UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)



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

For the quarterly period ended March 31, 2018



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

For the transition period from _____________ to _____________

Commission file number 1-34831

WILLIAMS PARTNERS L.P.

(Exact name of registrant as specified in its charter)



DELAWARE		20-2485124
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

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

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

NO CHANGE

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

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

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

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



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

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

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

The registrant had 957,529,489 common units and 18,124,096 Class B units outstanding as of April 30, 2018.

Williams Partners L.P.

Index



Part I. Financial Information		Page
Item 1. Financial Statements
Consolidated Statement of Comprehensive Income – Three Months Ended March 31, 2018 and 2017		6
Consolidated Balance Sheet – March 31, 2018 and December 31, 2017		7
Consolidated Statement of Changes in Equity – Three Months Ended March 31, 2018		8
Consolidated Statement of Cash Flows – Three Months Ended March 31, 2018 and 2017		9
Notes to Consolidated Financial Statements		10
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		30
Item 3. Quantitative and Qualitative Disclosures About Market Risk		48
Item 4. Controls and Procedures		48
Part II. Other Information		48
Item 1. Legal Proceedings		48
Item 1A. Risk Factors		50
Item 6. Exhibits		51

The reports, filings, and other public announcements of Williams Partners L.P. (WPZ) may contain or incorporate by reference statements that do not directly or exclusively relate to historical facts. Such statements are “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (Securities Act) and Section 21E of the Securities Exchange Act of 1934, as amended (Exchange Act). These forward-looking statements relate to anticipated financial performance, management’s plans and objectives for future operations, business prospects, outcome of regulatory proceedings, market conditions, and other matters.

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


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


•	Our and our affiliates’ future credit ratings;


•	Amounts and nature of future capital expenditures;


•	Expansion and growth of our business and operations;


•	Expected in-service dates for capital projects;


•	Financial condition and liquidity;


•	Business strategy;


•	Cash flow from operations or results of operations;


•	Seasonality of certain business components;


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


•	Demand for our services.

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


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


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


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


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


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


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


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


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


•	Our ability to successfully expand our facilities and operations;


•	Development and rate of adoption of alternative energy sources;


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

•

The impact of existing and future laws (including, but not limited to, the Tax Cuts and Job Acts of 2017), regulations (including, but not limited to, the FERC’s “Revised Policy Statement on Treatment of Income Taxes” in Docket No. PL17-1-000), the regulatory environment, environmental liabilities, and litigation, as well as our ability to obtain necessary permits and approvals, and achieve favorable rate proceeding outcomes;


•	Our costs for defined benefit pension plans and other postretirement benefit plans sponsored by our affiliates;


•	Changes in maintenance and construction costs;


•	Changes in the current geopolitical situation;


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


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


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


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


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


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

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

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

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

Because forward-looking statements involve risks and uncertainties, we caution that there are important factors, in addition to those listed above, that may cause actual results to differ materially from those contained in the forward-looking statements. For a detailed discussion of those factors, see Part I, Item 1A. Risk Factors in our Annual Report on Form 10-K filed with the SEC on February 22, 2018, and in Part II, Item 1A. Risk Factors in this Quarterly Report on Form 10-Q.

DEFINITIONS

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

Measurements:

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

Bcf : One billion cubic feet of natural gas

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

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

Fahrenheit

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

Mbbls/d: One thousand barrels per day

Mdth/d: One thousand dekatherms per day

MMcf/d: One million cubic feet per day

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

MMdth/d: One million dekatherms per day

Tbtu: One trillion British thermal units

Consolidated Entities:

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

Constitution: Constitution Pipeline Company, LLC

Gulfstar One: Gulfstar One LLC

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

Northwest Pipeline: Northwest Pipeline LLC

Transco: Transcontinental Gas Pipe Line Company, LLC

Partially Owned Entities: Entities in which we do not own a 100 percent ownership interest and which, as of March 31, 2018, we account for as an equity-method investment, including principally the following:

Aux Sable: Aux Sable Liquid Products LP

Caiman II: Caiman Energy II, LLC

Discovery: Discovery Producer Services LLC

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

Laurel Mountain: Laurel Mountain Midstream, LLC

OPPL: Overland Pass Pipeline Company LLC

UEOM: Utica East Ohio Midstream LLC

Government and Regulatory:

EPA: Environmental Protection Agency

FERC: Federal Energy Regulatory Commission

SEC: Securities and Exchange Commission

Other:

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

GAAP: U.S. generally accepted accounting principles

IDR: Incentive distribution right

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

MVC: Minimum volume commitment

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

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

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

Throughput: The volume of product transported or passing through a pipeline, plant, terminal, or other facility

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

PART I – FINANCIAL INFORMATION

Williams Partners L.P.

Consolidated Statement of Comprehensive Income

(Unaudited)



	Three Months Ended March 31,
	2018			2017
	(Millions, except per-unit amounts)
Revenues:
Service revenues	$	1,346		$	1,256
Service revenues – commodity consideration (Note 2)	101			—
Product sales	636			727
Total revenues	2,083			1,983
Costs and expenses:
Product costs	613			579
Processing commodity expenses (Note 2)	35			—
Operating and maintenance expenses	351			361
Depreciation and amortization expenses	423			433
Selling, general, and administrative expenses	138			156
Other (income) expense – net	31			4
Total costs and expenses	1,591			1,533
Operating income (loss)	492			450
Equity earnings (losses)	82			107
Other investing income (loss) – net (Note 4)	4			271
Interest incurred	(218		)	(221		)
Interest capitalized	9			7
Other income (expense) – net	15			49
Income (loss) before income taxes	384			663
Provision (benefit) for income taxes	—			3
Net income (loss)	384			660
Less: Net income (loss) attributable to noncontrolling interests	24			26
Net income (loss) attributable to controlling interests	$	360		$	634
Allocation of net income (loss) for calculation of earnings per common unit:
Net income (loss) attributable to controlling interests	$	360		$	634
Allocation of net income (loss) to Class B units	7			11
Allocation of net income (loss) to common units	$	353		$	623
Basic earnings (loss) per common unit:
Net income (loss) per common unit	$	.37		$	.68
Weighted-average number of common units outstanding (thousands)	957,279			919,944
Diluted earnings (loss) per common unit:
Net income (loss) per common unit	$	.37		$	.68
Weighted-average number of common units outstanding (thousands)	957,336			920,250
Cash distributions per common unit	$	.614		$	.600

Other comprehensive income (loss):
Cash flow hedging activities:
Net unrealized gain (loss) from derivative instruments	$	2		$	4
Reclassifications into earnings of net derivative instruments (gain) loss	—			(1		)
Other comprehensive income (loss)	2			3
Comprehensive income (loss)	386			663
Less: Comprehensive income attributable to noncontrolling interests	24			26
Comprehensive income (loss) attributable to controlling interests	$	362		$	637

See accompanying notes.

Williams Partners L.P.

Consolidated Balance Sheet

(Unaudited)



	March 31, 2018			December 31, 2017
	(Dollars in millions)
ASSETS
Current assets:
Cash and cash equivalents	$	1,268		$	881
Trade accounts and other receivables (net of allowance of $10 at March 31, 2018 and $9 at December 31, 2017)	718			972
Inventories	160			113
Other current assets and deferred charges	198			176
Total current assets	2,344			2,142
Investments	6,513			6,552
Property, plant, and equipment	39,876			38,931
Accumulated depreciation and amortization	(11,329		)	(11,019		)
Property, plant, and equipment – net	28,547			27,912
Intangible assets – net of accumulated amortization	8,643			8,790
Regulatory assets, deferred charges, and other	528			507
Total assets	$	46,575		$	45,903
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable:
Trade	$	755		$	957
Affiliate	58			134
Accrued interest	163			214
Other accrued liabilities	519			643
Long-term debt due within one year	501			501
Total current liabilities	1,996			2,449
Long-term debt	17,011			15,996
Asset retirement obligations	987			944
Deferred income tax liabilities	15			16
Regulatory liabilities, deferred income, and other	3,221			2,809
Contingent liabilities (Note 9)
Equity:
Partners’ equity:
Common units (957,529,465 and 956,952,542 units outstanding at March 31, 2018 and December 31, 2017, respectively)	20,906			21,251
Class B units (18,124,096 and 17,853,088 units outstanding at March 31, 2018 and December 31, 2017, respectively)	788			784
Accumulated other comprehensive income (loss)	(3		)	(5		)
Total partners’ equity	21,691			22,030
Noncontrolling interests in consolidated subsidiaries	1,654			1,659
Total equity	23,345			23,689
Total liabilities and equity	$	46,575		$	45,903

See accompanying notes.

Williams Partners L.P.

Consolidated Statement of Changes in Equity

(Unaudited)



	Williams Partners L.P.
	Common Units			Class B Units			Accumulated Other Comprehensive Income (Loss)			Total Partners’ Equity			Noncontrolling Interests			Total Equity
	(Millions)
Balance – December 31, 2017	$	21,251		$	784		$	(5	)	$	22,030		$	1,659		$	23,689
Adoption of ASC 606 (Note 1)	(148		)	(3		)	—			(151		)	3			(148		)
Net income (loss)	353			7			—			360			24			384
Other comprehensive income (loss)	—			—			2			2			—			2
Distributions to partners	(574		)	—			—			(574		)	—			(574		)
Sales of common units (Note 7)	22			—			—			22			—			22
Distributions to noncontrolling interests	—			—			—			—			(35		)	(35		)
Contributions from noncontrolling interests	—			—			—			—			3			3
Contributions from (distributions to) The Williams Companies, Inc. – net	2			—			—			2			—			2
Net increase (decrease) in equity	(345		)	4			2			(339		)	(5		)	(344		)
Balance – March 31, 2018	$	20,906		$	788		$	(3	)	$	21,691		$	1,654		$	23,345

See accompanying notes.

Williams Partners L.P.

Consolidated Statement of Cash Flows

(Unaudited)



	Three Months Ended March 31,
	2018			2017
	(Millions)
OPERATING ACTIVITIES:
Net income (loss)	$	384		$	660
Adjustments to reconcile to net cash provided (used) by operating activities:
Depreciation and amortization	423			433
Provision (benefit) for deferred income taxes	(1		)	(1		)
Equity (earnings) losses	(82		)	(107		)
Distributions from unconsolidated affiliates	140			190
Net (gain) loss on disposition of equity-method investments	—			(269		)
Amortization of stock-based awards	—			2
Cash provided (used) by changes in current assets and liabilities:
Accounts and notes receivable	258			22
Inventories	(40		)	(30		)
Other current assets and deferred charges	(12		)	19
Accounts payable	(197		)	38
Accrued liabilities	(58		)	(28		)
Affiliate accounts receivable and payable – net	(76		)	(32		)
Other, including changes in noncurrent assets and liabilities	13			(45		)
Net cash provided (used) by operating activities	752			852
FINANCING ACTIVITIES:
Proceeds from (payments of) commercial paper – net	—			(93		)
Proceeds from long-term debt	1,808			—
Payments of long-term debt	(750		)	(1,350		)
Proceeds from sales of common units	—			2,178
Distributions paid	(552		)	(796		)
Distributions to noncontrolling interests	(35		)	(43		)
Contributions from noncontrolling interests	3			4
Contributions from (distributions to) The Williams Companies, Inc. – net	2			(11		)
Payments for debt issuance costs	(18		)	—
Other – net	(34		)	(23		)
Net cash provided (used) by financing activities	424			(134		)
INVESTING ACTIVITIES:
Property, plant, and equipment:
Capital expenditures (1)	(948		)	(509		)
Dispositions – net	(1		)	(2		)
Contributions in aid of construction	190			131
Proceeds from dispositions of equity-method investments	—			200
Purchases of and contributions to equity-method investments	(21		)	(52		)
Other – net	(9		)	(6		)
Net cash provided (used) by investing activities	(789		)	(238		)
Increase (decrease) in cash and cash equivalents	387			480
Cash and cash equivalents at beginning of year	881			145
Cash and cash equivalents at end of period	$	1,268		$	625
_________
(1) Increases to property, plant, and equipment	$	(925	)	$	(569	)
Changes in related accounts payable and accrued liabilities	(23		)	60
Capital expenditures	$	(948	)	$	(509	)

See accompanying notes.

Williams Partners L.P.

