UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended March 31, 2012

OR

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

For the transition period from              to             

Commission file number 1-7584

TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC

(Exact name of registrant as specified in its charter)

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

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

NO CHANGE

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

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

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

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

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

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

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

TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC

Index

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

Forward Looking Statements

Certain matters contained in this report include “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. These forward-looking statements relate to anticipated financial performance, management’s plans and objectives for future operations, business prospects, outcome of regulatory proceedings, market conditions and other matters. We make these forward-looking statements in reliance on the safe harbor protections provided under the Private Securities Litigation Reform Act of 1995.

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

• Amounts and nature of future capital expenditures;

• Expansion and growth of our business and operations;

• Financial condition and liquidity;

• Business strategy;

• Cash flow from operations or results of operations;

• Rate case filings; and

• Natural gas prices and demand.

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

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

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

• The strength and financial resources of our competitors;

• Development of alternative energy sources;

• The impact of operational and development hazards;

• Costs of, changes in, or the results of laws, government regulations (including safety and climate change regulation and changes in natural gas production from exploration and production areas that we serve), environmental liabilities, litigation, and rate proceedings;

• Our allocated costs for defined benefit pension plans and other postretirement benefit plans sponsored by our affiliates;

• Changes in maintenance and construction costs;

• Changes in the current geopolitical situation;

• Our exposure to the credit risks of our customers and counterparties;

• Risks related to strategy and financing, including restrictions stemming from our debt agreements, future changes in our credit ratings, and the availability and cost of credit;

• Risks associated with future weather conditions;

• Acts of terrorism, including cybersecurity threats and related disruptions; and

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

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

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

Because forward-looking statements involve risks and uncertainties, we caution that there are important factors, in addition to those listed above, that may cause actual results to differ materially from those contained in the forward-looking statements. For a detailed discussion of those factors, see Part I, Item 1A. Risk Factors in our Annual Report on Form 10-K for the year ended December 31, 2011.

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PART I – FINANCIAL INFORMATION

ITEM 1. Financial Statements.

TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC

CONDENSED CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME

(Thousands of Dollars)

(Unaudited)

	Three Months Ended March 31,
	2012			2011
Operating Revenues:
Natural gas sales	$	10,146		$	27,042
Natural gas transportation		262,467			240,376
Natural gas storage		35,750			36,820
Other		1,516			1,118
Total operating revenues		309,879			305,356
Operating Costs and Expenses:
Cost of natural gas sales		10,146			27,042
Cost of natural gas transportation		11,383			11,364
Operation and maintenance		59,353			59,435
Administrative and general		48,170			42,786
Depreciation and amortization		65,995			64,243
Taxes - other than income taxes		13,593			13,535
Other (income) expense, net		7,781			(9,850	)
Total operating costs and expenses		216,421			208,555
Operating Income		93,458			96,801
Other (Income) and Other Deductions:
Interest expense		23,718			23,822
Interest income - affiliates		(7	)		(10	)
Allowance for equity and borrowed funds used during construction (AFUDC)		(3,511	)		(5,337	)
Equity in earnings of unconsolidated affiliates		(1,536	)		(1,318	)
Miscellaneous other (income) deductions, net		11			(2,042	)
Total other (income) and other deductions		18,675			15,115
Net Income		74,783			81,686
Equity interest in unrealized gain (loss) on interest rate hedge		(25	)		31
Comprehensive Income	$	74,758		$	81,717

See accompanying notes.

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TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC

CONDENSED CONSOLIDATED BALANCE SHEET

(Thousands of Dollars)

(Unaudited)

	March 31, 2012		December 31, 2011
ASSETS
Current Assets:
Cash	$	102	$	164
Receivables:
Affiliates		747		5,903
Advances to affiliates		293,366		253,611
Others, less allowance of $407 ($407 in 2011)		125,118		121,589
Transportation and exchange gas receivables		2,375		4,914
Inventories		36,501		35,608
Regulatory assets		38,116		37,877
Other		6,435		12,973
Total current assets		502,760		472,639
Investments, at cost plus equity in undistributed earnings		61,518		56,994
Property, Plant and Equipment:
Natural gas transmission plant		8,147,494		8,089,338
Less-Accumulated depreciation and amortization		2,825,658		2,801,104
Total property, plant and equipment, net		5,321,836		5,288,234
Other Assets:
Regulatory assets		205,622		207,945
Other		49,421		50,471
Total other assets		255,043		258,416
Total assets	$	6,141,157	$	6,076,283

(continued)

See accompanying notes.

