10-Q

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended September 30, 2017

OR

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

For the transition period from to

Commission file number 1-7584

TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC

(Exact name of registrant as specified in its charter)

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

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

NO CHANGE

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

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

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

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

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

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

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

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

TRANSCONTINTENTAL GAS PIPE LINE COMPANY, LLC

Index

	Page
Part I. Financial Information:
Item 1. Financial Statements
Condensed Consolidated Statement of Comprehensive Income —Three and Nine Months Ended September 30, 2017 and 2016	4
Condensed Consolidated Balance Sheet — September 30, 2017 and December 31, 2016	5
Condensed Consolidated Statement of Cash Flows — Nine Months Ended September 30, 2017 and 2016	7
Notes to Condensed Consolidated Financial Statements	8
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	16
Item 4. Controls and Procedures	19
Part II. Other Information	19
Item 1. Legal Proceedings	19
Item 6. Exhibits	20

Forward Looking Statements

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

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

• Our and our affiliates’ future credit ratings;

• Amounts and nature of future capital expenditures;

• Expansion and growth of our business and operations;

• Expected in-service dates for capital projects;

• Financial condition and liquidity;

• Business strategy;

• Cash flow from operations or results of operations;

• Rate case filings;

• Natural gas prices, supply and demand; and

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• Demand for our services.

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

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

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

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

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

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

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

• Our ability to successfully expand our facilities and operations;

• Development and rate of adoption of alternative energy sources;

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

• The impact of existing and future laws, 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, including cybersecurity threats, and related disruptions; and

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

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

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

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

Because forward-looking statements involve risks and uncertainties, we caution that there are important factors, in addition to those listed above, that may cause actual results to differ materially from those contained in the forward-looking statements. For a detailed discussion of those factors, see Part I, Item 1A. Risk Factors in our Annual Report on Form 10-K filed with the SEC on February 22, 2017.

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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,
	2017			2016			2017			2016
Operating Revenues:
Natural gas sales	$	26,763		$	31,244		$	74,867		$	67,474
Natural gas transportation	389,080			346,004			1,116,891			1,042,547
Natural gas storage	33,954			34,258			102,778			88,315
Other	2,255			1,343			3,734			3,396
Total operating revenues	452,052			412,849			1,298,270			1,201,732
Operating Costs and Expenses:
Cost of natural gas sales	26,763			31,244			74,867			67,474
Cost of natural gas transportation	5,828			4,689			15,282			15,501
Operation and maintenance	113,101			83,916			267,914			225,975
Administrative and general	43,110			40,604			132,020			125,997
Depreciation and amortization	82,826			76,755			239,368			231,110
Taxes — other than income taxes	15,333			14,584			49,131			45,154
Other expense, net	13,475			12,894			43,112			41,541
Total operating costs and expenses	300,436			264,686			821,694			752,752
Operating Income	151,616			148,163			476,576			448,980
Other (Income) and Other Expenses:
Interest expense	41,304			37,318			115,797			113,957
Allowance for equity and borrowed funds used during construction (AFUDC)	(22,334		)	(19,922		)	(70,783		)	(45,656		)
Equity in earnings of unconsolidated affiliates	(912		)	(1,455		)	(3,322		)	(4,447		)
Miscellaneous other (income) expenses, net	(774		)	309			(5,972		)	655
Total other (income) and other expenses	17,284			16,250			35,720			64,509
Net Income	134,332			131,913			440,856			384,471
Other comprehensive income (loss):
Equity interest in unrealized gain (loss) on interest rate hedges (includes $38 and $41 for the three months ended and $75 and $140 for the nine months ended September 30, 2017 and September 30, 2016, respectively, of accumulated other comprehensive income reclassification for equity interest in realized losses on interest rate hedges)	72			156			108			(128		)
Comprehensive Income	$	134,404		$	132,069		$	440,964		$	384,343

See accompanying notes.

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TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC

CONDENSED CONSOLIDATED BALANCE SHEET

(Thousands of Dollars)

(Unaudited)

	September 30, 2017		December 31, 2016
ASSETS
Current Assets:
Cash	$	—	$	—
Receivables:
Affiliates	326		489
Advances to affiliate	299,059		811,693
Trade and other	146,471		144,315
Transportation and exchange gas receivables	944		1,827
Inventories	47,685		55,209
Regulatory assets	90,367		87,059
Other	14,179		13,305
Total current assets	599,031		1,113,897
Investments, at cost plus equity in undistributed earnings	39,571		42,403
Property, Plant and Equipment:
Natural gas transmission plant	13,136,224		11,996,454
Less-Accumulated depreciation and amortization	3,833,689		3,687,473
Total property, plant and equipment, net	9,302,535		8,308,981
Other Assets:
Regulatory assets	269,000		264,001
Other	132,052		102,198
Total other assets	401,052		366,199
Total assets	$	10,342,189	$	9,831,480

(continued)

See accompanying notes.

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TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC

CONDENSED CONSOLIDATED BALANCE SHEET

(Thousands of Dollars)

(Unaudited)

	September 30, 2017		December 31, 2016
LIABILITIES AND OWNER’S EQUITY
Current Liabilities:
Payables:
Affiliates	$	23,483	$	29,455
Trade and other	305,949		251,872
Transportation and exchange gas payables	3,555		1,571
Accrued liabilities	160,087		197,697
Long-term debt due within one year	251,320		—
Total current liabilities	744,394		480,595
Long-Term Debt	2,197,717		2,210,754
Other Long-Term Liabilities:
Asset retirement obligations	271,211		248,518
Regulatory liabilities	501,201		449,391
Advances for construction costs	261,487		283,028
Transportation prepayments	11,115		11,837
Deferred revenue	228,258		—
Other	4,573		6,088
Total other long-term liabilities	1,277,845		998,862
Contingent Liabilities and Commitments (Note 2)
Owner’s Equity:
Member’s capital	3,788,499		3,678,499
Retained earnings	2,333,616		2,462,760
Accumulated other comprehensive income	118		10
Total owner’s equity	6,122,233		6,141,269
Total liabilities and owner’s equity	$	10,342,189	$	9,831,480

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,
	2017			2016
Cash flows from operating activities:
Net income	$	440,856		$	384,471
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Depreciation and amortization	239,368			231,110
Allowance for equity funds used during construction (equity AFUDC)	(53,867		)	(37,285		)
Changes in operating assets and liabilities:
Receivables — affiliates	163			341
— trade and other	(2,156		)	17,045
Transportation and exchange gas receivable	883			(216		)
Inventories	7,524			13,617
Payables — affiliates	(5,972		)	(23,340		)
— trade	(28,536		)	6,041
Accrued liabilities	(41,137		)	61,484
Asset retirement obligations - non-current	45,629			3,761
Asset retirement obligations - removal costs	(1,708		)	(2,688		)
Deferred revenue	(2,142		)	—
Other, net	(4,691		)	23,451
Net cash provided by operating activities	594,214			677,792
Cash flows from financing activities:
Proceeds from long-term debt	—			998,250
Retirement of long-term debt	—			(200,000		)
Payments on other financing obligation	(241		)	—
Payments for debt issuance costs	(13		)	(8,235		)
Cash distributions to parent	(330,000		)	(350,000		)
Cash contributions from parent	110,000			372,000
Net cash provided by (used in) financing activities	(220,254		)	812,015
Cash flows from investing activities:
Property, plant and equipment additions, net of equity AFUDC*	(1,089,917		)	(906,105		)
Contributions and advances for construction costs	252,249			157,545
Disposal of property, plant and equipment, net	(33,281		)	(4,439		)
Advances to affiliate, net	512,634			(718,279		)
Return of capital from unconsolidated affiliates	2,729			2,106
Purchase of ARO Trust investments	(46,709		)	(61,086		)
Proceeds from sale of ARO Trust investments	27,520			38,330
Proceeds from insurance	3,200			2,121
Other, net	(2,385		)	—
Net cash used in investing activities	(373,960		)	(1,489,807		)
Increase (decrease) in cash	—			—
Cash at beginning of period	—			—
Cash at end of period	$	—		$	—
*       Increase to property, plant and equipment, net of equity AFUDC	$	(1,154,317	)	$	(907,023	)
Changes in related accounts payable and accrued liabilities	64,400			918
Property, plant and equipment additions, net of equity AFUDC	$	(1,089,917	)	$	(906,105	)

See accompanying notes.