Notes to Consolidated Financial Statements

(Unaudited)

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

General

Our accompanying interim consolidated financial statements do not include all the notes in our annual financial statements and, therefore, should be read in conjunction with the consolidated financial statements and notes thereto for the year ended December 31, 2017, 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. (WPZ) and its subsidiaries. Unless the context clearly indicates otherwise, references to “we,” “our,” and “us” include the operations in which we own interests accounted for as equity-method investments that are not consolidated in our financial statements. When we refer to our equity investees by name, we are referring exclusively to their businesses and operations.

We are a Delaware limited partnership whose common units are listed and traded on the New York Stock Exchange. WPZ GP LLC, a Delaware limited liability company wholly owned by The Williams Companies, Inc. (Williams), serves as our general partner. As of March 31, 2018, Williams owns a 74 percent limited partner interest in us. Our operations are located in the United States.

Financial Repositioning

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

Description of Business

Consistent with the manner in which our chief operating decision maker evaluates performance and allocates resources, our operations are organized into the following reportable segments: Northeast G&P, Atlantic-Gulf, West, and NGL & Petchem Services. Certain other corporate activities are included in Other.

Northeast G&P is comprised of our midstream gathering and processing businesses in the Marcellus Shale region primarily in Pennsylvania, New York, and West Virginia and the Utica Shale region of eastern Ohio, as well as a 66 percent interest in Cardinal Gas Services, L.L.C. (Cardinal) (a consolidated entity), a 62 percent equity-method investment in Utica East Ohio Midstream, LLC, a 69 percent equity-method investment in Laurel Mountain Midstream, LLC, a 58 percent equity-method investment in Caiman Energy II, LLC, and Appalachia Midstream Services, LLC, which owns equity-method investments with an approximate average 66 percent interest in multiple 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

Notes (Continued)

assets in the Gulf Coast region, including a 51 percent interest in Gulfstar One LLC (Gulfstar One) (a consolidated entity), which is a proprietary floating production system, and various petrochemical and feedstock pipelines in the Gulf Coast region, as well as a 50 percent equity-method investment in Gulfstream Natural Gas System, L.L.C., a 41 percent interest in Constitution Pipeline Company, LLC (Constitution) (a consolidated entity), which is developing a pipeline project (see Note 3 – Variable Interest Entities), and a 60 percent equity-method investment in Discovery Producer Services LLC.

West is comprised of our interstate natural gas pipeline, Northwest Pipeline LLC (Northwest Pipeline), and our gathering, processing, and treating operations in New Mexico, Colorado, and Wyoming, as well as the Barnett Shale region of north-central Texas, the Eagle Ford Shale region of south Texas, the Haynesville Shale region of northwest Louisiana, and the Mid-Continent region which includes the Anadarko, Arkoma, Delaware, and Permian basins. This segment also includes our natural gas liquid (NGL) and natural gas marketing business, storage facilities, an undivided 50 percent interest in an NGL fractionator near Conway, Kansas, and a 50 percent equity-method investment in Overland Pass Pipeline, LLC, as well as our previously owned 50 percent equity-method investment in the Delaware basin gas gathering system (DBJV) in the Mid-Continent region (see Note 4 – Investing Activities).

NGL & Petchem Services is comprised of previously owned operations, including an 88.5 percent undivided interest in an olefins production facility in Geismar, Louisiana, which was sold in July 2017, and a refinery grade propylene splitter in the Gulf region, which was sold in June 2017.

Basis of Presentation

Significant risks and uncertainties

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

On March 15, 2018, the Federal Energy Regulatory Commission (FERC) issued a policy statement regarding the recovery of income tax costs in rates of natural gas pipelines. The FERC found that an impermissible double recovery results from granting a Master Limited Partnership (MLP) pipeline both an income tax allowance and a return on equity pursuant to the discounted cash flow methodology. The FERC will no longer permit an MLP pipeline to recover an income tax allowance in its cost of service. The FERC further stated it will address the application of this policy to non-MLP partnership forms as those issues arise in subsequent proceedings. The FERC also issued a Notice of Proposed Rulemaking proposing a process that will allow it to determine which natural gas pipelines may be collecting unjust and unreasonable rates in light of the recent reduction in the corporate income tax rate in the Tax Cuts and Jobs Act (Tax Reform) and this policy statement. Furthermore, the FERC issued a Notice of Inquiry seeking comments on the additional impacts of Tax Reform on jurisdictional rates, particularly whether, and if so how, the FERC should address changes relating to accumulated deferred income tax amounts after the corporate income tax rate reduction and bonus depreciation rules, as well as whether other features of Tax Reform require FERC action. We are evaluating the impact of these developments on our interstate natural gas pipelines and currently expect any associated impacts would be prospective and determined through subsequent rate proceedings. We also continue to monitor developments that may impact our regulatory liabilities resulting from Tax Reform. It is reasonably possible that future tariff-based rates collected by our interstate natural gas pipelines may be adversely impacted.

Accounting standards issued and adopted

Effective January 1, 2018, we adopted Accounting Standards Update (ASU) 2017-12 “Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities” (ASU 2017-12). ASU 2017-12 applies to entities that elect hedge accounting in accordance with Accounting Standards Codification (ASC) 815. The ASU affects both the designation and measurement guidance for hedging relationships and the presentation of hedging results. ASU 2017-12 was applied using a modified retrospective approach for cash flow and net investment hedges existing at the date of adoption and prospectively for the presentation and disclosure guidance. The adoption of ASU 2017-12 did not have a significant impact on our consolidated financial statements.

Notes (Continued)

Effective January 1, 2018, we adopted ASU 2016-15 “Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments” (ASU 2016-15). Among other things, ASU 2016-15 permits an accounting policy election to classify distributions received from equity-method investees using either the cumulative earnings approach or the nature of distribution approach. We have elected to apply the nature of distribution approach and have retrospectively conformed the prior year presentation within the Consolidated Statement of Cash Flows in accordance with ASU 2016-15. For the period ended March 31, 2017, amounts previously presented as Distributions from unconsolidated affiliates in excess of cumulative earnings within Investing Activities are now presented as part of Distributions from unconsolidated affiliates within Operating Activities, resulting in an increase to Net cash provided (used) by operating activities of $121 million with a corresponding reduction in Net cash provided (used) by investing activities.

In May 2014, the Financial Accounting Standards Board (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 became effective for interim and annual reporting periods beginning after December 15, 2017.

We adopted the provisions of ASC 606 effective January 1, 2018, utilizing the modified retrospective transition method for all contracts with customers, which included applying the provisions of ASC 606 beginning January 1, 2018, to all contracts not completed as of that date with the cumulative effect of applying the standard for periods prior to January 1, 2018, as an adjustment to Total equity upon adoption. As a result of our adoption, the cumulative impact to our Total equity at January 1, 2018, was a decrease of $148 million in the Consolidated Balance Sheet.

For each revenue contract type, we conducted a formal contract review process to evaluate the impact of ASC 606. The adjustment to Total equity upon adoption of ASC 606 is primarily comprised of the impact to the timing of recognition of deferred revenue (contract liabilities) associated with certain contracts which underwent modifications in periods prior to January 1, 2018. Under the provisions of ASC 606, when a contract modification does not increase both the scope and price of the contract, and the remaining goods and services are distinct from the goods and services transferred prior to the modification, the modification is treated as a termination of the existing contract and the creation of a new contract. ASC 606 requires that the transaction price, including any remaining contract liabilities from the old contract, be allocated to the performance obligations over the term of the new contract. The contract modification adjustments are partially offset by the impact of changes to the timing of recognizing revenue which is subject to the constraint on estimates of variable consideration of certain contracts. The constraint of variable consideration will result in the acceleration of revenue recognition and corresponding de-recognition of contract liabilities for certain contracts (as compared to the previous revenue recognition model) as a result of our assessment that it is probable such recognition would not result in a significant revenue reversal in the future. Additionally, under ASC 606, our revenues will increase in situations where we receive noncash consideration, which exists primarily in certain of our gas processing contracts where we receive commodities as full or partial consideration for services provided. This increase in revenues will be offset by a similar increase in costs and expenses when the commodities received are subsequently sold. Financial systems and internal controls necessary for adoption were implemented effective January 1, 2018. (See Note 2 – Revenue Recognition.)

Accounting standards issued but not yet adopted

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

Notes (Continued)

In February 2016, the FASB issued ASU 2016-02 “Leases (Topic 842)” (ASU 2016-02). ASU 2016-02 establishes a comprehensive new lease accounting model. ASU 2016-02 modifies the definition of a lease, requires a dual approach to lease classification similar to current lease accounting, and causes lessees to recognize operating leases on the balance sheet as a lease liability measured as the present value of the future lease payments with a corresponding right-of-use asset, with an exception for leases with a term of one year or less. Additional disclosures will also be required regarding the amount, timing, and uncertainty of cash flows arising from leases. In January 2018, the FASB issued ASU 2018-01 “Leases (Topic 842): Land Easement Practical Expedient for Transition to Topic 842” (ASU 2018-01). Per ASU 2018-01, land easements and rights-of-way are required to be assessed under ASU 2016-02 to determine whether the arrangements are or contain a lease. ASU 2018-01 permits an entity to elect a transition practical expedient to not apply ASU 2016-02 to land easements that exist or expired before the effective date of ASU 2016-02 and that were not previously assessed under the previous lease guidance in ASC Topic 840 “Leases.” ASU 2016-02 is effective for interim and annual periods beginning after December 15, 2018. Early adoption is permitted. We expect to adopt ASU 2016-02 effective January 1, 2019. ASU 2016-02 currently requires a modified retrospective transition for financing or operating leases existing at or entered into after the beginning of the earliest comparative period presented in the financial statements.

In January 2018, the FASB proposed an ASU titled “Leases (Topic 842): Targeted Improvements,” which is an update to ASU 2016-02 allowing entities an additional transition method to the existing requirements whereby an entity could adopt the provisions of ASU 2016-02 by recognizing a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption without adjustment to the financial statements for periods prior to adoption.

We are in the process of reviewing contracts to identify leases based on the modified definition of a lease, implementing a financial lease accounting system, and evaluating internal control changes to support management in the accounting for and disclosure of leasing activities. While we are still in the process of completing our implementation evaluation of ASU 2016-02, we currently believe the most significant changes to our financial statements relate to the recognition of a lease liability and offsetting right-of-use asset in our consolidated balance sheet for operating leases. We are also evaluating ASU 2016-02’s currently available and proposed practical expedients on adoption.

Note 2 – Revenue Recognition

Customers in our gas pipeline businesses are comprised of public utilities, municipalities, gas marketers and producers, intrastate pipelines, direct industrial users, and electrical generators. Customers in our midstream businesses are comprised of oil and natural gas producer counterparties. Customers for our product sales are comprised of public utilities, gas marketers, and direct industrial users.

A performance obligation is a promise in a contract to transfer a distinct good or service (or integrated package of goods or services) to the customer. A contract’s transaction price is allocated to each distinct performance obligation and recognized as revenue, when, or as, the performance obligation is satisfied. A performance obligation is distinct if the service is separately identifiable from other items in the integrated package of services and if a customer can benefit from it on its own or with other resources that are readily available to the customer. An integrated package of services typically represents a single performance obligation if the services are contained within the same contract or within multiple contracts entered into in contemplation with one another that are highly interdependent or highly interrelated, meaning each of the services is significantly affected by one or more of the other services in the contract. Service revenue contracts related to our gas pipeline and midstream businesses contain a series of distinct services, with the majority of our contracts having a single performance obligation that is satisfied over time as the customer simultaneously receives and consumes the benefits provided by our performance. Most of our product sales contracts have a single performance obligation with revenue recognized at a point in time when the products have been sold and delivered to the customer.

Certain customers reimburse us for costs we incur associated with construction of property, plant, and equipment utilized in our operations. For our rate-regulated gas pipeline businesses that apply ASC 980. "Regulated Operations" (Topic 980), we follow FERC guidelines with respect to reimbursement of construction costs. FERC tariffs only allow for cost reimbursement and are non-negotiable in nature; thus, the construction activities do not represent an ongoing major and central operation of our gas pipelines business and are not within the scope of ASC 606. Accordingly, cost reimbursements are treated as a reduction to the cost of the constructed asset. For our midstream businesses, reimbursement and service contracts with customers are viewed together as providing the same commercial

Notes (Continued)

objective, as we have the ability to negotiate the mix of consideration between reimbursements and amounts billed over time. Accordingly, we generally recognize reimbursements of construction costs from customers on a gross basis as a contract liability separate from the associated costs included within property, plant, and equipment. The contract liability is recognized into service revenues as the underlying performance obligations are satisfied.

