquidity necessary to meet our requirements for working capital, capital and investment expenditures, unitholder distributions, and debt service payments while maintaining a sufficient level of liquidity. In particular, as previously discussed in Company Outlook, our expected growth capital and investment expenditures total approximately $1.9 billion in 2016. We retain the flexibility to adjust planned levels of capital and investment expenditures in response to changes in economic conditions or business opportunities. We expect additional proceeds from amounts held in escrow from the sale of our Canadian operations by early 2017. (See Note 2 – Divestiture of Notes to Consolidated Financial Statements.)

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 2016. Our internal and external sources of consolidated liquidity include:


•	Cash and cash equivalents on hand;


•	Cash generated from operations, including cash distributions from our equity-method investees;


•	Cash proceeds from issuances of debt and/or equity securities, including issuances under our equity distribution agreement;


•	Distribution reinvestment program (DRIP);


•	Use of our credit facilities and/or commercial paper program;


•	Transco’s January 2016 debt issuance described further below;


•	Proceeds from sale of our Canadian operations. (See Note 2 – Divestiture of Notes to Consolidated Financial Statements.)

We anticipate our more significant uses of cash to be:


•	Working capital requirements;


•	Maintenance and expansion capital and investment expenditures;


•	Interest on our long-term debt;


•	Repayment of current debt maturities;


•	Quarterly distributions to our unitholders and general partner, including IDRs.

Management’s Discussion and Analysis (Continued)

We implemented a DRIP in the third quarter of 2016. Williams has announced that it plans to reinvest approximately $1.7 billion in us through 2017. Williams reinvested $250 million in the third quarter of 2016 via a private purchase of common units, and Williams plans to reinvest $250 million in the fourth quarter of 2016 via the DRIP. The remaining $1.2 billion is planned to be reinvested in 2017 via the DRIP.

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

As of September 30, 2016, we had a working capital deficit (current liabilities, inclusive of $785 million in Long-term debt due within one year, in excess of current assets) of $838 million. Our available liquidity is as follows:



Available Liquidity	September 30, 2016
	(Millions)
Cash and cash equivalents	$	68
Capacity available under our $3.5 billion credit facility, less amounts outstanding under our $3 billion commercial paper program (1)	2,268
	$	2,336

(1)

In managing our available liquidity, we do not expect a maximum outstanding amount in excess of the capacity of our credit facility inclusive of any outstanding amounts under our commercial paper program. Through September 30, 2016, the highest amount outstanding under our commercial paper program and credit facility during 2016 was $2.326 billion. At September 30, 2016, we were in compliance with the financial covenants associated with this credit facility. See Note 8 – Debt and Banking Arrangements of Notes to Consolidated Financial Statements for additional information on our commercial paper program. Borrowing capacity available under our $3.5 billion credit facility as of October 28, 2016, was $2.427 billion.

On September 24, 2015, we received a special distribution of $396 million from Gulfstream reflecting our proportional share of the proceeds from new debt issued by Gulfstream. The new debt was issued to refinance Gulfstream’s debt maturities. Subsequently, we contributed $248 million and $148 million to Gulfstream for our proportional share of amounts necessary to fund debt maturities of $500 million due on November 1, 2015, and $300 million due on June 1, 2016, respectively.

Incentive Distribution Rights

Williams’ ownership interest in us includes the right to incentive distributions determined in accordance with our partnership agreement. In connection with the sale of our Canadian operations in the third quarter of 2016, Williams agreed to waive $150 million of incentive distributions otherwise payable by us to Williams in the fourth quarter of 2016. (See Note 2 – Divestiture of Notes to Consolidated Financial Statements.)

Williams has also agreed to temporarily waive incentive distributions of approximately $2 million per quarter in connection with our acquisition of an approximate 13 percent additional interest in UEOM on June 10, 2015. The waiver will continue through the quarter ending September 30, 2017.

Williams was required to pay us a $428 million termination fee associated with the Termination Agreement (as described in Note 1 – General, Description of Business, and Basis of Presentation of Notes to Consolidated Financial Statements), which settled through a reduction of quarterly incentive distributions payable to Williams (such reduction not to exceed $209 million per quarter). The 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.

Debt Issuances and Retirements

Northwest Pipeline retired $175 million of 7 percent senior unsecured notes that matured on June 15, 2016.

