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 June 30, 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 958,225,979 common units and 18,442,649 Class B units outstanding as of July 30, 2018.

Williams Partners L.P.

Index



Part I. Financial Information		Page
Item 1. Financial Statements
Consolidated Statement of Comprehensive Income – Three and Six Months Ended June 30, 2018 and 2017		6
Consolidated Balance Sheet – June 30, 2018 and December 31, 2017		7
Consolidated Statement of Changes in Equity – Six Months Ended June 30, 2018		8
Consolidated Statement of Cash Flows – Six Months Ended June 30, 2018 and 2017		9
Notes to Consolidated Financial Statements		10
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		33
Item 3. Quantitative and Qualitative Disclosures About Market Risk		54
Item 4. Controls and Procedures		54
Part II. Other Information		54
Item 1. Legal Proceedings		54
Item 1A. Risk Factors		56
Item 6. Exhibits		58

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:


•	The closing and expected timing of, and anticipated financial results following, the WPZ Merger;


•	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:


•	Satisfaction of the conditions to the completion of the WPZ Merger including receipt of the Williams stockholder approval, and our ability to close the WPZ Merger;


•	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, market demand, and volatility of prices;


•	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 investment opportunities;


•	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 and unforeseen interruptions;


•	The impact of existing and future laws (including, but not limited to, the Tax Cuts and Job Acts of 2017), regulations, the regulatory environment, environmental liabilities, and litigation, as well as our ability to obtain necessary permits and approvals, and achieve favorable rate proceeding outcomes;


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


•	Changes in maintenance and construction costs;


•	Changes in the current geopolitical situation;


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


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


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


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


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


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

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

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

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

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

DEFINITIONS

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

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 June 30, 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.

Jackalope: Jackalope Gas Gathering Services, 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:

Charter Amendment: An amendment to Williams’ Amended and Restated Certificate of Incorporation to increase the number of authorized shares of Williams common stock to 1,500,000,000 shares, consisting of 1,470,000,000 shares of Williams common stock and 30,000,000 shares of Williams preferred stock, par value $1.00 per share

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

RGP Splitter: Refinery grade propylene splitter

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)

WPZ Merger: The merger of SCMS LLC, a Delaware limited liability company and a wholly owned subsidiary of Williams, with and into WPZ, with WPZ as the sole surviving entity

WPZ Merger Agreement: Agreement and Plan of Merger dated as of May 16, 2018, by and among The Williams Companies, Inc., SCMS LLC, Williams Partners L.P., and WPZ GP LLC

PART I – FINANCIAL INFORMATION

Williams Partners L.P.

Consolidated Statement of Comprehensive Income

(Unaudited)



	Three Months Ended June 30,						Six Months Ended June 30,
	2018			2017			2018			2017
	(Millions, except per-unit amounts)
Revenues:
Service revenues	$	1,335		$	1,277		$	2,681		$	2,533
Service revenues – commodity consideration (Note 2)	94			—			195			—
Product sales	657			642			1,293			1,369
Total revenues	2,086			1,919			4,169			3,902
Costs and expenses:
Product costs	636			537			1,249			1,116
Processing commodity expenses (Note 2)	26			—			61			—
Operating and maintenance expenses	383			384			734			745
Depreciation and amortization expenses	426			423			849			856
Selling, general, and administrative expenses	136			154			274			310
Other (income) expense – net	(1		)	9			30			13
Total costs and expenses	1,606			1,507			3,197			3,040
Operating income (loss)	480			412			972			862
Equity earnings (losses)	92			125			174			232
Other investing income (loss) – net (Note 4)	67			2			71			273
Interest incurred	(224		)	(214		)	(442		)	(435		)
Interest capitalized	13			9			22			16
Other income (expense) – net	21			15			36			64
Income (loss) before income taxes	449			349			833			1,012
Provision (benefit) for income taxes	—			1			—			4
Net income (loss)	449			348			833			1,008
Less: Net income (loss) attributable to noncontrolling interests	23			28			47			54
Net income (loss) attributable to controlling interests	$	426		$	320		$	786		$	954
Allocation of net income (loss) for calculation of earnings per common unit:
Net income (loss) attributable to controlling interests	$	426		$	320		$	786		$	954
Allocation of net income (loss) to Class B units	8			6			15			17
Allocation of net income (loss) to common units	$	418		$	314		$	771		$	937
Basic earnings (loss) per common unit:
Net income (loss) per common unit	$	.44		$	.33		$	.81		$	1.00
Weighted-average number of common units outstanding (thousands)	957,896			955,636			957,589			937,889
Diluted earnings (loss) per common unit:
Net income (loss) per common unit	$	.44		$	.33		$	.81		$	1.00
Weighted-average number of common units outstanding (thousands)	957,965			955,986			957,652			938,217
Cash distributions per common unit	$	.629		$	.600		$	1.243		$	1.200

Other comprehensive income (loss):
Cash flow hedging activities:
Net unrealized gain (loss) from derivative instruments	$	(19	)	$	—		$	(17	)	$	4
Reclassifications into earnings of net derivative instruments (gain) loss	4			(1		)	4			(2		)
Other comprehensive income (loss)	(15		)	(1		)	(13		)	2
Comprehensive income (loss)	434			347			820			1,010
Less: Comprehensive income attributable to noncontrolling interests	23			28			47			54
Comprehensive income (loss) attributable to controlling interests	$	411		$	319		$	773		$	956

See accompanying notes.

