WPZ Williams Partners, L.P. Common Units Representing Limited Partner Interests (delisted)

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)

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•	The status, expected timing and expected outcome of the proposed ETC Merger;

•	Events which may occur subsequent to the proposed ETC Merger including events which directly impact our business;

•	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;

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•	Expansion and growth 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.

•	The timing and likelihood of completion of the proposed ETC Merger, including the satisfaction of conditions to the completion of the proposed ETC Merger;

•	Energy Transfer’s plans for us, as well as the other master limited partnerships it currently controls, following the completion of the proposed ETC Merger;

•	Disruption from the proposed ETC Merger making it more difficult to maintain business and operational relationships;

•	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;

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

•	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 execute investment opportunities;

•	Our ability to acquire new businesses and assets and successfully integrate those operations and assets into our existing businesses as well as successfully expand our facilities;

•	Development of alternative energy sources;

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

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•	Costs of, changes in, or the results of laws, government regulations (including safety and environmental regulations), environmental liabilities, litigation, and rate proceedings;

•	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;

•	Acts of terrorism, including cybersecurity threats and related disruptions;

•	Additional risks described in our filings with the SEC.

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PART I – FINANCIAL INFORMATION

Williams Partners L.P.

Consolidated Statement of Comprehensive Income

(Unaudited)

	Three Months Ended   March 31,
	2016				2015
	(Millions, except per-unit amounts)
Revenues:
Service revenues	$	1,226			$	1,192
Product sales	428				519
Total revenues	1,654				1,711
Costs and expenses:
Product costs	317				463
Operating and maintenance expenses	382				380
Depreciation and amortization expenses	435				419
Selling, general, and administrative expenses	181				193
Other (income) expense – net	30				17
Total costs and expenses	1,345				1,472
Operating income	309				239
Equity earnings (losses)	97				51
Impairment of equity-method investments	(112		)		—
Other investing income (loss) – net	—				1
Interest incurred	(240		)		(209		)
Interest capitalized	11				17
Other income (expense) – net	15				16
Income (loss) before income taxes	80				115
Provision (benefit) for income taxes	1				3
Net income (loss)	79				112
Less: Net income attributable to noncontrolling interests	29				23
Net income (loss) attributable to controlling interests	$	50			$	89
Allocation of net income (loss) for calculation of earnings per common unit:
Net income (loss) attributable to controlling interests	$	50			$	89
Allocation of net income (loss) to general partner	202				195
Allocation of net income (loss) to Class B units	(4		)		(2		)
Allocation of net income (loss) to Class D units	—				68
Allocation of net income (loss) to common units	$	(148	)		$	(172	)
Basic and diluted earnings (loss) per common unit:
Net income (loss) per common unit	$	(.25	)		$	(.34	)
Weighted-average number of common units outstanding (thousands)	588,562				507,001
Cash distributions per common unit	$	.85			$	.85
Other comprehensive income (loss):
Foreign currency translation adjustments	72				(87		)
Other comprehensive income (loss)	72				(87		)
Comprehensive income (loss)	151				25
Less: Comprehensive income attributable to noncontrolling interests	29				23
Comprehensive income (loss) attributable to controlling interests	$	122			$	2

See accompanying notes.

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Williams Partners L.P.

Consolidated Balance Sheet

(Unaudited)

	March 31, 2016				December 31, 2015
	(Dollars in millions)
ASSETS
Current assets:
Cash and cash equivalents	$	125			$	96
Trade accounts and notes receivable (net of allowance of $6 at March 31, 2016 and $3 at December 31, 2015)	727				1,026
Inventories	141				127
Other current assets	159				190
Total current assets	1,152				1,439
Investments	7,181				7,336
Property, plant, and equipment, at cost	38,373				37,833
Accumulated depreciation	(9,550		)		(9,233		)
Property, plant, and equipment – net	28,823				28,600
Goodwill	47				47
Other intangible assets – net of accumulated amortization	9,880				9,969
Regulatory assets, deferred charges, and other	497				479
Total assets	$	47,580			$	47,870
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable:
Trade	$	670			$	648
Affiliate	129				141
Accrued interest	198				231
Asset retirement obligations	50				57
Other accrued liabilities	446				469
Long-term debt due within one year	976				176
Commercial paper	135				499
Total current liabilities	2,604				2,221
Long-term debt	18,504				19,001
Asset retirement obligations	876				857
Deferred income tax liabilities	126				119
Regulatory liabilities, deferred income, and other	1,220				1,066
Contingent liabilities (Note 9)
Equity:
Partners’ equity:
Common units (588,565,185 and 588,546,022 units outstanding at March 31, 2016 and December 31, 2015, respectively)	19,281				19,730
Class B units (15,343,001 and 14,784,015 units outstanding at March 31, 2016 and December 31, 2015, respectively)	772				771
General partner	2,546				2,552
Accumulated other comprehensive income (loss)	(100		)		(172		)
Total partners’ equity	22,499				22,881
Noncontrolling interests in consolidated subsidiaries	1,751				1,725
Total equity	24,250				24,606
Total liabilities and equity	$	47,580			$	47,870

 

See accompanying notes.

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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)	43				1				6				—				50				29				79
Other comprehensive income (loss)	—				—				—				72				72				—				72
Cash distributions	(500		)		—				(16		)		—				(516		)		—				(516		)
Contributions from general partner	—				—				3				—				3				—				3
Contributions from noncontrolling interests	—				—				—				—				—				16				16
Distributions to noncontrolling interests	—				—				—				—				—				(19		)		(19		)
Other	8				—				1				—				9				—				9
Net increase (decrease) in equity	(449		)		1				(6		)		72				(382		)		26				(356		)
Balance – March 31, 2016	$	19,281			$	772			$	2,546			$	(100	)		$	22,499			$	1,751			$	24,250

See accompanying notes.

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Williams Partners L.P.

