10-Q

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended June 30, 2018

OR

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

For the transition period from to

Commission file number 1-7584

TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC

(Exact name of registrant as specified in its charter)

DELAWARE	74-1079400
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
2800 POST OAK BOULEVARD HOUSTON, TEXAS	77056
(Address of principal executive offices)	(Zip Code)

Registrant’s telephone number, including area code: (713) 215-2000

NO CHANGE

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

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

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

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

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

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

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

REGISTRANT MEETS THE CONDITIONS SET FORTH IN GENERAL INSTRUCTIONS H (1)(a) AND (b) OF FORM 10-Q AND IS THEREFORE FILING THIS FORM 10-Q WITH THE REDUCED DISCLOSURE FORMAT.

TRANSCONTINTENTAL GAS PIPE LINE COMPANY, LLC

Index

	Page
Part I. Financial Information:
Item 1. Financial Statements
Condensed Consolidated Statement of Comprehensive Income —Three and Six Months Ended June 30, 2018 and 2017	4
Condensed Consolidated Balance Sheet — June 30, 2018 and December 31, 2017	5
Condensed Consolidated Statement of Cash Flows — Six Months Ended June 30, 2018 and 2017	7
Notes to Condensed Consolidated Financial Statements	8
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	19
Item 4. Controls and Procedures	23
Part II. Other Information	23
Item 1. Legal Proceedings	23
Item 1A. Risk Factors	24
Item 6. Exhibits	25

Forward Looking Statements

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

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

• Our and our affiliates’ future credit ratings;

• Amounts and nature of future capital expenditures;

• Expansion and growth of our business and operations;

• Expected in-service dates for capital projects;

• Financial condition and liquidity;

• Business strategy;

• Cash flow from operations or results of operations;

• Rate case filings;

• Natural gas prices, supply and demand; and

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• Demand for our services.

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

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

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

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

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

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

• Our ability to successfully expand our facilities and operations;

• Development and rate of adoption of alternative energy sources;

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

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

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

• Changes in maintenance and construction costs;

• Changes in the current geopolitical situation;

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

• Risks related to financing, including restrictions stemming from our debt agreements, future changes in our credit ratings and the availability and cost of capital;

• 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; and

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

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

In addition to causing our actual results to differ, the factors listed above and referred to below may cause our intentions to change from those statements of intention set forth in this report. Such changes in our intentions may also

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cause our results to differ. We may change our intentions, at any time and without notice, based upon changes in such factors, our assumptions, or otherwise.

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

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PART I — FINANCIAL INFORMATION

ITEM 1. Financial Statements.

TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC

CONDENSED CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME

(Thousands of Dollars)

(Unaudited)

	Three months ended   June 30,						Six months ended   June 30,
	2018			2017			2018			2017
Operating Revenues:
Natural gas sales	$	29,873		$	33,009		$	55,124		$	48,104
Natural gas transportation	415,708			365,246			842,286			727,811
Natural gas storage	33,786			33,935			68,553			68,824
Other	2,308			312			4,948			1,479
Total operating revenues	481,675			432,502			970,911			846,218
Operating Costs and Expenses:
Cost of natural gas sales	29,873			33,009			55,124			48,104
Cost of natural gas transportation	8,461			4,447			21,535			9,454
Operation and maintenance	93,659			82,100			180,675			154,813
Administrative and general	46,981			44,794			93,362			88,910
Depreciation and amortization	89,282			79,064			172,506			156,542
Taxes — other than income taxes	17,164			16,890			35,602			33,798
Regulatory credit resulting from Tax Reform (Note 1)	(20,867		)	—			(20,867		)	—
Other expense, net	12,564			14,415			30,405			29,637
Total operating costs and expenses	277,117			274,719			568,342			521,258
Operating Income	204,558			157,783			402,569			324,960
Other (Income) and Other Expenses:
Interest expense	53,375			37,236			98,449			74,493
Allowance for equity and borrowed funds used during construction (AFUDC)	(34,895		)	(25,419		)	(61,503		)	(48,449		)
Equity in (earnings) losses of unconsolidated affiliates	(1,325		)	(1,389		)	265			(2,410		)
Miscellaneous other (income) expenses, net	(4,819		)	(4,313		)	(6,780		)	(5,198		)
Total other (income) and other expenses	12,336			6,115			30,431			18,436
Net Income	192,222			151,668			372,138			306,524
Other comprehensive income:
Equity interest in unrealized gain on interest rate hedges (includes $(33) and $22 for the three months ended and $(27) and $37 for the six months ended June 30, 2018 and June 30, 2017, respectively, of accumulated other comprehensive income reclassification for equity interest in realized losses (gains) on interest rate hedges)	119			1			524			36
Comprehensive Income	$	192,341		$	151,669		$	372,662		$	306,560

See accompanying notes.

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TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC

CONDENSED CONSOLIDATED BALANCE SHEET

(Thousands of Dollars)

(Unaudited)

	June 30, 2018		December 31, 2017
ASSETS
Current Assets:
Cash	$	—	$	—
Receivables:
Affiliates	809		1,109
Advances to affiliate	589,133		395,247
Trade and other	165,369		170,422
Transportation and exchange gas receivables	8,137		3,205
Inventories	59,821		40,027
Regulatory assets	107,853		97,149
Other	17,880		12,508
Total current assets	949,002		719,667
Investments, at cost plus equity in undistributed earnings	27,833		28,505
Property, Plant and Equipment:
Natural gas transmission plant	15,215,789		13,771,183
Less-Accumulated depreciation and amortization	4,005,315		3,859,520
Total property, plant and equipment, net	11,210,474		9,911,663
Other Assets:
Regulatory assets	283,986		276,315
Other	161,828		141,786
Total other assets	445,814		418,101
Total assets	$	12,633,123	$	11,077,936

(continued)

See accompanying notes.

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TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC

CONDENSED CONSOLIDATED BALANCE SHEET

(Thousands of Dollars)

(Unaudited)

	June 30, 2018		December 31, 2017
LIABILITIES AND MEMBER’S EQUITY
Current Liabilities:
Payables:
Affiliates	$	33,356	$	43,420
Trade and other	425,033		469,153
Transportation and exchange gas payables	3,411		2,121
Accrued liabilities	188,822		173,602
Long-term debt due within one year	1,642		251,430
Total current liabilities	652,264		939,726
Long-Term Debt	3,199,991		2,191,576
Other Long-Term Liabilities:
Asset retirement obligations	352,379		350,280
Regulatory liabilities	991,895		990,702
Advances for construction costs	739,953		426,771
Deferred revenue	231,450		236,729
Other	5,205		4,828
Total other long-term liabilities	2,320,882		2,009,310
Contingent Liabilities and Commitments (Note 3)
Member’s Equity:
Member’s capital	4,428,499		4,088,499
Retained earnings	2,030,626		1,848,488
Accumulated other comprehensive income	861		337
Total member’s equity	6,459,986		5,937,324
Total liabilities and member’s equity	$	12,633,123	$	11,077,936

See accompanying notes.

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TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC

CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS

(Thousands of Dollars)

(Unaudited)

	Six months ended June 30,
	2018			2017
Cash flows from operating activities:
Net income	$	372,138		$	306,524
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Depreciation and amortization	172,506			156,542
Allowance for equity funds used during construction (equity AFUDC)	(45,910		)	(37,260		)
Regulatory credit resulting from Tax Reform (Note 1)	(20,867		)	—
Equity in (earnings) losses of unconsolidated affiliates	265			(2,410		)
Distributions from unconsolidated affiliates	931			4,848
Changes in operating assets and liabilities:
Receivables — affiliates	300			(33		)
— trade and other	5,053			1,789
Transportation and exchange gas receivable	(4,932		)	(1,282		)
Inventories	(19,794		)	(20,674		)
Payables — affiliates	(10,686		)	4,134
— trade	(30,052		)	(1,467		)
Accrued liabilities	15,719			(29,703		)
Asset retirement obligations - non-current	23,230			19,977
Asset retirement obligations - removal costs	(4,013		)	(1,212		)
Deferred revenue	(5,279		)	(479		)
Other, net	(12,222		)	10,719
Net cash provided by operating activities	436,387			410,013
Cash flows from financing activities:
Proceeds from long-term debt	993,440			—
Proceeds from other financing obligation	24,298			—
Retirement of long-term debt	(250,000		)	—
Payments on other financing obligation	(758		)	—
Payments for debt issuance costs	(9,208		)	(13		)
Cash distributions to parent	(190,000		)	(210,000		)
Cash contributions from parent	340,000			110,000
Net cash provided by (used in) financing activities	907,772			(100,013		)
Cash flows from investing activities:
Property, plant and equipment additions, net of equity AFUDC*	(1,463,600		)	(740,079		)
Contributions and advances for construction costs	337,874			194,108
Disposal of property, plant and equipment, net	(7,477		)	(20,843		)
Advances to affiliate, net	(193,886		)	270,641
Purchase of ARO Trust investments	(36,807		)	(32,290		)
Proceeds from sale of ARO Trust investments	19,737			15,263
Proceeds from insurance	—			3,200
Net cash used in investing activities	(1,344,159		)	(310,000		)
Increase (decrease) in cash	—			—
Cash at beginning of period	—			—
Cash at end of period	$	—		$	—
*       Increase to property, plant and equipment, net of equity AFUDC	$	(1,434,519	)	$	(807,408	)
Changes in related accounts payable and accrued liabilities	(29,081		)	67,329
Property, plant and equipment additions, net of equity AFUDC	$	(1,463,600	)	$	(740,079	)

See accompanying notes.

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TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1. BASIS OF PRESENTATION

In this report, Transco (which includes Transcontinental Gas Pipe Line Company, LLC and, unless the context otherwise requires, all of our majority-owned subsidiaries) is at times referred to in the first person as “we,” “us” or “our.”

Transco is indirectly owned by Williams Partners L.P. (WPZ), a publicly traded Delaware limited partnership, which is consolidated by The Williams Companies, Inc. (Williams). On May 16, 2018, WPZ entered into an agreement for a stock-for-unit transaction whereby Williams will acquire all of WPZ's 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 WPZ a $410 million termination fee. Williams currently owns approximately 74 percent limited partner interest in WPZ.

General

The condensed consolidated unaudited financial statements include our accounts and the accounts of the subsidiaries we control. Companies in which we and our subsidiaries own 20 percent to 50 percent of the voting common stock or otherwise exercise significant influence over operating and financial policies of the company are accounted for under the equity method. The equity method investments as of June 30, 2018 and December 31, 2017 consist of Cardinal Pipeline Company, LLC (Cardinal) with an ownership interest of approximately 45 percent and Pine Needle LNG Company, LLC (Pine Needle) with an ownership interest of 35 percent. We received distributions associated with our equity method investments totaling $0.9 million and $4.8 million in the six months ended June 30, 2018 and June 30, 2017, respectively.

The condensed consolidated unaudited financial statements have been prepared from our books and records. Certain information and footnote disclosures normally included in financial statements prepared in accordance with U.S. generally accepted accounting principles (GAAP) have been condensed or omitted in this Form 10-Q pursuant to Securities and Exchange Commission rules and regulations. The condensed consolidated unaudited financial statements include all normal recurring adjustments and others which, in the opinion of our management, are necessary to present fairly our interim financial statements. These condensed consolidated unaudited financial statements should be read in conjunction with the consolidated financial statements and the notes thereto included in our 2017 Annual Report on Form 10-K.

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the amounts reported in the condensed consolidated unaudited financial statements and accompanying notes. Actual results could differ from those estimates.

