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, 2019



¨	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)

Securities registered pursuant to Section 12(b) of the Act: None

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

THE 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



	Page
Part I. Financial Information:
Item 1. Financial Statements
Condensed Consolidated Statement of Comprehensive Income —Three ~~and Nine~~ Months Ended ~~September 30, 2017~~March 31, 2019 and ~~2016~~2018	4
Condensed Consolidated Balance Sheet — ~~September 30, 2017~~March 31, 2019 and December 31, ~~2016~~2018	5
Condensed Consolidated Statement of ~~Cash Flows~~Member's Equity — ~~Nine~~Three Months Ended ~~September 30, 2017~~March 31, 2019 and ~~2016~~2018	7
Condensed Consolidated Statement of Cash Flows — Three Months Ended March 31, 2019 and 2018	8
Notes to Condensed Consolidated Financial Statements	89

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	1619

Item 4. Controls and Procedures	1922

Part II. Other Information	1922

Item 1. Legal Proceedings	1922

Item 1A. Risk Factors	22

Item 6. Exhibits	2023

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;~~prices;

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

Our ability to successfully expand our facilities and operations;

Development and rate of adoption of alternative energy sources;

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

The impact of existing and future laws and regulations, the regulatory environment, environmental liabilities, and litigation, as well as our ability to obtain necessary permits and approvals and achieve favorable rate proceeding outcomes;

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

Changes in maintenance and construction ~~costs;~~costs, as well as our ability to obtain sufficient construction related inputs including skilled labor;

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,~~incidents, 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.~~21, 2019.

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			2019			2018
Operating Revenues:
Natural gas sales	$	26,763		$	31,244		$	74,867		$	67,474		$	24,086		$	25,251
Natural gas transportation	389,080			346,004			1,116,891			1,042,547			534,160			426,579
Natural gas storage	33,954			34,258			102,778			88,315			36,085			34,767
Other	2,255			1,343			3,734			3,396			2,762			2,639
Total operating revenues	452,052			412,849			1,298,270			1,201,732			597,093			489,236

Operating Costs and Expenses:
Cost of natural gas sales	26,763			31,244			74,867			67,474			24,086			25,251
Cost of natural gas transportation	5,828			4,689			15,282			15,501			14,635			13,074
Operation and maintenance	113,101			83,916			267,914			225,975			83,448			87,016
Administrative and general	43,110			40,604			132,020			125,997			48,151			46,381
Depreciation and amortization	82,826			76,755			239,368			231,110			104,623			83,224
Taxes — other than income taxes	15,333			14,584			49,131			45,154			20,277			18,438
Regulatory credit resulting from Tax Reform													(1,749		)	—
Other expense, net	13,475			12,894			43,112			41,541			13,349			17,841
Total operating costs and expenses	300,436			264,686			821,694			752,752			306,820			291,225

Operating Income	151,616			148,163			476,576			448,980			290,273			198,011

Other (Income) and Other Expenses:
Interest expense	41,304			37,318			115,797			113,957			71,091			45,074
Allowance for equity and borrowed funds used during construction (AFUDC)	(22,334		)	(19,922		)	(70,783		)	(45,656		)	(8,714		)	(26,608		)
Equity in earnings of unconsolidated affiliates	(912		)	(1,455		)	(3,322		)	(4,447		)
Equity in (earnings) losses of unconsolidated affiliates													(771		)	1,590
Miscellaneous other (income) expenses, net	(774		)	309			(5,972		)	655			(1,035		)	(1,961		)
Total other (income) and other expenses	17,284			16,250			35,720			64,509			60,571			18,095

Net Income	134,332			131,913			440,856			384,471			229,702			179,916

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		)
Equity interest in unrealized gain (loss) on interest rate hedges (includes $(78) for 2019 and $6 for 2018, of accumulated other comprehensive income reclassification for equity interest in realized losses (gains) on interest rate hedges)													(230		)	405

Comprehensive Income	$	134,404		$	132,069		$	440,964		$	384,343		$	229,472		$	180,321

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, 2019		December 31, 2018
ASSETS

Current Assets:
Cash	$	—	$	—	$	—	$	—
Receivables:
Affiliates	326		489		399		1,018
Advances to affiliate	299,059		811,693		—		33,034
Trade and other	146,471		144,315		234,245		201,198
Transportation and exchange gas receivables	944		1,827		6,339		4,515
Inventories	47,685		55,209		67,736		63,205
Regulatory assets	90,367		87,059		103,903		95,770
Other	14,179		13,305		7,474		12,574
Total current assets	599,031		1,113,897		420,096		411,314

Investments, at cost plus equity in undistributed earnings	39,571		42,403		25,815		26,520

Property, Plant and Equipment:
Natural gas transmission plant	13,136,224		11,996,454		16,073,782		15,908,878
Less-Accumulated depreciation and amortization	3,833,689		3,687,473		4,240,363		4,147,729
Total property, plant and equipment, net	9,302,535		8,308,981		11,833,419		11,761,149

Other Assets:
Regulatory assets	269,000		264,001		273,733		289,479
Right-of-use assets					89,824		—
Other	132,052		102,198		187,070		167,490
Total other assets	401,052		366,199		550,627		456,969

Total assets	$	10,342,189	$	9,831,480	$	12,829,957	$	12,655,952

(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, 2019		December 31, 2018
LIABILITIES AND OWNER’S EQUITY
LIABILITIES AND MEMBER’S EQUITY

Current Liabilities:
Payables:
Affiliates	$	23,483	$	29,455		$	46,485	$	50,727
Advances from affiliates					86,580	86,580		—
Trade and other	305,949		251,872			165,998		226,911
Transportation and exchange gas payables	3,555		1,571			3,480		5,973
Regulatory liabilities						44,226		5,097
Accrued liabilities	160,087		197,697			208,382		218,384
Long-term debt due within one year	251,320		—			15,810		15,419
Total current liabilities	744,394		480,595			570,961		522,511