Consolidated Statement of Cash Flows

(Unaudited)

	Three Months Ended   March 31,
	2016				2015
	(Millions)
OPERATING ACTIVITIES:
Net income (loss)	$	79			$	112
Adjustments to reconcile to net cash provided (used) by operating activities:
Depreciation and amortization	435				419
Provision (benefit) for deferred income taxes	—				3
Impairment of equity-method investments	112				—
Amortization of stock-based awards	9				8
Cash provided (used) by changes in current assets and liabilities:
Accounts and notes receivable	298				208
Inventories	(15		)		32
Other current assets and deferred charges	23				7
Accounts payable	(19		)		(74		)
Accrued liabilities	(70		)		(61		)
Affiliate accounts receivable and payable – net	(15		)		6
Other, including changes in noncurrent assets and liabilities	87				37
Net cash provided (used) by operating activities	924				697
FINANCING ACTIVITIES:
Proceeds from (payments of) commercial paper – net	(365		)		(799		)
Proceeds from long-term debt	1,838				4,825
Payments of long-term debt	(1,526		)		(3,223		)
Contributions from general partner	3				4
Distributions to limited partners and general partner	(516		)		(725		)
Distributions to noncontrolling interests	(19		)		(13		)
Contributions from noncontrolling interests	16				25
Contributions from The Williams Companies, Inc. – net	—				20
Payments for debt issuance costs	(8		)		(27		)
Other – net	1				(11		)
Net cash provided (used) by financing activities	(576		)		76
INVESTING ACTIVITIES:
Property, plant, and equipment:
Capital expenditures (1)	(463		)		(735		)
Purchases of and contributions to equity-method investments	(63		)		(83		)
Distributions from unconsolidated affiliates in excess of cumulative earnings	109				93
Other – net	98				58
Net cash provided (used) by investing activities	(319		)		(667		)
Increase (decrease) in cash and cash equivalents	29				106
Cash and cash equivalents at beginning of year	96				171
Cash and cash equivalents at end of period	$	125			$	277
_________
(1) Increases to property, plant, and equipment	$	(498	)		$	(645	)
Changes in related accounts payable and accrued liabilities	35				(90		)
Capital expenditures	$	(463	)		$	(735	)

  See accompanying notes.

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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 our Annual Report on Form 10-K. The accompanying unaudited financial statements include all normal recurring adjustments and others that, in the opinion of management, are necessary to present fairly our interim financial statements.

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

Unless the context clearly indicates otherwise, references in this report to “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 March 31, 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 is required to pay us a $428 million termination fee, which will settle through a reduction of quarterly incentive distributions payable to Williams (such reduction not to exceed $209 million per quarter). Our November 2015 and February 2016 distributions to Williams were each reduced by $209 million related to this termination fee. Our next distribution to Williams in May 2016 will be reduced by the final $10 million 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 provides that, subject to the satisfaction of customary closing conditions, Williams will 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 will be treated as a corporation for U.S. federal income tax purposes. Immediately following the completion of the ETC Merger, ETC will 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. We expect to retain our current name and remain a publicly traded limited partnership following the ETC Merger.

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Notes (Continued)

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 (ACMP Acquisition).

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 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.

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. 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).

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Notes (Continued)

Basis of Presentation

Significant risks and uncertainties

We have previously announced that our business plan for 2016 includes the expectation of proceeds from planned asset monetizations. We have identified our Canadian operations, which have a net book value of Property, plant, and equipment of approximately $1.1 billion as of March 31, 2016, as one possible source for such proceeds and have recently engaged in marketing efforts to identify potentially interested parties and indications of value. As a result of these developments and the influence of the current low-price commodity environment on market values, we performed an impairment evaluation of these assets as of March 31, 2016, which considered probability-weighted scenarios of undiscounted future net cash flows pursuant to the guidance of Accounting Standards Codification (ASC) Topic 360. These included scenarios involving the continued ownership and operation of the assets, as well as selling all of or a partial interest in the assets at assumed transaction prices below our carrying value. As a result of this evaluation, we determined that no impairment was required as of March 31, 2016.

As the marketing process continues and our cash flow and probability assumptions are updated, it is reasonably possible that a portion of the Property, plant, and equipment – net of our Canadian operations may be determined to be unrecoverable and thus result in a significant impairment as early as the second quarter of 2016. The primary factors that may affect this determination are the structure and likelihood of a sale and the level of proceeds estimated to be received.

Accumulated other comprehensive income (loss)

Accumulated other comprehensive income (loss) (AOCI) is substantially comprised of foreign currency translation adjustments. These adjustments did not impact Net income (loss) in any of the periods presented.

Accounting standards issued but not yet adopted

In February 2016, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2016-02 “Leases (Topic 842)” (ASU 2016-02). ASU 2016-02 establishes a comprehensive new lease accounting model. 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 ASC Topic 606, “Revenue from Contracts with Customers” (ASC 606). ASC 606 establishes a comprehensive new revenue recognition model designed to depict the transfer of goods or services to a customer in an amount that reflects the consideration the entity expects to be entitled to receive in exchange for those goods or services and requires significantly enhanced revenue disclosures. In August 2015, the FASB issued ASU 2015-14 “Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date” (ASU 2015-14). Per ASU 2015-14, the standard is effective for interim and annual reporting periods beginning after December 15, 2017. ASC 606 allows either full retrospective or modified retrospective transition and early adoption is permitted for annual periods beginning after December 15, 2016. We continue to evaluate both the impact of this new standard on our consolidated financial statements and the transition method we will utilize for adoption.

Note 2 – Variable Interest Entities

As of March 31, 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

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Notes (Continued)

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 in service in the third quarter of 2016. The current estimate of the total remaining construction cost for the expansion project is approximately $108 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.

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 project in-service date is targeted as early as the second half of 2018 (see Note 11 – Subsequent Event ) and the total remaining cost of the project is estimated to be approximately $616 million , which we expect will be funded with capital contributions from us and the other equity partners on a proportional basis.

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.

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

	March 31, 2016				December 31, 2015				Classification
	(Millions)
Assets (liabilities):
Cash and cash equivalents	$	93			$	70			Cash and cash equivalents
Accounts receivable	66				71				Trade accounts and notes receivable – net
Prepaid assets	2				2				Other current assets
Property, plant, and equipment –  net	3,049				3,000				Property, plant, and equipment – net
Goodwill	47				47				Goodwill
Other intangible assets  –  net	1,422				1,436				Other intangible assets – net of accumulated amortization
Accounts payable	(66		)		(59		)		Accounts payable – trade
Accrued liabilities	(14		)		(14		)		Other accrued liabilities
Current deferred revenue	(51		)		(62		)		Other accrued liabilities
Noncurrent asset retirement obligations	(94		)		(93		)		Asset retirement obligations
Noncurrent deferred revenue associated with customer advance payments	(331		)		(331		)		Regulatory liabilities, deferred income, and other

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Notes (Continued)

