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

WILLIAMS PARTNERS L.P.

(Exact name of registrant as specified in its charter)

DELAWARE		20-2485124
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)
ONE WILLIAMS CENTER
TULSA, OKLAHOMA		74172-0172
(Address of principal executive offices)		(Zip Code)

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•	The 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;

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•	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.

•	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;

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•	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).

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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.

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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.

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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.

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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.

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Williams Partners L.P.

Notes to Consolidated Financial Statements

(Unaudited)

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

General

Our accompanying interim consolidated financial statements do not include all the notes in our annual financial statements and, therefore, should be read in conjunction with the consolidated financial statements and notes thereto for the year ended December 31, 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.

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

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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.

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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

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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

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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:

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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,

15

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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.

16

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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.

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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

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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

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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

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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,

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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.

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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.

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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

24

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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 .

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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		)		—

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Notes (Continued)

Fair Value Methods

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

Assets and liabilities measured at fair value on a recurring basis

ARO Trust investments :  Transco deposits a portion of its collected rates, pursuant to its rate case settlement, into an external trust (ARO Trust) that is specifically designated to fund future asset retirement obligations (ARO). The ARO Trust invests in a portfolio of actively traded mutual funds that are measured at fair value on a recurring basis based on quoted prices in an active market 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

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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.

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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.

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Notes (Continued)

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

	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

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Notes (Continued)

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

	Three Months Ended   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.

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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.

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Item 2

Management’s Discussion and Analysis of

Financial Condition and Results of Operations

General

We are an energy infrastructure master limited partnership focused on connecting North America’s significant hydrocarbon resource plays to growing markets for natural gas 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

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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

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 .

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

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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.

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. We believe this Final Rule and the previously discussed WPZ Merger, will allow for the continued recovery of income tax allowances in Transco’s and Northwest Pipeline’s rates. Further, because of Transco’s requirement to file a general rate case no later than August 31, 2018, Transco is exempt from the Final Rule’s filing requirement.

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.

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

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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.

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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;

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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

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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.

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. (See Note 3 – Variable Interest Entities of Notes to Consolidated Financial Statements.)

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

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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.

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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.

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Management’s Discussion and Analysis (Continued)

Results of Operations

Consolidated Overview

The following table and discussion is a summary of our consolidated results of operations for the three 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.

Three months ended June 30, 2018 vs. three months ended June 30, 2017

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

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Management’s Discussion and Analysis (Continued)

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

Product sales increased primarily due to higher marketing revenues reflecting higher non-ethane prices and higher system management gas sales, partially offset by $120 million lower olefin sales associated with the absence of volumes due to the sales of our olefin operations in 2017.

The increase in Product costs is primarily due to the impact of ASC 606 in which costs reflected in this line item for 2018 include volumes acquired as commodity consideration for NGL processing services, as well as higher marketing costs and system management gas costs. This increase is partially offset by the absence of $68 million of olefin feedstock volumes associated with the sales of our olefin operations, as well as the absence of natural gas purchases associated with the production of equity NGLs, which are now reported in Processing commodity expenses in conjunction with the implementation of ASC 606.

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

Operating and maintenance expenses decreased slightly primarily due the absence of $26 million of costs associated with our former olefin operations, partially offset by higher operating and maintenance expenses primarily at Transco including pipeline integrity, general maintenance, and other testing.

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

Selling, general, and administrative expenses decreased primarily due to the absence of $11 million of costs associated with our former olefin operations and the absence of severance-related and organizational realignment costs incurred in 2017.

The favorable change in Other (income) expense – net within Operating income (loss) includes favorable adjustments associated with certain regulatory liabilities resulting from Tax Reform, partially offset by the absence of a gain on the sale of our RGP Splitter in 2017.

The favorable change in Operating income (loss) includes an increase in Service revenues primarily associated with Transco projects placed in-service in 2017 and 2018, favorable NGL and marketing commodity margins reflecting higher non-ethane prices, and favorable adjustments associated with certain regulatory liabilities resulting from Tax Reform, partially offset by the absence of operating income related to our former olefin operations, and higher operating costs at Transco.

The unfavorable change in Equity earnings (losses) is primarily due to a decrease in volumes at Discovery.

The favorable change in Other investing income (loss) – net is primarily due to a gain on the deconsolidation of our interest in Jackalope. (See Note 4 – Investing Activities of Notes to Consolidated Financial Statements.)

