TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC - FORM 10-Q

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EX-32 - EX-32 - TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC	tgpl_20180930xex-32.htm
EX-31.2 - EX-31.2 - TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC	tgpl_20180930xex-312.htm
EX-31.1 - EX-31.1 - TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC	tgpl_20180930xex-311.htm

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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, 2018



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

For the transition period from to

Commission file number 1-7584

TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC

(Exact name of registrant as specified in its charter)



DELAWARE		74-1079400
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

2800 POST OAK BOULEVARD HOUSTON, TEXAS		77056
(Address of principal executive offices)		(Zip Code)

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

NO CHANGE

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

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

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

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



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

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

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

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

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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, 2018 and 2017	4
Condensed Consolidated Balance Sheet — September 30, 2018 and December 31, 2017	5
Condensed Consolidated Statement of Cash Flows — Nine Months Ended September 30, 2018 and 2017	7
Notes to Condensed Consolidated Financial Statements	8

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	20

Item 4. Controls and Procedures	25

Part II. Other Information	25

Item 1. Legal Proceedings	25

Item 1A. Risk Factors	26

Item 6. Exhibits	27

Forward Looking Statements

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

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


•	Our and our affiliates’ future credit ratings;


•	Amounts and nature of future capital expenditures;


•	Expansion and growth of our business and operations;


•	Expected in-service dates for capital projects;


•	Financial condition and liquidity;


•	Business strategy;


•	Cash flow from operations or results of operations;


•	Rate case filings;

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•	Natural gas prices, supply and demand; and


•	Demand for our services.

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


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


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


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


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


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


•	Our ability to successfully expand our facilities and operations;


•	Development and rate of adoption of alternative energy sources;


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


•	The impact of existing and future laws (including, but not limited to, the Tax Cuts and Job Acts of 2017), regulations, the regulatory environment, environmental liabilities, and litigation, as well as our ability to obtain necessary permits and approvals, and achieve favorable rate proceeding outcomes;


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


•	Changes in maintenance and construction costs;


•	Changes in the current geopolitical situation;


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


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


•	Risks associated with weather and natural phenomena including climate conditions and physical damage to our facilities;


•	Acts of terrorism, cybersecurity 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

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

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

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PART I — FINANCIAL INFORMATION



ITEM 1.	Financial Statements.

TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC

CONDENSED CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME

(Thousands of Dollars)

(Unaudited)



	Three months ended September 30,						Nine months ended September 30,
	2018			2017			2018			2017
Operating Revenues:
Natural gas sales	$	41,757		$	26,763		$	96,881		$	74,867
Natural gas transportation	422,999			389,080			1,265,285			1,116,891
Natural gas storage	33,839			33,954			102,392			102,778
Other	2,815			2,255			7,763			3,734
Total operating revenues	501,410			452,052			1,472,321			1,298,270

Operating Costs and Expenses:
Cost of natural gas sales	41,757			26,763			96,881			74,867
Cost of natural gas transportation	9,126			5,828			30,661			15,282
Operation and maintenance	101,916			113,101			282,591			267,914
Administrative and general	44,474			43,110			137,836			132,020
Depreciation and amortization	91,670			82,826			264,176			239,368
Taxes — other than income taxes	16,622			15,333			52,224			49,131
Regulatory credit resulting from Tax Reform (Note 1)	—			—			(20,867		)	—
Other expense, net	15,631			13,475			46,036			43,112
Total operating costs and expenses	321,196			300,436			889,538			821,694

Operating Income	180,214			151,616			582,783			476,576

Other (Income) and Other Expenses:
Interest expense	50,180			41,304			148,629			115,797
Allowance for equity and borrowed funds used during construction (AFUDC)	(43,165		)	(22,334		)	(104,668		)	(70,783		)
Equity in earnings of unconsolidated affiliates	(762		)	(912		)	(497		)	(3,322		)
Miscellaneous other (income) expenses, net	(5,537		)	(774		)	(12,317		)	(5,972		)
Total other (income) and other expenses	716			17,284			31,147			35,720

Net Income	179,498			134,332			551,636			440,856

Other comprehensive income:
Equity interest in unrealized gain on interest rate hedges (includes $(51) and $38 for the three months ended and $(78) and $75 for the nine months ended September 30, 2018 and September 30, 2017, respectively, of accumulated other comprehensive income reclassification for equity interest in realized losses (gains) on interest rate hedges)	48			72			572			108

Comprehensive Income	$	179,546		$	134,404		$	552,208		$	440,964

See accompanying notes.

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TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC

CONDENSED CONSOLIDATED BALANCE SHEET

(Thousands of Dollars)

(Unaudited)



	September 30, 2018		December 31, 2017
ASSETS

Current Assets:
Cash	$	—	$	—
Receivables:
Affiliates	721		1,109
Advances to affiliate	244,816		395,247
Trade and other	151,186		170,422
Transportation and exchange gas receivables	1,669		3,205
Inventories	56,159		40,027
Regulatory assets	103,677		97,149
Other	15,306		12,508
Total current assets	573,534		719,667

Investments, at cost plus equity in undistributed earnings	27,824		28,505

Property, Plant and Equipment:
Natural gas transmission plant	15,606,560		13,771,183
Less-Accumulated depreciation and amortization	4,064,910		3,859,520
Total property, plant and equipment, net	11,541,650		9,911,663

Other Assets:
Regulatory assets	281,457		276,315
Other	168,346		141,786
Total other assets	449,803		418,101

Total assets	$	12,592,811	$	11,077,936

(continued)

See accompanying notes.

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TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC

CONDENSED CONSOLIDATED BALANCE SHEET

(Thousands of Dollars)

(Unaudited)



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

Current Liabilities:
Payables:
Affiliates	$	42,185	$	43,420
Trade and other	264,588		469,153
Transportation and exchange gas payables	1,888		2,121
Accrued liabilities	177,389		173,602
Long-term debt due within one year	1,681		251,430
Total current liabilities	487,731		939,726

Long-Term Debt	3,204,044		2,191,576

Other Long-Term Liabilities:
Asset retirement obligations	327,760		350,280
Regulatory liabilities	1,010,647		990,702
Advances for construction costs	789,762		426,771
Deferred revenue	228,807		236,729
Other	4,528		4,828
Total other long-term liabilities	2,361,504		2,009,310

Contingent Liabilities and Commitments (Note 3)

Member’s Equity:
Member’s capital	4,428,499		4,088,499
Retained earnings	2,110,124		1,848,488
Accumulated other comprehensive income	909		337
Total member’s equity	6,539,532		5,937,324

Total liabilities and member’s equity	$	12,592,811	$	11,077,936

See accompanying notes.