Transco retired $200 million of 6.4 percent senior unsecured notes that matured on April 15, 2016.

Management’s Discussion and Analysis (Continued)

On January 22, 2016, Transco issued $1 billion of 7.85 percent senior unsecured notes due 2026 to investors in a private debt placement. Transco used the net proceeds from the offering to repay debt and to fund capital expenditures.

Registrations

In September 2016, we filed a registration statement for our new DRIP. (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, and we also 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. From February 2015 through September 30, 2016, we have received net proceeds of approximately $59 million from equity issued under this registration.

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	Negative	BBB-	BBB-
Moody’s Investors Service	Negative	Baa3	N/A
Fitch Ratings	Stable	BBB-	N/A

As of September 30, 2016, we estimate that a downgrade to a rating below investment grade could require us to post up to $447 million in additional collateral with third parties.

Cash Distributions to Unitholders

The Board of Directors of our general partner declared a cash distribution of $0.85 per common unit on October 25, 2016, to be paid on November 14, 2016, to unitholders of record at the close of business on November 4, 2016.

Sources (Uses) of Cash

The following table summarizes the increase (decrease) in cash and cash equivalents for each of the periods presented:



	Nine Months Ended September 30,
	2016			2015
	(Millions)
Net cash provided (used) by:
Operating activities	$	2,341		$	2,098
Financing activities	(1,849		)	290
Investing activities	(520		)	(2,449		)
Increase (decrease) in cash and cash equivalents	$	(28	)	$	(61	)

Management’s Discussion and Analysis (Continued)

Operating activities

The factors that determine operating activities are largely the same as those that affect Net income (loss), with the exception of noncash items such as Depreciation and amortization, Provision (benefit) for deferred income taxes, Impairment of equity-method investments, and Impairment of and net (gain) loss on sale of assets and businesses. Our Net cash provided (used) by operating activities in 2016 increased from 2015 primarily due to the impact of higher operating income and net favorable changes in operating working capital.

Financing activities

Significant transactions include:


•	$499 million in 2016 of net payments of commercial paper;


•	$727 million in 2015 of net proceeds from commercial paper;


•	$998 million in 2016 and $2.992 billion in 2015 net received from our debt offerings;


•	$375 million in 2016 and $1.533 billion in 2015 paid on our debt retirements;


•	$2.665 billion in 2016 and $2.457 billion in 2015 received from our credit facility borrowings;


•	$2.745 billion in 2016 and $2.597 billion in 2015 paid on our credit facility borrowings;


•	$250 million in 2016 of proceeds from sales of common units;


•	$1.956 billion, including $1.321 billion to Williams, in 2016 and $2.173 billion, including $1.543 billion to Williams, in 2015 related to quarterly cash distributions paid to limited partner unitholders and the general partner;


•	$148 million in 2016 paid in contribution to Gulfstream for repayment of debt;


•	$396 million in 2015 received in special distribution from Gulfstream.

Investing activities

Significant transactions include:


•	Capital expenditures of $1.472 billion in 2016 and $2.142 billion in 2015;


•	$510 million in 2016 received in net proceeds from sale of our Canadian operations;


•	$112 million in 2015 paid to purchase a gathering system comprised of approximately 140 miles of pipeline and a sour gas compression facility in the Eagle Ford shale;


•	Purchases of and contributions to our equity-method investments of $132 million in 2016 and $528 million in 2015;


•	Distributions from unconsolidated affiliates in excess of cumulative earnings of $341 million in 2016 and $251 million in 2015.

Management’s Discussion and Analysis (Continued)

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

We have various other guarantees and commitments which are disclosed in Note 3 – Variable Interest Entities, Note 8 – Debt and Banking Arrangements, Note 10 – Fair Value Measurements and Guarantees, and Note 11 – Contingent Liabilities of Notes to Consolidated Financial Statements. We do not believe these guarantees and commitments or the possible fulfillment of them will prevent us from meeting our liquidity needs.

Item 3

Quantitative and Qualitative Disclosures About Market Risk

Interest Rate Risk

Our current interest rate risk exposure is related primarily to our debt portfolio and has not materially changed during the first nine months of 2016.