Regulatory Accounting

In December 2017, the Tax Cuts and Jobs Act (Tax Reform) was enacted, which, among other things, reduced the federal corporate income tax rate from 35 percent to 21 percent . In accordance with ASC 980-740-25-2, we have recognized a regulatory liability to reflect the probable return to certain customers through future rates of the future decrease in income taxes payable associated with Tax Reform. In determining the estimated liability that we currently believe is probable of return to certain customers through future rates, we considered the mix of services provided by us, taking into consideration that certain of these services are provided under fixed negotiated rates, in lieu of cost-based recourse rates, that are designed to recover the cost of providing those services, with no expected future rate adjustment for the term of those contracts. The liability was recorded in December 2017 through a regulatory charge to operating income of $471.1 million. At the end of our rate case base period at May 2018, we recorded a reduction to the liability of $20.9 million mostly due to an updated weighted average state income tax rate. The timing and actual

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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.

Accounting Standards Issued and Adopted

Effective January 1, 2018, we adopted Accounting Standards Update (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 Condensed Consolidated Statement of Cash Flows in accordance with ASU 2016-15. For the period ended June 30, 2017, amounts previously presented as Return of capital from unconsolidated affiliates within Investing Activities are now presented as part of Distributions from unconsolidated affiliates within Operating Activities, resulting in an increase to Net cash provided by operating activities of $2.1 million with a corresponding reduction in Net cash used in investing activities.

In May 2014, the Financial Accounting Standards Board (FASB) issued ASU 2014-09 establishing Accounting Standards Codification (ASC) Topic 606, “Revenue from Contracts with Customers” (ASC 606). ASC 606 establishes a comprehensive new revenue recognition model designed to depict the transfer of goods or services to a customer in an amount that reflects the consideration 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. There was no cumulative effect adjustment to retained earnings upon initially applying ASC 606 for periods prior to January 1, 2018.

For each revenue contract type, we conducted a formal contract review process to evaluate the impact of ASC 606. As a result of the adoption of ASC 606, there are no changes to the timing of our revenue recognition or differences in the presentation in our condensed consolidated financial statements from those under the previous revenue standard (See Note 2).

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. ASU 2016-13 requires varying transition methods for the different categories of amendments. We do not expect ASU 2016-13 to have a significant impact on our consolidated financial statements.

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

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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 significant changes to our financial statements relate to the recognition of a lease liability and offsetting right-of-use asset in our Condensed Consolidated Balance Sheet for operating leases. We are also evaluating ASU 2016-02's available practical expedients on adoption, which we expect to elect.

2. REVENUE RECOGNITION

Our customers are comprised of public utilities, municipalities, gas marketers and producers, intrastate pipelines, direct industrial users, and electrical generators.

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 product or 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. Service revenue contracts 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. As a rate-regulated entity applying ASC 980 "Regulated Operations" (Topic 980), we follow Federal Energy Regulatory Commission (FERC) guidelines with respect to reimbursement of construction costs. FERC tariffs only allow for cost reimbursement and are non-negotiable in nature; thus, the construction activities do not represent an ongoing major and central operation of our gas pipelines business and are not within the scope of ASC 606. Accordingly, cost reimbursements are treated as a reduction to the cost of the constructed asset.

Service Revenues

We are subject to regulation by certain state and federal authorities, including the FERC, with revenue derived from 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 as negotiated with our customers, 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 include the following:

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• 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 the integrated package of services a single performance obligation, which represents a majority of our 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 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.

Product Sales

In the course of providing transportation services to customers, 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. Revenue is recognized from the sale of natural gas upon settlement of the transportation and exchange imbalances.

Revenue by Category

Our revenue disaggregation by major service line includes Natural gas sales, Natural gas transportation, Natural gas storage, and Other, which are separately presented on the Condensed Consolidated Statement of Comprehensive Income.

Contract Liabilities

Our contract liabilities consist of advance payments from customers, which include 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 straight-line over the remaining contractual service periods, and are classified as current or non-current according to when such amounts are expected to be recognized. Current and non-current contract liabilities are included within Accrued Liabilities and Other Long-Term Liabilities - Deferred revenue, respectively, in our Condensed 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 and when the customer pays for those goods or services and the prevailing interest rates. We have assessed our contracts and determined none of our contracts contain a significant financing component.

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The following table presents a reconciliation of our contract liabilities:

	Quarter to Date June 30, 2018			Year to Date June 30, 2018
	(Thousands)
Balance at beginning of period	$	244,658		$	247,296
Payments received and deferred	—			—
Recognized in revenue	(2,641		)	(5,279		)
Balance at end of period	$	242,017		$	242,017

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:

	(Thousands)
2018 (remainder)	$	5,287
2019	10,566
2020	10,568
2021	10,566
2022	10,566
2023	10,566
Thereafter	183,898

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 reservation charges on contracted capacity on our firm transportation and storage contracts with customers. Amounts from certain contracts included in the table below, which are subject to the periodic review and approval by the FERC, 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 the variable consideration component for commodity charges. It also excludes consideration 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 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.

	(Thousands)
2018 (remainder)	$	850,434
2019	1,618,612
2020	1,515,147
2021	1,309,562
2022	1,116,179
2023	982,445
Thereafter	8,493,236
Total	$	15,885,615

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. Our credit risk exposure in the event of nonperformance by the other parties is limited to the face value of the receivables. We perform ongoing credit evaluations

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of our customers' financial condition and require collateral from our customers, if necessary. Due to our customer base, we have not historically experienced recurring credit losses in connection with our receivables.

Receivables from contracts with customers are included within Receivables - Trade and other and Receivables - Affiliates and receivables that are not related to contracts with customers are included with Receivables - Advances to affiliate in our Condensed Consolidated Balance Sheet. At June 30, 2018 and January 1, 2018, Receivables - Trade and other includes $6.9 million and $2.5 million, respectively, of receivables not related to contracts with customers.

3. CONTINGENT LIABILITIES AND COMMITMENTS

Rate Matters

On March 15, 2018, the FERC issued a revised policy statement in Docket No. PL17-1 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 a 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 fact 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 in Docket No. RM18-11 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 Tax Reform and the revised policy statement. On July 18, 2018, the FERC issued a Final Rule in the docket, 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. 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 in Docket No. RM18-12 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 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 our future tariff-based rates collected may be adversely impacted.

Station 62 Incident

On October 8, 2015, an explosion and fire occurred at our Compressor Station No. 62 in Gibson, Louisiana. At the time of the incident, planned facility maintenance was being performed at the station and the facility was not operational. The incident was related to maintenance work being performed on the slug catcher at the station. Four contractor employees were killed in the incident and others were injured.

In responding to the incident, we cooperated with local, state and federal authorities, including the Louisiana State Police, Terrebonne Parish, the Louisiana Department of Environmental Quality, the U.S. Environmental Protection

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Agency (Region 6), the Occupational Safety and Health Administration, and the U.S. Department of Transportation's Pipeline and Hazardous Materials Safety Administration (PHMSA). On July 29, 2016, PHMSA issued a Notice of Probable Violation (NOPV), which includes a $1.6 million proposed civil penalty to us in connection with the incident. This penalty was accrued in the second quarter of 2016 and would not be covered by our insurance policies. We filed a response to the NOPV on August 25, 2016, and on July 14, 2017, PHMSA held a hearing on the NOPV.

The incident did not cause any rupture of the gas pipeline or any damage to the building containing the compressor engines. In anticipation of the planned maintenance, our Southeast Louisiana Lateral was taken out of service on October 4, 2015, which affected approximately 200 MMcf/d of natural gas production. The lateral was restored to service in early 2016 after repairs were made to the facilities damaged in the incident.

We are a defendant in lawsuits seeking damages for wrongful death, personal injury and property damages. We believe it is reasonably possible that losses will be incurred on some lawsuits. However, in management's judgment, the ultimate resolution of these matters will not have a material effect on our financial condition, results of operations or cash flows. While we also have claims for indemnification, we believe that it is probable that any ultimate losses incurred will be covered by our contractors' insurance and our insurance.

Environmental Matters

We have had studies underway for many years to test some of our facilities for the presence of toxic and hazardous substances such as polychlorinated biphenyls (PCBs) and mercury to determine to what extent, if any, remediation may be necessary. We have also similarly evaluated past on-site disposal of hydrocarbons at a number of our facilities. We have worked closely with and responded to data requests from the U.S. Environmental Protection Agency (EPA) and state agencies regarding such potential contamination of certain of our sites. On the basis of the findings to date, we estimate that environmental assessment and remediation costs under various federal and state statutes will total approximately $6 million to $8 million (including both expense and capital expenditures), measured on an undiscounted basis, and will substantially be spent over the next four to six years. This estimate depends on a number of assumptions concerning the scope of remediation that will be required at certain locations and the cost of the remedial measures. We are conducting environmental assessments and implementing a variety of remedial measures that may result in increases or decreases in the total estimated costs. At June 30, 2018, we had a balance of approximately $3.7 million for the expense portion of these estimated costs, $1.8 million recorded in Accrued liabilities and $1.9 million recorded in Other Long-Term Liabilities - Other in the accompanying Condensed Consolidated Balance Sheet. At December 31, 2017, we had a balance of approximately $4.0 million for the expense portion of these estimated costs, $1.8 million recorded in Accrued liabilities and $2.2 million recorded in Other Long-Term Liabilities - Other in the accompanying Condensed Consolidated Balance Sheet.

We have been identified as a potentially responsible party (PRP) at various Superfund and state waste disposal sites. Based on present volumetric estimates and other factors, our estimated aggregate exposure for remediation of these sites is less than $0.5 million. The estimated remediation costs for all of these sites are included in the $6 million to $8 million range discussed above. Liability under the Comprehensive Environmental Response, Compensation and Liability Act and applicable state law can be joint and several with other PRPs. Although volumetric allocation is a factor in assessing liability, it is not necessarily determinative; thus, the ultimate liability could be substantially greater than the amounts described above.

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

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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.

We consider prudently incurred environmental assessment and remediation costs and the costs associated with compliance with environmental standards to be recoverable through rates. To date, we have been permitted recovery of environmental costs, and it is our intent to continue seeking recovery of such costs through future rate filings. As a result, as estimated costs of environmental assessment and remediation are incurred, they are recorded as regulatory assets in the Condensed Consolidated Balance Sheet until collected through rates. At June 30, 2018, we had a balance of approximately $1.6 million of uncollected environmental related regulatory assets, $1.2 million recorded in Current Assets - Regulatory assets and $0.4 million recorded in Other Assets - Regulatory assets in the accompanying Condensed Consolidated Balance Sheet. At December 31, 2017, we had a balance of approximately $2.2 million of uncollected environmental related regulatory assets, $1.2 million recorded in Current Assets - Regulatory assets and $1.0 million recorded in Other Assets - Regulatory assets in the accompanying Condensed Consolidated Balance Sheet.

Other Matters

Various other proceedings are pending against us and are considered incidental to our operations.

Summary

We estimate that for all matters for which we are able to reasonably estimate a range of loss, including those noted above and others that are not individually significant, our aggregate reasonably possible losses beyond amounts accrued for all of our contingent liabilities 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. We have disclosed all significant matters for which we are unable to reasonably estimate a range of possible loss.

4. DEBT AND FINANCING ARRANGEMENTS

Credit Facility

We along with WPZ and Northwest Pipeline LLC (Northwest Pipeline), are party to a credit facility with aggregate commitments available of $3.5 billion, with up to an additional $500 million increase in aggregate commitments available under certain circumstances. Total letter of credit capacity available to WPZ under this credit facility is $1.125 billion. We are able to borrow up to $500 million under this credit facility to the extent not otherwise utilized by the other co-borrowers. At June 30, 2018, no letters of credit have been issued and no loans were outstanding under the credit facility.