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TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC

CONDENSED CONSOLIDATED BALANCE SHEET

(Thousands of Dollars)

(Unaudited)

	March 31, 2012			December 31, 2011
LIABILITIES AND OWNER’S EQUITY
Current Liabilities:
Payables:
Affiliates	$	31,439		$	16,937
Other		93,136			108,706
Transportation and exchange gas payables		1,902			2,784
Accrued liabilities		136,902			140,390
Current maturities of long-term debt		324,609			324,321
Total current liabilities		587,988			593,138
Long-Term Debt		1,029,426			1,029,397
Other Long-Term Liabilities:
Asset retirement obligations		241,192			245,365
Regulatory liabilities		202,462			182,848
Other		6,237			6,182
Total other long-term liabilities		449,891			434,395
Contingent liabilities and commitments (Note 2)
Owner’s Equity:
Member’s capital		1,875,888			1,841,888
Retained earnings		2,198,335			2,177,811
Accumulated other comprehensive income (loss)		(371	)		(346	)
Total owner’s equity		4,073,852			4,019,353
Total liabilities and owner’s equity	$	6,141,157		$	6,076,283

See accompanying notes.

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TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC

CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS

(Thousands of Dollars)

(Unaudited)

	Three months ended March 31,
	2012			2011
Cash flows from operating activities:
Net income	$	74,783		$	81,686
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Depreciation and amortization		66,102			64,321
Allowance for equity funds used during construction (Equity AFUDC)		(2,414	)		(3,704	)
Changes in operating assets and liabilities:
Receivables  - affiliates		5,156			2,267
- others		(3,529	)		7,583
Transportation and exchange gas receivable		2,539			(3,475	)
Inventories		(892	)		4,976
Payables   - affiliates		14,502			6,103
- others		(24,137	)		7,527
Accrued liabilities		(7,866	)		5,869
Asset retirement obligation removal costs		(7,873	)		(442	)
Other, net		9,131			3,718
Net cash provided by operating activities		125,502			176,429
Cash flows from financing activities:
Cash distributions		(54,259	)		(45,000	)
Cash contributions from parent		34,000			40,000
Other, net		(5,931	)		(6,032	)
Net cash used in financing activities		(26,190	)		(11,032	)
Cash flows from investing activities:
Property, plant and equipment additions, net of equity AFUDC*		(61,611	)		(84,626	)
Disposal of property, plant and equipment, net		3,438			(8,066	)
Advances to affiliates, net		(39,755	)		(72,060	)
Purchase of long-term investments		(3,998	)		(5,914	)
Purchase of ARO Trust investments		(7,766	)		(4,576	)
Proceeds from sale of ARO Trust investments		10,305			7,841
Other, net		13			1,963
Net cash used in investing activities		(99,374	)		(165,438	)
Increase (decrease) in cash		(62	)		(41	)
Cash at beginning of period		164			148
Cash at end of period	$	102		$	107
*        Increase to property, plant and equipment	$	(80,361	)	$	(85,712	)
Changes in related accounts payable and accrued liabilities		18,750			1,086
Property, plant and equipment additions, net of equity AFUDC	$	(61,611	)	$	(84,626	)

See accompanying notes.

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TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1. BASIS OF PRESENTATION.

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

Transco is owned, through Williams Partners Operating LLC (WPO), by Williams Partners L.P. (WPZ), a publicly traded Delaware limited partnership, which is consolidated by The Williams Companies, Inc. (Williams). At March 31, 2012, Williams holds an approximate 72 percent interest in WPZ, comprised of an approximate 70 percent limited partner interest and all of WPZ’s 2 percent general partner interest.

General.

The condensed consolidated unaudited financial statements include our accounts and the accounts of the subsidiaries we control. Companies in which we and our subsidiaries own 20 percent to 50 percent of the voting common stock or otherwise exercise significant influence over operating and financial policies of the company are accounted for under the equity method. The equity method investments as of March 31, 2012 and December 31, 2011 consist of Cardinal Pipeline Company, LLC (Cardinal) with ownership interest of approximately 45 percent and Pine Needle LNG Company, LLC with ownership interest of 35 percent. We received distributions associated with our equity method investments totaling $1.0 million and $3.1 million in the three months ended March 31, 2012 and March 31, 2011, respectively. We made capital contributions to Cardinal related to Cardinal’s expansion project totaling $4.0 million and $5.9 million in the three months ended March 31, 2012 and March 31, 2011, respectively.

