For the quarterly period ended ~~March 31,~~September 30, 2019

For the transition period from to

Commission file number 1-7584



~~DELAWARE~~DE		74-1079400
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)
2800 POST OAK BOULEVARD
~~2800 POST OAK BOULEVARD~~ HOUSTON ~~TEXAS~~	TX	77056

(Address of principal executive offices)		(Zip Code)

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

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

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

Indicate by check mark whether the registrant has submitted electronically 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). Yesþ 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~~ Filer

Smaller reporting company¨

☐

Emerging growth 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.

TRANSCONTINTENTAL GAS PIPE LINE COMPANY, LLC

Forward Looking Statements

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

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

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:

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 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)

~~See accompanying notes.~~

See accompanying notes.

CONDENSED CONSOLIDATED STATEMENT OF MEMBER’S EQUITY

See accompanying notes.

TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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 The Williams Companies, Inc. (Williams).

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 ~~March 31,~~September 30, 2019 and December 31, 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 ~~$1.2~~$3.7 million and ~~$0.4~~$1.8 million in the ~~three~~nine months ended ~~March 31,~~September 30, 2019 and ~~March 31,~~September 30, 2018,, respectively. We made a $12.3 million contribution to Pine Needle in the second quarter of 2019.

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 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~~$9.8 million for the ~~three~~nine months ended ~~March 31,~~September 30, 2018, has been made to conform to the 2019 presentation.

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. We have reached an agreement on the terms of a settlement with the participants in our general rate case proceeding in FERC Docket No. RP18-1126 that would resolve all issues in that proceeding without the need for a hearing. Final resolution of the rate case is subject to the filing of a formal stipulation and agreement and subsequent approval by the FERC. At ~~March 31,~~September 30, 2019, we have ~~provided a reserve for rate refunds~~accrued approximately $130.8 million related to Docket No. RP18-1126, which we believe is adequate for any refunds that may be required.

Accounting Standards Issued and Adopted

In February 2016, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2016-02 “Leases (Topic 842)” (ASU 2016-02). ASU 2016-02 establishes a comprehensive new lease accounting model. ASU 2016-02 modifies the definition of a lease, requires a dual approach to lease classification similar to 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 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 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~~nonlease components from the associated lease component if certain conditions are present. ASU 2016-02 is effective for interim and annual periods beginning after December 15, 2018. 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 of ASU 2016-02. We implemented a 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 also evaluated ASU 2016-02’s available practical expedients on ~~adoption. We~~adoption and have generally elected to adopt the practical expedients, which includes the practical expedient to not separate lease and ~~non-lease~~nonlease 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 us for interim and annual periods beginning after December 15, 2019. We plan to adopt as of January 1, 2020. We anticipate that ASU 2016-13 will primarily apply to our trade receivables. While we do not expect a significant financial impact, we ~~are currently developing additional~~have analyzed our historical credit loss experience and continue to develop and implement processes, procedures and internal controls in order to make the necessary credit loss assessments and required ~~disclosures.~~disclosures upon adoption.

2. REVENUE RECOGNITION

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:



	Quarter to Date September 30, 2019			Year to Date September 30, 2019
	(Thousands)
Balance at beginning of period	$	231,451		$	236,730
Payments received and deferred	—			—
Recognized in revenue	(2,644		)	(7,923		)
Balance at end of period	$	228,807		$	228,807

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,~~September 30, 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)	$	2,642
2020	10,568
2021	10,566
2022	10,566
2023	10,566
Thereafter	183,899
Total	$	228,807

Remaining Performance Obligations

The following table presents the transaction price allocated to the remaining performance obligations under certain contracts as of ~~March 31,~~September 30, 2019. These primarily include reservation charges on contracted capacity on our firm transportation and storage contracts with customers. Amounts from certain contracts included in the table below, which are subject to the periodic review and approval by the FERC, reflect the rates for such services in our current FERC tariffs, 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 related to contract liabilities 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,~~September 30, 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.



	(Thousands)
2019 (remainder)	$	575,156
2020	2,215,134
2021	2,073,550
2022	1,909,976
2023	1,478,138
Thereafter	13,843,450
Total	$	22,095,404

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,~~September 30, 2019 and December 31, 2018, Receivables - Trade and other includes ~~$13.8~~$15.1 million and $10.4 million, respectively, of receivables not related to contracts with customers.

We are a lessee through noncancellable lease agreements for property and equipment consisting primarily of buildings, land, vehicles, and equipment used in both our operations and administrative functions. We recognize a lease liability with 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~~nonlease components for all classes of leased assets in our calculation of the lease liability and the offsetting right-of-use asset.