Williams Partners L.P.

Consolidated Balance Sheet

(Unaudited)



	June 30, 2018			December 31, 2017
	(Dollars in millions)
ASSETS
Current assets:
Cash and cash equivalents	$	255		$	881
Trade accounts and other receivables (net of allowance of $10 at June 30, 2018 and $9 at December 31, 2017)	800			972
Inventories	153			113
Other current assets and deferred charges	260			176
Total current assets	1,468			2,142
Investments	6,810			6,552
Property, plant, and equipment	40,329			38,931
Accumulated depreciation and amortization	(11,611		)	(11,019		)
Property, plant, and equipment – net	28,718			27,912
Intangible assets – net of accumulated amortization	8,405			8,790
Regulatory assets, deferred charges, and other	537			507
Total assets	$	45,938		$	45,903
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable:
Trade	$	841		$	957
Affiliate	109			134
Accrued interest	226			214
Other accrued liabilities	598			643
Long-term debt due within one year	2			501
Total current liabilities	1,776			2,449
Long-term debt	17,018			15,996
Asset retirement obligations	961			944
Deferred income tax liabilities	15			16
Regulatory liabilities, deferred income, and other	3,269			2,809
Contingent liabilities (Note 9)
Equity:
Partners’ equity:
Common units (958,183,223 and 956,952,542 units outstanding at June 30, 2018 and December 31, 2017, respectively)	20,761			21,251
Class B units (18,442,649 and 17,853,088 units outstanding at June 30, 2018 and December 31, 2017, respectively)	796			784
Accumulated other comprehensive income (loss)	(18		)	(5		)
Total partners’ equity	21,539			22,030
Noncontrolling interests in consolidated subsidiaries	1,360			1,659
Total equity	22,899			23,689
Total liabilities and equity	$	45,938		$	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)	771			15			—			786			47			833
Other comprehensive income (loss)	—			—			(13		)	(13		)	—			(13		)
Distributions to partners	(1,162		)	—			—			(1,162		)	—			(1,162		)
Sales of common units (Note 7)	46			—			—			46			—			46
Distributions to noncontrolling interests	—			—			—			—			(93		)	(93		)
Contributions from noncontrolling interests	—			—			—			—			11			11
Deconsolidation of subsidiary (Note 3)	—			—			—			—			(267		)	(267		)
Contributions from (distributions to) The Williams Companies, Inc. – net	3			—			—			3			—			3
Net increase (decrease) in equity	(490		)	12			(13		)	(491		)	(299		)	(790		)
Balance – June 30, 2018	$	20,761		$	796		$	(18	)	$	21,539		$	1,360		$	22,899

See accompanying notes.

Williams Partners L.P.

Consolidated Statement of Cash Flows

(Unaudited)



	Six Months Ended June 30,
	2018			2017
	(Millions)
OPERATING ACTIVITIES:
Net income (loss)	$	833		$	1,008
Adjustments to reconcile to net cash provided (used) by operating activities:
Depreciation and amortization	849			856
Provision (benefit) for deferred income taxes	(1		)	(1		)
Equity (earnings) losses	(174		)	(232		)
Distributions from unconsolidated affiliates	316			404
Net (gain) loss on disposition of equity-method investments	—			(269		)
Amortization of stock-based awards	—			4
Cash provided (used) by changes in current assets and liabilities:
Accounts and notes receivable	160			194
Inventories	(33		)	(30		)
Other current assets and deferred charges	(69		)	(14		)
Accounts payable	(100		)	35
Accrued liabilities	68			(100		)
Affiliate accounts receivable and payable – net	(25		)	21
Other, including changes in noncurrent assets and liabilities	(114		)	(111		)
Net cash provided (used) by operating activities	1,710			1,765
FINANCING ACTIVITIES:
Proceeds from (payments of) commercial paper – net	—			(93		)
Proceeds from long-term debt	1,814			1,698
Payments of long-term debt	(1,251		)	(1,535		)
Proceeds from sales of common units	—			2,184
Distributions paid	(1,116		)	(1,357		)
Distributions to noncontrolling interests	(93		)	(108		)
Contributions from noncontrolling interests	11			10
Contributions from (distributions to) The Williams Companies, Inc. – net	3			(8		)
Payments for debt issuance costs	(18		)	(13		)
Other – net	(34		)	(23		)
Net cash provided (used) by financing activities	(684		)	755
INVESTING ACTIVITIES:
Property, plant, and equipment:
Capital expenditures (1)	(1,873		)	(1,049		)
Dispositions – net	3			(14		)
Contributions in aid of construction	339			194
Proceeds from dispositions of equity-method investments	—			200
Purchases of and contributions to equity-method investments	(91		)	(79		)
Other – net	(30		)	(9		)
Net cash provided (used) by investing activities	(1,652		)	(757		)
Increase (decrease) in cash and cash equivalents	(626		)	1,763
Cash and cash equivalents at beginning of year	881			145
Cash and cash equivalents at end of period	$	255		$	1,908
_________
(1) Increases to property, plant, and equipment	$	(1,847	)	$	(1,155	)
Changes in related accounts payable and accrued liabilities	(26		)	106
Capital expenditures	$	(1,873	)	$	(1,049	)

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 Exhibit 99.1 of our Form 8-K dated May 3, 2018. 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 June 30, 2018, Williams owns a 74 percent limited partner interest in us. Our operations are located in the United States.

