e10vq

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, 2006


o		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 CORPORATION

(Exact name of registrant as specified in its charter)


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

2800 Post Oak Boulevard
P. O. Box 1396
Houston, Texas		77251
(Address of principal executive offices)		(Zip Code)

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

None
(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 o

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

Large accelerated filer o Accelerated filer o Non-accelerated filer þ

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yes o No þ

The number of shares of Common Stock, par value $1.00 per share, outstanding as of October 31, 2006 was 100.

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.

EXPLANATORY NOTE

On February 28, 2006, we concluded that our consolidated financial statements for the years ending December 31, 2004 and 2003 should be restated to correct an error related to the methodology used to calculate the average cost of our natural gas inventory. We believe the impact of the adjustment is not material to any of the previously issued consolidated financial statements. However, the cumulative adjustment required to correct the error was significant to the Consolidated Statement of Income for 2005. In connection with the restatement required by the natural gas inventory adjustment, the consolidated financial statements for the years ending December 31, 2004 and 2003 were also restated to record the effects of certain other prior period adjustments.

As we have determined that the quarterly financial information included in our Quarterly Reports on Forms 10-Q and 10 Q/A filed in 2005 were not materially misstated and can be relied upon, we did not amend those filings.

For a discussion of additional information on the restatement, along with restated financial statements for the three and nine months ending September 30, 2005, see “Part I. Financial Information: Item 1. Financial Statements – Notes to Condensed Consolidated Financial Statements – 2. Restatement.”

TRANSCONTINENTAL GAS PIPE LINE CORPORATION
INDEX


	Page
PART I. FINANCIAL INFORMATION:

Item 1. Financial Statements -

Condensed Consolidated Statement of Income for the three and nine months ended September 30, 2006 and 2005		4

Condensed Consolidated Balance Sheet as of September 30, 2006 and December 31, 2005		5

Condensed Consolidated Statement of Cash Flows for the nine months ended September 30, 2006 and 2005		7

Notes to Condensed Consolidated Financial Statements		8

Item 2. Management’s Narrative Analysis of the Results of Operations		25

Item 4. Controls and Procedures		30

PART II. OTHER INFORMATION		31

Item 1. Legal Proceedings		31

Item 1A. Risk Factors		31

Item 6. Exhibits		31
Certification Pursuant to Section 302
Certification Pursuant to Section 302
Certification Pursuant to Section 906

Certain matters discussed in this report, excluding historical information, include forward-looking statements – statements that discuss our expected future results based on current and pending business operations. We make these forward-looking statements in reliance on the safe harbor protections provided under the Private Securities Litigation Reform Act of 1995.

Forward-looking statements can be identified by words such as “anticipates,” “believes,” “expects,” “planned,” “scheduled,” “could,” “continues,” “estimates,” “forecasts,” “might,” “potential,” “projects” or similar expressions. Although we believe these forward-looking statements are based on reasonable assumptions, statements made regarding future results are subject to a number of assumptions, uncertainties and risks that may cause future results to be materially different from the results stated or implied in this document. Additional information about issues that could cause actual results to differ materially from forward-looking statements is contained in our 2005 Annual Report on Form 10-K and 2006 First and Second Quarter Reports on Form 10-Q.

PART 1 – FINANCIAL INFORMATION

ITEM 1. Financial Statements.

TRANSCONTINENTAL GAS PIPE LINE CORPORATION

CONDENSED CONSOLIDATED STATEMENT OF INCOME
(Thousands of Dollars)
(Unaudited)


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2006			2005			2006			2005
				(Restated)						(Restated)
Operating Revenues:
Natural gas sales	$	41,076		$	50,650		$	108,959		$	211,814
Natural gas transportation		188,518			188,159			571,320			572,158
Natural gas storage		29,867			30,508			89,883			91,643
Other		2,355			1,574			12,057			8,023

Total operating revenues		261,816			270,891			782,219			883,638


Operating Costs and Expenses:
Cost of natural gas sales		41,067			50,669			108,948			211,787
Cost of natural gas transportation		2,663			(13,542	)		9,237			(5,317	)
Operation and maintenance		56,441			49,936			162,272			145,948
Administrative and general		48,121			30,945			116,038			79,449
Depreciation and amortization		51,530			48,639			154,117			147,173
Taxes — other than income taxes		12,741			11,337			39,413			34,917
Other, net		(2,592	)		420			(7,405	)		1,044

Total operating costs and expenses		209,971			178,404			582,620			615,001


Operating Income		51,845			92,487			199,599			268,637


Other (Income) and Other Deductions:
Interest expense		23,489			19,782			61,503			59,574
Interest income – affiliates		(4,310	)		(2,306	)		(10,867	)		(7,462	)
Allowance for equity and borrowed funds used during construction (AFUDC)		(3,161	)		(3,059	)		(8,530	)		(6,994	)
Equity in earnings of unconsolidated affiliates		(1,983	)		(1,916	)		(5,729	)		(5,366	)
Miscellaneous other (income) deductions, net		(1,859	)		(1,946	)		(4,973	)		(4,617	)

Total other (income) and other deductions		12,176			10,555			31,404			35,135


Income before Income Taxes		39,669			81,932			168,195			233,502

Provision for Income Taxes		15,320			31,357			64,009			88,498


Net Income	$	24,349		$	50,575		$	104,186		$	145,004

See accompanying notes.

TRANSCONTINENTAL GAS PIPE LINE CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEET (Continued)
(Thousands of Dollars)
(Unaudited)


	September 30,			December 31,
	2006			2005
LIABILITIES AND STOCKHOLDER’S EQUITY
Current Liabilities:

Payables:
Affiliates	$	20,052		$	27,812
Other		91,691			80,876
Transportation and exchange gas payables		26,545			49,657
Accrued liabilities		115,446			168,730
Reserve for rate refunds		3,946			3,763

Total current liabilities		257,680			330,838


Long-Term Debt		1,201,242			1,000,623


Other Long-Term Liabilities:
Deferred income taxes		1,014,146			955,503
Other		264,136			172,764

Total other long-term liabilities		1,278,282			1,128,267


Contingent liabilities and commitments (Note 3)

Common Stockholder’s Equity:
Common stock $1.00 par value:
100 shares authorized, issued and outstanding		—			—
Premium on capital stock and other paid-in capital		1,652,430			1,652,430
Retained earnings		911,786			902,600
Accumulated other comprehensive loss		(274	)		(408	)

Total common stockholder’s equity		2,563,942			2,554,622


Total liabilities and stockholder’s equity	$	5,301,146		$	5,014,350

See accompanying notes.

TRANSCONTINENTAL GAS PIPE LINE CORPORATION

CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS
(Thousands of Dollars)
(Unaudited)


	Nine Months Ended
	September 30,
	2006			2005
				(Restated)
Cash flows from operating activities:
Net income	$	104,186		$	145,004
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Depreciation and amortization		152,361			148,403
Deferred income taxes		46,882			17,895
Allowance for equity funds used during construction (Equity AFUDC)		(6,380	)		(4,825	)
Changes in operating assets and liabilities:
Receivables – affiliates		(1,362	)		(4,377	)
– others		6,983			11,999
Transportation and exchange gas receivables		(1,284	)		(1,675	)
Inventories		(7,919	)		(3,671	)
Payables – affiliates		(7,760	)		2,500
– others		1,083			(18,167	)
Transportation and exchange gas payables		(23,112	)		(4,880	)
Accrued liabilities		(49,826	)		(33,380	)
Reserve for rate refunds		183			(4,002	)
Other, net		(15,611	)		(9,251	)

Net cash provided by operating activities		198,424			241,573


Cash flows from financing activities:
Additions of long-term debt		200,000			—
Retirement of long-term debt		—			(200,000	)
Debt issue costs		(3,187	)		(255	)
Change in cash overdrafts		(2,023	)		(8,378	)
Common stock dividends paid		(95,000	)		(80,000	)

Net cash provided by (used in) financing activities		99,790			(288,633	)


Cash flows from investing activities:
Property, plant and equipment:
Additions, net of equity AFUDC		(265,066	)		(169,373	)
Changes in accounts payable		11,754			(5,396	)
Advances to affiliates, net		(43,384	)		217,634
Advances to others, net		745			547
Other, net		(2,435	)		3,993

Net cash provided by (used in) investing activities		(298,386	)		47,405


Net increase (decrease) in cash		(172	)		345
Cash at beginning of period		362			176

Cash at end of period	$	190		$	521

See accompanying notes.

TRANSCONTINENTAL GAS PIPE LINE CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

1. BASIS OF PRESENTATION

Transcontinental Gas Pipe Line Corporation (Transco) is a wholly-owned subsidiary of Williams Gas Pipeline Company, LLC (WGP). WGP is a wholly-owned subsidiary of The Williams Companies, Inc. (Williams).