Our lease agreements require both fixed and variable periodic payments, with initial terms typically ranging from one year 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 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 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 termination provisions, when at our sole election, will be reasonably certain of being exercised. Periods after the 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 lease term. Additionally, we have elected to exclude leases with an original term of one year or less, including renewal periods, from the calculation of the lease liability and 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 September 30,		Nine Months Ended September 30,
	2019
	(Thousands)
Lease Cost:
Operating lease cost	$	2,573	$	7,739
Short-term lease cost	—		—
Variable lease cost	1,365		5,489
Total lease cost	$	3,938	$	13,228

Cash paid for amounts included in the measurement of operating lease liabilities	$	2,393	$	7,677

			September 30, 2019
			(Thousands)
Other Information:
Right-of-use assets			$	90,023
Operating lease liabilities:
Current (included in Accrued liabilities in our Condensed Consolidated Balance Sheet)			$	3,538
Lease liability			$	85,969
Weighted-average remaining lease term - operating leases (years)			15
Weighted-average discount rate - operating leases			4.65		%

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,~~September 30, 2019, the following table represents our operating lease maturities, including renewal provisions that we have assessed as being reasonably certain of exercise, for each of the years ended December 31:



	(Thousands)
2019 (remainder)	$	1,603
2020	7,615
2021	9,644
2022	9,625
2023	9,628
Thereafter	92,848
Total future lease payments	130,963
Less amount representing interest	41,456
Total obligations under operating leases	$	89,507

(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

4. CONTINGENT LIABILITIES AND COMMITMENTS

General rate case (Docket No. RP18-1126) 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~~reached

an agreement on the terms of a settlement with the participants in our general rate case proceeding in FERC Docket No. RP18-1126 that would resolve all issues in that proceeding without the need for a hearing. Final resolution of the rate case is subject to the filing of a formal stipulation and agreement and subsequent approval by the FERC. As of September 30, 2019, we have accrued a reserve for rate refunds of approximately $130.8 million, 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 a Notice of Inquiry (NOI) in Docket No. PL19-4-000, seeking comments regarding whether and, if so, how FERC should revise its policies for

determining the 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 isits policy for electric public utilities. FERC's action follows a decision from the United States Court of Appeals for the District of Columbia Circuit, 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 remanded proceedings that it rely on four financial models to establish ROEs for the affected utilities rather than rely primarily on its long-used, two-step Discounted Cash Flow model. In the NOI, FERC poses a series of questions and ~~invites~~invited comments on this proposed new approach, including whether it should apply the new approach to future proceedings involving interstate natural gas and oil pipeline ROEs. ~~Comments in response to the NOI~~We are ~~due on June 26, 2019, with reply comments due on July 26, 2019. We~~ currently ~~are~~ monitoring this proceeding.

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~~included a $1.6 million proposed civil penalty to us in connection with the incident. This penalty, which is not covered by our insurance policies, was accrued in the second quarter of ~~2016 and would not be covered by our insurance policies.~~2016. 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. In a subsequent order issued on September 16, 2019, PHSMA denied our request to modify the supporting explanation for one of the findings. On October 9, 2019, we submitted payment of the $1.4 million civil penalty to PHMSA, fully resolving the NOPV.

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

We, ~~are a defendant~~with the insurer of one of our contractors, have settled all claims against us for wrongful death and personal injury. In addition, we have settled in principle the remaining lawsuits seeking damages for ~~wrongful death, personal injury~~property damage. All such losses incurred have been, and the remaining 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 havedamage claims ~~for indemnification, we believe that it is probable that any ultimate losses incurred~~ will be, covered by our contractors' ~~insurance and our~~ insurance.

Environmental Matters

We have had studies underway for many years to test some of our facilities for the presence of toxic and hazardous substances such as polychlorinated biphenyls (PCBs) and mercury to determine to what extent, if any, remediation may be necessary. We have also similarly evaluated past on-site disposal of hydrocarbons at a number of our facilities. We have worked closely with and responded to data requests from the U.S. Environmental Protection Agency (EPA) and state agencies regarding such potential contamination of certain of our sites. On the basis of the findings to date, we estimate that environmental assessment and remediation costs under various federal and state statutes will total approximately $5 million to $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 ~~March 31,~~September 30, 2019,, we had a balance of approximately ~~$3.2~~$3.0 million for the expense portion of these estimated costs, ~~$1.5~~$1.3 million recorded in Accrued liabilities and $1.7 million recorded in Other Long-Term Liabilities - Other in the accompanying Condensed Consolidated Balance Sheet. At December 31, 2018,, we had a balance of approximately $3.5 million for the expense portion of these estimated costs, $1.5 million

recorded in Accrued liabilities and $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 ~~$5 million to $7 million range~~environmental liabilities discussed above. Liability under the Comprehensive Environmental Response, Compensation and Liability Act and applicable state law can be joint and several with other PRPs. Although volumetric allocation is a factor in assessing liability, it is not necessarily determinative; thus, the ultimate liability could be substantially greater than the amounts described above.

The EPA and various state regulatory agencies routinely promulgate and propose new rules, and issue updated guidance to existing rules. 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 Standards for ground-level ozone. We are monitoring the rule’s implementation as it will trigger additional federal and state regulatory actions that may impact our operations. Implementation of the regulations is expected to result in impacts to our operations and increase the cost of additions to Total property, plant and equipment, net in the Condensed Consolidated Balance Sheet for both new and existing facilities in affected areas. We are unable to reasonably estimate the cost of additions that may be required to meet the regulations at this time due to uncertainty created by various legal challenges to these regulations and the need for further specific regulatory guidance.