Public Unit Exchange

On May 16, 2018, we entered into an agreement for a stock-for-unit transaction whereby Williams will acquire all of our publicly held outstanding common units in exchange for shares of William’s common stock (WPZ Merger). Each such common unit will be converted into the right to receive 1.494 shares of William’s common stock or 1.513 shares if the closing does not occur before the record date of William’s third-quarter 2018 dividend. In the event this agreement is terminated under certain circumstances, Williams could be required to pay us a $410 million termination fee. Williams currently owns approximately 74 percent of us.

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.

Notes (Continued)

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 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, a 50 percent interest in Jackalope Gas Gathering Services, L.L.C. (Jackalope) (an equity-method investment following deconsolidation as of June 30, 2018), and 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 revised 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. As a result, 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.

On July 18, 2018, the FERC issued an order dismissing the requests for rehearing and clarification of the revised policy statement. In addition, the FERC provided guidance that an MLP pipeline (or other pass-through entity) no longer recovering an income tax allowance pursuant to the revised policy may eliminate previously accumulated deferred income taxes (ADIT) from its cost of service instead of flowing these previously accumulated ADIT balances to ratepayers. However, the FERC stated that the revised policy statement and such guidance do not establish a binding rule, but are instead expressions of general policy intent designed to provide guidance by notifying entities of the course of action the FERC intends to follow in future adjudications. To the extent the FERC addresses these issues in future proceedings, it will consider any arguments regarding not only the application of the revised policy to the facts of the case, but also any arguments regarding the underlying validity of the policy itself.

Notes (Continued)

On March 15, 2018, the FERC also issued a Notice of Proposed Rulemaking proposing a filing 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 the revised policy statement. On July 18, 2018, the FERC issued a Final Rule, retaining the filing requirement and reaffirming the options that pipelines have to either reflect the reduced tax rate or explain why no rate change is necessary. The FERC also clarified that a natural gas company organized as a pass-through entity and all of whose income or losses are consolidated on the federal income tax return of its corporate parent is considered to be subject to the federal corporate income tax and is thus eligible for a tax allowance.

On March 15, 2018, the FERC also 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.

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 June 30, 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 $258 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

Notes (Continued)

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 could impact our trade receivables as the related allowance for credit losses will be recognized earlier under the expected loss model.

In February 2016, the FASB issued ASU 2016-02 “Leases (Topic 842)” (ASU 2016-02). ASU 2016-02 establishes a comprehensive new lease accounting model. ASU 2016-02 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.”

In July 2018, the FASB issued ASU 2018-11 “Leases (Topic 842): Targeted Improvements” (ASU 2018-11). Prior to ASU 2018-11, a modified retrospective transition was required for financing or operating leases existing at or entered into after the beginning of the earliest comparative period presented in the financial statements. ASU 2018-11 allows 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. ASU 2018-11 also allows a practical expedient that permits lessors to not separate non-lease components from the associated lease component if certain conditions are present. 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.

We are in the process of finalizing our review of contracts to identify leases based on the modified definition of a lease, implementing a financial lease accounting system, and identifying changes to our internal controls to support management in the accounting for and disclosure of leasing activities upon adoption of ASU 2016-02. While we are still in the process of completing our implementation evaluation of ASU 2016-02, we currently believe the most

Notes (Continued)

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 available practical expedients on adoption, which we expect to elect.

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 pipeline businesses 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 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:

Notes (Continued)


•	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 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,

Notes (Continued)

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 June 30, 2018
Revenues from contracts with customers:
Service revenues:
Non-regulated gathering, processing, transportation, and storage:
Monetary consideration	$	205	$	128	$	414		$	—	$	—	$	(18	)	$	729
Commodity consideration	5		11		78			—		—		—			94
Regulated interstate natural gas transportation and storage	—		—		—			450		108		—			558
Other	21		2		13			1		—		(3		)	34
Total service revenues	231		141		505			451		108		(21		)	1,415
Product Sales:
NGL and natural gas	75		76		558			30		—		(83		)	656
Other	—		—		4			—		—		(1		)	3
Total product sales	75		76		562			30		—		(84		)	659
Total revenues from contracts with customers	306		217		1,067			481		108		(105		)	2,074
Other revenues (1)	5		7		(2		)	2		—		—			12
Total revenues	$	311	$	224	$	1,065		$	483	$	108	$	(105	)	$	2,086

Six Months Ended June 30, 2018
Revenues from contracts with customers:
Service revenues:
Non-regulated gathering, processing, transportation, and storage:
Monetary consideration	$	407	$	265	$	822		$	—	$	—	$	(36	)	$	1,458
Commodity consideration	9		26		160			—		—		—			195
Regulated interstate natural gas transportation and storage	—		—		—			911		220		(1		)	1,130
Other	42		8		24			1		—		(6		)	69
Total service revenues	458		299		1,006			912		220		(43		)	2,852
Product Sales:
NGL and natural gas	173		144		1,079			55		—		(168		)	1,283
Other	—		—		8			—		—		(1		)	7
Total product sales	173		144		1,087			55		—		(169		)	1,290
Total revenues from contracts with customers	631		443		2,093			967		220		(212		)	4,142
Other revenues (1)	10		9		3			5		—		—			27
Total revenues	$	641	$	452	$	2,096		$	972	$	220	$	(212	)	$	4,169

______________________________

(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.