Note 3 – 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   March 31,
	2016				2015
	(Millions)
Allocation of net income to general partner:
Net income (loss)	$	79			$	112
Net income applicable to pre-merger operations allocated to general partner	—				(2		)
Net income applicable to noncontrolling interests	(29		)		(23		)
Costs charged directly to the general partner	—				20
Income (loss) subject to 2% allocation of general partner interest	50				107
General partner’s share of net income	2		%		2		%
General partner’s allocated share of net income (loss) before items directly allocable to general partner interest	1				2
Priority allocations, including incentive distributions, paid to general partner	5				212
Pre-merger net income allocated to general partner interest	—				2
Costs charged directly to the general partner	—				(20		)
Net income allocated to general partner’s equity	$	6			$	196
Net income (loss)	$	79			$	112
Net income allocated to general partner’s equity	6				196
Net income (loss) allocated to Class B limited partners’ equity	1				(4		)
Net income allocated to Class D limited partners’ equity (1)	—				69
Net income allocated to noncontrolling interests	29				23
Net income (loss) allocated to common limited partners’ equity	$	43			$	(172	)
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)	1				212
Incentive distributions declared (2) (3)	(200		)		(212		)
Impact of unit issuance timing and other	8				—
Allocation of net income (loss) to common units	$	(148	)		$	(172	)

(1)	Includes amortization of the beneficial conversion feature associated with the Pre-merger WPZ Class D units of $68 million for the three months ended March 31, 2015. See following discussion of Class D units.

(2)	The 2016 amounts reflect the waiver of IDRs associated with the Termination Agreement. (See Note 1 – General, Description of Business, and Basis of Presentation .)

(3)	The Board of Directors of our general partner declared a cash distribution of $0.85 per common unit on April 26, 2016, to be paid on May 13, 2016, to unitholders of record at the close of business on May 6, 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 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 576,627 Class B units associated with the first-quarter distribution, to be issued on May 13, 2016.

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Notes (Continued)

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 4 – Investing Activities

Investing Income

First-quarter 2016 other-than-temporary impairment charges include $59 million and $50 million related to certain equity-method investments in the Delaware basin gas gathering system and Laurel Mountain, respectively (see Note 8 – Fair Value Measurements and Guarantees ).

Summarized Results of Operations for Certain Equity-Method Investments

The table below presents aggregated selected income statement data for our investments in Discovery, Gulfstream, OPPL, Appalachia Midstream Investments, and UEOM, which are considered significant.

	Three Months Ended March 31,
	2016				2015
	(Millions)
Gross revenue	$	300			$	246
Operating income	177				113
Net income	157				96

Note 5 – Other Income and Expenses

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

	Three Months Ended March 31,
	2016				2015
	(Millions)
Atlantic-Gulf
Amortization of regulatory assets associated with asset retirement obligations	$	8			$	8
NGL & Petchem Services
Net foreign currency exchange (gains) losses (1)	11				(5		)

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

ACMP Merger and Transition

•	Selling, general, and administrative expenses for the three months ended March 31, 2016 , and March 31, 2015 , includes $5 million and $29 million , 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 $4 million for the three months ended March 31, 2015 , of transition costs from the ACMP Merger within the Central segment.

15

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Notes (Continued)

•	Interest incurred includes transaction-related financing costs of $2 million for the three months ended March 31, 2015 , from the ACMP Merger.

Additional Items

•	Service revenues have been reduced by $15 million for the three months ended March 31, 2016 , related to potential refunds associated with a ruling received in certain rate case litigation within the Atlantic-Gulf segment.

•	Selling, general, and administrative expenses and Operating and maintenance expenses for the three months ended March 31, 2016 , include $25 million in severance and other related costs associated with an approximate 10 percent reduction in workforce. Amounts by segment are as follows:

	Three Months Ended March 31, 2016
	(Millions)
Central	$	6
Northeast G&P	3
Atlantic-Gulf	8
West	4
NGL & Petchem Services	4

•	Other income (expense) – net below Operating income includes $17 million for allowance for equity funds used during construction for both the three months ended March 31, 2016 , and March 31, 2015 , within the Atlantic-Gulf segment.

Note 6 – Inventories

	March 31, 2016				December 31, 2015
	(Millions)
Natural gas liquids, olefins, and natural gas in underground storage	$	70			$	57
Materials, supplies, and other	71				70
	$	141			$	127

Note 7 – 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.

16

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Notes (Continued)

Commercial Paper Program

As of March 31, 2016, we had $135 million of Commercial paper outstanding under our $3 billion commercial paper program with a weighted average interest rate of 1.29 percent .

Credit Facilities

	March 31, 2016
	Stated Capacity				Outstanding
	(Millions)
Long-term credit facility (1)	$	3,500			$	625
Letters of credit under certain bilateral bank agreements					2
Short-term credit facility	150				—

(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 8 – 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 March 31, 2016:
Measured on a recurring basis:
ARO Trust investments	$	82			$	82			$	82			$	—			$	—
Energy derivatives assets not designated as hedging instruments	3				3				1				1				1
Energy derivatives liabilities not designated as hedging instruments	(2		)		(2		)		—				—				(2		)
Additional disclosures:
Other receivables	13				13				12				1				—
Long-term debt, including current portion (1)	(19,479		)		(17,096		)		—				(17,096		)		—
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.

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Notes (Continued)

Fair Value Methods

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

Assets and liabilities measured at fair value on a recurring basis

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

Energy derivatives :  Energy derivatives include commodity based exchange-traded contracts and over-the-counter contracts, which consist of physical forwards, futures, and swaps that are measured at fair value on a recurring basis. The fair value amounts are presented on a gross basis and do not reflect the netting of asset and liability positions permitted under the terms of our master netting arrangements. Further, the amounts do not include cash held on deposit in margin accounts that we have received or remitted to collateralize certain derivative positions. Energy derivatives assets are reported in Other current assets 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 three months ended March 31, 2016 or 2015 .

Additional fair value disclosures

Other receivables: Other receivables primarily consists of margin deposits, which are reported in Other current assets 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. Our other receivables are reported in Trade accounts and notes receivable - net and Regulatory assets, deferred charges, and other in the Consolidated Balance Sheet. The disclosed fair value of our other receivables is primarily determined by an income approach which considers the underlying contract amounts and our assessment of our ability to recover these amounts.

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.

Assets measured at fair value on a nonrecurring basis

	Date of Measurement		Fair Value				Impairments
			(Millions)
Impairment of equity-method investments (1)	March 31, 2016		$	1,294			$	109
Other impairment of equity-method investment	March 31, 2016		—				3
Level 3 fair value measurements of equity-method investments							$	112

______________

(1)

Reflects other-than-temporary impairment charges related to Central’s equity-method investment in the Delaware basin gas gathering system and Northeast G&P’s equity-method investment in Laurel Mountain reported within Impairment of equity-method investments in the Consolidated Statement of Comprehensive Income . Our carrying values in these equity-method investments had been written down to fair value at December 31, 2015. Our first-quarter 2016 analysis reflects 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

18

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Notes (Continued)

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 9 – 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 March 31, 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.