Six months ended June 30, 2018 vs. six months ended June 30, 2017

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

Service revenues – commodity consideration increased as the result of implementing ASC 606 using a modified retrospective approach, effective January 1, 2018. Therefore, prior periods have not been recast under the new guidance. These revenues represent consideration we receive in the form of commodities as full or partial payment for gathering

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Management’s Discussion and Analysis (Continued)

and processing services provided. (See Note 2 – Revenue Recognition of Notes to Consolidated Financial Statements.) Most of these NGL volumes are sold within the month processed and therefore are offset in Product costs below.

Product sales decreased primarily due to the absence of $267 million in olefin revenue associated with the sales of our olefin operations in 2017, partially offset by higher marketing revenues and higher system management gas sales. The increase in marketing revenue is driven by higher NGL prices and volumes, partially offset by lower crude oil and olefin-related volumes.

The increase in Product costs is primarily due to the impact of ASC 606 in which costs reflected in this line item for 2018 include volumes acquired as commodity consideration for NGL processing services, as well as higher marketing costs and system management gas costs. This increase is partially offset by the absence of $143 million of olefin feedstock volumes associated with the sales of our olefin operations, as well as the absence of natural gas purchases associated with the production of equity NGLs, which are now reported in Processing commodity expenses in conjunction with the implementation of ASC 606.

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

Operating and maintenance expenses decreased primarily due to the absence of $49 million of costs associated with our former olefin operations, partially offset by higher operating and maintenance expenses at Transco primarily associated with pipeline integrity, general maintenance, and other testing and labor costs.

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

Selling, general, and administrative expenses decreased primarily due to the absence of $18 million in costs associated with our former olefin operations, the absence of severance-related and organizational realignment costs incurred in 2017, and ongoing cost containment efforts.

The unfavorable change in Other (income) expense – net within Operating income (loss) includes the absence of gains from certain contract settlements and terminations in 2017, the absence of a gain on the sale of our RGP Splitter in 2017, and 2018 regulatory charges associated with Northwest Pipeline’s approved rates related to Tax Reform, partially offset by favorable adjustments to certain regulatory liabilities associated with Tax Reform.

The favorable change in Operating income (loss) includes an increase in Service revenues primarily associated with Transco projects placed in-service in 2017 and 2018 and higher gathering and processing volumes across certain of our operating locations, as well as higher NGL and marketing margins. These favorable changes are partially offset by the absence of operating income related to our former olefin operations, and higher operating costs at Transco.

The unfavorable change in Equity earnings (losses) is primarily due to a decrease in volumes at Discovery.

The unfavorable change in Other investing income (loss) – net is primarily due to the absence of a gain on disposition of our investments in DBJV and Ranch Westex JV LLC in 2017, partially offset by a gain on the deconsolidation of our interest in Jackalope in 2018. (See Note 4 – Investing Activities of Notes to Consolidated Financial Statements.)

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

Period-Over-Period Operating Results – Segments

We evaluate segment operating performance based upon Modified EBITDA . Note 10 – Segment Disclosures of Notes to Consolidated Financial Statements includes a reconciliation of this non-GAAP measure to Net income (loss) . Management uses Modified EBITDA because it is an accepted financial indicator used by investors to compare company performance. In addition, management believes that this measure provides investors an enhanced perspective of the

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Management’s Discussion and Analysis (Continued)

operating performance of our assets. Modified EBITDA should not be considered in isolation or as a substitute for a measure of performance prepared in accordance with GAAP.

Northeast G&P

	Three Months Ended   June 30,								Six Months Ended   June 30,
	2018				2017				2018				2017
	(Millions)
Service revenues	$	232			$	217			$	460			$	434
Service revenues - commodity consideration	4				—				8				—
Product sales	75				52				173				120
Segment revenues	311				269				641				554
Product costs	(77		)		(49		)		(176		)		(118		)
Processing commodity expenses	(2		)		—				(4		)		—
Other segment costs and expenses	(92		)		(90		)		(179		)		(177		)
Proportional Modified EBITDA of equity-method investments	115				117				223				214
Northeast G&P Modified EBITDA	$	255			$	247			$	505			$	473

Three months ended June 30, 2018 vs. three months ended June 30, 2017

Modified EBITDA increased primarily due to higher Service revenues .

