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, 2007


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, 2007 was 100.

REGISTRANT MEETS THE CONDITIONS SET FORTH IN GENERAL INSTRUCTIONS H (1)2
(a) AND (b) OF FORM 10-Q AND IS THEREFORE FILING THIS FORM 10-Q WITH THE REDUCED DISCLOSURE FORMAT.

TRANSCONTINENTAL GAS PIPE LINE CORPORATION
INDEX


	Page
PART I. FINANCIAL INFORMATION:

Item 1. Financial Statements -

Condensed Consolidated Statements of Income for the three and nine months ended September 30, 2007 and 2006		4

Condensed Consolidated Balance Sheets as of September 30, 2007 and December 31, 2006		5

Condensed Consolidated Statements of Cash Flows for the nine months ended September 30, 2007 and 2006		7

Notes to Condensed Consolidated Financial Statements		8

Item 2. Management’s Narrative Analysis of the Results of Operations		14

Item 4. Controls and Procedures		18

PART II. OTHER INFORMATION		19

Item 1. Legal Proceedings		19

Item 1A. Risk Factors		19

Item 6. Exhibits		19
Certification of Principal Executive Officer Pursuant to Section 302
Certification of Principal Financial Officer Pursuant to Section 302
Certification Pursuant to Section 906

Certain matters contained in this report include “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. These statements 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.

All statements, other than statements of historical facts, included in this report which address activities, events or developments that we expect, believe or anticipate will exist or may occur in the future, are forward-looking statements. Forward-looking statements can be identified by various forms of words such as “anticipates,” “believes,” “could,” “may,” “should,” “continues,” “estimates,” “expects,” “forecasts,” “might,” “planned,” “potential,” “projects,” “scheduled” or similar expressions. These forward-looking statements include, among others, statements regarding:

	•		Amounts and nature of future capital expenditures;

	•		Expansion and growth of our business and operations;

	•		Business strategy;

	•		Cash flow from operations;

	•		Power and natural gas prices and demand.

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

	•		Availability of supplies (including the uncertainties inherent in assessing and estimating future natural gas reserves), market demand, volatility of prices, and increased costs of capital;

	•		Inflation, interest rates and general economic conditions;

	•		The strength and financial resources of our competitors;

	•		Development of alternative energy sources;

	•		The impact of operational and development hazards;

	•		Costs of, changes in, or the results of laws, government regulations including proposed climate change legislation, environmental liabilities, litigation, and rate proceedings;

	•		Changes in the current geopolitical situation;

	•		Risks related to strategy and financing, including restrictions stemming from our debt agreements and our lack of investment grade credit ratings; and

	•		Risk associated with future weather conditions and acts of terrorism.

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

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

Because forward-looking statements involve risks and uncertainties, we caution that there are important factors, in addition to those listed above, that may cause actual results to differ materially from those contained in the forward-looking statements. For a detailed discussion of those factors, see Part I, Item 1A. Risk Factors in our Annual Report on Form 10-K for the year ended December 31, 2006 and our 2007 First and Second Quarter Reports on Form 10-Q.

PART 1 — FINANCIAL INFORMATION

ITEM 1. Financial Statements.

TRANSCONTINENTAL GAS PIPE LINE CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(Thousands of Dollars)

(Unaudited)


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2007			2006			2007			2006
Operating Revenues:
Natural gas sales	$	36,546		$	41,076		$	127,785		$	108,959
Natural gas transportation		215,059			188,518			627,245			571,320
Natural gas storage		36,036			29,867			104,402			89,883
Other		1,047			2,355			17,546			12,057

Total operating revenues		288,688			261,816			876,978			782,219


Operating Costs and Expenses:
Cost of natural gas sales		36,547			41,067			127,715			108,948
Cost of natural gas transportation		3,005			2,663			8,446			9,237
Operation and maintenance		55,698			56,441			167,094			162,272
Administrative and general		36,647			48,121			114,339			116,038
Depreciation and amortization		57,590			51,530			168,762			154,117
Taxes — other than income taxes		11,424			12,741			40,002			39,413
Other (income) expense, net		4,143			(2,592	)		8,468			(7,405	)