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 emission limits, and new air quality standards impacting 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 March 31, 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 March 31, 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 (Geismar Incident). We are addressing the following matters in connection with the Geismar Incident.

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Notes (Continued)

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 trial for certain plaintiffs claiming personal injury, that was set to begin on June 15, 2015, in Iberville Parish, Louisiana, has been postponed to September 6, 2016. The court also set trial dates for additional plaintiffs in November 2016 and January and April 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 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. Due to the preliminary status of the 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. We cannot reasonably estimate a range of potential loss at this time.

Other

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

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.

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Notes (Continued)

Note 10 – 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.

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.

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Notes (Continued)

The following table reflects the reconciliation of Segment revenues to Total revenues as reported in the Consolidated Statement of Comprehensive Income .

	Central				Northeast G&P				Atlantic- Gulf				West				NGL & Petchem Services				Eliminations				Total
	(Millions)
Three Months Ended March 31, 2016
Segment revenues:
Service revenues
External	$	252			$	208			$	465			$	263			$	38			$	—			$	1,226
Internal	3				3				1				—				—				(7		)		—
Total service revenues	255				211				466				263				38				(7		)		1,226
Product sales
External	—				19				37				4				368				—				428
Internal	—				5				32				48				38				(123		)		—
Total product sales	—				24				69				52				406				(123		)		428
Total revenues	$	255			$	235			$	535			$	315			$	444			$	(130	)		$	1,654
Three Months Ended March 31, 2015
Segment revenues:
Service revenues
External	$	245			$	196			$	457			$	262			$	32			$	—			$	1,192
Internal	7				—				1				—				—				(8		)		—
Total service revenues	252				196				458				262				32				(8		)		1,192
Product sales
External	—				37				68				8				406				—				519
Internal	—				1				53				56				37				(147		)		—
Total product sales	—				38				121				64				443				(147		)		519
Total revenues	$	252			$	234			$	579			$	326			$	475			$	(155	)		$	1,711

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Notes (Continued)

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

	Three Months Ended   March 31,
	2016				2015
	(Millions)
Modified EBITDA by segment:
Central	$	157			$	133
Northeast G&P	214				185
Atlantic-Gulf	376				335
West	155				161
NGL & Petchem Services	53				6
Other	—				(3		)
	955				817
Accretion expense associated with asset retirement obligations for nonregulated operations	(7		)		(7		)
Depreciation and amortization expenses	(435		)		(419		)
Equity earnings (losses)	97				51
Impairment of equity-method investments	(112		)		—
Other investing income (loss) – net	—				1
Proportional Modified EBITDA of equity-method investments	(189		)		(136		)
Interest expense	(229		)		(192		)
(Provision) benefit for income taxes	(1		)		(3		)
Net income (loss)	$	79			$	112

The following table reflects Total assets by reportable segment.  

	Total Assets
	March 31,   2016				December 31,   2015
	(Millions)
Central	$	13,654			$	13,914
Northeast G&P	13,667				13,827
Atlantic-Gulf	13,453				12,171
West	4,981				5,035
NGL & Petchem Services	3,401				3,306
Other corporate assets	324				350
Eliminations (1)	(1,900		)		(733		)
Total	$	47,580			$	47,870

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

Note 11 – Subsequent Event

As previously discussed, we are the construction manager for and own a 41 percent consolidated interest in Constitution. 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

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Notes (Continued)

pipeline. We remain steadfastly committed to the project and intend to challenge the legality and appropriateness of the NYSDEC’s decision. In light of the NYSDEC’s denial of the water quality certification and the anticipated actions 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. An unfavorable resolution could result in the impairment of a significant portion of the capitalized project costs, which total $396 million on a consolidated basis at March 31, 2016, and are included within Property, plant, and equipment, at cost in the Consolidated Balance Sheet . It is also possible that we could incur certain supplier-related costs in the event of a prolonged delay or termination of the project.

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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 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.

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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, 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. 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 March 31, 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 2015 Annual Report on Form 10-K dated February 26, 2016.

Distributions

On April 26, 2016 , our general partner’s Board of Directors approved a quarterly distribution to unitholders of $0.85 per common unit on May 13, 2016, on our outstanding common units to unitholders of record at the close of business on May 6, 2016.

Overview of Three Months Ended March 31, 2016

Net income (loss) attributable to controlling interests for the three months ended March 31, 2016 , decreased $39 million compared to the three months ended March 31, 2015 , primarily due to impairment charges associated with certain equity-method investments and an increase in interest incurred, which were partially offset by an increase in olefins margins associated with our Geismar plant and higher equity earnings at Discovery related to the completion of the Keathley Canyon Connector in 2015. See additional discussion in Results of Operations.

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 provides that, subject to the satisfaction of customary closing conditions, Williams will be merged with and into the newly formed ETC, with ETC surviving the ETC Merger. Energy Transfer formed ETC as a limited partnership that will be treated as a corporation for U.S. federal income tax purposes. Immediately following the completion of the ETC Merger, ETC will 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. We expect to retain our current name and remain a publicly traded limited partnership following the ETC Merger.

NGL & Petchem Services

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 butane, an alkylation feed and condensate under a long-term, fee-based agreement.

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Management’s Discussion and Analysis (Continued)

Volatile Commodity Prices

NGL per-unit margins were approximately 36 percent lower in the first three months of 2016 compared to the same period of 2015 driven primarily by 30 percent lower per-unit non-ethane prices, as well as a change in the relative mix of NGL products produced, which has shifted to a higher proportion of lower-margin ethane products . These decreases are partially offset by more than a 30 percent decline in per-unit natural gas feedstock prices.

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

The 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

As previously discussed, Williams entered into a Merger Agreement with Energy Transfer and certain of its affiliates and expects the ETC Merger to close in the second quarter of 2016. The following discussion reflects our operating plan for 2016.

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Management’s Discussion and Analysis (Continued)

Our strategy is to provide large-scale energy infrastructure designed to maximize the opportunities created by the vast supply of natural gas, natural gas products, and crude oil that exists in North America. 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.

This strategy remains intact and we continue to execute on infrastructure projects that serve long-term natural gas needs. We expect commodity prices to remain challenged and costs of capital to remain sharply higher throughout 2016 as compared to 2015. Anticipating these conditions, our business plan for 2016 includes significant reductions in capital investment and expenses, including the workforce reductions previously discussed in Note 5 – Other Income and Expenses , from our previous plans. In addition, we expect proceeds from planned asset monetizations in excess of $1 billion during 2016.