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TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC

CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS

(Thousands of Dollars)

(Unaudited)



	Nine months ended September 30,
	2018			2017
Cash flows from operating activities:
Net income	$	551,636		$	440,856
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Depreciation and amortization	264,176			239,368
Allowance for equity funds used during construction (equity AFUDC)	(78,337		)	(53,867		)
Regulatory credit resulting from Tax Reform (Note 1)	(20,867		)	—
Equity in earnings of unconsolidated affiliates	(497		)	(3,322		)
Distributions from unconsolidated affiliates	1,751			6,261
Changes in operating assets and liabilities:
Receivables — affiliates	388			163
— trade and other	19,236			(2,156		)
Transportation and exchange gas receivable	1,536			883
Inventories	(16,132		)	7,524
Payables — affiliates	(1,235		)	(5,972		)
— trade	(57,502		)	(28,536		)
Accrued liabilities	(8,867		)	(41,137		)
Asset retirement obligations - non-current	28,216			45,629
Asset retirement obligations - removal costs	(6,671		)	(1,708		)
Deferred revenue	(7,922		)	(2,864		)
Other, net	(1,387		)	(4,179		)
Net cash provided by operating activities	667,522			596,943

Cash flows from financing activities:
Proceeds from long-term debt	993,440			—
Proceeds from other financing obligation	29,188			—
Retirement of long-term debt	(250,000		)	—
Payments on other financing obligation	(1,151		)	(241		)
Payments for debt issuance costs	(10,043		)	(13		)
Cash distributions to parent	(290,000		)	(330,000		)
Cash contributions from parent	340,000			110,000
Net cash provided by (used in) financing activities	811,434			(220,254		)

Cash flows from investing activities:
Property, plant and equipment additions, net of equity AFUDC*	(1,982,386		)	(1,089,917		)
Contributions and advances for construction costs	393,130			252,249
Disposal of property, plant and equipment, net	(21,284		)	(33,281		)
Advances to affiliate, net	150,431			512,634
Purchase of ARO Trust investments	(44,492		)	(46,709		)
Proceeds from sale of ARO Trust investments	25,964			27,520
Proceeds from insurance	—			3,200
Other, net	(319		)	(2,385		)
Net cash used in investing activities	(1,478,956		)	(376,689		)

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

* Increase to property, plant and equipment, net of equity AFUDC	$	(1,803,610	)	$	(1,154,317	)
Changes in related accounts payable and accrued liabilities	(178,776		)	64,400
Property, plant and equipment additions, net of equity AFUDC	$	(1,982,386	)	$	(1,089,917	)

See accompanying notes.

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TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1. BASIS OF PRESENTATION

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

Transco was indirectly owned by Williams Partners L.P. (WPZ), a publicly traded Delaware limited partnership, which was consolidated by The Williams Companies, Inc. (Williams). On August 10, 2018, Williams completed a merger with WPZ, pursuant to which Williams acquired all of the approximately 256 million publicly held outstanding common units of WPZ in exchange for 382 million shares of Williams' common stock (WPZ Merger). Williams continued as the surviving entity. Transco is now indirectly owned by Williams.

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, 2018 and December 31, 2017 consist of Cardinal Pipeline Company, LLC (Cardinal) with an ownership interest of approximately 45 percent and Pine Needle LNG Company, LLC (Pine Needle) with an ownership interest of 35 percent. We received distributions associated with our equity method investments totaling $1.8 million and $6.3 million in the nine months ended September 30, 2018 and September 30, 2017, respectively.

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

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

Regulatory Accounting

In December 2017, the Tax Cuts and Jobs Act (Tax Reform) was enacted, which, among other things, reduced the federal corporate income tax rate from 35 percent to 21 percent . In accordance with ASC 980-740-25-2, we have recognized a regulatory liability to reflect the probable return to certain customers through future rates of the future decrease in income taxes payable associated with Tax Reform. In determining the estimated liability that we currently believe is probable of return to certain customers through future rates, we considered the mix of services provided by us, taking into consideration that certain of these services are provided under fixed negotiated rates, in lieu of cost-based recourse rates, that are designed to recover the cost of providing those services, with no expected future rate adjustment for the term of those contracts. The liability was recorded in December 2017 through a regulatory charge to operating income of $471.1 million. At the end of May 2018, we recorded a reduction to the liability of $20.9 million mostly due to an updated weighted average state income tax rate. The timing and actual amount of such return will be subject to the outcome of our rate case proceeding filed in Docket No. RP18-1126.

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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.

Accounting Standards Issued and Adopted

Effective January 1, 2018, we adopted Accounting Standards Update (ASU) 2016-15 “Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments” (ASU 2016-15). Among other things, ASU 2016-15 permits an accounting policy election to classify distributions received from equity-method investees using either the cumulative earnings approach or the nature of distribution approach. We have elected to apply the nature of distribution approach and have retrospectively conformed the prior year presentation within the Condensed Consolidated Statement of Cash Flows in accordance with ASU 2016-15. For the period ended September 30, 2017, amounts previously presented as Return of capital from unconsolidated affiliates within Investing Activities are now presented as part of Distributions from unconsolidated affiliates within Operating Activities, resulting in an increase to Net cash provided by operating activities of $2.7 million with a corresponding reduction in Net cash used in investing activities.

In May 2014, the Financial Accounting Standards Board (FASB) issued ASU 2014-09 establishing Accounting Standards Codification (ASC) Topic 606, “Revenue from Contracts with Customers” (ASC 606). ASC 606 establishes a comprehensive new revenue recognition model designed to depict the transfer of goods or services to a customer in an amount that reflects the consideration the entity expects to be entitled to receive in exchange for those goods or services and requires significantly enhanced revenue disclosures. In August 2015, the FASB issued ASU 2015-14 “Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date” (ASU 2015-14). Per ASU 2015-14, the standard became effective for interim and annual reporting periods beginning after December 15, 2017.