The condensed consolidated unaudited financial statements have been prepared from our books and records. Certain information and footnote disclosures normally included in financial statements prepared in accordance with U.S. generally accepted accounting principles (GAAP) have been condensed or omitted in this Form 10-Q pursuant to SEC rules and regulations. The condensed consolidated unaudited financial statements include all normal recurring adjustments and others which, in the opinion of our management, are necessary to present fairly our interim financial statements. These condensed consolidated unaudited financial statements should be read in conjunction with the consolidated financial statements and the notes thereto included in our 2011 Annual Report on Form 10-K.

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

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

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Certain reclassifications from investing activities to operating activities, related to asset retirement obligations (ARO) removal costs of $0.4 million for the three months ended March 31, 2011, have been made to correct the 2011 Condensed Consolidated Statement of Cash Flows.

Comprehensive Income.

In January 2012, we adopted Accounting Standards Update No. 2011-5, “Comprehensive Income (Topic 220) Presentation of Comprehensive Income” (ASU 2011-5) and Accounting Standards Update No. 2011-12, “Comprehensive Income (Topic 220) Deferral of the Effective Date for Amendments to the Presentation of Reclassifications of Items Out of Accumulated Other Comprehensive Income in Accounting Standards Update No. 2011-05” (ASU 2011-12). ASU 2011-5 requires presentation of net income and other comprehensive income either in a single continuous statement or in two separate, but consecutive, statements. ASU 2011-5 also requires separate presentation in both net income and other comprehensive income of reclassification adjustments for items that are reclassified from other comprehensive income to net income. The new guidance does not change the items reported in other comprehensive income. ASU 2011-12 defers the effective date for only the presentation requirements related to reclassifications in ASU 2011-5. During this deferral period, ASU 2011-12 provides that we should continue to report reclassifications out of accumulated other comprehensive income consistent with the presentation requirements in effect before ASU 2011-05. All other requirements in ASU 2011-05 are not affected by ASU 2011-12. Net income (loss) and other comprehensive income (loss) are now presented in a single continuous statement.

2. CONTINGENT LIABILITIES AND COMMITMENTS.

Rate Matters.

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

The one issue reserved for litigation or further settlement relates to our proposal to change the design of the rates for service under one of our storage rate schedules, which was implemented subject to refund on March 1, 2007. A hearing on that issue was held before a FERC Administrative Law Judge (ALJ) in July 2008. In November 2008, the ALJ issued an initial decision in which he determined that our proposed incremental rate design is unjust and unreasonable. On January 21, 2010, the FERC reversed the ALJ’s initial decision, and approved our proposed incremental rate design. Certain parties sought rehearing of the FERC’s order and, on April 2, 2012, the FERC denied the requesting request.

Environmental Matters.

We have had studies underway to test some of our facilities for the presence of toxic and hazardous substances to determine to what extent, if any, remediation may be necessary. We have responded to data requests from the U.S. Environmental Protection Agency (EPA) and state agencies regarding such potential contamination of certain of our sites. On the basis of the findings to date, we estimate that environmental assessment and remediation costs under various federal and state statutes will total approximately $7 million to $9 million (including both expense and capital expenditures), measured on an undiscounted basis, and will be spent over the next three to five years. This estimate depends on a number of assumptions concerning the scope of remediation that will be required at certain locations and the cost of the remedial measures. We are conducting environmental assessments and implementing a variety of remedial measures that may result in increases or decreases in the total estimated costs. At March 31, 2012, we had a balance of approximately $3.3 million for the expense portion of these estimated costs recorded in current liabilities ($0.8 million) and other long-term liabilities ($2.5 million) in the accompanying Condensed Consolidated Balance Sheet. At December 31, 2011, we had a balance of approximately $3.5 million for the expense portion of these estimated costs recorded in current liabilities ($0.8 million) and other long-term liabilities ($2.7 million) in the accompanying Condensed Consolidated Balance Sheet.