In this report, Transco (which includes Transcontinental Gas Pipe Line Corporation 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”.

The condensed consolidated financial statements include our accounts and the accounts of our majority-owned subsidiaries. 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 condensed consolidated 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 have been condensed or omitted. The condensed unaudited consolidated financial statements include all adjustments both normal recurring and others which, in the opinion of our management, are necessary to present fairly our financial position at September 30, 2006, and results of operations for the three and nine months ended September 30, 2006 and 2005, and cash flows for the nine months ended September 30, 2006 and 2005. These condensed consolidated financial statements should be read in conjunction with the consolidated financial statements and the notes thereto included in our 2005 Annual Report on Form 10-K and 2006 First and Second Quarter Reports on Form 10-Q.

As a participant in Williams’ cash management program, we have advances to and from Williams. The advances are represented by demand notes. The interest rate on intercompany demand notes is based upon the weighted average cost of Williams’ debt outstanding at the end of each quarter.

Through an agency agreement, Williams Power Company (WPC), an affiliate, manages our remaining jurisdictional merchant gas sales, which excludes our cash out sales in settlement of gas imbalances. The long-term purchase agreements managed by WPC 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 that are managed by WPC. WPC receives all margins associated with jurisdictional merchant gas sales business and, as our agent, 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 U.S. generally accepted accounting principles requires management to make estimates and assumptions that affect the amounts reported in the condensed consolidated financial statements and accompanying notes. Actual results could differ from those estimates. Estimates and assumptions which, in the opinion of management, are significant to the underlying amounts included in the financial statements and for which it would be reasonably possible that future

events or information could change those estimates include: 1) revenues subject to refund; 2) litigation-related contingencies; 3) environmental remediation obligations; 4) impairment assessments of long-lived assets; 5) deferred and other income taxes; 6) depreciation; 7) pensions and other post-employment benefits; and 8) asset retirement obligations.

Our Board of Directors declared and we paid cash dividends on common stock in the amounts of $40 million on March 31, 2006, $40 million on June 30, 2006 and $15 million on September 30, 2006.

Comprehensive income for the three and nine months ended September 30, 2006 and 2005 respectively, are as follows (in thousands):


	Three Months					Nine Months
	Ended September 30,					Ended September 30,
	2006			2005		2006		2005
				(restated)				(restated)
Net income	$	24,349		$	50,575	$	104,186	$	145,004
Equity interest in unrealized gain/(loss) on interest rate hedge		(150	)		240		134		409

Total comprehensive income	$	24,199		$	50,815	$	104,320	$	145,413

Asset Retirement Obligation As disclosed in our 2005 Annual Report on Form 10-K, we recorded an asset retirement obligation (ARO) of approximately $53.6 million as of December 31, 2005. The ARO was recorded in accordance with Financial Accounting Standards Board (FASB) Statement No. 143, “Accounting for Asset Retirement Obligations,” and FASB Interpretation (FIN) No. 47, “Accounting for Conditional Asset Retirement Obligations — an interpretation of FASB Statement No. 143.”

The accrued obligations relate to underground storage caverns, offshore platforms, pipelines, and gas transmission facilities. At the end of the useful life of each respective asset, we are legally obligated to plug storage caverns and remove any related surface equipment, to dismantle offshore platforms, to cap certain gathering pipelines at the wellhead connection and remove any related surface equipment, and to remove certain components of gas transmission facilities from the ground.

During the third quarter of 2006, we obtained additional information impacting our estimation of our ARO. Factors affected by the additional information included estimated settlement dates, estimated settlement costs and inflation rates. We adjusted the ARO related to off-shore assets because the additional information results in improved and best available estimates regarding the ARO costs, lives, and inflation rates. As a result, in the third quarter of 2006, we recorded an increase in Other Long-Term Liabilities: Other of $88 million and an increase in property, plant and equipment of $88 million.

With respect to the onshore assets, we have not yet determined whether the additional information should result in an adjustment to some or all assumptions and thus no adjustment was made in the third quarter. We are in the process of assessing the asset retirement obligations associated with our onshore assets, and anticipate completing the assessment in the fourth quarter of 2006.

Recent Accounting Developments

In June 2006, the Financial Accounting Standards Board (FASB) issued FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes, an interpretation of FASB Statement No. 109” (FIN 48). The Interpretation clarifies the accounting for uncertainty in income taxes under FASB Statement No. 109, “Accounting for Income Taxes.” The Interpretation prescribes guidance for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. To recognize a

tax position, the enterprise determines whether it is more likely than not that the tax position will be sustained upon examination, including resolution of any related appeals or litigation processes, based on the technical merits of the position. A tax position that meets the more likely than not recognition threshold is measured to determine the amount of benefit to recognize in the financial statements. The tax position is measured at the largest amount of benefit that is greater than 50 percent likely of being realized upon ultimate settlement.

FIN 48 is effective for fiscal years beginning after December 15, 2006. The cumulative effect of applying the Interpretation must be reported as an adjustment to the opening balance of retained earnings in the year of adoption. We will adopt the Interpretation beginning in 2007. We do not anticipate that the adoption of this Interpretation will have any material impact on our Consolidated Financial Statements.

The FASB issued SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans – an amendment of FASB Statements No. 87, 88, 106 and 132(R)” (SFAS No. 158) in September 2006. The Statement requires an employer to recognize in its statement of financial position an asset for a defined benefit pension or other postretirement benefit plan’s overfunded status or a liability for a plan’s underfunded status. Entities will now recognize in the statement of financial position changes in the funded status of a defined benefit pension or other postretirement benefit plan in the year in which the changes occur. Those changes that arise during the year but are not recognized as a component of net periodic benefit cost would typically be reported in other comprehensive income, however subject to further clarification under regulatory accounting guidelines, we may report such amounts as regulatory assets or liabilities. The Statement also requires measurement of a plan’s assets and its obligations that determine its funded status as of the end of the employer’s fiscal year. The requirement to recognize the funded status of a defined benefit plan and the related disclosure requirements is effective as of the end of the fiscal year ending after December 15, 2006. The initial impact of this Statement on our financial statements will not be determined until the Williams sponsored plans’ benefit obligations and the fair value of the plans’ assets are measured as of December 31, 2006. Adoption of the Statement is not expected to impact our Statement of Income or funding requirements. Estimates based on January 1, 2006 data indicate that the decrease in our pension and other postretirement benefit assets and the increase in our pension and other postretirement benefit liabilities could potentially total approximately $65 million due to the adoption of this Statement. The actual adjustments ultimately recorded will depend on various factors including, but not limited to, regulatory accounting interpretations, changes in assumptions used to calculate the year-end benefit obligations, changes in the fair value of plan assets at year-end, and the impact of income taxes. The requirement to measure plan assets and benefit obligations as of the date of the employer’s fiscal year-end statement of financial position is effective for fiscal years ending after December 15, 2008, and will not impact our financial statements as the Williams sponsored plans’ obligations and assets are currently measured as of our fiscal year-end.

FERC Accounting Guidance On June 30, 2005, the Federal Energy Regulatory Commission (FERC) issued an order, “Accounting for Pipeline Assessment Cost,” to be applied prospectively effective January 1, 2006. The order requires companies to expense certain pipeline integrity-related assessment costs that we have historically capitalized. As disclosed in our 2006 Second Quarter Report on Form 10-Q, we anticipated expensing approximately $5 million to $10 million in 2006 that previously would have been capitalized prior to the order becoming effective. During the three and nine months ended September 30, 2006, the application of this order resulted in $2.5 million and $6 million, respectively, of such costs being expensed.

2. RESTATEMENT

On February 28, 2006, we concluded that our consolidated financial statements for each of the years ending December 31, 2004 and 2003 should be restated to correct an error related to the methodology used to calculate the average cost of our natural gas inventory. We believe the impact of the adjustment is not material to any of the previously issued consolidated financial statements. However, the cumulative adjustment required to correct the error was significant to the Consolidated Statement of Income for 2005.

We revised the weighted average and LIFO cost of our natural gas inventories and valuation of gas imbalances, which corrections thereby affected amounts of previously reported fuel gains, storage losses, and deferred cash out gains and losses. The restatement for these items resulted in an increase in Cost of natural gas transportation of $3.2 million for the nine months ended September 30, 2005.

Certain other adjustments were identified in 2005 related to prior periods including an adjustment to lease expense and a correction of depreciation and amortization expense. None of these items were individually significant but they have been reflected in the proper periods in conjunction with the restatement. The impact of these adjustments was an increase in Administrative and general expense of $0.6 million and an increase in Depreciation and amortization expense of $0.1 million for the nine months ended September 30, 2005.