Notes (Continued)

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 our contract assets:



	Quarter-to-Date June 30, 2018			Year-to-Date June 30, 2018
	(Millions)
Balance at beginning of period	$	24		$	4
Revenue recognized in excess of cash received	16			36
Minimum volume commitments invoiced	(1		)	(1		)
Balance at end of period	$	39		$	39

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 our contract liabilities:



	Quarter-to-Date June 30, 2018			Year-to-Date June 30, 2018
	(Millions)
Balance at beginning of period	$	1,574		$	1,596
Payments received and deferred	126			218
Deconsolidation of Jackalope interest (Note 3)	(52		)	(52		)
Recognized in revenue	(113		)	(227		)
Balance at end of period	$	1,535		$	1,535

Notes (Continued)

The following table presents the amount of the contract liabilities balance as of June 30, 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)	$	184
2019	249
2020	128
2021	110
2022	103
2023	99
Thereafter	662

Remaining Performance Obligations

The following table presents the transaction price allocated to the remaining performance obligations under certain contracts as of June 30, 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 June 30, 2018, that will be recognized in future periods (see above for Contract Liabilities and the expected recognition of those amounts within 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 June 30, 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)	$	1,238
2019	2,438
2020	2,267
2021	2,033
2022	1,840
2023	1,659
Thereafter	12,588
Total	$	24,063

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:



	June 30, 2018		January 1, 2018
	(Millions)
Accounts receivable related to revenues from contracts with customers	$	742	$	956
Other accounts receivable	58		16
Total reflected in Trade accounts and other receivables	$	800	$	972

Notes (Continued)

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.



	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 June 30, 2018
Service revenues	$	1,335		$	6		$	1,341
Service revenues - commodity consideration	94			(94		)	—
Product sales	657			32			689
Total revenues	2,086			(56		)	2,030
Product costs	636			(40		)	596
Processing commodity expenses	26			(26		)	—
Operating and maintenance expenses	383			4			387
Total costs and expenses	1,606			(62		)	1,544
Operating income (loss)	480			6			486
Equity earnings (losses)	92			1			93
Other investing income (loss) - net	67			(9		)	58
Interest incurred	(224		)	4			(220		)
Interest capitalized	13			(2		)	11
Less: Net income (loss) attributable to noncontrolling interests	23			(1		)	22
Net income (loss) attributable to controlling interests	426			1			427
Allocation of net income (loss) to common units	418			1			419
Less: Comprehensive income attributable to noncontrolling interests	23			(1		)	22
Comprehensive income (loss) attributable to controlling interests	411			1			412

Six Months Ended June 30, 2018
Service revenues	$	2,681		$	11		$	2,692
Service revenues - commodity consideration	195			(195		)	—
Product sales	1,293			42			1,335
Total revenues	4,169			(142		)	4,027
Product costs	1,249			(95		)	1,154
Processing commodity expenses	61			(61		)	—
Operating and maintenance expenses	734			3			737
Depreciation and amortization expenses	849			1			850
Total costs and expenses	3,197			(152		)	3,045
Operating income (loss)	972			10			982
Equity earnings (losses)	174			1			175
Other investing income (loss) - net	71			(9		)	62
Interest incurred	(442		)	7			(435		)
Interest capitalized	22			(4		)	18
Income (loss) before income taxes	833			5			838
Net income (loss)	833			5			838
Less: Net income (loss) attributable to noncontrolling interests	47			(2		)	45
Net income (loss) attributable to controlling interests	$	786		$	7		$	793
Allocation of net income (loss) to common units	771			7			778
Basic earnings (loss) per common unit	.81			.01			.82

Notes (Continued)



	As Reported			Adjustments resulting from adoption of ASC 606			Balance without adoption of ASC 606
	(Millions, except per unit amounts)
Diluted earnings (loss) per common unit	$	.81		$	.01		$	.82
Comprehensive income (loss)	820			5			825
Less: Comprehensive income attributable to noncontrolling interests	47			(2		)	45
Comprehensive income (loss) attributable to controlling interests	773			7			780

Consolidated Balance Sheet
June 30, 2018
Inventories	$	153		$	(7	)	$	146
Other current assets and deferred charges	260			(35		)	225
Total current assets	1,468			(42		)	1,426
Investments	6,810			(1		)	6,809
Property, plant and equipment	40,329			(4		)	40,325
Property, plant, and equipment – net	28,718			(4		)	28,714
Intangible assets – net of accumulated amortization	8,405			62			8,467
Regulatory assets, deferred charges, and other	537			(4		)	533
Total assets	45,938			11			45,949
Regulatory liabilities, deferred income, and other	3,269			(133		)	3,136
Common and Class B units	21,557			156			21,713
Total partners’ equity	21,539			156			21,695
Noncontrolling interests in consolidated subsidiaries	1,360			(12		)	1,348
Total equity	22,899			144			23,043
Total liabilities and equity	45,938			11			45,949

Consolidated Statement of Changes in Equity
June 30, 2018
Adoption of ASC 606	$	(148	)	$	148		$	—
Net income (loss)	833			5			838
Deconsolidation of subsidiary	(267		)	(9		)	(276		)
Net increase (decrease) in equity	(790		)	144			(646		)
Balance - June 30, 2018	22,899			144			23,043

Note 3 – Variable Interest Entities

Consolidated VIEs

As of June 30, 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 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,

Notes (Continued)

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 (D.C. 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 2017 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. We filed a request for rehearing of the FERC’s decision, but in July 2018 the FERC denied our request.

