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, 2014

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 or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer ¨ Accelerated filer ¨ Non-accelerated filer þ Smaller reporting company ¨

(Do not check if a smaller reporting company)

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, 2014 and 2013	3
Condensed Consolidated Balance Sheet — September 30, 2014 and December 31, 2013	4
Condensed Consolidated Statement of Cash Flows — Nine Months Ended September 30, 2014 and 2013	6
Notes to Condensed Consolidated Financial Statements	7
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	13
Item 4. Controls and Procedures	16
Part II. Other Information	16
Item 1. Legal Proceedings	16
Item 6. Exhibits	17

Forward Looking Statements

Certain matters contained in this report include “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. 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. We make these forward-looking statements in reliance on the safe harbor protections provided under the Private Securities Litigation Reform Act of 1995.

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 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 statements are based on management’s beliefs and assumptions and on information currently available to management and include, among others, statements regarding:

• Amounts and nature of future capital expenditures;

• Expansion and growth of our business and operations;

• Financial condition and liquidity;

• Business strategy;

• Cash flow from operations or results of operations;

• Rate case filings;

• Natural gas prices, supply and demand; and

• Demand for our services.

Forward-looking statements are based on numerous assumptions, uncertainties, and risks that could cause future events or results to be materially different from those stated or implied in this report. Many of the factors that will

1

determine these results are beyond our ability to control or predict. Specific factors that could cause actual results to differ from results contemplated by the forward-looking statements include, among others, the following:

• Availability of supplies, market demand, and volatility of prices;

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

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

• Whether we are able to successfully identify, evaluate and execute investment opportunities;

• Development of alternative energy sources;

• The impact of operational and development hazards and unforeseen interruptions;

• Costs of, changes in, or the results of laws, government regulations (including safety and environmental regulations), environmental liabilities, litigation, and rate proceedings;

• Our allocated 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;

• 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 the result of any revisions to any of the forward-looking statements to reflect future events or developments.

In addition to causing our actual results to differ, the factors listed above and referred to below may cause our intentions to change from those statements of intention set forth in this report. Such changes in our intentions may also cause our results to differ. We may change our intentions, at any time and without notice, based upon changes in such factors, our assumptions, or otherwise.

Because forward-looking statements involve risks and uncertainties, we caution that there are important factors, in addition to those listed above, that may cause actual results to differ materially from those contained in the forward-looking statements. For a detailed discussion of those factors, see Part I, Item 1A. Risk Factors in our Annual Report on Form 10-K for the year ended December 31, 2013.

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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,
	2014			2013			2014			2013
Operating Revenues:
Natural gas sales	$	33,454		$	27,282		$	79,460		$	87,866
Natural gas transportation	283,404			268,426			867,764			808,002
Natural gas storage	34,557			35,736			105,817			107,243
Other	1,384			811			3,874			3,085
Total operating revenues	352,799			332,255			1,056,915			1,006,196
Operating Costs and Expenses:
Cost of natural gas sales	33,454			27,282			79,460			87,866
Cost of natural gas transportation	5,145			3,056			23,099			22,053
Operation and maintenance	68,457			70,294			192,795			194,008
Administrative and general	42,284			43,747			134,015			135,767
Depreciation and amortization	67,532			66,989			205,143			198,148
Taxes — other than income taxes	11,591			11,318			35,236			33,879
Other expense, net	12,018			12,562			25,424			24,750
Total operating costs and expenses	240,481			235,248			695,172			696,471
Operating Income	112,318			97,007			361,743			309,725
Other (Income) and Other Expenses:
Interest expense	20,954			21,416			64,110			62,716
Allowance for equity and borrowed funds used during construction (AFUDC)	(7,050		)	(5,002		)	(14,423		)	(15,352		)
Equity in earnings of unconsolidated affiliates	(1,472		)	(1,493		)	(4,329		)	(4,234		)
Miscellaneous other (income) expenses, net	(2,856		)	(1,632		)	(3,626		)	(4,747		)
Total other (income) and other expenses	9,576			13,289			41,732			38,383
Net Income	102,742			83,718			320,011			271,342
Other comprehensive income (loss):
Equity interest in unrealized gain (loss) on interest rate hedges (includes $87 and $83 for the three months ended and $257 and $244 for the nine months ended September 30, 2014 and September 30, 2013, respectively, of accumulated other comprehensive income reclassification for realized losses on interest rate hedges)	159			(102		)	156			404
Comprehensive Income	$	102,901		$	83,616		$	320,167		$	271,746

See accompanying notes.