Our growth capital and investment expenditures in 2016 are expected to total $2.1 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 to known new producer volumes, including wells drilled and 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.

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

For example, we have been 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 margins are highly dependent upon regional supply/demand balances of natural gas as they relate to NGL margins, while olefins are impacted by global supply and demand fundamentals. We anticipate the following trends in energy commodity prices in 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, we anticipate our operating results will include increases from our fee-based businesses primarily as a result of Atlantic-Gulf projects placed in service in 2015 and those anticipated to be placed in service in 2016, increases in our olefins volumes associated with a full year of operations at our Geismar plant following its 2015 repair and expansion, and lower general and administrative costs associated with previously discussed workforce reductions. Additionally, we anticipate these improvements will be partially offset by the absence of operating results associated with certain asset monetizations and additional operating expenses associated with growth projects placed in service in 2015 and those anticipated to be placed in service in 2016. It is also possible that certain asset monetization scenarios could result in impairments if assets are sold for amounts less than their carrying value.

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Management’s Discussion and Analysis (Continued)

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 proceeds from planned asset monetizations;

•	Cost reductions at levels lower than anticipated;

•	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;

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

•	Lower than expected levels of cash flow from operations;

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

•	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 North America.

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 2019.

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Management’s Discussion and Analysis (Continued)

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 intend to challenge the legality and appropriateness of the NYSDEC’s decision. (See Note 11 – Subsequent Event .) 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 anticipated actions 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.

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 fourth quarter of 2016 and the remaining portion in the third 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 first quarter of 2019.

Hillabee

In February 2016, the FERC issued a certificate order for the initial phases of Transco’s Hillabee Expansion Project (Hillabee). 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. Construction is expected to begin in the second quarter of 2016. Hillabee will be constructed in phases, and all of the project expansion capacity will be leased to Sabal Trail. We plan to place the initial phases of Hillabee into service during the second quarters of 2017 and 2020, assuming timely receipt of all necessary regulatory approvals, 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. We expect to recognize income associated with these receipts over the term of the capacity lease agreement.

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Management’s Discussion and Analysis (Continued)

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 2015, we filed an application with 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, assuming timely receipt of all necessary regulatory approvals, and it is expected to increase capacity by 115 Mdth/d.

Rock Springs

In March 2015, we received approval from the FERC to expand Transco’s existing natural gas transmission system from New Jersey to a proposed generation facility in Maryland. We plan to place the project into service in the third quarter of 2016 and it is expected to increase capacity by 192 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 plan to place the project into service as early as late 2017, assuming timely receipt of all necessary regulatory approvals, and it is expected to increase capacity by 1,700 Mdth/d.

Virginia Southside II

In March 2015, we filed an application with the FERC to expand Transco’s existing natural gas transmission system together with greenfield facilities to provide incremental firm transportation capacity from 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 March 2015, we filed an application with the FERC to expand Transco’s existing natural gas transmission system together with greenfield facilities to provide incremental firm transportation capacity from Station 210 in New Jersey to markets in northwest Georgia. We plan to place the project into service in 2017, assuming timely receipt of all necessary regulatory approvals, and it is expected to increase capacity by 448 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 March 31, 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

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Management’s Discussion and Analysis (Continued)

book value by approximately $262 million, or 10 percent. We estimate 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.

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 Delaware basin gas gathering system (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 reflects higher discount rates for both DBJV and LMM, along with lower natural gas prices for LMM.

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 estimate 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 $104 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.

At March 31, 2016, our Consolidated Balance Sheet includes approximately $7.2 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 loss in value has occurred, we compare our estimate of 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;

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

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Management’s Discussion and Analysis (Continued)

Constitution Pipeline Capitalized Project Costs

As of March 31, 2016, Property, plant, and equipment, at cost in our Consolidated Balance Sheet includes approximately $396 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 intend to challenge the legality and appropriateness of the NYSDEC’s decision.

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 will continue to monitor the capitalized project costs associated with Constitution for potential impairment.

Property, Plant, and Equipment - Canadian Operations

We evaluate our property, plant, and equipment 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.

We have previously announced that our business plan for 2016 includes the expectation of proceeds from planned asset monetizations. We have identified our Canadian operations, which have a net book value of property, plant, and equipment of approximately $1.1 billion as of March 31, 2016, as one possible source for such proceeds and have recently engaged in marketing efforts to identify potentially interested parties and indications of value. As a result of these developments and the influence of the current low-price commodity environment on market values, we performed an impairment evaluation of these assets as of March 31, 2016, which considered probability-weighted scenarios of undiscounted future net cash flows pursuant to the guidance of Accounting Standards Codification Topic 360. These included scenarios involving the continued ownership and operation of the assets, as well as selling all of or a partial interest in the assets at assumed transaction prices below our carrying value. As a result of this evaluation, we determined that no impairment was required as of March 31, 2016.

As the marketing process continues and our cash flow and probability assumptions are updated, it is reasonably possible that a portion of the property, plant and equipment of our Canadian operations may be determined to be unrecoverable and thus result in a significant impairment as early as the second quarter of 2016. The primary factors that may affect this determination are the structure and likelihood of a sale and the level of proceeds estimated to be received.

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Management’s Discussion and Analysis (Continued)

Results of Operations

Consolidated Overview

The following table and discussion is a summary of our consolidated results of operations for the three months ended March 31, 2016 , compared to the three months ended March 31, 2015 . The results of operations by segment are discussed in further detail following this consolidated overview discussion.

	Three Months Ended   March 31,
	2016				2015				$ Change*			% Change*
	(Millions)
Revenues:
Service revenues	$	1,226			$	1,192			+34			+3	%
Product sales	428				519				-91			-18	%
Total revenues	1,654				1,711
Costs and expenses:
Product costs	317				463				+146			+32	%
Operating and maintenance expenses	382				380				-2			-1	%
Depreciation and amortization expenses	435				419				-16			-4	%
Selling, general, and administrative expenses	181				193				+12			+6	%
Other (income) expense – net	30				17				-13			-76	%
Total costs and expenses	1,345				1,472
Operating income	309				239
Equity earnings (losses)	97				51				+46			+90	%
Impairment of equity-method investments	(112		)		—				-112			NM
Other investing income (loss) – net	—				1				-1			+100	%
Interest expense	(229		)		(192		)		-37			-19	%
Other income (expense) – net	15				16				-1			-6	%
Income (loss) before income taxes	80				115
Provision (benefit) for income taxes	1				3				+2			+67	%
Net income (loss)	79				112
Less: Net income attributable to noncontrolling interests	29				23				-6			-26	%
Net income (loss) attributable to controlling interests	$	50			$	89

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

Three months ended March 31, 2016 vs. three months ended March 31, 2015

Service revenues increased primarily due to expansion projects placed in service in 2015 and 2016 in most of our operating areas. These increases were partially offset by a decrease in storage revenues at Transco, natural volume declines in certain production areas, and operational issues of producers in the Gulf Coast region.