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TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1. BASIS OF PRESENTATION

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

Transco is indirectly owned by Williams Partners L.P. (WPZ), a publicly traded Delaware limited partnership, which is consolidated by The Williams Companies, Inc. (Williams). In January 2017, Williams permanently waived the WPZ general partner's incentive distribution rights, converted its 2 percent general partner interest in WPZ to a non-economic interest and purchased additional WPZ common units. At September 30, 2017, Williams owns a 74 percent limited partner interest in WPZ.

General

The condensed consolidated unaudited financial statements include our accounts and the accounts of the subsidiaries we control. Companies in which we and our subsidiaries own 20 percent to 50 percent of the voting common stock or otherwise exercise significant influence over operating and financial policies of the company are accounted for under the equity method. The equity method investments as of September 30, 2017 and December 31, 2016 consist of Cardinal Pipeline Company, LLC (Cardinal) with an ownership interest of approximately 45 percent and Pine Needle LNG Company, LLC (Pine Needle) with an ownership interest of 35 percent. We received distributions associated with our equity method investments totaling $6.3 million and $6.5 million in the nine months ended September 30, 2017 and September 30, 2016, respectively. Included in the distributions are $2.7 million and $2.1 million return of capital in 2017 and 2016, respectively.

The condensed consolidated unaudited financial statements have been prepared from our books and records. Certain information and footnote disclosures normally included in financial statements prepared in accordance with U.S. generally accepted accounting principles (GAAP) have been condensed or omitted in this Form 10-Q pursuant to Securities and Exchange Commission rules and regulations. The condensed consolidated unaudited financial statements include all normal recurring adjustments and others which, in the opinion of our management, are necessary to present fairly our interim financial statements. These condensed consolidated unaudited financial statements should be read in conjunction with the consolidated financial statements and the notes thereto included in our 2016 Annual Report on Form 10-K.

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

Accounting Standards Issued But Not Yet Adopted

In August 2016, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2016-15 “Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments” (ASU 2016-15). ASU 2016-15 provides specific guidance on eight cash flow classification issues, including debt prepayment or debt extinguishment costs and distributions received from equity method investees, to reduce diversity in practice. ASU 2016-15 is effective for interim and annual periods beginning after December 15, 2017. Early adoption is permitted. ASU 2016-15 requires a retrospective transition. We do not expect ASU 2016-15 to have a material impact on our consolidated financial statements.

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

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is effective for interim and annual periods beginning after December 15, 2019. Early adoption is permitted. ASU 2016-13 requires varying transition methods for the different categories of amendments. We do not expect ASU 2016-13 to have a significant impact on our consolidated financial statements.

In February 2016, the FASB issued ASU 2016-02 “Leases (Topic 842)” (ASU 2016-02). ASU 2016-02 establishes a comprehensive new lease accounting model. ASU 2016-02 clarifies the definition of a lease, requires a dual approach to lease classification similar to current lease classifications, and causes lessees to recognize leases on the balance sheet as a lease liability with a corresponding right-of-use asset. ASU 2016-02 is effective for interim and annual periods beginning after December 15, 2018. Early adoption is permitted. ASU 2016-02 requires a modified retrospective transition for capital or operating leases existing at or entered into after the beginning of the earliest comparative period presented in the financial statements. We are in the process of reviewing contracts to identify leases, as well as evaluating the applicability of ASU 2016-02 to contracts involving easement/rights-of-way.

In May 2014, the FASB issued ASU 2014-09 establishing Accounting Standards Codification (ASC) Topic 606, “Revenue from Contracts with Customers” (ASC 606). ASC 606 establishes a comprehensive new revenue recognition model designed to depict the transfer of goods or services to a customer in an amount that reflects the consideration the entity expects to be entitled to receive in exchange for those goods or services and requires significantly enhanced revenue disclosures. In August 2015, the FASB issued ASU 2015-14 “Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date” (ASU 2015-14). Per ASU 2015-14, the standard is effective for interim and annual reporting periods beginning after December 15, 2017. ASC 606 allows either full retrospective or modified retrospective transition and early adoption is permitted for annual periods beginning after December 15, 2016.

We continue to evaluate the impact ASC 606 may have on our financial statements. For each revenue contract type, we are conducting a formal contract review process to evaluate the impact, if any, that ASC 606 may have. We continue to evaluate contracts with a significant financing component, which may exist in situations where the timing of the consideration we receive varies significantly from the timing of when we provide the service, as well as a certain contract with prepayments for services. We are unable to determine the potential impact upon the amount and the timing of our revenue recognition. We continue to develop and evaluate disclosures required under the new standard, with a particular focus on the scope of contracts subject to disclosure of remaining performance obligations. Additionally, we have identified possible financial system and internal control changes necessary for adoption. We currently anticipate utilizing a modified retrospective transition upon the adoption of ASC 606 as of January 1, 2018.

2. CONTINGENT LIABILITIES AND COMMITMENTS

Rate Matters

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

The one issue reserved for litigation or further settlement relates to our proposal to change the design of the rates for service under our WSS-OA storage rate schedule, which was implemented subject to refund on March 1, 2007. Following a hearing, the FERC issued an opinion approving our proposed incremental rate design, and subsequently denied requests for rehearing of that approval. On February 21, 2014, the U. S. Court of Appeals for the D.C. Circuit (D.C. Circuit) issued an opinion that vacated and remanded the FERC's order because the FERC did not adequately support its conclusions. On March 17, 2016, the FERC issued an order addressing the issues raised by the D.C. Circuit's opinion. In the March 17 order, the FERC reversed its prior opinion and found that Transco's incremental rate design is unjust and unreasonable. The FERC directed Transco to design its WSS-OA rates on a rolled-in basis, to file revised WSS-OA rates reflecting the findings in the order, and to refund the amounts collected in excess of those rates since March 1, 2007. On April 18, 2016, we submitted the compliance filing reflecting rolled-in rates for WSS-OA service consistent with the March 17 order, and began charging those rates beginning April 19, 2016. We also filed a request for rehearing of the March 17 order. On October 4, 2017, the FERC issued an order denying all requests for rehearing of the March 17 order, accepting our April 18, 2016 compliance filing, and directing us to make refunds. As of September 30, 2017, we have accrued a liability for refunds of $19.3 million in Payables - Trade and other in the accompanying

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Condensed Consolidated Balance Sheet. Assuming no further request for rehearing of the order is filed, we expect to issue refunds in the fourth quarter of 2017.

Station 62 Incident

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

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

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

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

Environmental Matters

We have had studies underway for many years to test some of our facilities for the presence of toxic and hazardous substances such as polychlorinated biphenyls (PCBs) and mercury to determine to what extent, if any, remediation may be necessary. We have also similarly evaluated past on-site disposal of hydrocarbons at a number of our facilities. We have worked closely with and responded to data requests from the U.S. Environmental Protection Agency (EPA) and state agencies regarding such potential contamination of certain of our sites. On the basis of the findings to date, we estimate that environmental assessment and remediation costs under various federal and state statutes will total approximately $6 million to $8 million (including both expense and capital expenditures), measured on an undiscounted basis, and will substantially be spent over the next four to six years. This estimate depends on a number of assumptions concerning the scope of remediation that will be required at certain locations and the cost of the remedial measures. We are conducting environmental assessments and implementing a variety of remedial measures that may result in increases or decreases in the total estimated costs. At September 30, 2017, we had a balance of approximately $3.9 million for the expense portion of these estimated costs, $2.1 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, 2016, we had a balance of approximately $4.2 million for the expense portion of these estimated costs, $2.1 million recorded in Accrued liabilities and $2.1 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.

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

In December 2014, the EPA proposed to further reduce the ground-level ozone NAAQS from the March 2008 levels and subsequently finalized a rule on October 1, 2015. We are monitoring the rule's implementation as the reduction will trigger additional federal and state regulatory actions that may impact our operations. As a result, the cost of additions to property, plant and equipment is expected to increase. We are unable at this time to estimate with any certainty the cost of additions that may be required to meet new regulations.

In February 2010, the EPA set a new one-hour nitrogen dioxide (NO2) NAAQS. In January 2012, the EPA determined pursuant to available information that no area in the country is violating the 2010 NO2 NAAQS and thus designated all areas of the country as “unclassifiable/attainment.” However, the EPA or states may require ambient air quality modeling on a case by case basis to demonstrate compliance with the NO2 standard. Because we are unable to predict the outcome of the EPA’s or states’ assessment of NO2 compliance, we are unable to estimate the cost of additions that may be required to meet this regulation.