Service Revenues

Gas pipeline businesses

Revenues from our interstate natural gas pipeline businesses, which are included within the caption “Regulated interstate natural gas transportation and storage” in the revenue by category table below and are subject to regulation by certain state and federal authorities, including the FERC, include both firm and interruptible transportation and storage contracts. Firm transportation and storage agreements provide for a reservation charge based on the pipeline or storage capacity reserved, and a commodity charge based on the volume of natural gas delivered/stored, each at rates specified in our FERC tariffs or based on negotiated contractual rates, with contract terms that are generally long-term in nature. Most of our long-term contracts contain an evergreen provision, which allows the contracts to be extended for periods primarily up to one year in length an indefinite number of times following the specified contract term and until terminated generally by either us or the customer. Interruptible transportation and storage agreements provide for a volumetric charge based on actual commodity transportation or storage utilized in the period in which those services are provided, and the contracts are generally limited to one month periods or less. Our performance obligations related to our interstate natural gas pipeline businesses include the following:


•	Guaranteed transportation or storage under firm transportation and storage contracts—an integrated package of services typically constituting a single performance obligation, which includes standing ready to provide such services and receiving, transporting or storing (as applicable), and redelivering commodities;


•	Interruptible transportation and storage under interruptible transportation and storage contracts—an integrated package of services typically constituting a single performance obligation, which includes receiving, transporting or storing (as applicable), and redelivering commodities upon nomination by the customer.

In situations where we consider an integrated package of services a single performance obligation, which represents a majority of our interstate natural gas pipeline contracts with customers, we do not consider there to be multiple performance obligations because the nature of the overall promise in the contract is to stand ready (with regard to firm transportation and storage contracts), receive, transport or store, and redeliver natural gas to the customer; therefore, revenue is recognized at the completion of the integrated package of services and represents a single performance obligation.

We recognize revenues for reservation charges over the performance obligation period, which is the contract term, regardless of the volume of natural gas that is transported or stored. Revenues for commodity charges from both firm and interruptible transportation services and storage services are recognized when natural gas is delivered at the agreed upon delivery point or when natural gas is injected or withdrawn from the storage facility because they specifically relate to our efforts to transfer these distinct services. Generally, reservation charges and commodity charges in our interstate natural gas pipeline businesses are recognized as revenue in the same period they are invoiced to our customers. As a result of the ratemaking process, certain amounts collected by us may be subject to refunds upon the issuance of final orders by the FERC in pending rate proceedings. We record estimates of rate refund liabilities considering our and other third-party regulatory proceedings, advice of counsel, and other risks.

Midstream businesses

Revenues from our midstream businesses, which are included in the caption titled “Non-regulated gathering, processing, transportation, and storage” in the revenue by category table below, include contracts for natural gas gathering, processing, treating, compression, transportation, and other related services with contract terms that are generally long-term in nature and may extend up to the production life of the associated reservoir. Additionally, our midstream businesses generate revenues from fees charged for storing customers’ NGLs, generally under prepaid contracted storage capacity contracts. In situations where we provide an integrated package of services combined into

Notes (Continued)

a single performance obligation, which represents a majority of this class of contracts with customers, we do not consider there to be multiple performance obligations because the nature of the overall promise in the contract is to provide gathering, processing, transportation, storage, and related services resulting in the delivery, or redelivery in the context of storage services, of pipeline-quality natural gas and NGLs to the customer. As such, revenue is recognized at the daily completion of the integrated package of services as the integrated package represents a single performance obligation. Additionally, certain contracts in our midstream businesses contain fixed or upfront payment terms that result in the deferral of revenues until such services have been performed or such capacity has been made available.

We also earn revenues from offshore crude oil and natural gas gathering and transportation and offshore production handling. These services represent an integrated package of services and are considered a single distinct performance obligation for which we recognize revenues as the services are provided to the customer.

We generally earn a contractually-stated fee per unit for the volume of product transported, gathered, processed, or stored. The rate is generally fixed; however, certain contracts contain variable rates that are subject to change based on commodity prices, levels of throughput, or an annual adjustment based on a formulaic cost of service calculation. In addition, we have contracts with contractually-stated fees that decline over the contract term, such as declines based on the passage of time periods or achievement of cumulative throughput amounts. For all of our contracts, we allocate the transaction price to each performance obligation based on the relative standalone selling price. The excess of consideration received over revenue recognized results in the deferral of those amounts until future periods based on a units of production or straight-line methodology. Certain of our gas gathering and processing agreements have minimum volume commitments (MVC). If a customer under such an agreement fails to meet its MVC for a specified period (thus not exercising all the contractual rights to gathering and processing services within the specified period, herein referred to as “breakage”), it is obligated to pay a contractually determined fee based upon the shortfall between the actual gathered or processed volumes and the MVC for the period contained in the contract. When we conclude it is probable that the customer will not exercise all or a portion of its remaining rights, we recognize revenue associated with such breakage amount in proportion to the pattern of exercised rights within the respective MVC period.

Under keep-whole and percent-of-liquids processing contracts, we receive commodity consideration in the form of NGLs and take title to the NGLs at the tailgate of the plant. We recognize such commodity consideration as service revenue based on the market value of the NGLs retained at the time the processing is provided. The current market value, as opposed to the market value at the contract inception date, is used due to a combination of factors, including the fact that the volume, mix, and market price of NGL consideration to be received is unknown at the time of contract execution and is not specified in our contracts with customers. Additionally, product sales revenue (discussed below) is recognized upon the sale of the NGLs to a third party based on the sales price at the time of sale. As a result, revenue is recognized both at the time the processing service is provided in Service revenues – commodity consideration and at the time the NGLs retained as part of the processing service are sold in Product sales. The recognition of revenue related to commodity consideration has the impact of increasing the book value of NGL inventory, resulting in higher cost of goods sold at the time of sale. Given that most inventory is sold in the same period that it is generated, the impact of these transactions is expected to have little impact to operating income.

Product Sales

In the course of providing transportation services to customers of our gas pipeline businesses and gathering and processing services to customers of our midstream businesses, we may receive different quantities of natural gas from customers than the quantities delivered on behalf of those customers. The resulting imbalances are primarily settled through the purchase or sale of natural gas with each customer under terms provided for in our FERC tariffs or gathering and processing agreements, respectively. Revenue is recognized from the sale of natural gas upon settlement of imbalances.

In certain instances, we purchase NGLs, crude oil, and natural gas from our oil and natural gas producer customers. In addition, we retain NGLs as consideration in certain processing arrangements, as discussed above in the Service Revenues - Midstream businesses section. We recognize revenue from the sale of these commodities when the products have been sold and delivered. Our product sales contracts are primarily short-term contracts based on prevailing market rates at the time of the transaction.

Notes (Continued)

Revenue by Category

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



	Northeast Midstream		Atlantic- Gulf Midstream		West Midstream		Transco		Northwest Pipeline		Intercompany Eliminations			Total
	(Millions)
Three Months Ended March 31, 2018
Revenues from contracts with customers:
Service revenues:
Non-regulated gathering, processing, transportation, and storage:
Monetary consideration	$	202	$	137	$	408	$	—	$	—	$	(18	)	$	729
Commodity consideration	4		15		82		—		—		—			101
Regulated interstate natural gas transportation and storage	—		—		—		461		112		(1		)	572
Other	21		6		11		—		—		(3		)	35
Total service revenues	227		158		501		461		112		(22		)	1,437
Product Sales:
NGL and natural gas	98		68		521		25		—		(85		)	627
Other	—		—		4		—		—		—			4
Total product sales	98		68		525		25		—		(85		)	631
Total revenues from contracts with customers	325		226		1,026		486		112		(107		)	2,068
Other revenues (1)	5		2		5		3		—		—			15
Total revenues	$	330	$	228	$	1,031	$	489	$	112	$	(107	)	$	2,083

(1)

We provide management services to operated joint ventures and other investments for which we receive a management fee that is categorized as Service revenues in our Consolidated Statement of Comprehensive Income. These management fees do not constitute revenue from contracts with customers. Product sales in our Consolidated Statement of Comprehensive Income include amounts associated with our derivative contracts that are not within the scope of ASC 606.

Contract Assets

Our contract assets primarily consist of revenue recognized under contracts containing MVC features whereby management has concluded it is probable there will be a short-fall payment at the end of the current MVC period, which typically follows the calendar year, and that a significant reversal of revenue recognized currently for the future MVC payment will not occur. As a result, our contract assets related to our future MVC payments are generally expected to be collected within the next 12 months and are included within Other current assets and deferred charges in our Consolidated Balance Sheet until such time as the MVC short-fall payments are invoiced to the customer.

The following table presents a reconciliation of the beginning and ending balances of our contract assets for the period ended March 31, 2018:



	2018
	(Millions)
Balance at January 1	$	4
Revenue recognized in excess of cash received	20
Minimum volume commitments invoiced	—
Balance at March 31	$	24

Notes (Continued)

Contract Liabilities

Our contract liabilities consist of advance payments primarily from midstream business customers which include construction reimbursements, prepayments, and other billings for which future services are to be provided under the contract. These amounts are deferred until recognized in revenue when the associated performance obligation has been satisfied, which is primarily based on a units of production methodology over the remaining contractual service periods, and are classified as current or noncurrent according to when such amounts are expected to be recognized. Current and noncurrent contract liabilities are included within Other accrued liabilities and Regulatory liabilities, deferred income, and other, respectively, in our Consolidated Balance Sheet.

Contracts requiring advance payments and the recognition of contract liabilities are evaluated to determine whether the advance payments provide us with a significant financing benefit. This determination is based on the combined effect of the expected length of time between when we transfer the promised good or service to the customer, when the customer pays for those goods or services, and the prevailing interest rates. We have assessed our contracts for significant financing components and determined that one group of contracts entered into in contemplation of one another for certain capital reimbursements contains a significant financing component. As a result, we recognize noncash interest expense based on the effective interest method and revenue (noncash) is recognized when the underlying asset is placed into service utilizing a units of production or straight-line methodology over the life of the corresponding customer contract.

The following table presents a reconciliation of the beginning and ending balances of our contract liabilities for the period ended March 31, 2018:



	2018
	(Millions)
Balance at January 1	$	1,596
Payments received and deferred	92
Recognized in revenue	(114		)
Balance at March 31	$	1,574

The following table presents the amount of the contract liabilities balance as of March 31, 2018, expected to be recognized as revenue in each of the next five years as performance obligations are expected to be satisfied:



	(Millions)
2018 (remainder)	$	251
2019	252
2020	120
2021	100
2022	94
2023	88
Thereafter	669

Remaining Performance Obligations

The following table presents the transaction price allocated to the remaining performance obligations under certain contracts as of March 31, 2018. These primarily include long-term contracts containing MVCs associated with our midstream businesses, fixed payments associated with offshore production handling, and reservation charges on contracted capacity on our gas pipeline firm transportation contracts with customers, as well as storage capacity contracts. Amounts included in the table below for our interstate natural gas pipeline businesses reflect the rates for such services in our current FERC tariffs for the life of the related contracts; however, these rates may change based on future tariffs approved by the FERC and the amount and timing of these changes is not currently known. As a practical expedient permitted by ASC 606, this table excludes variable consideration as well as consideration in contracts that is recognized in revenue as billed. It also excludes consideration received prior to March 31, 2018, that will be recognized in future periods (see above for Contract Liabilities and the expected recognition of those amounts within

Notes (Continued)

revenue). As noted above, certain of our contracts contain evergreen and other renewal provisions for periods beyond the initial term of the contract. The remaining performance obligation as of March 31, 2018, does not consider potential future performance obligations for which the renewal has not been exercised. The table below also does not include contracts with customers for which the underlying facilities have not received FERC authorization to be placed into service.



	(Millions)
2018 (remainder)	$	1,917
2019	2,399
2020	2,199
2021	1,881
2022	1,749
2023	1,559
Thereafter	11,636
Total	$	23,340

Accounts Receivable

We do not offer extended payment terms and typically receive payment within one month. We consider receivables past due if full payment is not received by the contractual due date. Interest income related to past due accounts receivable is generally recognized at the time full payment is received or collectability is assured.