We adopted the provisions of ASC 606 effective January 1, 2018, utilizing the modified retrospective transition method for all contracts with customers, which included applying the provisions of ASC 606 beginning January 1, 2018, to all contracts not completed as of that date. There was no cumulative effect adjustment to retained earnings upon initially applying ASC 606 for periods prior to January 1, 2018.

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

Accounting Standards Issued But Not Yet Adopted

In June 2016, the FASB issued ASU 2016-13 “Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments” (ASU 2016-13). ASU 2016-13 changes the impairment model for most financial assets and certain other instruments. For trade and other receivables, held-to-maturity debt securities, loans, and other instruments, entities will be required to use a new forward-looking “expected loss” model that generally will result in the earlier recognition of allowances for losses. The guidance also requires increased disclosures. ASU 2016-13 is effective for interim and annual periods beginning after December 15, 2019. Early adoption is permitted. ASU 2016-13 requires varying transition methods for the different categories of amendments. We do not expect ASU 2016-13 to have a significant impact on our consolidated financial statements.

In February 2016, the FASB issued ASU 2016-02 “Leases (Topic 842)” (ASU 2016-02). ASU 2016-02 establishes a comprehensive new lease accounting model. ASU 2016-02 modifies the definition of a lease, requires a dual approach to lease classification similar to current lease accounting, and causes lessees to recognize operating leases on the balance sheet as a lease liability measured as the present value of the future lease payments with a corresponding right-of-use asset, with an exception for leases with a term of one year or less. Additional disclosures will also be required regarding the amount, timing, and uncertainty of cash flows arising from leases. In January 2018, the FASB issued ASU 2018-01 “Leases (Topic 842): Land Easement Practical Expedient for Transition to Topic 842” (ASU 2018-01). Per ASU 2018-01, land easements and right-of-way are required to be assessed under ASU 2016-02 to determine whether the

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arrangements are or contain a lease. ASU 2018-01 permits an entity to elect a transition practical expedient to not apply ASU 2016-02 to land easements that exist or expired before the effective date of ASU 2016-02 and that were not previously assessed under the previous lease guidance in ASC Topic 840 “Leases”.

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

We are in the process of finalizing our review of contracts to identify leases based on the modified definition of a lease and identifying changes to our internal controls to support management in the accounting for and disclosure of leasing activities upon adoption of ASU 2016-02. We implemented a financial lease accounting system to assist management in the accounting for leases upon adoption. While we are still in the process of completing our implementation evaluation of ASU 2016-02, we currently believe the most significant changes to our financial statements relate to the recognition of a lease liability and offsetting right-of-use asset in our Condensed Consolidated Balance Sheet for operating leases. We are also evaluating ASU 2016-02's available practical expedients on adoption, which we generally expect to elect.

2. REVENUE RECOGNITION

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

A performance obligation is a promise in a contract to transfer a distinct good or service (or integrated package of goods or services) to the customer. A contract’s transaction price is allocated to each distinct performance obligation and recognized as revenue, when, or as, the performance obligation is satisfied. A performance obligation is distinct if the product or service is separately identifiable from other items in the integrated package of services and if a customer can benefit from it on its own or with other resources that are readily available to the customer. Service revenue contracts contain a series of distinct services, with the majority of our contracts having a single performance obligation that is satisfied over time as the customer simultaneously receives and consumes the benefits provided by our performance. Most of our product sales contracts have a single performance obligation with revenue recognized at a point in time when the products have been sold and delivered to the customer.

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

Service Revenues

We are subject to regulation by certain state and federal authorities, including the FERC, with revenue derived from both firm and interruptible transportation and storage contracts. Firm transportation and storage agreements provide for a reservation charge based on the pipeline or storage capacity reserved, and a commodity charge based on the volume of natural gas delivered/stored, each at rates specified in our FERC tariffs or as negotiated with our customers, with contract terms that are generally long-term in nature. Most of our long-term contracts contain an evergreen provision, which allows the contracts to be extended for periods primarily up to one year in length an indefinite number of times following the specified contract term and until terminated generally by either us or the customer. Interruptible transportation and storage agreements provide for a volumetric charge based on actual commodity transportation or

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storage utilized in the period in which those services are provided, and the contracts are generally limited to one month periods or less. Our performance obligations include the following:


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


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

In situations where we consider the integrated package of services as a single performance obligation, which represents a majority of our contracts with customers, we do not consider there to be multiple performance obligations because the nature of the overall promise in the contract is to stand ready (with regard to firm transportation and storage contracts), receive, transport or store, and redeliver natural gas to the customer; therefore, revenue is recognized at the completion of the integrated package of services and represents a single performance obligation.

We recognize revenues for reservation charges over the performance obligation period, which is the contract term, regardless of the volume of natural gas that is transported or stored. Revenues for commodity charges from both firm and interruptible transportation services and storage services are recognized when natural gas is delivered at the agreed upon delivery point or when natural gas is injected or withdrawn from the storage facility because they specifically relate to our efforts to provide these distinct services. Generally, reservation charges and commodity charges are recognized as revenue in the same period they are invoiced to our customers. As a result of the ratemaking process, certain amounts collected by us may be subject to refunds upon the issuance of final orders by the FERC in pending rate proceedings. We record estimates of rate refund liabilities considering our and other third-party regulatory proceedings, advice of counsel, and other risks.

Product Sales

In the course of providing transportation services to customers, we may receive different quantities of natural gas from customers than the quantities delivered on behalf of those customers. The resulting imbalances are primarily settled through the purchase or sale of natural gas with each customer under terms provided for in our FERC tariffs. Revenue is recognized from the sale of natural gas upon settlement of the transportation and exchange imbalances.

Revenue by Category

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

Contract Liabilities

Our contract liabilities consist of advance payments from customers, which include prepayments, and other billings for which future services are to be provided under the contract. These amounts are deferred until recognized in revenue when the associated performance obligation has been satisfied, which is primarily straight-line over the remaining contractual service periods, and are classified as current or non-current according to when such amounts are expected to be recognized. Current and non-current contract liabilities are included within Accrued Liabilities and Other Long-Term Liabilities - Deferred revenue, respectively, in our Condensed Consolidated Balance Sheet.

Contracts requiring advance payments and the recognition of contract liabilities are evaluated to determine whether the advance payments provide us with a significant financing benefit. This determination is based on the combined effect of the expected length of time between when we transfer the promised good or service to the customer and when the customer pays for those goods or services and the prevailing interest rates. We have assessed our contracts and determined none of our contracts contain a significant financing component.