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TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC

CONDENSED CONSOLIDATED BALANCE SHEET

(Thousands of Dollars)

(Unaudited)

	September 30, 2014		December 31, 2013
ASSETS
Current Assets:
Cash	$	109	$	113
Receivables:
Affiliates	2,879		2,601
Advances to affiliate	412,225		526,380
Trade and other	119,799		148,172
Transportation and exchange gas receivables	2,904		6,757
Inventories	72,718		47,532
Regulatory assets	61,310		37,520
Other	20,217		13,451
Total current assets	692,161		782,526
Investments, at cost plus equity in undistributed earnings	48,032		50,262
Property, Plant and Equipment:
Natural gas transmission plant	9,334,231		8,867,626
Less-Accumulated depreciation and amortization	3,231,725		3,090,234
Total property, plant and equipment, net	6,102,506		5,777,392
Other Assets:
Regulatory assets	247,452		256,612
Other	67,405		57,785
Total other assets	314,857		314,397
Total assets	$	7,157,556	$	6,924,577

(continued)

See accompanying notes.

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TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC

CONDENSED CONSOLIDATED BALANCE SHEET

(Thousands of Dollars)

(Unaudited)

	September 30, 2014			December 31, 2013
LIABILITIES AND OWNER’S EQUITY
Current Liabilities:
Payables:
Affiliates	$	27,721		$	28,268
Trade and other	199,488			114,635
Transportation and exchange gas payables	14,192			3,599
Reserve for rate refunds	—			98,217
Accrued liabilities	126,987			153,263
Total current liabilities	368,388			397,982
Long-Term Debt	1,428,459			1,428,355
Other Long-Term Liabilities:
Asset retirement obligations	275,935			238,085
Regulatory liabilities	313,717			269,563
Other	19,605			5,307
Total other long-term liabilities	609,257			512,955
Contingent Liabilities and Commitments (Note 2)
Owner’s Equity:
Member’s capital	2,421,499			2,257,499
Retained earnings	2,330,055			2,328,044
Accumulated other comprehensive loss	(102		)	(258		)
Total owner’s equity	4,751,452			4,585,285
Total liabilities and owner’s equity	$	7,157,556		$	6,924,577

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,
	2014			2013
Cash flows from operating activities:
Net income	$	320,011		$	271,342
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Depreciation and amortization	204,449			197,112
Allowance for equity funds used during construction (equity AFUDC)	(10,748		)	(10,959		)
Changes in operating assets and liabilities:
Receivables — affiliates	(278		)	1,352
— trade and other	28,402			1,448
Transportation and exchange gas receivable	3,853			(2,026		)
Inventories	(25,186		)	295
Payables — affiliates	(547		)	(4,589		)
— trade	19,858			(25,480		)
Accrued liabilities	(8,483		)	23,645
Reserve for rate refunds	(98,217		)	68,407
Asset retirement obligation removal costs	(10,307		)	(24,619		)
Other, net	9,511			66,741
Net cash provided by operating activities	432,318			562,669
Cash flows from financing activities:
Cash distributions to parent	(318,000		)	(186,000		)
Cash contributions from parent	164,000			203,000
Other, net	8,108			9,143
Net cash provided by (used in) financing activities	(145,892		)	26,143
Cash flows from investing activities:
Property, plant and equipment additions, net of equity AFUDC*	(432,167		)	(444,542		)
Contributions and advances for construction costs	39,185			25,977
Disposal of property, plant and equipment, net	(2,939		)	(1,786		)
Advances to affiliate, net	114,155			(158,788		)
Return of capital from unconsolidated affiliates	1,381			916
Purchase of ARO Trust investments	(37,521		)	(44,975		)
Proceeds from sale of ARO Trust investments	29,589			32,968
Other, net	1,887			1,340
Net cash used in investing activities	(286,430		)	(588,890		)
Decrease in cash	(4		)	(78		)
Cash at beginning of period	113			185
Cash at end of period	$	109		$	107
*       Increase to property, plant and equipment	$	(474,716	)	$	(457,104	)
Changes in related accounts payable and accrued liabilities	42,549			12,562
Property, plant and equipment additions, net of equity AFUDC	$	(432,167	)	$	(444,542	)

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 owned, through Williams Partners Operating LLC (WPO), by Williams Partners L.P. (WPZ), a publicly traded Delaware limited partnership, which is consolidated by The Williams Companies, Inc. (Williams). At September 30, 2014, Williams holds an approximate 66 percent interest in WPZ, comprised of an approximate 64 percent limited partner interest and all of WPZ’s 2 percent general partner interest.