The following is a summary of our Trade accounts and other receivables as it relates to contracts with customers:



	March 31, 2018
	(Millions)
Accounts receivable related to revenues from contracts with customers	$	701
Other accounts receivable	17
Total reflected in Trade accounts and other receivables	$	718

Impact of Adoption of ASC 606

The following table depicts the impact of the adoption of ASC 606 on our 2018 financial statements. The adjustment to Intangible assets – net of accumulated amortization in the table below relates to the recognition under ASC 606 of contract assets for MVC-related contracts associated with a 2014 acquisition. The recognition of these contract assets resulted in a lower purchase price allocation to intangible assets. The adoption of ASC 606 did not result in adjustments to total operating, investing, or financing cash flows.

Notes (Continued)



	As Reported			Adjustments resulting from adoption of ASC 606			Balance without adoption of ASC 606
	(Millions, except per unit amounts)
Consolidated Statement of Comprehensive Income
Three Months Ended March 31, 2018
Service revenues	$	1,346		$	5		$	1,351
Service revenues - commodity consideration	101			(101		)	—
Product sales	636			10			646
Total revenues	2,083			(86		)	1,997
Product costs	613			(55		)	558
Processing commodity expenses	35			(35		)	—
Operating and maintenance expenses	351			(1		)	350
Depreciation and amortization expenses	423			1			424
Total costs and expenses	1,591			(90		)	1,501
Operating income (loss)	492			4			496
Interest incurred	(218		)	3			(215		)
Interest capitalized	9			(2		)	7
Income (loss) before income taxes	384			5			389
Net income (loss)	384			5			389
Less: Net income (loss) attributable to noncontrolling interests	24			(1		)	23
Net income (loss) attributable to controlling interests	360			6			366
Allocation of net income (loss) to common units	353			6			359
Basic earnings (loss) per common unit	0.37			0.01			0.38
Diluted earnings (loss) per common unit	0.37			0.01			0.38
Comprehensive income (loss)	386			5			391
Less: Comprehensive income attributable to noncontrolling interests	24			(1		)	23
Comprehensive income (loss) attributable to controlling interests	362			6			368

Consolidated Balance Sheet
March 31, 2018
Inventories	$	160		$	(8	)	$	152
Other current assets and deferred charges	198			(20		)	178
Total current assets	2,344			(28		)	2,316
Investments	6,513			(1		)	6,512
Property, plant and equipment	39,876			(2		)	39,874
Property, plant, and equipment – net	28,547			(2		)	28,545
Intangible assets – net of accumulated amortization	8,643			63			8,706
Regulatory assets, deferred charges, and other	528			(4		)	524
Total assets	46,575			28			46,603
Regulatory liabilities, deferred income, and other	3,221			(125		)	3,096
Common and Class B units	21,694			157			21,851
Total partners’ equity	21,691			157			21,848
Noncontrolling interests in consolidated subsidiaries	1,654			(4		)	1,650
Total equity	23,345			153			23,498
Total liabilities and equity	46,575			28			46,603

Consolidated Statement of Changes in Equity
March 31, 2018
Adoption of ASC 606	$	(148	)	$	148		$	—
Net income (loss)	384			5			389
Net increase (decrease) in equity	(344		)	153			(191		)
Balance - March 31, 2018	23,345			153			23,498

Note 3 – Variable Interest Entities

As of March 31, 2018, we consolidate the following variable interest entities (VIEs):

Gulfstar One

We own a 51 percent interest in Gulfstar One, a subsidiary that, due to certain risk-sharing provisions in its customer contracts, is a VIE. Gulfstar One includes a proprietary floating-production system, Gulfstar FPS, and associated pipelines which provide production handling and gathering services in the eastern deepwater Gulf of Mexico. We are

Notes (Continued)

the primary beneficiary because we have the power to direct the activities that most significantly impact Gulfstar One’s economic performance.

Constitution

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

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

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

The project’s sponsors remain committed to the project. In February 2018, we filed a request with the FERC for rehearing of its finding that the NYSDEC did not waive the Section 401 certification requirement. If the FERC denies such request, we will file a petition for review with the D.C. Circuit Court of Appeals. In January 2018, we filed a petition with the United States Supreme Court to review the decision of the Second Circuit Court of Appeals that upheld the merits of the NYSDEC’s denial of the Section 401 certification. However, on April 30, 2018, the Court denied our petition. This decision is separate and independent from (and thus has no impact on) our request for rehearing (or appeal) of the FERC’s decision that the NYSDEC did not waive the Section 401 certification requirement.

Should any court or FERC decision determine that the NYSDEC waived the Section 401 certification requirement, we estimate that the target in-service date for the project would be approximately 10 to 12 months following any such determination. An unfavorable resolution could result in the impairment of a significant portion of the capitalized project costs, which total $379 million on a consolidated basis at March 31, 2018, and are included within Property, plant, and equipment in the Consolidated Balance Sheet. Beginning in April 2016, we discontinued capitalization of development costs related to this project. It is also possible that we could incur certain supplier-related costs in the event of a prolonged delay or termination of the project.

Cardinal

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

Notes (Continued)

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, 2018			December 31, 2017			Classification
	(Millions)
Assets (liabilities):
Cash and cash equivalents	$	54		$	35		Cash and cash equivalents
Accounts receivable	66			76			Trade accounts and other receivables
Prepaid assets	2			2			Other current assets and deferred charges
Property, plant, and equipment – net	2,852			2,887			Property, plant, and equipment – net
Intangible assets – net	1,369			1,381			Intangible assets – net of accumulated amortization
Accounts payable	(15		)	(28		)	Accounts payable – trade
Accrued liabilities	(1		)	(1		)	Other accrued liabilities
Current deferred revenue	(57		)	(57		)	Other accrued liabilities
Noncurrent asset retirement obligations	(105		)	(103		)	Asset retirement obligations
Noncurrent deferred revenue associated with customer advance payments	(293		)	(305		)	Regulatory liabilities, deferred income, and other

Note 4 – Investing Activities

Acquisition of Additional Interests in Appalachia Midstream Investments

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

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

Notes (Continued)

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,
	2018		2017
	(Millions)
West
Gains on contract settlements and terminations	$	—	$	(13	)

Additional Items

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


•	Other income (expense) – net below Operating income (loss) includes income of $20 million and $18 million for the three months ended March 31, 2018 and 2017, respectively, related to allowance for equity funds used during construction within the Atlantic-Gulf segment.

•

Other income (expense) – net below Operating income (loss) for the three months ended March 31, 2018, includes a $7 million net loss associated with the March 28, 2018, early retirement of $750 million of 4.875 percent senior unsecured notes that were due in 2024. The net loss within the Other segment reflects $34 million in premiums paid, partially offset by $27 million of unamortized premium. For the three months ended March 31, 2017, Other income (expense) – net below Operating income (loss) includes a $30 million net gain associated with the February 23, 2017, early retirement of $750 million of 6.125 percent senior unsecured notes that were due in 2022. The net gain within the Other segment reflects $53 million of unamortized premium, partially offset by $23 million in premiums paid. (See Note 6 – Debt and Banking Arrangements.)

Note 6 – Debt and Banking Arrangements

Long-Term Debt

Issuances and retirements

On March 5, 2018, we completed a public offering of $800 million of 4.85 percent senior unsecured notes due 2048. We used the net proceeds for general partnership purposes, primarily the March 28, 2018, repayment of $750 million of 4.875 percent senior unsecured notes that were due in 2024.

On March 15, 2018, Transco issued $400 million of 4.0 percent senior unsecured notes due 2028 and $600 million of 4.6 percent senior unsecured notes due 2048 to investors in a private debt placement. Transco intends to use the net proceeds to retire $250 million of 6.05 percent senior unsecured notes due June 2018, and for general corporate purposes, including the funding of capital expenditures. As part of the 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 a registration default, increasing by an additional 0.25 percent per annum with respect to each subsequent 90-day period thereafter, up to a maximum amount for all such registration defaults of 0.5 percent annually. Following the cure of any registration defaults, the accrual of additional interest will cease.

Notes (Continued)

Other financing obligation

During the first quarter of 2018, Transco received an additional $19 million of funding from a co-owner related to the construction of the Dalton expansion project. This additional funding is reflected as Long-term debt in the Consolidated Balance Sheet.

Commercial Paper Program

As of March 31, 2018, no commercial paper was outstanding under our $3 billion commercial paper program.

Credit Facilities



	March 31, 2018
	Stated Capacity		Outstanding
	(Millions)
Long-term credit facility (1)	$	3,500	$	—
Letters of credit under certain bilateral bank agreements			1


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

Note 7 – Partners’ Capital

Distribution Reinvestment Program

The February 2018 distribution resulted in 576,923 common units issued to the public at a discounted average price of $38.83 per unit associated with the reinvested distributions of $22 million.

Common Units

The Board of Directors of our general partner declared a cash distribution of $0.614 per common unit on April 23, 2018, to be paid on May 11, 2018, to unitholders of record at the close of business on May 4, 2018.

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 318,553 Class B units associated with the first-quarter distribution, to be issued on May 11, 2018.

Notes (Continued)

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, 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, 2018:
Measured on a recurring basis:
ARO Trust investments	$	145		$	145		$	145		$	—		$	—
Energy derivatives assets designated as hedging instruments	2			2			2			—			—
Energy derivatives assets not designated as hedging instruments	4			4			4			—			—
Energy derivatives liabilities designated as hedging instruments	(3		)	(3		)	(3		)	—			—
Energy derivatives liabilities not designated as hedging instruments	(4		)	(4		)	(1		)	—			(3		)
Additional disclosures:
Other receivables	7			7			7			—			—
Long-term debt, including current portion	(17,512		)	(18,307		)	—			(18,307		)	—

Assets (liabilities) at December 31, 2017:
Measured on a recurring basis:
ARO Trust investments	$	135		$	135		$	135		$	—		$	—
Energy derivatives liabilities designated as hedging instruments	(3		)	(3		)	(2		)	(1		)	—
Energy derivatives liabilities not designated as hedging instruments	(3		)	(3		)	—			—			(3		)
Additional disclosures:
Other receivables	7			7			7			—			—
Long-term debt, including current portion	(16,497		)	(18,112		)	—			(18,112		)	—

Fair Value Methods

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

Assets and liabilities measured at fair value on a recurring basis

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

Energy derivatives: Energy derivatives include commodity-based exchange-traded contracts and over-the-counter contracts, which consist of physical forwards, futures, and swaps that are measured at fair value on a recurring basis. The fair value amounts are presented on a gross basis and do not reflect the netting of asset and liability positions permitted under the terms of our master netting arrangements. Further, the amounts do not include cash held on deposit in margin

Notes (Continued)

accounts that we have received or remitted to collateralize certain derivative positions. Energy derivatives assets are reported in Other current assets and deferred charges and Regulatory assets, deferred charges, and other in the Consolidated Balance Sheet. Energy derivatives liabilities are reported in Other accrued liabilities and Regulatory liabilities, deferred income, and other in the Consolidated Balance Sheet.

Reclassifications of fair value between Level 1, Level 2, and Level 3 of the fair value hierarchy, if applicable, are made at the end of each quarter. No transfers between Level 1 and Level 2 occurred during the three months ended March 31, 2018 or 2017.

Additional fair value disclosures

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

Long-term debt, including current portion: The disclosed fair value of our long-term debt is determined primarily by a market approach using broker quoted indicative period-end bond prices. The quoted prices are based on observable transactions in less active markets for our debt or similar instruments.

Guarantees

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

Note 9 – Contingent Liabilities

Environmental Matters

We are a participant in certain environmental activities in various stages including assessment studies, cleanup operations, and/or remedial processes at certain sites, some of which we currently do not own. We are monitoring these sites in a coordinated effort with other potentially responsible parties, the U.S. Environmental Protection Agency (EPA), or other governmental authorities. We are jointly and severally liable along with unrelated third parties in some of these activities and solely responsible in others. Certain of our subsidiaries have been identified as potentially responsible parties at various Superfund and state waste disposal sites. In addition, these subsidiaries have incurred, or are alleged to have incurred, various other hazardous materials removal or remediation obligations under environmental laws. As of March 31, 2018, we have accrued liabilities totaling $17 million for these matters, as discussed below. Estimates of the most likely costs of cleanup are generally based on completed assessment studies, preliminary results of studies, or our experience with other similar cleanup operations. At March 31, 2018, certain assessment studies were still in process for which the ultimate outcome may yield different estimates of most likely costs. Therefore, the actual costs incurred will depend on the final amount, type, and extent of contamination discovered at these sites, the final cleanup standards mandated by the EPA or other governmental authorities, and other factors.