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The following table presents a reconciliation of our contract liabilities:



	Quarter to Date September 30, 2018			Year to Date September 30, 2018
	(Thousands)
Balance at beginning of period	$	242,017		$	247,296
Payments received and deferred	—			—
Recognized in revenue	(2,644		)	(7,923		)
Balance at end of period	$	239,373		$	239,373

The following table presents the amount of the contract liabilities balance as of September 30, 2018, expected to be recognized as revenue in each of the next five years as performance obligations are expected to be satisfied:



	(Thousands)
2018 (remainder)	$	2,643
2019	10,566
2020	10,568
2021	10,566
2022	10,566
2023	10,566
Thereafter	183,898

Remaining Performance Obligations

The following table presents the transaction price allocated to the remaining performance obligations under certain contracts as of September 30, 2018. These primarily include reservation charges on contracted capacity on our firm transportation and storage contracts with customers. Amounts from certain contracts included in the table below, which are subject to the periodic review and approval by the FERC, reflect the rates for such services in our current FERC tariffs for the life of the related contracts; however, these rates may change based on future tariffs approved by the FERC and the amount and timing of these changes is not currently known. As a practical expedient permitted by ASC 606, this table excludes the variable consideration component for commodity charges. It also excludes consideration that will be recognized in future periods (see above for Contract Liabilities and the expected recognition of those amounts within revenue). As noted above, certain of our contracts contain evergreen provisions for periods beyond the initial term of the contract. The remaining performance obligation as of September 30, 2018, does not consider potential future performance obligations for which the renewal has not been exercised. The table below also does not include contracts with customers for which the underlying facilities have not received FERC authorization to be placed into service.



	(Thousands)
2018 (remainder)	$	424,051
2019	1,627,699
2020	1,509,440
2021	1,371,150
2022	1,094,138
2023	960,611
Thereafter	8,339,653
Total	$	15,326,742

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The table above excludes remaining performance obligations associated with the Atlantic Sunrise expansion project for which we received FERC authorization to place into service in October 2018. We anticipate annual performance obligations of approximately $420 million associated with Atlantic Sunrise over the term of the contracts.

Accounts Receivable

We do not offer extended payment terms and typically receive payment within one month. We consider receivables past due if full payment is not received by the contractual due date. Our credit risk exposure in the event of nonperformance by the other parties is limited to the face value of the receivables. We perform ongoing credit evaluations of our customers' financial condition and require collateral from our customers, if necessary. Due to our customer base, we have not historically experienced recurring credit losses in connection with our receivables.

Receivables from contracts with customers are included within Receivables - Trade and other and Receivables - Affiliates and receivables that are not related to contracts with customers are included with Receivables - Advances to affiliate in our Condensed Consolidated Balance Sheet. At September 30, 2018 and January 1, 2018, Receivables - Trade and other includes $8.9 million and $2.5 million, respectively, of receivables not related to contracts with customers.

3. CONTINGENT LIABILITIES AND COMMITMENTS

Rate Matters

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 the Natural Gas Act of 1938, Section 5.

Income tax matters On March 15, 2018, the FERC issued a revised policy statement (the March 15 Statement) in Docket No. PL17-1 regarding the recovery of income tax costs in rates of natural gas pipelines. The FERC found that an impermissible double recovery results from granting a Master Limited Partnership (MLP) pipeline both an income tax allowance and a return on equity pursuant to the discounted cash flow methodology. As a result, the FERC will no longer permit a MLP pipeline to recover an income tax allowance in its cost of service. The FERC further stated it will address the application of this policy to non-MLP partnership forms as those issues arise in subsequent proceedings. One of the benefits of the recent WPZ Merger is to allow us to continue to recover an income tax allowance in our cost of service rates.

On July 18, 2018, the FERC issued an order dismissing the requests for rehearing and clarification of the revised policy statement. In addition, the FERC provided guidance that an MLP pipeline (or other pass-through entity) no longer recovering an income tax allowance pursuant to the revised policy may eliminate previously accumulated deferred income taxes (ADIT) from its cost of service instead of flowing these previously accumulated ADIT balances to ratepayers. This guidance, if implemented, would significantly mitigate the impact of the March 15 Statement. However, the FERC stated that the revised policy statement and such guidance do not establish a binding rule, but are instead expressions of general policy intent designed to provide guidance by notifying entities of the course of action the FERC intends to follow in future adjudications. To the extent the FERC addresses these issues in future proceedings, it will consider any arguments regarding not only the application of the revised policy to the fact of the case, but also any arguments regarding the underlying validity of the policy itself. The FERC's guidance on ADIT likely will be challenged by customers and state commission, which would result in a long period of revenue uncertainty for pipelines eliminating ADIT from their cost of service. The WPZ Merger has the additional benefit of eliminating this uncertainty.

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options that pipelines have to either reflect the reduced tax rate or explain why no rate change is necessary. FERC also clarified that a natural gas company organized as a pass-through entity all of whose income or losses are consolidated on the federal income tax return of its corporate parent is considered to be subject to the federal corporate income tax, and is thus eligible for a tax allowance. We believe this Final Rule and the previously discussed WPZ Merger allow for the continued recovery of income tax allowances in our rates. Our Docket No. RP18-1126 rate case filing (discussed above) reflects a tax allowance based on this clarification, and the FERC's September 28, 2018 order in that rate case proceeding finds that we are exempt from the FERC Form No. 501-G filing requirement established in Docket No. RM18-11.

On March 15, 2018, the FERC also issued a Notice of Inquiry in Docket No. RM18-12 seeking comments on the additional impacts of Tax Reform on jurisdictional rates, particularly whether, and if so how, the FERC should address changes relating to accumulated deferred income tax amounts after the corporate income tax rate reduction and bonus depreciation rules, as well as whether other features of Tax Reform require FERC action. We are evaluating the impact of these developments and currently expect any associated impacts would be prospective and determined through subsequent rate proceedings. We also continue to monitor developments that may impact our regulatory liabilities resulting from Tax Reform. It is reasonably possible that our future tariff-based rates collected may be adversely impacted.