Product sales decreased due to reduced marketing revenues primarily associated with lower prices across most products and lower volumes, as well as a reduction in revenues from our equity NGLs mainly related to a decrease in NGL prices. Additionally, olefin sales from our RGP Splitter and our Canadian operations decreased driven by lower per-unit prices. These decreases were partially offset by an increase in olefin sales primarily associated with resuming our Geismar operations.

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Management’s Discussion and Analysis (Continued)

The decrease in Product costs includes lower marketing purchases primarily associated with a decline in per-unit costs across most products and lower volumes. The decrease also includes reduced natural gas purchases associated with the production of equity NGLs mostly due to lower natural gas prices, as well as decreased olefin feedstock purchases at our RGP Splitter and our Canadian operations driven by lower per-unit costs. An increase in olefin feedstock purchases primarily related to resuming our Geismar operations partially offset these decreases.

Operating and maintenance expenses includes $14 million of severance and related costs recognized in 2016 associated with workforce reductions. This increase was substantially offset by lower operating costs including electric power costs, outside services fees, and materials and supplies expenses.

Depreciation and amortization expenses increased primarily due to depreciation on new projects placed in service, including the Geismar expansion.

Selling, general, and administrative expenses decreased primarily due to lower merger and transition costs associated with the ACMP Merger, partially offset by $11 million of severance and related costs recognized in 2016 associated with workforce reductions.

Other (income) expense – net within Operating income includes an unfavorable change in net foreign currency exchange gains and losses.

Operating income increased primarily due to higher olefin margins related to the resumption of operations at Geismar, higher fee revenues from expansion projects placed in service in 2015 and 2016, and lower costs related to the merger and integration of ACMP. These increases were partially offset by higher depreciation expenses related to new projects placed in service and severance and related workforce reduction costs recognized in 2016.

Equity earnings (losses) changed favorably primarily due to a $25 million increase at Discovery related to the completion of the Keathley Canyon Connector in the first quarter of 2015. Additionally, UEOM contributed $10 million primarily due to an increase in our ownership percentage and Laurel Mountain contributed $9 million primarily related to the absence of impairments recognized during the first quarter of 2015.

Impairment of equity-method investments reflects 2016 impairment charges associated with certain equity-method investments. (See Note 4 – Investing Activities of Notes to Consolidated Financial Statements.)

Interest expense increased due to higher Interest incurred of $31 million primarily attributable to new debt issuances in 2016 and 2015 as well as lower Interest capitalized of $6 million mostly related to construction projects that have been placed into service, partially offset by lower interest due to 2015 debt retirements. (See Note 7 – Debt and Banking Arrangements of Notes to Consolidated Financial Statements.)

Period-Over-Period Operating Results – Segments

We evaluate segment operating performance based upon Modified EBITDA . Note 10 – 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.

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Management’s Discussion and Analysis (Continued)

Central

	Three Months Ended   March 31,
	2016				2015
	(Millions)
Service revenues	$	255			$	252
Segment costs and expenses	(107		)		(127		)
Proportional Modified EBITDA of equity-method investments	9				8
Central Modified EBITDA	$	157			$	133

Three months ended March 31, 2016 vs. three months ended March 31, 2015

Modified EBITDA increased primarily due to a decrease in ACMP Merger and transition expenses incurred in 2016.

Service revenues increased slightly primarily due to higher rates in the Haynesville area, partially offset by lower volumes in the Barnett and Anadarko areas.

Segment costs and expenses decreased primarily due to a $27 million decrease in ACMP Merger and transition expenses in 2016, partially offset by $6 million of severance and related costs recognized in 2016 related to workforce reductions.

Northeast G&P

	Three Months Ended   March 31,
	2016				2015
	(Millions)
Service revenues	$	211			$	196
Product sales	24				38
Segment revenues	235				234
Product costs	(21		)		(37		)
Other segment costs and expenses	(97		)		(88		)
Proportional Modified EBITDA of equity-method investments	97				76
Northeast G&P Modified EBITDA	$	214			$	185

Three months ended March 31, 2016 vs. three months ended March 31, 2015

Modified EBITDA increased primarily due to improvements in Proportional Modified EBITDA of equity-method investments driven by increases in our ownership percentage of UEOM and the absence of certain impairments in the first quarter of 2015.

Service revenues include an increase in Utica Shale gathering revenues primarily due to growth in volumes associated with new well connects and higher reimbursement of certain costs from customers, partially offset by a decline in fee-based revenues from our Ohio Valley Midstream operations associated with producer shut-ins and lower rates.

Product sales decreased primarily due to a $16 million decline in marketing sales in the Ohio Valley Midstream business, comprised of an $11 million decrease reflecting a 39 percent decline in non-ethane per-unit marketing sales prices and a $5 million decline associated with a 16 percent decrease in non-ethane volumes. The changes in marketing revenues are offset by similar changes in marketing purchases, reflected above as Product costs .

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Management’s Discussion and Analysis (Continued)

Proportional Modified EBITDA of equity-method investments improved primarily due to an $11 million increase from UEOM associated with an increase in our ownership percentage and a $10 million increase from Laurel Mountain primarily due to the absence of impairments incurred during the first quarter of 2015.

Atlantic-Gulf

	Three Months Ended   March 31,
	2016				2015
	(Millions)
Service revenues	$	466			$	458
Product sales	69				121
Segment revenues	535				579
Product costs	(64		)		(113		)
Other segment costs and expenses	(161		)		(169		)
Proportional Modified EBITDA of equity-method investments	66				38
Atlantic-Gulf Modified EBITDA	$	376			$	335
NGL margin	$	5			$	7

Three months ended March 31, 2016 vs. three months ended March 31, 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, lower segment costs and expenses, and higher service revenues.

Service revenues increased primarily due to a $36 million increase in Transco’s natural gas transportation fee revenues primarily associated with expansion projects placed in service in 2015 and 2016. This increase was partially offset by 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. In addition, Eastern Gulf Coast fee revenues decreased $10 million primarily related to producers’ operational issues at Gulfstar and natural declines in certain production areas.

