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 ~~September 30, 2017~~March 31, 2018



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

For the transition period from to

Commission file number 1-7584

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.

Table of Contents

TRANSCONTINTENTAL GAS PIPE LINE COMPANY, LLC

Index

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~~“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

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;

~~Whether Williams will be able to effectively manage the transition in its board of directors and management as well as successfully execute its business restructuring;~~

Our ability to successfully expand our facilities and operations;

Development and rate of adoption of alternative energy sources;

The impact of operational and ~~development~~developmental hazards, unforeseen interruptions, and the availability of adequate insurance ~~coverage for such interruptions;~~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

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, ~~2017.~~2018 and in Part II, Item 1A. Risk Factors in this Quarterly Report on Form 10-Q.

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 September 30,						Nine months ended September 30,						Three months ended March 31,
	2017			2016			2017			2016			2018			2017
Operating Revenues:
Natural gas sales	$	26,763		$	31,244		$	74,867		$	67,474		$	25,251		$	15,095
Natural gas transportation	389,080			346,004			1,116,891			1,042,547			426,579			362,565
Natural gas storage	33,954			34,258			102,778			88,315			34,767			34,889
Other	2,255			1,343			3,734			3,396			2,639			1,167
Total operating revenues	452,052			412,849			1,298,270			1,201,732			489,236			413,716

Operating Costs and Expenses:
Cost of natural gas sales	26,763			31,244			74,867			67,474			25,251			15,095
Cost of natural gas transportation	5,828			4,689			15,282			15,501			13,074			5,007
Operation and maintenance	113,101			83,916			267,914			225,975			87,016			72,713
Administrative and general	43,110			40,604			132,020			125,997			46,381			44,116
Depreciation and amortization	82,826			76,755			239,368			231,110			83,224			77,478
Taxes — other than income taxes	15,333			14,584			49,131			45,154			18,438			16,908
Other expense, net	13,475			12,894			43,112			41,541			17,841			15,222
Total operating costs and expenses	300,436			264,686			821,694			752,752			291,225			246,539

Operating Income	151,616			148,163			476,576			448,980			198,011			167,177

Other (Income) and Other Expenses:
Interest expense	41,304			37,318			115,797			113,957			45,074			37,257
Allowance for equity and borrowed funds used during construction (AFUDC)	(22,334		)	(19,922		)	(70,783		)	(45,656		)	(26,608		)	(23,030		)
Equity in earnings of unconsolidated affiliates	(912		)	(1,455		)	(3,322		)	(4,447		)
Equity in (earnings) losses of unconsolidated affiliates													1,590			(1,021		)
Miscellaneous other (income) expenses, net	(774		)	309			(5,972		)	655			(1,961		)	(885		)
Total other (income) and other expenses	17,284			16,250			35,720			64,509			18,095			12,321

Net Income	134,332			131,913			440,856			384,471			179,916			154,856

Other comprehensive income (loss):
Equity interest in unrealized gain (loss) on interest rate hedges (includes $38 and $41 for the three months ended and $75 and $140 for the nine months ended September 30, 2017 and September 30, 2016, respectively, of accumulated other comprehensive income reclassification for equity interest in realized losses on interest rate hedges)	72			156			108			(128		)
Other comprehensive income:
Equity interest in unrealized gain on interest rate hedges (includes $6 for 2018 and $15 for 2017, of accumulated other comprehensive income reclassification for equity interest in realized losses on interest rate hedges)													405			35

Comprehensive Income	$	134,404		$	132,069		$	440,964		$	384,343		$	180,321		$	154,891

See accompanying notes.

TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC

CONDENSED CONSOLIDATED BALANCE SHEET

(Thousands of Dollars)

(Unaudited)


	September 30, 2017		December 31, 2016		March 31, 2018		December 31, 2017
ASSETS

Current Assets:
Cash	$	—	$	—	$	—	$	—
Receivables:
Affiliates	326		489		511		1,109
Advances to affiliate	299,059		811,693		1,249,372		395,247
Trade and other	146,471		144,315		161,810		170,422
Transportation and exchange gas receivables	944		1,827		2,930		3,205
Inventories	47,685		55,209		77,913		40,027
Regulatory assets	90,367		87,059		105,331		97,149
Other	14,179		13,305		7,769		12,508
Total current assets	599,031		1,113,897		1,605,636		719,667

Investments, at cost plus equity in undistributed earnings	39,571		42,403		26,892		28,505

Property, Plant and Equipment:
Natural gas transmission plant	13,136,224		11,996,454		14,519,157		13,771,183
Less-Accumulated depreciation and amortization	3,833,689		3,687,473		3,919,145		3,859,520
Total property, plant and equipment, net	9,302,535		8,308,981		10,600,012		9,911,663

Other Assets:
Regulatory assets	269,000		264,001		287,375		276,315
Other	132,052		102,198		150,983		141,786
Total other assets	401,052		366,199		438,358		418,101

Total assets	$	10,342,189	$	9,831,480	$	12,670,898	$	11,077,936

(continued)

See accompanying notes.

TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC

CONDENSED CONSOLIDATED BALANCE SHEET

(Thousands of Dollars)

(Unaudited)


	September 30, 2017		December 31, 2016		March 31, 2018		December 31, 2017
LIABILITIES AND OWNER’S EQUITY
LIABILITIES AND MEMBER’S EQUITY

Current Liabilities:
Payables:
Affiliates	$	23,483	$	29,455	$	13,924	$	43,420
Trade and other	305,949		251,872		414,824		469,153
Transportation and exchange gas payables	3,555		1,571		2,072		2,121
Accrued liabilities	160,087		197,697		154,567		173,602
Long-term debt due within one year	251,320		—		251,541		251,430
Total current liabilities	744,394		480,595		836,928		939,726

Long-Term Debt	2,197,717		2,210,754		3,194,679		2,191,576

Other Long-Term Liabilities:
Asset retirement obligations	271,211		248,518		384,319		350,280
Regulatory liabilities	501,201		449,391		1,010,341		990,702
Advances for construction costs	261,487		283,028		602,569		426,771
Transportation prepayments	11,115		11,837
Deferred revenue	228,258		—		234,091		236,729
Other	4,573		6,088		5,326		4,828
Total other long-term liabilities	1,277,845		998,862		2,236,646		2,009,310

Contingent Liabilities and Commitments (Note 2)
Contingent Liabilities and Commitments (Note 3)

Owner’s Equity:
Member’s Equity:
Member’s capital	3,788,499		3,678,499		4,428,499		4,088,499
Retained earnings	2,333,616		2,462,760		1,973,404		1,848,488
Accumulated other comprehensive income	118		10		742		337
Total owner’s equity	6,122,233		6,141,269
Total member’s equity					6,402,645		5,937,324

Total liabilities and owner’s equity	$	10,342,189	$	9,831,480
Total liabilities and member’s equity					$	12,670,898	$	11,077,936

See accompanying notes.

TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC

CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS

(Thousands of Dollars)

(Unaudited)


	Nine months ended September 30,						Three months ended March 31,
	2017			2016			2018			2017
Cash flows from operating activities:
Net income	$	440,856		$	384,471		$	179,916		$	154,856
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Depreciation and amortization	239,368			231,110			83,224			77,478
Allowance for equity funds used during construction (equity AFUDC)	(53,867		)	(37,285		)	(19,782		)	(18,366		)
Equity in (earnings) losses of unconsolidated affiliates							1,590			(1,021		)
Distributions from unconsolidated affiliates							429			2,598
Changes in operating assets and liabilities:
Receivables — affiliates	163			341			598			(452		)
— trade and other	(2,156		)	17,045			8,612			6,231
Transportation and exchange gas receivable	883			(216		)	275			(1,467		)
Inventories	7,524			13,617			(37,886		)	(14,370		)
Payables — affiliates	(5,972		)	(23,340		)	(29,496		)	(1,064		)
— trade	(28,536		)	6,041			(52,553		)	(11,738		)
Accrued liabilities	(41,137		)	61,484			(13,385		)	(71,928		)
Asset retirement obligations - non-current	45,629			3,761			18,400			24,670
Asset retirement obligations - removal costs	(1,708		)	(2,688		)	(1,199		)	(222		)
Deferred revenue	(2,142		)	—			(2,638		)	—
Other, net	(4,691		)	23,451			(4,384		)	6,593
Net cash provided by operating activities	594,214			677,792			131,721			151,798

Cash flows from financing activities:
Proceeds from long-term debt	—			998,250			993,440			—
Retirement of long-term debt	—			(200,000		)
Proceeds from other financing obligation							18,804			—
Payments on other financing obligation	(241		)	—			(375		)	—
Payments for debt issuance costs	(13		)	(8,235		)	(9,025		)	(13		)
Cash distributions to parent	(330,000		)	(350,000		)	(55,000		)	(100,000		)
Cash contributions from parent	110,000			372,000			340,000			110,000
Net cash provided by (used in) financing activities	(220,254		)	812,015
Net cash provided by financing activities							1,287,844			9,987

Cash flows from investing activities:
Property, plant and equipment additions, net of equity AFUDC*	(1,089,917		)	(906,105		)	(737,004		)	(374,220		)
Contributions and advances for construction costs	252,249			157,545			188,543			131,874
Disposal of property, plant and equipment, net	(33,281		)	(4,439		)	(5,241		)	(2,131		)
Advances to affiliate, net	512,634			(718,279		)	(854,125		)	91,733
Return of capital from unconsolidated affiliates	2,729			2,106
Purchase of ARO Trust investments	(46,709		)	(61,086		)	(15,530		)	(22,418		)
Proceeds from sale of ARO Trust investments	27,520			38,330			3,792			10,177
Proceeds from insurance	3,200			2,121			—			3,200
Other, net	(2,385		)	—
Net cash used in investing activities	(373,960		)	(1,489,807		)	(1,419,565		)	(161,785		)

Increase (decrease) in cash	—			—			—			—
Cash at beginning of period	—			—			—			—
Cash at end of period	$	—		$	—		$	—		$	—

* Increase to property, plant and equipment, net of equity AFUDC	$	(1,154,317	)	$	(907,023	)	$	(721,921	)	$	(434,824	)
Changes in related accounts payable and accrued liabilities	64,400			918			(15,083		)	60,604
Property, plant and equipment additions, net of equity AFUDC	$	(1,089,917	)	$	(906,105	)	$	(737,004	)	$	(374,220	)

See accompanying notes.