Station 62 Incident

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

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

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

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

Environmental Matters

We have had studies underway for many years to test some of our facilities for the presence of toxic and hazardous substances such as polychlorinated biphenyls (PCBs) and mercury to determine to what extent, if any, remediation may be necessary. We have also similarly evaluated past on-site disposal of hydrocarbons at a number of our facilities. We have worked closely with and responded to data requests from the U.S. Environmental Protection Agency (EPA) and state agencies regarding such potential contamination of certain of our sites. On the basis of the findings to date, we estimate that environmental assessment and remediation costs under various federal and state statutes will total approximately $6 million to $8 million (including both expense and capital expenditures), measured on an undiscounted basis, and will substantially be spent over the next four to six years. This estimate depends on a number of assumptions concerning the scope of remediation that will be required at certain locations and the cost of the remedial measures. We are conducting environmental assessments and implementing a variety of remedial measures that may result in

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increases or decreases in the total estimated costs. At September 30, 2018, we had a balance of approximately $3.6 million for the expense portion of these estimated costs, $1.8 million recorded in Accrued liabilities and $1.8 million recorded in Other Long-Term Liabilities - Other in the accompanying Condensed Consolidated Balance Sheet. At December 31, 2017, we had a balance of approximately $4.0 million for the expense portion of these estimated costs, $1.8 million recorded in Accrued liabilities and $2.2 million recorded in Other Long-Term Liabilities - Other in the accompanying Condensed Consolidated Balance Sheet.

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

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

We consider prudently incurred environmental assessment and remediation costs and the costs associated with compliance with environmental standards to be recoverable through rates. To date, we have been permitted recovery of environmental costs, and it is our intent to continue seeking recovery of such costs through future rate filings. As a result, as estimated costs of environmental assessment and remediation are incurred, they are recorded as regulatory assets in the Condensed Consolidated Balance Sheet until collected through rates. At September 30, 2018, we had a balance of approximately $1.3 million of uncollected environmental related regulatory assets, $1.2 million recorded in Current Assets - Regulatory assets and $0.1 million recorded in Other Assets - Regulatory assets in the accompanying Condensed Consolidated Balance Sheet. At December 31, 2017, we had a balance of approximately $2.2 million of uncollected environmental related regulatory assets, $1.2 million recorded in Current Assets - Regulatory assets and $1.0 million recorded in Other Assets - Regulatory assets in the accompanying Condensed Consolidated Balance Sheet.

Other Matters

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

Summary

We estimate that for all matters for which we are able to reasonably estimate a range of loss, including those noted above and others that are not individually significant, our aggregate reasonably possible losses beyond amounts accrued for all of our contingent liabilities are immaterial to our expected future annual results of operations, liquidity and financial position. These calculations have been made without consideration of any potential recovery from third parties. We have disclosed all significant matters for which we are unable to reasonably estimate a range of possible loss.

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4. DEBT AND FINANCING ARRANGEMENTS

Credit Facility

Effective August 2018, we along with Williams and Northwest Pipeline LLC (Northwest Pipeline), entered into and are party to a credit facility with aggregate commitments available of $4.5 billion, with up to an additional $500 million increase in aggregate commitments available under certain circumstances. Total letter of credit capacity available to Williams under this credit facility is $1 billion. We are able to borrow up to $500 million under this credit facility to the extent not otherwise utilized by the other co-borrowers. At September 30, 2018, no letters of credit have been issued and no loans were outstanding under the credit facility.

On August 10, 2018, following the consummation of the WPZ Merger, WPZ's $3 billion commercial paper program was discontinued and Williams entered into a new $4 billion commercial paper program. Williams management considers amounts outstanding under this program to be a reduction of available capacity under the credit facility. At September 30, 2018, Williams had approximately $824 million of commercial paper outstanding.

Other Financing Obligation

During the first nine months of 2018, we received an additional $29.2 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 September 30, 2018, the amount included in Long-Term Debt on our Condensed Consolidated Balance Sheet for this financing obligation is $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 $1.7 million.

During the construction of our Atlantic-Sunrise project, we received funding from a partner for its proportionate share of construction costs related to an undivided ownership interest in certain parts of the project. Amounts received were recorded in Advances for construction costs and 100 percent of the costs associated with construction were capitalized on our Condensed Consolidated Balance Sheet. Upon placing the project in service during October 2018, we began utilizing this partner's undivided interest in the lateral, including the associated pipeline capacity, and expect to reclassify approximately $789.8 million, as of the balance sheet date, of funding previously received from our partner from Advances for construction costs to debt to reflect the financing obligation payable to our partner over an expected term of 20 years. As this transaction did not meet the criteria for sale leaseback accounting due to our continued involvement, it will be accounted for as a financing arrangement over the course of the capacity agreement.

Issuance and Retirement of Long-Term Debt

On March 15, 2018, we issued $400 million of 4.0 percent senior unsecured notes due 2028 and $600 million of 4.6 percent senior unsecured notes due 2048 to investors in a private placement. We used the net proceeds to retire our $250 million of 6.05 percent senior unsecured notes due June 2018, and for general purposes, including the funding of capital expenditures. In September 2018, we completed an exchange of these notes for substantially identical new notes that are registered under the Securities Act of 1933, as amended.

5. ARO TRUST

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

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

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



	September 30, 2018				December 31, 2017
	Amortized Cost Basis		Fair Value		Amortized Cost Basis		Fair Value
Money Market Funds	$	16.4	$	16.4	$	12.6	$	12.6
U.S. Equity Funds	46.4		66.7		35.9		50.5
International Equity Funds	21.9		24.5		20.7		24.6
Municipal Bond Funds	50.1		49.2		46.8		46.9
Total	$	134.8	$	156.8	$	116.0	$	134.6

6. FAIR VALUE MEASUREMENTS

The following table presents, by level within the fair value hierarchy, certain of our financial assets and liabilities. The carrying values of short-term financial assets (advances to affiliate) that have variable interest rates, accounts receivable and accounts payable approximate fair value because of the short-term nature of these instruments. Therefore, these assets and liabilities are not presented in the following table.