Service revenues increased primarily due to higher gathering volumes at Susquehanna Supply Hub reflecting increased production from customers, as well as higher gathering and processing revenues at Ohio Valley Midstream.

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

Six months ended June 30, 2018 vs. six months ended June 30, 2017

Modified EBITDA increased primarily due to higher Service revenues .

Service revenues increased primarily due to higher gathering volumes at Susquehanna Supply Hub reflecting increased production from customers, as well as higher gathering and processing volumes and higher fractionation revenues at Ohio Valley Midstream.

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

Proportional Modified EBITDA of equity-method investments increased primarily due to a $19 million increase at Appalachia Midstream Investments reflecting our increased ownership acquired in late first-quarter 2017 and higher volumes, partially offset by decreases at UEOM and Laurel Mountain Midstream.

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Management’s Discussion and Analysis (Continued)

Atlantic-Gulf

	Three Months Ended   June 30,								Six Months Ended   June 30,
	2018				2017				2018				2017
	(Millions)
Service revenues	$	590			$	547			$	1,199			$	1,083
Service revenues - commodity consideration	12				—				27				—
Product sales	105				125				198				259
Segment revenues	707				672				1,424				1,342
Product costs	(106		)		(113		)		(198		)		(231		)
Processing commodity expenses	(2		)		—				(7		)		—
Other segment costs and expenses	(168		)		(185		)		(380		)		(359		)
Proportional Modified EBITDA of equity-method investments	44				80				87				152
Atlantic-Gulf Modified EBITDA	$	475			$	454			$	926			$	904
NGL margin	$	8			$	9			$	18			$	23

Three months ended June 30, 2018 vs. three months ended June 30, 2017

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

Service revenues increased primarily due to a $50 million increase in Transco’s natural gas transportation fee revenues driven by expansion projects placed in service in 2017 and 2018.

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

The decrease in Product sales includes a $18 million decrease in commodity marketing revenues driven by a $40 million decrease in crude oil revenues as this activity is now presented on a net basis within Product costs in 2018 in conjunction with the adoption of ASC 606, partially offset by a $22 million increase in non-ethane marketing revenues reflecting 53 percent higher non-ethane prices.

Product costs decreased primarily due to a $16 million decrease in marketing purchases (more than offset in Product sales ) and the absence of natural gas purchases associated with the production of equity NGLs, which are now reported in Processing commodity expenses in conjunction with the implementation of ASC 606. This decrease was partially offset by an impact of ASC 606 in which costs reflected in this line item for 2018 include volumes acquired as commodity consideration for NGL processing services.

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

The net sum of Service revenues - commodity consideration, Product sales, Product costs, and Processing commodity expenses comprise our commodity product margins.

Other segment costs and expenses decreased primarily due to a favorable $20 million adjustment of regulatory liabilities associated with Tax Reform, partially offset by higher pipeline integrity costs, general maintenance, and other testing.

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Management’s Discussion and Analysis (Continued)

The decrease in Proportional Modified EBITDA of equity-method investments is due to a $35 million decrease at Discovery, primarily related to a $29 million decrease associated with production ending on certain wells.

Six months ended June 30, 2018 vs. six months ended June 30, 2017

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

Service revenues increased primarily due to a $114 million increase in Transco’s natural gas transportation fee revenues driven by a $107 million increase associated with expansion projects placed in service in 2017 and 2018.

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

The decrease in Product sales includes:

•	A $63 million decrease in commodity marketing revenues driven by a $91 million decrease in crude oil revenues as this activity is now presented on a net basis within Product costs in 2018 in conjunction with the adoption of ASC 606, partially offset by a $27 million increase in NGL marketing revenues reflecting 37 percent higher non-ethane prices;

•	A $23 million increase in system management gas sales. System management gas sales are substantially offset in Product costs and therefore have little impact to Modified EBITDA.

Product costs decreased primarily due to a $61 million decrease in marketing purchases (more than offset in Product sales ) and the absence of natural gas purchases associated with the production of equity NGLs, which are now reported in Processing commodity expenses in conjunction with the implementation of ASC 606. This decrease was partially offset by an impact of ASC 606 in which costs reflected in this line item for 2018 include volumes acquired as commodity consideration for NGL processing services, as well as a $23 million increase in system management gas costs (more than offset in Product sales ).