We consider prudently incurred environmental assessment and remediation costs and the costs associated with compliance with environmental standards to be recoverable through rates. To date, we have been permitted recovery of environmental costs, and it is our intent to continue seeking recovery of such costs through future rate filings. As a result, as estimated costs of environmental assessment and remediation are incurred, they are recorded as regulatory assets in the Condensed Consolidated Balance Sheet until collected through rates. At September 30, 2017, we had a balance of approximately $1.6 million of uncollected environmental related regulatory assets, $1.2 million recorded in Current Assets - Regulatory assets and $0.4 million recorded in Other Assets - Regulatory assets in the accompanying Condensed Consolidated Balance Sheet. At December 31, 2016, we had a balance of approximately $2.5 million of uncollected environmental related regulatory assets, $1.2 million recorded in Current Assets - Regulatory assets and $1.3 million recorded in Other Assets - Regulatory assets in the accompanying Condensed Consolidated Balance Sheet.

Other Matters

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

Summary

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

3. DEBT AND FINANCING ARRANGEMENTS

Credit Facility

We along with WPZ and Northwest Pipeline LLC, are party to a credit agreement with aggregate commitments available of $3.5 billion, with up to an additional $500 million increase in aggregate commitments available under certain circumstances. Total letter of credit capacity available to WPZ under this credit facility is $1.125 billion. We

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are able to borrow up to $500 million under this credit facility to the extent not otherwise utilized by the other co-borrowers. At September 30, 2017, no letters of credit have been issued and no loans were outstanding under the credit facility.

WPZ participates in a commercial paper program, and WPZ management considers amounts outstanding under this program to be a reduction of available capacity under the credit facility. The program allows a maximum outstanding amount at any time of $3 billion of unsecured commercial paper notes. At September 30, 2017, no commercial paper was outstanding under the commercial paper program.

Other Financing Obligation

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

Long-Term Debt Due Within One Year

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

4. ARO TRUST

Available-for-Sale Investments

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

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

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

	September 30, 2017				December 31, 2016
	Amortized Cost Basis		Fair Value		Amortized Cost Basis		Fair Value
Cash and Money Market Funds	$	8.5	$	8.5	$	5.0	$	5.0
U.S. Equity Funds	35.9		47.7		29.4		36.5
International Equity Funds	20.7		23.7		19.2		18.6
Municipal Bond Funds	46.8		47.1		36.7		36.3
Total	$	111.9	$	127.0	$	90.3	$	96.4

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5. FAIR VALUE MEASUREMENTS

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

							Fair Value Measurements Using
	Carrying Amount			Fair Value			Quoted Prices In Active Markets for Identical Assets (Level  1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
	(Millions)
Assets (liabilities) at September 30, 2017:
Measured on a recurring basis:
ARO Trust investments	$	127.0		$	127.0		$	127.0	$	—		$	—
Additional disclosures:
Long-term debt, including current portion	(2,449.0		)	(3,051.1		)	—		(3,051.1		)	—
Assets (liabilities) at December 31, 2016:
Measured on a recurring basis:
ARO Trust investments	$	96.4		$	96.4		$	96.4	$	—		$	—
Additional disclosures:
Long-term debt	(2,210.8		)	(2,507.5		)	—		(2,507.5		)	—

Fair Value of Methods

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

ARO Trust investments — We deposit a portion of our collected rates, pursuant to the terms of the Docket No. RP12-993 rate case settlement, into the ARO Trust which is specifically designated to fund future asset retirement obligations. The ARO Trust invests in a portfolio of actively traded mutual funds that are measured at fair value on a recurring basis based on quoted prices in an active market, are classified as available-for-sale and are reported in Other Assets-Other in the Condensed Consolidated Balance Sheet. However, both realized and unrealized gains and losses are ultimately recorded as regulatory assets or liabilities. See Note 4 for more information regarding the ARO Trust.

Long-term debt — The disclosed fair value of our long-term debt is determined primarily by a market approach using broker quoted indicative period-end bond prices. The quoted prices are based on observable transactions in less active markets for our debt or similar instruments. The fair value of the financing obligation associated with our Dalton lateral, which is included within long-term debt, was determined using an income approach (See Note 3 - 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, 2017 or 2016.

6. TRANSACTIONS WITH AFFILIATES

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

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carrying amounts. Interest income is recognized when chargeable and collectability is reasonably assured. The interest rate on these intercompany demand notes is based upon the daily overnight investment rate paid on WPZ’s excess cash at the end of each month. At September 30, 2017, the interest rate was 0.91 percent.

Included in Operating Revenues in the accompanying Condensed Consolidated Statement of Comprehensive Income are revenues received from affiliates of $2.5 million and $8.9 million for the three and nine months ended September 30, 2017, respectively, and $4.8 million and $8.9 million for the three and nine months ended September 30, 2016, respectively. The rates charged to provide sales and services to affiliates are the same as those that are charged to similarly-situated nonaffiliated customers.

Included in Cost of natural gas sales in the accompanying Condensed Consolidated Statement of Comprehensive Income are cost of gas purchased from affiliates of $1.0 million and $2.9 million for the three and nine months ended September 30, 2017, respectively, and $1.8 million and $3.3 million for the three and nine months ended September 30, 2016, respectively. All gas purchases are made at market or contract prices.

We have no employees. Services necessary to operate our business are provided to us by Williams and certain affiliates of Williams. We reimburse Williams and its affiliates for all direct and indirect expenses incurred or payments made (including salary, bonus, incentive compensation and benefits) in connection with these services. Employees of Williams also provide general, administrative and management services to us, and we are charged for certain administrative expenses incurred by Williams. These charges are either directly identifiable or allocated to our assets. Direct charges are for goods and services provided by Williams at our request. Allocated charges are based on a three-factor formula, which considers revenues; property, plant and equipment; and payroll. In management’s estimation, the allocation methodologies used are reasonable and result in a reasonable allocation to us of our costs of doing business incurred by Williams. We were billed $91.4 million and $261.1 million in the three and nine months ended September 30, 2017, respectively and $78.4 million and $234.7 million in the three and nine months ended September 30, 2016, respectively, for these services. Such expenses are primarily included in Operation and maintenance and Administrative and general expenses in the accompanying Condensed Consolidated Statement of Comprehensive Income. The amount billed to us for the nine months ended September 30, 2016, includes $6.3 million recognized in the first quarter for severance and other related costs associated with a reduction in workforce.

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

We made equity distributions totaling $330.0 million and $350.0 million during the nine months ended September 30, 2017 and 2016, respectively. During October 2017, we made an additional distribution of $100.0 million. Our parent made contributions to us totaling $110.0 million and $372.0 million in the nine months ended September 30, 2017 and 2016, respectively, to fund a portion of our expenditures for additions to property, plant and equipment.

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

7. OTHER

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

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

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

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

RESULTS OF OPERATIONS

Operating Income and Net Income

Operating Income for the nine months ended September 30, 2017 was $476.6 million compared to $449.0 million for the nine months ended September 30, 2016. The increase in Operating Income of $27.6 million (6.1 percent) was primarily due to higher Natural gas transportation and Natural gas storage revenues in the first nine months of 2017 compared to the same period in 2016, partly offset by an increase in Operating Costs and Expenses, as discussed below. Net Income for the nine months ended September 30, 2017 was $440.9 million compared to $384.5 million for the nine months ended September 30, 2016. The increase in Net Income of $56.4 million (14.7 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 $7.4 million (11.0 percent) for the nine months ended September 30, 2017 compared to the same period in 2016. The increase was primarily due to system management gas sales. 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 nine months ended September 30, 2017 increased $74.4 million (7.1 percent) over the same period in 2016. The increase was primarily due to higher transportation reservation revenues related to new incremental projects of $88.4 million (primarily due to $38.3 million from our Gulf Trace project placed in service in February 2017, $28.0 million from our Dalton project placed in partial service in April 2017, and fully in service in August 2017, $11.2 million from our Hillabee project Phase I placed in partial service in June 2017 and fully in service in July 2017 and $8.3 million from our Rock Springs project placed in service in August 2016), partially offset by $6.7 million lower commodity revenues, $3.6 million due to one less billable day in 2017 compared to 2016, and $3.5 million lower firm transportation backhaul revenues.

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

Operating Costs and Expenses

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

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

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

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

• A $3.9 million (8.6 percent) increase in Taxes - other than income taxes primarily due to higher ad valorem taxes as a result of additional assets placed into service.