Adjustments for the related income tax effects were also recorded.

The cumulative impact of these adjustments to our Condensed Consolidated Statement of Income for the nine months ended September 30, 2005 was a decrease in Operating income of $3.9 million and Net Income of $2.4 million.

The following schedules reconcile the amounts as originally reported in our Condensed Consolidated Statements of Income for the three and nine months ended September 30, 2005 and Condensed Consolidated Statement of Cash Flows for the nine months ended September 30, 2005.

TRANSCONTINENTAL GAS PIPE LINE CORPORATION

CONDENSED CONSOLIDATED STATEMENT OF INCOME
(Thousands of Dollars)
(Unaudited)


	Three Months Ended September 30, 2005
	(As Reported)			Adjustment			(As Restated)
Operating Revenues:
Natural gas sales	$	50,650		$	—		$	50,650
Natural gas transportation		188,159			—			188,159
Natural gas storage		30,508			—			30,508
Other		1,574			—			1,574

Total operating revenues		270,891			—			270,891


Operating Costs and Expenses:
Cost of natural gas sales		50,669			—			50,669
Cost of natural gas transportation		(13,504	)		(38	)		(13,542	)
Operation and maintenance		49,936			—			49,936
Administrative and general		30,733			212			30,945
Depreciation and amortization		49,034			(395	)		48,639
Taxes — other than income taxes		11,337			—			11,337
Other, net		420			—			420

Total operating costs and expenses		178,625			(221	)		178,404


Operating Income		92,266			221			92,487


Other (Income) and Other Deductions:
Interest expense		19,782			—			19,782
Interest income – affiliates		(2,306	)		—			(2,306	)
Allowance for equity and borrowed funds used during construction (AFUDC)		(3,059	)		—			(3,059	)
Equity in earnings of unconsolidated affiliates		(1,916	)		—			(1,916	)
Miscellaneous other (income) deductions, net		(1,946	)		—			(1,946	)

Total other (income) and other deductions		10,555			—			10,555


Income before Income Taxes		81,711			221			81,932

Provision for Income Taxes		31,273			84			31,357


Net Income	$	50,438		$	137		$	50,575

TRANSCONTINENTAL GAS PIPE LINE CORPORATION

CONDENSED CONSOLIDATED STATEMENT OF INCOME
(Thousands of Dollars)
(Unaudited)


	Nine Months Ended September 30, 2005
	(As Reported)			Adjustment			(As Restated)
Operating Revenues:
Natural gas sales	$	211,814		$	—		$	211,814
Natural gas transportation		572,158			—			572,158
Natural gas storage		91,643			—			91,643
Other		8,023			—			8,023

Total operating revenues		883,638			—			883,638


Operating Costs and Expenses:
Cost of natural gas sales		211,787			—			211,787
Cost of natural gas transportation		(8,513	)		3,196			(5,317	)
Operation and maintenance		145,948			—			145,948
Administrative and general		78,892			557			79,449
Depreciation and amortization		147,041			132			147,173
Taxes — other than income taxes		34,917			—			34,917
Other, net		1,044			—			1,044

Total operating costs and expenses		611,116			3,885			615,001


Operating Income		272,522			(3,885	)		268,637


Other (Income) and Other Deductions:
Interest expense		59,574			—			59,574
Interest income – affiliates		(7,462	)		—			(7,462	)
Allowance for equity and borrowed funds used during construction (AFUDC)		(6,994	)		—			(6,994	)
Equity in earnings of unconsolidated affiliates		(5,366	)		—			(5,366	)
Miscellaneous other (income) deductions, net		(4,617	)		—			(4,617	)

Total other (income) and other deductions		35,135			—			35,135


Income before Income Taxes		237,387			(3,885	)		233,502

Provision for Income Taxes		89,967			(1,469	)		88,498


Net Income	$	147,420		$	(2,416	)	$	145,004

TRANSCONTINENTAL GAS PIPE LINE CORPORATION

CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS
(Thousands of Dollars)
(Unaudited)


	Nine Months Ended September 30, 2005
	(As Reported)			Adjustment			(As Restated)
Cash flows from operating activities:
Net income	$	147,420		$	(2,416	)	$	145,004
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Depreciation and amortization		147,264			1,139			148,403
Deferred income taxes		17,895			—			17,895
Allowance for equity funds used during construction (Equity AFUDC)		(4,825	)		—			(4,825	)
Changes in operating assets and liabilities:
Receivables – affiliates		(4,377	)		—			(4,377	)
– other		12,546			(547	)		11,999
Transportation and exchange gas receivables		(1,675	)		—			(1,675	)
Inventories		(27,800	)		24,129			(3,671	)
Payables – affiliates		2,500			—			2,500
– other		(18,167	)		—			(18,167	)
Transportation and exchange gas payables		9,024			(13,904	)		(4,880	)
Accrued liabilities		(46,756	)		13,376			(33,380	)
Reserve for rate refunds		(4,002	)		—			(4,002	)
Other, net		12,720			(21,971	)		(9,251	)

Net cash provided by (used in) operating activities		241,767			(194	)		241,573


Cash flows from financing activities:
Retirement of long-term debt		(200,000	)		—			(200,000	)
Debt issue costs		(255	)		—			(255	)
Change in cash overdrafts		(8,378	)		—			(8,378	)
Common stock dividends paid		(80,000	)		—			(80,000	)

Net cash used in financing activities		(288,633	)		—			(288,633	)


Cash flows from investing activities:
Property, plant and equipment:
Additions, net of equity AFUDC		(169,020	)		(353	)		(169,373	)
Changes in accounts payable		(5,396	)		—			(5,396	)
Advances to affiliates, net		217,634			—			217,634
Advances to others, net		—			547			547
Other, net		3,993			—			3,993

Net cash provided by investing activities		47,211			194			47,405


Net increase in cash		345			—			345
Cash at beginning of period		176			—			176

Cash at end of period	$	521		$	—		$	521

See accompanying notes.

3. CONTINGENT LIABILITIES AND COMMITMENTS

Rate and Regulatory Matters

General rate case (Docket No. RP06-569) On August 31, 2006, we submitted to the Federal Energy Regulatory Commission (FERC) a general rate filing principally designed to recover costs associated with (a) an increase in operation and maintenance expenses and administrative and general expenses; (b) an increase in depreciation expense; (c) the inclusion of costs for asset retirement obligations; (d) an increase in rate base resulting from additional plant; and (e) an increase in rate of return and related taxes. The filing reflected an increase in annual revenues from jurisdictional service of approximately $281 million over the cost of service underlying the rates reflected in the settlement of our Docket No. RP01-245 rate proceeding, as adjusted to include the cost of service and rate base amounts for expansion projects placed in service after the September 1, 2001 effective date of the Docket No. RP01-245 rates. The filing also reflected changes to our tariff, cost allocation and rate design methods, including the refunctionalization of certain facilities from transmission plant accounts to jurisdictional gathering plant accounts consistent with various FERC orders (including the facilities addressed in the FERC’s various spin-down orders discussed below). On September 29, 2006, the FERC issued an order accepting and suspending our August 31, 2006 general rate filing to be effective March 1, 2007, subject to refund and the outcome of a hearing.

General rate case (Docket No. RP01-245) On March 1, 2001, we submitted to the FERC a general rate filing principally designed to recover costs associated with an increase in rate base resulting from additional plant, an increase in rate of return and related taxes, and an increase in operation and maintenance expenses.

In July 2002, the FERC approved a Stipulation and Agreement (Settlement) which resolved all cost of service, throughput and throughput mix issues in this rate case proceeding with the exception of one cost of service issue related to the valuation of certain right-of-way access for the installation of a fiber optic system by a then Transco affiliate, the resolution of which is to be applied prospectively. Other issues not resolved by the Settlement include various cost allocation, rate design and tariff matters.

On December 3, 2002, an Administrative Law Judge (ALJ) issued his initial decision on the issues not resolved by the Settlement. In the initial decision, the ALJ determined, among other things, that (1) our existing treatment of the arrangement with our former affiliate relating to right of way is just and reasonable, (2) our proposal to roll-in the costs of the Cherokee, Pocono and SunBelt projects is unjust and unreasonable, and (3) our recovery of the costs of the Mobile Bay expansion project on a rolled-in basis is unjust and unreasonable. As to the Mobile Bay issue, the ALJ determined that we had the burden of establishing that roll-in of that project is just and reasonable, but did not address the issue of any potential refunds. Our current rates are based on the roll-in of the Mobile Bay expansion project.