Long-Term Debt	2,197,717		2,210,754			4,003,258		3,998,988

Other Long-Term Liabilities:
Asset retirement obligations	271,211		248,518			366,945		348,609
Regulatory liabilities	501,201		449,391			991,779		1,026,892
Advances for construction costs	261,487		283,028
Transportation prepayments	11,115		11,837
Deferred revenue	228,258		—			223,526		226,164
Lease liability						85,759		—
Other	4,573		6,088			5,657		4,188
Total other long-term liabilities	1,277,845		998,862			1,673,666		1,605,853

Contingent Liabilities and Commitments (Note 2)
Contingent Liabilities and Commitments (Note 4)

Owner’s Equity:
Member’s Equity:
Member’s capital	3,788,499		3,678,499			4,428,499		4,428,499
Retained earnings	2,333,616		2,462,760			2,153,269		2,099,567
Accumulated other comprehensive income	118		10			304		534
Total owner’s equity	6,122,233		6,141,269
Total member’s equity						6,582,072		6,528,600

Total liabilities and owner’s equity	$	10,342,189	$	9,831,480
Total liabilities and member’s equity						$	12,829,957	$	12,655,952

See accompanying notes.

TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC

CONDENSED CONSOLIDATED STATEMENT OF MEMBER’S EQUITY

(Thousands of Dollars)

(Unaudited)



	Three months ended March 31,
	2019			2018
Member's Capital:
Balance at beginning of period	$	4,428,499		$	4,088,499
Cash contributions from parent	—			340,000
Balance at end of period	4,428,499			4,428,499
Retained Earnings:
Balance at beginning of period	2,099,567			1,848,488
Net income	229,702			179,916
Cash distributions to parent	(176,000		)	(55,000		)
Balance at end of period	2,153,269			1,973,404
Accumulated Other Comprehensive Income:
Balance at beginning of period	534			337
Equity interest in unrealized gain (loss) on interest rate hedge	(230		)	405
Balance at end of period	304			742

Total Member's Equity	$	6,582,072		$	6,402,645

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			2019			2018
Cash flows from operating activities:
Net income	$	440,856		$	384,471		$	229,702		$	179,916
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Depreciation and amortization	239,368			231,110			104,623			83,224
Allowance for equity funds used during construction (equity AFUDC)	(53,867		)	(37,285		)	(6,510		)	(19,782		)
Regulatory credit resulting from Tax Reform							(1,749		)	—
Equity in (earnings) losses of unconsolidated affiliates							(771		)	1,590
Distributions from unconsolidated affiliates							1,248			429
Changes in operating assets and liabilities:
Receivables — affiliates	163			341			619			598
— trade and other	(2,156		)	17,045			(33,047		)	8,612
Transportation and exchange gas receivable	883			(216		)	(1,824		)	275
Inventories	7,524			13,617			(4,531		)	(37,886		)
Payables — affiliates	(5,972		)	(23,340		)	(4,242		)	(29,496		)
— trade	(28,536		)	6,041			(45,546		)	(52,553		)
Accrued liabilities	(41,137		)	61,484			(13,105		)	(11,473		)
Asset retirement obligations - non-current	45,629			3,761			18,577			17,201
Asset retirement obligations - removal costs	(1,708		)	(2,688		)
Deferred revenue	(2,142		)	—			(2,638		)	(2,638		)
Other, net	(4,691		)	23,451			3,419			(6,296		)
Net cash provided by operating activities	594,214			677,792			244,225			131,721

Cash flows from financing activities:
Proceeds from long-term debt	—			998,250			—			993,440
Retirement of long-term debt	—			(200,000		)
Payments on other financing obligation	(241		)	—
Proceeds from other financing obligations							7,914			18,804
Payments on other financing obligations							(3,680		)	(375		)
Payments for debt issuance costs	(13		)	(8,235		)	—			(9,025		)
Cash distributions to parent	(330,000		)	(350,000		)	(176,000		)	(55,000		)
Cash contributions from parent	110,000			372,000			—			340,000
Advances from affiliate, net							86,580			—
Net cash provided by (used in) financing activities	(220,254		)	812,015			(85,186		)	1,287,844

Cash flows from investing activities:
Property, plant and equipment additions, net of equity AFUDC*	(1,089,917		)	(906,105		)	(184,556		)	(737,004		)
Contributions and advances for construction costs	252,249			157,545			10,057			188,543
Disposal of property, plant and equipment, net	(33,281		)	(4,439		)	(5,477		)	(5,241		)
Advances to affiliate, net	512,634			(718,279		)	33,034			(854,125		)
Return of capital from unconsolidated affiliates	2,729			2,106
Purchase of ARO Trust investments	(46,709		)	(61,086		)	(19,518		)	(15,530		)
Proceeds from sale of ARO Trust investments	27,520			38,330			9,767			3,792
Proceeds from insurance	3,200			2,121
Other, net	(2,385		)	—			(2,346		)	—
Net cash used in investing activities	(373,960		)	(1,489,807		)	(159,039		)	(1,419,565		)

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	)	$	(161,741	)	$	(721,921	)
Changes in related accounts payable and accrued liabilities	64,400			918			(22,815		)	(15,083		)
Property, plant and equipment additions, net of equity AFUDC	$	(1,089,917	)	$	(906,105	)	$	(184,556	)	$	(737,004	)

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, 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, 2019 and December 31, ~~2016~~2018 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~~$1.2 million and ~~$6.5~~$0.4 million in the ~~nine~~three months ended ~~September 30, 2017~~March 31, 2019 and ~~September 30, 2016~~March 31, 2018, ~~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~~2018 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.

