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

TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC - FORM 10-Q - October 31, 2012

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EXCEL - IDEA: XBRL DOCUMENT - TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC	Financial_Report.xls
EX-32 - EX-32 - TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC	d430135dex32.htm
EX-31.1 - EX-31.1 - TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC	d430135dex311.htm
EX-31.2 - EX-31.2 - TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC	d430135dex312.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended September 30, 2012

¨	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 x 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 x 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):

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

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, 2012 and 2011		3
Condensed Consolidated Balance Sheet — September 30, 2012 and December 31, 2011		4
Condensed Consolidated Statement of Cash Flows — Nine Months Ended September 30, 2012 and 2011		6
Notes to Condensed Consolidated Financial Statements		7
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		14
Item 4. Controls and Procedures		17
Part II. Other Information		17
Item 1. Legal Proceedings		17
Item 6. Exhibits		18

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; and

•

Natural gas prices and demand.

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 the forward-looking statements include, among others, the following:

•

Availability of supplies, market demand, volatility of prices, and the availability and cost of capital;

•

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;

•

Development of alternative energy sources;

•

The impact of operational and development hazards;

•

Costs of, changes in, or the results of laws, government regulations (including safety and climate change regulation and changes in natural gas production from exploration and production areas that we serve), 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 strategy and financing, including restrictions stemming from our debt agreements, future changes in our credit ratings, and the availability and cost of credit;

•

Risks associated with future weather 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, 2011.

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,
	2012			2011			2012			2011
Operating Revenues:
Natural gas sales	$	15,828		$	36,368		$	36,691		$	89,649
Natural gas transportation		251,691			248,322			761,659			726,767
Natural gas storage		34,714			35,392			105,171			107,255
Other		724			1,612			3,079			4,230

Total operating revenues		302,957			321,694			906,600			927,901


Operating Costs and Expenses:
Cost of natural gas sales		15,828			36,368			36,691			89,649
Cost of natural gas transportation		8,104			9,349			27,264			27,695
Operation and maintenance		78,480			68,988			214,068			201,465
Administrative and general		42,443			34,900			131,225			113,527
Depreciation and amortization		66,693			66,300			199,068			196,556
Taxes - other than income taxes		12,644			11,930			39,110			37,328
Other (income) expense, net		7,753			4,600			31,214			(1,500	)

Total operating costs and expenses		231,945			232,435			678,640			664,720


Operating Income		71,012			89,259			227,960			263,181


Other (Income) and Other Deductions:
Interest expense		21,132			23,887			68,518			71,582
Interest income - affiliates		(9	)		(6	)		(24	)		(22	)
Allowance for equity and borrowed funds used during construction (AFUDC)		(5,886	)		(3,118	)		(14,468	)		(12,513	)
Equity in earnings of unconsolidated affiliates		(2,127	)		(1,355	)		(5,395	)		(3,768	)
Miscellaneous other (income) deductions, net		(2,060	)		777			(4,097	)		1,678

Total other (income) and other deductions		11,050			20,185			44,534			56,957


Net Income		59,962			69,074			183,426			206,224

Equity interest in unrealized gain (loss) on interest rate hedge		(283	)		(316	)		(441	)		(556	)


Comprehensive Income	$	59,679		$	68,758		$	182,985		$	205,668

See accompanying notes.

TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC

CONDENSED CONSOLIDATED BALANCE SHEET

(Thousands of Dollars)

(Unaudited)


	September 30, 2012		December 31, 2011
ASSETS

Current Assets:
Cash	$	100	$	164
Receivables:
Affiliates		2,533		5,903
Advances to affiliates		317,797		253,611
Others, less allowance of $0 ($407 in 2011)		108,496		121,589
Transportation and exchange gas receivables		3,892		4,914
Inventories		45,392		35,608
Regulatory assets		36,006		37,877
Other		18,095		12,973

Total current assets		532,311		472,639


Investments, at cost plus equity in undistributed earnings		54,458		56,994


Property, Plant and Equipment:
Natural gas transmission plant		8,376,177		8,089,338
Less-Accumulated depreciation and amortization		2,909,588		2,801,104

Total property, plant and equipment, net		5,466,589		5,288,234


Other Assets:
Regulatory assets		212,080		207,945
Other		48,507		50,471

Total other assets		260,587		258,416


Total assets	$	6,313,945	$	6,076,283

(continued)

See accompanying notes.

TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC

CONDENSED CONSOLIDATED BALANCE SHEET

(Thousands of Dollars)

(Unaudited)


	September 30, 2012			December 31, 2011
LIABILITIES AND OWNER’S EQUITY

Current Liabilities:
Payables:
Affiliates	$	30,015		$	16,937
Other		110,278			108,706
Transportation and exchange gas payables		1,753			2,784
Accrued liabilities		130,966			140,390
Current maturities of long-term debt		—			324,321

Total current liabilities		273,012			593,138


Long-Term Debt		1,428,290			1,029,397


Other Long-Term Liabilities:
Asset retirement obligations		260,261			245,365
Regulatory liabilities		223,015			182,848
Other		6,288			6,182

Total other long-term liabilities		489,564			434,395


Contingent liabilities and commitments (Note 2)

Owner’s Equity:
Member’s capital		1,958,888			1,841,888
Retained earnings		2,164,978			2,177,811
Accumulated other comprehensive loss		(787	)		(346	)

Total owner’s equity		4,123,079			4,019,353


Total liabilities and owner’s equity	$	6,313,945		$	6,076,283

See accompanying notes.

TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC

CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS

(Thousands of Dollars)

(Unaudited)


	Nine months ended September 30,
	2012			2011
Cash flows from operating activities:
Net income	$	183,426		$	206,224
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Depreciation and amortization		199,451			196,834
Allowance for equity funds used during construction (Equity AFUDC)		(9,935	)		(8,643	)
Changes in operating assets and liabilities:
Receivables - affiliates		3,370			(529	)
- others		13,093			3,677
Inventories		1,199			29,531
Payables - affiliates		13,078			9,763
- others		(14,067	)		13,816
Accrued liabilities		(1,930	)		27,413
Asset retirement obligation removal costs		(30,646	)		(34,508	)
Other, net		26,744			(4,399	)

Net cash provided by operating activities		383,783			439,179


Cash flows from financing activities:
Additions to long-term debt		398,804			372,518
Retirement of long-term debt		(325,000	)		(300,000	)
Debt issue costs		(4,304	)		(3,811	)
Cash distributions to parent		(196,259	)		(152,000	)
Cash contributions from parent		117,000			100,000
Other, net		(4,507	)		(7,671	)

Net cash provided by (used in) financing activities		(14,266	)		9,036


Cash flows from investing activities:
Property, plant and equipment additions, net of equity AFUDC*		(326,998	)		(267,522	)
Disposal of property, plant and equipment, net		9,920			(639	)
Advances to affiliates, net		(64,186	)		(172,910	)
Return of capital from unconsolidated affiliates		11,327			1,925
Contributions to unconsolidated affiliates		(5,806	)		(13,120	)
Purchase of ARO Trust investments		(27,134	)		(36,577	)
Proceeds from sale of ARO Trust investments		32,471			47,901
Other, net		825			(7,301	)

Net cash used in investing activities		(369,581	)		(448,243	)


Increase (decrease) in cash		(64	)		(28	)
Cash at beginning of period		164			148

Cash at end of period	$	100		$	120


* Increase to property, plant and equipment	$	(327,634	)	$	(272,116	)
Changes in related accounts payable and accrued liabilities		636			4,594

Property, plant and equipment additions, net of equity AFUDC	$	(326,998	)	$	(267,522	)

See accompanying notes.

TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1. BASIS OF PRESENTATION.