							Fair Value Measurements Using
	Carrying Amount			Fair Value			Quoted Prices In Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
	(Millions)
Assets (liabilities) at September 30, 2018:
Measured on a recurring basis:
ARO Trust investments	$	156.8		$	156.8		$	156.8	$	—		$	—

Additional disclosures:
Long-term debt, including current portion	(3,205.7		)	(3,621.6		)	—		(3,621.6		)	—

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

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

Fair Value Methods

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

ARO Trust investments — We deposit a portion of our collected rates, pursuant to the terms of the Docket No. RP12-993 rate case settlement, into the ARO Trust which is specifically designated to fund future asset retirement obligations. The ARO Trust invests in a portfolio of actively traded mutual funds that are measured at fair value on a recurring basis based on quoted prices in an active market and are reported in Other Assets-Other in the Condensed Consolidated Balance Sheet. However, both realized and unrealized gains and losses are ultimately recorded as regulatory assets or liabilities. See Note 5 for more information regarding the ARO Trust.

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Long-term debt — The disclosed fair value of our long-term debt is determined primarily by a market approach using broker quoted indicative period-end bond prices. The quoted prices are based on observable transactions in less active markets for our debt or similar instruments. The fair value of the financing obligation associated with our Dalton lateral, which is included within long-term debt, was determined using an income approach (See Note 4 - Debt and Financing Arrangements).

Reclassifications of fair value between Level 1, Level 2, and Level 3 of the fair value hierarchy, if applicable, are made at the end of each quarter. No transfers between Level 1 and Level 2 occurred during the nine months ended September 30, 2018 or 2017.

7. TRANSACTIONS WITH AFFILIATES

We are a participant in Williams' cash management program (See Note 1), and we make advances to and receive advances from Williams. At September 30, 2018, our advances to Williams totaled approximately $244.8 million and at December 31, 2017, our advances to WPZ totaled approximately $395.2 million. These advances are represented by demand notes and are classified as Receivables - Advances to affiliate in the accompanying Condensed Consolidated Balance Sheet. Advances are stated at the historical carrying amounts. Interest income is recognized when chargeable and collectability is reasonably assured. The interest rate on these intercompany demand notes is based upon the daily overnight investment rate paid on Williams' excess cash at the end of each month. At September 30, 2018, the interest rate was 1.99 percent.

Included in Operating Revenues in the accompanying Condensed Consolidated Statement of Comprehensive Income are revenues received from affiliates of $2.9 million and $6.2 million for the three and nine months ended September 30, 2018, respectively, and $2.5 million and $8.9 million for the three and nine months ended September 30, 2017, respectively. The rates charged to provide sales and services to affiliates are the same as those that are charged to similarly-situated nonaffiliated customers.

Included in Cost of natural gas sales in the accompanying Condensed Consolidated Statement of Comprehensive Income are cost of gas purchased from affiliates of $1.2 million and $4.9 million for the three and nine months ended September 30, 2018, respectively, and $1.0 million and $2.9 million for the three and nine months ended September 30, 2017, respectively. All gas purchases are made at market or contract prices.

We have no employees. Services necessary to operate our business are provided to us by Williams and certain affiliates of Williams. We reimburse Williams and its affiliates for all direct and indirect expenses incurred or payments made (including salary, bonus, incentive compensation and benefits) in connection with these services. Employees of Williams also provide general, administrative and management services to us, and we are charged for certain administrative expenses incurred by Williams. These charges are either directly identifiable or allocated to our assets. Direct charges are for goods and services provided by Williams at our request. Allocated charges are based on a three-factor formula, which considers revenues; property, plant and equipment; and payroll. In management’s estimation, the allocation methodologies used are reasonable and result in a reasonable allocation to us of our costs of doing business incurred by Williams. We were billed $99.2 million and $290.0 million in the three and nine months ended September 30, 2018, respectively, and $91.4 million and $261.1 million in the three and nine months ended September 30, 2017, respectively, for these services. Such expenses are primarily included in Operation and maintenance and Administrative and general expenses in the accompanying Condensed Consolidated Statement of Comprehensive Income.

We provide services to certain of our affiliates. We recorded reductions in operating expenses for services provided to and reimbursed by our affiliates of $1.7 million and $3.9 million for the three and nine months ended September 30, 2018, respectively, and $0.9 million and $2.7 million for the three and nine months ended September 30, 2017, respectively.

We made equity distributions totaling $290.0 million and $330.0 million during the nine months ended September 30, 2018 and 2017, respectively. During October 2018, we made an additional distribution of $200.0 million. Our parent made contributions to us totaling $340.0 million and $110.0 million in the nine months ended September 30, 2018 and 2017, respectively, to fund a portion of our expenditures for additions to property, plant and equipment.

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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.

8. OTHER

The Advances for construction costs on the accompanying Condensed Consolidated Balance Sheet are associated with advances received from a third party related to construction costs on the Atlantic Sunrise project. This balance increases as we receive additional advances. In October 2018, the project was placed into service and the related liabilities will be reclassified to debt and reduced by payments we make to the third party under terms of the applicable lease agreement.

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

General

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

On August 10, 2018, Williams completed a merger with WPZ, pursuant to which Williams acquired all of the approximately 256 million publicly held outstanding common units of WPZ in exchange for 382 million shares of Williams' common stock. Williams continued as the surviving entity.

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 the Natural Gas Act of 1938, Section 5. The impact of these specific new rates is expected to reduce revenues by approximately $2.5 million per month beginning October 1, 2018.

Income Tax Matters

On March 15, 2018, the FERC issued a revised policy statement (the March 15 Statement) in Docket No. PL17-1 regarding the recovery of income tax costs in rates of natural gas pipelines. The FERC found that an impermissible double recovery results from granting a Master Limited Partnership (MLP) pipeline both an income tax allowance and a return on equity pursuant to the discounted cash flow methodology. As a result, the FERC will no longer permit a MLP pipeline to recover an income tax allowance in its cost of service. The FERC further stated it will address the application of this policy to non-MLP partnership forms as those issues arise in subsequent proceedings. One of the benefits of the recent WPZ Merger is to allow us to continue to recover an income tax allowance in our cost of service rates.