Although we discontinued the use of lubricating oils containing polychlorinated biphenyls (PCBs) in the 1970s, we have discovered residual PCB contamination in equipment and soils at certain gas compressor station sites. We

8

have worked closely with the EPA and state regulatory authorities regarding PCB issues, and we have a program to assess and remediate such conditions where they exist. In addition, we commenced negotiations with certain environmental authorities and other parties concerning investigative and remedial actions relative to potential mercury contamination at certain gas metering sites. All such costs are included in the $7 million to $9 million range discussed above.

We have been identified as a potentially responsible party (PRP) at various Superfund and state waste disposal sites. Based on present volumetric estimates and other factors, our estimated aggregate exposure for remediation of these sites is less than $0.5 million. The estimated remediation costs for all of these sites are included in the $7 million to $9 million range discussed above. Liability under the Comprehensive Environmental Response, Compensation and Liability Act (and applicable state law) can be joint and several with other PRPs. Although volumetric allocation is a factor in assessing liability, it is not necessarily determinative; thus, the ultimate liability could be substantially greater than the amounts described above.

In March 2008, the EPA promulgated a new, lower National Ambient Air Quality Standard (NAAQS) for ground-level ozone. Within two years, the EPA was expected to designate new eight-hour ozone non-attainment areas. However, in September 2009, the EPA announced it would reconsider the 2008 NAAQS for ground level ozone to ensure that the standards were clearly grounded in science and were protective of both public health and the environment. As a result, the EPA delayed designation of new eight-hour ozone non-attainment areas under the 2008 standards until the reconsideration is complete. In January 2010, the EPA proposed to further reduce the ground-level ozone NAAQS from the March 2008 levels. On September 22, 2011, the EPA announced that it was proceeding with required actions to implement the 2008 ozone standard and area designations. Designation of new eight-hour ozone non-attainment areas are expected to result in additional federal and state regulatory actions that will likely impact our operations and increase the cost of additions to property, plant and equipment. Until such non-attainment areas are designated, we are unable at this time to estimate the cost of additions that may be required to meet this new regulation.

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

In February 2010, the EPA promulgated a final rule establishing a new one-hour nitrogen dioxide (NO₂) NAAQS. The effective date of the new NO₂ standard was April 12, 2010. This new standard is subject to numerous challenges in the federal court. Given the uncertainty associated with the implementation of the new standard and the broad range of actions we could be required to take to meet the standard, we have not estimated the cost of additions that may be required to meet this new regulation.

We consider prudently incurred environmental assessment and remediation costs and the costs associated with compliance with environmental standards to be recoverable through rates. To date, we have been permitted recovery of environmental costs, and it is our intent to continue seeking recovery of such costs through future rate filings. As a result, as estimated costs of environmental assessment and remediation are incurred, they are recorded as regulatory assets in the Condensed Consolidated Balance Sheet until collected through rates. However, we had no uncollected environmental related regulatory assets at March 31, 2012 or December 31, 2011.

By letter dated September 20, 2007, the EPA required us to provide information regarding natural gas compressor stations in the states of Mississippi and Alabama as part of the EPA’s investigation of our compliance with the Act. By January 2008, we responded with the requested information. By Notices of Violation (NOVs) dated March 28, 2008, the EPA found us to be in violation of the requirements of the Act with respect to these compressor stations. We met with the EPA in May 2008 to discuss the allegations contained in the NOVs; in June 2008, we submitted to the EPA a written response denying the allegations. The EPA has requested additional information pertaining to these compressor stations and in May 2011, we submitted information in response to the EPA’s latest request. In August, 2010, the EPA requested, and we provided, similar information for a compressor station in Maryland.

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Safety Matters.

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

Currently, we estimate that the cost to complete the required initial assessments and associated remediation through 2012 will be primarily capital in nature and range between $30 million and $45 million. Ongoing periodic reassessments and new initial assessments of any new high consequence areas will be completed within the timeframes required by the rule. Management considers the costs associated with compliance with the rule to be prudent costs incurred in the ordinary course of business and, therefore, recoverable through our rates.

Other Matters.

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

Summary.

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

Other Commitments.

Commitments for construction We have commitments for construction and acquisition of property, plant and equipment of approximately $283.8 million at March 31, 2012.

3. DEBT AND FINANCING ARRANGEMENTS.

Credit Facility.