Foreign Currency Risk

In September 2016, we disposed of our Canadian operations, which comprised all of our foreign operations. We continue to be exposed to fluctuations in foreign currency exchange rates due to local currency denominated proceeds in escrow and contingent consideration associated with that disposition. (See Note 2 – Divestiture of Notes to Consolidated Financial Statements.)

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 Williams Partners L.P. 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 2016 that 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.

In November 2013, we became aware of deficiencies with the air permit for the Fort Beeler gas processing facility located in West Virginia. We notified the EPA and the West Virginia Department of Environmental Protection and worked to bring the Fort Beeler facility into full compliance. On April 26, 2016, the EPA executed a consent order resolving various air permitting and emissions issues requiring payment of $140,000 in civil penalties which was paid on May 13, 2016. We do not anticipate penalties being imposed by the West Virginia Department of Environmental Protection.

On January 21, 2016, we received a Compliance Order from the Pennsylvania Department of Environmental Protection requiring the correction of several alleged deficiencies arising out of the construction of the Springville Gathering Line, the Pennsylvania Mainline Gathering Line, and the 2008 Core Zone Gathering Line. The Order also identifies civil penalties in the amount of approximately $712,000. We are working with the Pennsylvania Department of Environmental Protection to address certain issues and are in the process of negotiating the Order and the associated penalty.

Other

The additional information called for by this item is provided in Note 11 – Contingent Liabilities of the Notes to Consolidated Financial Statements included under Part I, Item 1. Financial Statements of this report, which information is incorporated by reference into this item.

Item 1A. Risk Factors

Part I, Item 1A. Risk Factors in our Annual Report on Form 10-K for the year ended December 31, 2015 and Part II, Item 1A Risk Factors in our Quarterly Report on Form 10-Q for the period ended June 30, 2016, include certain risk factors that could materially affect our business, financial condition, or future results. Except as listed below, the risk factors stated in our periodic reports remain applicable, however, the risk factors listed below pertaining to the ETC Merger are no longer applicable:


•	The pendency of the proposed ETC Merger between Energy Transfer and Williams could adversely affect our business and operations.


•	The notes we acquired from ACMP in the ACMP Merger contain provisions that would require us to make an offer to repurchase such notes should our credit be downgraded within a period of ninety days following the completion of the proposed ETC Merger.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

On August 26, 2016, we entered into a Common Unit Purchase Agreement with Williams providing for the issuance and sale to Williams of 6,975,446 common units representing limited partner interests in us in a private placement transaction in reliance on Section 4(a)(2) of the Securities Act of 1933, as amended, as a transaction by an issuer not involving a public offering. The sale of the common units closed on August 30, 2016. The common units were sold for an aggregate purchase price of approximately $250 million, representing the reinvestment of a portion of the quarterly cash distribution received by Williams from us on August 12, 2016. The price per common unit of $35.84 was equal to the average of the high and low trading prices of our common units on the New York Stock Exchange for each of the five trading days from August 19 to August 25, 2016, less a discount of 2.5 percent per common unit, which price per common unit was calculated using the same method and discount that initially will be used to determine the price of the common units to be issued pursuant to our DRIP. The sale proceeds were used to repay amounts outstanding under our credit facility and for general partnership purposes.

Item 6. Exhibits



Exhibit No.		Description

§Exhibit 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).
§Exhibit 2.2	—	Share Purchase Agreement by and between Williams Energy Canada LP and Inter Pipeline Ltd. and Williams Partners L.P., dated August 8, 2016 (filed on August 12, 2016 as Exhibit 2.2 to Williams Partners L.P.’s current report on Form 8-K (file No. 001-34831) and incorporated herein by reference).
Exhibit 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).
Exhibit 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).
Exhibit 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).
Exhibit 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).
Exhibit 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).
Exhibit 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).
Exhibit 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).
Exhibit 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).
Exhibit 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).
Exhibit 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