In this report, Transco (which includes Transcontinental Gas Pipe Line Company, LLC and unless the context otherwise requires, the subsidiaries that we control) 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, 2012, 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, 2012 and December 31, 2011 consist of Cardinal Pipeline Company, LLC (Cardinal) with ownership interest of approximately 45 percent and Pine Needle LNG Company, LLC (Pine Needle) with ownership interest of 35 percent. We received distributions associated with our equity method investments totaling $13.3 million and $5.1 million in the nine months ended September 30, 2012 and September 30, 2011, respectively. Included in the distributions are $11.3 million return of capital from Cardinal in 2012 and $1.9 million return of capital from Pine Needle in 2011. We made capital contributions to Cardinal related to Cardinal’s expansion project totaling $5.8 million and $13.1 million in the nine months ended September 30, 2012 and September 30, 2011, 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 2011 Annual Report on Form 10-K.

Through an agency agreement, WPX Energy Marketing, LLC (WPXEM), our affiliate until December 31, 2011, managed our long-term purchase agreements and our remaining jurisdictional merchant gas sales, which excludes our cash out sales in settlement of gas imbalances. On December 31, 2011, Williams completed the spin-off of its former exploration and production business, WPX Energy, Inc. (WPX). Subsequent to the spin-off, WPX managed our merchant function until May 1, 2012. Beginning May 1, 2012, our merchant function has been managed by Williams Energy Resources, LLC (WER), our affiliate. The long-term purchase agreements managed by WER remain in our name, as do the corresponding sales of such purchased gas. Therefore, we continue to record natural gas sales revenues and the related accounts receivable and cost of natural gas sales and the related accounts payable for the jurisdictional merchant sales managed by WER. WER receives all margins associated with our jurisdictional merchant gas sales business and assumes all market and credit risk associated with our jurisdictional merchant gas sales. Consequently, our merchant gas sales service has no impact on our operating income or results of operations.

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.

Certain reclassifications from Administrative and general to Operation and maintenance, related to certain employee related expenses of $2.4 million and $7.0 million for the three and nine months ended September 30, 2011, respectively, have been made to conform to the presentation utilized in the 2012 Condensed Consolidated Statement of Comprehensive Income.

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) to file a rate case no later than August 31, 2012. On September 28, 2012, the FERC issued an order accepting and suspending our filing to be effective March 1, 2013, subject to refund and the outcome of a hearing, except that rates for certain services that were proposed as overall rate decreases, were accepted, without suspension, to be effective October 1, 2012. These decreased rates will not be subject to refund, but may be subject to decrease prospectively under the Natural Gas Act of 1938, Section 5.

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). If the D.C. Circuit were to overturn the FERC’s order, 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 $7 million to $9 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, 2012, we had a balance of approximately $2.7 million for the expense portion of these estimated costs recorded in current liabilities ($0.8 million) and other long-term liabilities ($1.9 million) in the accompanying Condensed Consolidated Balance Sheet. At December 31, 2011, we had a balance of approximately $3.5 million for the expense portion of these estimated costs recorded in current liabilities ($0.8 million) and other long-term liabilities ($2.7 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 $7 million to $9 million range discussed above.

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 $7 million to $9 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 or state actions have been proposed to mandate additional emission controls at these facilities. At this time, it is unknown whether future federal or state regulatory actions associated with implementation of the 2008 ozone standard will impact our operations and increase the cost of additions to property, plant and equipment. Until any additional federal or state regulatory actions are proposed, we are unable to estimate the cost of additions that may be required to meet this new regulation.

Additionally, in August 2010, the EPA promulgated National Emission Standards for Hazardous Air Pollutants (NESHAP) regulations that will impact our operations. The emission control additions required to comply with the hazardous air pollutant regulations are estimated to include capital costs in the range of $18 million to $23 million through 2013, the compliance date.

In February 2010, the EPA promulgated a final rule establishing a new one-hour nitrogen dioxide (NO₂) NAAQS. In February 2012, the EPA designated all areas of the country as “unclassifiable/attainment”, meaning that information available at that time did not indicate that air quality in these areas exceeded the NAAQS. Also, at that time, the EPA noted its plan to deploy an expanded NO₂ monitoring network beginning in 2013. 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.

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. However, we had no uncollected environmental related regulatory assets at September 30, 2012 or December 31, 2011.

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.

Safety Matters.