Product sales decreased primarily due to:

•

A $42 million decrease in crude oil and NGL marketing revenues. Crude oil marketing sales decreased $24 million associated with 38 percent lower crude oil per barrel sales prices and 27 percent lower volumes. Lower volumes were primarily due to natural declines in production areas served by our Mountaineer crude oil pipeline. NGL marketing sales decreased $18 million associated with 30 percent lower non-ethane per-unit sales prices and 22 percent lower non-ethane sales volumes. These changes in marketing revenues are offset by similar changes in marketing purchases;

•	A $5 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 decreased primarily due to:

•	A $43 million decrease in marketing purchases (offset in Product sales );

•	A $5 million decrease in system management gas costs (offset in Product sales ) .

Other segment costs and expenses decreased primarily due to lower operating expenses and project development costs. These decreases were partially offset by $8 million of severance and related costs recognized in 2016 associated with workforce reductions.

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Management’s Discussion and Analysis (Continued)

The increase in Proportional Modified EBITDA of equity-method investments is primarily due to a $28 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   March 31,
	2016				2015
	(Millions)
Service revenues	$	263			$	262
Product sales	52				64
Segment revenues	315				326
Product costs	(31		)		(36		)
Other segment costs and expenses	(129		)		(129		)
West Modified EBITDA	$	155			$	161
NGL margin	$	20			$	25

Three months ended March 31, 2016 vs. three months ended March 31, 2015

Modified EBITDA decreased due to lower NGL margins as a result of lower prices, partially offset by lower per-unit natural gas costs and contributions from the start-up of the Bucking Horse processing facility in the first quarter of 2015.

Service revenues increased due to $7 million higher gathering and processing revenues from the Niobrara operations due to the start-up of the Bucking Horse processing facility in the first quarter of 2015, partially offset by lower gathering and processing fees in the Piceance basin primarily due to lower volumes.

Product sales decreased primarily due to a $10 million decrease in revenues from our equity NGLs associated with 26 percent lower average per-unit non-ethane sales prices driven by the decline in NGL prices.

Product costs decreased primarily due to lower per-unit natural gas costs.

NGL & Petchem Services

	Three Months Ended   March 31,
	2016				2015
	(Millions)
Service revenues	$	38			$	32
Product sales	406				443
Segment revenues	444				475
Product costs	(325		)		(424		)
Other segment costs and expenses	(83		)		(56		)
Proportional Modified EBITDA of equity-method investments	17				11
NGL & Petchem Services Modified EBITDA	$	53			$	6
Olefins margin	$	71			$	9
NGL margin	5				10

Three months ended March 31, 2016 vs. three months ended March 31, 2015

Modified EBITDA increased primarily due to higher olefin margins driven by the return to operation of the Geismar plant in late March 2015, partially offset by an unfavorable change in net foreign currency exchange gains and losses.

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Management’s Discussion and Analysis (Continued)

Product sales decreased primarily due to:

•	An $89 million decrease in marketing revenues primarily due to lower prices across all products, especially non-ethane (more than offset by lower Product costs );

•	An $11 million decrease in Canadian NGL sales revenues primarily due to lower prices, reflecting 71 percent and 22 percent per-unit lower propane and ethane prices, respectively;

•	A $65 million increase in olefin sales primarily due to $96 million in higher sales from our Geismar plant that returned to operation in late March 2015, partially offset by a $20 million decrease from our RGP Splitter and an $11 million decrease from our Canadian operations, both driven by lower per-unit prices.

Product costs decreased primarily due to:

•	A $92 million decrease in marketing product costs primarily due to lower per-unit costs across all products, especially non-ethane (substantially offset by lower Product sales );

•	A $6 million decrease in NGL product costs primarily related to a decline in the price of natural gas associated with the production of equity NGLs;

•	A $3 million increase in olefin feedstock purchases primarily comprised of $36 million in higher purchases due to increased volumes at our Geismar plant as it returned to operation in late March 2015, partially offset by $31 million lower per-unit purchase costs at our RGP Splitter and $2 million lower per-unit purchase costs in our Canadian operations.

The increase in Other segment costs and expenses includes a $16 million unfavorable change in foreign currency exchange that primarily relates to losses incurred on foreign currency transactions and the remeasurement of U.S. dollar denominated current assets and liabilities within our Canadian operations. The increase in Other segment costs and expenses was also driven by higher operating expenses, including severance and related costs recognized in 2016 associated with workforce reductions and the return to operation of the Geismar plant in late March 2015.

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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 $2.1 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. In addition, we expect proceeds from planned asset monetizations in excess of $1 billion during 2016.

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;

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

•	Transco’s recent debt issuance described further below;

•	Proceeds from planned asset monetizations.

We do not plan to issue public equity or public debt in 2016. 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.

Potential risks associated with our planned levels of liquidity discussed above include those previously discussed in Company Outlook. We further note that certain long-term debt originally issued by ACMP totaling $2.9 billion has provisions that would require us to make an offer to repurchase such notes at 101 percent of the principle amount should our credit be downgraded by either Moody’s Investor Service or Standard and Poor’s within a period of ninety days following the completion of the proposed ETC Merger. If we are required to repurchase the notes, we would expect

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Management’s Discussion and Analysis (Continued)

our funding sources to be derived from credit facility borrowings, new debt issuances, additional asset sales, reductions of distributions, and/or equity issuances.

As of March 31, 2016 , we had a working capital deficit (current liabilities, inclusive of $135 million in Commercial paper outstanding and $976 million in Long-term debt due within one year , in excess of current assets) of $1.452 billion . Our available liquidity is as follows:

Available Liquidity	March 31, 2016
	(Millions)
Cash and cash equivalents	$	125
Capacity available under our $3.5 billion credit facility, less amounts outstanding under our $3 billion commercial paper program (1)	2,740
Capacity available under our short-term credit facility (2)	150
	$	3,015

(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 March 31, 2016 , the highest amount outstanding under our commercial paper program and credit facility during 2016 was $1.856 billion. At March 31, 2016 , we were in compliance with the financial covenants associated with this credit facility and the commercial paper program. See Note 7 – Debt and Banking Arrangements of Notes to Consolidated Financial Statements for additional information on our commercial paper program. Borrowing capacity available under this facility as of May 3, 2016, was $2.707 billion.

(2)	Borrowing capacity available under this facility as of May 3, 2016, was $150 million.