Total operating costs and expenses		205,054			209,971			634,826			582,620


Operating Income		83,634			51,845			242,152			199,599


Other (Income) and Other Deductions:
Interest expense		24,097			23,489			70,721			61,503
Interest income — affiliates		(3,830	)		(4,310	)		(11,755	)		(10,867	)
Allowance for equity and borrowed funds used during construction (AFUDC)		(5,463	)		(3,161	)		(10,176	)		(8,530	)
Equity in earnings of unconsolidated affiliates		(1,717	)		(1,983	)		(5,114	)		(5,729	)
Miscellaneous other (income) deductions, net		(2,933	)		(1,859	)		(7,453	)		(4,973	)

Total other (income) and other deductions		10,154			12,176			36,223			31,404


Income before Income Taxes		73,480			39,669			205,929			168,195

Provision for Income Taxes		27,927			15,320			78,632			64,009


Net Income	$	45,553		$	24,349		$	127,297		$	104,186

See accompanying notes.

TRANSCONTINENTAL GAS PIPE LINE CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

(Thousands of Dollars)

(Unaudited)


	September 30,		December 31,
	2007		2006
ASSETS
Current Assets:
Cash	$	117	$	315
Receivables:
Affiliates		5,327		7,814
Advances to affiliates		152,780		190,399
Others, less allowance of $503 ($503 in 2006)		100,108		84,445
Transportation and exchange gas receivables		13,413		7,075
Inventories		70,131		64,821
Deferred income taxes		20,726		17,414
Other		40,562		28,557

Total current assets		403,164		400,840


Investments, at cost plus equity in undistributed earnings		44,866		44,820


Property, Plant and Equipment:
Natural gas transmission plant		6,780,551		6,475,172
Less-Accumulated depreciation and amortization		2,056,486		1,939,430

Total property, plant and equipment, net		4,724,065		4,535,742


Other Assets		247,291		300,587


Total assets	$	5,419,386	$	5,281,989

See accompanying notes.

TRANSCONTINENTAL GAS PIPE LINE CORPORATION

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


	September 30,			December 31,
	2007			2006
LIABILITIES AND STOCKHOLDER’S EQUITY
Current Liabilities:
Payables:
Affiliates	$	19,004		$	23,007
Other		122,922			113,418
Transportation and exchange gas payables		16,438			14,693
Accrued liabilities		170,955			112,062
Current maturities of long-term debt		174,979			—

Total current liabilities		504,298			263,180


Long-Term Debt		1,027,155			1,201,458


Other Long-Term Liabilities:
Deferred income taxes		1,035,552			1,013,282
Other		265,696			265,633

Total other long-term liabilities		1,301,248			1,278,915


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		962,149			914,851
Accumulated other comprehensive loss		(27,894	)		(28,845	)

Total common stockholder’s equity		2,586,685			2,538,436


Total liabilities and stockholder’s equity	$	5,419,386		$	5,281,989

See accompanying notes.

TRANSCONTINENTAL GAS PIPE LINE CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Thousands of Dollars)

(Unaudited)


	Nine Months Ended
	September 30,
	2007			2006
Cash flows from operating activities:
Net income	$	127,297		$	104,186
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Depreciation and amortization		169,920			152,361
Deferred income taxes		18,369			46,882
Allowance for equity funds used during construction (Equity AFUDC)		(7,420	)		(6,380	)
Changes in operating assets and liabilities:
Receivables — affiliates		2,487			(1,362	)
— others		(15,663	)		6,983
Transportation and exchange gas receivables		(6,338	)		(1,284	)
Inventories		(5,310	)		(7,919	)
Payables — affiliates		(4,003	)		(7,760	)
— others		(4,660	)		(3,195	)
Transportation and exchange gas payables		1,745			(23,112	)
Accrued liabilities		58,893			(49,643	)
Other, net		24,219			(15,611	)

Net cash provided by operating activities		359,536			194,146


Cash flows from financing activities:
Additions of long-term debt		—			200,000
Debt issue costs		(10	)		(3,187	)
Change in cash overdrafts		(894	)		(2,023	)
Common stock dividends paid		(80,000	)		(95,000	)

Net cash provided by (used in) financing activities		(80,904	)		99,790


Cash flows from investing activities:
Property, plant and equipment:
Additions, net of equity AFUDC		(314,121	)		(265,066	)
Changes in accounts payable		15,058			16,032
Advances to affiliates, net		37,619			(43,384	)
Advances to others, net		651			745
Other, net		(18,037	)		(2,435	)

Net cash used in investing activities		(278,830	)		(294,108	)


Net decrease in cash		(198	)		(172	)
Cash at beginning of period		315			362

Cash at end of period	$	117		$	190

See accompanying notes.