Exhibit 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).
Exhibit 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).
*Exhibit 3.13	—	Composite Agreement of Limited Partnership of Williams Partners L.P.
Exhibit 3.14	—	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).
Exhibit 3.15	—	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).
Exhibit 3.16	—	Certificate of Amendment to Certificate of Formation of Access Midstream Partners GP, L.L.C. (filed on February 3, 2015 to Williams Partners L.P.’s current report on Form 8‑K (File No. 001-34831) and incorporated herein by reference).
Exhibit 3.17	—	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).
Exhibit 3.18	—	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).
Exhibit 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).
*Exhibit 10.2	—	Third Amendment to Equity Distribution Agreement dated August 2, 2016, between Williams Partners L.P., WPZ GP LLC and Citigroup Global Markets Inc., Barclays Capital Inc., J.P. Morgan Securities LLC, UBS Securities LLC, Merrill Lynch, Pierce, Fenner & Smith Incorporated, Scotia Capital (USA) Inc., Deutsche Bank Securities Inc., Morgan Stanley & Co. LLC, Mizuho Securities USA Inc. and MUFJG Securities (USA), Inc.
*Exhibit 12	—	Computation of Ratio of Earnings to Fixed Charges.
*Exhibit 31.1	—	Certification of Chief Executive Officer pursuant to Rules 13a-14(a) and 15d-14(a) promulgated under the Securities Exchange Act of 1934, as amended, and Item 601(b)(31) of Regulation S-K, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
*Exhibit 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.
**Exhibit 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.
*Exhibit 101.INS	—	XBRL Instance Document.



Exhibit No.		Description

*Exhibit 101.SCH	—	XBRL Taxonomy Extension Schema.
*Exhibit 101.CAL	—	XBRL Taxonomy Extension Calculation Linkbase.
*Exhibit 101.DEF	—	XBRL Taxonomy Extension Definition Linkbase.
*Exhibit 101.LAB	—	XBRL Taxonomy Extension Label Linkbase.
*Exhibit 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)

October 31, 2016

EXHIBIT INDEX



Exhibit No.		Description

§Exhibit 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).
§Exhibit 2.2	—	Share Purchase Agreement by and between Williams Energy Canada LP and Inter Pipeline Ltd. and Williams Partners L.P., dated August 8, 2016 (filed on August 12, 2016 as Exhibit 2.2 to Williams Partners L.P.’s current report on Form 8-K (file No. 001-34831) and incorporated herein by reference).
Exhibit 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).
Exhibit 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).
Exhibit 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).
Exhibit 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).
Exhibit 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).
Exhibit 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).
Exhibit 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).
Exhibit 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).
Exhibit 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).
Exhibit 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

Exhibit 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).
Exhibit 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).
*Exhibit 3.13	—	Composite Agreement of Limited Partnership of Williams Partners L.P.
Exhibit 3.14	—	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).
Exhibit 3.15	—	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).
Exhibit 3.16	—	Certificate of Amendment to Certificate of Formation of Access Midstream Partners GP, L.L.C. (filed on February 3, 2015 to Williams Partners L.P.’s current report on Form 8‑K (File No. 001-34831) and incorporated herein by reference).
Exhibit 3.17	—	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).
Exhibit 3.18	—	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).
Exhibit 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).
*Exhibit 10.2	—	Third Amendment to Equity Distribution Agreement dated August 2, 2016, between Williams Partners L.P., WPZ GP LLC and Citigroup Global Markets Inc., Barclays Capital Inc., J.P. Morgan Securities LLC, UBS Securities LLC, Merrill Lynch, Pierce, Fenner & Smith Incorporated, Scotia Capital (USA) Inc., Deutsche Bank Securities Inc., Morgan Stanley & Co. LLC, Mizuho Securities USA Inc. and MUFJG Securities (USA), Inc.
*Exhibit 12	—	Computation of Ratio of Earnings to Fixed Charges.
*Exhibit 31.1	—	Certification of Chief Executive Officer pursuant to Rules 13a-14(a) and 15d-14(a) promulgated under the Securities Exchange Act of 1934, as amended, and Item 601(b)(31) of Regulation S-K, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
*Exhibit 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.
**Exhibit 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.
*Exhibit 101.INS	—	XBRL Instance Document.



Exhibit No.		Description

*Exhibit 101.SCH	—	XBRL Taxonomy Extension Schema.
*Exhibit 101.CAL	—	XBRL Taxonomy Extension Calculation Linkbase.
*Exhibit 101.DEF	—	XBRL Taxonomy Extension Definition Linkbase.
*Exhibit 101.LAB	—	XBRL Taxonomy Extension Label Linkbase.
*Exhibit 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.

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