We consider prudently incurred environmental assessment and remediation costs and the costs associated with compliance with environmental standards to be recoverable through rates. To date, we have been permitted recovery of environmental costs, and it is our intent to continue seeking recovery of such costs through future rate filings.

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

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.

5. DEBT AND FINANCING ARRANGEMENTS

We, along with Williams and Northwest Pipeline LLC (Northwest) (the “borrowers”), are party to a Credit Agreement with aggregate commitments available of $4.5 billion, with up to an additional $500 million increase in aggregate commitments available under certain circumstances. We and Northwest are each subject to a $500 million borrowing sublimit. Letter of credit commitments of $1.0 billion are, subject to the $500 million borrowing sublimit applicable to us and Northwest, available to the borrowers. At ~~March 31,~~September 30, 2019, no0 letters of credit have been issued and no0 loans were outstanding under the credit facility.

Williams participates in a commercial paper program and 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 $4.0 billion of unsecured commercial paper notes. At ~~March 31,~~September 30, 2019, Williams had ~~$1.0 billion of~~0 outstanding commercial paper.

Other Financing Obligations

Dalton Expansion Project

During the first ~~quarter~~nine months of 2019, we received an additional $0.7 million of funding from a co-owner for its proportionate share of construction costs related to its undivided ownership interest in the Dalton lateral. This additional funding is reflected in Long-Term Debt on our Condensed Consolidated Balance Sheet. At ~~March 31,~~September 30, 2019, the amount included in Long-Term Debt on our Condensed Consolidated Balance Sheet for this financing obligation is ~~$258.3~~$257.3 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~~$2.0 million.

Atlantic Sunrise Project

During the first ~~quarter~~nine months of 2019, we received an additional ~~$7.2~~$35.0 million of funding from a co-owner for its proportionate share of construction costs related to its undivided ownership interest in certain parts of the project. This additional funding is reflected in Long-Term Debt on our Condensed Consolidated Balance Sheet. At ~~March 31,~~September 30, 2019, the amount included in Long-Term Debt on our Condensed Consolidated Balance Sheet for this financing obligation is ~~$797.4~~$814.8 million, and the amount included in Long-term debt due within one year on our Condensed Consolidated Balance Sheet for this financing obligation is ~~$13.9~~$16.1 million.

Long-Term Debt Due Within One Year

The long-term debt due within one year at ~~March 31,~~September 30, 2019 is associated with the previously described other financing obligations.

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, 2019, the annual funding obligation is approximately $35.9 million, with deposits made monthly.

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



	September 30, 2019				December 31, 2018
	Amortized Cost Basis		Fair Value		Amortized Cost Basis		Fair Value
Money Market Funds	$	23.3	$	23.3	$	21.7	$	21.7
U.S. Equity Funds	54.7		76.2		46.4		56.8
International Equity Funds	25.4		27.0		21.9		21.4
Municipal Bond Funds	59.3		60.8		50.1		49.6
Total	$	162.7	$	187.3	$	140.1	$	149.5

March 31, 2019 December 31, 2018

Amortized
Cost Basis

Fair
Value

Amortized
Cost Basis

Fair
Value
Money Market Funds $ 27.8
$ 27.8
$ 21.7
$ 21.7
U.S. Equity Funds 50.5
68.9
46.4
56.8
International Equity Funds 23.8
25.6
21.9
21.4
Municipal Bond Funds 50.1
50.5
50.1
49.6
Total $ 152.2
$ 172.8
$ 140.1
$ 149.5

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 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
	Carrying Amount			Fair Value			Quoted Prices In Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
	(Millions)
Assets (liabilities) at September 30, 2019:
Measured on a recurring basis:
ARO Trust investments	$	187.3		$	187.3		$	187.3	$	—		$	—

Additional disclosures:
Long-term debt, including current portion	(4,038.7		)	(5,218.2		)	—		(5,218.2		)	—

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

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

Fair Value Measurements Using

Carrying
Amount
Fair Value
Quoted
Prices In
Active
Markets for
Identical
Assets
(Level 1)

Significant
Other
Observable
Inputs
(Level 2)

Significant
Unobservable
Inputs
(Level 3)
(Millions)
Assets (liabilities) at March 31, 2019:
Measured on a recurring basis:
ARO Trust investments $ 172.8
$ 172.8
$ 172.8
$ —
$ —

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

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

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

Fair Value Methods

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

ARO Trust investments — We deposit a portion of our collected rates, pursuant to the terms of the Docket No. RP18-1126 rate case, into the ARO Trust which is specifically designated to fund future asset retirement obligations. The ARO Trust invests in a portfolio of actively traded mutual funds that are measured at fair value on a recurring basis based on quoted prices in an active market and are reported in Other Assets-Other in the Condensed Consolidated Balance Sheet. However, both realized and unrealized gains and losses are ultimately recorded as regulatory assets or liabilities. See Note 6 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 obligations associated with our Dalton and Atlantic Sunrise expansions, which are included within long-term debt, were determined using an income approach (See Note ~~5 - Debt and Financing Arrangements)~~5).