TRANSCONTINENTAL GAS PIPE LINE CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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 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, 2007, and results of operations for the three and nine months ended September 30, 2007 and 2006, and cash flows for the nine months ended September 30, 2007 and 2006. These condensed consolidated financial statements should be read in conjunction with the consolidated financial statements and the notes thereto included in our 2006 Annual Report on Form 10-K and our 2007 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 $20 million on March 30, 2007, $20 million on June 29, 2007 and $40 million on September 28, 2007.

Comprehensive income for the three and nine months ended September 30, 2007 and 2006, respectively, is as follows (in thousands):


	Three Months						Nine Months
	Ended September 30,						Ended September 30,
	2007			2006			2007			2006
Net income	$	45,553		$	24,349		$	127,297		$	104,186
Equity interest in unrealized gain/(loss) on interest rate hedge, net of tax		(132	)		(150	)		(18	)		134
Pension benefits, net of tax
Amortization of prior service credit		(256	)		—			(767	)		—
Amortization of net actuarial loss		579			—			1,736			—

Total comprehensive income	$	45,744		$	24,199		$	128,248		$	104,320

Effective January 1, 2007, 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 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 as the largest amount of benefit, determined on a cumulative probability basis, 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 adopted FIN 48 beginning January 1, 2007, as required. The adoption of FIN 48 did not have a material effect on our consolidated financial position or results of operations.

Our policy is to recognize interest and penalties related to unrecognized tax benefits as a component of income tax expense.

As of January 1, 2007, the Internal Revenue Service (IRS) examination of Williams’ consolidated U.S. income tax return including 2002 was in process. The Williams’ consolidated U.S. income tax return incorporates our tax information. During the first quarter of 2007 the IRS also commenced examination of the 2003 through 2005 consolidated U.S. income tax returns of Williams. IRS examinations for 1996 through 2001 have been completed but the years remain open while certain issues are under review with the Appeals Division of the IRS. The statute of limitations for most states expires one year after IRS audit settlement.

FERC Accounting and Reporting Guidance

On March 29, 2007, the Federal Energy Regulatory Commission (FERC) issued “Commission Accounting and Reporting Guidance to Recognize the Funded Status of Defined Benefit Postretirement Plans.” The guidance is being provided to all jurisdictional entities to ensure proper and consistent implementation of Statement of Financial Accounting Standards No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans-an amendment of FASB Statements No. 87, 88, 106 and 132 (R)” for FERC financial reporting purposes beginning with the 2007 FERC Form 2 to be filed in 2008. We completed our evaluation and applied the FERC guidance during the second quarter of 2007. It had no effect on our financial statements.

Certain reclassifications have been made in the 2006 financial statements to conform to the 2007 presentation, including changes in capital related accounts payable as investing activities in the condensed consolidated statement of cash flows.

2. RATE AND REGULATORY MATTERS

On March 1, 2001, we submitted to the FERC a general rate filing (Docket No. RP01-245) to recover increased costs. The rates became effective on September 1, 2001. All cost of service, throughput and throughput mix issues in this rate proceeding have been resolved by settlement or litigation. Certain cost allocation, rate design and tariff matters in this proceeding have not yet been resolved. We believe the resolution of these matters will not have a materially adverse effect upon our future financial position.

On August 31, 2006, we submitted to the FERC a general rate filing (Docket No. RP06-569) 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. The rates became effective March 1, 2007, subject to refund and the outcome of a hearing. Transco and its customers have reached an agreement in principle on all substantive issues in the rate case. Final resolution of the rate case is subject to the filing of a formal stipulation and agreement and subsequent approval by the FERC. We expect to file the formal stipulation and agreement with FERC in the fourth quarter. We have provided a reserve for rate refunds which we believe is adequate for any refunds that may be required.