On March 26, 2004, the FERC issued an order that affirmed, in part, and reversed, in part, the ALJ’s initial decision on the issues not resolved by the Settlement. On the issues discussed above, the FERC affirmed the ALJ’s determination that our existing treatment of the arrangement with our former affiliate relating to right of way is just and reasonable and our proposal to roll-in the costs of the Cherokee, Pocono and SunBelt projects is unjust and unreasonable, but reversed the ALJ’s rejection of our proposal to recover the costs of the Mobile Bay expansion project on a rolled-in basis and found that we had shown that our proposed rolled-in rates are just and reasonable. The FERC also affirmed the ALJ’s determination that we must separate our Emergency Eminence Withdrawal service from our Rate Schedule FT service and offer the Emergency Eminence Withdrawal service under a separate rate schedule, thereby permitting shippers to decide whether to take that service. Currently, the cost of the Emergency Eminence Withdrawal service is

included as part of our Rate Schedule FT service for those shippers that can access the Eminence Storage Field. Under the FERC’s decision, we would be at risk for those costs to the extent that shippers did not elect to subscribe to all of the separately offered service. On April 26, 2004, several parties, including Transco, filed requests for rehearing of the FERC’s March 26, 2004 order.

On August 5, 2005, the FERC issued an order addressing the requests for rehearing of the March 26, 2004 order. The FERC generally denied rehearing of the March 26, 2004 order, but granted rehearing on a limited number of issues. On the issues described above, the FERC affirmed its determination that we must separate our Emergency Eminence Withdrawal service from our Rate Schedule FT service, but granted rehearing to require that each Rate Schedule FT shipper that currently has access to the Emergency Eminence Withdrawal service must subscribe to its proportionate share of the unbundled Emergency Eminence Withdrawal service until its Rate Schedule FT contract terminates. The FERC also affirmed its determinations that our existing treatment of the arrangement with our former affiliate relating to right of way is just and reasonable, our proposal to roll-in the costs of the Cherokee, Pocono and SunBelt projects is unjust and unreasonable, and our proposal to recover the costs of the Mobile Bay expansion project on a rolled-in basis is just and reasonable. The August 5, 2005 order did grant rehearing on certain of the cost allocation, rate design and tariff issues, finding, among other things, that we must adopt a “paper” pooling method for our Rate Zone 4, and that we must allocate storage costs to incremental transportation services and to the transportation component of our bundled storage services and include additional storage services in the allocation of storage costs to our transportation services. Pursuant to the Settlement, the changes to our existing practices required by or affirmed in the August 5, 2005 order would be implemented on a prospective basis. On September 6, 2005, several parties, including Transco, filed requests for rehearing of the FERC’s August 5, 2005 order.

On May 30, 2006, the FERC issued an order on rehearing of its August 5, 2005 order, which denied most of the requests for rehearing, clarified the order in certain respects and established further proceedings to address other issues. In particular, the FERC clarified the order with regard to the requirement that we separate our Emergency Eminence Withdrawal service from our Rate Schedule FT service (Emergency Eminence Issue) to provide that Rate Schedule FT shippers must subscribe to a proportionate share of the unbundled Emergency Eminence Withdrawal service for a term that coincides with their Rate Schedule FT contracts, but may elect at the end of that term to decline to renew the unbundled Emergency Eminence Withdrawal service while still being able to retain and renew their Rate Schedule FT contracts. With regard to the allocation of storage costs to our transportation services (Storage Cost Allocation Issue), the FERC established a hearing to address the issue of the appropriate level of costs that should be subject to that allocation. In addition, the FERC established a technical conference to explore issues concerning the appropriate method of conducting pooling for our Zone 4 before the FERC reaches a final determination on whether our existing method is consistent with FERC policy, and, if not, what modification to the current method would be appropriate. Certain parties filed requests for rehearing of the May 30, 2006 order, which the FERC denied on July 31, 2006. In addition, the FERC’s orders have been appealed to the United States Court of Appeals for the District of Columbia Circuit (D.C. Circuit Court).

On September 25, 2006, we filed a Stipulation and Agreement which, if approved by the FERC, will resolve the Storage Cost Allocation Issue and the Emergency Eminence Issue. On October 30, 2006, the ALJ certified the Stipulation and Agreement to the FERC for its consideration as an uncontested settlement.

On October 3, 2006, the FERC issued an order clarifying the Settlement and directing us to submit a filing, within 30 days of the date of the order, to comply with the directives of the FERC on issues reserved for litigation that have been finally resolved by various FERC orders in this proceeding. On November 2, 2006, we made the compliance filing as directed in the October 3, 2006 order, and contemporaneously submitted a request for rehearing of the order.

Gathering facilities spin-down order (Docket Nos. CP96-206-000 and CP96-207-000) In 1996, we filed an application with the FERC for an order authorizing the abandonment of certain facilities located

onshore and offshore in Texas, Louisiana and Mississippi by conveyance to an affiliate, Williams Gas Processing — Gulf Coast Company (Gas Processing). The net book value of these facilities at September 30, 2006, was approximately $284 million. Concurrently, Gas Processing filed a petition for declaratory order requesting a determination that its gathering services and rates be exempt from FERC regulation under the Natural Gas Act of 1938 (NGA). The FERC issued an order dismissing our application and Gas Processing’s petition for declaratory order and in 2001, the FERC issued an order that denied our request for rehearing. Certain parties, including Transco, filed in the D.C. Circuit Court petitions for review of the FERC’s orders and in June 2003, those petitions were denied. Several parties petitioned the United States Supreme Court for review of the D.C. Circuit Court’s opinion, and on January 12, 2004, the Court denied those petitions.

While the proceedings related to the 1996 application were pending, we filed with the FERC the applications described below seeking authorization to abandon portions of the facilities included in the 1996 application.

North Padre Island/Central Texas Systems Spin-down Proceeding (Docket Nos. CP01-32 and CP01-34) In 2000, we filed an application with the FERC seeking authorization to abandon certain of our offshore Texas facilities by conveyance to Gas Processing. Gas Processing filed a contemporaneous request that the FERC declare that the facilities sought to be abandoned would be considered nonjurisdictional gathering facilities upon transfer to Gas Processing. The FERC approved the abandonment and the non-jurisdictional treatment of all of these facilities. Effective December 2001, we transferred to Gas Processing the North Padre Island facilities through a non-cash dividend of $3.3 million, which represents the net book value of the facilities as of that date. Parties filed petitions for review of the FERC’s orders with the D.C. Circuit Court which were consolidated with the appeals of the FERC’s orders in CP96-206 and CP96-207, discussed above, and which were denied by the D.C. Circuit Court in its opinion issued in June, 2003. In 2001, Shell Offshore, Inc. filed a complaint at the FERC against Gas Processing, Williams Field Services Company (WFS) and us alleging concerted actions by these affiliates frustrated the FERC’s regulation of us. The alleged actions are related to offers of gathering service by WFS and its subsidiaries with respect to the North Padre Island facilities. In 2002, the FERC issued an order reasserting jurisdiction over that portion of the North Padre Island facilities previously transferred to WFS. The FERC also determined a gathering rate for service on these facilities, which is to be collected by us. Transco, Gas Processing and WFS each sought rehearing of the FERC’s order, and in May 2003, the FERC denied those requests for rehearing. Transco, Gas Processing and WFS filed petitions for review of the FERC’s orders with the D.C. Circuit Court and on July 13, 2004, the court granted the petitions, vacating the FERC’s orders and remanding the case to the FERC for further proceedings not inconsistent with the court’s opinion. On February 15, 2005, the FERC issued an order in response to the D.C. Circuit Court remand. In that order, the FERC determined that, based on the record and the court’s decision, there is not a sufficient basis to reassert NGA jurisdiction or to assert Outer Continental Shelf Lands Act jurisdiction over the gathering rates and service on the North Padre Island facilities. Accordingly, the FERC reversed its initial decision, dismissed the complaint filed by Shell, and directed us to remove the North Padre Island gathering rate and rate schedule from our tariff. On March 7, 2005, Shell filed a request for rehearing of the FERC’s February 15, 2005 order. On September 15, 2005, the FERC issued an order denying Shell’s request for rehearing and terminated this Docket No. RP02-99 proceeding, but concurrently with that order instituted a notice of inquiry in Docket No. PL05-10-000 to evaluate possible changes to its test for reassertion of NGA jurisdiction over gathering facilities. If the FERC adopts a different test, the FERC stated that its action in denying Shell’s request for rehearing is without prejudice to Shell’s ability to present evidence that would satisfy that new test. On October 17, 2005, Shell filed a request for rehearing of the FERC’s September 15, 2005 order.