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 ~~three~~nine months ended ~~March 31,~~September 30, 2019 or ~~2018~~.2018.

8. TRANSACTIONS WITH AFFILIATES

We are a participant in Williams' cash management program, and we receive advances from and make advances to Williams. At ~~March 31,~~September 30, 2019,, our advances from Williams totaled approximately ~~$86.6~~$169.9 million and isare classified as Payables - Advances from ~~affiliates~~affiliate in the accompanying Condensed Consolidated Balance Sheet. At December 31, 2018, our advances to Williams totaled approximately ~~$33.0~~$33.0 million and isare classified as Receivables - Advances to affiliate in the accompanying Condensed Consolidated Balance Sheet. Advances are stated at the historical carrying amounts. Interest income and 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 Williams' excess cash at the end of each month. At ~~March 31,~~September 30, 2019,, the interest rate was ~~2.33~~1.92 percent.

Included in Operating Revenues in the accompanying Condensed Consolidated Statement of Comprehensive Income are revenues received from affiliates of ~~$3.3~~$2.8 million and ~~$1.8~~$8.4 million for the three and nine months ended ~~March 31,~~

September 30, 2019, respectively, and $2.9 million and $6.2 million for the three and nine months ended September 30, 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 ~~$1.6~~$0.8 million and ~~$1.9~~$3.0 million for the three and nine months ended ~~March 31,~~September 30, 2019, respectively, and $1.2 million and $4.9 million for the three and nine months ended September 30, 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 ~~$92.2~~$110.7 million and ~~$91.5~~$315.4 million in the three and nine months ended ~~March 31,~~September 30, 2019, respectively, and $99.2 million and $290.0 million in the three and nine months ended September 30, 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, 2019, includes $27.0 million for estimated severance and related costs driven by a voluntary separation program associated with a review of Williams' enterprise cost structure.

We provide services to certain of our affiliates. We recorded reductions in operating expenses for services provided to and reimbursed by our affiliates of $1.2 million and ~~$1.0~~$3.5 million for the three and nine months ended ~~March 31,~~September 30, 2019, respectively, and $1.7 million and $3.9 million for the three and nine months ended September 30, 2018, respectively.

We made equity distributions totaling ~~$176.0~~$559.0 million and $~~55.0~~290.0 million during the ~~three~~nine months ended ~~March 31,~~September 30, 2019 and 2018,, respectively. During ~~April~~October 2019, we made an additional distribution of ~~$170.0~~$265.0 million. Our parent made contributions to us totaling $340.0 million in during the ~~three~~nine months ended ~~March 31,~~ September 30, 2018,, to fund a portion of our expenditures for additions to property, plant and equipment.



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 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 reached an agreement on the terms of a settlement with the participants in our general rate case proceeding in FERC Docket No. RP18-1126 that would resolve all issues in that proceeding without the need for a hearing. Final resolution of the rate case is subject to the filing of a formal stipulation and agreement and subsequent approval by the FERC. 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~~$429.0 million as of ~~March 31,~~September 30, 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 ~~three~~nine months ended ~~March 31,~~September 30, 2019 was $~~290.3~~897.2 million compared to $~~198.0~~582.8 million for the ~~three~~nine months ended ~~March 31,~~September 30, 2018. The increase in Operating Income of ~~$92.3~~$314.4 million ~~(46.6~~(53.9 percent) was primarily due to higher ~~Natural gas transportation~~ ~~revenues~~Operating Revenues in the first ~~three~~nine months of 2019 compared to the same period in 2018, as discussed below, partly offset by an increase in Operating Costs and Expenses, as discussed below. Net Income for the ~~three~~nine months ended ~~March 31,~~September 30, 2019 was ~~$229.7~~$715.9 million compared to ~~$179.9~~$551.6 million for the ~~three~~nine months ended ~~March 31,~~September 30, 2018. The increase in Net Income of ~~$49.8~~$164.3 million ~~(27.7~~(29.8 percent) was mostly attributable to the increase in Operating Income partially offset by an unfavorable change in net expenses in Other (Income) and Other Expenses, as discussed below.

Operating Revenues

Natural gas sales decreased $8.8 million (9.1 percent) for the nine months ended September 30, 2019 compared to the same period in 2018. The decrease was primarily due to $4.4 million of lower cash out sales and $4.4 million of lower system management gas sales. Cash out sales and system management gas sales are offset in our cost of natural gas sold and therefore have no impact on our operating income or results of operations.

Natural gas transportation for the ~~three~~nine months ended ~~March 31,~~September 30, 2019 increased ~~$107.6~~$361.3 million ~~(25.2~~(28.6 percent) over the same period in 2018. The increase was primarily attributable to:

$~~110.6~~358.9 million increase in transportation reservation revenues ~~related to new incremental projects~~ attributable to:

$~~97.2~~296.6 million from our Atlantic Sunrise project placed in full service in October 2018;

$~~8.6~~27.0 million from our Gulf Connector project placed in service in January 2019; and

$~~4.8~~35.3 million from ~~our~~other projects such as Garden State, ~~project placed in full service in March 2018.~~St. James, Rivervale South to Market and an adjustment related to our reserve for rate refunds.