The project’s sponsors remain committed to the project. Now that the FERC has issued an order on our request for rehearing, we are clear to seek review of the matter with the D.C. Circuit. We plan to file a petition for review with the D.C. Circuit. An unfavorable resolution could result in the impairment of a significant portion of the capitalized project costs, which total $377 million on a consolidated basis at June 30, 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)

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



	June 30, 2018			December 31, 2017 (1)			Classification
	(Millions)
Assets (liabilities):
Cash and cash equivalents	$	28		$	35		Cash and cash equivalents
Accounts receivable	53			76			Trade accounts and other receivables
Prepaid assets	2			2			Other current assets and deferred charges
Property, plant, and equipment – net	2,432			2,887			Property, plant, and equipment – net
Intangible assets – net	1,200			1,381			Intangible assets – net of accumulated amortization
Accounts payable	(15		)	(28		)	Accounts payable – trade
Accrued liabilities	—			(1		)	Other accrued liabilities
Current deferred revenue	(65		)	(57		)	Other accrued liabilities
Deposits held	(8		)	—			Other accrued liabilities
Noncurrent asset retirement obligations	(103		)	(103		)	Asset retirement obligations
Noncurrent deferred revenue associated with customer advance payments	(226		)	(305		)	Regulatory liabilities, deferred income, and other

_________________


(1)	Includes Jackalope, which was a consolidated VIE at December 31, 2017.

Nonconsolidated VIEs

Jackalope

We own a 50 percent interest in Jackalope, which provides gathering and processing services for the Powder River basin and is a VIE due to certain risks shared with customers. Prior to the second quarter of 2018 we were the primary beneficiary of Jackalope. During the second quarter of 2018, the scope of Jackalope’s planned future activities changed, resulting in a VIE reconsideration event. Upon evaluation, we determined that we are no longer the primary beneficiary, most notably due to changes in the activities that most significantly impact Jackalope’s economic performance and our determination that we do not control the power to direct such activities. These activities are primarily related to the capital decision making process. As a result, we deconsolidated Jackalope on June 30, 2018 and now account for this interest using the equity method of accounting as we exert significant influence over the financial and operational policies of Jackalope (see Note 4 – Investing Activities). At June 30, 2018, the carrying value of our investment in Jackalope was $310 million. Our maximum exposure to loss is limited to the carrying value of our investment. We expect to fund future capital contributions from us and the other equity partner on a proportional basis.

Note 4 – Investing Activities

Jackalope Deconsolidation

During the second quarter of 2018, we deconsolidated our interest in Jackalope (see Note 3 – Variable Interest Entities). We recorded our interest in Jackalope as an equity-method investment at its estimated fair value, resulting in a deconsolidation gain of $62 million reflected in Other investing income (loss) – net in the Consolidated Statement of Comprehensive Income. We estimated the fair value of our interest to be $310 million using an income approach based on expected future cash flows and an appropriate discount rate (a Level 3 measurement within the fair value hierarchy). The determination of expected future cash flows involved significant assumptions regarding gathering and processing volumes and related capital spending. A 10.9 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. The deconsolidated carrying value of the net assets of Jackalope included $47 million of goodwill.

Notes (Continued)

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.

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 June 30,						Six Months Ended June 30,
	2018			2017			2018			2017
	(Millions)
Atlantic-Gulf
Amortization of regulatory assets associated with asset retirement obligations	$	8		$	9		$	16		$	17
Accrual of regulatory liability related to overcollection of certain employee expenses	6			5			11			11
Adjustments to regulatory liability related to Tax Reform	(21		)	—			(10		)	—
West
Gains on contract settlements and terminations	—			(2		)	—			(15		)
Adjustments to regulatory liability related to Tax Reform	—			—			(7		)	—
Regulatory charge per approved rates related to Tax Reform	6			—			12			—
NGL & Petchem Services
Gain on sale of Refinery Grade Propylene Splitter	—			(12		)	—			(12		)

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 $26 million and $46 million for the three and six months ended June 30, 2018, respectively, and $19 million and $37 million for the three and six months ended June 30, 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 six months ended June 30, 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. (See Note 6 – Debt and Banking Arrangements.) For the six months ended June 30, 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

Notes (Continued)

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.

Note 6 – Debt and Banking Arrangements

Long-Term Debt

Issuances and retirements

Northwest Pipeline retired $250 million of 6.05 percent senior unsecured notes that matured on June 15, 2018.

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 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 used the net proceeds to retire $250 million of 6.05 percent senior unsecured notes that matured on June 15, 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.