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

The net sum of Service revenues - commodity consideration, Product sales, Product costs, and Processing commodity expenses comprise our commodity product margins.

Other segment costs and expenses increased primarily due to $40 million higher operating and maintenance expense driven by increased pipeline integrity costs, general maintenance, and other testing, as well as higher labor costs at Transco. This increase is partially offset by $9 million of favorable adjustments to certain regulatory liabilities resulting from Tax Reform and a $9 million increase in Transco’s allowance for equity funds used during construction (AFUDC).

The decrease in Proportional Modified EBITDA of equity-method investments is due to a $63 million decrease at Discovery, primarily related to a $52 million decrease associated with production ending on certain wells.

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Management’s Discussion and Analysis (Continued)

West

	Three Months Ended   June 30,								Six Months Ended   June 30,
	2018				2017				2018				2017
	(Millions)
Service revenues	$	535			$	527			$	1,066			$	1,045
Service revenues - commodity consideration	78				—				160				—
Product sales	560				435				1,090				891
Segment revenues	1,173				962				2,316				1,936
Product costs	(557		)		(409		)		(1,083		)		(825		)
Processing commodity expenses	(20		)		—				(50		)		—
Other segment costs and expenses	(226		)		(215		)		(418		)		(413		)
Proportional modified EBITDA of equity-method investments	19				18				37				43
West Modified EBITDA	$	389			$	356			$	802			$	741
NGL margin	$	53			$	30			$	105			$	67

Three months ended June 30, 2018 vs. three months ended June 30, 2017

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

Service revenues increased primarily due to:

•	A $15 million increase primarily related to higher processing rates in the Piceance region driven by higher NGL prices, as well as higher gathering volumes in the Haynesville Shale region and other areas, partially offset by lower gathering volumes primarily in the Eagle Ford region;

•

Offsetting changes primarily associated with implementing the new revenue guidance under ASC 606 including a $30 million decrease related to lower amortization of deferred revenue associated with the up-front cash payments received in conjunction with the fourth quarter 2016 Barnett Shale and Mid-Continent contract restructurings, offset by a $17 million increase related to the earlier recognition of revenues associated with MVCs and a $13 million increase related to other deferred revenue amortization primarily in the Permian basin;

•	A $7 million decrease at Northwest Pipeline primarily due to the reduction of its rates as a result of a rate case settlement that became effective January 1, 2018.

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

The increase in Product sales includes:

•	A $97 million increase in marketing revenues primarily due to increases in product prices including a 41 percent increase in average non-ethane per-unit sales prices and an 8 percent increase in ethane prices, partially offset by an 8 percent decrease in natural gas volumes (substantially offset by higher Product costs) ;

•	A $9 million increase in system management gas sales due to a change in presentation in accordance with ASC 606, which are offset in Product costs and, therefore, have no impact on Modified EBITDA.

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Management’s Discussion and Analysis (Continued)

The increase in Product costs includes the impact of ASC 606 in which costs reflected in this line item for 2018 include volumes acquired as commodity consideration for NGL processing services, as well as an $83 million increase in marketing purchases (more than offset in Product sales ) . The increase also includes a $10 million increase in system management gas costs (offset in Product sales ), partially offset by the absence of natural gas purchases associated with the production of equity NGLs, which are now reported in Processing commodity expenses in conjunction with the implementation of ASC 606.

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

The net sum of Service revenues - commodity consideration, Product sales, Product costs, and Processing commodity expenses comprise our commodity product margins. Our commodity product margins increased primarily due to a $23 million increase in NGL product margins and a $14 million increase in marketing margins. NGL margins are driven by $21 million in higher non-ethane margins, reflecting higher non-ethane prices and lower natural gas prices.

Other segment costs and expenses increased primarily due to a $6 million regulatory charge associated with Northwest Pipeline’s approved rates related to Tax Reform.