Incentive Distribution Rights

Williams has agreed to temporarily waive incentive distributions of approximately $2 million per quarter in connection with our acquisition of 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 was to be settled through a reduction of quarterly incentive distributions payable to Williams (such reduction not to exceed $209 million per quarter). The November 2015 and February 2016 distributions to Williams were each reduced by $209 million related to this termination fee. The May 2016 distribution payable to Williams will be reduced by the final $10 million related to this termination.

Debt Issuances and Retirements

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

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.

Shelf Registration

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 March 31, 2016 , we have received net proceeds of approximately $59 million from equity issued under this registration.

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Management’s Discussion and Analysis (Continued)

Distributions from Equity-Method Investees

The organizational documents of entities in which we have an equity-method interest 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
Standard & Poor’s		Negative		BBB-		BBB-
Moody’s Investors Service		Negative		Baa3		N/A
Fitch Ratings		Stable		BBB-		N/A

As of March 31, 2016 , we estimated that a downgrade to a rating below investment grade could require us to post up to $283 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 April 26, 2016 , to be paid on May 13, 2016, to unitholders of record at the close of business on May 6, 2016.

Sources (Uses) of Cash

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

	Three Months Ended   March 31,
	2016				2015
	(Millions)
Net cash provided (used) by:
Operating activities	$	924			$	697
Financing activities	(576		)		76
Investing activities	(319		)		(667		)
Increase (decrease) in cash and cash equivalents	$	29			$	106

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 and Impairment of equity-method investments . Our Net cash provided (used) by operating activities in 2016 increased from 2015 primarily due to the impact of higher operating income, cash received related to Hillabee (see Expansion Projects), and net favorable changes in operating working capital.

Financing activities

Significant transactions include:

•	$365 million in 2016 and $799 million in 2015 of net payments for commercial paper;

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

•	$750 million in 2015 paid on our debt retirement;

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Management’s Discussion and Analysis (Continued)

•	$840 million in 2016 and $1.832 billion in 2015 received from our credit facility borrowings;

•	$1.525 billion in 2016 and $2.472 billion in 2015 paid on our credit facility borrowings;

•	$516 million , including $304 million to Williams, in 2016 and $725 million , including $515 million to Williams, in 2015 related to quarterly cash distributions paid to limited partner unitholders and the general partner.

Investing activities

Significant transactions include:

•	Capital expenditures of $463 million in 2016 and $735 million in 2015 ;

•	Purchases of and contributions to our equity-method investments of $63 million in 2016 and $83 million in 2015 ;

•	Distributions from unconsolidated affiliates in excess of cumulative earnings of $109 million in 2016 and $93 million in 2015 .

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

We have various other guarantees and commitments which are disclosed in Note 2 – Variable Interest Entities , Note 7 – Debt and Banking Arrangements , Note 8 – Fair Value Measurements and Guarantees , and Note 9 – Contingent Liabilities of Notes to Consolidated Financial Statements. We do not believe these guarantees and commitments or the possible fulfillment of them will prevent us from meeting our liquidity needs.

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Item 3

Quantitative and Qualitative Disclosures About Market Risk

Interest Rate Risk

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

Foreign Currency Risk

Our foreign operations, whose functional currency is the local currency, are located in Canada. Net assets of our foreign operations were approximately $1.0 billion and $916 million at March 31, 2016 and December 31, 2015 , respectively. These investments have the potential to impact our financial position due to fluctuations in the local currency arising from the process of translating the local functional currency into the U.S. dollar. As an example, a 20 percent change in the functional currency against the U.S. dollar would have changed Total partners’ equity by approximately $202 million and $183 million at March 31, 2016 and December 31, 2015 , respectively.

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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 first 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. At March 31, 2016 , we had accrued liabilities of $140,000 for potential penalties arising out of the deficiencies, and 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. We do not anticipate penalties being imposed by the West Virginia Department of Environmental Protection.

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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 9 – 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.

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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 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 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).

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Exhibit No.				Description
Exhibit 3.12		—		Composite Agreement of Limited Partnership of Williams Partners L.P. (filed on October 29, 2015 as Exhibit 3.12 to Williams Partners L.P.'s quarterly report on Form 10-Q (File No. 001-34831) and incorporated herein by reference).
Exhibit 3.13		—		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 3.14		—		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 3.15		—		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 3.16		—		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 3.17		—		Seventh Amended and Restated Limited Liability Company Agreement of WPZ GP LLC (filed on February 2, 2015 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 4.1		—		Indenture, dated as of January 22, 2016, between Transcontinental Gas Pipe Line Company, LLC and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on January 22, 2016 as Exhibit 4.1 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-34831) and incorporated herein by reference).
Exhibit 10.1		—		Registration Rights Agreement, dated January 22, 2016, between Transcontinental Gas Pipe Line Company, LLC and each of the initial purchasers listed therein (filed on January 22, 2016 as Exhibit 10.1 to Williams Partners L.P.’s Form 8-K (File No. 001-34831) and incorporated herein by reference).
*Exhibit 10.2		—		Second Amendment to Equity Distribution Agreement dated February 29, 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 Mitsubishi UFJ 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 101.SCH		—		XBRL Taxonomy Extension Schema.
*Exhibit 101.CAL		—		XBRL Taxonomy Extension Calculation Linkbase.

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Exhibit No.				Description
*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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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)

May 5, 2016

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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 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 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).

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Exhibit No.				Description
Exhibit 3.12		—		Composite Agreement of Limited Partnership of Williams Partners L.P. (filed on October 29, 2015 as Exhibit 3.12 to Williams Partners L.P.'s quarterly report on Form 10-Q (File No. 001-34831) and incorporated herein by reference).
Exhibit 3.13		—		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 3.14		—		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 3.15		—		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 3.16		—		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 3.17		—		Seventh Amended and Restated Limited Liability Company Agreement of WPZ GP LLC (filed on February 2, 2015 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 4.1		—		Indenture, dated as of January 22, 2016, between Transcontinental Gas Pipe Line Company, LLC and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on January 22, 2016 as Exhibit 4.1 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-34831) and incorporated herein by reference.
Exhibit 10.1		—		Registration Rights Agreement, dated January 22, 2016, between Transcontinental Gas Pipe Line Company, LLC and each of the initial purchasers listed therein (filed on January 22, 2016 as Exhibit 10.1 to Williams Partners L.P.’s Form 8-K (File No. 001-34831) and incorporated herein by reference).
*Exhibit 10.2		—		Second Amendment to Equity Distribution Agreement dated February 29, 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 Mitsubishi UFJ 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 101.SCH		—		XBRL Taxonomy Extension Schema.
*Exhibit 101.CAL		—		XBRL Taxonomy Extension Calculation Linkbase.

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Exhibit No.				Description
*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.