On March 15, 2018, the FERC also issued a Notice of Proposed Rulemaking in Docket No. RM18-11 proposing a filing process that will allow it to determine which natural gas pipelines may be collecting unjust and unreasonable rates in light of the recent reduction in the corporate income tax rate in Tax Reform and the revised policy statement. On July 18, 2018, the FERC issued a Final Rule in the docket, retaining the filing requirement and reaffirming the options that pipelines have to either reflect the reduced tax rate or explain why no rate change is necessary. FERC also clarified that a natural gas company organized as a pass-through entity all of whose income or losses are consolidated on the federal income tax return of its corporate parent is considered to be subject to the federal corporate income tax, and is thus eligible for a tax allowance. We believe this Final Rule and the previously discussed WPZ Merger allow for the continued recovery of income tax allowances in our rates. Our Docket No. RP18-1126 rate case filing (discussed above) reflects a tax allowance based on this clarification, and the FERC's September 28, 2018 order in that rate case proceeding finds that we are exempt from the FERC Form No. 501-G filing requirement established in Docket No. RM18-11.

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subsequent rate proceedings. We also continue to monitor developments that may impact our regulatory liabilities resulting from Tax Reform. It is reasonably possible that our future tariff-based rates collected may be adversely impacted.

Critical Accounting Estimates

In December 2017, Tax Reform was enacted, which, among other things, reduced the corporate income tax rate from 35 percent to 21 percent. Rates charged to our customers are subject to the rate-making policies of the FERC, which have historically permitted the recovery of a income tax allowance that includes a deferred income tax component. As a result of the reduced income tax rate from Tax Reform and the collection of historical rates that reflected historical federal income tax rates, we expect that we will be required to return amounts to certain customers through future rates and have accordingly established a regulatory liability totaling $450.2 million as of September 30, 2018 and $471.1 million as of December 31, 2017. 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 months ended September 30, 2018 was $582.8 million compared to $476.6 million for the nine months ended September 30, 2017. The increase in Operating Income of $106.2 million (22.3 percent) was primarily due to higher Natural gas transportation, Natural gas sales and Other revenues in the first nine months of 2018 compared to the same period in 2017, partly offset by an increase in Operating Costs and Expenses, as discussed below. Net Income for the nine months ended September 30, 2018 was $551.6 million compared to $440.9 million for the nine months ended September 30, 2017. The increase in Net Income of $110.7 million (25.1 percent) was mostly attributable to the increase in Operating Income and a favorable change in net expenses in Other (Income) and Other Expenses, as discussed below.

Operating Revenues

Natural gas sales increased $22.0 million (29.4 percent) for the nine months ended September 30, 2018 compared to the same period in 2017. The increase was primarily due to $19.8 million of higher cash out sales and $2.2 million of higher system management gas sales. Cash out sales and system management gas are offset in our cost of natural gas sold and therefore have no impact on our operating income or results of operations.

Natural gas transportation for the nine months ended September 30, 2018 increased $148.4 million (13.3 percent) over the same period in 2017. The increase was primarily attributable to:


•	$133.4 million increase in transportation reservation revenues related to new incremental projects primarily attributable to:


•	$29.7 million from our Virginia Southside Phase II project placed in service in December 2017.


•	$27.9 million from our Dalton project placed in partial service in April 2017, and fully in service in August 2017;


•	$22.6 million from our Hillabee project Phase I placed in partial service in June 2017, and fully in service in July 2017;


•	$17.7 million from our Atlantic Sunrise project placed in partial service in September 2017;


•	$17.4 million from our New York Bay expansion project placed in service in October 2017;


•	$13.2 million from our Garden State project placed in partial service in September 2017, and fully in service in March 2018; and


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


•	$10.3 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; and


•	$4.9 million higher commodity revenue.

Other for the nine months ended September 30, 2018 increased $4.1 million (110.8 percent) over the same period in 2017. The increase was primarily attributable to deferred revenue on the Hillabee Project.

Operating Costs and Expenses

Excluding the Cost of natural gas sales, which is directly offset in revenues, of $96.9 million for the nine months ended September 30, 2018 and $74.9 million for the comparable period in 2017, our operating costs and expenses for the

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nine months ended September 30, 2018 increased $45.9 million (6.1 percent) from the comparable period in 2017. This increase was primarily attributable to:


•	$24.8 million (10.4 percent) increase in Depreciation and amortization costs primarily resulting from $27.8 million increase related to additional assets placed into service, partly offset by $4.4 million lower expenses due to ARO related depreciation;


•	$15.4 million (100.7 percent) increase in Cost of natural gas transportation costs primarily resulting from $10.3 million higher electric power costs and $5.1 million higher fuel costs. Electric power costs are recovered from customers through transportation rates resulting in no net impact on our operating income or results of operations;


•	$14.7 million (5.5 percent) increase in Operation and maintenance costs primarily resulting from $9.4 million higher employee labor and related benefit costs and $8.1 million increase in contracted services mainly related to our compressor stations engines overhaul;


•	$5.8 million (4.4 percent) increase in Administrative and general costs primarily due to higher allocated corporate expenses;


•	$3.1 million (6.3 percent) increase in Taxes - other than income taxes primarily due to higher ad valorem taxes as a result of additional assets placed into service;


•	$2.9 million (6.7 percent) increase in Other expenses, net primarily related to an unfavorable change in the deferral of ARO related depreciation to a regulatory asset; and


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

Other (Income) and Other Expenses

Other (income) and other expenses for the nine months ended September 30, 2018 had a favorable change of $4.6 million (12.9 percent) over the same period in 2017. This is mostly due to a favorable change of $33.9 million in Allowance for equity and borrowed funds used during construction (AFUDC) associated with capital expenditures on projects and a favorable change of $6.3 million in Miscellaneous other (income) expenses, net primarily due to higher interest income from affiliates, mostly offset by $32.8 million increase in Interest expense primarily due to $23.7 million associated with our debt issuance in March 2018 and $14.1 million associated with the other financing obligation (See Note 4), partly offset by $4.5 million due to debt re-payment.

Pipeline Expansion Projects

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

Hillabee

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

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

In August 2017, the Court of Appeals for the District of Columbia Circuit granted an appeal of the FERC certificate order for the Southeast Market Pipelines projects (which includes a group of related projects, including the Hillabee Expansion Project) filed by certain non-governmental organizations. In doing so, the court (i) remanded the matter to the FERC for preparation of an Environmental Impact Statement (EIS) that conforms with the court's opinion regarding quantifying certain greenhouse gas emissions, and (ii) vacated the FERC's certificate order for the projects, which would be effective following the court's mandate (by court order, the mandate will not issue until after disposition of any timely petitions for rehearing). In compliance with the court's directive, on February 5, 2018, the FERC issued a Final Supplemental EIS for the project, reaffirming that while the projects would result in temporary and permanent impacts on the environment, those impacts would not be significant. On March 14, 2018, the FERC issued an order on remand

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reinstating the certificate and abandonment authorizations for the Hillabee Expansion Project and the other Southeast Market Pipelines projects. As this order was issued prior to the court's mandate (which was issued on March 30, 2018), we experienced no lapse in FERC authorization for the project.