Total letter of credit capacity available to WPZ under the $2.0 billion credit facility is $1.3 billion. At March 31, 2012, no letters of credit have been issued and no loans are outstanding, so the full $400 million under the credit facility was available to us.

Current Maturities of Long-Term Debt.

The current maturities of long-term debt at March 31, 2012 are associated with $325 million of 8.875 percent Notes that mature on July 15, 2012.

Issuance of Long-Term Debt.

In August 2011, we issued $375 million of 5.4 percent senior unsecured notes due 2041 to investors in a private debt placement. As part of the new issuance, we entered into a registration rights agreement with the initial purchasers of the notes. An offer to exchange these unregistered notes for substantially identical new notes that are registered under the Securities Act of 1933, as amended, was commenced in February 2012 and completed in March 2012.

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4. FAIR VALUE MEASUREMENTS.

ARO Trust.

We are entitled to collect in rates the amounts necessary to fund our ARO. We deposit monthly, into an external trust account, the revenues specifically designated for ARO. We established the ARO trust account (ARO Trust) on June 30, 2008. The ARO Trust carries a moderate risk portfolio. We measure the financial instruments held in our ARO Trust at fair value. However, in accordance with the ASC Topic 980, Regulated Operations, both realized and unrealized gains and losses of the ARO Trust are recorded as regulatory assets or liabilities.

The fair value hierarchy prioritizes the inputs used to measure fair value, giving the highest priority to quoted prices in active markets for identical assets or liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements). We classify our ARO Trust within Level 1 of the hierarchy. Our ARO Trust consists of the following financial instruments (in millions):

	March 31, 2012		December 31, 2011
Money market funds	$	2.1	$	1.4
U.S. equity funds		7.9		9.5
International equity funds		5.1		5.3
Municipal bond funds		8.6		8.3
Total	$	23.7	$	24.5

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

							Fair Value Measurements Using
	Carrying Amount			Fair Value			Quoted Prices In Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
	(Millions)
Assets (liabilities) at March 31, 2012:
Recurring basis:
ARO Trust investments	$	23.7		$	23.7		$	23.7	$	—		$	—
Additional disclosures:
Notes receivables		9.6			9.6			—		9.6			—
Long-term debt, including current portion		(1,354.0	)		(1,536.7	)		—		(1,536.7	)		—
Assets (liabilities) at December 31, 2011:
Recurring basis:
ARO Trust investments	$	24.5		$	24.5		$	24.5	$	—		$	—
Additional disclosures:
Notes receivables		9.5			9.5			N/A		N/A			N/A
Long-term debt, including current portion		(1,353.7	)		(1,539.2	)		N/A		N/A			N/A

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Fair Value of Methods.

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

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

ARO Trust investments - The ARO Trust invests in a moderate risk portfolio that is reported at fair value.

Notes receivable - The carrying value of our notes receivable are considered to approximate the fair value generally due to the nature of the related interest rates and our assessment of our ability to recover these amounts using an income approach.

Long-term debt - The disclosed fair value of our long-term debt is determined by a market approach using broker quoted indicative period-end bond prices. The quoted prices are based on observable transactions in less active markets for our debt or similar instruments.

Reclassifications of fair value between Level 1, Level 2, and Level 3 of the fair value hierarchy, if applicable, are made at the end of each quarter. No transfers between Level 1 and Level 2 occurred during the three months ended March 31, 2012 or 2011.

5. TRANSACTIONS WITH AFFILIATES.

We are a participant in WPZ’s cash management program, and we make advances to and receive advances from WPZ. At March 31, 2012 and December 31, 2011, the advances due us by WPZ totaled approximately $293.4 million and $253.6 million, respectively. The advances are represented by demand notes. Advances are stated at the historical carrying amounts. Interest income is recognized when chargeable and collectability is reasonably assured. The interest rate on these intercompany demand notes is based upon the daily overnight investment rate paid on WPZ’s excess cash at the end of each month. At March 31, 2012, the interest rate was 0.01 percent.

Included in our operating revenues for the three months ending March 31, 2012 and 2011 are revenues received from affiliates of $0.2 million and $4.3 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, WPXEM managed our jurisdictional merchant gas sales. Subsequent to the spinoff of WPX, beginning on or about May 1, 2012, our affiliate WER will manage our jurisdictional merchant gas sales.