The EPA and various state regulatory agencies routinely promulgate and propose new rules, and issue updated guidance to existing rules. More recent rules and rulemakings include, but are not limited to, rules for reciprocating internal combustion engine maximum achievable control technology, air quality standards for one hour nitrogen dioxide emissions, and volatile organic compound and methane new source performance standards impacting design and operation of storage vessels, pressure valves, and compressors. On October 1, 2015, the EPA issued its rule regarding National Ambient Air Quality Standards for ground-level ozone, setting a stricter standard of 70 parts per billion. We are monitoring the rule’s implementation as the reduction will trigger additional federal and state regulatory actions that may impact our operations. Implementation of the regulations is expected to result in impacts to our operations and increase the cost of additions to Property, plant, and equipment – net in the Consolidated Balance Sheet for both new and existing facilities in affected areas. We are unable to reasonably estimate the cost of additions that may be

Notes (Continued)

required to meet the regulations at this time due to uncertainty created by various legal challenges to these regulations and the need for further specific regulatory guidance.

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, 2018, 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, 2018, we have accrued liabilities totaling $10 million for these costs.

Royalty Matters

Certain of our customers, including one major customer, have been named in various lawsuits alleging underpayment of royalties and claiming, among other things, violations of anti-trust laws and the Racketeer Influenced and Corrupt Organizations Act. We have also been named as a defendant in certain of these cases filed in Pennsylvania based on allegations that we improperly participated with that major customer in causing the alleged royalty underpayments. We believe that the claims asserted are subject to indemnity obligations owed to us by that major customer. Due to the preliminary status of the cases, we are unable to estimate a range of potential loss at this time.

Unitholder Litigation

On March 7, 2016, a purported unitholder of us filed a putative class action on behalf of certain purchasers of our units in U.S. District Court in Oklahoma. The action names as defendants us, Williams, Williams Partners GP LLC, Alan S. Armstrong, and former Chief Financial Officer Donald R. Chappel and alleges violations of certain federal securities laws for failure to disclose Energy Transfer Equity, L.P.’s intention to pursue a purchase of Williams conditioned on Williams not closing the May 2015 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) when announcing the WPZ Public Unit Exchange. The complaint seeks, among other things, damages and an award of costs and attorneys’ fees. The plaintiff filed an amended complaint on August 31, 2016. On October 17, 2016, we requested the court dismiss the action, and on March 8, 2017, the court dismissed the complaint with prejudice. On April 7, 2017, the plaintiff filed a notice of appeal. We cannot reasonably estimate a range of potential loss at this time.

Other

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

Summary

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

Note 10 – Segment Disclosures

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

Notes (Continued)

Performance Measurement

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

We define Modified EBITDA as follows:


•	Net income (loss) before:


◦	Provision (benefit) for income taxes;


◦	Interest incurred, net of interest capitalized;


◦	Equity earnings (losses);


◦	Impairment of equity-method investments;


◦	Other investing income (loss) – net;


◦	Impairment of goodwill;


◦	Depreciation and amortization expenses;


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


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

Notes (Continued)

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



	Northeast G&P		Atlantic- Gulf		West		NGL & Petchem Services		Eliminations			Total
	(Millions)
Three Months Ended March 31, 2018
Segment revenues:
Service revenues
External	$	219	$	596	$	531	$	—	$	—		$	1,346
Internal	9		13		—		—		(22		)	—
Total service revenues	228		609		531		—		(22		)	1,346
Total service revenues – commodity consideration (external only)	4		15		82		—		—			101
Product sales
External	89		35		512		—		—			636
Internal	9		58		18		—		(85		)	—
Total product sales	98		93		530		—		(85		)	636
Total revenues	$	330	$	717	$	1,143	$	—	$	(107	)	$	2,083

Three Months Ended March 31, 2017
Segment revenues:
Service revenues
External	$	208	$	527	$	518	$	3	$	—		$	1,256
Internal	9		9		—		—		(18		)	—
Total service revenues	217		536		518		3		(18		)	1,256
Product sales
External	60		69		405		193		—			727
Internal	8		65		51		6		(130		)	—
Total product sales	68		134		456		199		(130		)	727
Total revenues	$	285	$	670	$	974	$	202	$	(148	)	$	1,983

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,
	2018			2017
	(Millions)
Modified EBITDA by segment:
Northeast G&P	$	250		$	226
Atlantic-Gulf	451			450
West	413			385
NGL & Petchem Services	—			51
Other	(7		)	20
	1,107			1,132
Accretion expense associated with asset retirement obligations for nonregulated operations	(8		)	(6		)
Depreciation and amortization expenses	(423		)	(433		)
Equity earnings (losses)	82			107
Other investing income (loss) – net	4			271
Proportional Modified EBITDA of equity-method investments	(169		)	(194		)
Interest expense	(209		)	(214		)
(Provision) benefit for income taxes	—			(3		)
Net income (loss)	$	384		$	660

Notes (Continued)

The following table reflects Total assets by reportable segment.



	Total Assets
	March 31, 2018			December 31, 2017
	(Millions)
Northeast G&P	$	14,388		$	14,397
Atlantic-Gulf	16,806			15,230
West	15,802			16,144
NGL & Petchem Services	2			3
Other (1)	1,366			936
Eliminations (2)	(1,789		)	(807		)
Total	$	46,575		$	45,903


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


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

Item 2

Management’s Discussion and Analysis of

Financial Condition and Results of Operations

General

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

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

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

Consistent with the manner in which our chief operating decision maker evaluates performance and allocates resources, our reportable segments are Northeast G&P, Atlantic-Gulf, West, and NGL & Petchem Services, which are comprised of the following businesses:

•

Northeast G&P is comprised of our midstream gathering and processing businesses in the Marcellus Shale region primarily in Pennsylvania, New York, and West Virginia and the Utica Shale region of eastern Ohio, as well as a 66 percent interest in Cardinal (a consolidated entity), a 62 percent equity-method investment in UEOM, a 69 percent equity-method investment in Laurel Mountain, a 58 percent equity-method investment in Caiman II, and Appalachia Midstream Services, LLC, which owns equity-method investments with an approximate average 66 percent interest in multiple gas gathering systems in the Marcellus Shale (Appalachia Midstream Investments).

•

Atlantic-Gulf is comprised of our interstate natural gas pipeline, Transco, and significant natural gas gathering and processing and crude oil production handling and transportation assets in the Gulf Coast region, including a 51 percent interest in Gulfstar One (a consolidated entity), which is a proprietary floating production system, and various petrochemical and feedstock pipelines in the Gulf Coast region, as well as a 50 percent equity-method investment in Gulfstream, a 60 percent equity-method investment in Discovery, and a 41 percent interest in Constitution (a consolidated entity), which is developing a pipeline project (see Note 3 – Variable Interest Entities of Notes to Consolidated Financial Statements).

•

West is comprised of our interstate natural gas pipeline, Northwest Pipeline, and our gathering, processing and treating operations in New Mexico, Colorado, and Wyoming, as well as the Barnett Shale region of north-central Texas, the Eagle Ford Shale region of south Texas, the Haynesville Shale region of northwest Louisiana, and the Mid-Continent region which includes the Anadarko, Arkoma, Delaware, and Permian basins. This segment also includes our NGL and natural gas marketing business, storage facilities, an undivided 50 percent interest in an NGL fractionator near Conway, Kansas, and a 50 percent equity-method investment in OPPL, as well as our previously owned 50 percent equity-method investment in the Delaware basin gas gathering system (DBJV) in the Mid-Continent region (see Note 4 – Investing Activities of Notes to Consolidated Financial Statements).

Management’s Discussion and Analysis (Continued)


•	NGL & Petchem Services is comprised of previously owned operations, including an 88.5 percent undivided interest in an olefins production facility in Geismar, Louisiana, which was sold in July 2017, and a refinery grade propylene splitter in the Gulf region, which was sold in June 2017.

Financial Repositioning

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

Distributions

Overview of Three Months Ended March 31, 2018

Net income (loss) attributable to controlling interests for the three months ended March 31, 2018, decreased $274 million compared to the three months ended March 31, 2017, primarily due to the absence of a $269 million gain associated with the disposition of certain equity-method investments in 2017.

Unless indicated otherwise, the following discussion and analysis of results of operations and financial condition and liquidity should be read in conjunction with the consolidated financial statements and notes thereto of this Form 10‑Q and our Annual Report on Form 10‑K dated February 22, 2018.

FERC Income Tax Policy Revision

On March 15, 2018, the FERC issued a policy statement regarding the recovery of income tax costs in rates of natural gas pipelines. The FERC found that an impermissible double recovery results from granting a Master Limited Partnership (MLP) pipeline both an income tax allowance and a return on equity pursuant to the discounted cash flow methodology. The FERC will no longer permit an MLP pipeline to recover an income tax allowance in its cost of service. The FERC further stated it will address the application of this policy to non-MLP partnership forms as those issues arise in subsequent proceedings. The FERC also issued a Notice of Proposed Rulemaking proposing a process that will allow it to determine which natural gas pipelines may be collecting unjust and unreasonable rates in light of the recent reduction in the corporate income tax rate in the Tax Cuts and Jobs Act (Tax Reform) and this policy statement. Furthermore, the FERC issued a Notice of Inquiry seeking comments on the additional impacts of Tax Reform on jurisdictional rates, particularly whether, and if so how, the FERC should address changes relating to accumulated deferred income tax amounts after the corporate income tax rate reduction and bonus depreciation rules, as well as whether other features of Tax Reform require FERC action. We are evaluating the impact of these developments on our interstate natural gas pipelines and currently expect any associated impacts would be prospective and determined through subsequent rate proceedings. We also continue to monitor developments that may impact our regulatory liabilities resulting from Tax Reform. It is reasonably possible that future tariff-based rates collected by our interstate natural gas pipelines may be adversely impacted.

Revenue Recognition

As a result of the adoption of Accounting Standards Update 2014-09, Revenues from Contracts with Customers (ASC 606), we now record revenues for transactions where we receive noncash consideration, primarily in certain of our gas processing contracts that provide commodities as full or partial consideration for services provided. These revenues are reflected as Service revenues – commodity consideration in the Consolidated Statement of Comprehensive Income. The costs associated with these revenues, primarily related to natural gas shrink replacement, are reported as Processing commodity expenses. The revenues and costs associated with the subsequent sale of the commodity

Management’s Discussion and Analysis (Continued)

consideration received is reflected within Product sales and Product costs in the Consolidated Statement of Comprehensive Income. Service revenues – commodity consideration plus Product sales less Product costs and Processing commodity expenses represents the margin that we have historically characterized as commodity margin. This presentation is being reflected prospectively in the Consolidated Statement of Comprehensive Income. (See Note 2 – Revenue Recognition of Notes to Consolidated Financial Statements.)

Additionally, future revenues are impacted by application of the new accounting standard to certain contracts for which we received prepayments for services and have recorded deferred revenue (contract liabilities). For these contracts, which underwent modifications in periods prior to January 1, 2018, the modification is treated as a termination of the existing contract and the creation of a new contract. The new accounting guidance requires that the transaction price, including any remaining deferred revenue from the old contract, be allocated to the performance obligations over the term of the new contract. As a result, we will recognize the deferred revenue over longer periods than application of revenue recognition under accounting guidance prior to January 1, 2018. The application of ASC 606 to prior periods related to these contracts would have resulted in lower revenues in 2017. Annual revenues will also be lower in 2018 and 2019 than what would have been recorded under the previous guidance, offset by increased revenues in later reporting periods given the longer period of recognition.

Expansion Project Updates

Significant expansion project updates for the period, including projects placed into service are described below. Ongoing major expansion projects are discussed later in Company Outlook.

Northeast G&P

Susquehanna Supply Hub

During the first quarter of 2018, the remaining facilities that comprise the Susquehanna Supply Hub Expansion were fully commissioned. The project added two new compression facilities with an additional 49,000 horsepower and 59 miles of 12 to 24 inch pipeline, and is expected to increase gathering capacity, allowing a certain producer to fulfill its commitment to deliver 850 Mdth/d to our Atlantic Sunrise development.

Atlantic-Gulf

Garden State

In March 2018, Phase 2 of the Garden State Expansion project was placed into service. This project expanded 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. Phase 1 of the project was placed into service in September 2017, and together they increased capacity by 180 Mdth/d.

