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

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

Commission file number 1-7584

TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC

(Exact name of registrant as specified in its charter)

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

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

NO CHANGE

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

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

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

     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 o		Accelerated filer o		Non-accelerated filer þ		Smaller reporting company o
				(Do not check if a smaller reporting company)

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

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

 

 

TRANSCONTINTENTAL GAS PIPE LINE COMPANY, LLC
Index

Part I. Financial Information:		Page
Item 1. Financial Statements
Condensed Consolidated Statement of Income —Three and Six Months Ended June 30, 2011 and 2010			3
Condensed Consolidated Balance Sheet — June 30, 2011 and December 31, 2010			4
Condensed Consolidated Statement of Cash Flows — Six Months Ended June 30, 2011 and 2010.			6
Notes to Condensed Consolidated Financial Statements			7
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations			15
Item 4. Controls and Procedures			18
Part II. Other Information			18
Item 1. Legal Proceedings			18
Item 1A. Risk Factors			18
Item 6. Exhibits			21
EX-10.1
EX-31.1
EX-31.2
EX-32
EX-101 INSTANCE DOCUMENT
EX-101 SCHEMA DOCUMENT
EX-101 CALCULATION LINKBASE DOCUMENT
EX-101 LABELS LINKBASE DOCUMENT
EX-101 PRESENTATION LINKBASE DOCUMENT

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 (including the uncertainties inherent in assessing and estimating future natural gas reserves), market demand, volatility of prices, and the availability and cost of capital;

	•		Inflation, interest rates and general economic conditions (including future disruptions and volatility in the global credit markets and the impact of these events on our customers and suppliers);
	•		The strength and financial resources of our competitors;
	•		Development of alternative energy sources;
	•		The impact of operational and development hazards;
	•		Costs of, changes in, or the results of laws, government regulations (including safety and climate change regulation), 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;
	•		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; 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, 2010, and Part II, Item 1A. Risk Factors of this Form 10-Q.

PART I – FINANCIAL INFORMATION

ITEM 1. Financial Statements.

TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC

CONDENSED CONSOLIDATED STATEMENT OF INCOME

(Thousands of Dollars)

(Unaudited)

		Three months ended								Six months ended
		June 30,								June 30,
		2011				2010				2011				2010
Operating Revenues:
Natural gas sales		$	26,239			$	15,706			$	53,281			$	43,428
Natural gas transportation			238,069				223,338				478,445				457,653
Natural gas storage			35,043				36,302				71,863				73,490
Other			1,500				1,335				2,618				3,159
Total operating revenues			300,851				276,681				606,207				577,730
Operating Costs and Expenses:
Cost of natural gas sales			26,239				15,706				53,281				43,428
Cost of natural gas transportation			6,982				3,808				18,346				12,337
Operation and maintenance			68,404				62,609				127,839				121,461
Administrative and general			40,479				40,055				83,265				75,171
Depreciation and amortization			66,013				62,502				130,256				124,996
Taxes - other than income taxes			11,863				11,647				25,398				24,155
Other (income) expense, net			3,750				2,570				(6,100	)			3,763
Total operating costs and expenses			223,730				198,897				432,285				405,311
Operating Income			77,121				77,784				173,922				172,419
Other (Income) and Other Deductions:
Interest expense			23,873				23,733				47,695				47,280
Interest income - affiliates			(6	)			(16	)			(16	)			(2,178	)
Allowance for equity and borrowed funds used during construction (AFUDC)			(4,058	)			(3,263	)			(9,395	)			(5,831	)
Equity in earnings of unconsolidated affiliates			(1,095	)			(1,525	)			(2,413	)			(3,066	)
Miscellaneous other (income) deductions, net			2,874				78				729				1,314
Total other (income) and other deductions			21,588				19,007				36,600				37,519
Income before Income Taxes			55,533				58,777				137,322				134,900
Provision for Income Taxes			69				105				172				234
Net Income		$	55,464			$	58,672			$	137,150			$	134,666

See accompanying notes.

TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC

CONDENSED CONSOLIDATED BALANCE SHEET

(Thousands of Dollars)

(Unaudited)

		June 30,				December 31,
		2011				2010
ASSETS
Current Assets:
Cash		$	100			$	148
Receivables:
Affiliates			5,074				4,921
Advances to affiliates			208,467				108,838
Others, less allowance of $407 ($406 in 2010)			116,990				110,434
Transportation and exchange gas receivables			10,710				2,417
Inventories			82,009				85,425
Regulatory assets			40,626				48,444
Other			17,787				13,132
Total current assets			481,763				373,759
Investments, at cost plus equity in undistributed earnings			53,292				43,753
Property, Plant and Equipment:
Natural gas transmission plant			7,874,468				7,674,366
Less-Accumulated depreciation and amortization			2,726,787				2,650,133
Total property, plant and equipment, net			5,147,681				5,024,233
Other Assets:
Regulatory assets			199,348				198,921
Other			63,195				59,223
Total other assets			262,543				258,144
Total assets		$	5,945,279			$	5,699,889

See accompanying notes.

TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC
CONDENSED CONSOLIDATED BALANCE SHEET (Continued)
(Thousands of Dollars)
(Unaudited)

		June 30,				December 31,
		2011				2010
LIABILITIES AND OWNER’S EQUITY
Current Liabilities:
Payables:
Affiliates		$	41,171			$	18,769
Other			125,570				92,647
Transportation and exchange gas payables			2,161				1,646
Accrued liabilities			142,137				119,125
Current maturities of long-term debt			299,986				299,932
Total current liabilities			611,025				532,119
Long-Term Debt			980,591				980,018
Other Long-Term Liabilities:
Asset retirement obligations			226,115				220,644
Regulatory liabilities			154,369				115,563
Other			6,509				6,785
Total other long-term liabilities			386,993				342,992
Contingent liabilities and commitments (Note 2)
Owner’s Equity:
Member’s capital			1,813,434				1,727,434
Retained earnings			2,153,303				2,117,153
Accumulated other comprehensive income (loss)			(67	)			173
Total owner’s equity			3,966,670				3,844,760
Total liabilities and owner’s equity		$	5,945,279			$	5,699,889

See accompanying notes.

TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC

CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS

(Unaudited)

		Six months ended June 30,
		2011				2010
		(Thousands)
Cash flows from operating activities:
Net income		$	137,150			$	134,666
Adjustments to reconcile net income to net cash provided by (used in) operating activities
Depreciation and amortization			130,432				124,886
Allowance for equity funds used during construction (Equity AFUDC)			(6,497	)			(3,993	)
Changes in operating assets and liabilities:
Receivables   - affiliates			(153	)			3,789
- others			(6,556	)			22,912
Transportation and exchange gas receivables			(8,293	)			(4,988	)
Inventories			3,752				(36,756	)
Payables        - affiliates			22,402				3,529
- others			25,716				6,081
Transportation and exchange gas payables			515				3,740
Accrued liabilities			25,694				(2,993	)
Other, net			(24,393	)			7,382
Net cash provided by operating activities			299,769				258,255
Cash flows from financing activities:
Cash distributions			(101,000	)			(203,791	)
Cash contributions from parent			86,000				-
Other, net			(5,727	)			(4,674	)
Net cash used in financing activities			(20,727	)			(208,465	)
Cash flows from investing activities:
Property, plant and equipment additions, net of equity AFUDC*			(160,780	)			(138,677	)
Disposal of property, plant and equipment, net			(3,924	)			6,122
Advances to affiliates, net			(99,629	)			95,507
Purchase of long-term investments			(11,460	)			-
Purchase of ARO trust investments			(24,545	)			(33,145	)
Proceeds from sale of ARO trust investments			26,655				20,812
Other, net			(5,407	)			(405	)
Net cash used in investing activities			(279,090	)			(49,786	)
Increase (decrease) in cash and cash equivalents			(48	)			4
Cash and cash equivalents at beginning of period			148				108
Cash and cash equivalents at end of period		$	100			$	112
______________
* Increase to property, plant and equipment		$	(171,032	)		$	(107,660	)
Changes in related accounts payable and accrued liabilities			10,252				(31,017	)
Property, plant and equipment additions, net of equity AFUDC		$	(160,780	)		$	(138,677	)

See accompanying notes.

TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

1.  BASIS OF PRESENTATION.

     In this report, Transco (which includes Transcontinental Gas Pipe Line Company, LLC and unless the context otherwise requires, all of the subsidiaries we control) is at times referred to in the first person as “we,” “us” or “our.” Unless the context clearly indicates otherwise, references to “we,” “us,” and “our” include the operations of Cardinal Pipeline Company, LLC (Cardinal) and Pine Needle LNG Company, LLC (Pine Needle) in which we own interests accounted for as equity investments. When we refer to Cardinal and Pine Needle by name, we are referring exclusively to their respective businesses and operations.

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 June 30, 2011 and December 31, 2010 consist of Cardinal with ownership interest of approximately 45 percent and Pine Needle with ownership interest of 35 percent. We received distributions associated with our equity method investments totaling $4.1 million and $1.2 million in the six months ended June 30, 2011 and June 30, 2010, respectively. We made capital contributions to Cardinal related to Cardinal’s expansion project totaling $11.5 million in the six months ended June 30, 2011, and $1.7 million in July 2011.

     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 financial position at June 30, 2011, and results of operations for the three and six months ended June 30, 2011 and 2010, and cash flows for the six months ended June 30, 2011 and 2010. These condensed consolidated financial statements should be read in conjunction with the consolidated financial statements and the notes thereto included in our 2010 Annual Report on Form 10-K.