WPZ participates in a commercial paper program, and WPZ management considers amounts outstanding under this program to be a reduction of available capacity under the credit facility. The program allows a maximum outstanding amount at any time of $3 billion of unsecured commercial paper notes. At June 30, 2018, WPZ had no commercial paper outstanding under the commercial paper program.

During July 2018, in anticipation of the WPZ Merger closing, Williams entered into a new $4.5 billion unsecured revolving credit agreement (Credit Agreement) that includes us and Northwest Pipeline as co-borrowers. The full amount of the credit facility will be available to Williams to the extent not utilized by us and Northwest Pipeline. Both Transco and Northwest Pipeline will have access up to $500 million under this Credit Agreement. The Credit Agreement will become effective upon closing of the WPZ Merger and will be initially available for five years from the Credit Agreement effective date.

Other Financing Obligation

During the first six months of 2018, we received an additional $24.3 million of funding from a co-owner for its proportionate share of construction costs related to its undivided ownership interest in the Dalton lateral. This additional funding is reflected in Long-Term Debt on our Condensed Consolidated Balance Sheet. At June 30, 2018, the amount included in Long-Term Debt on our Condensed Consolidated Balance Sheet for this financing obligation is $252.8

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million, and the amount included in Long-term debt due within one year on our Condensed Consolidated Balance Sheet for this financing obligation is $1.6 million.

Issuance and Retirement of Long-Term Debt

On March 15, 2018, we issued $400 million of 4.0 percent senior unsecured notes due 2028 and $600 million of 4.6 percent senior unsecured notes due 2048 to investors in a private placement. We used the net proceeds to retire our $250 million of 6.05 percent senior unsecured notes due June 2018, and for general purposes, including the funding of capital expenditures. As part of the issuance, we entered into a registration rights agreement with the initial purchasers of the unsecured notes. We are 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. We are required to provide a shelf registration statement to cover resales of the notes under certain circumstances. If we fail 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.

5. ARO TRUST

We are entitled to collect in rates the amounts necessary to fund our asset retirement obligations (ARO). We deposit monthly, into an external trust account (ARO Trust), the revenues specifically designated for ARO. The ARO Trust carries a moderate risk portfolio. We measure the financial instruments held in our ARO Trust at fair value. However, in accordance with the ASC Topic 980, Regulated Operations, both realized and unrealized gains and losses of the ARO Trust are recorded as regulatory assets or liabilities.

Effective March 1, 2013, the annual funding obligation is approximately $36.4 million, with deposits made monthly.

Investments within the ARO Trust at fair value were as follows (in millions):

	June 30, 2018				December 31, 2017
	Amortized Cost Basis		Fair Value		Amortized Cost Basis		Fair Value
Cash and Money Market Funds	$	14.7	$	14.7	$	12.6	$	12.6
U.S. Equity Funds	46.3		62.5		35.9		50.5
International Equity Funds	21.9		24.5		20.7		24.6
Municipal Bond Funds	50.1		49.6		46.8		46.9
Total	$	133.0	$	151.3	$	116.0	$	134.6

6. FAIR VALUE MEASUREMENTS

The following table presents, by level within the fair value hierarchy, certain of our financial assets and liabilities. The carrying values of cash, short-term financial assets (advances to affiliate) that have variable interest rates, 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.

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							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	$	151.3		$	151.3		$	151.3	$	—		$	—
Additional disclosures:
Long-term debt, including current portion	(3,201.6		)	(3,638.9		)	—		(3,638.9		)	—
Assets (liabilities) at December 31, 2017:
Measured on a recurring basis:
ARO Trust investments	$	134.6		$	134.6		$	134.6	$	—		$	—
Additional disclosures:
Long-term debt	(2,443.0		)	(3,103.3		)	—		(3,103.3		)	—

Fair Value Methods

The following methods and assumptions were used to estimate the fair value of each class of financial instruments for which it is practicable to estimate that value:

ARO Trust investments — We deposit a portion of our collected rates, pursuant to the terms of the Docket No. RP12-993 rate case settlement, into the ARO Trust which is specifically designated to fund future asset retirement obligations. 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 are reported in Other Assets-Other in the Condensed Consolidated Balance Sheet. However, both realized and unrealized gains and losses are ultimately recorded as regulatory assets or liabilities. See Note 5 for more information regarding the ARO Trust.

Long-term debt — 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. The fair value of the financing obligation associated with our Dalton lateral, which is included within long-term debt, was determined using an income approach (See Note 4 - Debt and Financing Arrangements).

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.

7. TRANSACTIONS WITH AFFILIATES

We are a participant in WPZ’s cash management program, and we make advances to and receive advances from WPZ. At June 30, 2018 and December 31, 2017, our advances to WPZ totaled approximately $589.1 million and $395.2 million, respectively. These advances are represented by demand notes and are classified as Receivables - Advances to affiliate in the accompanying Condensed Consolidated Balance Sheet. Advances are stated at the historical carrying amounts. Interest income is recognized when chargeable and collectability is reasonably assured. The interest rate on these intercompany demand notes is based upon the daily overnight investment rate paid on WPZ’s excess cash at the end of each month. At June 30, 2018, the interest rate was 1.80 percent.

Included in Operating Revenues in the accompanying Condensed Consolidated Statement of Comprehensive Income are revenues received from affiliates of $1.5 million and $3.3 million for the three and six months ended June 30, 2018, respectively, and $3.1 million and $6.4 million for the three and six months ended June 30, 2017, respectively.

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The rates charged to provide sales and services to affiliates are the same as those that are charged to similarly-situated nonaffiliated customers.

Included in Cost of natural gas sales in the accompanying Condensed Consolidated Statement of Comprehensive Income are cost of gas purchased from affiliates of $1.8 million and $3.7 million for the three and six months ended June 30, 2018, respectively, and $0.8 million and $1.9 million for the three and six months ended June 30, 2017, respectively. All gas purchases are made at market or contract prices.

We have no employees. Services necessary to operate our business are provided to us by Williams and certain affiliates of Williams. We reimburse Williams and its affiliates for all direct and indirect expenses incurred or payments made (including salary, bonus, incentive compensation and benefits) in connection with these services. Employees of Williams also provide general, administrative and management services to us, and we are charged for certain administrative expenses incurred by Williams. These charges are either directly identifiable or allocated to our assets. Direct charges are for goods and services provided by Williams at our request. Allocated charges are based on a three-factor formula, which considers revenues; property, plant and equipment; and payroll. In management’s estimation, the allocation methodologies used are reasonable and result in a reasonable allocation to us of our costs of doing business incurred by Williams. We were billed $99.3 million and $190.8 million in the three and six months ended June 30, 2018, respectively, and $87.3 million and $169.7 million in the three and six months ended June 30, 2017, respectively, for these services. Such expenses are primarily included in Operation and maintenance and Administrative and general expenses in the accompanying Condensed Consolidated Statement of Comprehensive Income.

We provide services to certain of our affiliates. We recorded reductions in operating expenses for services provided to and reimbursed by our affiliates of $1.2 million and $2.2 million for the three and six months ended June 30, 2018, respectively, and $0.9 million and $1.8 million for the three and six months ended June 30, 2017, respectively.

We made equity distributions totaling $190.0 million and $210.0 million during the six months ended June 30, 2018 and 2017, respectively. During July 2018, we made an additional distribution of $100.0 million. Our parent made contributions to us totaling $340.0 million and $110.0 million in the six months ended June 30, 2018 and 2017, respectively, to fund a portion of our expenditures for additions to property, plant and equipment.

During July 2017, we recorded deferred revenue and recognized a non-cash distributionto our parent of $240 million associated with funds received by WPZ related to the March 2016 WPZ agreement with the member-sponsors of Sabal Trail regarding the Hillabee Expansion and Sabal Trail projects. Although the agreement was between WPZ and the member-sponsors, since the agreement was, in part, related to furthering the completion of Hillabee, this deferred revenue is assigned to our results of operations over the 25-year term of the capacity agreement with Sabal Trail.

8. OTHER

The Advances for construction costs on the accompanying Condensed Consolidated Balance Sheet are associated with advances received from a third party related to construction costs on the Atlantic Sunrise project. This balance increases as we receive additional advances. After construction of the project is completed, the related liabilities will be reclassified to Long-Term Debt and reduced by payments we make to the third party under terms of the applicable lease agreement.

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ITEM 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

General

The following discussion should be read in conjunction with the Consolidated Financial Statements, Notes and Management’s Discussion and Analysis contained in Items 7 and 8 of our 2017 Annual Report on Form 10-K and with the Condensed Consolidated Financial Statements and Notes contained in this Form 10-Q.

On May 16, 2018, WPZ entered into an agreement for a stock-for-unit transaction whereby Williams will acquire all of WPZ's 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 WPZ a $410 million termination fee. Williams currently owns approximately 74 percent limited partner interest in WPZ. WPZ expects the WPZ Merger will be completed during the third quarter of 2018.

On March 15, 2018, the FERC issued a revised policy statement (the March 15 Statement) in Docket No. PL17-1 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 a 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 WPZ Merger is to allow us to continue to recover an income tax allowance in our 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 fact 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 commission, 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 in Docket No. RM18-11 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 Tax Reform and the revised policy statement. On July 18, 2018, the FERC issued a Final Rule in the docket, 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. 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. We believe this Final Rule and the previously discussed WPZ Merger will allow for the continued recovery of income tax allowances in our rates. Further, because of our requirement to file a general rate case no later than August 31, 2018, we are exempt from the Final Rule's filing requirement.

On March 15, 2018, the FERC also issued a Notice of Inquiry in Docket No. RM18-12 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 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 our future tariff-based rates collected may be adversely impacted.

Critical Accounting Estimates

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 our customers are subject to the rate-making policies of the FERC, which have historically permitted the recovery of a income tax allowance that includes a deferred income tax component. As

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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 we will be required to return amounts to certain customers through future rates and have accordingly established a regulatory liability totaling $450.2 million as of June 30, 2018 and $471.1 million as of December 31, 2017. 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.

RESULTS OF OPERATIONS

Operating Income and Net Income

Operating Income for the six months ended June 30, 2018 was $402.6 million compared to $325.0 million for the six months ended June 30, 2017. The increase in Operating Income of $77.6 million (23.9 percent) was primarily due to higher Natural gas transportation and Other revenues in the first six months of 2018 compared to the same period in 2017, partly offset by an increase in Operating Costs and Expenses, as discussed below. Net Income for the six months ended June 30, 2018 was $372.1 million compared to $306.5 million for the six months ended June 30, 2017. The increase in Net Income of $65.6 million (21.4 percent) was mostly attributable to the increase in Operating Income and an unfavorable change in net expenses in Other (Income) and Other Expenses, as discussed below.

Operating Revenues

Natural gas sales increased $7.0 million (14.6 percent) for the six months ended June 30, 2018 compared to the same period in 2017. The increase was primarily due to $11.1 million of higher cash out sales, partly offset by $4.0 million of lower system management gas sales. Cash out sales and system management gas are offset in our cost of natural gas sold and therefore have no impact on our operating income or results of operations.