Hillabee

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

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

Management’s Discussion and Analysis (Continued)

rehearing). In compliance with the court's directive, on February 5, 2018, the FERC issued a Final Supplemental EIS for the projects, reaffirming that while the projects would result in temporary and permanent impacts on the environment, those impacts would not be significant. On March 14, 2018, the FERC issued an order on remand reinstating the certificate and abandonment authorizations for the Hillabee Expansion Project and the other Southeast Market Pipelines projects. As this order was issued prior to the court’s mandate (which was issued on March 30, 2018), we experienced no lapse in FERC authorization for the project.

Commodity Prices

NGL per-unit margins were approximately 6 percent higher in the first three months of 2018 compared to the same period of 2017 primarily due to a 19 percent increase in per-unit non-ethane prices and an approximate 21 percent decrease in per-unit natural gas feedstock prices.

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

The potential impact of commodity prices on our business for the remainder of 2018 is further discussed in the following Company Outlook.

Company Outlook

Our strategy is to provide large-scale energy infrastructure designed to maximize the opportunities created by the vast supply of natural gas and natural gas products that exists in the United States. We accomplish this by connecting the growing demand for cleaner fuels and feedstocks with our major positions in the premier natural gas and natural gas products supply basins. We continue to maintain a strong commitment to safety, environmental stewardship, operational excellence, and customer satisfaction. We believe that accomplishing these goals will position us to deliver safe and reliable service to our customers and an attractive return to our unitholders.

Our business plan for 2018 includes a continued focus on growing our fee-based businesses, executing growth projects and accomplishing cost discipline initiatives to ensure operations support our strategy. We anticipate operating results will increase through organic business growth driven primarily by Transco expansion projects and continued growth in the Northeast region. We intend to fund planned growth capital with retained cash flow and debt, and based on currently forecasted projects, we do not expect to access public equity markets for the next several years.

Our growth capital and investment expenditures in 2018 are currently expected to be at least $2.7 billion. Approximately $1.7 billion of our growth capital funding needs include Transco expansions and other interstate pipeline growth projects, most of which are fully contracted with firm transportation agreements. The remaining growth capital spending in 2018 primarily reflects investment in gathering and processing systems in the Northeast G&P segment limited primarily to known new producer volumes, including volumes that support Transco expansion projects including our Atlantic Sunrise project. In addition to growth capital and investment expenditures, we also remain committed to projects that maintain our assets for safe and reliable operations, as well as projects that meet legal, regulatory, and/or contractual commitments.

As a result of our significant continued capital and investment expenditures on Transco expansions and fee-based gathering and processing projects, fee-based businesses are a significant component of our portfolio and serve to reduce the influence of commodity price fluctuations on our operating results and cash flows. We expect to benefit as continued growth in demand for low-cost natural gas is driven by increases in LNG exports, industrial demand and power generation. For 2018, current forward market prices indicate oil prices are expected to be higher compared to 2017 and NGL prices are expected to be slightly higher or comparable with 2017, while natural gas prices are expected to be lower or comparable with 2017. We continue to address certain pricing risks through the utilization of commodity hedging strategies. However, some of our customers may continue to curtail or delay drilling plans until there is a more sustained recovery in prices, which may negatively impact our gathering and processing volumes. The credit profiles

Management’s Discussion and Analysis (Continued)

of certain of our producer customers could be challenged as a result of lower energy commodity prices. Unfavorable changes in energy commodity prices or the credit profile of our producer customers may also result in noncash impairments of our assets.

In 2018, our operating results are expected to include increases from our regulated Transco fee-based business primarily related to projects recently placed in-service or expected to be placed in-service in 2018, including the Atlantic Sunrise project. For our non-regulated businesses, we anticipate increases in fee-based revenue in the Northeast G&P segment, partially offset by lower fee-based revenue in the West segment. As previously discussed, under the new accounting guidance for revenue recognition, deferred revenue under certain contracts will be recognized over longer periods than under the prior guidance, contributing to the decrease in annual revenue for the West segment. We expect overall gathering and processing volumes to grow in 2018 and increase thereafter to meet the growing demand for natural gas and natural gas products. We also anticipate lower general and administrative expenses due to the full year impact of prior year cost reduction initiatives.

In accordance with the timing prescribed by its previous rate case settlement, Transco is required to file a rate case no later than August 31, 2018. If the case is filed on August 31, 2018, Transco expects the FERC to suspend rate increases to be effective March 1, 2019, subject to refund and the outcome of a hearing, and accept rate decreases to be effective October 1, 2018, not subject to refund. The final rates will be subject to a settlement agreement with customers and the FERC or the outcome of a hearing.

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


•	Certain aspects of Tax Reform, including regulatory liabilities relating to reduced corporate federal income tax rates, and the recent FERC income tax policy revision could adversely impact the rates we can charge on our regulated pipelines (see Note 1 – General, Description of Business, and Basis of Presentation of Notes to Consolidated Financial Statements);


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

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

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


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

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

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

•Production issues impacting offshore gathering volumes;


•	Other risks set forth under Part I, Item 1A. Risk Factors in our Annual Report on Form 10-K for the year ended December 31, 2017, as filed with the SEC on February 22, 2018, and in Part II, Item 1A. Risk Factors in this Quarterly Report on Form 10-Q.

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

Management’s Discussion and Analysis (Continued)

Expansion Projects

Our ongoing major expansion projects include the following:

Northeast G&P

Ohio River Supply Hub Expansion

We agreed to expand our services for certain customers to provide additional processing wet gas capacity in the Marcellus and Upper Devonian Shale in West Virginia and Pennsylvania. Associated with these agreements, we plan to further expand the processing capacity of our Oak Grove facility by 400 MMcf/d. Additionally, with one of these customers, we secured a gathering dedication agreement to gather dry gas in this same region. These expansions will be supported by long-term, fee-based agreements and volumetric commitments.

Atlantic-Gulf

Atlantic Sunrise

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

Constitution Pipeline

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

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

Management’s Discussion and Analysis (Continued)

2018, the Court denied our petition. This decision is separate and independent from (and thus has no impact on) our request for rehearing (or appeal) of the FERC’s decision that the NYSDEC did not waive the Section 401 certification requirement.

Gateway

In November 2017, we filed an application with the FERC to expand Transco’s existing natural gas transmission system to provide incremental firm transportation capacity from PennEast Pipeline Company's proposed interconnection with Transco’s mainline south of Station 205 in New Jersey to other existing Transco meter stations within New Jersey. We plan to place the project into service in the first quarter of 2021, assuming timely receipt of all necessary regulatory approvals. The project is expected to increase capacity by 65 Mdth/d.

Gulf Connector

In November 2017, we received approval from the FERC allowing Transco to expand its existing natural gas transmission system to provide incremental firm transportation capacity from Station 65 in Louisiana to delivery points in Wharton and San Patricio Counties, Texas. The project will be constructed in two phases and we plan to place both phases into service during the first half of 2019, assuming timely receipt of all necessary regulatory approvals. The project is expected to increase capacity by 475 Mdth/d.

Hillabee

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

Norphlet Project

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

Northeast Supply Enhancement

In March 2017, we filed an application with the FERC to expand Transco’s existing natural gas transmission system to provide incremental firm transportation capacity from Station 195 in Pennsylvania to the Rockaway Delivery Lateral transfer point in New York. On April 20, 2018, the NYSDEC denied, without prejudice, Transco’s application for certain permits required for the project. We have addressed the technical issues identified by NYSDEC and will refile our application for the permits. We plan to place the project into service in late 2019 or during the first half of 2020, assuming timely receipt of all necessary regulatory approvals. The project is expected to increase capacity by 400 Mdth/d.

Management’s Discussion and Analysis (Continued)

Rivervale South to Market

In August 2017, we filed an application with the FERC to expand Transco’s existing natural gas transmission system to provide incremental firm transportation capacity from the existing Rivervale interconnection with Tennessee Gas Pipeline on Transco’s North New Jersey Extension to other existing Transco locations within New Jersey. We plan to place the project into service as early as the fourth quarter of 2019, assuming timely receipt of all necessary regulatory approvals. The project is expected to increase capacity by 190 Mdth/d.

Southeastern Trail

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

West

North Seattle Lateral Upgrade

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

Critical Accounting Estimates

Constitution Pipeline Capitalized Project Costs

As of March 31, 2018, Property, plant, and equipment in our Consolidated Balance Sheet includes approximately $379 million of capitalized project costs for Constitution, for which we are the construction manager and own a 41 percent consolidated interest. As a result of the events discussed in Company Outlook, we evaluated the capitalized project costs for impairment as recently as December 31, 2017, and determined that no impairment was necessary. Our evaluation considered probability-weighted scenarios of undiscounted future net cash flows, including scenarios assuming construction of the pipeline, as well as a scenario where the project does not proceed. These scenarios included our most recent estimate of total construction costs. The probability-weighted scenarios also considered our assessment of the likelihood of success of the path to obtain necessary certification, as described in Company Outlook. It is reasonably possible that future unfavorable developments, such as a reduced likelihood of success, increased estimates of construction costs, or further significant delays, could result in a future impairment.

Equity-Method Investments

As of March 31, 2018, the carrying value of our equity-method investment in Discovery is $524 million. During the fourth quarter of 2017, certain customers of Discovery terminated a significant offshore gas gathering agreement following the shut-in of production after the associated wells ceased flowing. As a result, we evaluated this investment for impairment in the fourth quarter of 2017 and determined that no impairment was necessary.

This evaluation included probability-weighted assumptions of additional commercial development, assigning higher probabilities to those commercial development opportunities that were more advanced in the discussion and contracting process, that utilized existing infrastructure due to producer capital constraints, and/or that we believe Discovery has a competitive advantage due to geographical proximity to the prospect. We continue to monitor this investment as it is reasonably possible that an impairment could be required in the future if commercial development activities are not as successful or as timely as assumed.

Management’s Discussion and Analysis (Continued)

Regulatory Liabilities Resulting from Tax Reform

In December 2017, Tax Reform was enacted, which, among other things, reduced the corporate income tax rate from 35 percent to 21 percent. Rates charged to customers of our regulated natural gas pipelines are subject to the rate-making policies of the FERC, which have historically permitted the recovery of an income tax allowance that includes a deferred income tax component. As a result of the reduced income tax rate from Tax Reform and the collection of historical rates that reflected historical federal income tax rates, we expect that our regulated natural gas pipelines will be required to return amounts to certain customers through future rates and have accordingly established regulatory liabilities totaling $678 million as of March 31, 2018. The timing and actual amount of such return will be subject to future negotiations regarding this matter and many other elements of cost–of–service rate proceedings, including other costs of providing service.

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, 2018, compared to the three months ended March 31, 2017. The results of operations by segment are discussed in further detail following this consolidated overview discussion.



	Three Months Ended March 31,
	2018			2017			$ Change*	% Change*
	(Millions)
Revenues:
Service revenues	$	1,346		$	1,256		+90	+7	%
Service revenues – commodity consideration	101			—			+101	NM
Product sales	636			727			-91	-13	%
Total revenues	2,083			1,983
Costs and expenses:
Product costs	613			579			-34	-6	%
Processing commodity expenses	35			—			-35	NM
Operating and maintenance expenses	351			361			+10	+3	%
Depreciation and amortization expenses	423			433			+10	+2	%
Selling, general, and administrative expenses	138			156			+18	+12	%
Other (income) expense – net	31			4			-27	NM
Total costs and expenses	1,591			1,533
Operating income (loss)	492			450
Equity earnings (losses)	82			107			-25	-23	%
Other investing income (loss) – net	4			271			-267	-99	%
Interest expense	(209		)	(214		)	+5	+2	%
Other income (expense) – net	15			49			-34	-69	%
Income (loss) before income taxes	384			663
Provision (benefit) for income taxes	—			3			+3	+100	%
Net income (loss)	384			660
Less: Net income attributable to noncontrolling interests	24			26			+2	+8	%
Net income (loss) attributable to controlling interests	$	360		$	634


*	+ = 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, 2018 vs. three months ended March 31, 2017

Service revenues increased primarily due to higher transportation fee revenues at Transco associated with expansion projects placed in-service in 2017 and 2018, as well as higher gathering volumes across certain of our operating locations.