Pipeline Integrity Regulations We have developed an Integrity Management Plan that we believe meets the United States Department of Transportation Pipeline and Hazardous Materials Safety Administration (PHMSA) final rule that was issued pursuant to the requirements of the Pipeline Safety Improvement Act of 2002. The rule requires gas pipeline operators to develop an integrity management program for transmission pipelines that could affect high consequence areas in the event of pipeline failure. The Integrity Management Program includes a baseline assessment plan to be completed in 2012 along with periodic reassessments to be completed within required timeframes. In meeting the integrity regulations, we have identified high consequence areas and developed our baseline assessment plan. We are on schedule to complete the required assessments within the required timeframes.

Currently, we estimate that the cost to complete the required initial assessments and associated remediation through 2012 will be primarily capital in nature and range between $12 million and $16 million. Ongoing periodic reassessments and new initial assessments of any new high consequence areas will be completed within the timeframes required by the rule. Management considers the costs associated with compliance with the rule to be prudent costs incurred in the ordinary course of business and, therefore, recoverable through our rates.

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.

Other Commitments.

Commitments for construction We have commitments for construction and acquisition of property, plant and equipment of approximately $267.0 million at September 30, 2012.

3. DEBT AND FINANCING ARRANGEMENTS.

Credit Facility.

In September 2012, WPZ amended its existing $2 billion senior unsecured revolving credit facility agreement to increase its aggregate commitments by $400 million. This facility was also amended to provide an additional $400 million increase to be available under certain conditions in the future. We may borrow up to $400 million under the credit facility to the extent not otherwise utilized by WPZ and Northwest Pipeline GP.

Letter of credit capacity under the $2.4 billion credit facility is $1.3 billion. At September 30, 2012, no letters of credit have been issued and no loans are outstanding under the credit facility. At September 30, 2012, the full $400 million under the credit facility was available to us.

Issuance and Retirement of Long-Term Debt.

In August 2011, we issued $375 million of 5.4 percent senior unsecured notes due 2041 to investors in a private debt placement. As part of the new issuance, we entered into a registration rights agreement with the initial purchasers of the notes. An offer to exchange these unregistered notes for substantially identical new notes that are

registered under the Securities Act of 1933, as amended, was commenced in February 2012 and completed in March 2012.

On July 13, 2012, we issued $400 million aggregate principal amount of 4.45 percent senior unsecured notes due 2042 (4.45 percent Notes) to certain institutional investors pursuant to certain exemptions from registration under the Securities Act of 1933, as amended. Interest is payable on February 1 and August 1 of each year, beginning February 1, 2013. A portion of these proceeds was used to repay our $325 million 8.875 percent notes (8.875 percent Notes) that matured on July 15, 2012. We will use the remainder for general corporate purposes, including the funding of capital expenditures.

As part of the new issuance, we entered into a registration rights agreement with the initial purchasers of the 4.45 percent Notes. We are obligated to file a registration statement for an offer to exchange the notes for a new issue of substantially identical notes registered under the Securities Act of 1933, as amended, within 180 days from closing and to use our commercially reasonable efforts to cause the registration statement to be declared effective within 270 days after closing and to consummate the exchange offer within 30 business days after such effective date. We are required to provide a shelf registration statement to cover resales of the notes under certain circumstances. If we fail to fulfill these obligations, additional interest will accrue on the affected securities. The rate of additional interest will be 0.25 percent per annum on the principal amount of the affected securities for the first 90-day period immediately following the occurrence of default, increasing by an additional 0.25 percent per annum with respect to each subsequent 90-day period thereafter, up to a maximum amount for all such defaults of 0.5 percent annually. Following the cure of any registration defaults, the accrual of additional interest will cease.

4. INVESTMENTS.

Available-for-Sale Investments.

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


	September 30, 2012				December 31, 2011
	Amortized Cost Basis		Fair Value		Amortized Cost Basis		Fair Value
Money Market Funds	$	0.5	$	0.5	$	1.4	$	1.4
U.S. Equity Funds		6.4		9.0		7.1		9.5
International Equity Funds		4.1		4.4		5.4		5.3
Municipal Bond Funds		6.7		7.2		7.9		8.3

Total	$	17.7	$	21.1	$	21.8	$	24.5

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.