Six months ended June 30, 2018 vs. six months ended June 30, 2017

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

Service revenues increased primarily due to:

•	A $26 million increase driven by higher gathering volumes primarily in the Haynesville Shale region;

•	A $13 million increase in rates driven by higher NGL prices in the Piceance region as well as higher average gathering and processing rates across most other areas, partially offset by lower rates primarily in the Haynesville Shale;

•

Nearly offsetting changes primarily associated with implementing the new revenue guidance under ASC 606 including a $59 million decrease related to lower amortization of deferred revenue associated with the up-front cash payments received in conjunction with the fourth quarter 2016 Barnett Shale and Mid-Continent contract restructurings, offset by a $34 million increase related to the earlier recognition of revenues associated with MVCs and a $24 million increase related to other deferred revenue amortization primarily in the Permian basin;

•	A $15 million decrease at Northwest Pipeline primarily due to the reduction of its rates as a result of a rate case settlement that became effective January 1, 2018.

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

The increase in Product sales includes:

•	A $129 million increase in marketing revenues primarily due to increases in product prices including a 29 percent increase in average non-ethane per-unit sales prices and a 10 percent increase in ethane prices, partially offset by an 18 percent decrease in natural gas volumes (substantially offset by higher Product costs) ;

•	A $26 million increase in system management gas sales due to a change in presentation in accordance with ASC 606, which are offset in Product costs and, therefore, have no impact on Modified EBITDA.

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Management’s Discussion and Analysis (Continued)

The increase in Product costs includes the impact of ASC 606 in which costs reflected in this line item for 2018 include volumes acquired as commodity consideration for NGL processing services, a $115 million increase in marketing purchases (more than offset in Product sales ) , a $26 million increase in system management gas costs (offset in Product sales ), partially offset by the absence of natural gas purchases associated with the production of equity NGLs, which are now reported in Processing commodity expenses in conjunction with the implementation of ASC 606.

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

The net sum of Service revenues - commodity consideration, Product sales, Product costs, and Processing commodity expenses comprise our commodity product margins. Our commodity product margins increased primarily due to a $38 million increase in NGL product margins and a $14 million increase in marketing margins. NGL margins are driven by $36 million in higher non-ethane margins, reflecting higher non-ethane prices and lower natural gas prices.

Other segment costs and expenses increased primarily due to the absence of a $15 million gain from contract settlements and terminations in 2017 and a $12 million regulatory charge associated with Northwest Pipeline’s approved rates related to Tax Reform, partially offset by $9 million lower general and administrative costs reflecting ongoing cost containment efforts and slightly lower operating and maintenance costs.

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

NGL & Petchem Services

	Three Months Ended   June 30,								Six Months Ended   June 30,
	2018				2017				2018				2017
	(Millions)
NGL & Petchem Services Modified EBITDA	$	—			$	30			$	—			$	81
Olefins margin	$	—			$	52			$	—			$	123

Modified EBITDA changed unfavorably for the three and six months ended June 30, 2018 compared to the three and six months ended June 30, 2017 due to the sales of our olefin operations in 2017. As a result, there are no operations within this reporting segment in 2018.

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Management’s Discussion and Analysis (Continued)

Management’s Discussion and Analysis of Financial Condition and Liquidity

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

Outlook

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

As previously discussed in Company Outlook, our growth capital and investment expenditures in 2018 are currently expected to be at least $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. We intend to fund the planned 2018 growth capital with retained cash flow, debt, and proceeds from assets sales. We retain the flexibility to adjust planned levels of growth capital and investment expenditures in response to changes in economic conditions or business opportunities.

Liquidity

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

•	Cash and cash equivalents on hand;

•	Cash generated from operations;

•	Distributions from our equity-method investees;

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

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

•	Proceeds from asset monetizations.

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

•	Working capital requirements;

•	Capital and investment expenditures;

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

•	Quarterly distributions to our unitholders.

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

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Management’s Discussion and Analysis (Continued)

As of June 30, 2018 , we had a working capital deficit of $308 million . Our available liquidity is as follows:

Available Liquidity	June 30, 2018
	(Millions)
Cash and cash equivalents	$	255
Capacity available under our $3.5 billion credit facility, less amounts outstanding under our $3 billion commercial paper program (1)	3,500
	$	3,755

(1)

In managing our available liquidity, we do not expect a maximum outstanding amount in excess of the capacity of our credit facility inclusive of any outstanding amounts under our commercial paper program. Through June 30, 2018 , no amount was outstanding under our commercial paper program and credit facility during 2018. At June 30, 2018 , we were in compliance with the financial covenants associated with this credit facility. Borrowing capacity available under our $3.5 billion credit facility as of July 31, 2018, was $3.5 billion.