A reclassification within operating activities in the Condensed Consolidated Statement of Cash Flows between Accrued liabilities and Other, net of $1.9 million for the three months ended March 31, 2018, has been made to conform to the 2019 presentation.

Income Taxes

We generally are not a taxable entity for federal or state and local income tax purposes. The tax on net income is generally borne by our parent, Williams. Net income for financial statement purposes may differ significantly from taxable income of Williams as a result of differences between the tax basis and financial reporting basis of assets and liabilities.

Revenue Subject to Refund

Federal Energy Regulatory Commission (FERC) regulations promulgate policies and procedures which govern a process to establish the rates that we are permitted to charge customers for natural gas sales and services, including the transportation and storage of natural gas. Key determinants in the ratemaking process are (1) costs of providing service, including depreciation expense, (2) allowed rate of return, including the equity component of the capital structure and related taxes, and (3) volume throughput assumptions.

As a result of the ratemaking process, certain revenues collected by us may be subject to refund 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 estimated total exposure, as well as collection and other risks. Depending on the results of these proceedings, the actual amounts allowed to be collected from customers could differ from management's estimate. In addition, as a result of rate orders, tariff provisions or regulations, we are required to refund or credit certain revenues to our customers. At March 31, 2019, we have provided a reserve for rate refunds related to Docket No. RP18-1126 which we believe is adequate for any refunds that may be required.

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

In ~~August~~February 2016, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) ~~2016-15 “Statement of Cash Flows~~2016-02 “Leases (Topic ~~230): Classification of Certain Cash Receipts and Cash Payments”~~842)” (ASU ~~2016-15)~~2016-02). ASU ~~2016-15 provides specific~~2016-02 establishes a comprehensive new lease accounting model. ASU 2016-02 modifies the definition of a lease, requires a dual approach to lease classification similar to prior lease accounting, and causes lessees to recognize operating leases on the balance sheet as a lease liability measured as the present value of the future lease payments with a corresponding right-of-use asset, with an exception for leases with a term of one year or less. Additional disclosures are required regarding the amount, timing, and uncertainty of cash flows arising from leases. In January 2018, the FASB issued ASU 2018-01 “Leases (Topic 842): Land Easement Practical Expedient for Transition to Topic 842” (ASU 2018-01). Per ASU 2018-01, land easements and rights-of-way are required to be assessed under ASU 2016-02 to determine whether the arrangements are or contain a lease. ASU 2018-01 permits an entity to elect a transition practical expedient to not apply ASU 2016-02 to land easements that exist or expired before the effective date of ASU 2016-02 and that were not previously assessed under the previous lease guidance ~~on eight cash flow classification issues, including debt prepayment~~in Accounting Standards Codification (ASC) Topic 840 “Leases.”

In July 2018, the FASB issued ASU 2018-11 “Leases (Topic 842): Targeted Improvements” (ASU 2018-11). Prior to ASU 2018-11, a modified retrospective transition was required for financing or ~~debt extinguishment costs and distributions received~~operating leases existing at or entered into after the beginning of the earliest comparative period presented in the financial statements. ASU 2018-11 allows entities an additional transition method to the existing requirements whereby an entity could adopt the provisions of ASU 2016-02 by recognizing a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption without adjustment to the financial statements for periods prior to adoption. ASU 2018-11 also allows a practical expedient that permits lessors to not separate non-lease components from ~~equity method investees, to reduce diversity in practice.~~the associated lease component if certain conditions are present. ASU ~~2016-15~~2016-02 is effective for interim and annual periods beginning after December 15, ~~2017. Early~~2018. We prospectively adopted ASU 2016-02 effective January 1, 2019, and did not adjust prior periods as permitted by ASU 2018-11 (See Note 3).

We completed our review of contracts to identify leases based on the modified definition of a lease and implemented changes to our internal controls to support management in the accounting for and disclosure of leasing activities upon adoption ~~is permitted.~~of ASU ~~2016-15 requires~~2016-02. We implemented a ~~retrospective transition.~~financial lease accounting system to assist management in the accounting for leases upon adoption. The most significant changes to our financial statements as a result of adopting ASU 2016-02 relate to the recognition of a $91.3 million lease liability and offsetting right-of-use asset in our Condensed Consolidated Balance Sheetfor operating leases. We doalso evaluated ASU 2016-02’s available practical expedients on adoption. We generally elected to adopt the practical expedients, which includes the practical expedient to not ~~expect ASU 2016-15 to have a material impact on our consolidated financial statements.~~separate lease and non-lease components by both lessees and lessors by class of underlying assets and the land easements practical expedient.

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.~~We plan to adopt as of January 1, 2020. We anticipate that ASU 2016-13 ~~requires varying transition methods for the different categories of amendments. We~~will primarily apply to our trade receivables. While we do not expect ~~ASU 2016-13 to have~~ a significant financial impact, we are currently developing additional processes, procedures and internal controls in order to make the necessary credit loss assessments and required disclosures.