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, 2014 and December 31, 2013 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 $6.7 million and $6.6 million in the nine months ended September 30, 2014 and September 30, 2013, respectively. Included in the distributions are $1.4 million and $0.9 million return of capital in 2014 and 2013, 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 SEC 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 2013 Annual Report on Form 10-K.

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

A reclassification within investing activities in the Condensed Consolidated Statement of Cash Flows between Property, plant and equipment additions, net of equity AFUDC* and Contributions and advances for construction costs of $26.0 million for the nine months ended September 30, 2013, has been made to correct the 2013 presentation to conform to the 2014 presentation.

Accounting Standards Issued But Not Yet Adopted.

In May 2014, the Financial Accounting Standards Board issued Accounting Standards Update 2014-09 establishing Accounting Standards Codification 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. The standard is effective for annual reporting periods beginning after December 15, 2016 and interim periods within the reporting period. Accordingly, Transco will adopt this standard in the first quarter 2017. ASC 606 allows either full retrospective or modified retrospective transition and early adoption is not permitted. We are currently evaluating the impact of this new standard on our consolidated financial statements.

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2. CONTINGENT LIABILITIES AND COMMITMENTS.

Rate Matters.

General rate case (Docket No. RP12-993) On August 31, 2012, we submitted to the Federal Energy Regulatory Commission (FERC) a general rate filing principally designed to recover increased costs and to comply with the terms of the settlement in our Docket No. RP06-569 rate proceeding (see below) which required us to file a rate case no later than August 31, 2012. On September 28, 2012, the FERC issued an order accepting our filing subject to the outcome of a hearing. The rates for certain services that were proposed as overall rate decreases became effective October 1, 2012 and the increased rates became effective March 1, 2013. All issues in this proceeding have been resolved by a stipulation and agreement (Agreement) approved by the FERC. Pursuant to its terms, the Agreement became effective on March 1, 2014 and refunds of approximately $118 million were issued on April 18, 2014.

General rate case (Docket No. RP06-569) On August 31, 2006, we submitted to the 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 one of our storage rate schedules, which was implemented subject to refund on March 1, 2007. A hearing on that issue was held before a FERC Administrative Law Judge (ALJ) in July 2008. In November 2008, the ALJ issued an initial decision in which he determined that our proposed incremental rate design is unjust and unreasonable. On January 21, 2010, the FERC reversed the ALJ’s initial decision, and approved our proposed incremental rate design. Certain parties sought rehearing of the FERC’s order and, on April 2, 2012, the FERC denied the rehearing request. On June 1, 2012, one of the parties filed an appeal in the U.S. Court of Appeals for the D.C. Circuit (D.C. Circuit). On February 21, 2014, the D.C. Circuit issued an opinion that vacated and remanded the FERC's order because the FERC did not adequately support its conclusions. On October 16, 2014, the FERC issued an order establishing a "paper hearing" and requesting briefs on certain questions raised by the D.C. Circuit's opinion. The order also provides an opportunity for the parties to discuss settlement, prior to requiring that the briefs be filed. We intend to continue to pursue approval of our proposed rate design. If we are unsuccessful, we believe any refunds would not be material to our results of operations.

Environmental Matters.

We have had studies underway to test some of our facilities for the presence of toxic and hazardous substances to determine to what extent, if any, remediation may be necessary. We have 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 be spent over the next three to five 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, 2014, we had a balance of approximately $2.7 million for the expense portion of these estimated costs recorded in current liabilities ($2.3 million) and other long-term liabilities ($0.4 million) in the accompanying Condensed Consolidated Balance Sheet. At December 31, 2013, we had a balance of approximately $4.1 million for the expense portion of these estimated costs recorded in current liabilities ($2.3 million) and other long-term liabilities ($1.8 million) in the accompanying Condensed Consolidated Balance Sheet.