Registrations

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

In September 2016, we filed a registration statement for our distribution reinvestment program. (See Note 7 – Partners’ Capital of Notes to Consolidated Financial Statements.) In July 2018, we gave notice to terminate our distribution reinvestment program.

Distributions from Equity-Method Investees

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

Credit Ratings

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

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

Following the announcement of the WPZ Merger, on May 17, 2018, the credit ratings agencies affirmed and/or revised the outlook and ratings as noted in the table above. The outlook for WPZ was changed by S&P Global Ratings and Moody’s.

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

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Management’s Discussion and Analysis (Continued)

Cash Distributions to Unitholders

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 .

Sources (Uses) of Cash

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

	Cash Flow		Six Months Ended   June 30,
	Category		2018				2017
			(Millions)
Sources of cash and cash equivalents:
Operating activities – net	Operating		$	1,710			$	1,765
Proceeds from long-term debt (see Note 6)	Financing		1,814				1,698
Contributions in aid of construction	Investing		339				194
Proceeds from sales of common units (see Note 1)	Financing		—				2,184
Proceeds from dispositions of equity-method investments (see Note 4)	Investing		—				200
Uses of cash and cash equivalents:
Capital expenditures	Investing		(1,873		)		(1,049		)
Payments of long-term debt (see Note 6)	Financing		(1,251		)		(1,535		)
Distributions paid (1)	Financing		(1,116		)		(1,357		)
Distributions to noncontrolling interests	Financing		(93		)		(108		)
Purchases of and contributions to equity-method investments	Investing		(91		)		(79		)
Payments of commercial paper – net	Financing		—				(93		)
Other sources / (uses) – net	Financing and Investing		(65		)		(57		)
Increase (decrease) in cash and cash equivalents			$	(626	)		$	1,763

_________

(1)	Includes $852 million and $1.018 billion to Williams in 2018 and 2017, respectively.

Operating activities

The factors that determine operating activities are largely the same as those that affect Net income (loss) , with the exception of noncash items such as Depreciation and amortization , Equity (earnings) losses , and Net (gain) loss on disposition of equity-method investments . Our Net cash provided (used) by operating activities for the six months ended June 30, 2018 , decreased from the same period in 2017 primarily due to the impact of net unfavorable changes in operating working capital and decreased distributions from unconsolidated affiliates in 2018, partially offset by higher operating income in 2018.

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

We have various other guarantees and commitments which are disclosed in Note 3 – Variable Interest Entities , Note 6 – Debt and Banking Arrangements , Note 8 – Fair Value Measurements and Guarantees , and Note 9 – Contingent Liabilities of Notes to Consolidated Financial Statements. We do not believe these guarantees and commitments or the possible fulfillment of them will prevent us from meeting our liquidity needs.

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Item 3

Quantitative and Qualitative Disclosures About Market Risk

Interest Rate Risk

Our current interest rate risk exposure is related primarily to our debt portfolio and has not materially changed during the first six months of 2018 .

Item 4

Controls and Procedures

Our management, including our general partner’s Chief Executive Officer and Chief Financial Officer, does not expect that our disclosure controls and procedures (as defined in Rules 13a - 15(e) and 15d - 15(e) of the Securities Exchange Act of 1934, as amended) (Disclosure Controls) or our internal control over financial reporting (Internal Controls) will prevent all errors and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within the partnership have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty, and that breakdowns can occur because of simple error or mistake. Additionally, controls can be circumvented by the individual acts of some persons, by collusion of two or more people, or by management override of the control. The design of any system of controls also is based in part upon certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions. Because of the inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and not be detected. We monitor our Disclosure Controls and Internal Controls and make modifications as necessary; our intent in this regard is that the Disclosure Controls and Internal Controls will be modified as systems change and conditions warrant.

Evaluation of Disclosure Controls and Procedures

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

Changes in Internal Control Over Financial Reporting

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

PART II. OTHER INFORMATION

Item 1. Legal Proceedings

Environmental

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

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

On February 21, 2017, we received notice from the Environmental Enforcement Section of the United States Department of Justice (DOJ) regarding certain alleged violations of the Clean Air Act at our Moundsville facility as set forth in a Notice of Noncompliance issued by the EPA on January 14, 2016. The notice includes an offer to avoid further legal action on the alleged violations by paying $2 million. In discussion with the DOJ and the EPA, the EPA has indicated its belief that additional similar violations have occurred at our Oak Grove facility and has expressed interest in pursuing a global settlement. On July 23, 2018, we received an offer from the DOJ to globally settle the government’s claim for civil penalties associated with the alleged violations at both the Moundsville and the Oak Grove facilities for $1.6 million. We are evaluating the agencies’ offer.