Natural gas transportation for the six months ended June 30, 2018 increased $114.5 million (15.7 percent) over the same period in 2017. The increase was primarily attributable to:

• $106.5 million increase in transportation reservation revenues related to new incremental projects primarily attributable to:

• $26.3 million from our Dalton project placed in partial service in April 2017, and fully in service in August 2017;

• $21.4 million from our Hillabee project Phase I placed in partial service in June 2017, and fully in service in July 2017;

•$19.7 million from our Virginia Southside Phase II project placed in service in December 2017.

•$15.4 million from our Atlantic Sunrise project placed in partial service in September 2017;

• $11.5 million from our New York Bay expansion project placed in service in October 2017;

• $7.3 million from our Garden State project placed in partial service in September 2017, and fully in service in March 2018; and

• $4.9 million from our Gulf Trace project placed in service in February 2017.

• $7.2 million higher recoveries of electric power costs. Electric power costs are recovered from customers through transportation rates resulting in no net impact on our operating income or results of operations.

Other for the six months ended June 30, 2018 increased $3.4 million (226.7 percent) over the same period in 2017. The increase was primarily attributable to deferred revenue on the Hillabee Project.

Operating Costs and Expenses

Excluding the Cost of natural gas sales, which is directly offset in revenues, of $55.1 million for the six months ended June 30, 2018 and $48.1 million for the comparable period in 2017, our operating costs and expenses for the six months ended June 30, 2018 increased $40.0 million (8.5 percent) from the comparable period in 2017. This increase was primarily attributable to:

• $25.9 million (16.7 percent) increase in Operation and maintenance costs primarily resulting from a $16.8 million increase in contracted services mainly related to pipeline integrity, general maintenance and other testing on our pipeline and $8.9 million higher employee labor and related benefit costs;

• $16.0 million (10.2 percent) increase in Depreciation and amortization costs primarily related to additional assets placed into service;

20

• $12.0 million (126.3 percent) increase in Cost of natural gas transportation costs primarily resulting from $7.2 million higher electric power costs and $4.9 million higher fuel costs. Electric power costs are recovered from customers through transportation rates resulting in no net impact on our operating income or results of operations;

• $4.5 million (5.1 percent) increase in Administrative and general costs primarily due to higher allocated corporate expenses; and

• Partially offset by a $20.9 million adjustment to a regulatory liability related to Tax Reform.

Other (Income) and Other Expenses

Other (income) and other expenses for the six months ended June 30, 2018 had an unfavorable change of $12.0 million (65.2 percent) over the same period in 2017. This is mostly due to a $23.9 million increase in Interest expense of which $12.8 million is associated with our debt issuance in March 2018 and $12.1 million is associated with the other financing obligation (See Note 4), partly offset by a favorable change of $13.1 million in Allowance for equity and borrowed funds used during construction (AFUDC) associated with capital expenditures on projects.

Filing of Rate Case

In accordance with the timing prescribed by our previous rate case settlement in Docket No. RP12-993, we are required to file a rate case no later than August 31, 2018. If the case is filed on August 31, 2018, we expect the FERC to 1) suspend rate increases to be effective March 1, 2019, subject to refund and the outcome of a hearing and 2) 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.

Pipeline Expansion Projects

We currently expect to invest capital of approximately $1.8 billion in 2018 in pipeline expansion projects.

Hillabee

The Hillabee Expansion Project involves an expansion of our existing natural gas transmission system from our Station 85 Pooling Point in Choctaw County, Alabama to a new interconnection with the Sabal Trail pipeline in Tallapoosa County, 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 on June 14, 2017, and we placed the remainder of Phase I into service on July 11, 2017. Phase I increased capacity by 818 Mdth/d. The in-service date of Phase II is planned for the second quarter of 2020. Together, the first two phases of the project are expected to increase capacity by 1,025 Mdth/d.

In March 2016, WPZ entered into an agreement with the member-sponsors of Sabal Trail to resolve several matters. In accordance with the agreement, the member-sponsors paid WPZ an aggregate amount of $240 million in three equal installments as certain milestones of the project were met. WPZ received the first $80 million payment in March 2016, the second $80 million payment in September 2016 and the third $80 million payment in July 2017. Although the agreement was an obligation between WPZ and the member-sponsors, since the agreement is, in part, related to furthering the completion of the project, we recorded deferred revenue and recognized a non-cash distribution to our parent. This deferred revenue is assigned to our results of operations over the 25-year term of the capacity agreement with Sabal Trail.

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 (which includes a group of related projects, including the Hillabee Expansion Project) filed by certain non-governmental organizations. In doing so, the court (i) remanded the matter to the FERC for preparation of an Environmental Impact Statement (EIS) that conforms with the court's opinion regarding quantifying certain greenhouse gas emissions, and (ii) vacated the FERC's certificate order for the projects, which would be effective following the court's mandate (by court order, the mandate will not issue until after disposition of any timely petitions for rehearing). In compliance with the court's directive, on February 5, 2018, the FERC issued a Final Supplemental EIS for the project, 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.

Garden State

The Garden State Expansion Project involves an expansion of our existing natural gas transmission system to provide incremental firm transportation capacity from our Station 210 Pooling Point in New Jersey to a new interconnection on our Trenton Woodbury Lateral in Burlington County, New Jersey. We placed the initial phase of the project into service

21

on September 9, 2017 and the remaining portion of the project was placed into service on March 23, 2018. The project increased capacity by 180 Mdth/d.

Atlantic Sunrise

The Atlantic Sunrise Project involves an expansion of our existing natural gas transmission system together with greenfield facilities to provide incremental firm transportation capacity from the northeastern Marcellus producing area to markets along our mainline as far south as our Station 85 Pooling Point in Choctaw County, Alabama. In February 2017, we received approval from the FERC for the project. We placed a portion of the mainline project facilities into service on September 1, 2017, which increased capacity by 400 Mdth/d. We placed additional mainline facilities into service on June 1, 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.

Gulf Connector

The Gulf Connector Expansion Project involves an expansion of our 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. In November 2017, we received approval from the FERC for the project. 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.

Northeast Supply Enhancement

The Northeast Supply Enhancement Project involves an expansion of our 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 New York State Department of Environmental Conservation (NYSDEC) denied, without prejudice, Transco's application for certain permits required for the project. We have addressed the technical issues identified by NYSDEC and refiled our application on May 16, 2018. We plan to place the project into service in 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

The Rivervale South to Market Project involves an expansion of our existing natural gas transmission system to provide incremental firm transportation capacity from the existing Rivervale interconnection with Tennessee Gas Pipeline on our North New Jersey Extension to our existing Central Manhattan meter station in New Jersey and our Station 210 Pooling Point in New Jersey. We filed an application with the FERC in August 2017 for approval of the project. 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.

Gateway

The Gateway Project involves an expansion of our existing natural gas transmission system to provide incremental firm transportation capacity from PennEast Pipeline Company's proposed interconnection with our mainline south of Station 205 in New Jersey to our existing Ridgefield meter station in Bergen County, New Jersey and our existing Paterson meter station in Passaic County, New Jersey. We filed an application with the FERC in November 2017 for approval of the project. We plan to place the project into service as early as the first quarter of 2021, assuming timely receipt of all necessary regulatory approvals. The project is expected to increase capacity by 65 Mdth/d.

Southeastern Trail

The Southeastern Trail Project involves an expansion of our 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 filed an application with the FERC in April 2018 for approval of the project. 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.

22

ITEM 4. Controls and Procedures

Our management, including our Senior Vice President and our Vice President and Chief Accounting 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 company 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 Senior Vice President and our Vice President and Chief Accounting Officer. Based upon that evaluation, our Senior Vice President and our Vice President and Chief Accounting 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

The information called for by this item is provided in Note 3 of the Notes to Condensed Consolidated Financial Statements included under Part I, Item 1. Financial Statements of this report, which information is incorporated by reference into this item.

23

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 that the risk factor in the Form 10-K captioned “The amount of income taxes that we will be allowed to recover will be determined by the outcome of future rate cases and any potential action taken by the FERC in response to its recent Notice of Inquiry” is replaced by the risk factor set forth 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 a MLP pipeline both an income tax allowance and a return on equity pursuant to the discounted cash flow methodology. As a result, the FERC will no longer permit an MLP pipeline to recover an income tax allowance in its cost of service and further stated it will address the application of this policy to non-MLP partnership forms as those issues arise in subsequent proceedings.

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 us 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.

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ITEM 6. Exhibits

The following instruments are included as exhibits to this report.

Exhibit Number	Description
2	Certificate of Conversion dated December 22, 2008 and effective December 31, 2008 (filed on February 24, 2011 as Exhibit 2.1 to our annual report on Form 10-K (File No. 001-07584) and incorporated herein by reference).
3.1	Certificate of Formation dated December 22, 2008 and effective December 31, 2008 (filed on February 24, 2011 as Exhibit 3.1 to our annual report on Form 10-K (File No. 001-07584) and incorporated herein by reference).
3.2	Amended and Restated Operating Agreement of Transcontinental Gas Pipe Line Company, LLC dated February 17, 2010 (filed on October 28, 2010 as Exhibit 3.2 to our quarterly report on Form 10-Q (File No. 001-07584) and incorporated herein by reference).
10.1	Credit Agreement dated as of July 13, 2018, between The Williams Companies, Inc., Northwest Pipeline LLC, and Transcontinental Gas Pipe Line Company, LLC, as co-borrowers, the lenders named therein, and Citibank, N.A. as Administrative Agent (filed on July 17, 2018 as Exhibit 10.1 to The Williams Companies, Inc.'s Current Report on Form 8-K (File No. 001-04174) and incorporated herein by reference).
31.1*	Certification of Principal Executive Officer pursuant to Rules 13a-14(a) and 15d-14(a) promulgated under the Securities Exchange Act of 1934, as amended, and Item 601(b)(31) of Regulation S-K, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*	Certification of Principal 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 Principal Executive Officer and Principal 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.

25

SIGNATURE

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

		TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC (Registrant)
Dated:	August 2, 2018	By:	/s/ Ted T. Timmermans
			Ted T. Timmermans
			Vice President and Chief Accounting Officer
			(Principal Accounting Officer)

EX-31.1

Exhibit 31.1

SECTION 302 CERTIFICATION

I, Frank J. Ferazzi, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Transcontinental Gas Pipe Line Company, LLC;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: August 2, 2018

By:	/s/ Frank J. Ferazzi
	Frank J. Ferazzi
	Senior Vice President
	(Principal Executive Officer)

EX-31.2

Exhibit 31.2

SECTION 302 CERTIFICATION

I, Ted T. Timmermans, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Transcontinental Gas Pipe Line Company, LLC;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: August 2, 2018

By:	/s/ Ted T. Timmermans
	Ted T. Timmermans
	Vice President and Chief Accounting Officer
	(Principal Financial Officer)

EX-32

Exhibit 32

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of Transcontinental Gas Pipe Line Company, LLC (the “Company”) on Form 10-Q for the period ending June 30, 2018 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), each of the undersigned hereby certifies, in his capacity as an officer of the Company, pursuant to 18 U.S.C. §1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002, that to his knowledge:

(1) The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Frank J. Ferazzi

Frank J. Ferazzi

Senior Vice President

August 2, 2018

/s/ Ted T. Timmermans

Ted T. Timmermans

Vice President and Chief Accounting Officer

August 2, 2018

A signed original of this written statement required by Section 906 has been provided to, and will be retained by, the Company and furnished to the Securities and Exchange Commission or its staff upon request.

The foregoing certification is being furnished to the Securities and Exchange Commission as an exhibit to the Report and shall not be considered filed as part of the Report.