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). In January 2017, Williams permanently waived the WPZ general partner's incentive distribution rights, converted its 2 percent general partner interest in WPZ to a non-economic interest and purchased additional WPZ common units. At ~~September 30, 2017~~March 31, 2018, Williams owns a 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 ~~September 30, 2017~~March 31, 2018 and December 31, ~~2016~~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 ~~$6.3~~$0.4 million and ~~$6.5~~$2.6 million in the ~~nine~~three months ended ~~September 30, 2017~~March 31, 2018 and ~~September 30, 2016~~March 31, 2017, ~~respectively. Included in the distributions are $2.7 million and $2.1 million return of capital in 2017 and 2016,~~ 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 ~~2016~~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.

Accounting Standards Issued ~~But Not Yet~~and Adopted

~~In August 2016, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU)~~Effective January 1, 2018, we adopted ASU 2016-15 “Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments” (ASU 2016-15). Among other things, ASU 2016-15 ~~provides specific guidance on eight cash flow classification issues, including debt prepayment or debt extinguishment costs and~~permits an accounting policy election to classify distributions received from ~~equity method~~equity-method investees using either the cumulative earnings approach or the nature of distribution approach. We have elected to ~~reduce diversity~~apply the nature of distribution approach and have retrospectively conformed the prior year presentation within the Condensed Consolidated Statement of Cash Flows in ~~practice.~~accordance with ASU ~~2016-15~~2016-15. For the period ended March 31, 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 $1.2 million with a corresponding reduction in Net cash used in investing activities.

In May 2014, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (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 is effective for interim and annual reporting periods beginning after December 15, 2017. ~~Early~~

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 ~~is permitted. ASU 2016-15 requires a retrospective transition. We do not expect ASU 2016-15~~of ASC 606, there are no changes to ~~have a material impact on~~the timing of our revenue recognition or differences in the presentation in our condensed consolidated financial ~~statements.~~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 clarifies the definition of a lease, requires a dual approach to lease classification similar to current lease ~~classifications,~~accounting, and causes lessees to recognize 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.~~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 and permits an entity to elect a transition practical expedient to not apply ASU 2016-02 to land easements that exist or expired before the effective date of ASU 2016-02 and that were not previously assessed under the previous lease guidance in ASC Topic 840 “Leases”. ASU 2016-02 is effective for interim and annual periods beginning after December 15, 2018. Early adoption is permitted. ASU 2016-02 currently requires a modified retrospective transition for ~~capital~~financing or operating leases existing at or entered into after the beginning of the earliest comparative period presented in the financial statements.

In January 2018, the FASB proposed an accounting standard update titled “Leases (Topic 842): Targeted Improvements”, which is an update to ASU 2016-02 allowing entities an additional transition method to the existing requirements whereby an entity could adopt the provisions of ASU 2016-02 by recognizing a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption without adjustment to the financial statements for periods prior to adoption. We expect to adopt ASU 2016-02 effective January 1, 2019.

We are in the process of reviewing contracts to identify leases ~~as well as~~based on the modified definition of a lease, implementing a financial lease accounting system, and evaluating internal control changes to support management in the ~~applicability~~accounting for and disclosure of leasing activities. While we are still in the process of completing our implementation evaluation of ASU 2016-02, we currently believe the most significant changes to ~~contracts involving easement/rights-of-way.~~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 currently available and proposed practical expedients on adoption.

~~In May 2014, the FASB issued ASU 2014-09 establishing Accounting Standards Codification (ASC) Topic 606, “Revenue from Contracts with Customers” (ASC 606). ASC 606 establishes~~

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 ~~comprehensive new revenue recognition model designed~~promise in a contract to ~~depict the~~ 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 acustomers, 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 ~~an amount that reflects~~our FERC tariffs. Revenue is recognized from the ~~consideration~~sale of natural gas upon settlement of the ~~entity expects~~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 ~~entitled~~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 ~~receive~~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 ~~exchange~~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 ~~requires significantly enhanced revenue disclosures. In August 2015,~~ the ~~FASB issued ASU 2015-14 “Revenue from Contracts with Customers (Topic 606): Deferral~~prevailing interest rates. We have assessed our contracts and determined none of the Effective Date” (ASU 2015-14). Per ASU 2015-14, the standard is effective for interim and annual reporting periods beginning after December 15, 2017. ASC 606 allows either full retrospective or modified retrospective transition and early adoption is permitted for annual periods beginning after December 15, 2016.

~~We continue to evaluate the impact ASC 606 may have on~~ our ~~financial statements. For each revenue contract type, we are conducting a formal contract review process to evaluate the impact, if any, that ASC 606 may have. We continue to evaluate~~ contracts ~~with~~contain a significant financing ~~component, which may exist in situations where the timing~~component.