5. FAIR VALUE MEASUREMENTS.

The following table presents, by level within the fair value hierarchy, certain of our financial assets and liabilities.


							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, 2012:
Measured on a recurring basis:
ARO Trust investments	$	21.1		$	21.1		$	21.1	$	—		$	—

Additional disclosures:
Notes receivable		8.7			8.7			—		8.7			—
Long-term debt		(1,428.3	)		(1,687.9	)		—		(1,687.9	)		—

Assets (liabilities) at December 31, 2011:
Measured on a recurring basis:
ARO Trust investments	$	24.5		$	24.5		$	24.5	$	—		$	—

Additional disclosures:
Notes receivable		9.5			9.5			N/A		N/A			N/A
Long-term debt, including current portion		(1,353.7	)		(1,539.2	)		N/A		N/A			N/A

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:

Cash and short-term financial assets (advances to affiliates) that have variable interest rates - The carrying amount is a reasonable estimate of fair value due to the short maturity of those instruments.

ARO Trust investments - We deposit a portion of our collected rates, pursuant to our 2008 rate case settlement, into an external trust (ARO Trust) that 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 net asset values, 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 carrying value of our notes receivable are considered to approximate the fair value generally due to the nature of the related interest rates and our assessment of our ability to recover these amounts using an income approach.

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, 2012 or 2011.

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, 2012 and December 31, 2011, the advances due us by WPZ totaled approximately $317.8 million and $253.6 million, respectively. These advances are represented by demand notes. 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, 2012, the interest rate was 0.01 percent.

Included in our operating revenues for the nine months ending September 30, 2012 and 2011 are revenues received from affiliates of $8.6 million and $17.9 million, 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 sales for the nine months ended September 30, 2012 and 2011 is purchased gas cost from affiliates of $3.2 million and $6.1 million, respectively. All gas purchases are made at market or contract prices.

Williams has a policy of charging its subsidiary companies for management services provided by the parent company and other affiliated companies. Included in our administrative and general expenses for the nine months ended September 30, 2012 and 2011, are $54.9 million and $40.2 million, respectively, for such corporate expenses charged by Williams, WPZ, and other affiliated companies.

Pursuant to an operating agreement, we serve as contract operator on certain Williams Field Services Company (WFS) facilities. Transco recorded reductions in operating expenses for services provided to and reimbursed by WFS of $2.7 million and $3.7 million for the nine months ended September 30, 2012 and 2011, respectively, under terms of the operating agreement.

We made equity distributions to WPO totaling $196.3 million and $152.0 million during the nine months ended September 30, 2012 and 2011, respectively. During October 2012, we made an additional distribution of $50.0 million. In the nine months ended September 30, 2012 and 2011, respectively, WPO made contributions totaling $117.0 million and $100.0 million to us to fund a portion of our expenditures for additions to property, plant and equipment. In October 2012, WPO made an additional $33.0 million contribution.

We have no employees. Services are provided to us by an affiliate, Transco Pipeline Services LLC (TPS), a Delaware limited liability company. Pursuant to an administrative services agreement, TPS provides personnel, facilities, goods and equipment not otherwise provided by us that are necessary to operate our business. In return, we reimburse TPS for all direct and indirect expenses it incurs or payments it makes (including salary, incentive compensation and benefits) in connection with these services. We were billed $155.0 million and $142.7 million in the nine months ended September 30, 2012 and 2011, respectively, for these services. Such expenses are primarily included in Administrative and general and Operation and maintenance expenses on the accompanying Condensed Consolidated Statement of Comprehensive Income.

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 2011 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, 2012 was $228.0 million compared to $263.2 million for the nine months ended September 30, 2011. Net income for the nine months ended September 30, 2012 was $183.4 million compared to $206.2 million for the nine months ended September 30, 2011. The decrease in Operating income of $35.2 million (13.4 percent) was primarily due to an increase in Operating Costs and Expenses, partially offset by higher Natural gas transportation revenues in 2012 compared to 2011, as discussed below. The decrease in Net income of $22.8 million (11.1 percent) was mostly attributable to the decrease in Operating income, partially offset by a favorable change in net deductions in Other (Income) and Other Deductions, as discussed below.