$~~4.3~~11.7 million higher recoveries of electric power costs. Electric power costs are recovered from customers through transportation rates resulting in no net impact on our operating income or results of operations.

$6.2 million higher commodity revenue.

Partially offset by ~~$6.0~~$17.7 million lower revenues related to Docket No. RP18-1126 rate decreases effective October 1, 2018.

Natural gas storage increased $7.4 million (7.2 percent) for the nine months ended September 30, 2019 compared to the same period in 2018. The increase was primarily due to the implementation of new rates in March 2019.

Operating Costs and Expenses

Excluding the Cost of natural gas sales, which is directly offset in revenues, of ~~$24.1~~$88.1 million for the ~~three~~nine months ended ~~March 31,~~September 30, 2019 and ~~$25.3~~$96.9 million for the comparable period in 2018, our operating costs and expenses for the ~~three~~nine months ended ~~March 31,~~September 30, 2019 increased ~~$16.7~~$54.6 million ~~(6.3~~(6.9 percent) from the comparable period in 2018. This increase was primarily attributable to:


•	$55.9 million (21.2 percent) increase in Depreciation and amortization costs primarily resulting from additional assets placed into service;

•

$17.7 million (12.8 percent) increase in Administrative and general costs primarily due to a $5.5 million increase in employee labor and related benefits costs mainly due to estimated severance and related costs driven by a voluntary separation program (VSP) associated with a review of Williams' enterprise cost structure, and a $10.8 million higher allocated corporate expenses, of which $4.8 million related to VSP;


•	$8.3 million (27.0 percent) increase in Cost of natural gas transportation costs primarily resulting from $11.7 million higher electric power costs, partly offset by $3.4 million lower fuel costs. Electric power costs are recovered from customers through transportation rates resulting in no net impact on our operating income or results of operations; and


•	$6.1 million (11.7 percent) increase in Taxes - other than income taxes primarily due to higher ad valorem taxes as a result of additional assets placed into service;


•	Partially offset by $26.5 million (57.6 percent) decrease in Other expenses, net primarily due to a $35.3 million favorable change in amortization of regulatory assets and liabilities associated with our general rate case filing in Docket No. RP18-1126, partly offset by a $6.6 million unfavorable change related to costs transferred from capital and certain other charges; and

•

$8.3 million (2.9 percent) decrease in Operation and maintenance costs primarily resulting from a $41.2 million decrease in contracted services compared to 2018 mainly due to the timing of required engine overhauls and integrity testing, partly offset by a $22.9 million increase in employee labor and related benefit costs ($14.8 million due to estimated severance and related costs driven by a VSP associated with a review of Williams' enterprise cost structure, and $10.2 million due to lower capitalized labor as a result of fewer capital projects ongoing in 2019) and a $9.4 million increase in contracted services related to costs transferred from capital.

~~$21.4 million (25.7 percent) increase in~~ ~~Depreciation and amortization~~ ~~costs primarily resulting from additional assets placed into service;~~

~~$1.5 million (11.5 percent) increase in~~ ~~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 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

~~$3.6 million (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 employee labor and related benefit costs.

Other (Income) and Other Expenses

Other (income) and other expenses for the ~~three~~nine months ended ~~March 31,~~September 30, 2019 had an unfavorable change of ~~$42.5~~$150.2 million ~~(234.8~~(482.3 percent) over the same period in 2018. This is mostly due to ~~a $26.0 million increase in~~ ~~Interest 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~~$75.8 million in Allowance for equity and borrowed funds used during construction (AFUDC)primarily associated with reduced capital expenditures on ~~projects.~~projects, a $65.5 million increase in Interest expense primarily due to other financing obligations, and an unfavorable change of $10.9 million in Miscellaneous other (income) expenses, net mostly due to the absence of affiliate interest income in 2019.

Pipeline Expansion Projects

Hillabee

The Hillabee Expansion Project involves an expansion of our existing natural gas transmission system from our Station 85 Pooling Point in Choctaw County, Alabama to a new interconnection with the Sabal Trail pipeline in Tallapoosa County, Alabama. The project is being constructed in phases, and all of the project expansion capacity is dedicated to Sabal Trail pursuant to a capacity lease agreement. Phase I was completed in 2017 and 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.

Gulf Connector

The Gulf Connector Expansion Project ~~involves~~involved 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 placed the project into service on January 4, 2019. The project increased capacity by 475 Mdth/d.

Northeast Supply Enhancement

The Northeast Supply Enhancement Project involves an expansion of our existing natural gas transmission system to provide incremental firm transportation capacity from Station 195 in Pennsylvania to the Rockaway Delivery Lateral transfer point in New York. ~~On April 20, 2018,~~In May 2019, we received approval from the FERC for the project. Approvals required for the project from the New York State Department of Environmental Conservation ~~(NYSDEC)~~and the New Jersey Department of Environmental Protection remain pending, with each such agency having denied, without prejudice, Transco's ~~application~~applications for ~~certain permits required~~such approvals. We have refiled our applications for ~~the project. We~~those approvals and have addressed the technical issues identified by ~~NYSDEC and refiled our application on May 16, 2018.~~the agencies. We plan to place the project into service in the fourth quarter of 2020, assuming timely receipt of ~~all necessary regulatory~~these remaining approvals. The project is expected to increase capacity by 400 Mdth/d.