The following table presents a reconciliation of the ~~consideration we receive varies significantly~~beginning and ending balances of our contract liabilities for the three months ended March 31, 2018:



	2018
	(Thousands)
Balance at January 1	$	247,296
Payments received and deferred	—
Recognized in revenue	(2,638		)
Balance at March 31	$	244,658

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



	(Thousands)
2018 (remainder)	$	7,928
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 March 31, 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 ~~timing~~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 ~~when we provide~~ the ~~service, as well as a certain contract with prepayments for services. We are unable to determine~~related contracts; however, these rates may change based on future tariffs approved by the ~~potential impact upon~~FERC and the amount and ~~the~~ 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 and consideration received prior to March 31, 2018, that will be recognized in future periods (see above for Contract Liabilities and the expected recognition of those amounts within revenue). As noted above, certain of our ~~revenue recognition. We continue to develop and evaluate disclosures required under~~contracts contain evergreen provisions for periods beyond the ~~new standard, with a particular focus on~~initial term of the ~~scope of contracts subject to disclosure of~~contract. The remaining performance ~~obligations. Additionally,~~obligation as of March 31, 2018, does not consider potential future performance obligations for which the renewal has not been exercised. The table below also does not include contracts with customers for which the underlying facilities have not received FERC authorization to be placed into service.



	(Thousands)
2018 (remainder)	$	1,284,187
2019	1,576,306
2020	1,482,893
2021	1,205,683
2022	1,095,132
2023	961,398
Thereafter	8,308,794
Total	$	15,914,393

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 ~~identified possible financial system~~not historically experienced recurring credit losses in connection with our receivables.

Receivables from contracts with customers are included within Receivables - Trade and ~~internal control changes necessary for adoption. We currently anticipate utilizing a modified retrospective transition upon the adoption~~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 March 31, 2018 and December 31, 2017, Receivables - Trade and other includes $4.4 million and $2.5 million, respectively, of ~~ASC 606 as of January 1, 2018.~~receivables not related to contracts with customers.

2.3. CONTINGENT LIABILITIES AND COMMITMENTS

Rate Matters

~~General rate case (Docket No. RP06-569)~~On ~~August 31, 2006, we submitted to the Federal Energy Regulatory Commission (FERC) a general rate filing principally designed to recover increased costs. The rates became effective~~ March ~~1, 2007, subject to refund and the outcome of a hearing. All issues in this proceeding except one have been resolved by settlement.~~

The one issue reserved for litigation or further settlement relates to our proposal to change the design of the rates for service under our WSS-OA storage rate schedule, which was implemented subject to refund on March 1, 2007. Following a hearing,15, 2018, the FERC issued a policy statement regarding the recovery of income tax costs in rates of natural gas pipelines. The FERC found that an ~~opinion approving our proposed incremental~~impermissible double recovery results from granting a Master Limited Partnership (MLP) pipeline both an income tax allowance and a return on equity pursuant to the discounted cash flow methodology. The FERC will no longer permit 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. The FERC also issued a Notice of Proposed Rulemaking proposing a process that will allow it to determine which natural gas pipelines may be collecting unjust and unreasonable rates in light of the recent reduction in the corporate income tax rate ~~design,~~in the Tax Cuts and ~~subsequently denied requests for rehearing of that approval. On February 21, 2014, the U. S. Court of Appeals for the D.C. Circuit (D.C. Circuit) issued an opinion that vacated~~Jobs Act (Tax Reform) and ~~remanded the FERC's order because the FERC did not adequately support its conclusions. On March 17, 2016,~~this policy statement. Furthermore, the FERC issued ~~an order addressing~~a Notice of Inquiry seeking comments on the ~~issues raised by the D.C. Circuit's opinion. In the March 17 order,~~additional impacts of Tax Reform on jurisdictional rates, particularly whether, and if so how, the FERC ~~reversed its prior opinion~~should address changes relating to accumulated deferred income tax amounts after the corporate income tax rate reduction and ~~found that Transco's incremental~~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 design is unjust and unreasonable. The FERC directed Transco to design its WSS-OA rates on a rolled-in basis, to file revised WSS-OA rates reflecting the findings in the order, and to refund the amounts collected in excess of those rates since March 1, 2007. On April 18, 2016, we submitted the compliance filing reflecting rolled-in rates for WSS-OA service consistent with the March 17 order, and began charging those rates beginning April 19, 2016.proceedings. We also ~~filed a request for rehearing of the March 17 order. On October 4, 2017, the FERC issued an order denying all requests for rehearing of the March 17 order, accepting~~continue to monitor developments that may impact our ~~April 18, 2016 compliance filing, and directing us to make refunds. As of September 30, 2017, we have accrued a liability for refunds of $19.3 million in~~ ~~Payables - Trade and other~~ ~~in the accompanying~~

~~Condensed Consolidated Balance Sheet. Assuming no further request for rehearing of the order~~regulatory liabilities resulting from Tax Reform. It is ~~filed, we expect to issue refunds in the fourth quarter of 2017.~~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 ~~general liability~~contractors' insurance ~~policy.~~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 ~~September 30, 2017~~March 31, 2018, we had a balance of approximately $3.9 million for the expense portion of these estimated costs, ~~$2.1~~$1.8 million recorded in Accrued liabilities and ~~$1.8~~$2.1 million recorded in Other Long-Term Liabilities - Other in the accompanying Condensed Consolidated Balance Sheet. At December 31, ~~2016~~2017, we had a balance of approximately ~~$4.2~~$4.0 million for the expense portion of these estimated costs, ~~$2.1~~$1.8 million recorded in Accrued liabilities and ~~$2.1~~$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.