Transportation Revenues.

Operating revenues: Natural gas transportation for the nine months ended September 30, 2012 increased $34.9 million (4.8 percent) over the same period in 2011. The increase was primarily due to higher transportation reservation revenues of $31.4 million, ($15.5 million from our 85 North Phase II project placed in service in May 2011, $10.0 million from the Pascagoula project placed in service in September 2011, $4.2 million from the Mobile Bay South Phase II project placed in service in May 2011, and $1.7 million from the Mid-South project place in service in September 2012), $2.3 million higher revenues due to one more billable day in 2012 because of leap year, and $2.0 million higher revenues from firm backhaul transportation in 2012.

Sales Revenues.

Operating revenues: Natural gas sales decreased $52.9 million (59.0 percent) for the nine months ended September 30, 2012 compared to the same period in 2011. The decrease was primarily due to lower system management gas sales of $30.8 million, the absence of Hester base gas sales of $4.4 million, recorded in 2011, and lower cash-out sales of $17.5 million. System management gas sales and 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.

Operating Costs and Expenses.

Excluding the Cost of natural gas sales, which is directly offset in revenues, of $36.7 million for the nine months ended September 30, 2012 and $89.6 million for the comparable period in 2011, our operating costs and expenses for the nine months ended September 30, 2012 increased approximately $66.8 million (11.6 percent) over the comparable period in 2011. This increase was primarily attributable to:

•

A $32.7 million unfavorable change in Other (income) expense, net primarily due to the absence of $10.1 million recorded in 2011 for the reversal of project feasibility costs from expense to capital associated with the Northeast Supply Link Expansion Project upon determining that the project was probable of development, a $14.5 million increase in other project feasibility costs, the absence of the $3.8 million gain on Hester base gas sales recorded in 2011, and a $3.0 million accrual for a certain litigation matter;

•

A $17.7 million (15.6 percent) increase in Administrative and general costs primarily resulting from a $14.4 million increase in allocated corporate expenses, a $2.0 million increase in information technology services, and a $1.6 million increase in rental costs;

•

A $12.6 million (6.3 percent) increase in Operation and maintenance costs resulting from a $11.3 million increase primarily related to compressor and pipeline maintenance and repairs, a $10.8 million increase in employee labor and related benefit costs and $2.0 million associated with the Alabama pipeline rupture, partially offset by $11.5 lower costs associated our Eminence storage field leak, and;

•

A $2.5 million (1.3 percent) increase in Depreciation and amortization costs primarily resulting from an increase in the depreciation base due to additional plant placed in service in 2011 and 2012.

Other (Income) and Other Deductions.

Other (income) and other deductions for the nine months ended September 30, 2012 had a favorable change of $12.5 million (21.9 percent) over the same period in 2011 primarily due to a $5.3 million higher amount of reimbursements for tax gross-up related to reimbursable projects, and $3.1 million in lower interest expense.

Eminence Storage Field Leak.

On December 28, 2010, we detected a leak in one of the seven underground natural gas storage caverns at our Eminence Storage Field in Covington County, Mississippi. Since that time, we have reduced the pressure in the cavern by safely venting and flaring gas. Due to the leak at this cavern and damage to the well at an adjacent cavern, both caverns are out of service. The event has not affected the performance of our obligations under our service agreements with our customers.

As a result of these occurrences, we have determined that these two caverns cannot be returned to service. In addition, two other caverns at the field, which were constructed at or about the same time as those caverns, have experienced operating problems, and we have determined that they should be retired. In September 2011 we filed an application with the FERC seeking authorization to abandon these four caverns. We estimate the cost to abandon the caverns, which will be capital in nature, will be approximately $91.6 million, which is expected to be spent through the end of 2013. This estimate is subject to change as work progresses and additional information becomes known. To the extent available, the abandonment costs will be funded from the ARO Trust. As of September 30, 2012, we have incurred approximately $61.7 million of abandonment costs. Management considers these costs to be prudent costs incurred in the abandonment of these caverns and expects to recover these costs, net of insurance proceeds, in future rate filings.