XML

Document and Entity Information - shares	6 Months Ended
	Jun. 30, 2018	Aug. 02, 2018
Entity [Abstract]
Entity Registrant Name	Transcontinental Gas Pipe Line Company, LLC
Entity Central Index Key	0000099250
Document Type	10-Q
Document Period End Date	Jun. 30, 2018
Amendment Flag	false
Document Fiscal Year Focus	2018
Document Fiscal Period Focus	Q2
Current Fiscal Year End Date	--12-31
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding		0

XML

Condensed Consolidated Statement of Comprehensive Income (Unaudited) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Operating Revenues:
Natural gas sales	$ 29,873	$ 33,009	$ 55,124	$ 48,104
Natural gas transportation	415,708	365,246	842,286	727,811
Natural gas storage	33,786	33,935	68,553	68,824
Other	2,308	312	4,948	1,479
Total operating revenues	481,675	432,502	970,911	846,218
Operating Costs and Expenses:
Cost of natural gas sales	29,873	33,009	55,124	48,104
Cost of natural gas transportation	8,461	4,447	21,535	9,454
Operation and maintenance	93,659	82,100	180,675	154,813
Administrative and general	46,981	44,794	93,362	88,910
Depreciation and amortization	89,282	79,064	172,506	156,542
Taxes - other than income taxes	17,164	16,890	35,602	33,798
Regulatory credit resulting from Tax Reform (Note 1)	(20,867)	0	(20,867)	0
Other expense, net	12,564	14,415	30,405	29,637
Total operating costs and expenses	277,117	274,719	568,342	521,258
Operating Income	204,558	157,783	402,569	324,960
Other (Income) and Other Expenses:
Interest expense	53,375	37,236	98,449	74,493
Allowance for equity and borrowed funds used during construction (AFUDC)	(34,895)	(25,419)	(61,503)	(48,449)
Equity in (earnings) losses of unconsolidated affiliates	(1,325)	(1,389)	265	(2,410)
Miscellaneous other (income) expenses, net	(4,819)	(4,313)	(6,780)	(5,198)
Total other (income) and other expenses	12,336	6,115	30,431	18,436
Net Income	192,222	151,668	372,138	306,524
Other comprehensive income:
Equity interest in unrealized gain on interest rate hedges (includes $(33) and $22 for the three months ended and $(27) and $37 for the six months ended June 30, 2018 and June 30, 2017, respectively, of accumulated other comprehensive income reclassification for equity interest in realized losses (gains) on interest rate hedges)	119	1	524	36
Comprehensive Income	$ 192,341	$ 151,669	$ 372,662	$ 306,560

XML

Condensed Consolidated Statement of Comprehensive Income (Unaudited) (Parentheticals) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Accumulated other comprehensive income reclassification for equity interest in realized losses (gains) on interest rate hedges	$ (33)	$ 22	$ (27)	$ 37

XML

Condensed Consolidated Balance Sheet (Unaudited) - USD ($) $ in Thousands	Jun. 30, 2018	Dec. 31, 2017
Current Assets:
Cash	$ 0	$ 0
Receivables:
Affiliates	809	1,109
Advances to affiliate	589,133	395,247
Trade and other	165,369	170,422
Transportation and exchange gas receivables	8,137	3,205
Inventories	59,821	40,027
Regulatory assets	107,853	97,149
Other	17,880	12,508
Total current assets	949,002	719,667
Investments, at cost plus equity in undistributed earnings	27,833	28,505
Property, Plant and Equipment:
Natural gas transmission plant	15,215,789	13,771,183
Less-Accumulated depreciation and amortization	4,005,315	3,859,520
Total property, plant and equipment, net	11,210,474	9,911,663
Other Assets:
Regulatory assets	283,986	276,315
Other	161,828	141,786
Total other assets	445,814	418,101
Total Assets	12,633,123	11,077,936
Payables:
Affiliates	33,356	43,420
Trade and other	425,033	469,153
Transportation and exchange gas payables	3,411	2,121
Accrued liabilities	188,822	173,602
Long-term debt due within one year	1,642	251,430
Total current liabilities	652,264	939,726
Long-Term Debt	3,199,991	2,191,576
Other Long-Term Liabilities:
Asset retirement obligations	352,379	350,280
Regulatory liabilities	991,895	990,702
Advances for construction costs	739,953	426,771
Deferred revenue	231,450	236,729
Other	5,205	4,828
Total other long-term liabilities	2,320,882	2,009,310
Contingent Liabilities and Commitments (Note 3)
Members' Equity
Member's capital	4,428,499	4,088,499
Retained earnings	2,030,626	1,848,488
Accumulated other comprehensive income	861	337
Total member's equity	6,459,986	5,937,324
Total liabilities and member's equity	$ 12,633,123	$ 11,077,936

XML

Condensed Consolidated Statement of Cash Flows (Unaudited) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017
Cash flows from operating activities:
Net income	$ 372,138	$ 306,524
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Depreciation and amortization	172,506	156,542
Allowance for equity funds used during construction (equity AFUDC)	(45,910)	(37,260)
Regulatory credit resulting from Tax Reform (Note 1)	(20,867)	0
Equity in (earnings) losses of unconsolidated affiliates	265	(2,410)
Distribution from unconsolidated affiliates	931	4,848
Changes in operating assets and liabilities:
Receivables - affiliates	300	(33)
Receivables - trade and other	5,053	1,789
Transportation and exchange gas receivable	(4,932)	(1,282)
Inventories	(19,794)	(20,674)
Payables - affiliates	(10,686)	4,134
Payables - trade	(30,052)	(1,467)
Accrued liabilities	15,719	(29,703)
Asset retirement obligations - non-current	23,230	19,977
Asset retirement obligations - removal costs	(4,013)	(1,212)
Deferred revenue	(5,279)	(479)
Other, net	(12,222)	10,719
Net cash provided by operating activities	436,387	410,013
Cash flows from financing activities:
Proceeds from long-term debt	993,440	0
Proceeds from other financing obligations	24,298	0
Retirement of long-term debt	250,000	0
Payments on other financing obligation	(758)	0
Payments for debt issuance costs	(9,208)	(13)
Cash distributions to parent	(190,000)	(210,000)
Cash contributions from parent	340,000	110,000
Net cash provided by financing activities	907,772	(100,013)
Cash flows from investing activities:
Property, plant and equipment additions, net of equity AFUDC	(1,463,600)	(740,079)
Contributions and advances for construction costs	337,874	194,108
Disposal of property, plant and equipment, net	(7,477)	(20,843)
Advances to affiliate, net	(193,886)	270,641
Purchase of ARO Trust investments	(36,807)	(32,290)
Proceeds from sale of ARO Trust investments	19,737	15,263
Proceeds from insurance	0	3,200
Net cash used in investing activities	(1,344,159)	(310,000)
Increase (decrease) in cash	0	0
Cash at beginning of period	0	0
Cash at end of period	0	0
Increase to property, plant and equipment, net of equity AFUDC	(1,434,519)	(807,408)
Changes in related accounts payable and accrued liabilities	(29,081)	67,329
Property, plant and equipment additions, net of equity AFUDC	$ (1,463,600)	$ (740,079)

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Basis of Presentation (Notes)

6 Months Ended

Jun. 30, 2018

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Basis of Presentation

BASIS OF PRESENTATION

In this report, Transco (which includes Transcontinental Gas Pipe Line Company, LLC and, unless the context otherwise requires, all of our majority-owned subsidiaries) is at times referred to in the first person as “we,” “us” or “our.”

Transco is indirectly owned by Williams Partners L.P. (WPZ), a publicly traded Delaware limited partnership, which is consolidated by The Williams Companies, Inc. (Williams). On May 16, 2018, WPZ entered into an agreement for a stock-for-unit transaction whereby Williams will acquire all of WPZ's 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 WPZ a $410 million termination fee. Williams currently owns approximately 74 percent limited partner interest in WPZ.

General

The condensed consolidated unaudited financial statements include our accounts and the accounts of the subsidiaries we control. Companies in which we and our subsidiaries own 20 percent to 50 percent of the voting common stock or otherwise exercise significant influence over operating and financial policies of the company are accounted for under the equity method. The equity method investments as of June 30, 2018 and December 31, 2017 consist of Cardinal Pipeline Company, LLC (Cardinal) with an ownership interest of approximately 45 percent and Pine Needle LNG Company, LLC (Pine Needle) with an ownership interest of 35 percent. We received distributions associated with our equity method investments totaling $0.9 million and $4.8 million in the six months ended June 30, 2018 and June 30, 2017, respectively.

The condensed consolidated unaudited financial statements have been prepared from our books and records. Certain information and footnote disclosures normally included in financial statements prepared in accordance with U.S. generally accepted accounting principles (GAAP) have been condensed or omitted in this Form 10-Q pursuant to Securities and Exchange Commission rules and regulations. The condensed consolidated unaudited financial statements include all normal recurring adjustments and others which, in the opinion of our management, are necessary to present fairly our interim financial statements. These condensed consolidated unaudited financial statements should be read in conjunction with the consolidated financial statements and the notes thereto included in our 2017 Annual Report on Form 10-K.

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the amounts reported in the condensed consolidated unaudited financial statements and accompanying notes. Actual results could differ from those estimates.

Regulatory Accounting

In December 2017, the Tax Cuts and Jobs Act (Tax Reform) was enacted, which, among other things, reduced the federal corporate income tax rate from 35 percent to 21 percent . In accordance with ASC 980-740-25-2, we have recognized a regulatory liability to reflect the probable return to certain customers through future rates of the future decrease in income taxes payable associated with Tax Reform. In determining the estimated liability that we currently believe is probable of return to certain customers through future rates, we considered the mix of services provided by us, taking into consideration that certain of these services are provided under fixed negotiated rates, in lieu of cost-based recourse rates, that are designed to recover the cost of providing those services, with no expected future rate adjustment for the term of those contracts. The liability was recorded in December 2017 through a regulatory charge to operating income of $471.1 million. At the end of our rate case base period at May 2018, we recorded a reduction to the liability of $20.9 million mostly due to an updated weighted average state income tax rate. 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.

Accounting Standards Issued and Adopted

Effective January 1, 2018, we adopted Accounting Standards Update (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 Condensed Consolidated Statement of Cash Flows in accordance with ASU 2016-15. For the period ended June 30, 2017, amounts previously presented as Return of capital from unconsolidated affiliates within Investing Activities are now presented as part of Distributions from unconsolidated affiliates within Operating Activities, resulting in an increase to Net cash provided by operating activities of $2.1 million with a corresponding reduction in Net cash used in investing activities.

In May 2014, the Financial Accounting Standards Board (FASB) issued ASU 2014-09 establishing Accounting Standards Codification (ASC) Topic 606, “Revenue from Contracts with Customers” (ASC 606). ASC 606 establishes a comprehensive new revenue recognition model designed to depict the transfer of goods or services to a customer in an amount that reflects the consideration 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. There was no cumulative effect adjustment to retained earnings upon initially applying ASC 606 for periods prior to January 1, 2018.

For each revenue contract type, we conducted a formal contract review process to evaluate the impact of ASC 606. As a result of the adoption of ASC 606, there are no changes to the timing of our revenue recognition or differences in the presentation in our condensed consolidated financial statements from those under the previous revenue standard (See Note 2).

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. ASU 2016-13 requires varying transition methods for the different categories of amendments. We do not expect ASU 2016-13 to have a significant impact on our consolidated financial statements.