With regard to the approval of the spin-down of the Central Texas facilities, a Transco customer filed a complaint with the FERC in Docket No. RP02-309 seeking the revocation of the FERC’s spin-down approval. In September 2002, the FERC issued an order requiring that, upon transfer of the Central Texas facilities, we acquire capacity on the transferred facilities and provide service to the existing customer under the original terms and conditions of service. Our request for rehearing was denied in May 2003. In that order, the FERC also required that we notify the FERC of Transco’s plans with regard to the transfer of the Central Texas facilities to Gas Processing. We replied that due to the numerous outstanding issues affecting the transfer of those facilities, we could not at that time predict the timing for the implementation of the transfer of the Central Texas facilities. Transco and the customer each also filed a request for rehearing of the FERC’s May 2003 order. On May 6, 2004, the FERC issued an order on rehearing effectively granting the customer’s request for rehearing. On June 7, 2004, we filed a request for rehearing of the May 6, 2004 order, which the FERC denied on July 6, 2004. On July 14, 2004, we filed a petition for review of the FERC’s orders with the D.C. Circuit Court. After we filed our initial brief, the FERC filed a motion for a voluntary remand of the record to permit the FERC to further consider the issues raised and to hold the proceedings in abeyance pending issuance of FERC orders on the matter. On February 11, 2005, the D.C. Circuit Court granted FERC’s motion and remanded the record of this proceeding to the FERC. On June 16, 2005, the FERC issued an order on remand, which, among other things, modifies the remedy adopted in its earlier orders to require Transco to reimburse the customer for any additional costs that it incurs following the transfer of the facilities and seeks to provide further support for its rulings in this proceeding. On July 18, 2005, we filed a request for rehearing of the June 16, 2005 order, which the FERC denied on February 21, 2006. On April 21, 2006, we filed a petition for review of the FERC’s orders in the remand proceeding with the D.C. Circuit Court. We have not transferred to our affiliate any of the facilities authorized for spin down and have no immediate plans to do so. At September 30, 2006, the net book value of these facilities was $60 million.

North High Island/West Cameron Systems and Central Louisiana System Spin-down Proceedings (Docket Nos. CP01-103 and CP01-104, and CP01-368 and CP01-369) In 2001 the FERC issued orders authorizing us to spin down only a portion of these systems to Gas Processing. All legal challenges of these FERC orders have been exhausted. We have not transferred to our affiliate any of the facilities authorized for spin down and have no immediate plans to do so. On May 6, 2004, the FERC issued an order relating to the Central Louisiana system spin-down proceeding in which the FERC required Transco and Gas Processing to show cause, due to developments in another proceeding, why certain of the Central Louisiana facilities previously found to be gathering should not be classified as jurisdictional transmission facilities. We filed our response to the show cause order on July 6, 2004, arguing that the FERC should not alter its conclusion that the facilities serve a gathering function. On April 19, 2005, the FERC issued an order reversing its earlier finding and found that the facilities in question are jurisdictional transmission facilities. Transco and Gas Processing filed a request for rehearing of the FERC’s April 19, 2005 order, and on June 28, 2005, the FERC denied that request. On August 26, 2005, Transco and Gas Processing filed a joint petition for review of the FERC’s orders with the D.C. Circuit Court.

The net book value, at the application dates in 2001, of the North High Island/West Cameron and Central Louisiana facilities included in these two applications was approximately $65 million.

FERC enforcement matter By order dated March 17, 2003, the FERC approved a settlement between the FERC staff and Williams, WPC and us which resolved certain FERC staff’s allegations. As part of the settlement, WPC agreed, subject to certain exceptions, that it will not enter into new transportation agreements that would increase the transportation capacity it holds on certain affiliated interstate gas pipelines, including Transco. We also agreed to pay a civil penalty in five equal installments totaling $20 million, and the final $4 million installment will be paid in 2007.

Legal Proceedings.

Royalty claims and litigation In connection with our renegotiations with producers to resolve take-or-pay and other contract claims and to amend gas purchase contracts, we entered into certain settlements which may require that we indemnify producers for claims for additional royalties resulting from such settlements. Through our agent WPC, we continue to purchase gas under contracts which extend, in some cases, through the life of the associated gas reserves. Certain of these contracts contain royalty indemnification provisions, which have no carrying value. We have been made aware of demands on producers for additional royalties and such producers may receive other demands which could result in claims against us pursuant to royalty indemnification provisions. Indemnification for royalties will depend on, among other things, the specific lease provisions between the producer and the lessor and the terms of the agreement between the producer and us. Consequently, the potential maximum future payments under such indemnification provisions cannot be determined. However, we believe that the probability of material payments is remote.

A producer had asserted a claim for damages against us for indemnification relating to prior royalty payments. The Louisiana Court of Appeals denied the producer’s appeal and affirmed a lower court’s judgment in our favor. On March 31, 2006, the Louisiana Supreme Court denied the producer’s request for further review. Consequently, we reversed in the first quarter of 2006 a related liability which resulted in an increase to pre-tax income of approximately $7.0 million.

In 1998, the United States Department of Justice (DOJ) informed Williams that Jack Grynberg, an individual, had filed claims in the United States District Court for the District of Colorado under the False Claims Act against Williams and certain of its wholly-owned subsidiaries including us. Mr. Grynberg had also filed claims against approximately 300 other energy companies and alleged that the defendants violated the False Claims Act in connection with the measurement, royalty valuation and purchase of hydrocarbons. The relief sought was an unspecified amount of royalties allegedly not paid to the federal government, treble damages, a civil penalty, attorneys’ fees, and costs. In April 1999, the DOJ declined to intervene in any of the Grynberg qui tam cases, and in October 1999, the Panel on Multi-District Litigation transferred all of the Grynberg qui tam cases, including those filed against Williams, to the United States District Court for the District of Wyoming for pre-trial purposes. In October 2002, the court granted a motion to dismiss Grynberg’s royalty valuation claims. Grynberg’s measurement claims remained pending against Williams, including us, and the other defendants, although the defendants have filed a number of motions to dismiss these claims on jurisdictional grounds. In March 2005, oral argument on these motions occurred. In May 2005, the court-appointed special master entered a report which recommended that many of the cases be dismissed, including the case pending against certain of the Williams defendants, including us. On October 20, 2006, the District Court dismissed all claims against us.

Hurricane lawsuits We were named as a defendant in two class action petitions for damages filed in the United States District Court for the Eastern District of Louisiana in September and October 2005 arising from hurricanes that struck Louisiana in 2005. The class plaintiffs, purporting to represent persons, businesses and entities in the State of Louisiana who have suffered damage as a result of the winds and storm surge from the hurricanes, allege that the operating activities of the two sub-classes of defendants, which include all oil and gas pipelines that dredged pipeline canals or installed pipelines in the marshes of south Louisiana (including us) and all oil and gas exploration and production companies which drilled for oil and gas or dredged canals in the marshes of south Louisiana, have altered marshland ecology and caused marshland destruction which otherwise would have averted all or almost all of the destruction and loss of life caused by the hurricanes. Plaintiffs request that the court allow the lawsuits to proceed as class actions and seek legal and equitable relief in an unspecified amount. On April 17, 2006, all defendants, including us,

filed a joint motion to dismiss the class action petitions on various grounds. This motion was granted on September 28, 2006, and the cases were dismissed. An additional class action case containing substantially identical allegations was filed against the same defendant class, including us, in August 2006. On October 20, 2006, the defendants filed a motion to dismiss this case on the same basis as the motion filed in the other cases.

Environmental Matters

We are subject to extensive federal, state and local environmental laws and regulations which affect our operations related to the construction and operation of pipeline facilities. Appropriate governmental authorities enforce these laws and regulations with a variety of civil and criminal enforcement measures, including monetary penalties, assessment and remediation requirements and injunctions as to future compliance. Our use and disposal of hazardous materials are subject to the requirements of the federal Toxic Substances Control Act (TSCA), the federal Resource Conservation and Recovery Act (RCRA) and comparable state statutes. The Comprehensive Environmental Response, Compensation and Liability Act (CERCLA), also known as “Superfund,” imposes liability, without regard to fault or the legality of the original act, for release of a “hazardous substance” into the environment. Because these laws and regulations change from time to time, practices that have been acceptable to the industry and to the regulators have to be changed and assessment and monitoring have to be undertaken to determine whether those practices have damaged the environment and whether remediation is required. Since 1989, 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 TSCA, RCRA, CERCLA and comparable state statutes will total approximately $14 million to $16 million, measured on an undiscounted basis, and will be spent over the next three years. This estimate depends upon 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, 2006, we had a balance of approximately $12.4 million for these estimated costs recorded in current liabilities ($4.6 million) and other long-term liabilities ($7.8 million) in the accompanying Condensed Consolidated Balance Sheet.