In the three and nine months ended September 30, 2012, we incurred $0.7 million and $1.8 million, respectively, of expense related primarily to costs to ensure the safety of the surrounding area. We anticipate incurring additional expense of approximately $5.7 million through the remainder of 2012 and in 2013.

Sweet Water, Alabama Pipeline Rupture.

On December 3, 2011, we experienced a rupture of our 36-inch diameter Main Line C pipeline near Sweet Water, Alabama, in a mostly unpopulated area. The rupture resulted in an explosion and fire which caused timber damage to adjacent landowners. There were no injuries as a result of the rupture. On December 6, 2011, PHMSA issued a Corrective Action Order (CAO) outlining the steps required to ensure the safety of Main Line C before its return to service. In March 2012, we submitted our plan to PHMSA to place Main Line C back in service and in June 2012, we received temporary authorization from PHMSA to do so. We are pursuing final resolution of the CAO which would remove the temporary nature of PHMSA’s prior authorization with respect to Main Line C. The adjacent B Line was exposed by the rupture and had coating damage due to the fire. We have replaced that section of B Line. Mainlines A, D and E were not damaged and were quickly back at full service. There has been no impact to our customers.

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, with the exception of certain rates that reflected a rate decrease, the FERC accepted and suspended our general rate filing to be effective March 1, 2013, subject to refund and the outcome of a hearing. The specific rates that reflected a rate decrease were accepted, without suspension, to be effective October 1, 2012 and will not be

subject to refund. The impact of these specific new rates that became effective October 1, 2012 is expected to reduce revenues by approximately $4.0 million for the period from October 1, 2012 until the remaining rates that are currently suspended become effective on March 1, 2013.

Capital Expenditures.

Our capital expenditures for the nine months ended September 30, 2012 were $327.0 million, compared to $267.5 million for the nine months ended September 30, 2011. The $59.5 million increase is primarily due to higher spending on expansion projects in 2012. Our capital expenditures estimate for 2012 and future capital projects are discussed in our 2011 Annual Report Form 10-K. The following describes those projects and certain new capital projects proposed by us.

Mid-South Expansion Project

The Mid-South Expansion Project involves an expansion of our mainline from Station 85 in Choctaw County, Alabama to markets as far downstream as North Carolina. In August 2011, we received approval from the FERC. The capital cost of the project is estimated to be approximately $205 million. We placed the first phase of the project into service in September 2012 which increased capacity by 95 thousand dekatherms per day (Mdth/d). We plan to place the second phase of the project into service in June 2013 which will increase capacity by an additional 130 Mdth/d.

Mid-Atlantic Connector Project

The Mid-Atlantic Connector Project involves an expansion of our mainline from an existing interconnection with East Tennessee Natural Gas in North Carolina to markets as far downstream as Maryland. In July 2011 we received approval from the FERC. The capital cost of the project is estimated to be approximately $55 million. We plan to place the project into service in November 2012, and it will increase capacity by 142 Mdth/d.

Northeast Supply Link Project

The Northeast Supply Link Project involves an expansion of our existing natural gas transmission system from the Marcellus Shale production region on the Leidy Line to various delivery points in Zone 6. We filed an application with the FERC in December 2011 for approval of the project. The capital cost of the project is estimated to be approximately $341 million. We plan to place the project into service in November 2013, and it will increase capacity by 250 Mdth/d.

Rockaway Delivery Lateral Project

The Rockaway Delivery Lateral Project involves the construction of a three-mile offshore lateral to National Grid’s distribution system in New York. We anticipate filing an application with the FERC in the fourth quarter of 2012. The capital cost of the project is estimated to be approximately $182 million. We plan to place the project into service as early as April 2014, and its capacity will 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. We anticipate filing an application with the FERC in the second quarter of 2013. The capital cost of the project is estimated to be approximately $39 million. We plan to place the project into service as early as April 2014, and it will increase capacity by 100 Mdth/d.