Garden State

The Garden State Expansion Project involved an expansion of our existing natural gas transmission system to provide incremental firm transportation capacity from our Station 210 Pooling Point in New Jersey to a new interconnection on our Trenton Woodbury Lateral in Burlington County, New Jersey. We placed the initial phase of the project into service on September 9, 2017 and the remaining portion of the project was placed into service on March 23, 2018. The project increased capacity by 180 Mdth/d.

Atlantic Sunrise

The Atlantic Sunrise Project involved 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. We placed a portion of the mainline project facilities into service on September 1, 2017, which increased capacity by 400 Mdth/d. We placed additional mainline facilities into service on June 1, 2018, which increased capacity by an additional 150 Mdth/d. We placed the full project into service on October 6, 2018.The full project increased capacity by 1,700 Mdth/d.

Gulf Connector

The Gulf Connector Expansion Project involves an expansion of our existing natural gas transmission system to provide incremental firm transportation capacity from Station 65 in Louisiana to delivery points in Wharton and San Patricio Counties, Texas. In November 2017, we received approval from the FERC for the project. We plan to place the project into service during the first quarter of 2019, assuming timely receipt of all necessary regulatory approvals. The project is expected to increase capacity by 475 Mdth/d.

Northeast Supply Enhancement

The Northeast Supply Enhancement Project involves an expansion of our existing natural gas transmission system to provide incremental firm transportation capacity from Station 195 in Pennsylvania to the Rockaway Delivery Lateral transfer point in New York. On April 20, 2018, the New York State Department of Environmental Conservation (NYSDEC) denied, without prejudice, Transco's application for certain permits required for the project. We addressed the technical issues identified by NYSDEC and refiled our application on May 16, 2018. We plan to place the project into service in the fourth quarter of 2020, assuming timely receipt of all necessary regulatory approvals. The project is expected to increase capacity by 400 Mdth/d.

Rivervale South to Market

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. In August 2018, we received approval from the FERC for the project. We plan to place the project into service as early as the fourth quarter of 2019, assuming timely receipt of all necessary regulatory approvals. The project is expected to increase capacity by 190 Mdth/d.

Gateway

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

Southeastern Trail

The Southeastern Trail Project involves an expansion of our existing natural gas transmission system to provide incremental firm transportation capacity from the Pleasant Valley interconnect with Dominion's Cove Point Pipeline in Virginia to the Station 65 Pooling Point in Louisiana. We filed an application with the FERC in April 2018 for approval of the project. We plan to place the project into service in late 2020, assuming timely receipt of all necessary regulatory approvals. The project is expected to increase capacity by 296 Mdth/d.

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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 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 580 Mdth/d.

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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 third quarter of 2018 that have materially affected, or are reasonably likely to materially affect, our Internal Control over Financial Reporting.

PART II — OTHER INFORMATION.



ITEM 1.	Legal Proceedings

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

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Item 1A. Risk Factors

Part I, Item 1A. Risk Factors in our Annual Report on Form 10-K for the year ended December 31, 2017, includes certain risk factors that could materially affect our business, financial condition, or future results. Those risk factors have not materially changed, except that the following risk factors are no longer applicable:

in the Form 10-K, the risk factor captioned:

The amount of income taxes that we will be allowed to recover will be determined by the outcome of future rate cases and any potential action taken by the FERC in response to its recent Notice of Inquiry; and

in the Form 10-Q for the period ending June 30, 2018, the risk factor captioned:

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

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ITEM 6.	Exhibits

The following instruments are included as exhibits to this report.



Exhibit Number		Description

2		Certificate of Conversion dated December 22, 2008 and effective December 31, 2008 (filed on February 24, 2011 as Exhibit 2.1 to our annual report on Form 10-K (File No. 001-07584) and incorporated herein by reference).

3.1		Certificate of Formation dated December 22, 2008 and effective December 31, 2008 (filed on February 24, 2011 as Exhibit 3.1 to our annual report on Form 10-K (File No. 001-07584) and incorporated herein by reference).

3.2		Amended and Restated Operating Agreement of Transcontinental Gas Pipe Line Company, LLC dated February 17, 2010 (filed on October 28, 2010 as Exhibit 3.2 to our quarterly report on Form 10-Q (File No. 001-07584) and incorporated herein by reference).

10.1		Credit Agreement dated as of July 13, 2018, between The Williams Companies, Inc., Northwest Pipeline LLC, and Transcontinental Gas Pipe Line Company, LLC, as co-borrowers, the lenders named therein, and Citibank, N.A. as Administrative Agent (filed on July 17, 2018 as Exhibit 10.1 to The Williams Companies, Inc.'s Current Report on Form 8-K (File No. 001-04174) and incorporated herein by reference).

31.1*		Certification of Principal Executive Officer pursuant to Rules 13a-14(a) and 15d-14(a) promulgated under the Securities Exchange Act of 1934, as amended, and Item 601(b)(31) of Regulation S-K, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2*		Certification of Principal Financial Officer pursuant to Rules 13a-14(a) and 15d-14(a) promulgated under the Securities Exchange Act of 1934, as amended, and Item 601(b)(31) of Regulation S-K, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32**		Certification of Principal Executive Officer and Principal Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

101.INS*		XBRL Instance Document.

101.SCH*		XBRL Taxonomy Extension Schema.

101.CAL*		XBRL Taxonomy Extension Calculation Linkbase.

101.DEF*		XBRL Taxonomy Extension Definition Linkbase.

101.LAB*		XBRL Taxonomy Extension Label Linkbase.

101.PRE*		XBRL Taxonomy Extension Presentation Linkbase.



*	Filed herewith.
**	Furnished herewith.

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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 1, 2018	By:	/s/ Ted T. Timmermans
			Ted T. Timmermans
			Vice President and Chief Accounting Officer
			(Principal Accounting Officer)

TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC - FORM 10-Q - November 1, 2018

Attached files

TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC Reports