2. REVENUE RECOGNITION

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

The following table presents a reconciliation of our contract liabilities:



		Year to Date March 31, 2019
	(Thousands)
Balance at beginning of period		$	236,730
Payments received and deferred		—
Recognized in revenue		(2,638		)
Balance at end of period		$	234,092

The following table presents the amount of the contract liabilities balance as of March 31, 2019, expected to be recognized as revenue in each of the next five years as performance obligations are expected to be satisfied:



	(Thousands)
2019 (remainder)	$	7,928
2020	10,568
2021	10,566
2022	10,566
2023	10,566
Thereafter	183,898
Total	$	234,092

Remaining Performance Obligations

The following table presents the transaction price allocated to the remaining performance obligations under certain contracts as of March 31, 2019. These primarily include reservation charges on contracted capacity on our ~~consolidated financial statements.~~firm transportation and storage contracts with customers. Amounts from certain contracts included in the table below, which are subject to the periodic review and approval by the FERC, reflect the rates for such services in our current FERC tariffs, net of estimated reserve for refund, for the life of the related contracts; however, these rates may change based on future tariffs approved by the FERC and the amount and timing of these changes is not currently known. This table excludes the variable consideration component for commodity charges. It also excludes consideration that will be recognized in future periods (see above for Contract Liabilities and the expected recognition of those amounts within revenue). Certain of our contracts contain evergreen provisions for periods beyond the initial term of the contract. The remaining performance obligations as of March 31, 2019, do 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.

~~In February 2016, the FASB issued ASU 2016-02 “Leases (Topic 842)” (ASU 2016-02). ASU 2016-02 establishes~~



	(Thousands)
2019 (remainder)	$	1,637,961
2020	2,060,759
2021	1,970,683
2022	1,673,295
2023	1,442,724
Thereafter	13,219,316
Total	$	22,004,738

Accounts Receivable

Receivables from contracts with customers are included within Receivables - Trade and other and Receivables - Affiliates and receivables that are not related to contracts with customers are included with Receivables - Advances to affiliate in our Condensed Consolidated Balance Sheet. At March 31, 2019 and December 31, 2018, Receivables - Trade and other includes $13.8 million and $10.4 million, respectively, of receivables not related to contracts with customers.

3. LEASES

We are a ~~comprehensive new~~lessee through noncancellable lease ~~accounting model. ASU 2016-02 clarifies the definition~~agreements for property and equipment consisting primarily of ~~a lease, requires a dual approach to lease classification similar to current lease classifications,~~buildings, land, vehicles, and ~~causes lessees to~~equipment used in both our operations and administrative functions. We recognize ~~leases on the balance sheet as~~ a lease liability with ~~a corresponding~~an offsetting right-of-use asset in our Condensed Consolidated Balance Sheet for operating leases based on the present value of the future lease payments. As an accounting policy, we have elected to combine lease and non-lease components for all classes of leased assets in our calculation of the lease liability and the offsetting right-of-use asset. ~~ASU 2016-02~~

Our lease agreements require both fixed and variable periodic payments, with initial terms typically ranging from one to 15 years, but a certain land lease has a term of 108 years. Payment provisions in certain of our lease agreements contain escalation factors which may be based on stated rates or a change in a published index at a future time. The amount by which a lease escalates based on the change in a published index, which is ~~effective~~not known at lease commencement, is considered a variable payment and is not included in the present value of the future lease payments, which only includes those that are stated or can be calculated based on the lease agreement at lease commencement. In addition to the noncancellable periods, many of our lease agreements provide for ~~interim~~one or more extensions of the lease agreement for periods ranging from one year in length to an indefinite number of times following the specified contract term. Other lease agreements provide for extension terms that allow us to utilize the identified leased asset for an indefinite period of time so long as the asset continues to be utilized in our operations. In consideration of these renewal features, we assess the term of the lease agreements, which includes using judgment in the determination of which renewal periods and ~~annual periods beginning after December 15, 2018. Early adoption is permitted. ASU 2016-02 requires a modified retrospective transition for capital or operating leases existing~~termination provisions, when at ~~or entered into~~our sole election, will be reasonably certain of being exercised. Periods after the ~~beginning~~initial term or extension terms that allow for either party to the lease to cancel the lease are not considered in the assessment of the earliest comparative period presented in the financial statements. We are in the process of reviewing contracts to identify leases, as well as evaluating the applicability of ASU 2016-02 to contracts involving easement/rights-of-way.

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 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. 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 a significant financing component, which may exist in situations where the timing of the consideration we receive varies significantly from the timing of when we provide the service, as well as a certain contract with prepayments for services. We are unable to determine the potential impact upon the amount and the timing of our revenue recognition. We continue to develop and evaluate disclosures required under the new standard, with a particular focus on the scope of contracts subject to disclosure of remaining performance obligations.lease term. Additionally, we have ~~identified possible financial system~~elected to exclude leases with an original term of one year or less, including renewal periods, from the calculation of the lease liability and ~~internal control changes necessary~~the offsetting right-of-use asset.

We used judgment in determining the discount rate upon which the present value of the future lease payments is determined. This rate is based on a collateralized interest rate corresponding to the term of the lease agreement using company, industry, and market information available.



	Three Months Ended March 31, 2019
	(Thousands)
Lease Cost:
Operating lease cost	$	2,502
Short-term lease cost	—
Variable lease cost	1,392
Total lease cost	$	3,894

Cash paid for amounts included in the measurement of operating lease liabilities	$	2,388

	March 31, 2019
	(Thousands)
Other Information:
Right-of-use assets	$	89,824
Operating lease liabilities:
Current (included in Accrued liabilities in our Condensed Consolidated Balance Sheet)	$	3,482
Lease liability	$	85,759
Weighted-average remaining lease term - operating leases (years)	15
Weighted-average discount rate - operating leases	5		%

As of March 31, 2019, the following table represents our operating lease maturities, including renewal provisions that we have assessed as being reasonably certain of exercise, for ~~adoption. We currently anticipate utilizing a modified retrospective transition upon~~each of the ~~adoption of ASC 606 as of January 1, 2018.~~years ended December 31:



	(Thousands)
2019 (remainder)	$	6,540
2020	7,367
2021	9,448
2022	9,431
2023	9,435
Thereafter	86,075
Total future lease payments	128,296
Less amount representing interest	39,055
Total obligations under operating leases	$	89,241