Rivervale South to Market

The Rivervale South to Market Project ~~involves~~involved 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. ~~In August 2018, we received approval from~~The project was placed into partial service on July 1, 2019, and the ~~FERC for the project. We plan to place~~remainder of the project was placed into service ~~as early as the fourth quarter of 2019, assuming timely receipt of all necessary regulatory approvals.~~on September 1, 2019. The project ~~is expected to increase~~increased 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. In December 2018, we received approval from the FERC for the project. We plan to place the project into service ~~mid-year~~in the first half of 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~~In October 2019, we received approval from 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 remaining 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~~filed an application with the FERC in ~~June~~July 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~~582 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~~June 2020 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 and Chief Accounting Officer, does not expect that our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934 as amended) (Disclosure Controls) or our internal control over financial reporting (Internal Controls)will prevent all errors and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within the company have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty, and that breakdowns can occur because of simple error or mistake. Additionally, controls can be circumvented by the individual acts of some persons, by collusion of two or more people, or by management override of the control. The design of any system of controls also is based in part upon certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions. Because of the inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and not be detected. We monitor our Disclosure Controls and Internal Controls and make modifications as necessary; our intent in this regard is that the Disclosure Controls and Internal Controls will be modified as systems change and conditions warrant.

Evaluation of Disclosure Controls and Procedures

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

Changes in Internal Control Over Financial Reporting

There have been no changes during the ~~first~~third quarter of 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

The information called for by this item is provided in Note 4 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. The instance document does not appear in the interactive data file because its XBRL tags are embedded within the inline XBRL 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.

104*		Cover Page Interactive Data File. The cover page interactive data file does not appear in the interactive data file because its XBRL tags are embedded within the inline XBRL document (contained in Exhibit 101).



*	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:	~~May 2,~~October 31, 2019	By:	/s/ Kathleen R. Hambleton
			Kathleen R. Hambleton
			Controller
			(Principal Accounting Officer)


	Three months ended March 31,						Three months ended September 30,						Nine months ended September 30,
	2019			2018			2019			2018			2019			2018
Operating Revenues:
Natural gas sales	$	24,086		$	25,251		$	41,547		$	41,757		$	88,062		$	96,881
Natural gas transportation	534,160			426,579			566,240			422,999			1,626,552			1,265,285
Natural gas storage	36,085			34,767			35,194			33,839			109,751			102,392
Other	2,762			2,639			2,735			2,815			8,255			7,763
Total operating revenues	597,093			489,236			645,716			501,410			1,832,620			1,472,321

Operating Costs and Expenses:
Cost of natural gas sales	24,086			25,251			41,547			41,757			88,062			96,881
Cost of natural gas transportation	14,635			13,074			15,395			9,126			38,970			30,661
Operation and maintenance	83,448			87,016			92,706			101,916			274,289			282,591
Administrative and general	48,151			46,381			49,997			44,474			155,506			137,836
Depreciation and amortization	104,623			83,224			112,296			91,670			320,103			264,176
Taxes — other than income taxes	20,277			18,438			19,316			16,622			58,253			52,224
Regulatory credit resulting from Tax Reform	(1,749		)	—			(12,247		)	—			(19,244		)	(20,867		)
Other expense, net	13,349			17,841			(6,263		)	15,631			19,451			46,036
Total operating costs and expenses	306,820			291,225			312,747			321,196			935,390			889,538

Operating Income	290,273			198,011			332,969			180,214			897,230			582,783

Other (Income) and Other Expenses:
Interest expense	71,091			45,074			71,980			50,180			214,059			148,629
Allowance for equity and borrowed funds used during construction (AFUDC)	(8,714		)	(26,608		)	(12,640		)	(43,165		)	(28,857		)	(104,668		)
Equity in (earnings) losses of unconsolidated affiliates	(771		)	1,590			(847		)	(762		)	(2,441		)	(497		)
Miscellaneous other (income) expenses, net	(1,035		)	(1,961		)	194			(5,537		)	(1,414		)	(12,317		)
Total other (income) and other expenses	60,571			18,095			58,687			716			181,347			31,147

Net Income	229,702			179,916			274,282			179,498			715,883			551,636

Other comprehensive income (loss):
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
Equity interest in unrealized gain (loss) on interest rate hedges (includes $(24) and $(51) for the three months ended and $(153) and $(78) for the nine months ended September 30, 2019 and September 30, 2018, respectively, of accumulated other comprehensive income reclassification for equity interest in realized gains on interest rate hedges)							(93		)	48			(692		)	572

Comprehensive Income	$	229,472		$	180,321		$	274,189		$	179,546		$	715,191		$	552,208