3. CONTINGENT LIABILITIES AND COMMITMENTS

Legal Proceedings

By order dated March 17, 2003, the FERC approved a settlement between the FERC staff and Williams, WPC and us which resolved certain of FERC staff 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. The final $4 million installment was paid in the second quarter of 2007.

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 May 2005, the court-appointed special master entered a report which recommended that many of the cases be dismissed, including the case pending against us and certain of the Williams defendants. On October 20, 2006, the District Court dismissed all claims against us. Mr. Grynberg filed a Notice of Appeal from the dismissals with the Tenth Circuit Court of Appeals effective November 17, 2006.

Environmental Matters

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 various federal and state statutes will total approximately $11 million to $13 million (including both expense and capital expenditures), measured on an undiscounted basis, and will be spent over the next five to seven 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, 2007, we had a balance of approximately $5.2 million for the expense portion of these estimated costs recorded in current liabilities ($1.2 million) and other long-term liabilities ($4.0 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, less amounts collected, have also been recorded as regulatory assets in Current Assets: Other and Other Assets in the accompanying Condensed Consolidated Balance Sheet. At September 30, 2007, we had recorded approximately $3.6 million of environmental related regulatory assets.

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 parties concerning investigative and remedial actions relative to potential mercury contamination at certain gas metering sites. All such costs are included in the $11 million to $13 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 The Comprehensive Environmental Response, Compensation and Liability Act (and applicable state law) can be joint and several with other PRPs. Although volumetric allocation is a factor in assessing liability, it is not necessarily determinative; thus, the ultimate liability could be substantially greater than the amounts described above.

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. Pursuant to requirements of the 1990 Amendments, and EPA rules designed to mitigate the migration of ground-level ozone (NOx), 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. 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 $25 million to $35 million for the period 2007 through 2010. EPA’s designation of eight-hour ozone 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.

By letter dated September 20, 2007, the EPA required Transco to provide information regarding natural gas compressor stations in the states of Mississippi and Alabama as part of EPA’s investigation of Transco’s compliance with the Clean Air Act. We are preparing our response.

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 $325 million and $375 million over the remaining assessment period of 2007 through 2012. Management considers the costs associated with compliance with the rule to be prudent costs incurred in the ordinary course of business and, therefore, recoverable through our rates.

Other Matters

In addition to the foregoing, various other proceedings are pending against us incidental to our operations.

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 $165 million at September 30, 2007, which is expected to be spent in the fourth quarter of 2007 and in 2008. We have commitments for gas purchases of approximately $177 million at September 30, 2007, which is expected to be spent over the next eleven years.

Guarantees

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.

4. DEBT AND FINANCING ARRANGEMENTS

Revolving Credit and Letter of Credit Facilities

Under Williams’ $1.5 billion unsecured revolving credit facility, letters of credit totaling $28 million, none of which were issued on our behalf, have been issued by the participating institutions and no revolving credit loans were outstanding under the facility at September 30, 2007.

On May 9, 2007, Williams amended its $1.5 billion unsecured credit facility, extending the maturity date from May 1, 2009 to May 1, 2012. Applicable borrowing rates and commitment fees for investment grade credit ratings were also modified.

Current Maturities of Long-Term Debt

The current maturities of long-term debt at September 30, 2007 are associated with $100 million of 6.25% Notes that mature on January 15, 2008 and $75 million of our Floating Rate Notes that mature on April 15, 2008. It is our intent to refinance this debt.

5. TRANSACTIONS WITH AFFILIATES

Included in our operating revenues for the nine months ending September 30, 2007 and 2006 are revenues received from affiliates of $32.0 million and $38.1 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. The agency fees billed by WPC under the agency agreement for the nine months ending September 30, 2007 and 2006 were not significant.