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

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

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

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

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

Other Litigation

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

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Item 1A. Risk Factors

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

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

In May 2005, the FERC issued a statement of general policy permitting a pipeline to include in its cost-of-service computations an income tax allowance provided that an entity or individual has an actual or potential income tax liability on income from the pipeline’s public utility assets. Pursuant to that policy, the extent to which owners of pipelines have such actual or potential income tax liability will be reviewed by the FERC on a case-by-case basis in rate cases where the amounts of the allowances will be established. On March 15, 2018, the FERC 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 an MLP pipeline both an income tax allowance and a return on equity pursuant to the discounted cash flow methodology. As a result, the FERC will no longer permit an MLP pipeline to recover an income tax allowance in its cost of service and further stated it will address the application of this policy to non-MLP partnership forms as those issues arise in subsequent proceedings.

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.

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 as a result of Tax Reform and the FERC’s revised policy statement regarding MLPs. On July 18, 2018, the FERC issued a Final Rule in the docket, retaining the filing process and reaffirming the options that pipelines have to either reflect the reduced tax rate or explain why no rate change is necessary. FERC also clarified that a natural gas company organized as a pass-through entity 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, and whether other features of Tax Reform require FERC action. Due to the foregoing, it is reasonably possible that future tariff-based rates collected by our interstate natural gas pipelines may be negatively impacted by such actions, which may have a material adverse effect on our business, financial condition, results of operations, and cash flows.

The WPZ Merger is subject to closing conditions that, if not satisfied or waived, will result in the WPZ Merger not being consummated, which may cause the market price of our common units and/or Williams common stock to decline.

The obligation of the parties to the WPZ Merger Agreement to complete the WPZ Merger is subject to the satisfaction or waiver of certain conditions, some of which remain outstanding, including:

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•	The delivery of the joint consent statement/proxy statement/prospectus to holders of WPZ Units at least 20 business days prior to the closing;

•	The delivery of the written consent in which WPZ unit holders holding a majority of the WPZ Units outstanding approve and adopt the WPZ Merger Agreement and the WPZ Merger in accordance with applicable law;

•	The effectiveness of the registration statement of which the joint consent statement/proxy statement/prospectus forms a part;

•	The approval for listing on the NYSE of the Williams common stock to be issued in the WPZ Merger, subject to official notice of issuance;

•	The absence of any decree, order, injunction, or law that prohibits the WPZ Merger or makes the WPZ Merger unlawful;

•	The approval by Williams stockholders of (i) the Charter Amendment and (ii) the issuance of Williams common stock in the WPZ Merger pursuant to the WPZ Merger Agreement, each having been obtained in accordance with applicable law and Williams’ governing documents.

The parties’ obligations are also separately subject to the satisfaction or waiver of the following conditions:

•	Certain fundamental representations and warranties of the other party relating to organization and existence, authorization to enter into the WPZ Merger Agreement and to complete the transactions contemplated thereby, and capitalization being true and correct as of the closing in all material respects;

•	The representations and warranties of the other party relating to the absence of changes that would have a material adverse effect on such party and the absence of material damage, destruction, or loss to any material portion of assets of such party or its subsidiaries being true and correct as of the closing;

•	All other representations and warranties of the other party being true and correct as of the closing, other than certain failures to be true and correct that would not in the aggregate result in a material adverse effect on the party making the representation or warranty;

•	The other party having performed or complied with all agreements and covenants required to be performed by it under the WPZ Merger Agreement in all material respects.

If these conditions are not satisfied or waived, the WPZ Merger will not occur, which may cause the market price of our common units and/or Williams common stock to decline.