Although we discontinued the use of lubricating oils containing polychlorinated biphenyls (PCBs) in the 1970s, we have discovered residual PCB contamination in equipment and soils at certain gas compressor station sites. We have worked closely with the EPA and state regulatory authorities regarding PCB issues, and we have a program to assess and remediate such conditions where they exist. In addition, we commenced negotiations with certain environmental authorities and other parties concerning investigative and remedial actions relative to potential mercury contamination at certain gas metering sites. All such costs are included in the $6 million to $8 million range discussed above.

8

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. However, in September 2009, the EPA announced it would reconsider the 2008 NAAQS for ground-level ozone to ensure that the standards were clearly grounded in science, and were protective of both public health and the environment. As a result, the EPA delayed designation of new eight-hour ozone non-attainment areas under the 2008 standards until the reconsideration is complete. In January 2010, the EPA proposed to further reduce the ground-level ozone NAAQS from the March 2008 levels. In September 2011, the EPA announced that it was proceeding with required actions to implement the 2008 ozone standard and area designations. In May 2012, the EPA completed designation of new eight-hour ozone non-attainment areas. Several Transco facilities are located in 2008 ozone non-attainment areas; however, each facility has been previously subjected to federal and/or state emission control requirements implemented to address preceding ozone standards. To date, no new federal actions have been proposed to mandate additional emission controls at these facilities. Pursuant to recently proposed state regulatory actions associated with implementation of the 2008 ozone standard, we anticipate that some Transco 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.

On January 22, 2010, the EPA set a new one-hour nitrogen dioxide (NO2) NAAQS. The effective date of the new NO2 standard was April 12, 2010. On January 20, 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.” Also, at that time, the EPA noted its plan to deploy an expanded NO2 monitoring network beginning in 2013. However, on October 5, 2012, the EPA proposed a graduated implementation of the monitoring network between January 1, 2014 and January 1, 2017. Once three years of data is collected from the new monitoring network, the EPA will reassess attainment status with the one-hour NO2 NAAQS. Until that time, 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’ future assessment using the new monitoring network, 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, 2014, we had a balance of approximately $0.9 million of uncollected environmental related regulatory assets recorded in current assets in the accompanying Condensed Consolidated Balance Sheet. At December 31, 2013, we had a balance of approximately $1.8 million of uncollected environmental related regulatory assets recorded in current assets ($1.2 million) and other assets ($0.6 million) in the accompanying Condensed Consolidated Balance Sheet.

By letter dated September 20, 2007, the EPA required us to provide information regarding natural gas compressor stations in the states of Mississippi and Alabama as part of the EPA’s investigation of our compliance with the Federal Clean Air Act (Act). By January 2008, we responded with the requested information. By Notices of Violation (NOVs) dated March 28, 2008, the EPA found us to be in violation of the requirements of the Act with respect to these compressor stations. We met with the EPA in May 2008 to discuss the allegations contained in the NOVs; in June 2008, we submitted to the EPA a written response denying the allegations. The EPA has requested additional information pertaining to these compressor stations and, in May 2011, we submitted information in response to the EPA’s latest request. In August, 2010, the EPA requested, and we provided, similar information for a compressor station in Maryland. Since 2011, we have not received any additional requests from the EPA for information related to these facilities.

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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 (Northwest) are co-borrowers under a $2.5 billion credit facility. Total letter of credit capacity available to WPZ under the $2.5 billion credit facility is $1.3 billion. We may borrow up to $500 million under the credit facility to the extent not otherwise utilized by WPZ and Northwest. At September 30, 2014, no letters of credit have been issued and no loans are outstanding under our 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 $2 billion of unsecured commercial paper notes. At September 30, 2014, WPZ had $265 million in outstanding commercial paper.

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, the revenues specifically designated for ARO. We established the ARO trust account (ARO Trust) on June 30, 2008. 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, 2014				December 31, 2013
	Amortized Cost Basis		Fair Value		Amortized Cost Basis		Fair Value
Cash and Money Market Funds	$	3.4	$	3.4	$	6.5	$	6.5
U.S. Equity Funds	12.6		15.8		8.0		11.1
International Equity Funds	6.2		6.7		4.2		4.9
Municipal Bond Funds	15.2		15.7		10.2		10.2
Total	$	37.4	$	41.6	$	28.9	$	32.7

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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, 2014:
Measured on a recurring basis:
ARO Trust investments	$	41.6		$	41.6		$	41.6	$	—		$	—
Additional disclosures:
Notes receivable	4.4			4.4			—		4.4			—
Long-term debt	(1,428.5		)	(1,548.5		)	—		(1,548.5		)	—
Assets (liabilities) at December 31, 2013:
Measured on a recurring basis:
ARO Trust investments	$	32.7		$	32.7		$	32.7	$	—		$	—
Additional disclosures:
Notes receivable	6.3			6.3			—		6.3			—
Long-term debt	(1,428.4		)	(1,512.9		)	—		(1,512.9		)	—

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 Agreement in 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.