Other (Income) and Other Expenses

Other (income) and other expenses for the nine months ended September 30, 2017 had a favorable change of $28.8 million (44.7 percent) over the same period in 2016 mostly due to an increase in Allowance for equity and borrowed funds used during construction (AFUDC) associated with capital expenditures on projects.

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Pipeline Expansion Projects

Gulf Trace

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

Hillabee

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

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

In August 2017, the Court of Appeals for the District of Columbia Circuit granted an appeal of the FERC certificate order for the Southeast Market Pipelines projects (which includes a group of related projects, including the Hillabee Expansion Project) filed by certain non-governmental organizations. In doing so, the court (i) remanded the matter to the FERC for preparation of an Environmental Impact Statement that conforms with the court's opinion regarding quantifying certain greenhouse gas emissions, and (ii) vacated the FERC's certificate order for the projects, which would be effective following the court's mandate (by court order, the mandate will not issue until after disposition of all petitions for rehearing). We, along with other intervenors, and the FERC have filed petitions for rehearing with the court to overturn the remedy that would involve vacating the FERC certificate order. If the court's mandate is issued prior to the FERC re-issuing certificate authority for the projects, we believe that the FERC will take the necessary steps (which may include issuing temporary certificate authority) to avoid any lapse in federal authorization for the projects.

Garden State

The Garden State Expansion Project involves an expansion of our existing natural gas transmission system to provide incremental firm transportation capacity from our Station 210 Pooling Point in New Jersey to a new interconnection on our Trenton Woodbury Lateral in Burlington County, New Jersey. The project will be constructed in phases. The FERC certificate for the project and the other regulatory approvals necessary to commence construction of the project have been received. We placed the initial phase of the project into service on September 9, 2017 and plan to place the remaining portion of the project into service during the second quarter of 2018. The project is expected to increase capacity by 180 Mdth/d.

Dalton

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

Atlantic Sunrise

The Atlantic Sunrise Project involves an expansion of our existing natural gas transmission system together with greenfield facilities to provide incremental firm transportation capacity from the northeastern Marcellus producing area to markets along our mainline as far south as our Station 85 Pooling Point in Choctaw County, Alabama. In February 2017, we received approval from the FERC for the project. We placed a portion of the mainline project facilities into service on September 1, 2017, which increased capacity by 400 Mdth/d. We plan to place the full project into service during mid-2018, assuming timely receipt of the remaining regulatory approvals. The full project is expected to increase capacity by 1,700 Mdth/d.

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Virginia Southside II

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

New York Bay Expansion

The New York Bay Expansion Project involves an expansion of our existing natural gas transmission system to provide incremental firm transportation capacity from Station 195 in Pennsylvania to the Rockaway Delivery Lateral transfer point and the Narrows meter station in New York. We placed the project into service on October 6, 2017, and it increased capacity by 115 Mdth/d.

Gulf Connector

The Gulf Connector Expansion Project involves an expansion of our existing natural gas transmission system to provide incremental firm transportation capacity from Station 65 in Louisiana to delivery points in Wharton and San Patricio Counties, Texas. We filed an application with the FERC in August 2016 for approval of the project. The project will be constructed in two phases, and we plan to place both phases into service during the first half of 2019, assuming timely receipt of all necessary regulatory approvals. The project is expected to increase capacity by 475 Mdth/d.

Northeast Supply Enhancement

The Northeast Supply Enhancement Project involves an expansion of our existing natural gas transmission system to provide incremental firm transportation capacity from Station 195 in Pennsylvania to the Rockaway Delivery Lateral transfer point in New York. We filed an application with the FERC in March 2017 for approval of the project. We plan to place the project into service in late 2019 or during the first half of 2020, assuming timely receipt of all necessary regulatory approvals. The project is expected to increase capacity by 400 Mdth/d.

Rivervale South to Market

The Rivervale South to Market Project involves an expansion of our existing natural gas transmission system to provide incremental firm transportation capacity from the existing Rivervale interconnection with Tennessee Gas Pipeline on our North New Jersey Extension to our existing Central Manhattan meter station in New Jersey and our Station 210 Pooling Point in New Jersey. We filed an application with the FERC in August 2017 for approval of the project. We plan to place the project into service as early as the fourth quarter of 2019, assuming timely receipt of all necessary regulatory approvals. The project is expected to increase capacity by 190 Mdth/d.

Gateway

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

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ITEM 4. Controls and Procedures

Our management, including our Senior Vice President and our Vice President, Controller and Chief Accounting Officer, does not expect that our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act) (Disclosure Controls) or our internal control over financial reporting (Internal Controls)will prevent all errors and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within the company have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty, and that breakdowns can occur because of simple error or mistake. Additionally, controls can be circumvented by the individual acts of some persons, by collusion of two or more people, or by management override of the control. The design of any system of controls also is based in part upon certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions. Because of the inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and not be detected. We monitor our Disclosure Controls and Internal Controls and make modifications as necessary; our intent in this regard is that the Disclosure Controls and Internal Controls will be modified as systems change and conditions warrant.

Evaluation of Disclosure Controls and Procedures

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

Changes in Internal Control Over Financial Reporting

There have been no changes during the third quarter of 2017 that have materially affected, or are reasonably likely to materially affect, our Internal Control over Financial Reporting.

PART II — OTHER INFORMATION.

ITEM 1. Legal Proceedings

Environmental

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

Other

The additional information called for by this item is provided in Note 2 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 6. Exhibits

The following instruments are included as exhibits to this report.

Exhibit Number	Description
2	Certificate of Conversion dated December 22, 2008 and effective December 31, 2008 (filed on February 24, 2011 as Exhibit 2.1 to our annual report on Form 10-K (File No. 001-07584) and incorporated herein by reference).
3.1	Certificate of Formation dated December 22, 2008 and effective December 31, 2008 (filed on February 24, 2011 as Exhibit 3.1 to our annual report on Form 10-K (File No. 001-07584) and incorporated herein by reference).
3.2	Amended and Restated Operating Agreement of Transcontinental Gas Pipe Line Company, LLC dated February 17, 2010 (filed on October 28, 2010 as Exhibit 3.2 to our quarterly report on Form 10-Q (File No. 001-07584) and incorporated herein by reference).
31.1*	Certification of Principal Executive Officer pursuant to Rules 13a-14(a) and 15d-14(a) promulgated under the Securities Exchange Act of 1934, as amended, and Item 601(b)(31) of Regulation S-K, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*	Certification of Principal Financial Officer pursuant to Rules 13a-14(a) and 15d-14(a) promulgated under the Securities Exchange Act of 1934, as amended, and Item 601(b)(31) of Regulation S-K, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32**	Certification of Principal Executive Officer and Principal Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS*	XBRL Instance Document.
101.SCH*	XBRL Taxonomy Extension Schema.
101.CAL*	XBRL Taxonomy Extension Calculation Linkbase.
101.DEF*	XBRL Taxonomy Extension Definition Linkbase.
101.LAB*	XBRL Taxonomy Extension Label Linkbase.
101.PRE*	XBRL Taxonomy Extension Presentation Linkbase.

*	Filed herewith.
**	Furnished herewith.

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

EX-31.1

Exhibit 31.1

SECTION 302 CERTIFICATION

I, Frank J. Ferazzi, certify that:

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

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

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

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

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

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

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

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

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

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

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

Date: November 2, 2017

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

EX-31.2

Exhibit 31.2

SECTION 302 CERTIFICATION

I, Ted T. Timmermans, certify that:

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

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

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

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

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

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

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

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

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

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

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

Date: November 2, 2017

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

EX-32

Exhibit 32

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of Transcontinental Gas Pipe Line Company, LLC (the “Company”) on Form 10-Q for the period ending September 30, 2017 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), each of the undersigned hereby certifies, in his capacity as an officer of the Company, pursuant to 18 U.S.C. §1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002, that to his knowledge:

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

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

/s/ Frank J. Ferazzi

Frank J. Ferazzi

Senior Vice President

November 2, 2017

/s/ Ted T. Timmermans

Ted T. Timmermans

Vice President, Controller and Chief Accounting Officer

November 2, 2017

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

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

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Document and Entity Information - shares	9 Months Ended
	Sep. 30, 2017	Nov. 02, 2017
Entity [Abstract]
Entity Registrant Name	Transcontinental Gas Pipe Line Company, LLC
Entity Central Index Key	0000099250
Document Type	10-Q
Document Period End Date	Sep. 30, 2017
Amendment Flag	false
Document Fiscal Year Focus	2017
Document Fiscal Period Focus	Q3
Current Fiscal Year End Date	--12-31
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding		0