Other financing obligation

During the first half of 2018, Transco received an additional $24 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 June 30, 2018, no commercial paper was outstanding under our $3 billion commercial paper program.

Credit Facilities



	June 30, 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 May 2018 distribution resulted in 653,734 common units issued to the public at a discounted average price of $35.79 per unit associated with the reinvested distributions of $23 million.

Notes (Continued)

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 $0.629 per common unit on July 23, 2018, to be paid on August 10, 2018, to unitholders of record at the close of business on August 3, 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 282,067 Class B units associated with the second-quarter distribution, to be issued on August 10, 2018.

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 June 30, 2018:
Measured on a recurring basis:
ARO Trust investments	$	151		$	151		$	151		$	—		$	—
Energy derivatives assets not designated as hedging instruments	4			4			4			—			—
Energy derivatives liabilities designated as hedging instruments	(16		)	(16		)	(15		)	(1		)	—
Energy derivatives liabilities not designated as hedging instruments	(4		)	(4		)	(1		)	—			(3		)
Additional disclosures:
Other receivables	21			21			21			—			—
Long-term debt, including current portion	(17,020		)	(17,702		)	—			(17,702		)	—

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		)	—

Notes (Continued)

Fair Value Methods

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

Assets and liabilities measured at fair value on a recurring basis

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

Energy derivatives: Energy derivatives include commodity-based exchange-traded contracts and over-the-counter contracts, which consist of physical forwards, futures, and swaps that are measured at fair value on a recurring basis. The fair value amounts are presented on a gross basis and do not reflect the netting of asset and liability positions permitted under the terms of our master netting arrangements. Further, the amounts do not include cash held on deposit in margin accounts that we have received or remitted to collateralize certain derivative positions. Energy derivatives assets are reported in Other current assets and 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 six months ended June 30, 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 June 30, 2018, we have accrued liabilities totaling $16 million for these matters, as discussed below. Estimates of

Notes (Continued)

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 June 30, 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. These 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 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 June 30, 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 June 30, 2018, we have accrued liabilities totaling $9 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. That customer has reached a tentative settlement to resolve substantially all Pennsylvania royalty cases pending, which settlement would apply to both the customer and us. The settlement as reported would not require any contribution from us.

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 when announcing the May 2015 agreement. The complaint seeks, among other things, damages and an award of costs and attorneys’ fees. The plaintiff filed an amended complaint on August 31, 2016. On October 17, 2016, we requested the court dismiss the action, and on March 8, 2017, the court dismissed the complaint with prejudice. On April 7, 2017, the plaintiff filed a notice of appeal. On May 22, 2018, the appellate court affirmed the dismissal of plaintiff’s complaint.

Notes (Continued)

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.

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 June 30, 2018
Segment revenues:
Service revenues
External	$	222	$	578	$	535	$	—	$	—		$	1,335
Internal	10		12		—		—		(22		)	—
Total service revenues	232		590		535		—		(22		)	1,335
Total service revenues – commodity consideration (external only)	4		12		78		—		—			94
Product sales
External	66		50		541		—		—			657
Internal	9		55		19		—		(83		)	—
Total product sales	75		105		560		—		(83		)	657
Total revenues	$	311	$	707	$	1,173	$	—	$	(105	)	$	2,086

Three Months Ended June 30, 2017
Segment revenues:
Service revenues
External	$	206	$	540	$	527	$	4	$	—		$	1,277
Internal	11		7		—		—		(18		)	—
Total service revenues	217		547		527		4		(18		)	1,277
Product sales
External	43		75		369		155		—			642
Internal	9		50		66		2		(127		)	—
Total product sales	52		125		435		157		(127		)	642
Total revenues	$	269	$	672	$	962	$	161	$	(145	)	$	1,919

Six Months Ended June 30, 2018
Segment revenues:
Service revenues
External	$	441	$	1,174	$	1,066	$	—	$	—		$	2,681
Internal	19		25		—		—		(44		)	—
Total service revenues	460		1,199		1,066		—		(44		)	2,681
Total service revenues – commodity consideration (external only)	8		27		160		—		—			195
Product sales
External	155		85		1,053		—		—			1,293
Internal	18		113		37		—		(168		)	—
Total product sales	173		198		1,090		—		(168		)	1,293
Total revenues	$	641	$	1,424	$	2,316	$	—	$	(212	)	$	4,169

Six Months Ended June 30, 2017
Segment revenues:
Service revenues
External	$	414	$	1,067	$	1,045	$	7	$	—		$	2,533
Internal	20		16		—		—		(36		)	—
Total service revenues	434		1,083		1,045		7		(36		)	2,533
Product sales
External	103		144		774		348		—			1,369
Internal	17		115		117		8		(257		)	—
Total product sales	120		259		891		356		(257		)	1,369
Total revenues	$	554	$	1,342	$	1,936	$	363	$	(293	)	$	3,902

Notes (Continued)

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



	Three Months Ended June 30,						Six Months Ended June 30,
	2018			2017			2018			2017
	(Millions)
Modified EBITDA by segment:
Northeast G&P	$	255		$	247		$	505		$	473
Atlantic-Gulf	475			454			926			904
West	389			356			802			741
NGL & Petchem Services	—			30			—			81
Other	(4		)	(11		)	(11		)	9
	1,115			1,076			2,222			2,208
Accretion expense associated with asset retirement obligations for nonregulated operations	(10		)	(11		)	(18		)	(17		)
Depreciation and amortization expenses	(426		)	(423		)	(849		)	(856		)
Equity earnings (losses)	92			125			174			232
Other investing income (loss) – net	67			2			71			273
Proportional Modified EBITDA of equity-method investments	(178		)	(215		)	(347		)	(409		)
Interest expense	(211		)	(205		)	(420		)	(419		)
(Provision) benefit for income taxes	—			(1		)	—			(4		)
Net income (loss)	$	449		$	348		$	833		$	1,008

The following table reflects Total assets by reportable segment.