We consider prudently incurred environmental assessment and remediation costs and 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. Therefore, these estimated costs of environmental assessment and remediation have also been recorded as regulatory assets in Current Assets: Other and Other Assets in the accompanying Consolidated Balance Sheet.

We have used lubricating oils containing polychlorinated biphenyls (PCBs) and, although the use of such oils was discontinued 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 programs concerning investigative and remedial actions relative to potential mercury contamination at certain gas metering sites. All such costs are included in the $14 million to $16 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 $500,000. The estimated remediation costs for all of these sites have been included in the environmental reserve discussed above. Liability under CERCLA (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.

We are also subject to the federal Clean Air Act and to the federal Clean Air Act Amendments of 1990 (1990 Amendments), which added significantly to the existing requirements established by the federal Clean Air Act. The 1990 Amendments required that the EPA issue new regulations, mainly related to stationary sources, air toxics, ozone non-attainment areas and acid rain. During the last few years we have been installing new emission control devices required for new or modified facilities in areas designated as non-attainment by EPA. We operate some of our facilities in areas of the country currently designated as non-attainment with the one-hour ozone standard. In April 2004, EPA designated eight-hour ozone non-attainment areas. We also operate facilities in areas of the country now designated as non-attainment with the eight-hour ozone standard. Pursuant to non-attainment area requirements of the 1990 Amendments, and proposed EPA rules designed to mitigate the migration of ground-level ozone (NOx) in 22 Eastern states, we are planning installation of air pollution controls on existing sources at certain facilities in order to reduce NOx emissions. We anticipate that additional facilities may be subject to increased controls within five years. For many of these facilities, we are developing more cost effective and innovative compressor engine control designs. In March 2004 and June 2004, the EPA promulgated additional regulations regarding hazardous air pollutants; these regulations may impose controls in addition to the controls described above. Due to the developing nature of federal and state emission regulations, it is not possible to precisely determine the ultimate emission control costs. However, the emission control additions required to comply with current federal Clean Air Act requirements, the 1990 Amendments, the hazardous air pollutant regulations, and the individual state implementation plans for NOx reductions are estimated to include costs in the range of $67 million to $78 million subsequent to 2005, through 2009. EPA’s recent designation of new non-attainment areas will result in new federal and state regulatory action that may impact our operations. As a result, the cost of additions to property, plant and equipment is expected to increase. We are unable at this time to estimate with any certainty the cost of additions that may be required to meet new regulations, although it is believed that some of those costs are included in the ranges discussed above. Management considers costs associated with compliance with the environmental laws and regulations described above to be prudent costs incurred in the ordinary course of business and, therefore, recoverable through our rates.

Safety Matters

Pipeline Integrity Regulations We have developed an Integrity Management Plan that meets the United States Department of Transportation Pipeline and Hazardous Materials Safety Administration final rule pursuant to the requirements of the Pipeline Safety Improvement Act of 2002. In meeting the Integrity Regulations, we have identified the high consequence areas, including a baseline assessment and periodic reassessments to be completed within specified timeframes. Currently, we estimate that the cost to perform required assessments and remediation will be between $300 million and $350 million over the remaining assessment period of 2006 through 2012. As a result of the June 30, 2005 FERC order described in Note 1, a portion of this amount will be expensed. We implemented the FERC order effective January 1, 2006. 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.

Summary

Litigation, arbitration, regulatory matters, environmental matters and safety matters are subject to inherent uncertainties. Were an unfavorable ruling to occur, there exists the possibility of a material adverse impact on the results of operations in the period in which the ruling occurs. Management, including internal counsel, currently believes that the ultimate resolution of the foregoing matters, taken as a whole and after consideration of amounts accrued, insurance coverage, recovery from customers or other indemnification arrangements, will not have a materially adverse effect upon our future financial position.

Other Commitments

Commitments for construction and gas purchases We have commitments for construction and acquisition of property, plant and equipment of approximately $187 million at September 30, 2006. We have commitments for gas purchases of approximately $211 million at September 30, 2006.

4. DEBT AND FINANCING ARRANGEMENTS

Revolving Credit and Letter of Credit Facilities

In May 2006, Williams obtained an unsecured, three-year, $1.5 billion revolving credit facility, replacing the $1.275 billion secured revolving credit facility. The new unsecured facility contains similar terms and financial covenants as the secured facility, but contains additional restrictions on asset sales, certain subsidiary debt and sale-leaseback transactions. The facility is guaranteed by WGP, and Williams guarantees obligations of Williams Partners L.P. for up to $75 million. We have access to $400 million under the facility to the extent not otherwise utilized by Williams. Interest is calculated based on a choice of two methods: a fluctuating rate equal to the lender’s base rate plus an applicable margin or a periodic fixed rate equal to the London Interbank Offered Rate (LIBOR) plus an applicable margin. Williams is required to pay a commitment fee (currently 0.25 % annually) based on the unused portion of the facility. The margins and commitment fee are based on the specific borrower’s senior unsecured long-term debt ratings. Letters of credit totaling approximately $46 million, none of which are associated with us, have been issued by the participating institutions and no revolving credit loans were outstanding at September 30, 2006. Significant financial covenants under the credit agreement include the following:

	•		Williams’ ratio of debt to capitalization must be no greater than 65 percent;

	•		Our ratio of debt to capitalization must be no greater than 55 percent; and

	•		Williams’ ratio of EBITDA to interest, on a rolling four quarter basis, must be no less than 2.5 for the period ending December 31, 2007 and 3.0 for the remaining term of the agreement.

Issuance of Long-Term Debt

On April 11, 2006, we issued $200 million aggregate principal amount of unsecured notes to certain institutional investors in a private debt placement which pay interest at 6.4% per annum on April 15 and October 15 each year, beginning October 15, 2006 (6.4% Notes). The 6.4% Notes mature on April 15, 2016, but are subject to redemption at any time, at our option, in whole or part, at a specified redemption price, plus accrued and unpaid interest to the date of redemption. The net proceeds of the sale are being used for general corporate purposes, including the funding of capital expenditures.

In October 2006, we completed the exchange of the 6.4% Notes for substantially identical new notes that are registered under the Securities Act of 1933, as amended.

5. STOCK-BASED COMPENSATION

Plan Information

The Williams Companies, Inc. 2002 Incentive Plan (Plan) was approved by stockholders on May 16, 2002, and amended and restated on May 15, 2003, and January 23, 2004. The Plan provides for common-stock-based awards to both employees and nonmanagement directors. The Plan permits the granting of various types of awards including, but not limited to, stock options and deferred stock. Awards may be granted for no consideration other than prior and future services or based on certain financial performance targets being achieved.

Williams currently bills us directly for compensation expense related to stock-based compensation awards granted directly to our employees. We are also billed for our proportionate share of both WGP’s and Williams’ stock-based compensation expense though various allocation processes.

Accounting for Stock-Based Compensation

Prior to January 1, 2006, we accounted for the Plan under the recognition and measurement provisions of Accounting Principles Board (APB) Opinion No. 25, “Accounting for Stock Issued to Employees,” and related interpretations, as permitted by Financial Accounting Standards Board (FASB) Statement No. 123, “Accounting for Stock-Based Compensation” (SFAS No. 123). Compensation cost for stock options was not recognized in the Condensed Consolidated Statement of Income for the nine months ending September 30, 2005, as all stock options granted under the Plan had an exercise price equal to the market value of the underlying common stock on the date of the grant. Prior to January 1, 2006, compensation cost was recognized for deferred share awards. Effective January 1, 2006, we adopted the fair value recognition provisions of FASB Statement No. 123(R), “Share-Based Payment” (SFAS No. 123(R)), using the modified-prospective method. Under this method, compensation cost recognized in the first nine months of 2006 includes: (1) compensation cost for all share-based payments granted through December 31, 2005, but for which the requisite service period had not been completed as of December 31, 2005, based on the grant date fair value estimated in accordance with the original provisions of SFAS No. 123, and (2) compensation cost for most share-based payments granted subsequent to December 31, 2005, based on the grant date fair value estimated in accordance with the provisions of SFAS No. 123(R). The performance targets for certain performance based deferred shares have not been established and therefore expense is not currently recognized. Results for prior periods have not been restated.

Total stock-based compensation expense, included in administrative and general expenses, for the three and nine months ending September 30, 2006 was $0.4 million and $1.1 million, respectively, excluding amounts allocated from WGP and Williams.

6. TRANSACTIONS WITH AFFILIATES

Included in our operating revenues for the nine months ending September 30, 2006 and 2005 are revenues received from affiliates of $38.1 million and $68.3 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.

Through an agency agreement with us, WPC manages our remaining jurisdictional merchant gas sales. For the nine months ending September 30, 2005, included in our cost of sales is $5.5 million representing agency fees billed to us by WPC under the agency agreement. Due to the termination of our remaining Firm Sales agreements effective April 1, 2005, the agency fees billed by WPC for the nine months ending September 2006 were not significant.