	March 31, 2019		December 31, 2018
ASSETS

Current Assets:
Cash	$	—	$	—
Receivables:
Affiliates	399		1,018
Advances to affiliate	—		33,034
Trade and other	234,245		201,198
Transportation and exchange gas receivables	6,339		4,515
Inventories	67,736		63,205
Regulatory assets	103,903		95,770
Other	7,474		12,574
Total current assets	420,096		411,314

Investments, at cost plus equity in undistributed earnings	25,815		26,520

Property, Plant and Equipment:
Natural gas transmission plant	16,073,782		15,908,878
Less-Accumulated depreciation and amortization	4,240,363		4,147,729
Total property, plant and equipment, net	11,833,419		11,761,149

Other Assets:
Regulatory assets	273,733		289,479
Right-of-use assets	89,824		—
Other	187,070		167,490
Total other assets	550,627		456,969

Total assets	$	12,829,957	$	12,655,952



		March 31, 2019		December 31, 2018
LIABILITIES AND MEMBER’S EQUITY

Current Liabilities:
Payables:
Affiliates		$	46,485	$	50,727
Advances from affiliates	86,580	86,580		—
Trade and other		165,998		226,911
Transportation and exchange gas payables		3,480		5,973
Regulatory liabilities		44,226		5,097
Accrued liabilities		208,382		218,384
Long-term debt due within one year		15,810		15,419
Total current liabilities		570,961		522,511

Long-Term Debt		4,003,258		3,998,988

Other Long-Term Liabilities:
Asset retirement obligations		366,945		348,609
Regulatory liabilities		991,779		1,026,892
Deferred revenue		223,526		226,164
Lease liability		85,759		—
Other		5,657		4,188
Total other long-term liabilities		1,673,666		1,605,853

Contingent Liabilities and Commitments (Note 4)

Member’s Equity:
Member’s capital		4,428,499		4,428,499
Retained earnings		2,153,269		2,099,567
Accumulated other comprehensive income		304		534
Total member’s equity		6,582,072		6,528,600

Total liabilities and member’s equity		$	12,829,957	$	12,655,952



	September 30, 2019		December 31, 2018
ASSETS

Current Assets:
Cash	$	—	$	—
Receivables:
Affiliates	1,043		1,018
Advances to affiliate	—		33,034
Trade and other	227,437		201,198
Transportation and exchange gas receivables	4,256		4,515
Inventories	63,260		63,205
Regulatory assets	78,617		95,770
Other	12,745		12,574
Total current assets	387,358		411,314

Investments, at cost plus equity in undistributed earnings	36,776		26,520

Property, Plant and Equipment:
Natural gas transmission plant	16,601,011		15,908,878
Less-Accumulated depreciation and amortization	4,386,364		4,147,729
Total property, plant and equipment, net	12,214,647		11,761,149

Other Assets:
Regulatory assets	295,733		289,479
Right-of-use assets	90,023		—
Other	194,305		167,490
Total other assets	580,061		456,969

Total assets	$	13,218,842	$	12,655,952



	September 30, 2019			December 31, 2018
LIABILITIES AND MEMBER’S EQUITY

Current Liabilities:
Payables:
Affiliates	$	54,508		$	50,727
Advances from affiliates	169,908			—
Trade and other	207,871			226,911
Transportation and exchange gas payables	2,456			5,973
Reserve for rate refunds	130,752			—
Regulatory liabilities	56,871			5,097
Accrued liabilities	197,569			218,384
Long-term debt due within one year	18,082			15,419
Total current liabilities	838,017			522,511

Long-Term Debt	4,020,631			3,998,988

Other Long-Term Liabilities:
Asset retirement obligations	391,565			348,609
Regulatory liabilities	967,398			1,026,892
Deferred revenue	218,241			226,164
Lease liability	85,969			—
Other	12,230			4,188
Total other long-term liabilities	1,675,403			1,605,853

Contingent Liabilities and Commitments (Note 4)

Member’s Equity:
Member’s capital	4,428,499			4,428,499
Retained earnings	2,256,450			2,099,567
Accumulated other comprehensive income (loss)	(158		)	534
Total member’s equity	6,684,791			6,528,600

Total liabilities and member’s equity	$	13,218,842		$	12,655,952



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



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



	Page
Part I. Financial Information:
Item 1. Financial Statements
Condensed Consolidated Statement of Comprehensive Income —Three and Nine Months Ended ~~March 31,~~September 30, 2019 and 2018	4
Condensed Consolidated Balance Sheet — ~~March 31,~~September 30, 2019 and December 31, 2018	5
Condensed Consolidated Statement of Member's Equity — Three and Nine Months Ended ~~March 31,~~September 30, 2019 and 2018	7
Condensed Consolidated Statement of Cash Flows — ~~Three~~Nine Months Ended ~~March 31,~~September 30, 2019 and 2018	8
Notes to Condensed Consolidated Financial Statements	9