Notes receivable — The disclosed fair value of our notes receivable is determined by an income approach which considers the underlying contract amounts and our assessment of our ability to recover these amounts. The current portion is reported in Trade and other receivables, and the noncurrent portion is reported in Other Assets-Other in the Condensed Consolidated Balance Sheet.

Long-term debt — The disclosed fair value of our long-term debt is determined 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.

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, 2014 or 2013.

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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, 2014 and December 31, 2013, our advances to WPZ totaled approximately $412.2 million and $526.4 million, respectively. These advances are represented by demand notes and are classified as Current Assets 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, 2014, the interest rate was 0.01 percent.

Included in our Operating Revenues in the accompanying Condensed Consolidated Statement of Comprehensive Income are revenues from affiliates of $3.5 million and $6.3 million for the three and nine months ended September 30, 2014, respectively, and $1.6 million and $14.1 million for the three and nine months ended September 30, 2013, 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 our Cost of natural gas sales in the accompanying Condensed Consolidated Statement of Comprehensive Income are cost of gas purchased from affiliates of $1.3 million and $8.1 million, for the three and nine months ended September 30, 2014, respectively, and $1.7 million and $5.7 million for the three and nine months ended September 30, 2013, 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 $73.9 million and $223.6 million in the three and nine months ended September 30, 2014, respectively, and $79.5 million and $233.0 million in the three and nine months ended September 30, 2013, respectively, for these services. Such expenses are primarily included in Administrative and general and Operation and maintenance expenses in the accompanying Condensed Consolidated Statement of Comprehensive Income.

We provide services to certain of our affiliates. We recorded reductions in operating expenses for services provided to and reimbursed by our affiliates of $1.6 million and $4.8 million for the three and nine months ended September 30, 2014, respectively, and $1.6 million and $5.0 million for the three and nine months ended September 30, 2013, respectively. In the first quarter of 2014, pursuant to construction agreements, we received pre-payments from Williams Field Services Group, LLC of $4.2 million associated with capital projects.

We made equity distributions to WPO totaling $318.0 million and $186.0 million during the nine months ended September 30, 2014 and 2013, respectively. During October 2014, we made an additional distribution to WPO of $93.0 million. WPO made contributions to us totaling $164.0 million and $203.0 million in the nine months ended September 30, 2014 and 2013, respectively, to fund a portion of our expenditures for additions to property, plant and equipment. In October 2014, WPO made an additional $103.0 million contribution to us.

7. OTHER.

For the nine months ended September 30, 2014, we capitalized $3.5 million of project feasibility cost associated with various projects, which had been expensed in prior periods in Other expense, net, upon determining that the projects were probable of development.

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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 2013 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, 2014 was $361.7 million compared to $309.7 million for the nine months ended September 30, 2013. Net income for the nine months ended September 30, 2014 was $320.0 million compared to $271.3 million for the nine months ended September 30, 2013. The increase in Operating income of $52.0 million (16.8 percent) was primarily due to higher Natural gas transportation revenues in the first nine months of 2014 compared to the same period in 2013, partly offset by an increase in Operating Costs and Expenses, as discussed below. The increase in Net income of $48.7 million (18.0 percent) was mostly attributable to the increase in Operating income partly offset by an unfavorable change in net expenses in Other (Income) and Other Expenses, as discussed below.

Sales Revenues.

Operating revenues: Natural gas sales decreased $8.4 million (9.6 percent) for the nine months ended September 30, 2014 compared to the same period in 2013. The decrease was due to lower cash-out sales. Cash-out sales are offset in our cost of natural gas sold and therefore had no impact on our operating income or results of operations.

Transportation Revenues.

Operating revenues: Natural gas transportation for the nine months ended September 30, 2014 increased $59.8 million (7.4 percent) over the same period in 2013. The increase was primarily due to higher transportation reservation revenues related to new incremental projects of $42.8 million ($37.3 million from our Northeast Supply Link project placed in service in August 2013 and $5.5 million from our Mid-South project Phase 2 placed in service in June 2013), higher firm transportation backhaul revenues of $7.5 million and higher commodity revenues of $4.8 million.