~~In March 2008,~~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 ~~promulgated a new, lower~~issued its rule regarding National Ambient Air Quality ~~Standard (NAAQS)~~Standards for ground-level ~~ozone. In May 2012, the EPA completed designation~~ozone, setting a stricter standard of new eight-hour ozone non-attainment areas. Several of our facilities are located in 2008 ozone non-attainment areas. To date, no federal actions have been proposed to mandate additional emission controls at these facilities. Pursuant to recently finalized state regulatory actions associated with implementation of the 2008 ozone standard, we anticipate that some facilities may be subject to increased controls within five years. As a result, the cost of additions to property, plant, and equipment is expected to increase. We are unable at this time to estimate with any certainty the cost of additions that may be required to meet the proposed regulations.

~~In December 2014, the EPA proposed to further reduce the ground-level ozone NAAQS from the March 2008 levels and subsequently finalized a rule on October 1, 2015.~~70 parts per billion. We are monitoring the ~~rule's~~rule’s implementation as the reduction will trigger additional federal and state regulatory actions that may impact our operations. ~~As a~~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, ~~is expected to increase.~~net in the Condensed Consolidated Balance Sheet for both new and existing facilities in affected areas. We are unable ~~at this time~~ to ~~estimate with any certainty the cost of additions that may be required to meet new regulations.~~

~~In February 2010, the EPA set a new one-hour nitrogen dioxide (NO~~2~~) NAAQS. In January 2012, the EPA determined pursuant to available information that no area in the country is violating the 2010 NO~~2 NAAQS and thus designated all areas of the country as “unclassifiable/attainment.” However, the EPA or states may require ambient air quality modeling on a case by case basis to demonstrate compliance with the NO2 ~~standard. Because we are unable to predict the outcome of the EPA’s or states’ assessment of NO~~2 ~~compliance, we are unable to~~reasonably estimate the cost of additions that may be required to meet the regulations at this ~~regulation.~~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 ~~September 30, 2017,~~March 31, 2018, we had a balance of approximately ~~$1.6~~$1.9 million of uncollected environmental related regulatory assets, $1.2 million recorded in Current Assets - Regulatory assets and ~~$0.4~~$0.7 million recorded in Other Assets - Regulatory assets in the accompanying Condensed Consolidated Balance Sheet. At December 31, ~~2016,~~2017, we had a balance of approximately ~~$2.5~~$2.2 million of uncollected environmental related regulatory assets, $1.2 million recorded in Current Assets - Regulatory assets and ~~$1.3~~$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.

3.4. DEBT AND FINANCING ARRANGEMENTS

Credit Facility

We along with WPZ and Northwest Pipeline LLC, are party to a credit agreement 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 ~~September 30, 2017,~~March 31, 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 ~~September 30, 2017~~March 31, 2018, WPZ had no commercial paper ~~was~~ outstanding under the commercial paper program.

Other Financing Obligation

During the ~~construction~~first quarter of ~~our Dalton Expansion Project,~~2018, we received an additional $18.8 million of funding from a ~~partner~~co-owner for its proportionate share of construction costs related to its undivided ownership interest in the Dalton lateral. ~~Amounts received were recorded~~This additional funding is reflected in ~~Advances for construction costs~~Long-Term Debt on our Condensed Consolidated Balance Sheet. ~~Upon placing~~At March 31, 2018, the ~~project~~amount included in service during the third quarter of 2017, we began leasing this partner's undivided interest in the lateral, including the associated pipeline capacity, and reclassified approximately $235.8 million of funding previously received from our partner from ~~Advances for construction costs~~ to Long-Term Debt on our Condensed Consolidated Balance Sheet ~~to reflect the~~for this financing obligation ~~payable to~~is $247.7 million, and the amount included in Long-term debt due within one year on our ~~partner over an expected term of 35 years. As~~Condensed Consolidated Balance Sheet for this ~~transaction did not meet the criteria for sale leaseback accounting due to our continued involvement, it was accounted for as a~~ financing ~~arrangement over the course of the capacity agreement. The~~ obligation ~~matures in July 2052, requires monthly interest and principal payments, and bears an interest rate of approximately 10 percent.~~is $1.6 million.

Long-Term Debt Due Within One Year

The long-term debt due within one year at ~~September 30, 2017~~March 31, 2018 is associated with the $250 million of 6.05 percent notes maturing on June 15, 2018 and ~~$1.5 million associated~~ with the previously described other financing obligation.

Issuance 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 intend to use 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.

4.5. ARO TRUST

Available-for-Sale Investments

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 in available-for-sale securities within the ARO Trust at fair value were as follows (in millions):


	September 30, 2017				December 31, 2016				March 31, 2018				December 31, 2017
	Amortized Cost Basis		Fair Value		Amortized Cost Basis		Fair Value		Amortized Cost Basis		Fair Value		Amortized Cost Basis		Fair Value
Cash and Money Market Funds	$	8.5	$	8.5	$	5.0	$	5.0	$	24.3	$	24.3	$	12.6	$	12.6
U.S. Equity Funds	35.9		47.7		29.4		36.5		35.9		50.0		35.9		50.5
International Equity Funds	20.7		23.7		19.2		18.6		20.7		24.4		20.7		24.6
Municipal Bond Funds	46.8		47.1		36.7		36.3		46.8		46.3		46.8		46.9
Total	$	111.9	$	127.0	$	90.3	$	96.4	$	127.7	$	145.0	$	116.0	$	134.6

5.6. 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.