In February 2016, the FASB issued ASU 2016-02 “Leases (Topic 842)” (ASU 2016-02). ASU 2016-02 establishes a comprehensive new lease accounting model. 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 right-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 significant changes to our financial statements relate to the recognition of a lease liability and offsetting right-of-use asset in our Condensed Consolidated Balance Sheet for operating leases. We are also evaluating ASU 2016-02's available practical expedients on adoption, which we expect to elect.

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Contingent Liabilities and Commitments (Notes)

6 Months Ended

Jun. 30, 2018

Commitments and Contingencies Disclosure [Abstract]

Contingent Liabilities and Commitments

CONTINGENT LIABILITIES AND COMMITMENTS

Rate Matters

On March 15, 2018, the FERC issued a revised policy statement in Docket No. PL17-1 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 a 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 fact 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 in Docket No. RM18-11 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 Tax Reform and the revised policy statement. On July 18, 2018, the FERC issued a Final Rule in the docket, 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. 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 in Docket No. RM18-12 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 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 our future tariff-based rates collected may be adversely impacted.

Station 62 Incident

On October 8, 2015, an explosion and fire occurred at our Compressor Station No. 62 in Gibson, Louisiana. At the time of the incident, planned facility maintenance was being performed at the station and the facility was not operational. The incident was related to maintenance work being performed on the slug catcher at the station. Four contractor employees were killed in the incident and others were injured.

In responding to the incident, we cooperated with local, state and federal authorities, including the Louisiana State Police, Terrebonne Parish, the Louisiana Department of Environmental Quality, the U.S. Environmental Protection Agency (Region 6), the Occupational Safety and Health Administration, and the U.S. Department of Transportation's Pipeline and Hazardous Materials Safety Administration (PHMSA). On July 29, 2016, PHMSA issued a Notice of Probable Violation (NOPV), which includes a $1.6 million proposed civil penalty to us in connection with the incident. This penalty was accrued in the second quarter of 2016 and would not be covered by our insurance policies. We filed a response to the NOPV on August 25, 2016, and on July 14, 2017, PHMSA held a hearing on the NOPV.

The incident did not cause any rupture of the gas pipeline or any damage to the building containing the compressor engines. In anticipation of the planned maintenance, our Southeast Louisiana Lateral was taken out of service on October 4, 2015, which affected approximately 200 MMcf/d of natural gas production. The lateral was restored to service in early 2016 after repairs were made to the facilities damaged in the incident.

We are a defendant in lawsuits seeking damages for wrongful death, personal injury and property damages. We believe it is reasonably possible that losses will be incurred on some lawsuits. However, in management's judgment, the ultimate resolution of these matters will not have a material effect on our financial condition, results of operations or cash flows. While we also have claims for indemnification, we believe that it is probable that any ultimate losses incurred will be covered by our contractors' insurance and our insurance.

Environmental Matters

We have had studies underway for many years to test some of our facilities for the presence of toxic and hazardous substances such as polychlorinated biphenyls (PCBs) and mercury to determine to what extent, if any, remediation may be necessary. We have also similarly evaluated past on-site disposal of hydrocarbons at a number of our facilities. We have worked closely with and responded to data requests from the U.S. Environmental Protection Agency (EPA) and state agencies regarding such potential contamination of certain of our sites. On the basis of the findings to date, we estimate that environmental assessment and remediation costs under various federal and state statutes will total approximately $6 million to $8 million (including both expense and capital expenditures), measured on an undiscounted basis, and will substantially be spent over the next four to six years. This estimate depends on a number of assumptions concerning the scope of remediation that will be required at certain locations and the cost of the remedial measures. We are conducting environmental assessments and implementing a variety of remedial measures that may result in increases or decreases in the total estimated costs. At June 30, 2018, we had a balance of approximately $3.7 million for the expense portion of these estimated costs, $1.8 million recorded in Accrued liabilities and $1.9 million recorded in Other Long-Term Liabilities - Other in the accompanying Condensed Consolidated Balance Sheet. At December 31, 2017, we had a balance of approximately $4.0 million for the expense portion of these estimated costs, $1.8 million recorded in Accrued liabilities and $2.2 million recorded in Other Long-Term Liabilities - Other in the accompanying Condensed Consolidated Balance Sheet.

We have been identified as a potentially responsible party (PRP) at various Superfund and state waste disposal sites. Based on present volumetric estimates and other factors, our estimated aggregate exposure for remediation of these sites is less than $0.5 million. The estimated remediation costs for all of these sites are included in the $6 million to $8 million range discussed above. Liability under the Comprehensive Environmental Response, Compensation and Liability Act and applicable state law can be joint and several with other PRPs. Although volumetric allocation is a factor in assessing liability, it is not necessarily determinative; thus, the ultimate liability could be substantially greater than the amounts described above.

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

We consider prudently incurred environmental assessment and remediation costs and the costs associated with compliance with environmental standards to be recoverable through rates. To date, we have been permitted recovery of environmental costs, and it is our intent to continue seeking recovery of such costs through future rate filings. As a result, as estimated costs of environmental assessment and remediation are incurred, they are recorded as regulatory assets in the Condensed Consolidated Balance Sheet until collected through rates. At June 30, 2018, we had a balance of approximately $1.6 million of uncollected environmental related regulatory assets, $1.2 million recorded in Current Assets - Regulatory assets and $0.4 million recorded in Other Assets - Regulatory assets in the accompanying Condensed Consolidated Balance Sheet. At December 31, 2017, we had a balance of approximately $2.2 million of uncollected environmental related regulatory assets, $1.2 million recorded in Current Assets - Regulatory assets and $1.0 million recorded in Other Assets - Regulatory assets in the accompanying Condensed Consolidated Balance Sheet.

Other Matters

Various other proceedings are pending against us and are considered incidental to our operations.

Summary

We estimate that for all matters for which we are able to reasonably estimate a range of loss, including those noted above and others that are not individually significant, our aggregate reasonably possible losses beyond amounts accrued for all of our contingent liabilities 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. We have disclosed all significant matters for which we are unable to reasonably estimate a range of possible loss.

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Debt and Financing Arrangements (Notes)

6 Months Ended

Jun. 30, 2018

Debt Disclosure [Abstract]

Debt and Financing Arrangements

DEBT AND FINANCING ARRANGEMENTS

Credit Facility

We along with WPZ and Northwest Pipeline LLC (Northwest Pipeline), are party to a credit facility with aggregate commitments available of $3.5 billion, with up to an additional $500 million increase in aggregate commitments available under certain circumstances. Total letter of credit capacity available to WPZ under this credit facility is $1.125 billion. We are able to borrow up to $500 million under this credit facility to the extent not otherwise utilized by the other co-borrowers. At June 30, 2018, no letters of credit have been issued and no loans were outstanding under the credit facility.

WPZ participates in a commercial paper program, and WPZ management considers amounts outstanding under this program to be a reduction of available capacity under the credit facility. The program allows a maximum outstanding amount at any time of $3 billion of unsecured commercial paper notes. At June 30, 2018, WPZ had no commercial paper outstanding under the commercial paper program.

During July 2018, in anticipation of the WPZ Merger closing, Williams entered into a new $4.5 billion unsecured revolving credit agreement (Credit Agreement) that includes us and Northwest Pipeline as co-borrowers. The full amount of the credit facility will be available to Williams to the extent not utilized by us and Northwest Pipeline. Both Transco and Northwest Pipeline will have access up to $500 million under this Credit Agreement. The Credit Agreement will become effective upon closing of the WPZ Merger and will be initially available for five years from the Credit Agreement effective date.

Other Financing Obligation

During the first six months of 2018, we received an additional $24.3 million of funding from a co-owner for its proportionate share of construction costs related to its undivided ownership interest in the Dalton lateral. This additional funding is reflected in Long-Term Debt on our Condensed Consolidated Balance Sheet. At June 30, 2018, the amount included in Long-Term Debt on our Condensed Consolidated Balance Sheet for this financing obligation is $252.8 million, and the amount included in Long-term debt due within one year on our Condensed Consolidated Balance Sheet for this financing obligation is $1.6 million.

Issuance and Retirement of Long-Term Debt

On March 15, 2018, we issued $400 million of 4.0 percent senior unsecured notes due 2028 and $600 million of 4.6 percent senior unsecured notes due 2048 to investors in a private placement. We used the net proceeds to retire our $250 million of 6.05 percent senior unsecured notes due June 2018, and for general purposes, including the funding of capital expenditures. As part of the issuance, we entered into a registration rights agreement with the initial purchasers of the unsecured notes. We are 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. We are required to provide a shelf registration statement to cover resales of the notes under certain circumstances. If we fail 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.

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ARO Trust (Notes)

6 Months Ended

Jun. 30, 2018

Investments, Debt and Equity Securities [Abstract]

ARO Trust

ARO TRUST

We are entitled to collect in rates the amounts necessary to fund our asset retirement obligations (ARO). We deposit monthly, into an external trust account (ARO Trust), the revenues specifically designated for ARO. The ARO Trust carries a moderate risk portfolio. We measure the financial instruments held in our ARO Trust at fair value. However, in accordance with the ASC Topic 980, Regulated Operations, both realized and unrealized gains and losses of the ARO Trust are recorded as regulatory assets or liabilities.

Effective March 1, 2013, the annual funding obligation is approximately $36.4 million, with deposits made monthly.

Investments within the ARO Trust at fair value were as follows (in millions):

	June 30, 2018				December 31, 2017
	Amortized Cost Basis		Fair Value		Amortized Cost Basis		Fair Value
Cash and Money Market Funds	$	14.7	$	14.7	$	12.6	$	12.6
U.S. Equity Funds	46.3		62.5		35.9		50.5
International Equity Funds	21.9		24.5		20.7		24.6
Municipal Bond Funds	50.1		49.6		46.8		46.9
Total	$	133.0	$	151.3	$	116.0	$	134.6

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Fair Value Measurements (Notes)

6 Months Ended

Jun. 30, 2018

Fair Value Disclosures [Abstract]

Fair Value Measurements

FAIR VALUE MEASUREMENTS

The following table presents, by level within the fair value hierarchy, certain of our financial assets and liabilities. The carrying values of cash, short-term financial assets (advances to affiliate) that have variable interest rates, 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	$	151.3		$	151.3		$	151.3	$	—		$	—
Additional disclosures:
Long-term debt, including current portion	(3,201.6		)	(3,638.9		)	—		(3,638.9		)	—
Assets (liabilities) at December 31, 2017:
Measured on a recurring basis:
ARO Trust investments	$	134.6		$	134.6		$	134.6	$	—		$	—
Additional disclosures:
Long-term debt	(2,443.0		)	(3,103.3		)	—		(3,103.3		)	—

Fair Value Methods

The following methods and assumptions were used to estimate the fair value of each class of financial instruments for which it is practicable to estimate that value:

ARO Trust investments — We deposit a portion of our collected rates, pursuant to the terms of the Docket No. RP12-993 rate case settlement, into the ARO Trust which is specifically designated to fund future asset retirement obligations. 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 are reported in Other Assets-Other in the Condensed Consolidated Balance Sheet. However, both realized and unrealized gains and losses are ultimately recorded as regulatory assets or liabilities. See Note 5 for more information regarding the ARO Trust.

Long-term debt — 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. The fair value of the financing obligation associated with our Dalton lateral, which is included within long-term debt, was determined using an income approach (See Note 4 - Debt and Financing Arrangements).

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.