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Condensed Consolidated Statement of Comprehensive Income (Unaudited) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Operating Revenues:
Natural gas sales	$ 26,763	$ 31,244	$ 74,867	$ 67,474
Natural gas transportation	389,080	346,004	1,116,891	1,042,547
Natural gas storage	33,954	34,258	102,778	88,315
Other	2,255	1,343	3,734	3,396
Total operating revenues	452,052	412,849	1,298,270	1,201,732
Operating Costs and Expenses:
Cost of natural gas sales	26,763	31,244	74,867	67,474
Cost of natural gas transportation	5,828	4,689	15,282	15,501
Operation and maintenance	113,101	83,916	267,914	225,975
Administrative and general	43,110	40,604	132,020	125,997
Depreciation and amortization	82,826	76,755	239,368	231,110
Taxes - other than income taxes	15,333	14,584	49,131	45,154
Other expense, net	13,475	12,894	43,112	41,541
Total operating costs and expenses	300,436	264,686	821,694	752,752
Operating Income	151,616	148,163	476,576	448,980
Other (Income) and Other Expenses:
Interest expense	41,304	37,318	115,797	113,957
Allowance for equity and borrowed funds used during construction (AFUDC)	(22,334)	(19,922)	(70,783)	(45,656)
Equity in earnings of unconsolidated affiliates	(912)	(1,455)	(3,322)	(4,447)
Miscellaneous other (income) expenses, net	(774)	309	(5,972)	655
Total other (income) and other expenses	17,284	16,250	35,720	64,509
Net Income	134,332	131,913	440,856	384,471
Other comprehensive income (loss):
Equity interest in unrealized gain (loss) on interest rate hedges (includes $38 and $41 for the three months ended and $ 75 and $140 for the nine months ended September 30, 2017 and September 30,2016, respectively, of accumulated other comprehensive income reclassification for equity interest in realized losses on interest rate hedges)	72	156	108	(128)
Comprehensive Income	$ 134,404	$ 132,069	$ 440,964	$ 384,343

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Condensed Consolidated Statement of Comprehensive Income (Unaudited) (Parentheticals) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Accumulated other comprehensive income reclassification for realized losses on interest rate hedges	$ 38	$ 41	$ 75	$ 140

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Condensed Consolidated Balance Sheet (Unaudited) - USD ($) $ in Thousands	Sep. 30, 2017	Dec. 31, 2016
Current Assets:
Cash	$ 0	$ 0
Receivables:
Affiliates	326	489
Advances to affiliate	299,059	811,693
Trade and other	146,471	144,315
Transportation and exchange gas receivables	944	1,827
Inventories	47,685	55,209
Regulatory assets	90,367	87,059
Other	14,179	13,305
Total current assets	599,031	1,113,897
Investments, at cost plus equity in undistributed earnings	39,571	42,403
Property, Plant and Equipment:
Natural gas transmission plant	13,136,224	11,996,454
Less-Accumulated depreciation and amortization	3,833,689	3,687,473
Total property, plant and equipment, net	9,302,535	8,308,981
Other Assets:
Regulatory assets	269,000	264,001
Other	132,052	102,198
Total other assets	401,052	366,199
Total Assets	10,342,189	9,831,480
Payables:
Affiliates	23,483	29,455
Trade and other	305,949	251,872
Transportation and exchange gas payables	3,555	1,571
Accrued liabilities	160,087	197,697
Long-term debt due within one year	251,320	0
Total current liabilities	744,394	480,595
Long-Term Debt	2,197,717	2,210,754
Other Long-Term Liabilities:
Asset retirement obligations	271,211	248,518
Regulatory liabilities	501,201	449,391
Advances for construction costs	261,487	283,028
Transportation prepayments	11,115	11,837
Deferred Revenue	228,258	0
Other	4,573	6,088
Total other long-term liabilities	1,277,845	998,862
Contingent Liabilities and Commitments (Note 2)
Owner's Equity:
Member's capital	3,788,499	3,678,499
Retained earnings	2,333,616	2,462,760
Accumulated other comprehensive income	118	10
Total owner's equity	6,122,233	6,141,269
Total liabilities and owner's equity	$ 10,342,189	$ 9,831,480

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Condensed Consolidated Statement of Cash Flows (Unaudited) - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016
Cash flows from operating activities:
Net income	$ 440,856	$ 384,471
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Depreciation and amortization	239,368	231,110
Allowance for equity funds used during construction (equity AFUDC)	(53,867)	(37,285)
Changes in operating assets and liabilities:
Receivables - affiliates	163	341
Receivables - trade and other	(2,156)	17,045
Transportation and exchange gas receivable	883	(216)
Inventories	7,524	13,617
Payables - affiliates	(5,972)	(23,340)
Payables - trade	(28,536)	6,041
Accrued liabilities	(41,137)	61,484
Asset retirement obligations - non-current	45,629	3,761
Asset retirement obligations - removal costs	(1,708)	(2,688)
Deferred revenue	(2,142)	0
Other, net	(4,691)	23,451
Net cash provided by operating activities	594,214	677,792
Cash flows from financing activities:
Proceeds from long-term debt	0	998,250
Retirements of long-term debt	0	(200,000)
Payments on other financing obligation	(241)	0
Payments for debt issuance costs	(13)	(8,235)
Cash distributions to parent	(330,000)	(350,000)
Cash contributions from parent	110,000	372,000
Net cash provided by financing activities	(220,254)	812,015
Cash flows from investing activities:
Property, plant and equipment additions, net of equity AFUDC	(1,089,917)	(906,105)
Contributions and advances for construction costs	252,249	157,545
Disposal of property, plant and equipment, net	(33,281)	(4,439)
Advances to affiliate, net	512,634	(718,279)
Return of capital from unconsolidated affiliates	2,729	2,106
Purchase of ARO Trust investments	(46,709)	(61,086)
Proceeds from sale of ARO Trust investments	27,520	38,330
Proceeds from insurance	3,200	2,121
Other, net	2,385	0
Net cash used in investing activities	(373,960)	(1,489,807)
Increase (decrease) in cash	0	0
Cash at beginning of period	0	0
Cash at end of period	0	0
Increase to property, plant and equipment, net of equity AFUDC	(1,154,317)	(907,023)
Changes in related accounts payable and accrued liabilities	64,400	918
Property, plant and equipment additions, net of equity AFUDC	$ (1,089,917)	$ (906,105)

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Basis of Presentation (Notes)

9 Months Ended

Sep. 30, 2017

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Basis of Presentation

BASIS OF PRESENTATION

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

Transco is indirectly owned by Williams Partners L.P. (WPZ), a publicly traded Delaware limited partnership, which is consolidated by The Williams Companies, Inc. (Williams). In January 2017, Williams permanently waived the WPZ general partner's incentive distribution rights, converted its 2 percent general partner interest in WPZ to a non-economic interest and purchased additional WPZ common units. At September 30, 2017, Williams owns a 74 percent limited partner interest in WPZ.

General

The condensed consolidated unaudited financial statements include our accounts and the accounts of the subsidiaries we control. Companies in which we and our subsidiaries own 20 percent to 50 percent of the voting common stock or otherwise exercise significant influence over operating and financial policies of the company are accounted for under the equity method. The equity method investments as of September 30, 2017 and December 31, 2016 consist of Cardinal Pipeline Company, LLC (Cardinal) with an ownership interest of approximately 45 percent and Pine Needle LNG Company, LLC (Pine Needle) with an ownership interest of 35 percent. We received distributions associated with our equity method investments totaling $6.3 million and $6.5 million in the nine months ended September 30, 2017 and September 30, 2016, respectively. Included in the distributions are $2.7 million and $2.1 million return of capital in 2017 and 2016, respectively.

The condensed consolidated unaudited financial statements have been prepared from our books and records. Certain information and footnote disclosures normally included in financial statements prepared in accordance with U.S. generally accepted accounting principles (GAAP) have been condensed or omitted in this Form 10-Q pursuant to Securities and Exchange Commission rules and regulations. The condensed consolidated unaudited financial statements include all normal recurring adjustments and others which, in the opinion of our management, are necessary to present fairly our interim financial statements. These condensed consolidated unaudited financial statements should be read in conjunction with the consolidated financial statements and the notes thereto included in our 2016 Annual Report on Form 10-K.