							Fair Value Measurements Using													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)		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)													(Millions)
Assets (liabilities) at September 30, 2017:
Assets (liabilities) at March 31, 2018:
Measured on a recurring basis:
ARO Trust investments	$	127.0		$	127.0		$	127.0	$	—		$	—	$	145.0		$	145.0		$	145.0	$	—		$	—

Additional disclosures:
Long-term debt, including current portion	(2,449.0		)	(3,051.1		)	—		(3,051.1		)	—		(3,446.2		)	(3,895.0		)	—		(3,895.0		)	—

Assets (liabilities) at December 31, 2016:
Assets (liabilities) at December 31, 2017:
Measured on a recurring basis:
ARO Trust investments	$	96.4		$	96.4		$	96.4	$	—		$	—	$	134.6		$	134.6		$	134.6	$	—		$	—

Additional disclosures:
Long-term debt	(2,210.8		)	(2,507.5		)	—		(2,507.5		)	—		(2,443.0		)	(3,103.3		)	—		(3,103.3		)	—

Fair Value of 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, are classified as available-for-sale 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 45 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 34 - 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 ~~nine~~three months ended ~~September 30, 2017~~March 31, 2018 or ~~2016~~2017.

6.7. TRANSACTIONS WITH AFFILIATES

We are a participant in WPZ’s cash management program, and we make advances to and receive advances from WPZ. At ~~September 30, 2017~~March 31, 2018 and December 31, ~~2016~~2017, our advances to WPZ totaled approximately $~~299.1~~1,249.4 million and $~~811.7~~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 ~~September 30, 2017~~March 31, 2018, the interest rate was ~~0.91~~1.54 percent.

Included in Operating Revenues in the accompanying Condensed Consolidated Statement of Comprehensive Income are revenues received from affiliates of ~~$2.5~~$1.8 million and ~~$8.9~~$3.3 million for the three ~~and nine~~ months ended ~~September 30,~~March 31,

2018 and 2017,~~, respectively, and $4.8 million and $8.9 million for the three and nine months ended September 30, 2016,~~ 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 ~~$1.0~~$1.9 million and ~~$2.9~~$1.1 million for the three ~~and nine~~ months ended ~~September 30,~~March 31, 2018 and 2017,~~, respectively, and $1.8 million and $3.3 million for the three and nine months ended September 30, 2016,~~ 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 ~~$91.4~~$91.5 million and ~~$261.1~~$82.4 million in the three ~~and nine~~ months ended ~~September 30,~~March 31, 2018 and 2017,~~, respectively and $78.4 million and $234.7 million in the three and nine months ended September 30, 2016,~~ 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. The amount billed to us for the nine months ended September 30, 2016, includes $6.3 million recognized in the first quarter for severance and other related costs associated with a reduction in workforce.

We provide services to certain of our affiliates. We recorded reductions in operating expenses for services provided to and reimbursed by our affiliates of ~~$0.9~~$1.0 million and ~~$2.7~~$0.9 million for the three ~~and nine~~ months ended ~~September 30,~~March 31, 2018 and 2017, ~~respectively, and $1.0 million and $3.4 million for the three and nine months ended September 30, 2016,~~ respectively.

We made equity distributions totaling $~~330.0~~55.0 million and $~~350.0~~100.0 million during the ~~nine~~three months ended ~~September 30, 2017~~March 31, 2018 and ~~2016~~2017, respectively. During ~~October 2017,~~April 2018, we made an additional distribution of ~~$100.0~~$135.0 million. Our parent made contributions to us totaling $~~110.0~~340.0 million and $~~372.0~~110.0 million in the ~~nine~~three months ended ~~September 30, 2017~~March 31, 2018 and ~~2016~~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 distribution to 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.

7.8. OTHER

~~For the nine months ended September 30, 2017 and 2016, we capitalized $0.2 million and $1.4 million, respectively, of project feasibility costs, which had been expensed in prior periods in~~ ~~Other expense, net, upon determining that the project was probable of development.~~

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

party under terms of the applicable lease ~~agreements. In the third quarter 2017, the advances received from a third party related to construction costs on the Dalton lateral was reclassified to~~ ~~Long-Term Debt~~ ~~on our Condensed Consolidated Balance Sheet.~~agreement.



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 ~~2016~~2017 Annual Report on Form 10-K and with the Condensed Consolidated Financial Statements and Notes contained in this Form 10-Q.

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 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 $471.1 million as of March 31, 2018. The timing and actual amount of such return will be subject to future negotiations regarding this matter and many other elements of cost-of-service rate proceedings, including other costs of providing service.

RESULTS OF OPERATIONS

Operating Income and Net Income

Operating Income for the ~~nine~~three months ended ~~September 30, 2017~~March 31, 2018 was $~~476.6~~198.0 million compared to $~~449.0~~167.2 million for the ~~nine~~three months ended ~~September 30, 2016~~March 31, 2017. The increase in Operating Income of ~~$27.6~~$30.8 million ~~(6.1~~(18.4 percent) was primarily due to higher Natural gas transportation ~~and~~ ~~Natural gas storage~~revenues in the first ~~nine~~three months of ~~2017~~2018 compared to the same period in ~~2016,~~2017, partly offset by an increase in Operating Costs and Expenses, as discussed below. Net Income for the ~~nine~~three months ended ~~September 30, 2017~~March 31, 2018 was ~~$440.9~~$179.9 million compared to ~~$384.5~~$154.9 million for the ~~nine~~three months ended ~~September 30, 2016.~~March 31, 2017. The increase in Net Income of ~~$56.4~~$25.0 million ~~(14.7~~(16.1 percent) was mostly attributable to the increase in Operating Income and ~~a favorable~~an unfavorable change in net expenses in Other (Income) and Other Expenses, as discussed below.