Operating Costs and Expenses.

Excluding the Cost of natural gas sales, which is directly offset in revenues, of $79.5 million for the nine months ended September 30, 2014 and $87.9 million for the comparable period in 2013, our operating costs and expenses for the nine months ended September 30, 2014 increased approximately $7.1 million (1.2 percent) from the comparable period in 2013. This increase was primarily attributable to a $7.0 million increase in Depreciation and amortization costs due to expansion projects placed into service in the mid and latter part of 2013.

Other (Income) and Other Expenses.

Other (income) and other expenses for the nine months ended September 30, 2014 had an unfavorable change of $3.3 million (8.6 percent) over the same period in 2013 primarily due to a $1.0 million decrease in AFUDC, $1.1 million lower amount of reimbursements for tax gross-up related to projects and $1.4 million increase in interest expense primarily due to regulatory liabilities and rate refunds.

Filing of Rate Case.

On August 31, 2012, we filed a general rate case with the FERC for an overall increase in rates. In September 2012, the FERC issued an order accepting our filing subject to the outcome of a hearing. The rates for certain services that were proposed as overall rate decreases became effective October 1, 2012, and the increased rates became effective March 1, 2013. All issues in this proceeding have been resolved by the Agreement approved by the FERC. Pursuant to its terms, the Agreement became effective March 1, 2014 and refunds of approximately $118 million were issued on April 18, 2014.

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Capital Expenditures.

Our capital expenditures for the nine months ended September 30, 2014 were $432.2 million, compared to $444.5 million for the nine months ended September 30, 2013. The $12.3 million decrease is primarily due to lower spending on maintenance capital projects in 2014. Our capital expenditures estimate for 2014 and future capital projects are discussed in our 2013 Annual Report on Form 10-K. The following describes those projects and certain new capital projects proposed by us.

Rockaway Delivery Lateral

The Rockaway Delivery Lateral Project involves the construction of a three-mile offshore lateral to National Grid’s distribution system in New York. In May 2014, we received approval from the FERC for the project. We plan to place the project into service during the first quarter of 2015, and the capacity of the lateral is expected to be 647 Mdth/d.

Northeast Connector Project

The Northeast Connector Project involves an expansion of our existing natural gas transmission system from southeastern Pennsylvania to the proposed Rockaway Delivery Lateral. In May 2014, we received approval from the FERC for the project. We plan, subject to FERC approval, to place part of the project into service during the fourth quarter of 2014, which will enable us to begin providing 65 Mdth/d of firm transportation from Station 195 to the Rockaway Delivery Lateral junction. We plan to place the remainder of the project into service during the first quarter of 2015. In total, the project is expected to increase capacity by 100 Mdth/d.

Mobile Bay South III

The Mobile Bay South III Project involves an expansion of the Mobile Bay line south from Station 85 in west central Alabama to delivery points along the line. In April 2014, we received approval from the FERC for the project. We plan to place the project into service during the second quarter of 2015, and it is expected to increase capacity on the line by 225 Mdth/d.

Virginia Southside

The Virginia Southside Project involves an expansion of our existing mainline natural gas transmission system together with a new lateral to provide firm transportation capacity from the Zone 6 Station 210 Pooling Point in New Jersey to Dominion Virginia Power’s proposed power station in Brunswick County, Virginia, and to both our Cascade Creek interconnection with East Tennessee Natural Gas and our Pleasant Hill delivery point to Piedmont Natural Gas Company, Inc. in North Carolina. In November 2013, we received approval from the FERC for the project. We plan, subject to FERC approval, to place part of the project into service during the fourth quarter of 2014, which will enable us to begin providing 250 Mdth/d of firm transportation capacity through the mainline portion of the project on an interim basis, until the in-service date of the project as a whole. We plan to place the remainder of the project into service during the third quarter of 2015 (the original target in-service date for the project). In total, the project is expected to increase capacity by 270 Mdth/d.

Leidy Southeast

The Leidy Southeast Project involves an expansion of our existing natural gas transmission system from the Marcellus Shale production region on the Leidy Line in Pennsylvania to the Station 85 Pooling Point in Choctaw County, Alabama. We filed an application with the FERC in September 2013 for approval of the project. We plan to place the project into service during the fourth quarter of 2015, assuming timely receipt of all necessary regulatory approvals, and it is expected to increase capacity by 525 Mdth/d.