2.4. CONTINGENT LIABILITIES AND COMMITMENTS

Rate Matters

General rate case (Docket No. ~~RP06-569)~~RP18-1126) On August 31, ~~2006,~~2018, we ~~submitted to the Federal Energy Regulatory Commission (FERC)~~filed a general rate case with the FERC for an overall increase in rates and to comply with the terms of the settlement in our prior rate case to file a rate case no later than August 31, 2018. On September 28, 2018, the FERC issued an order accepting and suspending our general rate filing ~~principally designed~~ to ~~recover increased costs. The rates became~~be effective March 1, ~~2007,~~2019, subject to refund and the outcome of a ~~hearing. All issues in this proceeding~~hearing, 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~~that rates for ~~service under our WSS-OA storage~~certain services that were proposed as overall rate ~~schedule, which was implemented~~decreases were accepted, without suspension, to be effective October 1, 2018. The decreased rates will not be subject to refund but may be subject to decrease prospectively under Section 5 of the Natural Gas Act of 1938, as amended. On March 18, 2019, the FERC accepted our motion to place the rates that were suspended by the September 28, 2018 order into effect on March 1, ~~2007. Following~~2019, subject to refund. We have provided a ~~hearing,~~reserve for rate refunds which we believe is adequate for any refunds that may be required.

Notice of Inquiry (Docket No. PL19-4-000) On March 21, 2019, the FERC issued ~~an opinion approving our proposed incremental rate design,~~a Notice of Inquiry (NOI) in Docket No. PL19-4-000, seeking comments regarding whether and, ~~subsequently denied requests~~if so, how FERC should revise its policies for ~~rehearing of that approval. On February 21, 2014,~~

determining the ~~U. S.~~base return on equity (ROE) used in setting rates charged by jurisdictional public utilities. FERC also seeks comment on, among other things, whether FERC should change its ROE policies for interstate natural gas and oil pipelines to align with is policy for electric public utilities. FERC's action follows a decision from the United States Court of Appeals for the ~~D.C.~~District of Columbia Circuit, ~~(D.C. Circuit) issued an opinion that~~which vacated and remanded a series of earlier FERC orders establishing a new base ROE for certain electric transmission owners. Following that decision, FERC proposed in the ~~FERC's order because~~remanded proceedings that it rely on four financial models to establish ROEs for the ~~FERC did not adequately support~~affected utilities rather than rely primarily on its ~~conclusions. On March 17, 2016, the FERC issued an order addressing the issues raised by the D.C. Circuit's opinion.~~long-used, two-step Discounted Cash Flow model. In the ~~March 17 order,~~NOI, FERC poses a series of questions and invites comments on this proposed new approach, including whether it should apply the ~~FERC reversed its prior opinion~~new approach to future proceedings involving interstate natural gas and ~~found that Transco's incremental rate design is unjust and unreasonable. The FERC directed Transco~~oil pipeline ROEs. Comments in response to ~~design its WSS-OA rates~~the NOI are due 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 consistentJune 26, 2019, with ~~the March 17 order, and began charging those rates beginning April 19, 2016.~~reply comments due on July 26, 2019. 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 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 is filed, we expect to issue refunds in the fourth quarter of 2017.~~currently are monitoring this proceeding.

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. On December 20, 2018, the PHMSA issued a Final Order, which made findings of violation, reduced the civil penalty to $1.4 million, and specified actions that need to be taken by us to comply with pipeline safety regulations.

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$5 million to ~~$8 million (including~~$7 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, 2019, we had a balance of approximately ~~$3.9~~$3.2 million for the expense portion of these estimated costs, ~~$2.1~~$1.5 million recorded in Accrued liabilities and ~~$1.8~~$1.7 million recorded in Other Long-Term Liabilities - Other in the accompanying Condensed Consolidated Balance Sheet. At December 31, ~~2016~~2018, we had a balance of approximately ~~$4.2~~$3.5 million for the expense portion of these estimated costs, ~~$2.1~~$1.5 million

recorded in Accrued liabilities and ~~$2.1~~$2.0 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$5 million to $8$7 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~~The EPA ~~promulgated a~~and various state regulatory agencies routinely promulgate and propose new ~~lower~~rules, and issue updated guidance to existing rules. These rulemakings include, but are not limited to, rules for reciprocating internal combustion engine and combustion turbine 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. The EPA previously issued its rule regarding National Ambient Air Quality ~~Standard (NAAQS)~~Standards for ground-level ozone. In May 2012, the EPA completed designation 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.~~ We are monitoring the ~~rule's~~rule’s implementation as ~~the reduction~~it 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, we had a balance of approximately $1.6 million of uncollected environmental related regulatory assets, $1.2 million recorded in ~~Current Assets - Regulatory assets~~ ~~and $0.4 million recorded in~~ ~~Other Assets - Regulatory assets~~ in the accompanying Condensed Consolidated Balance Sheet. At December 31, 2016, we had a balance of approximately $2.5 million of uncollected environmental related regulatory assets, $1.2 million recorded in ~~Current Assets - Regulatory assets~~ ~~and $1.3 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.

3.5. DEBT AND FINANCING ARRANGEMENTS

Credit Facility

We, along with ~~WPZ~~Williams and Northwest Pipeline LLC (Northwest) (the “borrowers”), are party to a ~~credit agreement~~Credit Agreement with aggregate commitments available of ~~$3.5~~$4.5 billion, with up to an additional $500 million increase in aggregate commitments available under certain circumstances. ~~Total letter~~We and Northwest are each subject to a $500 million borrowing sublimit. Letter of credit ~~capacity~~commitments of $1.0 billion are, subject to the $500 million borrowing sublimit applicable to us and Northwest, 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.~~borrowers. At ~~September 30, 2017,~~March 31, 2019, no letters of credit have been issued and no loans were outstanding under the credit facility.