Virginia Southside Expansion Project

The Virginia Southside Expansion Project involves an expansion of our existing natural gas transmission system from the Zone 6 Station 210 Pooling Point in New Jersey to Dominion Virginia Power’s proposed power station in Brunswick County, Virginia and our Cascade Creek interconnect with East Tennessee Natural Gas in North Carolina. We anticipate filing an application with the FERC in the fourth quarter of 2012. The capital cost of

the project is estimated to be approximately $296 million. We plan to place the project into service in September 2015, and it will increase capacity by 250 Mdth/d.

ITEM 4. Controls and Procedures.

Our management, including our Vice President and our Vice President and Treasurer, 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 Transco 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 Vice President and our Vice President and Treasurer. Based upon that evaluation, our Vice President and our Vice President and Treasurer concluded that these Disclosure Controls are effective at a reasonable assurance level.

Third Quarter 2012 Changes in Internal Controls.

There have been no changes during the third quarter of 2012 that have materially affected, or are reasonably likely to materially affect, our Internal Controls.

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.

ITEM 6. EXHIBITS

The following instruments are included as exhibits to this report.


Exhibit Number		Description

2.1		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 report Form 10-Q and incorporated herein by reference).

4.1		Indenture, dated as of July 13, 2012, between Transcontinental Gas Pipe Line Company, LLC and The Bank of New York Mellon Trust Company, N.A., as trustee. (filed on July 16, 2012 as Exhibit 4.1 to our Form 8-K and incorporated herein by reference).

4.2		Registration Rights Agreement, dated July 13, 2012, between Transcontinental Gas Pipe Line Company, LLC and Credit Suisse Securities (USA) LLC and J.P. Morgan Securities LLC. (filed on July 16, 2012 as Exhibit 10.1 to our Form 8-K and incorporated herein by reference).

10.1		Commitment Increase and First Amendment, dated as of September 25, 2012, by and among Williams Partners L.P., Northwest Pipeline GP and Transcontinental Gas Pipe Line Company, LLC, as co-borrowers, the lenders named therein, the Issuing Banks, and Citibank N. A., as Administrative Agent (filed on September 27, 2012 as Exhibit 10.1 to Williams Partners L.P.’s Form 8-K, (File No. 001-32599) and incorporated herein by reference).

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

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

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

101.INS**		XBRL Instance Document.

101.SCH**		XBRL Taxonomy Extension Schema.

101.CAL**		XBRL Taxonomy Extension Calculation Linkbase.

101.DEF**		XBRL Taxonomy Extension Definition Linkbase.

101.LAB**		XBRL Taxonomy Extension Label Linkbase.



101.PRE**		XBRL Taxonomy Extension Presentation Linkbase.

*	Filed herewith.

**	Furnished herewith.

SIGNATURE

Pursuant to the requirements of the Securities Exchange Act 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.


				TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC (Registrant)

Dated: October 31, 2012				By: /s/ Jeffrey P. Heinrichs
				Jeffrey P. Heinrichs
				Controller and Assistant Treasurer
				(Principal Accounting Officer)

EXHIBIT INDEX.


Exhibit Number		Description

2.1		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 report Form 10-Q and incorporated herein by reference).

4.1		Indenture, dated as of July 13, 2012, between Transcontinental Gas Pipe Line Company, LLC and The Bank of New York Mellon Trust Company, N.A., as trustee. (filed on July 16, 2012 as Exhibit 4.1 to our Form 8-K and incorporated herein by reference).

4.2		Registration Rights Agreement, dated July 13, 2012, between Transcontinental Gas Pipe Line Company, LLC and Credit Suisse Securities (USA) LLC and J.P. Morgan Securities LLC. (filed on July 16, 2012 as Exhibit 10.1 to our Form 8-K and incorporated herein by reference).

10.1		Commitment Increase and First Amendment, dated as of September 25, 2012, by and among Williams Partners L.P., Northwest Pipeline GP and Transcontinental Gas Pipe Line Company, LLC, as co-borrowers, the lenders named therein, the Issuing Banks, and Citibank N. A., as Administrative Agent (filed on September 27, 2012 as Exhibit 10.1 to Williams Partners L.P.’s Form 8-K, (File No. 001-32599) 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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