Included in our cost of sales for the three months ended March 31, 2012 and 2011 is purchased gas cost from affiliates of $1.3 million and $3.3 million, respectively. All gas purchases are made at market or contract prices.

Williams has a policy of charging its subsidiary companies for management services provided by the parent company and other affiliated companies. Included in our administrative and general expenses for the three months ended March 31, 2012 and 2011, are $15.8 million and $14.0 million, respectively, for such corporate expenses charged by Williams, WPZ, and other affiliated companies.

Pursuant to an operating agreement, we serve as contract operator on certain Williams Field Services Company (WFS) facilities. Transco recorded reductions in operating expenses for services provided to and reimbursed by WFS of $0.7 million and $1.1 million for the three months ended March 31, 2012 and 2011, respectively, under terms of the operating agreement.

We made equity distributions totaling $54.3 million and $45.0 million during the three months ended March 31, 2012 and 2011, respectively. During April 2012, we declared an additional distribution of $82.0 million to be paid on April 30, 2012. In the three months ended March 31, 2012 and 2011, respectively, WPO made contributions totaling $34.0 million and $40 million to us to fund a portion of our expenditures for additions to property, plant and equipment.

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We have no employees. Services are provided to us by an affiliate, Transco Pipeline Services LLC (TPS), a Delaware limited liability company. Pursuant to an administrative services agreement, TPS provides personnel, facilities, goods and equipment not otherwise provided by us that are necessary to operate our business. In return, we reimburse TPS for all direct and indirect expenses it incurs or payments it makes (including salary, bonus, incentive compensation and benefits) in connection with these services. We were billed $51.0 million and $47.0 million in the three months ended March 31, 2012 and 2011, respectively, for these services. Such expenses are primarily included in Administrative and general and Operations and maintenance expenses on the accompanying Condensed Consolidated Statement of Comprehensive Income.

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ITEM 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

General.

The following discussion should be read in conjunction with the Consolidated Financial Statements, Notes and Management’s Discussion and Analysis contained in Items 7 and 8 of our 2011 Annual Report on Form 10-K and with the Condensed Consolidated Financial Statements and Notes contained in this Form 10-Q.

RESULTS OF OPERATIONS.

Operating Income and Net Income.

Operating income for the three months ended March 31, 2012 was $93.5 million compared to $96.8 million for the three months ended March 31, 2011. Net income for the three months ended March 31, 2012 was $74.8 million compared to $81.7 million for the three months ended March 31, 2011. The decrease in Operating income of $3.3 million (3.4 percent) was primarily due to an increase in Operating Costs and Expenses, partially offset by higher Natural gas transportation revenues in 2012 compared to 2011. The decrease in Net income of $6.9 million (8.4 percent) was mostly attributable to the decrease in Operating income and higher net deductions in Other (Income) and Other Deductions.

Transportation Revenues.

Operating revenues: Natural gas transportation for the three months ended March 31, 2012 increased $22.1 million (9.2 percent) over the same period in 2011. The increase was primarily due to higher transportation reservation revenues of $18.2 million, ($11.7 million from our 85 North Phase II project placed in service in May 2011, $3.3 million from the Pascagoula project placed in service in September 2011, and $3.2 million from the Mobile Bay South Phase II project placed in service in May 2011), $2.3 million higher revenues due to one more billable day in 2012 because of leap year, and $1.3 million higher revenues from firm transportation backhaul revenues in 2012.

Sales Revenues.

Operating revenues: Natural gas sales decreased $16.9 million (62.6 percent) for the three months ended March 31, 2012 compared to the same period in 2011. The decrease was primarily due to the absence of system management gas sales of $12.0 million and Hester base gas sales of $4.4 million, both recorded in 2011. System management gas sales are offset in our cost of natural gas sold and therefore had no impact on our operating income or results of operations.

Operating Costs and Expenses.