Operating Revenues

Natural gas sales increased ~~$7.4~~$10.2 million ~~(11.0~~(67.6 percent) for the ~~nine~~three months ended ~~September 30, 2017~~March 31, 2018 compared to the same period in ~~2016.~~2017. The increase was ~~primarily~~ due to ~~system management gas~~cash out sales. ~~System management gas~~Cash out sales 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 ~~nine~~three months ended ~~September 30, 2017~~March 31, 2018 increased ~~$74.4~~$64.0 million ~~(7.1~~(17.7 percent) over the same period in ~~2016~~2017. The increase was primarily ~~due to higher~~attributable to:

$58.2 million increase in transportation reservation revenues related to new incremental projects ~~of $88.4 million (primarily due to $38.3 million from our Gulf Trace project placed in service in February 2017, $28.0~~primarily attributable to:

$18.4 million from our Dalton project placed in partial service in April 2017, and fully in service in August ~~2017, $11.2~~2017;

$11.1 million from our Hillabee project Phase I placed in partial service in June 2017, and fully in service in July ~~2017 and $8.3~~2017;

•$9.8 million from our ~~Rock Springs~~Virginia Southside Phase II project placed in service in August 2016), partially offset by $6.7 million lower commodity revenues, $3.6 million due to one less billable day in 2017 compared to 2016, and $3.5 million lower firm transportation backhaul revenues.December 2017.

~~Natural gas storage~~• ~~increased $14.5~~$7.1 million ~~(16.4 percent) for the nine months ended~~from our Atlantic Sunrise project placed in partial service in September ~~30, 2017 compared to the same period~~2017;

$5.7 million from our New York Bay expansion project placed in ~~2016. The increase was primarily due to the absence~~service in October 2017; and

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

$4.4 million higher recoveries of ~~an accrual for Washington Storage Service potential refunds recorded~~electric power costs. Electric power costs are recovered from customers through transportation rates resulting in ~~2016.~~no net impact on our operating income or results of operations.

Operating Costs and Expenses

Excluding the Cost of natural gas sales, which is directly offset in revenues, of ~~$74.9~~$25.3 million for the ~~nine~~three months ended ~~September 30, 2017~~March 31, 2018 and ~~$67.5~~$15.1 million for the comparable period in ~~2016~~2017, our operating costs and expenses for the ~~nine~~three months ended ~~September 30, 2017~~March 31, 2018 increased ~~approximately $61.5~~$34.6 million ~~(9.0~~(15.0 percent) from the comparable period in ~~2016~~2017. This increase was primarily attributable to:

~~A $41.9~~$14.3 million ~~(18.5~~(19.7 percent) increase in Operation and maintenance costs primarily ~~due~~resulting from a $9.7 million increase in contracted services related to ~~$32.9 million higher costs for~~ pipeline integrity, general maintenance and other testing on our pipeline and ~~$4.0~~$4.5 million higher employee labor and related benefit costs;

~~An $8.3~~$8.1 million ~~(3.6~~(162.0 percent) increase in Cost of natural gas transportation costs primarily resulting from $4.4 million higher electric power costs and $3.6 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;

$5.7 million (7.4 percent) increase in Depreciation and amortization costs primarily due to ~~$12.2~~$8.4 million higher expense ~~due~~related to additional assets placed into service, ~~after third quarter 2016,~~ partly offset by ~~$4.3~~$3.3 million lower ~~expense due to ARO-related~~ARO related depreciation; and

~~A $6.0~~$2.6 million ~~(4.8~~(17.1 percent) increase in ~~Administrative and general~~ ~~costs primarily due to higher allocated corporate expenses; and~~

~~A $3.9 million (8.6 percent) increase in~~ ~~Taxes - other than income taxes~~Other expense, net primarily ~~due~~related to ~~higher ad valorem taxes as~~an unfavorable change in the deferral of ARO related depreciation to a ~~result of additional assets placed into service.~~regulatory asset.

Other (Income) and Other Expenses

Other (income) and other expenses for the ~~nine~~three months ended ~~September 30, 2017~~March 31, 2018 had ~~a favorable~~an unfavorable change of ~~$28.8~~$5.8 million ~~(44.7~~(47.2 percent) over the same period in ~~2016~~2017. This is mostly due to ana $7.8 million increase in Interest expense of which $6.0 million is associated with a financing obligation (See Note 4), partly offset by a favorable change of $3.6 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

~~Gulf Trace~~

The Gulf Trace Expansion Project involves an expansion of our existing natural gas transmission system together with greenfield facilities to provide incremental firm transportation capacity from Station 65 in St. Helena Parish, Louisiana westward to a new interconnection with Sabine Pass Liquefaction in Cameron Parish, Louisiana. We placed the project into service on February 1, 2017, and it increased capacity by 1,200 Mdth/d.