Included in our cost of sales for the nine months ending September 30, 2006 and 2005 is purchased gas cost from affiliates, excluding the agency fees discussed above, $11.8 million and $68.3 million, respectively. All gas purchases are made at market or contract prices.

We have long-term gas purchase contracts containing variable prices that are currently in the range of estimated market prices. Our estimated purchase commitments under such gas purchase contracts are not material to our total gas purchases. Furthermore, through the agency agreement with us, WPC has assumed management of our merchant sales service and, as our agent, is at risk for any above-spot-market gas costs that it may incur.

Williams has a policy of charging 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 ending September 30, 2006 and 2005, are $40.6 million and $35.2 million, respectively, for such corporate expenses charged by Williams and other affiliated companies. Management considers the cost of these services to be reasonable.

Effective June 1, 2004 and pursuant to an operating agreement, we serve as contract operator on certain Williams Field Services Company (WFS) facilities. For the nine months ending September 30, 2006 and 2005, we recorded reductions in operating expenses for services provided to WFS for $5.7 million and $6.7 million respectively, under terms of the operating agreement.

ITEM 2. Management’s Narrative Analysis of the Results of Operations.

General

The following discussion should be read in conjunction with the consolidated financial statements, notes and management’s narrative analysis contained in Items 7 and 8 of our 2005 Annual Report on Form 10-K and in our 2006 First and Second Quarter Reports on Form 10-Q and with the condensed consolidated financial statements and notes contained in this report.

Restatement of Financial Results

We have accordingly restated the condensed consolidated statements of income for the three and nine months ending September 30, 2005 and cash flows for the nine months ending September 30, 2005. See “Item 1. Financial Statements” in this Form 10-Q.

For a discussion of additional information on the restatement, see “Item 1. Financial Statements – Notes to Condensed Consolidated Financial Statements – 2. Restatement.”

RESULTS OF OPERATIONS

Operating Income and Net Income

Our operating income for the nine months ended September 30, 2006 was $199.6 million compared to operating income of $268.6 million for the nine months ended September 30, 2005. Net income for the nine months ended September 30, 2006 was $104.2 million compared to $145.0 million for the nine months ended September 30, 2005. The lower operating income of $69.0 million was due to increases in cost of natural gas transportation, operation and maintenance expenses, administrative and general expenses, depreciation and amortization expenses and taxes other than income taxes, partially offset by a decrease in other expenses as discussed below. The decrease in net income of $40.8 million was mostly attributable to the decreased operating income partially offset by lower net expenses as discussed below in Other Income and Other Deductions.

Transportation Revenues

Our operating revenues related to transportation services of $571.3 million for the nine months ended September 30, 2006 were comparable to revenues of $572.2 million for the same period in 2005.

As shown in the table below, our total market-area deliveries for the nine months ended September 30, 2006 increased 4.0 trillion British Thermal Units (TBtu) (0.3%) when compared to the same period in

2005. Our production area deliveries for the nine months ended September 30, 2006 decreased 22.1 TBtu (10.4%) when compared to the same period in 2005. The net decrease in deliveries is primarily due to reduced demand resulting from the milder seasonal weather.


	Nine Months
	Ended September 30,
	2006		2005
Transco System Deliveries (TBtu)

Market-area deliveries:
Long-haul transportation		588.5		577.2
Market-area transportation		621.4		628.7

Total market-area deliveries		1,209.9		1,205.9
Production-area transportation		191.2		213.3

Total system deliveries		1,401.1		1,419.2

Average Daily Transportation Volumes (Tbtu)		5.1		5.2
Average Daily Firm Reserved Capacity (Tbtu)		6.6		6.6

Our facilities are divided into eight rate zones. Five are located in the production area and three are located in the market area. Long-haul transportation is gas that is received in one of the production-area zones and delivered in a market-area zone. Market-area transportation is gas that is both received and delivered within market-area zones. Production-area transportation is gas that is both received and delivered within production-area zones.

Sales Revenues

We make jurisdictional merchant gas sales pursuant to a blanket sales certificate issued by the FERC, with most of those sales previously having been made through a Firm Sales (FS) program which gave customers the option to purchase daily quantities of gas from us at market-responsive prices in exchange for a demand charge payment. Pursuant to the terms of an agreement with the FERC which resolved a prior investigation, we terminated our remaining FS agreements effective April 1, 2005.

Through an agency agreement, WPC manages our long-term purchase agreements and our remaining jurisdictional merchant gas sales, which excludes our cash out sales in settlement of gas imbalances. The long-term purchase agreements managed by WPC 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 that are managed by WPC. WPC receives all margins associated with jurisdictional merchant gas sales business and, as our agent, assumes all market and credit risk associated with our jurisdictional merchant gas sales. Consequently, our merchant gas sales service and the termination of the FS agreements in April 2005 have no impact on our operating income or results of operations.

In addition to our merchant gas sales, we also have cash out sales, which settle gas imbalances with shippers. In the course of providing transportation services to customers, we may receive different quantities of gas from shippers than the quantities delivered on behalf of those shippers. Additionally, we transport gas on various pipeline systems which may deliver different quantities of gas on our behalf than the quantities of gas received from us. These transactions result in gas transportation and exchange imbalance receivables and payables. Our tariff includes a method whereby the majority of transportation imbalances generated after August 1, 1991 are settled on a monthly basis through cash out sales or purchases. The cash out sales have no impact on our operating income or results of operations.

Operating revenues related to our sales services were $109.0 million for the nine months ended September 30, 2006, compared to $211.8 million for the same period in 2005. The decrease was primarily due to a lower volume of merchant sales because of the termination of the FS agreements during 2005. There were also lower cash out sales volumes related to the monthly settlement of imbalances.


	Nine Months
	Ended September 30,
Gas Sales Volumes (Tbtu)	2006		2005
Long-term sales		—		7.8
Short-term sales		2.4		5.8

Total gas sales		2.4		13.6

Storage Revenues

Our operating revenues related to storage services of $89.9 million for the nine months ended September 30, 2006 were comparable to revenues of $91.6 million for the same period in 2005.

Other Revenues

Our other operating revenues were $12.1 million for the nine months ended September 30, 2006 compared to $8.0 million for the same period in 2005. The increase was primarily due to higher environmental mitigation credit sales.

Operating Costs and Expenses

Excluding the cost of natural gas sales of $108.9 million for the nine months ended September 30, 2006 and $211.8 million for the comparable period in 2005, our operating expenses for the nine months ended September 30, 2006, were approximately $70.5 million higher than the comparable period in 2005. This increase was primarily attributable to higher cost of natural gas transportation, operation and maintenance expenses, administrative and general expenses, depreciation and amortization expense and taxes other than income taxes, partially offset by lower other expenses. The higher cost of natural gas transportation is primarily due to the absence of a 2005 positive adjustment of $14.2 million associated with our 1999 Fuel Tracker filing. The increase in operation and maintenance expense in 2006 of $16.3 million is due primarily to higher outside services of $6.5 million and higher material and supplies expenses of $2.5 million due primarily to integrity management assessment costs, and higher contract labor and services of $4.5 million. The increase in administrative and general expense of $36.6 million is mostly due to higher employee labor and benefits costs of $15.1 million, increased information systems costs of $10.0 million and higher property insurance of $6.8 million due to increased premiums on offshore facilities The increase in depreciation and amortization of $6.9 million was primarily due to higher expense associated with asset retirement obligations. The increase in taxes other than income taxes of $4.5 million is due to higher property taxes resulting from increased property values and additional capital spending and increased franchise taxes resulting from settlements of prior years audit issues. The lower other operating costs and expenses of $8.4 million were primarily due to a regulatory credit associated with asset retirement obligation depreciation expense of $5.4 million and a $2.0 million reduction of accrued liabilities for royalty claims associated with certain producer indemnities. See “Item 1. Financial Statements – Notes to Condensed Consolidated Financial Statements -3. Contingent Liabilities and Commitments.”

Other Income and Other Deductions

Other income and other deductions for the nine months ended September 30, 2006 resulted in lower net expense of $3.7 million compared to the same period in 2005. This was primarily due to a $5.0 million decrease in interest expense resulting from the reduction of accrued liabilities for royalty claims associated with certain producer indemnities. (See “Item 1. Financial Statements – Notes to Condensed Consolidated Financial Statements — 3. Contingent Liabilities and Commitments.”) The decrease was partially offset by increased interest expense primarily associated with the issuance of the 6.4% notes.