Excluding the Cost of natural gas sales, which is directly offset in revenues, of $10.1 million for the three months ended March 31, 2012 and $27.0 million for the comparable period in 2011, our operating costs and expenses for the three months ended March 31, 2012 increased approximately $24.8 million (13.7 percent) over the comparable period in 2011. This increase was primarily attributable to:

• A $17.7 million net expense increase (178.79 percent) in Other (income) expense, net primarily due to the absence of the $10.1 million reversal of project feasibility costs from expense to capital associated with the Northeast Supply Link Expansion Project upon determining that the project was probable of development recorded in 2011, a $4.3 million increase in other project costs, and the absence of the $3.8 million gain on Hester base gas sales recorded in 2011;

• A $5.4 million (12.6 percent) increase in Administrative and general costs primarily resulting from a $2.8 million increase in allocated corporate expenses, a $1.1 million increase in information technology services and $0.8 million increase in employee related benefit costs, and;

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• A $1.8 million (2.8 percent) increase in Depreciation and amortization costs primarily resulting from an increase in the depreciation base due to additional plant placed in service in 2011.

Other (Income) and Other Deductions.

Other (income) and other deductions for the three months ended March 31, 2012 increased $3.6 million (23.8 percent) over the same period in 2011. The increase was primarily due to higher Miscellaneous other (income) deductions, net of $2.0 million primarily due to a lower amount of reimbursements for tax gross-up related to reimbursable projects and a $1.8 million decrease in Allowance for equity and borrowed funds used during construction (AFUDC) due to lower construction spending in 2012 as compared to 2011 primarily related to our 85 North project that was placed in service May 2011.

Eminence Storage Field Leak.

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

As a result of these occurrences, we have determined that these two caverns cannot be returned to service. In addition, two other caverns at the field, which were constructed at or about the same time as those caverns, have experienced operating problems, and we have determined that they should be retired. In September 2011 we filed an application with the FERC seeking authorization to abandon these four caverns. We estimate the cost to abandon the caverns, which will be capital in nature, will be approximately $76.0 million, which is expected to be spent through the first half of 2013. This estimate is subject to change as work progresses and additional information becomes known. To the extent available, the abandonment costs will be funded from the ARO Trust. As of March 31, 2012, we have incurred approximately $44.2 million of abandonment costs. Management considers these costs to be prudent costs incurred in the abandonment of these caverns and expects to recover these costs, net of insurance proceeds, in future rate filings.

In the three months ended March 31, 2012, we incurred $0.6 million of expense related primarily to costs to ensure the safety of the surrounding area. We anticipate incurring additional expense of approximately $7.8 million through the remainder of 2012 and in 2013.

Sweet Water, Alabama Pipeline Rupture

On December 3, 2011, we experienced a rupture of our 36-inch diameter Main Line C pipeline near Sweet Water, Alabama, in a mostly unpopulated area. The rupture resulted in an explosion and fire which caused timber damage to adjacent landowners. There were no injuries as a result of the rupture. On December 6, 2011, PHMSA issued a Corrective Action Order (CAO) outlining the steps required to ensure the safety of Main Line C before its return to service. In March 2012, we submitted our plan to PHMSA to place Main Line C back in service. We received temporary approval from PHMSA to return a portion of the line to service; however, a portion is still out of service. We are working closely with PHMSA to return the remaining segment to service. The adjacent B Line was exposed by the rupture and had coating damage due to the fire. We have replaced that section of B Line. Mainlines A, D and E were not damaged and were quickly back at full service. There has been no impact to our customers.

Method of Financing.

We anticipate funding the July 15, 2012 maturity of our $325 million 8.875 percent Notes with a new debt issuance.

Capital Expenditures.

Our capital expenditures for the three months ended March 31, 2012 were $61.6 million, compared to $84.6 million for the three months ended March 31, 2011. The $23.0 million decrease is primarily due to lower spending on expansion projects in 2012. Our capital expenditures estimate for 2012 and future capital projects are discussed in our 2011 Annual Report Form 10-K. The following describes those projects and certain new capital projects proposed by us.

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Mid-South Expansion Project

The Mid-South Expansion Project involves an expansion of our mainline from Station 85 in Choctaw County, Alabama to markets as far downstream as North Carolina. In August 2011 we received approval from the FERC. The capital cost of the project is estimated to be approximately $217 million. We plan to place the project into service in phases in September 2012 and June 2013, and it will increase capacity by 225 thousand dekatherms per day (Mdth/d).

Mid-Atlantic Connector Project

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

Northeast Supply Link Project

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

Rockaway Delivery Lateral Project

The Rockaway Delivery Lateral Project involves the construction of a three-mile offshore lateral to National Grid’s distribution system in New York. We anticipate filing an application with the FERC in 2012. The capital cost of the project is estimated to be approximately $182 million. We plan to place the project into service as early as April 2014, and its capacity will be 647 Mdth/d.