~~WPZ~~Williams participates in a commercial paper program and ~~WPZ~~Williams 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$4.0 billion of unsecured commercial paper notes. At ~~September 30, 2017, no~~March 31, 2019, Williams had $1.0 billion of outstanding commercial ~~paper was outstanding under the commercial paper program.~~paper.

Other Financing ~~Obligation~~Obligations

Dalton Expansion Project

During the ~~construction~~first quarter of ~~our Dalton Expansion Project,~~2019, we received an additional $0.7 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, 2019, 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~~is $258.3 million, and the amount included in Long-term debt due within one year on our Condensed Consolidated Balance Sheet for this financing obligation is $1.9 million.

Atlantic Sunrise Project

During the first quarter of 2019, we received an additional $7.2 million of funding from a co-owner for its proportionate share of construction costs related to our partner over an expected term of 35 years. As 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 courseits undivided ownership interest in certain parts of the ~~capacity agreement. The~~project. This additional funding is reflected in Long-Term Debt on our Condensed Consolidated Balance Sheet. At March 31, 2019, the amount included in Long-Term Debt on our Condensed Consolidated Balance Sheet for this financing obligation ~~matures~~is $797.4 million, and the amount included in ~~July 2052, requires monthly interest and principal payments, and bears an interest rate of approximately 10 percent.~~Long-term debt due within one year on our Condensed Consolidated Balance Sheet for this financing obligation is $13.9 million.

Long-Term Debt Due Within One Year

The long-term debt due within one year at ~~September 30, 2017~~March 31, 2019 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.~~obligations.

4.6. 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. The Money Market Funds held in our ARO Trust are considered investments. 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,~~2019, the annual funding obligation is approximately ~~$36.4~~$35.9 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, 2019				December 31, 2018
	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
Money Market Funds									$	27.8	$	27.8	$	21.7	$	21.7
U.S. Equity Funds	35.9		47.7		29.4		36.5		50.5		68.9		46.4		56.8
International Equity Funds	20.7		23.7		19.2		18.6		23.8		25.6		21.9		21.4
Municipal Bond Funds	46.8		47.1		36.7		36.3		50.1		50.5		50.1		49.6
Total	$	111.9	$	127.0	$	90.3	$	96.4	$	152.2	$	172.8	$	140.1	$	149.5

5.7. 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 and from 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, 2019:
Measured on a recurring basis:
ARO Trust investments	$	127.0		$	127.0		$	127.0	$	—		$	—	$	172.8		$	172.8		$	172.8	$	—		$	—

Additional disclosures:
Long-term debt, including current portion	(2,449.0		)	(3,051.1		)	—		(3,051.1		)	—		(4,019.1		)	(5,034.0		)	—		(5,034.0		)	—

Assets (liabilities) at December 31, 2016:
Assets (liabilities) at December 31, 2018:
Measured on a recurring basis:
ARO Trust investments	$	96.4		$	96.4		$	96.4	$	—		$	—	$	149.5		$	149.5		$	149.5	$	—		$	—

Additional disclosures:
Long-term debt	(2,210.8		)	(2,507.5		)	—		(2,507.5		)	—
Long-term debt, including current portion														(4,014.4		)	(4,785.5		)	—		(4,785.5		)	—

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~~RP18-1126 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 46 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~~obligations associated with our Dalton ~~lateral,~~and Atlantic Sunrise expansions, which isare included within long-term debt, ~~was~~were determined using an income approach (See Note 35 - 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, 2019 or ~~2016~~2018.

6.8. TRANSACTIONS WITH AFFILIATES

We are a participant in ~~WPZ’s~~Williams' cash management program, and we receive advances from and make advances to ~~and receive advances from WPZ.~~Williams. At ~~September 30, 2017~~ ~~and~~ ~~December~~March 31, ~~2016~~2019, our advances from Williams totaled approximately $86.6 million and is classified as Payables - Advances from affiliates in the accompanying Condensed Consolidated Balance Sheet. At December 31, 2018, our advances to ~~WPZ~~Williams totaled approximately $~~299.1~~33.0 million and ~~$811.7 million, respectively. These advances are represented by demand notes and are~~is classified as Receivables - Advances to affiliate in the accompanying Condensed Consolidated Balance Sheet. Advances are stated at the historical

carrying amounts. Interest income isand expense are 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~~Williams' excess cash at the end of each month. At ~~September 30, 2017~~March 31, 2019, the interest rate was ~~0.91~~2.33 percent.

Included in Operating Revenues in the accompanying Condensed Consolidated Statement of Comprehensive Income are revenues received from affiliates of ~~$2.5~~$3.3 million and ~~$8.9~~$1.8 million for the three ~~and nine~~ months ended ~~September 30, 2017~~March 31,

2019~~, respectively,~~ and ~~$4.8 million and $8.9 million for the three and nine months ended September 30, 2016,~~2018, 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~~$1.6 million and ~~$2.9~~$1.9 million for the three ~~and nine~~ months ended ~~September 30, 2017~~March 31, 2019~~, respectively,~~ and ~~$1.8 million and $3.3 million for the three and nine months ended September 30, 2016,~~2018, 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~~$92.2 million and ~~$261.1~~$91.5 million in the three ~~and nine~~ months ended ~~September 30, 2017~~March 31, 2019~~, respectively~~ and ~~$78.4 million and $234.7 million in the three and nine months ended September 30, 2016,~~2018, 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~~$1.2 million and ~~$2.7~~$1.0 million for the three ~~and nine~~ months ended ~~September 30, 2017, respectively,~~March 31, 2019 and ~~$1.0 million and $3.4 million for the three and nine months ended September 30, 2016,~~2018, respectively.