	Total Assets
	June 30, 2018			December 31, 2017
	(Millions)
Northeast G&P	$	14,423		$	14,397
Atlantic-Gulf	16,725			15,230
West	15,365			16,144
NGL & Petchem Services	2			3
Other (1)	356			936
Eliminations (2)	(933		)	(807		)
Total	$	45,938		$	45,903


(1)	Decrease in Other due primarily to decreased cash balance.


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

Note 11 – Subsequent Events

WPZ Merger Unitholder Approval

On July 13, 2018, Williams Gas Pipeline Company, LLC, which as of the record date of the WPZ Merger beneficially owned approximately 73.8 percent of the outstanding WPZ units, delivered a written consent approving the WPZ Merger, and the related merger agreement, in all respects. As a result, no further action by any WPZ unitholder is required under applicable law or otherwise to approve the WPZ Merger and the consent process for holders of WPZ units with respect to the WPZ Merger is concluded.

Notes (Continued)

Agreement to Divest Four Corners Assets

In July 2018, we announced an agreement to sell our natural gas gathering and processing assets in the Four Corners area of New Mexico and Colorado for $1.125 billion, subject to customary closing conditions and purchase price adjustments. As of June 30, 2018, the net carrying amount of these assets in our West segment is approximately $530 million. This transaction is expected to close in the second half of 2018.

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, a 50 percent interest in Jackalope (an equity-method investment following deconsolidation as of June 30, 2018), and our previously owned 50 percent equity-method investment in the Delaware basin gas gathering

Management’s Discussion and Analysis (Continued)

system (DBJV) in the Mid-Continent region (see Note 4 – Investing Activities of Notes to Consolidated Financial Statements).


•	NGL & Petchem Services is comprised of previously owned operations, including an 88.5 percent undivided interest in an olefins production facility in Geismar, Louisiana, which was sold in July 2017, 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 Six Months Ended June 30, 2018

Net income (loss) attributable to controlling interests for the six months ended June 30, 2018, decreased $168 million compared to the six months ended June 30, 2017, primarily due to the absence of a $269 million gain associated with the disposition of certain equity-method investments in 2017, a $75 million decrease in product margins primarily due to the absence of olefins margins associated with our former olefin operations, partially offset by increased NGL and marketing margins, and a $58 million decrease in Equity earnings (losses). This decrease was partially offset by a $148 million increase in service revenue primarily resulting from expansion projects placed into service in 2017 and 2018 and a $62 million gain associated with the deconsolidation of Jackalope.

Unless indicated otherwise, the following discussion and analysis of results of operations and financial condition and liquidity should be read in conjunction with the consolidated financial statements and notes thereto of this Form 10‑Q and our annual consolidated financial statements and notes thereto in Exhibit 99.1 of our Form 8‑K dated May 3, 2018.

Public Unit Exchange

On May 16, 2018, we entered into an agreement for a stock-for-unit transaction whereby Williams will acquire all of our publicly held outstanding common units in exchange for shares of William’s common stock (WPZ Merger). Each such common unit will be converted into the right to receive 1.494 shares of William’s common stock or 1.513 shares if the closing does not occur before the record date of William’s third quarter 2018 dividend. In the event this agreement is terminated under certain circumstances, Williams could be required to pay us a $410 million termination fee. Williams currently owns approximately 74 percent of us. We expect the WPZ Merger will be completed during the third quarter of 2018.

FERC Income Tax Policy Revision

On March 15, 2018, the FERC issued a revised policy statement (the March 15 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. As a result, 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. One of the benefits of the pending

Management’s Discussion and Analysis (Continued)

WPZ Merger is to allow our FERC-regulated pipelines to continue to recover an income tax allowance in their cost of service rates.

On July 18, 2018, the FERC issued an order dismissing the requests for rehearing and clarification of the revised policy statement. In addition, the FERC provided guidance that an MLP pipeline (or other pass-through entity) no longer recovering an income tax allowance pursuant to the revised policy may eliminate previously accumulated deferred income taxes (ADIT) from its cost of service instead of flowing these previously accumulated ADIT balances to ratepayers. This guidance, if implemented, would significantly mitigate the impact of the March 15 Statement. However, the FERC stated that the revised policy statement and such guidance do not establish a binding rule, but are instead expressions of general policy intent designed to provide guidance by notifying entities of the course of action the FERC intends to follow in future adjudications. To the extent the FERC addresses these issues in future proceedings, it will consider any arguments regarding not only the application of the revised policy to the facts of the case, but also any arguments regarding the underlying validity of the policy itself. The FERC’s guidance on ADIT likely will be challenged by customers and state commissions, which would result in a long period of revenue uncertainty for pipelines eliminating ADIT from their cost of service. The WPZ Merger would have the additional benefit of eliminating this uncertainty.