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	19

Item 4. Controls and Procedures	22

Part II. Other Information	22

Item 1. Legal Proceedings	22

Item 1A. Risk Factors	22

Item 6. Exhibits	23


	Three months ended March 31,						Three Months ended September 30
	2019			2018			2019			2018
Member's Capital:
Balance at beginning of period	$	4,428,499		$	4,088,499		$	4,428,499		$	4,428,499
Cash contributions from parent	—			340,000			—			—
Balance at end of period	4,428,499			4,428,499			4,428,499			4,428,499
Retained Earnings:
Balance at beginning of period	2,099,567			1,848,488			2,195,168			2,030,626
Net income	229,702			179,916			274,282			179,498
Cash distributions to parent	(176,000		)	(55,000		)	(213,000		)	(100,000		)
Balance at end of period	2,153,269			1,973,404			2,256,450			2,110,124
Accumulated Other Comprehensive Income:
Balance at beginning of period	534			337			(65		)	861
Equity interest in unrealized gain (loss) on interest rate hedge	(230		)	405
Other comprehensive income (loss)							(93		)	48
Balance at end of period	304			742			(158		)	909

Total Member's Equity	$	6,582,072		$	6,402,645		$	6,684,791		$	6,539,532



	Nine Months ended September 30
	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	715,883			551,636
Cash distributions to parent	(559,000		)	(290,000		)
Balance at end of period	2,256,450			2,110,124
Accumulated Other Comprehensive Income:
Balance at beginning of period	534			337
Other comprehensive income (loss)	(692		)	572
Balance at end of period	(158		)	909

Total Member's Equity	$	6,684,791		$	6,539,532


	Three months ended March 31,						Nine months ended September 30,
	2019			2018			2019			2018
Cash flows from operating activities:
Net income	$	229,702		$	179,916		$	715,883		$	551,636
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Depreciation and amortization	104,623			83,224			320,103			264,176
Allowance for equity funds used during construction (equity AFUDC)	(6,510		)	(19,782		)	(22,926		)	(78,337		)
Regulatory credit resulting from Tax Reform	(1,749		)	—			(19,244		)	(20,867		)
Equity in (earnings) losses of unconsolidated affiliates	(771		)	1,590			(2,441		)	(497		)
Distributions from unconsolidated affiliates	1,248			429			3,744			1,751
Changes in operating assets and liabilities:
Receivables — affiliates	619			598			(25		)	388
— trade and other	(33,047		)	8,612			(26,239		)	19,236
Transportation and exchange gas receivable	(1,824		)	275			259			1,536
Inventories	(4,531		)	(37,886		)	6,584			(16,132		)
Payables — affiliates	(4,242		)	(29,496		)	3,781			(1,235		)
— trade	(45,546		)	(52,553		)	(21,844		)	(57,502		)
Accrued liabilities	(13,105		)	(11,473		)	(18,575		)	968
Reserve for rate refunds							130,752			—
Asset retirement obligations - non-current	18,577			17,201			7,615			21,545
Deferred revenue	(2,638		)	(2,638		)	(7,922		)	(7,922		)
Other, net	3,419			(6,296		)	15,264			(11,222		)
Net cash provided by operating activities	244,225			131,721			1,084,769			667,522

Cash flows from financing activities:
Proceeds from long-term debt	—			993,440			—			993,440
Proceeds from other financing obligations	7,914			18,804			35,709			29,188
Retirement of long-term debt							—			(250,000		)
Payments on other financing obligations	(3,680		)	(375		)	(12,581		)	(1,151		)
Payments for debt issuance costs	—			(9,025		)	—			(10,043		)
Cash distributions to parent	(176,000		)	(55,000		)	(559,000		)	(290,000		)
Cash contributions from parent	—			340,000			—			340,000
Advances from affiliate, net	86,580			—			169,908			—
Net cash provided by (used in) financing activities	(85,186		)	1,287,844			(365,964		)	811,434

Cash flows from investing activities:
Property, plant and equipment additions, net of equity AFUDC*	(184,556		)	(737,004		)
Capital expenditures*							(702,634		)	(1,982,386		)
Contributions and advances for construction costs	10,057			188,543			22,690			393,130
Disposal of property, plant and equipment, net	(5,477		)	(5,241		)	(37,014		)	(21,284		)
Advances to affiliate, net	33,034			(854,125		)	33,034			150,431
Contribution to unconsolidated affiliate							(12,250		)	—
Purchase of ARO Trust investments	(19,518		)	(15,530		)	(52,272		)	(44,492		)
Proceeds from sale of ARO Trust investments	9,767			3,792			29,641			25,964
Other, net	(2,346		)	—			—			(319		)
Net cash used in investing activities	(159,039		)	(1,419,565		)	(718,805		)	(1,478,956		)

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

* Increase to property, plant and equipment, net of equity AFUDC	$	(161,741	)	$	(721,921	)
* Increase to property, plant and equipment, exclusive of equity AFUDC							$	(686,270	)	$	(1,803,610	)
Changes in related accounts payable and accrued liabilities	(22,815		)	(15,083		)	(16,364		)	(178,776		)
Property, plant and equipment additions, net of equity AFUDC	$	(184,556	)	$	(737,004	)
Capital expenditures							$	(702,634	)	$	(1,982,386	)



		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



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



	(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



	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		%



	(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