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 ~~will be leased~~is dedicated to Sabal ~~Trail.~~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 ~~was,~~is, in part, related to furthering the completion of the project, ~~this~~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 ~~all~~any timely petitions for rehearing). ~~We, along~~In compliance with ~~other intervenors,~~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 ~~FERC have filed petitions for rehearing with the court to overturn the remedy that would involve vacating the FERC certificate order. If the court's mandate is~~other Southeast Market Pipelines projects. As this order was issued prior to the ~~FERC re-issuing certificate authority for the projects,~~court's mandate (which was issued on March 30, 2018), we ~~believe that the FERC will take the necessary steps (which may include issuing temporary certificate authority) to avoid any~~experienced no lapse in ~~federal~~FERC authorization for the ~~projects.~~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. ~~The project will be constructed in phases. The FERC certificate for the project and the other regulatory approvals necessary to commence construction of the project have been received.~~ We placed the initial phase of the project into service on September 9, 2017 and ~~plan to place~~ the remaining portion of the project was placed into service ~~during the second quarter of~~on March 23, 2018. ~~The project is expected to increase capacity by 180 Mdth/d.~~

~~Dalton~~

The Dalton Expansion Project involves an expansion of our existing natural gas transmission system together with greenfield facilities to provide incremental firm transportation capacity from our Station 210 Pooling Point in New Jersey to markets in northwest Georgia. On April 1, 2017, we began providing firm transportation service through the mainline portion of the project (from the Station 210 Pooling Point to the interconnection with Gulf South at Holmesville in Mississippi) on an interim basis, and on August 1, 2017, we placed the full project into service. The project increased capacity by ~~448~~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 plan to place the full project into service during mid-2018, assuming timely receipt of the remaining regulatory approvals. The full project is expected to increase capacity by 1,700 Mdth/d.

~~Virginia Southside II~~

The Virginia Southside II Expansion Project involves an expansion of our existing natural gas transmission system together with greenfield facilities to provide incremental firm transportation capacity from our Station 210 Pooling Point in New Jersey and our Station 165 Pooling Point in Virginia to a proposed delivery point on a new lateral off of our Brunswick Lateral in Virginia. The FERC certificate for the project and the other regulatory approvals necessary to commence construction of the project have been received. We plan to place the project into service during the fourth quarter of 2017, and it is expected to increase capacity by 250 Mdth/d.

~~New York Bay Expansion~~

The New York Bay Expansion 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 and the Narrows meter station in New York. We placed the project into service on October 6, 2017, and it increased capacity by 115 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. ~~We filed an application with~~In November 2017, we received approval from the FERC ~~in August 2016~~ for ~~approval of~~ 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. ~~We filed an~~On April 20, 2018, the New York State Department of Environmental Conservation (NYSDEC) denied, without prejudice, Transco's application ~~with the FERC in March 2017~~ for ~~approval of~~certain permits required for the project. We have addressed the technical issues identified by NYSDEC and will refile our application for the permits. We plan to place the project into service in late 2019 or during the first half of 2020, assuming timely receipt of all necessary regulatory approvals. The project is expected to increase capacity by 400 Mdth/d.

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 ~~expect to file~~filed an application with the FERC in ~~the fourth quarter of~~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.



ITEM 4.	Controls and Procedures

Our management, including our Senior Vice President and our Vice President, Controller 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)~~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, Controller and Chief Accounting Officer. Based upon that evaluation, our Senior Vice President and our Vice President, Controller 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 ~~third~~first quarter of ~~2017~~2018 that have materially affected, or are reasonably likely to materially affect, our Internal Control over Financial Reporting.

PART II — OTHER INFORMATION.



ITEM 1.	Legal Proceedings

~~Environmental~~

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

~~Other~~

The ~~additional~~ information called for by this item is provided in Note 23 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.

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:

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

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



ITEM 6.	Exhibits

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).

4.1		Indenture, dated as of March 15, 2018, between Transcontinental Gas Pipe Line Company, LLC and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on March 15, 2018 as Exhibit 4.1 to our current report on Form 8-K (File No. 001-07584) and incorporated herein by reference).

10.1		Registration Rights Agreement, dated March 15, 2018, among Transcontinental Gas Pipe Line Company, LLC and the initial purchasers listed therein (filed on March 15, 2018 as Exhibit 10.1 to our current report on Form 8-K (File No. 001-07584) 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.

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:	~~November 2, 2017~~May 3, 2018	By:	/s/ Ted T. Timmermans
			Ted T. Timmermans
			Vice President, Controller and Chief Accounting Officer
			(Principal Accounting Officer)



	Page
Part I. Financial Information:
Item 1. Financial Statements
Condensed Consolidated Statement of Comprehensive Income —Three ~~and Nine~~ Months Ended ~~September 30,~~March 31, 2017 and ~~2016~~2018	4
Condensed Consolidated Balance Sheet — ~~September 30, 2017~~March 31, 2018 and December 31, ~~2016~~2017	5
Condensed Consolidated Statement of Cash Flows — ~~Nine~~Three Months Ended ~~September 30,~~March 31, 2018 and 2017 ~~and 2016~~	7
Notes to Condensed Consolidated Financial Statements	8

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	1618

Item 4. Controls and Procedures	1921

Part II. Other Information	1921

Item 1. Legal Proceedings	1921

Item 1A. Risk Factors	22

Item 6. Exhibits	2023