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

Accounting Standards Issued But Not Yet Adopted

In August 2016, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2016-15 “Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments” (ASU 2016-15). ASU 2016-15 provides specific guidance on eight cash flow classification issues, including debt prepayment or debt extinguishment costs and distributions received from equity method investees, to reduce diversity in practice. ASU 2016-15 is effective for interim and annual periods beginning after December 15, 2017. Early adoption is permitted. ASU 2016-15 requires a retrospective transition. We do not expect ASU 2016-15 to have a material impact on our consolidated financial statements.

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

In February 2016, the FASB issued ASU 2016-02 “Leases (Topic 842)” (ASU 2016-02). ASU 2016-02 establishes a comprehensive new lease accounting model. ASU 2016-02 clarifies the definition of a lease, requires a dual approach to lease classification similar to current lease classifications, and causes lessees to recognize leases on the balance sheet as a lease liability with a corresponding right-of-use asset. ASU 2016-02 is effective for interim and annual periods beginning after December 15, 2018. Early adoption is permitted. ASU 2016-02 requires a modified retrospective transition for capital or operating leases existing at or entered into after the beginning of the earliest comparative period presented in the financial statements. We are in the process of reviewing contracts to identify leases, as well as evaluating the applicability of ASU 2016-02 to contracts involving easement/rights-of-way.

In May 2014, the FASB issued ASU 2014-09 establishing Accounting Standards Codification (ASC) Topic 606, “Revenue from Contracts with Customers” (ASC 606). ASC 606 establishes a comprehensive new revenue recognition model designed to depict the transfer of goods or services to a customer in an amount that reflects the consideration the entity expects to be entitled to receive in exchange for those goods or services and requires significantly enhanced revenue disclosures. In August 2015, the FASB issued ASU 2015-14 “Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date” (ASU 2015-14). Per ASU 2015-14, the standard is effective for interim and annual reporting periods beginning after December 15, 2017. ASC 606 allows either full retrospective or modified retrospective transition and early adoption is permitted for annual periods beginning after December 15, 2016.

We continue to evaluate the impact ASC 606 may have on our financial statements. For each revenue contract type, we are conducting a formal contract review process to evaluate the impact, if any, that ASC 606 may have. We continue to evaluate contracts with a significant financing component, which may exist in situations where the timing of the consideration we receive varies significantly from the timing of when we provide the service, as well as a certain contract with prepayments for services. We are unable to determine the potential impact upon the amount and the timing of our revenue recognition. We continue to develop and evaluate disclosures required under the new standard, with a particular focus on the scope of contracts subject to disclosure of remaining performance obligations. Additionally, we have identified possible financial system and internal control changes necessary for adoption. We currently anticipate utilizing a modified retrospective transition upon the adoption of ASC 606 as of January 1, 2018.

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Contingent Liabilities and Commitments (Notes)

9 Months Ended

Sep. 30, 2017

Commitments and Contingencies Disclosure [Abstract]

Contingent Liabilities and Commitments

CONTINGENT LIABILITIES AND COMMITMENTS

Rate Matters

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

The one issue reserved for litigation or further settlement relates to our proposal to change the design of the rates for service under our WSS-OA storage rate schedule, which was implemented subject to refund on March 1, 2007. Following a hearing, the FERC issued an opinion approving our proposed incremental rate design, and subsequently denied requests for rehearing of that approval. On February 21, 2014, the U. S. Court of Appeals for the D.C. Circuit (D.C. Circuit) issued an opinion that vacated and remanded the FERC's order because the FERC did not adequately support its conclusions. On March 17, 2016, the FERC issued an order addressing the issues raised by the D.C. Circuit's opinion. In the March 17 order, the FERC reversed its prior opinion and found that Transco's incremental rate design is unjust and unreasonable. The FERC directed Transco to design its WSS-OA rates on a rolled-in basis, to file revised WSS-OA rates reflecting the findings in the order, and to refund the amounts collected in excess of those rates since March 1, 2007. On April 18, 2016, we submitted the compliance filing reflecting rolled-in rates for WSS-OA service consistent with the March 17 order, and began charging those rates beginning April 19, 2016. We also filed a request for rehearing of the March 17 order. On October 4, 2017, the FERC issued an order denying all requests for rehearing of the March 17 order, accepting our April 18, 2016 compliance filing, and directing us to make refunds. As of September 30, 2017, we have accrued a liability for refunds of $19.3 million in Payables - Trade and other in the accompanying Condensed Consolidated Balance Sheet. Assuming no further request for rehearing of the order is filed, we expect to issue refunds in the fourth quarter of 2017.

Station 62 Incident

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

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

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

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

Environmental Matters

We have had studies underway for many years to test some of our facilities for the presence of toxic and hazardous substances such as polychlorinated biphenyls (PCBs) and mercury to determine to what extent, if any, remediation may be necessary. We have also similarly evaluated past on-site disposal of hydrocarbons at a number of our facilities. We have worked closely with and responded to data requests from the U.S. Environmental Protection Agency (EPA) and state agencies regarding such potential contamination of certain of our sites. On the basis of the findings to date, we estimate that environmental assessment and remediation costs under various federal and state statutes will total approximately $6 million to $8 million (including both expense and capital expenditures), measured on an undiscounted basis, and will substantially be spent over the next four to six years. This estimate depends on a number of assumptions concerning the scope of remediation that will be required at certain locations and the cost of the remedial measures. We are conducting environmental assessments and implementing a variety of remedial measures that may result in increases or decreases in the total estimated costs. At September 30, 2017, we had a balance of approximately $3.9 million for the expense portion of these estimated costs, $2.1 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, 2016, we had a balance of approximately $4.2 million for the expense portion of these estimated costs, $2.1 million recorded in Accrued liabilities and $2.1 million recorded in Other Long-Term Liabilities - Other in the accompanying Condensed Consolidated Balance Sheet.

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

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

In December 2014, the EPA proposed to further reduce the ground-level ozone NAAQS from the March 2008 levels and subsequently finalized a rule on October 1, 2015. We are monitoring the rule's implementation as the reduction will trigger additional federal and state regulatory actions that may impact our operations. As a result, the cost of additions to property, plant and equipment is expected to increase. We are unable at this time to estimate with any certainty the cost of additions that may be required to meet new regulations.

In February 2010, the EPA set a new one-hour nitrogen dioxide (NO2) NAAQS. In January 2012, the EPA determined pursuant to available information that no area in the country is violating the 2010 NO2 NAAQS and thus designated all areas of the country as “unclassifiable/attainment.” However, the EPA or states may require ambient air quality modeling on a case by case basis to demonstrate compliance with the NO2 standard. Because we are unable to predict the outcome of the EPA’s or states’ assessment of NO2 compliance, we are unable to estimate the cost of additions that may be required to meet this regulation.

We consider prudently incurred environmental assessment and remediation costs and the costs associated with compliance with environmental standards to be recoverable through rates. To date, we have been permitted recovery of environmental costs, and it is our intent to continue seeking recovery of such costs through future rate filings. As a result, as estimated costs of environmental assessment and remediation are incurred, they are recorded as regulatory assets in the Condensed Consolidated Balance Sheet until collected through rates. At September 30, 2017, we had a balance of approximately $1.6 million of uncollected environmental related regulatory assets, $1.2 million recorded in Current Assets - Regulatory assets and $0.4 million recorded in Other Assets - Regulatory assets in the accompanying Condensed Consolidated Balance Sheet. At December 31, 2016, we had a balance of approximately $2.5 million of uncollected environmental related regulatory assets, $1.2 million recorded in Current Assets - Regulatory assets and $1.3 million recorded in Other Assets - Regulatory assets in the accompanying Condensed Consolidated Balance Sheet.

Other Matters

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

Summary

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

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Debt and Financing Arrangements (Notes)

9 Months Ended

Sep. 30, 2017

Debt Disclosure [Abstract]

Debt and Financing Arrangements

DEBT AND FINANCING ARRANGEMENTS

Credit Facility

We along with WPZ and Northwest Pipeline LLC, are party to a credit agreement with aggregate commitments available of $3.5 billion, with up to an additional $500 million increase in aggregate commitments available under certain circumstances. Total letter of credit capacity available to WPZ under this credit facility is $1.125 billion. We are able to borrow up to $500 million under this credit facility to the extent not otherwise utilized by the other co-borrowers. At September 30, 2017, no letters of credit have been issued and no loans were outstanding under the credit facility.