We made equity distributions totaling ~~$330.0~~$176.0 million and $~~350.0~~55.0 million during the ~~nine~~three months ended ~~September 30, 2017~~March 31, 2019 and ~~2016~~2018, respectively. During ~~October 2017,~~April 2019, we made an additional distribution of ~~$100.0~~$170.0 million. Our parent made contributions to us totaling $~~110.0 million~~ ~~and~~ ~~$372.0~~340.0 million in the ~~nine~~three months ended March 31, ~~September 30, 2017~~ ~~and~~ ~~2016~~2018, ~~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. 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 third parties related to construction costs on the Atlantic Sunrise and Dalton projects. This balance increases as we receive additional advances. After construction of the respective projects are completed, the related liabilities will be reclassified to ~~Long-Term Debt~~ ~~and reduced by payments we make to the third parties~~

~~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.~~



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~~2018 Annual Report on Form 10-K and with the Condensed Consolidated Financial Statements and Notes contained in this Form 10-Q.

Filing of Rate Case

On August 31, 2018, we filed a general rate case with the FERC for an overall increase in rates and to comply with the terms of the settlement in our prior rate case to file a rate case no later than August 31, 2018. On September 28, 2018, the FERC issued an order accepting and suspending our general rate filing to be effective March 1, 2019, subject to refund and the outcome of a hearing, except that rates for certain services that were proposed as overall rate decreases were accepted, without suspension, to be effective October 1, 2018. The decreased rates will not be subject to refund but may be subject to decrease prospectively under Section 5 of the Natural Gas Act of 1938, as amended. On March 18, 2019, the FERC accepted our motion to place the rates that were suspended by the September 28, 2018 order into effect on March 1, 2019, subject to refund. We have provided a reserve for rate refunds which we believe is adequate for any refunds that may be required.

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 an income tax allowance that includes a deferred income tax component. As a result of the reduced income tax rate from Tax Reform and the collection of historical rates that reflected historical federal income tax rates, we expect that we will be required to return amounts to certain customers through future rates and have accordingly established a regulatory liability totaling $448.1 million as of March 31, 2019 and $450.2 million as of December 31, 2018. Effective March 1, 2019, we began amortizing this regulatory liability. The timing and actual amount of such return will be subject to the outcome of the rate case proceeding filed in Docket No. RP18-1126.

RESULTS OF OPERATIONS

Operating Income and Net Income

Operating Income for the ~~nine~~three months ended ~~September 30, 2017~~March 31, 2019 was $~~476.6~~290.3 million compared to $~~449.0~~198.0 million for the ~~nine~~three months ended ~~September 30, 2016~~March 31, 2018. The increase in Operating Income of ~~$27.6~~$92.3 million ~~(6.1~~(46.6 percent) was primarily due to higher Natural gas transportation ~~and~~ ~~Natural gas storage~~revenues in the first ~~nine~~three months of ~~2017~~2019 compared to the same period in ~~2016,~~2018, 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, 2019 was ~~$440.9~~$229.7 million compared to ~~$384.5~~$179.9 million for the ~~nine~~three months ended ~~September 30, 2016.~~March 31, 2018. The increase in Net Income of ~~$56.4~~$49.8 million ~~(14.7~~(27.7 percent) was mostly attributable to the increase in Operating Income ~~and a favorable~~partially offset by an unfavorable change in net expenses in Other (Income) and Other Expenses, as discussed below.

Operating Revenues

Natural gas ~~sales~~transportation for the three months ended March 31, 2019 increased ~~$7.4~~$107.6 million ~~(11.0~~(25.2 percent) ~~for the nine months ended September 30, 2017 compared to~~over the same period in ~~2016.~~2018. The increase was primarily ~~due~~attributable to:

$110.6 million increase in transportation reservation revenues related to ~~system management gas sales. System management gas sales~~new incremental projects attributable to:

$97.2 million from our Atlantic Sunrise project placed in full service in October 2018;

$8.6 million from our Gulf Connector project placed in service in January 2019; and

$4.8 million from our Garden State project placed in full service in March 2018.

$4.3 million higher recoveries of electric power costs. Electric power costs are ~~offset~~recovered from customers through transportation rates resulting in ~~our cost of natural gas sold and therefore have~~ no net impact on our operating income or results of operations.

~~Natural gas transportation~~ ~~for the~~ ~~nine~~ ~~months ended~~ ~~September 30, 2017~~ ~~increased $74.4~~Partially offset by $6.0 million ~~(7.1 percent) over the same period in~~ ~~2016. The increase was primarily due to higher transportation reservation~~lower 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 million from our Dalton project placed in partial service in April 2017, and fully in service in August 2017, $11.2 million from our Hillabee project Phase I placed in partial service in June 2017 and fully in service in July 2017 and $8.3 million from our Rock Springs 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.Docket No. RP18-1126 rate decreases effective October 1, 2018.

~~Natural gas storage~~ increased $14.5 million (16.4 percent) for the nine months ended September 30, 2017 compared to the same period in 2016. The increase was primarily due to the absence of an accrual for Washington Storage Service potential refunds recorded in 2016.