Service revenues – commodity consideration increased as the result of implementing ASC 606 using a modified retrospective approach, effective January 1, 2018. Therefore, prior periods have not been recast under the new guidance. These revenues represent consideration we receive in the form of commodities as full or partial payment for gathering and processing services provided. (See Note 2 – Revenue Recognition of Notes to Consolidated Financial Statements.) Most of these NGL volumes are sold within the month processed and therefore are offset in Product costs below.

Management’s Discussion and Analysis (Continued)

Product sales decreased primarily due to $146 million lower olefin sales associated with the absence of volumes due to the sales of our olefin operations in 2017, partially offset by higher system management gas sales.

The increase in Product costs is primarily due to the impact of ASC 606 in which costs reflected in this line item for 2018 include volumes acquired as commodity consideration for NGL processing services, as well as system management gas costs. This increase is partially offset by the absence of $75 million of olefin feedstock volumes associated with the sales of our olefin operations, as well as the absence of gas purchases associated with the production of equity NGLs, which are now reported in Processing commodity expenses in conjunction with the implementation of ASC 606.

Processing commodity expenses presents the natural gas purchases associated with the production of equity NGLs as previously described in conjunction with the implementation of ASC 606.

Operating and maintenance expenses decreased primarily due to the absence of $23 million of costs associated with our former olefin operations and ongoing cost containment efforts, partially offset by higher operating and maintenance expenses at Transco primarily associated with pipeline integrity, general maintenance, and other testing.

Depreciation and amortization expenses decreased primarily due to the absence of costs associated with our former olefin operations, partially offset by new assets placed in-service.

Selling, general, and administrative expenses decreased primarily due to the absence of severance and other related costs incurred in 2017, the absence of costs associated with our former olefin operations, and ongoing cost containment efforts.

The unfavorable change in Other (income) expense – net within Operating income (loss) includes the absence of gains from certain contract settlements and terminations in 2017 and certain regulatory charges associated with Tax Reform in 2018.

The favorable change in Operating income (loss) includes an increase in Service revenues primarily associated with Transco projects placed in-service in 2017 and 2018, partially offset by the absence of operating income related to our former olefin operations, and higher operating costs at Transco.

The unfavorable change in Equity earnings (losses) is due to a decrease in volumes at Discovery, partially offset by an increase in ownership of our Appalachian Midstream Investments. (See Note 4 – Investing Activities of Notes to Consolidated Financial Statements.)

The unfavorable change in Other investing income (loss) – net is due to the absence of a gain on disposition of our investments in DBJV and Ranch Westex JV LLC in 2017. (See Note 4 – Investing Activities of Notes to Consolidated Financial Statements.)

The unfavorable change in Other income (expense) – net below Operating income (loss) is primarily due to the absence of a net gain on early retirement of debt in 2017 and a loss on early retirement of debt in 2018. (See Note 5 – Other Income and Expenses 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.

Management’s Discussion and Analysis (Continued)

Northeast G&P



	Three Months Ended March 31,
	2018			2017
	(Millions)
Service revenues	$	228		$	217
Service revenues - commodity consideration	4			—
Product sales	98			68
Segment revenues	330			285

Product costs	(99		)	(69		)
Processing commodity expenses	(2		)	—
Other segment costs and expenses	(87		)	(87		)
Proportional Modified EBITDA of equity-method investments	108			97
Northeast G&P Modified EBITDA	$	250		$	226

Three months ended March 31, 2018 vs. three months ended March 31, 2017

Modified EBITDA increased primarily due to higher Service revenues and an increase in Proportional Modified EBITDA of equity-method investments.

Service revenues increased primarily due to a $5 million increase in fractionation revenues at Ohio Valley Midstream.

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

Proportional Modified EBITDA of equity-method investments increased primarily due to a $22 million increase at Appalachian Midstream Investments reflecting our increased ownership acquired in late first-quarter 2017, partially offset by decreases at UEOM and Laurel Mountain Midstream.

Atlantic-Gulf



	Three Months Ended March 31,
	2018			2017
	(Millions)
Service revenues	$	609		$	536
Service revenues - commodity consideration	15			—
Product sales	93			134
Segment revenues	717			670

Product costs	(92		)	(118		)
Processing commodity expenses	(5		)	—
Other segment costs and expenses	(212		)	(174		)
Proportional Modified EBITDA of equity-method investments	43			72
Atlantic-Gulf Modified EBITDA	$	451		$	450

NGL margin	$	10		$	14

Management’s Discussion and Analysis (Continued)

Three months ended March 31, 2018 vs. three months ended March 31, 2017

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

Service revenues increased primarily due to a $64 million increase in Transco’s natural gas transportation fee revenues driven by a $58 million increase associated with expansion projects placed in service in 2017 and 2018.

Service revenues - commodity consideration increased as a result of implementing ASC 606 using a modified retrospective approach. These revenues represent consideration we receive in the form of commodities as full or partial payment for gathering and processing services provided. Most of these NGL volumes are sold within the month processed and therefore are offset in Product costs below.

The decrease in Product sales includes:


•	A $45 million decrease in commodity marketing revenues driven by a $50 million decrease in crude oil revenues as this activity is now presented on a net basis within Product costs in 2018 in conjunction with the adoption of ASC 606, slightly offset by an increase in NGL marketing revenues reflecting 22 percent higher non-ethane prices;


•	An $18 million increase in system management gas sales. System management gas sales are offset in Product costs and therefore have no impact to Modified EBITDA.

Product costs decreased primarily due to a $44 million decrease in marketing purchases (more than offset in Product sales) and the absence of gas purchases associated with the production of equity NGLs, which are now reported in Processing commodity expenses in conjunction with the implementation of ASC 606. This decrease was partially offset by an impact of ASC 606 in which costs reflected in this line item for 2018 include volumes acquired as commodity consideration for NGL processing services, as well as an $18 million increase in system management gas costs (offset in Product sales).

Processing commodity expenses presents the natural gas purchases associated with the production of equity NGLs as previously described in conjunction with the implementation of ASC 606.

The net sum of Service revenues - commodity consideration, Product sales, Product costs, and Processing commodity expenses comprise our commodity product margins, which declined $5 million, primarily due to a $4 million decrease in NGL margins.

Other segment costs and expenses increased primarily due to $14 million higher Transco pipeline integrity testing, general maintenance and other testing, $11 million due to certain regulatory charges resulting from Tax Reform, and higher power and fuel costs.

The decrease in Proportional Modified EBITDA of equity-method investments is due to a $28 million decrease at Discovery, primarily related to a $23 million decrease associated with production ending on certain wells.

Management’s Discussion and Analysis (Continued)

West



	Three Months Ended March 31,
	2018			2017
	(Millions)
Service revenues	$	531		$	518
Service revenues - commodity consideration	82			—
Product sales	530			456
Segment revenues	1,143			974

Product costs	(526		)	(416		)
Processing commodity expenses	(30		)	—
Other segment costs and expenses	(192		)	(198		)
Proportional modified EBITDA of equity-method investments	18			25
West Modified EBITDA	$	413		$	385

NGL margin	$	52		$	37

Three months ended March 31, 2018 vs. three months ended March 31, 2017

Modified EBITDA increased primarily due to higher Service revenues and higher commodity margins.

Service revenues increased primarily due to:


•	A $20 million increase primarily related to higher gathering volumes in the Haynesville Shale region, as well as higher gathering volumes across most other areas;


•	Earlier recognition of revenues associated with MVC’s and other deferred revenue due to implementing the new revenue recognition guidance under ASC 606, offset by a $25 million decrease related to lower amortization of deferred revenue associated with the up-front cash payment received in conjunction with the fourth quarter 2016 Barnett Shale contract restructuring;


•	A $9 million decrease at Northwest Pipeline primarily due to the reduction of its rates as a result of a recent rate case settlement that became effective January 1, 2018.

The increase in Product sales includes:


•	A $32 million increase in marketing revenues primarily due to increases in product prices including a 19 percent increase in average non-ethane per-unit sales prices and a 14 percent increase in ethane prices, partially offset by a 28 percent decrease in natural gas volumes (offset by higher Product costs);


•	A $16 million increase in system management gas sales in accordance with ASC 606, which are offset in Product costs and, therefore, have no impact on Modified EBITDA.

Management’s Discussion and Analysis (Continued)

The increase in Product costs includes the impact of ASC 606 in which costs reflected in this line item for 2018 include volumes acquired as commodity consideration for NGL processing services, as well as a $32 million increase in marketing purchases (offset in Product sales), a $16 million increase in system management gas costs (offset in Product sales), as well as the absence of gas purchases associated with the production of equity NGLs, which are now reported in Processing commodity expenses in conjunction with the implementation of ASC 606.

Processing commodity expenses presents the natural gas purchases associated with the production of equity NGLs as previously described in conjunction with the implementation of ASC 606.

The net sum of Service revenues - commodity consideration, Product sales, Product costs, and Processing commodity expenses comprise our commodity product margins. Our commodity product margins increased primarily due to a $15 million increase in NGL product margins, which is driven by $15 million in higher non-ethane margins, reflecting higher non-ethane prices.

Other segment costs and expenses decreased primarily due to ongoing cost containment efforts and lower operating and maintenance costs, partially offset by the absence of a $13 million gain from contract settlements and terminations.

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

NGL & Petchem Services



	Three Months Ended March 31,
	2018		2017
	(Millions)
NGL & Petchem Services Modified EBITDA	$	—	$	51

Olefins margin	$	—	$	71

Three months ended March 31, 2018 vs. three months ended March 31, 2017

Modified EBITDA changed unfavorably due to the sales of our olefin operations in 2017. As a result, there are no operations within this reporting segment in 2018.

Management’s Discussion and Analysis (Continued)

Management’s Discussion and Analysis of Financial Condition and Liquidity

Outlook

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

As previously discussed in Company Outlook, our growth capital and investment expenditures in 2018 are currently expected to be at least $2.7 billion. Approximately $1.7 billion of our growth capital funding needs include Transco expansions and other interstate pipeline growth projects, most of which are fully contracted with firm transportation agreements. The remaining growth capital spending in 2018 primarily reflects investment in gathering and processing systems in the Northeast G&P segment limited primarily to known new producer volumes, including volumes that support Transco expansion projects including our Atlantic Sunrise project. In addition to growth capital and investment expenditures, we also remain committed to projects that maintain our assets for safe and reliable operations, as well as projects that meet legal, regulatory, and/or contractual commitments. We intend to fund the planned 2018 growth capital with retained cash flow and debt. We retain the flexibility to adjust planned levels of growth capital and investment expenditures in response to changes in economic conditions or business opportunities.

Liquidity

Based on our forecasted levels of cash flow from operations and other sources of liquidity, we expect to have sufficient liquidity to manage our businesses in 2018. Our potential material internal and external sources of liquidity for 2018 are as follows:


•	Cash and cash equivalents on hand;


•	Cash generated from operations;


•	Distributions from our equity-method investees;


•	Cash proceeds from issuance of debt and/or equity securities;


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


•	Proceeds from asset monetizations.

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


•	Working capital requirements;


•	Capital and investment expenditures;


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


•	Quarterly distributions to our unitholders.

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

Management’s Discussion and Analysis (Continued)

As of March 31, 2018, we had a working capital surplus of $348 million. Our available liquidity is as follows:



Available Liquidity	March 31, 2018
	(Millions)
Cash and cash equivalents	$	1,268
Capacity available under our $3.5 billion credit facility, less amounts outstanding under our $3 billion commercial paper program (1)	3,500
	$	4,768

(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, 2018, no amount was outstanding under our commercial paper program and credit facility during 2018. At March 31, 2018, we were in compliance with the financial covenants associated with this credit facility. Borrowing capacity available under our $3.5 billion credit facility as of May 1, 2018, was $3.5 billion.

Registrations

In February 2018, we filed a shelf registration statement, as a well-known seasoned issuer, registering common units representing limited partner interests and debt securities. Also in February 2018, we filed a shelf registration statement for the offer and sale from time to time of common units representing limited partner interests in us having an aggregate offering price of up to $1 billion. These sales are to be made over a period of time and from time to time in transactions at prices which are market prices prevailing at the time of sale, prices related to market price, or at negotiated prices.

In September 2016, we filed a registration statement for our distribution reinvestment program. (See Note 7 – Partners’ Capital of Notes to Consolidated Financial Statements.)