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Transactions with Affiliates (Notes)

6 Months Ended

Jun. 30, 2018

Related Party Transactions [Abstract]

Transactions with Affiliates

TRANSACTIONS WITH AFFILIATES

We are a participant in WPZ’s cash management program, and we make advances to and receive advances from WPZ. At June 30, 2018 and December 31, 2017, our advances to WPZ totaled approximately $589.1 million and $395.2 million, respectively. These advances are represented by demand notes and are classified as Receivables - Advances to affiliate in the accompanying Condensed Consolidated Balance Sheet. Advances are stated at the historical carrying amounts. Interest income is recognized when chargeable and collectability is reasonably assured. The interest rate on these intercompany demand notes is based upon the daily overnight investment rate paid on WPZ’s excess cash at the end of each month. At June 30, 2018, the interest rate was 1.80 percent.

Included in Operating Revenues in the accompanying Condensed Consolidated Statement of Comprehensive Income are revenues received from affiliates of $1.5 million and $3.3 million for the three and six months ended June 30, 2018, respectively, and $3.1 million and $6.4 million for the three and six months ended June 30, 2017, respectively. The rates charged to provide sales and services to affiliates are the same as those that are charged to similarly-situated nonaffiliated customers.

Included in Cost of natural gas sales in the accompanying Condensed Consolidated Statement of Comprehensive Income are cost of gas purchased from affiliates of $1.8 million and $3.7 million for the three and six months ended June 30, 2018, respectively, and $0.8 million and $1.9 million for the three and six months ended June 30, 2017, respectively. All gas purchases are made at market or contract prices.

We have no employees. Services necessary to operate our business are provided to us by Williams and certain affiliates of Williams. We reimburse Williams and its affiliates for all direct and indirect expenses incurred or payments made (including salary, bonus, incentive compensation and benefits) in connection with these services. Employees of Williams also provide general, administrative and management services to us, and we are charged for certain administrative expenses incurred by Williams. These charges are either directly identifiable or allocated to our assets. Direct charges are for goods and services provided by Williams at our request. Allocated charges are based on a three-factor formula, which considers revenues; property, plant and equipment; and payroll. In management’s estimation, the allocation methodologies used are reasonable and result in a reasonable allocation to us of our costs of doing business incurred by Williams. We were billed $99.3 million and $190.8 million in the three and six months ended June 30, 2018, respectively, and $87.3 million and $169.7 million in the three and six months ended June 30, 2017, respectively, for these services. Such expenses are primarily included in Operation and maintenance and Administrative and general expenses in the accompanying Condensed Consolidated Statement of Comprehensive Income.

We provide services to certain of our affiliates. We recorded reductions in operating expenses for services provided to and reimbursed by our affiliates of $1.2 million and $2.2 million for the three and six months ended June 30, 2018, respectively, and $0.9 million and $1.8 million for the three and six months ended June 30, 2017, respectively.

We made equity distributions totaling $190.0 million and $210.0 million during the six months ended June 30, 2018 and 2017, respectively. During July 2018, we made an additional distribution of $100.0 million. Our parent made contributions to us totaling $340.0 million and $110.0 million in the six months ended June 30, 2018 and 2017, respectively, to fund a portion of our expenditures for additions to property, plant and equipment.

During July 2017, we recorded deferred revenue and recognized a non-cash distributionto our parent of $240 million associated with funds received by WPZ related to the March 2016 WPZ agreement with the member-sponsors of Sabal Trail regarding the Hillabee Expansion and Sabal Trail projects. Although the agreement was between WPZ and the member-sponsors, since the agreement was, in part, related to furthering the completion of Hillabee, this deferred revenue is assigned to our results of operations over the 25-year term of the capacity agreement with Sabal Trail.

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Other (Notes)

6 Months Ended

Jun. 30, 2018

Other Income and Expenses [Abstract]

Other

OTHER

The Advances for construction costs on the accompanying Condensed Consolidated Balance Sheet are associated with advances received from a third party related to construction costs on the Atlantic Sunrise project. This balance increases as we receive additional advances. After construction of the project is completed, the related liabilities will be reclassified to Long-Term Debt and reduced by payments we make to the third party under terms of the applicable lease agreement.

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Revenue Recognition (Notes)

6 Months Ended

Jun. 30, 2018

Revenue Recognition [Abstract]

Revenue from Contract with Customer [Text Block]

2. REVENUE RECOGNITION

Our customers are comprised of public utilities, municipalities, gas marketers and producers, intrastate pipelines, direct industrial users, and electrical generators.

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 product or 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. Service revenue contracts 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. As a rate-regulated entity applying ASC 980 "Regulated Operations" (Topic 980), we follow Federal Energy Regulatory Commission (FERC) guidelines with respect to reimbursement of construction costs. FERC tariffs only allow for cost reimbursement and are non-negotiable in nature; thus, the construction activities do not represent an ongoing major and central operation of our gas pipelines business and are not within the scope of ASC 606. Accordingly, cost reimbursements are treated as a reduction to the cost of the constructed asset.

Service Revenues

We are subject to regulation by certain state and federal authorities, including the FERC, with revenue derived from 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 as negotiated with our customers, 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 include the following:

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

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

In situations where we consider the integrated package of services a single performance obligation, which represents a majority of our 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 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.

Product Sales

In the course of providing transportation services to customers, 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. Revenue is recognized from the sale of natural gas upon settlement of the transportation and exchange imbalances.

Revenue by Category

Our revenue disaggregation by major service line includes Natural gas sales, Natural gas transportation, Natural gas storage, and Other, which are separately presented on the Condensed Consolidated Statement of Comprehensive Income.

Contract Liabilities

Our contract liabilities consist of advance payments from customers, which include 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 straight-line over the remaining contractual service periods, and are classified as current or non-current according to when such amounts are expected to be recognized. Current and non-current contract liabilities are included within Accrued Liabilities and Other Long-Term Liabilities - Deferred revenue, respectively, in our Condensed 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 and when the customer pays for those goods or services and the prevailing interest rates. We have assessed our contracts and determined none of our contracts contain a significant financing component.

The following table presents a reconciliation of our contract liabilities:

	Quarter to Date June 30, 2018			Year to Date June 30, 2018
	(Thousands)
Balance at beginning of period	$	244,658		$	247,296
Payments received and deferred	—			—
Recognized in revenue	(2,641		)	(5,279		)
Balance at end of period	$	242,017		$	242,017

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:

	(Thousands)
2018 (remainder)	$	5,287
2019	10,566
2020	10,568
2021	10,566
2022	10,566
2023	10,566
Thereafter	183,898

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 reservation charges on contracted capacity on our firm transportation and storage contracts with customers. Amounts from certain contracts included in the table below, which are subject to the periodic review and approval by the FERC, 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 the variable consideration component for commodity charges. It also excludes consideration 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 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.

	(Thousands)
2018 (remainder)	$	850,434
2019	1,618,612
2020	1,515,147
2021	1,309,562
2022	1,116,179
2023	982,445
Thereafter	8,493,236
Total	$	15,885,615

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. Our credit risk exposure in the event of nonperformance by the other parties is limited to the face value of the receivables. We perform ongoing credit evaluations of our customers' financial condition and require collateral from our customers, if necessary. Due to our customer base, we have not historically experienced recurring credit losses in connection with our receivables.

Receivables from contracts with customers are included within Receivables - Trade and other and Receivables - Affiliates and receivables that are not related to contracts with customers are included with Receivables - Advances to affiliate in our Condensed Consolidated Balance Sheet. At June 30, 2018 and January 1, 2018, Receivables - Trade and other includes $6.9 million and $2.5 million, respectively, of receivables not related to contracts with customers.

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ARO Trust (Tables)

6 Months Ended

Jun. 30, 2018

Investments, Debt and Equity Securities [Abstract]

ARO Trust

Investments within the ARO Trust at fair value were as follows (in millions):

	June 30, 2018				December 31, 2017
	Amortized Cost Basis		Fair Value		Amortized Cost Basis		Fair Value
Cash and Money Market Funds	$	14.7	$	14.7	$	12.6	$	12.6
U.S. Equity Funds	46.3		62.5		35.9		50.5
International Equity Funds	21.9		24.5		20.7		24.6
Municipal Bond Funds	50.1		49.6		46.8		46.9
Total	$	133.0	$	151.3	$	116.0	$	134.6

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Fair Value Measurements (Tables)

6 Months Ended

Jun. 30, 2018

Fair Value Disclosures [Abstract]

Fair Value Measurements

The following table presents, by level within the fair value hierarchy, certain of our financial assets and liabilities. The carrying values of cash, short-term financial assets (advances to affiliate) that have variable interest rates, 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	$	151.3		$	151.3		$	151.3	$	—		$	—
Additional disclosures:
Long-term debt, including current portion	(3,201.6		)	(3,638.9		)	—		(3,638.9		)	—
Assets (liabilities) at December 31, 2017:
Measured on a recurring basis:
ARO Trust investments	$	134.6		$	134.6		$	134.6	$	—		$	—
Additional disclosures:
Long-term debt	(2,443.0		)	(3,103.3		)	—		(3,103.3		)	—

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Revenue Recognition Revenue Recognition (Tables)

6 Months Ended

Jun. 30, 2018

Revenue Recognition [Abstract]

Contract with Customer, Asset and Liability [Table Text Block]

The following table presents a reconciliation of our contract liabilities:

	Quarter to Date June 30, 2018			Year to Date June 30, 2018
	(Thousands)
Balance at beginning of period	$	244,658		$	247,296
Payments received and deferred	—			—
Recognized in revenue	(2,641		)	(5,279		)
Balance at end of period	$	242,017		$	242,017

Contract with Customer, Liablity Expected Timing of Revenue Recognition [Table Text Block]

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:

	(Thousands)
2018 (remainder)	$	5,287
2019	10,566
2020	10,568
2021	10,566
2022	10,566
2023	10,566
Thereafter	183,898

Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Table Text Block]

The following table presents the transaction price allocated to the remaining performance obligations under certain contracts as of June 30, 2018. These primarily include reservation charges on contracted capacity on our firm transportation and storage contracts with customers. Amounts from certain contracts included in the table below, which are subject to the periodic review and approval by the FERC, 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 the variable consideration component for commodity charges. It also excludes consideration 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 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.