Operating Costs and Expenses

Excluding the Cost of natural gas sales, which is directly offset in revenues, of ~~$74.9~~$24.1 million for the ~~nine~~three months ended ~~September 30, 2017~~March 31, 2019 and ~~$67.5~~$25.3 million for the comparable period in ~~2016~~2018, our operating costs and expenses for the ~~nine~~three months ended ~~September 30, 2017~~March 31, 2019 increased ~~approximately $61.5~~$16.7 million ~~(9.0~~(6.3 percent) from the comparable period in ~~2016~~2018. This increase was primarily attributable to:

~~A $41.9~~$21.4 million ~~(18.5 percent) increase in~~ ~~Operation and maintenance~~ ~~costs primarily due to $32.9 million higher costs for pipeline integrity, general maintenance and other testing on our pipeline and $4.0 million higher employee labor and related benefit costs;~~

~~An $8.3 million (3.6~~(25.7 percent) increase in Depreciation and amortization costs primarily ~~due to $12.2 million higher expense due to~~resulting from additional assets placed into ~~service after third quarter 2016, partly offset by $4.3 million lower expense due to ARO-related depreciation;~~service;

~~A $6.0~~$1.5 million ~~(4.8~~(11.5 percent) increase in ~~Administrative and general~~Cost of natural gas transportation costs primarily resulting from $4.3 million higher electric power costs, partly offset by $2.7 million lower fuel costs;

Partially offset by $4.5 million (25.3 percent) decrease in Other expenses, net primarily due to ~~higher allocated corporate expenses;~~a $1.7 million favorable change in the deferral of ARO related depreciation to a regulatory asset, and a $3.1 million favorable change in costs associated with pension and other postretirement benefits related to Docket No. RP18-1126; and

~~A $3.9~~$3.6 million ~~(8.6~~(4.1 percent) decrease in Operation and maintenance costs primarily resulting from a $5.8 million decrease in contracted services mainly related to general maintenance and other testing on our pipeline, partly offset by a $2.9 million increase in ~~Taxes - other than income taxes~~ ~~primarily due to higher ad valorem taxes as a result of additional assets placed into service.~~employee labor and related benefit costs.

Other (Income) and Other Expenses

Other (income) and other expenses for the ~~nine~~three months ended ~~September 30, 2017~~March 31, 2019 had ~~a favorable~~an unfavorable change of ~~$28.8~~$42.5 million ~~(44.7~~(234.8 percent) over the same period in ~~2016~~2018. This is mostly due to ana $26.0 million increase inInterest expense primarily due to $20.6 million associated with other financing obligations and $9.0 million associated with our debt issuance in March 2018, partly offset by $3.8 million associated with our debt retirement in June 2018, and an unfavorable change of $17.9 million in Allowance for equity and borrowed funds used during construction (AFUDC) associated with capital expenditures on projects.

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~~is being constructed in phases, and all of the project expansion capacity ~~will be leased~~is dedicated to Sabal ~~Trail. We placed~~Trail pursuant to a ~~portion of~~capacity lease agreement. Phase I ~~into service on June 14,~~was completed in 2017 and ~~we placed the remainder of Phase I into service on July 11, 2017. Phase I~~it 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, in part, related to furthering the completion of the project, this deferred revenue is assigned to our results of operations over the 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 that conforms with the court's opinion regarding quantifying certain greenhouse gas emissions, and (ii) vacated the FERC's certificate order for the projects, which would be effective following the court's mandate (by court order, the mandate will not issue until after disposition of all petitions for rehearing). We, along with other intervenors, 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 issued prior to the FERC re-issuing certificate authority for the projects, we believe that the FERC will take the necessary steps (which may include issuing temporary certificate authority) to avoid any lapse in federal authorization for the projects.

~~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 into service during the second quarter of 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 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~~placed the ~~FERC in August 2016 for approval of the project.~~project into service on January 4, 2019. 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 increaseincreased 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 addressed the technical issues identified by NYSDEC and refiled our application on May 16, 2018. We plan to place the project into service in ~~late 2019 or during~~ the ~~first half~~fourth quarter of 2020, assuming timely receipt of all necessary regulatory approvals. The project is expected to increase capacity by 400 Mdth/d.

Rivervale South to Market

The Rivervale South to Market Project involves an expansion of our existing natural gas transmission system to provide incremental firm transportation capacity from the existing Rivervale interconnection with Tennessee Gas Pipeline on our North New Jersey Extension to our existing Central Manhattan meter station in New Jersey and our Station 210 Pooling Point in New Jersey. ~~We filed an application with~~In August 2018, we received approval from 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 an application with~~In December 2018, we received approval from the FERC ~~in the fourth quarter of 2017~~ for ~~approval of~~ the project. We plan to place the project into service ~~as early as the first quarter of 2021,~~mid-year 2020, 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.

Leidy South

The Leidy South Project involves an expansion of our existing natural gas transmission system and an extension of our system through a capacity lease with National Fuel Gas Supply Corporation that will enable us to provide incremental firm transportation from Clermont, Pennsylvania and from the Zick interconnection on Transco's Leidy Line to the River Road regulating station in Lancaster County, Pennsylvania. We expect to file an application with the FERC in June 2019 for approval of the project. We plan to place the project into service in the second half of 2022, assuming timely receipt of all necessary regulatory approvals. The project is expected to increase capacity by 582.4 Mdth/d.

South Louisiana Market

The South Louisiana Market Project involves an expansion of our existing natural gas transmission system to provide incremental firm transportation capacity from Station 65 in Louisiana to a new interconnection with a proposed chemical plant in St. James Parish, Louisiana. We expect to file an application with the FERC in August 2019 for approval of the project. We plan to place the project into service in the fourth quarter of 2022, assuming timely receipt of all necessary regulatory approvals. The project is expected to increase capacity by 202 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~~2019 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 24 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, 2018, includes risk factors that could materially affect our business, financial condition, or future results. Those risk factors have not materially changed.



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).

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~~May 2, ~~2017~~2019	By:	/s/ ~~Ted T. Timmermans~~Kathleen R. Hambleton
			~~Ted T. Timmermans~~Kathleen R. Hambleton
			~~Vice President,~~ Controller ~~and Chief Accounting Officer~~
			(Principal Accounting Officer)