Rock Springs Expansion

The Rock Springs Expansion Project involves an expansion of our existing natural gas transmission system southbound from the Zone 6 Station 210 Pooling Point in New Jersey along with a new, eleven-mile lateral to Old Dominion Electric Cooperative's proposed Wildcat Point generation facility in Cecil County, Maryland. We filed an application with the FERC in June 2014 for approval of the project. We plan to place the project into service during the third quarter of 2016, assuming timely receipt of all necessary regulatory approvals, and it is expected to increase capacity by 192 Mdth/d.

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Hillabee Expansion

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 proposed new interconnection with Sabal Trail Transmission's system in Tallapoosa County, Alabama. The project will be constructed in phases and all of the project expansion capacity will be leased to Sabal Trail Transmission. We plan to file an application with the FERC in the fourth quarter of 2014 for approval of the initial phases of the project. We plan to place the initial phases of the project into service during the second quarter of 2017 and 2020, assuming timely receipt of all necessary regulatory approvals, and together they are expected to increase capacity by 1,025 Mdth/d.

Gulf Trace Expansion

The Gulf Trace Expansion Project involves an expansion of our existing natural gas transmission system together with greenfield facilities to provide firm transportation from Station 65 in St. Helena Parish, Louisiana westward to a new interconnection with Sabine Pass Liquefaction in Cameron Parish, Louisiana. We plan to file an application with the FERC in the fourth quarter of 2014 for approval of the project. We plan to place the project into service during the first half of 2017, assuming timely receipt of all necessary regulatory approvals, and it is expected to increase capacity by 1,200 Mdth/d.

Dalton Expansion

The Dalton Expansion Project involves an expansion of our existing natural gas transmission system together with greenfield facilities to provide firm transportation from the Zone 6 Station 210 Pooling Point in New Jersey to markets in northwest Georgia. We plan to file an application with the FERC in the first quarter of 2015 for approval of the project. We plan to place the project into service in 2017, assuming timely receipt of all necessary regulatory approvals, and it is expected to increase capacity by 448 Mdth/d.

Atlantic Sunrise Project

The Atlantic Sunrise Project involves an expansion of our existing natural gas transmission system together with greenfield facilities to provide firm transportation from the northeastern Marcellus producing area to markets along our mainline as far south as Station 85 in Alabama. We plan to file an application with the FERC in the second quarter of 2015 for approval of the project. We plan to place the project into service during the second half of 2017, assuming timely receipt of all necessary regulatory approvals, and it is expected to increase capacity by 1,700 Mdth/d.

Garden State Expansion

The Garden State Expansion Project involves an expansion of our existing natural gas transmission system to provide firm transportation from our Zone 6 Station 210 Pooling Point in New Jersey to a new interconnection on Transco's Trenton Woodbury Lateral in Burlington County, New Jersey. The project will be constructed in phases. We plan to file an application with the FERC in the first quarter of 2015 for approval of the project. We plan to place the initial phase of the project into service during the fourth quarter of 2016 and the remaining portion in the third quarter of 2017, assuming timely receipt of all necessary regulatory approvals. The project is expected to increase capacity by 180 Mdth/d.

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ITEM 4. Controls and Procedures.

Our management, including our Senior Vice President — Atlantic-Gulf and our Vice President and Chief Accounting Officer, does not expect that our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act) (Disclosure Controls) or our internal controls 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 — Atlantic-Gulf and our Vice President and Chief Accounting Officer. Based upon that evaluation, our Senior Vice President — Atlantic-Gulf and our Vice President and Chief Accounting Officer concluded that these Disclosure Controls are effective at a reasonable assurance level.

Changes in Internal Controls Over Financial Reporting

There have been no changes during the third quarter of 2014 that have materially affected, or are reasonably likely to materially affect, our Internal Controls over financial reporting.

PART II — OTHER INFORMATION.

ITEM 1. Legal Proceedings.

The 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 report Form 10-K 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 report Form 10-K 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 Form 10-Q 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.

17

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:	October 30, 2014	By:	/s/ Jeffrey P. Heinrichs
			Jeffrey P. Heinrichs
			Controller (Principal Accounting Officer)

EXHIBIT INDEX.

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 Form 10-K 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 Form 10-K 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 Form 10-Q 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.