Method of Financing

In May 2006, Williams obtained an unsecured, three-year, $1.5 billion revolving credit facility, replacing the $1.275 billion secured revolving credit facility. The new unsecured facility contains similar terms and financial covenants as the secured facility but contains additional restrictions on asset sales, certain subsidiary debt and sale-leaseback transactions. The facility is guaranteed by WGP, and Williams guarantees obligations of Williams Partners L.P. for up to $75 million. We have access to $400 million under the facility to the extent not otherwise utilized by Williams. Interest is calculated based on a choice of two methods: a fluctuating rate equal to the lender’s base rate plus an applicable margin or a periodic fixed rate equal to LIBOR plus an applicable margin. Williams is required to pay a commitment fee (currently 0.25 % annually) based on the unused portion of the facility. The margins and commitment fee are based on the specific borrower’s senior unsecured long-term debt ratings. Letters of credit totaling approximately $46 million, none of which are associated with us, have been issued by the participating institutions and no revolving credit loans were outstanding at September 30, 2006. Significant financial covenants under the credit agreement include the following:

	•		Williams’ ratio of debt to capitalization must be no greater than 65 percent;

	•		Our ratio of debt to capitalization must be no greater than 55 percent; and

	•		Williams’ ratio of EBITDA to interest, on a rolling four quarter basis, must be no less than 2.5 for the period ending December 31, 2007 and 3.0 for the remaining term of the agreement.

In October 2006, we completed the exchange of the 6.4% Notes for substantially identical new notes that are registered under the Securities Act of 1933, as amended.

Capital Expenditures

As shown in the table below, our capital expenditures for the nine months ended September 30, 2006 were $253.3 million, compared to $174.8 million for the nine months ended September 30, 2005. We currently estimate that capital expenditures for the year 2006 will be approximately $305 million to $340 million compared to the projection of approximately $275 million to $310 million included in our 2005 Annual Report on Form 10-K.


	Nine months
	Ended September 30,
	2006		2005
	(In Millions)
			(Restated)
Expansion projects	$	11.0	$	17.1
Maintenance of existing facilities and other projects		242.3		157.7

Total capital expenditures	$	253.3	$	174.8

Our capital expenditures estimate for 2006 and future capital projects are discussed in our 2005 Annual Report on Form 10-K and 2006 First and Second Quarter Reports on Form 10-Q. The following describes those projects and any new capital projects proposed by us.

Leidy to Long Island Expansion Project The Leidy to Long Island Expansion Project will involve an expansion of our existing natural gas transmission system in Zone 6 from the Leidy Hub in Pennsylvania to Long Island, New York. The project will provide 100,000 dekatherms per day (dt/d) of incremental firm transportation capacity, which has been fully subscribed by one shipper for a twenty-year primary term. The project facilities will include pipeline looping in Pennsylvania and pipeline looping, uprating and replacement and a natural gas compressor facility in New Jersey. The estimated capital cost of the project is approximately $127 million. We expect that over three-quarters of the project expenditures will occur in 2007. We filed an application for FERC authorization of the project in December 2005, which the FERC approved by order issued on May 18, 2006. On October 20, 2006, we filed an application to amend the FERC authorizations to reflect our ownership of certain appurtenant facilities as part of the project and to adjust the cost of facilities and rates. The target in-service date for the project is November 1, 2007.

Potomac Expansion Project The Potomac Expansion Project will involve an expansion of our existing natural gas transmission system from receipt points in North Carolina to delivery points in the greater Baltimore and Washington, D.C. metropolitan areas. The project will provide 165,000 dt/d of incremental firm transportation capacity, which has been fully subscribed by shippers under long-term firm arrangements. The estimated capital cost of the project is approximately $74 million. We filed an application for FERC approval of the project on July 17, 2006. The target in-service date for the project is November 1, 2007.

Sentinel Expansion Project We held an open season from October 31, 2005 through December 2, 2005 to receive requests from potential shippers for new firm transportation capacity to be made available on the Transco pipeline system under our proposed Sentinel Expansion Project, the path of which extends from the Leidy Hub in Clinton County, Pennsylvania and/or the Pleasant Valley Interconnection with Cove Point LNG, in Fairfax County, Virginia to various delivery points requested by the shippers. We are in the process of negotiating precedent agreements with shippers. The final project size, location of facilities and capital cost will depend on the outcome of those negotiations. The estimated capital cost of the project is approximately $152 million to $169 million. In order to accommodate the requests of certain shippers, we are planning to place the incremental firm transportation capacity into service in two phases, the first phase commencing on November 1, 2008 and the second phase commencing on November 1, 2009.

ITEM 4. Controls and Procedures.

Evaluation of Disclosure Controls and Procedures

An evaluation of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rule 13a-15(e) and 15d-15(e) of the Securities Exchange Act) (Disclosure Controls) was performed as of the end of the period covered by this report. This evaluation was performed under the supervision and with the participation of our management, including our Senior Vice President and our Vice President and Treasurer. Based upon that evaluation, our Senior Vice President and our Vice President and Treasurer have concluded that our Disclosure Controls and procedures were effective at a reasonable assurance level.

Our management, including our Senior Vice President and our Vice President and Treasurer, does not expect that our 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 the Internal Controls will be modified as systems change and conditions warrant.

A material weakness is a control deficiency, or combination of control deficiencies, that results in more than a remote likelihood that a material misstatement of the annual or interim financial statements will not be prevented or detected.

During the fourth quarter of 2005 and as reported in our 2005 Annual Report on Form 10-K, we identified a material weakness in internal control over financial reporting associated with the absence of an effective control to identify to specific customers a material amount of transportation and exchange imbalance volumes, primarily for the period April 2003 to December 2004. These natural gas volumes represent gas received in excess of amounts delivered on our pipeline systems that have not yet been associated with specific transportation contracts and related customers, and are recorded within Transportation and Exchange Gas Payables in our consolidated balance sheet. In 2005, we implemented controls designed to prevent the repetition of this failure of identification in future periods. In the second quarter of 2006, we began performing analyses of historical data pertaining to transportation and exchange imbalance volumes and utilizing new system reporting tools that will assist us in identifying the natural gas volumes relative to 2003 and 2004 to specific transportation contracts and related customers. We expect this analysis to be completed in the first half of 2007.

Changes in Internal Control over Financial Reporting

There have been no changes during the third quarter of 2006 that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.

PART II — OTHER INFORMATION

ITEMS 1. LEGAL PROCEEDINGS.

See discussion in Note 3 of the Notes to Condensed Consolidated Financial Statements included herein.

ITEM 1A. RISK FACTORS.

There are no material changes to the Risk Factors previously disclosed in Part I, Item 1A. Risk Factors in our Annual Report on Form 10-K for the year ended December 31, 2005.

ITEM 6. EXHIBITS

The following instruments are included as exhibits to this report. Those exhibits below incorporated by reference herein are indicated as such by the information supplied in the parenthetical thereafter. If no parenthetical appears after an exhibit, copies of the instrument have been included herewith.

(31)

Section 302 Certifications


-	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.

-	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)

Section 906 Certification


-				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.


	September 30,		December 31,
	2006		2005
ASSETS
Current Assets:

Cash	$	190	$	362
Receivables:
Affiliates		5,736		4,374
Advances to affiliates		173,691		130,307
Others, less allowance of $518 ($509 in 2005)		86,844		93,827
Transportation and exchange gas receivables		11,190		9,906
Inventories		90,599		82,680
Deferred income taxes		26,957		15,283
Other		28,328		17,663

Total current assets		423,535		354,402


Investments, at cost plus equity in undistributed earnings		44,645		44,108


Property, Plant and Equipment:
Natural gas transmission plant		6,467,117		6,134,951
Less-Accumulated depreciation and amortization		1,897,092		1,776,946

Total property, plant and equipment, net		4,570,025		4,358,005


Other Assets		262,941		257,835


Total assets	$	5,301,146	$	5,014,350


	TRANSCONTINENTAL GAS PIPE LINE
	CORPORATION (Registrant)

Dated: November 6, 2006	By	/s/ Jeffrey P. Heinrichs

	Jeffrey P. Heinrichs
	Controller
	(Principal Accounting Officer)


Date: November 6, 2006

By:		/s/Phillip D. Wright

		Phillip D. Wright
		Senior Vice President
		(Principal Executive Officer)


Date: November 6, 2006

By:		/s/ Richard D. Rodekohr

		Richard D. Rodekohr
		Vice President and Treasurer
		(Principal Financial Officer)


/s/ Phillip D. Wright
Phillip D. Wright
Senior Vice President
November 6, 2006

/s/ Richard D. Rodekohr
Richard D. Rodekohr
Vice President and Treasurer
November 6, 2006

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

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

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

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

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

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

	c)		Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the period covered by the report that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

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

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