WPZ participates in a commercial paper program, and WPZ management considers amounts outstanding under this program to be a reduction of available capacity under the credit facility. The program allows a maximum outstanding amount at any time of $3 billion of unsecured commercial paper notes. At September 30, 2017, no commercial paper was outstanding under the commercial paper program.

Other Financing Obligation

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

Long-Term Debt Due Within One Year

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

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ARO Trust (Notes)

9 Months Ended

Sep. 30, 2017

Investments, Debt and Equity Securities [Abstract]

ARO Trust

ARO TRUST

Available-for-Sale Investments

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

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

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

	September 30, 2017				December 31, 2016
	Amortized Cost Basis		Fair Value		Amortized Cost Basis		Fair Value
Cash and Money Market Funds	$	8.5	$	8.5	$	5.0	$	5.0
U.S. Equity Funds	35.9		47.7		29.4		36.5
International Equity Funds	20.7		23.7		19.2		18.6
Municipal Bond Funds	46.8		47.1		36.7		36.3
Total	$	111.9	$	127.0	$	90.3	$	96.4

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Fair Value Measurements (Notes)

9 Months Ended

Sep. 30, 2017

Fair Value Disclosures [Abstract]

Fair Value Measurements

FAIR VALUE MEASUREMENTS

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

							Fair Value Measurements Using
	Carrying Amount			Fair Value			Quoted Prices In Active Markets for Identical Assets (Level  1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
	(Millions)
Assets (liabilities) at September 30, 2017:
Measured on a recurring basis:
ARO Trust investments	$	127.0		$	127.0		$	127.0	$	—		$	—
Additional disclosures:
Long-term debt, including current portion	(2,449.0		)	(3,051.1		)	—		(3,051.1		)	—
Assets (liabilities) at December 31, 2016:
Measured on a recurring basis:
ARO Trust investments	$	96.4		$	96.4		$	96.4	$	—		$	—
Additional disclosures:
Long-term debt	(2,210.8		)	(2,507.5		)	—		(2,507.5		)	—

Fair Value of Methods

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

ARO Trust investments — We deposit a portion of our collected rates, pursuant to the terms of the Docket No. RP12-993 rate case settlement, into the ARO Trust which is specifically designated to fund future asset retirement obligations. The ARO Trust invests in a portfolio of actively traded mutual funds that are measured at fair value on a recurring basis based on quoted prices in an active market, are classified as available-for-sale and are reported in Other Assets-Other in the Condensed Consolidated Balance Sheet. However, both realized and unrealized gains and losses are ultimately recorded as regulatory assets or liabilities. See Note 4 for more information regarding the ARO Trust.

Long-term debt — The disclosed fair value of our long-term debt is determined primarily by a market approach using broker quoted indicative period-end bond prices. The quoted prices are based on observable transactions in less active markets for our debt or similar instruments. The fair value of the financing obligation associated with our Dalton lateral, which is included within long-term debt, was determined using an income approach (See Note 3 - 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, 2017 or 2016.

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Transactions with Affiliates (Notes)

9 Months Ended

Sep. 30, 2017

Related Party Transactions [Abstract]

Transactions with Affiliates

TRANSACTIONS WITH AFFILIATES

We are a participant in WPZ’s cash management program, and we make advances to and receive advances from WPZ. At September 30, 2017 and December 31, 2016, our advances to WPZ totaled approximately $299.1 million and $811.7 million, respectively. These advances are represented by demand notes and are classified as Receivables - Advances to affiliate in the accompanying Condensed Consolidated Balance Sheet. Advances are stated at the historical carrying amounts. Interest income is recognized when chargeable and collectability is reasonably assured. The interest rate on these intercompany demand notes is based upon the daily overnight investment rate paid on WPZ’s excess cash at the end of each month. At September 30, 2017, the interest rate was 0.91 percent.

Included in Operating Revenues in the accompanying Condensed Consolidated Statement of Comprehensive Income are revenues received from affiliates of $2.5 million and $8.9 million for the three and nine months ended September 30, 2017, respectively, and $4.8 million and $8.9 million for the three and nine months ended September 30, 2016, respectively. The rates charged to provide sales and services to affiliates are the same as those that are charged to similarly-situated nonaffiliated customers.

Included in Cost of natural gas sales in the accompanying Condensed Consolidated Statement of Comprehensive Income are cost of gas purchased from affiliates of $1.0 million and $2.9 million for the three and nine months ended September 30, 2017, respectively, and $1.8 million and $3.3 million for the three and nine months ended September 30, 2016, respectively. All gas purchases are made at market or contract prices.

We have no employees. Services necessary to operate our business are provided to us by Williams and certain affiliates of Williams. We reimburse Williams and its affiliates for all direct and indirect expenses incurred or payments made (including salary, bonus, incentive compensation and benefits) in connection with these services. Employees of Williams also provide general, administrative and management services to us, and we are charged for certain administrative expenses incurred by Williams. These charges are either directly identifiable or allocated to our assets. Direct charges are for goods and services provided by Williams at our request. Allocated charges are based on a three-factor formula, which considers revenues; property, plant and equipment; and payroll. In management’s estimation, the allocation methodologies used are reasonable and result in a reasonable allocation to us of our costs of doing business incurred by Williams. We were billed $91.4 million and $261.1 million in the three and nine months ended September 30, 2017, respectively and $78.4 million and $234.7 million in the three and nine months ended September 30, 2016, respectively, for these services. Such expenses are primarily included in Operation and maintenance and Administrative and general expenses in the accompanying Condensed Consolidated Statement of Comprehensive Income. The amount billed to us for the nine months ended September 30, 2016, includes $6.3 million recognized in the first quarter for severance and other related costs associated with a reduction in workforce.

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

We made equity distributions totaling $330.0 million and $350.0 million during the nine months ended September 30, 2017 and 2016, respectively. During October 2017, we made an additional distribution of $100.0 million. Our parent made contributions to us totaling $110.0 million and $372.0 million in the nine months ended September 30, 2017 and 2016, respectively, to fund a portion of our expenditures for additions to property, plant and equipment.

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

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Other (Notes)

9 Months Ended

Sep. 30, 2017

Other Income and Expenses [Abstract]

Other

OTHER

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

The Advances for construction costs on the accompanying Condensed Consolidated Balance Sheet are associated with advances received from third parties related to construction costs on the Atlantic Sunrise and Dalton projects. This balance increases as we receive additional advances. After construction of the respective projects are completed, the related liabilities will be reclassified to Long-Term Debt and reduced by payments we make to the third parties under terms of the applicable lease agreements. In the third quarter 2017, the advances received from a third party related to construction costs on the Dalton lateral was reclassified to Long-Term Debt on our Condensed Consolidated Balance Sheet.

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ARO Trust (Tables)

9 Months Ended

Sep. 30, 2017

Investments, Debt and Equity Securities [Abstract]

ARO Trust

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

	September 30, 2017				December 31, 2016
	Amortized Cost Basis		Fair Value		Amortized Cost Basis		Fair Value
Cash and Money Market Funds	$	8.5	$	8.5	$	5.0	$	5.0
U.S. Equity Funds	35.9		47.7		29.4		36.5
International Equity Funds	20.7		23.7		19.2		18.6
Municipal Bond Funds	46.8		47.1		36.7		36.3
Total	$	111.9	$	127.0	$	90.3	$	96.4

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Fair Value Measurements (Tables)

9 Months Ended

Sep. 30, 2017

Fair Value Disclosures [Abstract]

Fair Value Measurements

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

							Fair Value Measurements Using
	Carrying Amount			Fair Value			Quoted Prices In Active Markets for Identical Assets (Level  1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
	(Millions)
Assets (liabilities) at September 30, 2017:
Measured on a recurring basis:
ARO Trust investments	$	127.0		$	127.0		$	127.0	$	—		$	—
Additional disclosures:
Long-term debt, including current portion	(2,449.0		)	(3,051.1		)	—		(3,051.1		)	—
Assets (liabilities) at December 31, 2016:
Measured on a recurring basis:
ARO Trust investments	$	96.4		$	96.4		$	96.4	$	—		$	—
Additional disclosures:
Long-term debt	(2,210.8		)	(2,507.5		)	—		(2,507.5		)	—