Northeast Connector Project

The Northeast Connector Project involves an expansion of our existing natural gas transmission system from southeastern Pennsylvania to the proposed Rockaway Delivery Lateral. We anticipate filing an application with the FERC in 2012. The capital cost of the project is estimated to be approximately $39 million. We plan to place the project into service as early as April 2014, and it will increase capacity by 100 Mdth/d.

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ITEM 4. Controls and Procedures.

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

Evaluation of Disclosure Controls and Procedures.

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

First Quarter 2012 Changes in Internal Controls.

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

PART II – OTHER INFORMATION.

ITEM 1. LEGAL PROCEEDINGS.

The information called for by this item is provided in Note 2 of the Notes to Condensed Consolidated Financial Statements included under Part I, Item 1. Financial Statements of this report, which information is incorporated by reference into this item.

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ITEM 6. EXHIBITS

The following instruments are included as exhibits to this report.

Exhibit Number	Description
2.1	Certificate of Conversion dated December 22, 2008 and effective December 31, 2008. (filed on February 24, 2011 as Exhibit 2.1 to our report Form 10-K and incorporated herein by reference).
3.1	Certificate of Formation dated December 22, 2008 and effective December 31, 2008. (filed on February 24, 2011 as Exhibit 3.1 to our report Form 10-K and incorporated herein by reference).
3.2	Amended and Restated Operating Agreement of Transcontinental Gas Pipe Line Company, LLC dated February 17, 2010. (filed on October 28, 2010 as Exhibit 3.2 to our report Form 10-Q and incorporated herein by reference).
31.1*	Certification of Principal Executive Officer pursuant to Rules 13a-14(a) and 15d-14(a) promulgated under the Securities Exchange Act of 1934, as amended, and Item 601(b)(31) of Regulation S-K, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*	Certification of Principal Financial Officer pursuant to Rules 13a-14(a) and 15d-14(a) promulgated under the Securities Exchange Act of 1934, as amended, and Item 601(b)(31) of Regulation S-K, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32**	Certification of Principal Executive Officer and Principal Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS**	XBRL Instance Document.
101.SCH**	XBRL Taxonomy Extension Schema.
101.CAL**	XBRL Taxonomy Extension Calculation Linkbase.
101.LAB**	XBRL Taxonomy Extension Label Linkbase.
101.PRE**	XBRL Taxonomy Extension Presentation Linkbase.

* Filed herewith.

** Furnished herewith.

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SIGNATURE

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

	TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC
	(Registrant)
Dated: April 26, 2012	By:	/s/ Jeffrey P. Heinrichs
	Jeffrey P. Heinrichs
	Controller and Assistant Treasurer
	(Principal Accounting Officer)

EXHIBIT INDEX.

Exhibit Number	Description
2.1	Certificate of Conversion dated December 22, 2008 and effective December 31, 2008. (filed on February 24, 2011 as Exhibit 2.1 to our report Form 10-K and incorporated herein by reference).
3.1	Certificate of Formation dated December 22, 2008 and effective December 31, 2008. (filed on February 24, 2011 as Exhibit 3.1 to our report Form 10-K and incorporated herein by reference).
3.2	Amended and Restated Operating Agreement of Transcontinental Gas Pipe Line Company, LLC dated February 17, 2010. (filed on October 28, 2010 as Exhibit 3.2 to our report Form 10-Q and incorporated herein by reference).
31.1*	Certification of Principal Executive Officer pursuant to Rules 13a-14(a) and 15d-14(a) promulgated under the Securities Exchange Act of 1934, as amended, and Item 601(b)(31) of Regulation S-K, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*	Certification of Principal Financial Officer pursuant to Rules 13a-14(a) and 15d-14(a) promulgated under the Securities Exchange Act of 1934, as amended, and Item 601(b)(31) of Regulation S-K, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32**	Certification of Principal Executive Officer and Principal Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS**	XBRL Instance Document.
101.SCH**	XBRL Taxonomy Extension Schema.
101.CAL**	XBRL Taxonomy Extension Calculation Linkbase.
101.LAB**	XBRL Taxonomy Extension Label Linkbase.
101.PRE**	XBRL Taxonomy Extension Presentation Linkbase.

* Filed herewith.

** Furnished herewith.