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 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

Management’s Discussion and Analysis (Continued)

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.

Commodity Prices

NGL per-unit margins were approximately 35 percent higher in the first six months of 2018 compared to the same period of 2017 primarily due to a 27 percent increase in per-unit non-ethane prices and an approximate 25 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

Although we expect the WPZ Merger will be completed during the third quarter of 2018, the following discussion reflects our outlook in the event that the WPZ Merger is either delayed or not completed.

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.

Management’s Discussion and Analysis (Continued)

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, debt, and proceeds from asset sales. 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 expected to be at least $3.2 billion. Approximately $1.8 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 and NGL prices are expected to be higher compared to 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 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 slightly lower general and administrative expenses due to the full year impact of prior year cost reduction initiatives and lower equity earnings from our investment in Discovery due to production ending on certain wells.

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, 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;

Management’s Discussion and Analysis (Continued)

•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.

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 rich gas processing 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. With one of these customers, we secured a gathering dedication agreement to gather dry gas in this same region. Additionally, we will be constructing a new NGL pipeline from Moundsville to the Harrison Hub fractionation facility to provide a new outlet for NGLs. These expansions will be supported by long-term, fee-based agreements and volumetric commitments.

Susquehanna Supply Hub Expansion

We continue to expand the gathering systems in the Susquehanna Supply Hub that are needed to meet our customers’ production plans by 2020. This next expansion of the gathering infrastructure includes an additional 40,000 horsepower of new compression and gathering pipelines to bring the capacity to approximately 4.5 Bcf/d.

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 placed additional mainline facilities into service in June 2018, which increased capacity by an additional 150 Mdth/d. We expect to place the full project into service in the second half of August 2018, assuming timely receipt of the remaining regulatory approvals. The expected in-service date is based upon current contractor schedules and may be affected by weather. 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

Management’s Discussion and Analysis (Continued)

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 (D.C. 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 2017 the court denied our petition.

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.

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

Management’s Discussion and Analysis (Continued)

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 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.

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 in May 2018, we refiled our application for the permits. We plan to place the project into service in the fourth quarter of 2020, assuming timely receipt of all necessary regulatory approvals. The project is expected to increase capacity by 400 Mdth/d.

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 July 2018, we received approval from 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.

Management’s Discussion and Analysis (Continued)

Wamsutter Expansion

We plan to expand our gathering and processing infrastructure in the Wamsutter region of Wyoming in order to meet our customers’ production plans. The expansion includes the addition of approximately 54 miles of gathering pipelines and compression, and modifications to existing treating and processing facilities. We plan to place the project into service during the first quarter of 2019.

Critical Accounting Estimates

Constitution Pipeline Capitalized Project Costs

As of June 30, 2018, Property, plant, and equipment in our Consolidated Balance Sheet includes approximately $377 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 June 30, 2018, the carrying value of our equity-method investment in Discovery is $520 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.

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 $657 million as of June 30, 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 and six months ended June 30, 2018, compared to the three and six months ended June 30, 2017. The results of operations by segment are discussed in further detail following this consolidated overview discussion.



	Three Months Ended June 30,									Six Months Ended June 30,
	2018			2017			$ Change*	% Change*		2018			2017			$ Change*	% Change*
	(Millions)									(Millions)
Revenues:
Service revenues	$	1,335		$	1,277		+58	+5	%	$	2,681		$	2,533		+148	+6	%
Service revenues – commodity consideration	94			$	—		+94	NM		195			—			+195	NM
Product sales	657			642			+15	+2	%	1,293			1,369			-76	-6	%
Total revenues	2,086			1,919						4,169			3,902
Costs and expenses:
Product costs	636			537			-99	-18	%	1,249			1,116			-133	-12	%
Processing commodity expenses	26			—			-26	NM		61			—			-61	NM
Operating and maintenance expenses	383			384			+1	—	%	734			745			+11	+1	%
Depreciation and amortization expenses	426			423			-3	-1	%	849			856			+7	+1	%
Selling, general, and administrative expenses	136			154			+18	+12	%	274			310			+36	+12	%
Other (income) expense – net	(1		)	9			+10	NM		30			13			-17	-131	%
Total costs and expenses	1,606			1,507						3,197			3,040
Operating income (loss)	480			412						972			862
Equity earnings (losses)	92			125			-33	-26	%	174			232			-58	-25	%
Other investing income (loss) – net	67			2			+65	NM		71			273			-202	-74	%
Interest expense	(211		)	(205		)	-6	-3	%	(420		)	(419		)	-1	—	%
Other income (expense) – net	21			15			+6	+40	%	36			64			-28	-44	%
Income (loss) before income taxes	449			349						833			1,012
Provision (benefit) for income taxes	—			1			+1	+100	%	—			4			+4	+100	%
Net income (loss)	449			348						833			1,008
Less: Net income attributable to noncontrolling interests	23			28			+5	+18	%	47			54			+7	+13	%
Net income (loss) attributable to controlling interests	$	426		$	320					$	786		$	954


*	+ = 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.

WILLIAMS PARTNERS L.P. 10-Q