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Item 6. Exhibits

Exhibit No.				Description
2.1§		—		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 (filed on May 17, 2018 as Exhibit 2.1 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-34831) and incorporated herein by reference).
2.2§		—		Membership Interest Purchase Agreement, dated as of April 13, 2017, among Williams Field Services Group, LLC, Williams Partners L.P., Williams Olefins, L.L.C., NOVA Chemicals Inc., and NOVA Chemicals Corporation (filed on August 3, 2017 as Exhibit 2.2 to Williams Partners L.P.’s quarterly report on Form 10-Q (File No. 001-34831) and incorporated herein by reference).
3.1		—		Certificate of Limited Partnership of Chesapeake Midstream Partners, L.P. (filed on February 16, 2010 as Exhibit 3.1 to Williams Partners L.P.’s registration statement on Form S-1 (File No. 333-164905) and incorporated herein by reference).
3.2		—		Amendment to Certificate of Limited Partnership of Chesapeake Midstream Partners, L.P. (filed on July 30, 2012 as Exhibit 3.1 to Williams Partners L.P.’s current report on Form 8‑K (File No. 001-34831) and incorporated herein by reference).
3.3		—		Amendment to Certificate of Limited Partnership of Access Midstream Partners, L.P. (filed on February 3, 2015 as Exhibit 3.5 to Williams Partners L.P.’s current report on Form 8‑K (File No. 001-34831) and incorporated herein by reference).
3.4		—		Composite Certificate of Limited Partnership of Williams Partners L.P. (filed on February 25, 2015 as Exhibit 3.4 to Williams Partners L.P.’s annual report on Form 10-K (File No. 001-34831) and incorporated herein by reference).
3.5		—		Second Amended and Restated Agreement of Limited Partnership of Williams Partners L.P., dated as of February 1, 2018 (filed on February 1, 2018 as Exhibit 3.1 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-34831) and incorporated herein by reference).
3.6		—		Certificate of Formation of Chesapeake Midstream GP, L.L.C. (filed on February 16, 2010 as Exhibit 3.3 to Williams Partners L.P.’s registration statement on Form S-1 (File No. 333-164905) and incorporated herein by reference).
3.7		—		Certificate of Amendment to Certificate of Formation of Chesapeake Midstream GP, L.L.C. (filed on July 30, 2012 as Exhibit 3.5 to Williams Partners L.P.’s current report on Form 8‑K (File No. 001-34831) and incorporated herein by reference).
3.8		—		Certificate of Amendment of Certificate of Formation of Access Midstream Partners GP, L.L.C. (filed on February 3, 2015 as Exhibit 3.2 to Williams Partners L.P.’s current report on Form 8‑K (File No. 001-34831) and incorporated herein by reference).
3.9		—		Composite Certificate of Formation of WPZ GP LLC (filed on February 25, 2015 as Exhibit 3.14 to Williams Partners L.P.’s annual report on Form 10-K (File No. 001-34831) and incorporated herein by reference).
3.10		—		Eighth Amended and Restated Limited Liability Company Agreement of WPZ GP LLC (filed on August 2, 2016 as Exhibit 3.17 to Williams Partners L.P.’s quarterly report on Form 10-Q (File No. 001-34831) and incorporated herein by reference).
12*		—		Computation of Ratio of Earnings to Fixed Charges.
31.1*		—		Certification of Chief Executive Officer pursuant to Rules 13a-14(a) and 15d-14(a) promulgated under the Securities Exchange Act of 1934, as amended, and Item 601(b)(31) of Regulation S-K, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

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Exhibit No.				Description
31.2*		—		Certification of Chief Financial Officer pursuant to Rules 13a-14(a) and 15d-14(a) promulgated under the Securities Exchange Act of 1934, as amended, and Item 601(b)(31) of Regulation S-K, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32**		—		Certification of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS*		—		XBRL Instance Document.
101.SCH*		—		XBRL Taxonomy Extension Schema.
101.CAL*		—		XBRL Taxonomy Extension Calculation Linkbase.
101.DEF*		—		XBRL Taxonomy Extension Definition Linkbase.
101.LAB*		—		XBRL Taxonomy Extension Label Linkbase.
101.PRE*		—		XBRL Taxonomy Extension Presentation Linkbase.

*	Filed herewith.

**	Furnished herewith.

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

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SIGNATURE

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

		W ILLIAMS  P ARTNERS  L.P.
		(Registrant)
	By:	WPZ GP LLC, its general partner
		/s/ T ED  T. T IMMERMANS
		Ted T. Timmermans
		Vice President, Controller and Chief Accounting Officer (Duly Authorized Officer and Principal Accounting Officer)

August 2, 2018