	(Thousands)
2018 (remainder)	$	850,434
2019	1,618,612
2020	1,515,147
2021	1,309,562
2022	1,116,179
2023	982,445
Thereafter	8,493,236
Total	$	15,885,615

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Basis of Presentation (Details) $ in Thousands		3 Months Ended		6 Months Ended		12 Months Ended
	May 16, 2018 USD ($)	Jun. 30, 2018 USD ($)	Jun. 30, 2017 USD ($)	Jun. 30, 2018 USD ($)	Jun. 30, 2017 USD ($)	Dec. 31, 2017 USD ($)
Schedule of Equity Method Investments [Line Items]
Distribution from unconsolidated affiliates				$ 931	$ 4,848
Limited Liability Company or Limited Partnership, Members or Limited Partners, Ownership Interest				74.00%
Regulatory credit resulting from Tax Reform (Note 1)		$ (20,867)	$ 0	$ (20,867)	0
WPZ Merger Public Unit Exchange [Member]
Schedule of Equity Method Investments [Line Items]
Termination Fee	$ 410,000
WPZ Merger Public Unit Exchange [Member] | Merger Closed Prior To Third Quarter 2018 Dividend Record Date [Member]
Schedule of Equity Method Investments [Line Items]
Conversion Ratio	1.494
WPZ Merger Public Unit Exchange [Member] | Merger Closed After Third Quarter 2018 Dividend Record Date [Member]
Schedule of Equity Method Investments [Line Items]
Conversion Ratio	1.513
Operating Expense [Member]
Schedule of Equity Method Investments [Line Items]
Regulatory charge resulting from Tax Reform						$ 471,100
Regulatory credit resulting from Tax Reform (Note 1)				$ (20,867)
Minimum [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Description of Principal Activities				.20
Effective Income Tax Rate Reconciliation, Change in Enacted Tax Rate, Percent						21.00%
Maximum [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Description of Principal Activities				.50
Effective Income Tax Rate Reconciliation, Change in Enacted Tax Rate, Percent						35.00%
Cardinal Pipeline Company, LLC [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage		45.00%		45.00%		45.00%
Pine Needle LNG Company, LLC [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage		35.00%		35.00%		35.00%
Accounting Standards Update 2016-15 [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Net Cash Provided by (Used in) Operating Activities					$ 2,100

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Contingent Liabilities and Commitments (Details) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2018	Dec. 31, 2017	Dec. 31, 2016
Site Contingency [Line Items]
Regulatory assets, current	$ 107,853	$ 97,149
Regulatory assets, noncurrent	283,986	276,315
Environmental assessment and remediation [Member]
Site Contingency [Line Items]
Accrued environmental assessment and remediation costs, total	3,700	4,000
Accrued environmental assessment and remediation costs, current	1,800	1,800
Accrued environmental assessment and remediation costs, noncurrent	1,900	2,200
Regulatory assets, total	1,600	2,200
Regulatory assets, current	1,200	1,200
Regulatory assets, noncurrent	400	$ 1,000
Environmental assessment and remediation [Member] | Minimum [Member]
Site Contingency [Line Items]
Environmental assessment and remediation costs, best estimate	$ 6,000
Expected duration of environmental assessment and remediation spending	4 years
Environmental assessment and remediation [Member] | Maximum [Member]
Site Contingency [Line Items]
Environmental assessment and remediation costs, best estimate	$ 8,000
Expected duration of environmental assessment and remediation spending	6 years
Potentially responsible party at various Superfund and state waste disposal sites [Member] | Maximum [Member]
Site Contingency [Line Items]
Environmental assessment and remediation costs, best estimate	$ 500
Accrued Liabilities
Site Contingency [Line Items]
Notice of Penalty			$ 1,600

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Debt and Financing Arrangements (Details) - USD ($) $ in Millions	Jul. 31, 2018	Jun. 30, 2018	Mar. 15, 2018
Subsequent Event [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	$ 500.0
Williams Partners L.P. [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity		$ 3,500.0
Commercial paper, outstanding		0.0
Williams Companies Inc [Member] | Subsequent Event [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	$ 4,500.0
$3.5 billion credit facility [Member]
Line of Credit Facility [Line Items]
Letters of credit outstanding, amount		0.0
Additional Amount By Which Credit Facility Can Be Increased		500.0
Line of credit facility, amount outstanding		0.0
$3.5 billion credit facility [Member] | Williams Partners L.P. [Member] | Commercial paper [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity		3,000.0
$3.5 billion credit facility [Member] | Williams Partners L.P. [Member] | Letter of credit [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity		$ 1,125.0
4%SeniorUnsecuredNotesDue2028
Line of Credit Facility [Line Items]
Additional Interest Rate Accrued For Default Of Registration Rights Agreements First Period			0.25%
Additional Interest Rate Accrued For Default Of Registration Rights Agreements Each Subsequent Period			0.25%
Maximum Additional Interest Rate Accrued For Default Of Registration Rights Agreements All Periods			0.50%

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Debt and Financing Arrangements Long-Term Debt Instruments (Details) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2018	Mar. 15, 2018	Dec. 31, 2017
Debt Instrument [Line Items]
Long-Term Debt	$ 3,199,991		$ 2,191,576
Long-term debt due within one year	1,642		$ 251,430
6.05% due 2018
Debt Instrument [Line Items]
Retirement of debt	$ 250
Long-term debt, Interest Rate	6.05%
Dalton Expansion Project
Debt Instrument [Line Items]
Proceeds from Issuance of Other Long-term Debt	$ 24,300
Long-Term Debt	252,800
Long-term debt due within one year	1,600
4%SeniorUnsecuredNotesDue2028
Debt Instrument [Line Items]
Long-term debt, Interest Rate		4.00%
Issuance of Long-Term Debt		$ 400,000
Additional Interest Rate Accrued For Default Of Registration Rights Agreements First Period		0.25%
Additional Interest Rate Accrued For Default Of Registration Rights Agreements Each Subsequent Period		0.25%
Maximum Additional Interest Rate Accrued For Default Of Registration Rights Agreements All Periods		0.50%
4.6%SeniorUnsecuredNotesDue2048
Debt Instrument [Line Items]
Long-term debt, Interest Rate		4.60%
Issuance of Long-Term Debt		$ 600,000
Additional Interest Rate Accrued For Default Of Registration Rights Agreements First Period		0.25%
Additional Interest Rate Accrued For Default Of Registration Rights Agreements Each Subsequent Period		0.25%
Maximum Additional Interest Rate Accrued For Default Of Registration Rights Agreements All Periods		0.50%
Williams Partners L.P. [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	$ 3,500,000

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ARO Trust (Details) - USD ($) $ in Millions	Jun. 30, 2018	Dec. 31, 2017
Investments, Debt and Equity Securities [Abstract]
Annual funding obligation	$ 36.4
Schedule of Available-for-sale Securities [Line Items]
Available-for-sale securities, amortized cost basis	133.0	$ 116.0
Available-for-sale securities, fair value	151.3	134.6
Cash and Money Market Funds [Member]
Schedule of Available-for-sale Securities [Line Items]
Available-for-sale securities, amortized cost basis	14.7	12.6
Available-for-sale securities, fair value	14.7	12.6
U.S. Equity Funds [Member]
Schedule of Available-for-sale Securities [Line Items]
Available-for-sale securities, amortized cost basis	46.3	35.9
Available-for-sale securities, fair value	62.5	50.5
International Equity Funds [Member]
Schedule of Available-for-sale Securities [Line Items]
Available-for-sale securities, amortized cost basis	21.9	20.7
Available-for-sale securities, fair value	24.5	24.6
Municipal Bond Funds [Member]
Schedule of Available-for-sale Securities [Line Items]
Available-for-sale securities, amortized cost basis	50.1	46.8
Available-for-sale securities, fair value	$ 49.6	$ 46.9

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Fair Value Measurements (Details) - USD ($)	Jun. 30, 2018	Dec. 31, 2017	Jun. 30, 2017
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
ARO Trust investments	$ 151,300,000	$ 134,600,000
Fair Value, Transfers Between Level 1 and Level 2, Description and Policy [Abstract]
Fair Value, Assets, Level 1 to Level 2 Transfers, Amount	0		$ 0
Fair Value, Assets, Level 2 to Level 1 Transfers, Amount	0		0
Fair Value, Liabilities, Level 1 to Level 2 Transfers, Amount	0		0
Fair Value, Liabilities, Level 2 to Level 1 Transfers, Amount	0		$ 0
Fair Value, Inputs, Level 1 [Member]
Additional Fair Value Elements [Abstract]
Long-term debt, including current portion	0	0
Fair Value, Inputs, Level 2 [Member]
Additional Fair Value Elements [Abstract]
Long-term debt, including current portion	(3,638,900,000)	(3,103,300,000)
Fair Value, Inputs, Level 3 [Member]
Additional Fair Value Elements [Abstract]
Long-term debt, including current portion	0	0
Reported Value Measurement [Member]
Additional Fair Value Elements [Abstract]
Long-term debt, including current portion	(3,201,600,000)	(2,443,000,000)
Estimate of Fair Value Measurement [Member]
Additional Fair Value Elements [Abstract]
Long-term debt, including current portion	(3,638,900,000)	(3,103,300,000)
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
ARO Trust investments	151,300,000	134,600,000
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
ARO Trust investments	0	0
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
ARO Trust investments	0	0
Fair Value, Measurements, Recurring [Member] | Reported Value Measurement [Member]
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
ARO Trust investments	151,300,000	134,600,000
Fair Value, Measurements, Recurring [Member] | Estimate of Fair Value Measurement [Member]
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
ARO Trust investments	$ 151,300,000	$ 134,600,000

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Transactions with Affiliates (Details) $ in Thousands	1 Months Ended		3 Months Ended		6 Months Ended
	Jul. 31, 2018 USD ($)	Jul. 31, 2017 USD ($)	Jun. 30, 2018 USD ($) employee	Jun. 30, 2017 USD ($)	Jun. 30, 2018 USD ($) employee	Jun. 30, 2017 USD ($)	Dec. 31, 2017 USD ($)
Related Party Transaction [Line Items]
Advances to affiliate			$ 589,133		$ 589,133		$ 395,247
Related party transaction, rate					1.80%
Entity number of employees | employee			0		0
Expenses, related party			$ 99,300	$ 87,300	$ 190,800	$ 169,700
Cash distributions to parent					190,000	210,000
Cash contributions from parent					340,000	110,000
Noncash distribution to Parent		$ 240,000
Duration Of Period For Deferred Revenue Recognition		25 years
Affiliated Entity [Member]
Related Party Transaction [Line Items]
Operating revenues, related party			1,500	3,100	3,300	6,400
Cost of natural gas sales, related party			1,800	800	3,700	1,900
Expenses, related party			(1,200)	$ (900)	(2,200)	$ (1,800)
Williams Partners L.P. [Member]
Related Party Transaction [Line Items]
Advances to affiliate			$ 589,100		$ 589,100		$ 395,200
Subsequent Event [Member]
Related Party Transaction [Line Items]
Cash distributions to parent	$ 100,000

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Revenue Recognition Contract Liabilities (Details) - USD ($) $ in Thousands	3 Months Ended	6 Months Ended
	Jun. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Jan. 01, 2018
Revenue Recognition [Abstract]
Contract with Customer, Liability	$ 242,017	$ 242,017	$ 244,658	$ 247,296
Contract with Customer, Liability, Cumulative Catch-up Adjustment to Revenue, Change in Estimate of Transaction Price	0	0
Contract with Customer, Liability, Revenue Recognized	(2,641)	(5,279)
Other Receivable [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Receivables, Net, Current	6,900	6,900		$ 2,500
Performance Obligations Related To Contract Liabilities [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2018-07-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation	5,287	$ 5,287
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period		6 months
Performance Obligations Related To Contract Liabilities [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2019-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation	10,566	$ 10,566
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period		1 year
Performance Obligations Related To Contract Liabilities [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2020-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation	10,568	$ 10,568
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period		1 year
Performance Obligations Related To Contract Liabilities [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation	10,566	$ 10,566
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period		1 year
Performance Obligations Related To Contract Liabilities [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation	10,566	$ 10,566
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period		1 year
Performance Obligations Related To Contract Liabilities [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation	10,566	$ 10,566
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period		1 year
Performance Obligations Related To Contract Liabilities [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation	183,898	$ 183,898
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period		1 year
Remaining Performance Obligations [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2018-07-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation	850,434	$ 850,434
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period		6 months
Remaining Performance Obligations [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2019-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation	1,618,612	$ 1,618,612
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period		1 year
Remaining Performance Obligations [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2020-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation	1,515,147	$ 1,515,147
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period		1 year
Remaining Performance Obligations [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation	1,309,562	$ 1,309,562
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period		1 year
Remaining Performance Obligations [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation	1,116,179	$ 1,116,179
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period		1 year
Remaining Performance Obligations [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation	982,445	$ 982,445
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period		1 year
Remaining Performance Obligations [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation	$ 15,885,615	$ 15,885,615
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period		1 year