Included in our cost of sales for the nine months ending September 30, 2007 and 2006 is purchased gas cost from affiliates of $8.3 million and $11.8 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, 2007 and 2006, are $37.9 million and $40.6 million, respectively, for such corporate expenses charged by Williams and other affiliated companies. Management considers the cost of these services to be reasonable.

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, 2007 and 2006, we recorded reductions in operating expenses for services provided to WFS for $4.4 million and $5.7 million, respectively, under terms of the operating agreement.

ITEM 2. Management’s Narrative Analysis of 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 2006 Annual Report on Form 10-K and in our 2007 First and Second Quarter Reports on Form 10-Q and with the condensed consolidated financial statements and notes contained in this report.

RESULTS OF OPERATIONS

Operating Income and Net Income

Our operating income for the nine months ended September 30, 2007 was $242.2 million compared to operating income of $199.6 million for the nine months ended September 30, 2006. Net income for the nine months ended September 30, 2007 was $127.3 million compared to $104.2 million for the nine months ended September 30, 2006. The increase in operating income of $42.6 million (21.3%) was due primarily to an increase in operating revenues, partially offset by increases in operation and maintenance expenses, depreciation and amortization expenses, other operating costs and expenses and other less significant variances, as discussed below. The increase in net income of $23.1 million (22.2%) was mostly attributable to the higher operating income partly offset by an increase in interest expense as discussed below in Other Income and Other Deductions.

Transportation Revenues

Our operating revenues related to transportation services for the nine months ended September 30, 2007 were $627.2 million, compared to $571.3 million for the nine months ended September 30, 2006. The 9.8% increase was primarily due to the effects of placing into effect, subject to refund, the rates in Docket No. RP06-569, on March 1, 2007 and slightly higher market area deliveries.

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.

As shown in the table below, our total market-area deliveries for the nine months ended September 30, 2007 increased 74.3 trillion British Thermal Units (TBtu) (6.1%) when compared to the same period in 2006. The increased deliveries are primarily the result of the colder weather experienced in Transco’s northeast markets in the first quarter of 2007 compared to the same period in 2006 as well as warmer temperatures experienced in Transco’s southeast markets during the third quarter of 2007 compared to the same period in 2006. Our production-area deliveries for the nine months ended September 30, 2007 decreased 45.2 TBtu (23.6%) compared to the same period in 2006. The reduction in production area deliveries is due primarily to declining production from the offshore area. Despite this reduction in production area deliveries we were able to increase market area deliveries, primarily due to an increase in receipts from mainline interconnect points.


	Nine months
	Ended September 30,
Transco System Deliveries (TBtu)	2007		2006
Market-area deliveries:
Long-haul transportation		621.7		588.5
Market-area transportation		662.5		621.4

Total market-area deliveries		1,284.2		1,209.9
Production-area transportation		146.0		191.2

Total system deliveries		1,430.2		1,401.1


Average Daily Transportation Volumes (TBtu)		5.2		5.1
Average Daily Firm Reserved Capacity (TBtu)		6.5		6.6

Sales Revenues

We make jurisdictional merchant gas sales pursuant to a blanket sales certificate issued by the FERC. 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 has 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 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 $127.8 million for the nine months ended September 30, 2007, compared to $109.0 million for the same period in 2006. The 17.2% increase was primarily due to the sales of $37.0 million excess top gas from our Eminence storage field. Transco requested authorization from the FERC to sell the excess Eminence top gas inventory and retain any gain on the sales. The FERC authorized the top gas sales, but consolidated the issue of Transco’s request to retain the gain on the sales with Transco’s general rate case. Therefore, the gain on the sales of the excess top gas, which was $14.3 million, has been deferred pending resolution of this issue.

Storage Revenues

Our operating revenues related to storage services were $104.4 million for the nine months ended September 30, 2007 compared to $89.9 million for the same period in 2006. The 16.1% increase was primarily due to the effects of placing into effect, subject to refund, the rates in Docket No. RP06-569, on March 1, 2007.

Other Revenues

Our other operating revenues were $17.5 million for the nine months ended September 30, 2007 compared to $12.1 million for the same period in 2006. The increase of $5.4 million (44.6%) was primarily due to an $11.1 million increase of Park and Loan Service revenue, partially offset by a $5.5 million decrease in environmental mitigation credit sales. The trend of the increased Park and Loan Service revenues is not expected to continue throughout the year.