Distributions from Equity-Method Investees

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

Credit Ratings

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



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

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

Cash Distributions to Unitholders

Management’s Discussion and Analysis (Continued)

Sources (Uses) of Cash

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



	Cash Flow	Three Months Ended March 31,
	Category	2018			2017
		(Millions)
Sources of cash and cash equivalents:
Operating activities – net	Operating	$	752		$	852
Proceeds from long-term debt (see Note 6)	Financing	1,808			—
Contributions in aid of construction	Investing	190			131
Proceeds from sales of common units (see Note 1)	Financing	—			2,178
Proceeds from dispositions of equity-method investments (see Note 4)	Investing	—			200

Uses of cash and cash equivalents:
Capital expenditures	Investing	(948		)	(509		)
Payments of long-term debt (see Note 6)	Financing	(750		)	(1,350		)
Distributions paid (1)	Financing	(552		)	(796		)
Distributions to noncontrolling interests	Financing	(35		)	(43		)
Purchases of and contributions to equity-method investments	Investing	(21		)	(52		)
Payments of commercial paper – net	Financing	—			(93		)

Other sources / (uses) – net	Financing and Investing	(57		)	(38		)
Increase (decrease) in cash and cash equivalents		$	387		$	480

____________


(1)	Includes $421 million and $597 million to Williams in 2018 and 2017, respectively.

Operating activities

The factors that determine operating activities are largely the same as those that affect Net income (loss), with the exception of noncash items such as Depreciation and amortization, Equity (earnings) losses, and Net (gain) loss on disposition of equity-method investments. Our Net cash provided (used) by operating activities for the three months ended March 31, 2018, decreased from the same period in 2017 primarily due to the impact of net unfavorable changes in operating working capital and decreased distributions from unconsolidated affiliates in 2018.

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

We have various other guarantees and commitments which are disclosed in Note 3 – Variable Interest Entities, Note 6 – 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.

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 2018.

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

Evaluation of Disclosure Controls and Procedures

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

Changes in Internal Control Over Financial Reporting

There have been no changes during the first quarter of 2018 that have materially affected, or are reasonably likely to materially affect, our Internal Control over Financial Reporting.

PART II. OTHER INFORMATION

Item 1. Legal Proceedings

Environmental

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

On June 13, 2013, an explosion and fire occurred at our formerly owned Geismar olefins plant and rendered the facility temporarily inoperable (Geismar Incident). On October 21, 2013, the EPA, Region 6, issued an Inspection Report pursuant to the Clean Air Act’s Risk Management Program following its inspection of the facility on June 24 through June 28, 2013. The report notes the EPA’s preliminary determinations about the facility’s documentation regarding process safety, process hazard analysis, as well as operating procedures, employee training, and other matters. On June 16, 2014, we received a request for information related to the Geismar Incident from the EPA under Section 114 of the Clean Air Act to which we responded on August 13, 2014. The EPA could issue penalties pertaining to final determinations.

On February 21, 2017, we received notice from the Environmental Enforcement Section of the United States Department of Justice (DOJ) regarding certain alleged violations of the Clean Air Act at our Moundsville facility as set forth in a Notice of Noncompliance issued by the EPA on January 14, 2016. The notice includes an offer to avoid further legal action on the alleged violations by paying $2 million. In discussion with the DOJ and the EPA, the EPA has indicated its belief that additional similar violations have occurred at our Oak Grove facility and has expressed interest in pursuing a global settlement. On January 19, 2018, we received an offer from the DOJ to globally settle the government’s claim for civil penalties associated with the alleged violations at both the Moundsville and the Oak Grove facilities for $1.955 million. In March 2018, we made a counter-offer to settle the government’s claims as to both the Moundsville and Oak Grove facilities. We are awaiting the agencies’ response.

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

On January 19, 2018, we received notice from the United States Department of Transportation Pipeline and Hazardous Materials Safety Administration (PHMSA) regarding certain alleged violations of PHMSA regulations in connection with a fire and release of liquid ethane that occurred at our Houston Meter Station located near Houston, Washington County, Pennsylvania, on December 24, 2014. The Notice of Probable Violation and Proposed Civil Penalty issued by PHMSA alleges failure to timely notify the National Response Center of a release of a hazardous liquid resulting in a fire or explosion and failure to verify that the facility was constructed, inspected, tested, and calibrated in accordance with comprehensive written specifications or standards and proposes a total civil penalty of $174,100. We have since paid the proposed civil penalty and have resolved this matter.

On March 19, 2018, we received a Notice of Violation from the EPA, Region 8, regarding certain alleged violations of the Clean Air Act at our Ignacio Gas Plant in Durango, Colorado, following a previous on-site inspection of the facility. We were subsequently informed that this matter has been referred to the DOJ for handling. The Notice of Violation does not contain an initial penalty assessment. We are evaluating the alleged violations and will respond to the agency.

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

Other environmental matters called for by this Item are described under the caption “Environmental Matters” in Note 9 – Contingent Liabilities of Notes to Consolidated Financial Statements included under Part I, Item 1. Financial Statements of this report, which information is incorporated by reference into this Item.

Other Litigation

The additional information called for by this Item is provided in Note 9 – Contingent Liabilities of Notes to Consolidated Financial Statements included under Part I, Item 1. Financial Statements of this report, which information is incorporated by reference into this Item.

Item 1A. Risk Factors

Part I, Item 1A. Risk Factors in our Annual Report on Form 10-K for the year ended December 31, 2017, includes certain risk factors that could materially affect our business, financial condition, or future results. Those Risk Factors have not materially changed, except as set forth below:

On March 15, 2018, the FERC issued a policy statement that reversed its 2005 income tax policy that permitted master limited partnership (MLP) interstate oil and natural gas pipelines to recover an income tax allowance in cost of service rates, which if implemented, may adversely impact our financial condition and future results of operations.

In May 2005, the FERC issued a statement of general policy permitting a pipeline to include in its cost-of-service computations an income tax allowance provided that an entity or individual has an actual or potential income tax liability on income from the pipeline’s public utility assets. Pursuant to that policy, the extent to which owners of pipelines have such actual or potential income tax liability will be reviewed by the FERC on a case-by-case basis in rate cases where the amounts of the allowances will be established. On March 15, 2018, the FERC found that an impermissible double recovery results from granting a MLP pipeline both an income tax allowance and a return on equity pursuant to the discounted cash flow methodology. As a result, the FERC will no longer permit an MLP pipeline to recover an income tax allowance in its cost of service and further stated it will address the application of this policy to non-MLP partnership forms as those issues arise in subsequent proceedings. The FERC also issued a Notice of Proposed Rulemaking proposing a process that will allow it to consider costs and revenues in the context of the recent reduction in the corporate income tax rate as a result of Tax Reform and the FERC’s revised policy statement regarding MLPs. Furthermore, the FERC issued a Notice of Inquiry seeking comments on the additional impacts of Tax Reform on jurisdictional rates, and whether other features of Tax Reform require FERC action. Due to the foregoing, it is reasonably possible that future tariff-based rates collected by our interstate natural gas pipelines may be negatively impacted by such actions, which may have a material adverse effect on our business, financial condition, results of operations, and cash flows.

Item 6. Exhibits



Exhibit No.		Description

2.1§	—	Agreement and Plan of Merger dated as of May 12, 2015, by and among The Williams Companies, Inc., SCMS LLC, Williams Partners L.P., and WPZ GP LLC (filed on May 13, 2015 as Exhibit 2.1 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-34831) and incorporated herein by reference).
2.2§	—	Membership Interest Purchase Agreement, dated as of April 13, 2017, among Williams Field Services Group, LLC, Williams Partners L.P., Williams Olefins, L.L.C., NOVA Chemicals Inc., and NOVA Chemicals Corporation (filed on August 3, 2017 as Exhibit 2.2 to Williams Partners L.P.’s quarterly report on Form 10-Q (File No. 001-34831) and incorporated herein by reference).
3.1	—	Certificate of Limited Partnership of Chesapeake Midstream Partners, L.P. (filed on February 16, 2010 as Exhibit 3.1 to Williams Partners L.P.’s registration statement on Form S-1 (File No. 333-164905) and incorporated herein by reference).
3.2	—	Amendment to Certificate of Limited Partnership of Chesapeake Midstream Partners, L.P. (filed on July 30, 2012 as Exhibit 3.1 to Williams Partners L.P.’s current report on Form 8‑K (File No. 001-34831) and incorporated herein by reference).
3.3	—	Amendment to Certificate of Limited Partnership of Access Midstream Partners, L.P. (filed on February 3, 2015 as Exhibit 3.5 to Williams Partners L.P.’s current report on Form 8‑K (File No. 001-34831) and incorporated herein by reference).
3.4	—	Composite Certificate of Limited Partnership of Williams Partners L.P. (filed on February 25, 2015 as Exhibit 3.4 to Williams Partners L.P.’s annual report on Form 10-K (File No. 001-34831) and incorporated herein by reference).
3.5	—	Second Amended and Restated Agreement of Limited Partnership of Williams Partners L.P., dated as of February 1, 2018 (filed on February 1, 2018 as Exhibit 3.1 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-34831) and incorporated herein by reference).
3.6	—	Certificate of Formation of Chesapeake Midstream GP, L.L.C. (filed on February 16, 2010 as Exhibit 3.3 to Williams Partners L.P.’s registration statement on Form S-1 (File No. 333-164905) and incorporated herein by reference).
3.7	—	Certificate of Amendment to Certificate of Formation of Chesapeake Midstream GP, L.L.C. (filed on July 30, 2012 as Exhibit 3.5 to Williams Partners L.P.’s current report on Form 8‑K (File No. 001-34831) and incorporated herein by reference).
3.8	—	Certificate of Amendment of Certificate of Formation of Access Midstream Partners GP, L.L.C. (filed on February 3, 2015 as Exhibit 3.2 to Williams Partners L.P.’s current report on Form 8‑K (File No. 001-34831) and incorporated herein by reference).
3.9	—	Composite Certificate of Formation of WPZ GP LLC (filed on February 25, 2015 as Exhibit 3.14 to Williams Partners L.P.’s annual report on Form 10-K (File No. 001-34831) and incorporated herein by reference).
3.10	—	Eighth Amended and Restated Limited Liability Company Agreement of WPZ GP LLC (filed on August 2, 2016 as Exhibit 3.17 to Williams Partners L.P.’s quarterly report on Form 10-Q (File No. 001-34831) and incorporated herein by reference).
4.1	—	Tenth Supplemental Indenture, dated as of March 5, 2018, between Williams Partners L.P. and The Bank of New York Mellow Trust Company, N.A., as trustee (filed on March 5, 2018 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 No.		Description

4.2	—	Indenture, dated as of March15, 2018, between Transcontinental Gas Pipe Line Company, LLC and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on March 15, 2018 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).
10.1	—	Termination Agreement and Release, dated as of September 28, 2015, by and among The Williams Companies, Inc., SCMS LLC, Williams Partners L.P. and WPZ GP LLC (filed on September 28, 2015 as Exhibit 10.1 to Williams Partners L.P.’s current report on Form 8‑K (File No. 001-34831) and incorporated herein by reference).
10.2	—	Registration Rights Agreement, dated March 15, 2018, among Transcontinental Gas Pipe Line Company, LLC and the initial purchasers listed therein (filed on March 15, 2018 as Exhibit 10.1 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-34831) and incorporated herein by reference).
12*	—	Computation of Ratio of Earnings to Fixed Charges.
31.1*	—	Certification of Chief Executive Officer pursuant to Rules 13a-14(a) and 15d-14(a) promulgated under the Securities Exchange Act of 1934, as amended, and Item 601(b)(31) of Regulation S-K, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*	—	Certification of Chief Financial Officer pursuant to Rules 13a-14(a) and 15d-14(a) promulgated under the Securities Exchange Act of 1934, as amended, and Item 601(b)(31) of Regulation S-K, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32**	—	Certification of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS*	—	XBRL Instance Document.
101.SCH*	—	XBRL Taxonomy Extension Schema.
101.CAL*	—	XBRL Taxonomy Extension Calculation Linkbase.
101.DEF*	—	XBRL Taxonomy Extension Definition Linkbase.
101.LAB*	—	XBRL Taxonomy Extension Label Linkbase.
101.PRE*	—	XBRL Taxonomy Extension Presentation Linkbase.


*	Filed herewith.


**	Furnished herewith.


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

SIGNATURE

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



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

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

May 3, 2018

WILLIAMS PARTNERS L.P. 10-Q