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Basis of Presentation (Details) - USD ($) $ in Thousands	1 Months Ended	9 Months Ended
	Jan. 31, 2017	Sep. 30, 2017	Sep. 30, 2016	Dec. 31, 2016
Subsidiary of Limited Liability Company or Limited Partnership [Line Items]
Parent, limited partner ownership percentage		74.00%
Schedule of Equity Method Investments [Line Items]
Equity method investment, distributions		$ 6,300	$ 6,500
Equity method investment, return of capital		$ 2,729	$ 2,106
Financial Repositioning [Member]
Subsidiary of Limited Liability Company or Limited Partnership [Line Items]
Parent, general partner ownership percentage	2.00%
Cardinal Pipeline Company, LLC [Member]
Schedule of Equity Method Investments [Line Items]
Equity method investment, ownership percentage		45.00%		45.00%
Pine Needle LNG Company, LLC [Member]
Schedule of Equity Method Investments [Line Items]
Equity method investment, ownership percentage		35.00%		35.00%

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Contingent Liabilities and Commitments (Details) - USD ($) $ in Thousands	1 Months Ended	9 Months Ended
	Jul. 31, 2017	Sep. 30, 2017	Dec. 31, 2016
Site Contingency [Line Items]
Trade and other		$ 305,949	$ 251,872
Regulatory assets, current		90,367	87,059
Regulatory assets, noncurrent		269,000	264,001
Duration Of Period For Deferred Revenue Recognition	25 years
Environmental assessment and remediation [Member]
Site Contingency [Line Items]
Accrued environmental assessment and remediation costs, total		3,900	4,200
Accrued environmental assessment and remediation costs, current		2,100	2,100
Accrued environmental assessment and remediation costs, noncurrent		1,800	2,100
Regulatory assets, total		1,600	2,500
Regulatory assets, current		1,200	1,200
Regulatory assets, noncurrent		400	1,300
Environmental assessment and remediation [Member] | Minimum [Member]
Site Contingency [Line Items]
Environmental assessment and remediation costs, best estimate		$ 6,000
Expected duration of environmental assessment and remediation spending		4 years
Environmental assessment and remediation [Member] | Maximum [Member]
Site Contingency [Line Items]
Environmental assessment and remediation costs, best estimate		$ 8,000
Expected duration of environmental assessment and remediation spending		6 years
Potentially responsible party at various Superfund and state waste disposal sites [Member] | Maximum [Member]
Site Contingency [Line Items]
Environmental assessment and remediation costs, best estimate		$ 500
Potential refund obligation
Site Contingency [Line Items]
Trade and other		$ 19,300
Accrued Liabilities
Site Contingency [Line Items]
Notice of Penalty			$ 1,600

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Debt and Financing Arrangements (Details) $ in Millions	Sep. 30, 2017 USD ($)
Williams Partners L.P. [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	$ 3,500.0
Commercial paper, outstanding	0.0
$3.5 billion credit facility [Member]
Line of Credit Facility [Line Items]
Letters of credit outstanding, amount	0.0
Additional Amount By Which Credit Facility Can Be Increased	500.0
Line of credit facility, amount outstanding	0.0
$3.5 billion credit facility [Member] | Williams Partners L.P. [Member] | Commercial paper [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	3,000.0
$3.5 billion credit facility [Member] | Williams Partners L.P. [Member] | Letter of credit [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	$ 1,125.0

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Debt and Financing Arrangements Long-Term Debt Instruments (Details) - USD ($) $ in Thousands	Sep. 30, 2017	Dec. 31, 2016
Debt Instrument [Line Items]
Long-term debt due within one year	$ 251,320	$ 0
6.05% due 2018 [Member]
Debt Instrument [Line Items]
Long-term debt due within one year	$ 250,000
Long-term debt, Interest Rate	6.05%
Dalton Expansion Project [Member]
Debt Instrument [Line Items]
Long-term debt due within one year	$ 1,500
10% due 2052 [Member]
Debt Instrument [Line Items]
Long-term debt, Interest Rate	10.00%
Other Financing Obligations	$ 235,800

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ARO Trust (Details) - USD ($) $ in Millions	Sep. 30, 2017	Dec. 31, 2016
Investments, Debt and Equity Securities [Abstract]
Annual funding obligation	$ 36.4
Schedule of Available-for-sale Securities [Line Items]
Available-for-sale securities, amortized cost basis	111.9	$ 90.3
Available-for-sale securities, fair value	127.0	96.4
Cash and Money Market Funds [Member]
Schedule of Available-for-sale Securities [Line Items]
Available-for-sale securities, amortized cost basis	8.5	5.0
Available-for-sale securities, fair value	8.5	5.0
U.S. Equity Funds [Member]
Schedule of Available-for-sale Securities [Line Items]
Available-for-sale securities, amortized cost basis	35.9	29.4
Available-for-sale securities, fair value	47.7	36.5
International Equity Funds [Member]
Schedule of Available-for-sale Securities [Line Items]
Available-for-sale securities, amortized cost basis	20.7	19.2
Available-for-sale securities, fair value	23.7	18.6
Municipal Bond Funds [Member]
Schedule of Available-for-sale Securities [Line Items]
Available-for-sale securities, amortized cost basis	46.8	36.7
Available-for-sale securities, fair value	$ 47.1	$ 36.3

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Fair Value Measurements (Details) - USD ($)	Sep. 30, 2017	Dec. 31, 2016	Sep. 30, 2016
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
ARO Trust investments	$ 127,000,000	$ 96,400,000
Fair Value, Transfers Between Level 1 and Level 2, Description and Policy [Abstract]
Fair Value, Assets, Level 1 to Level 2 Transfers, Amount	0		$ 0
Fair Value, Assets, Level 2 to Level 1 Transfers, Amount	0		0
Fair Value, Liabilities, Level 1 to Level 2 Transfers, Amount	0		0
Fair Value, Liabilities, Level 2 to Level 1 Transfers, Amount	0		$ 0
Fair Value, Inputs, Level 1 [Member]
Additional Fair Value Elements [Abstract]
Long-term debt, including current portion	0	0
Fair Value, Inputs, Level 2 [Member]
Additional Fair Value Elements [Abstract]
Long-term debt, including current portion	(3,051,100,000)	(2,507,500,000)
Fair Value, Inputs, Level 3 [Member]
Additional Fair Value Elements [Abstract]
Long-term debt, including current portion	0	0
Reported Value Measurement [Member]
Additional Fair Value Elements [Abstract]
Long-term debt, including current portion	(2,449,000,000)	(2,210,800,000)
Estimate of Fair Value Measurement [Member]
Additional Fair Value Elements [Abstract]
Long-term debt, including current portion	(3,051,100,000)	(2,507,500,000)
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
ARO Trust investments	127,000,000	96,400,000
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
ARO Trust investments	0	0
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
ARO Trust investments	0	0
Fair Value, Measurements, Recurring [Member] | Reported Value Measurement [Member]
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
ARO Trust investments	127,000,000	96,400,000
Fair Value, Measurements, Recurring [Member] | Estimate of Fair Value Measurement [Member]
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
ARO Trust investments	$ 127,000,000	$ 96,400,000

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Transactions with Affiliates (Details) $ in Thousands	1 Months Ended		3 Months Ended		9 Months Ended
	Oct. 31, 2017 USD ($)	Jul. 31, 2017 USD ($)	Sep. 30, 2017 USD ($) employee	Sep. 30, 2016 USD ($)	Sep. 30, 2017 USD ($) employee	Sep. 30, 2016 USD ($)	Dec. 31, 2016 USD ($)
Related Party Transaction [Line Items]
Advances to affiliate			$ 299,059		$ 299,059		$ 811,693
Related party transaction, rate					0.91%
Entity number of employees | employee			0		0
Expenses, related party			$ 91,400	$ 78,400	$ 261,100	$ 234,700
Severance Costs						6,300
Cash distributions to parent					330,000	350,000
Cash contributions from parent					110,000	372,000
Noncash distribution to Parent		$ 240,000
Duration Of Period For Deferred Revenue Recognition		25 years
Affiliated Entity [Member]
Related Party Transaction [Line Items]
Operating revenues, related party			2,500	4,800	8,900	8,900
Cost of natural gas sales, related party			1,000	1,800	2,900	3,300
Expenses, related party			(900)	$ (1,000)	(2,700)	$ (3,400)
Williams Partners L.P. [Member]
Related Party Transaction [Line Items]
Advances to affiliate			$ 299,100		$ 299,100		$ 811,700
Subsequent Event [Member]
Related Party Transaction [Line Items]
Cash distributions to parent	$ 100,000

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Other (Details) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016
Other Income and Expenses [Abstract]
Capitalization of project feasibility costs previously expensed	$ 0.2	$ 1.4