Operating Costs and Expenses

Excluding the cost of natural gas sales of $127.7 million for the nine months ended September 30, 2007 and $108.9 million for the comparable period in 2006, our operating expenses for the nine months ended September 30, 2007, were approximately $33.4 million (7.1%) higher than the comparable period in 2006. This increase was primarily attributable to higher operation and maintenance expenses, higher depreciation and amortization expense and higher other expenses. The increase in operation and maintenance expenses in 2007 of $4.8 million is due primarily to higher employee labor and benefit costs resulting from higher levels of employment in addition to slightly higher levels of compensation. The increase in depreciation and amortization of $14.6 million was primarily due to higher expense associated with negative salvage. Other operating costs and expenses were $15.9 million higher primarily due to increased expenses of $13.8 million associated with our asset retirement obligations (AROs) due to the new rates in Docket No. RP06-569, effective March 1, 2007, subject to refund (See Note 2). In 2006, depreciation expense and accretion expense for AROs of $7.5 million was deferred as a regulatory asset to be recovered through the rates in Docket RP06-569. Effective March 1, 2007, we began collecting amounts for AROs and started amortizing the regulatory asset to expense. In addition, in 2007 we recognized accretion expense of $5.9 million. The variance was also due to the absence of a 2006 reduction of $2.0 million of accrued liabilities for royalty claims associated with certain producer indemnities.

Other Income and Other Deductions

Other income and other deductions for the nine months ended September 30, 2007 resulted in higher net expense of $4.8 million (15.3%) compared to the same period in 2006. This was primarily due to the absence of a 2006 decrease in interest expense of $5.0 million resulting from the reduction of accrued liabilities for royalty claims associated with certain producer indemnities.

Capital Expenditures

Our capital expenditures for the nine months ended September 30, 2007 were $314.1 million, compared to $265.1 million for the nine months ended September 30, 2006. Our capital expenditures estimate for 2007 and future capital projects are discussed in our 2006 Annual Report on Form 10-K. The following describes those projects and certain new capital projects proposed by us.

Leidy to Long Island Expansion Project The Leidy to Long Island Expansion Project involves an expansion of our existing natural gas transmission system in Zone 6 from the Leidy Hub in Pennsylvania to Long Island, New York. The capital cost of the project is estimated to be up to approximately $163 million. The project is expected to be placed into service in December 2007.

Potomac Expansion Project The Potomac Expansion Project involves 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 capital cost of the project is estimated to be up to approximately $88 million. The project is expected to be placed in service in November 2007.

Sentinel Expansion Project The Sentinel Expansion Project will involve an expansion of our existing natural gas transmission system from the Leidy Hub in Clinton County, Pennsylvania and from the Pleasant Valley interconnection with Cove Point LNG in Fairfax County, Virginia to various delivery points requested by the shippers under the project. The capital cost of the project is estimated to be up to approximately $169 million.

Transco plans to place the project into service in phases, in late 2008 and late 2009.

Pascagoula Expansion Project The Pascagoula Expansion Project will involve the construction of a new pipeline to be jointly owned with Florida Gas Transmission connecting Transco’s existing Mobile Bay Lateral to the outlet pipeline of a proposed liquefied natural gas import terminal in Mississippi. Transco’s share of the estimated capital cost of the project is up to $37 million. Transco plans to place the project into service on or about October 1, 2011.

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.

Third Quarter 2007 Changes in Internal Control over Financial Reporting

There have been no changes during the third quarter of 2007 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, 2006.

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.


		TRANSCONTINENTAL GAS PIPE LINE CORPORATION (Registrant)

Dated: November 5, 2007		By /s/ Jeffrey P. Heinrichs
		Jeffrey P. Heinrichs
		Controller
		(Principal Accounting Officer)


By:		/s/Phillip D. Wright Phillip D. Wright
		Senior Vice President
		(Principal Executive Officer)


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 5, 2007

/s/ Richard D. Rodekohr Richard D. Rodekohr
Vice President and Treasurer
November 5, 2007

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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.