     Through an agency agreement, WPX Energy Marketing, LLC (WPXEM), formerly Williams Gas Marketing, Inc., our 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 WPXEM 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 WPXEM. WPXEM receives all margins associated with 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 financial statements and accompanying notes. Actual results could differ from those estimates.

     Certain reclassifications from investing activities to operating activities, related to cash payments made to settle asset retirement obligations (ARO) of $1.2 million for the six months ended June 30, 2010, have been made to the 2010 financial statements to conform to the 2011 presentation.

Accounting Standards Issued But Not Yet Adopted.

     In May 2011, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update No. 2011-4, “Fair Value Measurement (Topic 820) Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in GAAP and International Financial Reporting Standards” (ASU 2011-4). ASU 2011-4 primarily eliminates the differences in fair value measurement principles between the FASB and International Accounting Standards Board. It clarifies existing guidance, changes certain fair value measurements and requires expanded disclosure primarily related to Level 3 measurements and transfers between Level 1 and Level 2 of the fair value hierarchy. ASU 2011-4 is effective on a prospective basis for interim and annual periods beginning after December 15, 2011. We are assessing the application of this update to our Consolidated Financial Statements.

     In June 2011, the FASB issued Accounting Standards Update No. 2011-5, “Comprehensive Income (Topic 220) Presentation of Comprehensive Income” (ASU 2011-5). 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. The Update 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. We currently report net income in the Consolidated Statement of Income and report other comprehensive income in our Notes to Consolidated Financial Statements. The standard is effective beginning the first quarter of 2012, with a retrospective application to prior periods. We plan to apply the new presentation beginning in 2012.

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 have requested rehearing of the FERC’s order. If the FERC were to reverse their opinion on rehearing, we believe any refunds would not be material to our results of operations.

Environmental Matters.

     We have had studies underway to test some of our facilities for the presence of toxic and hazardous substances to determine to what extent, if any, remediation may be necessary. We have responded to data requests from the U.S. Environmental Protection Agency (EPA) and state agencies regarding such potential contamination of certain of our sites. On the basis of the findings to date, we estimate that environmental assessment and remediation costs under various federal and state statutes will total approximately $7 million to $9 million (including both expense and capital expenditures), measured on an undiscounted basis, and will be spent over the next four to six 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 June 30, 2011, we had a balance of approximately $3.4 million for the expense portion of these estimated costs recorded in current liabilities ($0.8 million) and other long-term liabilities ($2.6 million) in the accompanying Condensed Consolidated Balance Sheet. At December 31, 2010, we had a balance of approximately $3.8 million for the expense portion of these estimated costs recorded in current liabilities ($0.8 million) and other long-term liabilities ($3.0 million) in the accompanying Condensed Consolidated Balance Sheet.

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

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

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

     We are also subject to the Federal Clean Air Act (Act) and to the Federal Clean Air Act Amendments of 1990 (1990 Amendments), which added significantly to the existing requirements established by the 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. For many of these facilities, we are developing more cost effective and innovative compressor engine control designs.

     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. The timing of finalization of the new ground-level ozone standard is uncertain. 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. 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 costs in the range of $25 million to $30 million through 2013, the compliance date.

     Furthermore, the EPA promulgated the Greenhouse Gas (GHG) Mandatory Reporting Rule on October 30, 2009, which requires facilities that emit 25,000 metric tons or more carbon dioxide (CO₂) equivalent per year from stationary fossil-fuel combustion sources to report GHG emissions to the EPA annually beginning March 31, 2011 for calendar year 2010. On March 18, 2011, EPA extended this reporting deadline to September 30, 2011. On November 30, 2010, the EPA issued additional regulations that expand the scope of the Mandatory Reporting Rule to include fugitive and vented greenhouse gas emissions effective January 1, 2011. Facilities that emit 25,000 metric tons or more CO₂ equivalent per year from stationary fossil-fuel combustion and fugitive/vented sources combined will be required to report GHG combustion and fugitive/vented emissions to the EPA annually beginning March 31, 2012 for calendar year 2011. Compliance with this reporting obligation is estimated to cost $7 million to $9 million over the next four to five years.

     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. We are unable at this time to estimate 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 Consolidated Balance Sheet until collected through rates. However, we had no uncollected environmental related regulatory assets at June 30, 2011 or December 31, 2010.

     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.

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 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 required timeframes. Currently, we estimate that the cost to complete the required initial assessments over the period of 2011 through 2012 and associated remediation will be primarily capital in nature and range between $80 million and $110 million. Ongoing periodic reassessments and 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.

     Appomattox, Virginia Pipeline Rupture On September 14, 2008, we experienced a rupture of our 30-inch diameter mainline B pipeline near Appomattox, Virginia. The rupture resulted in an explosion and fire which caused several minor injuries and property damage to several nearby residences. On September 25, 2008, PHMSA issued a Corrective Action Order which required that we operate three of our mainlines in a portion of Virginia at reduced operating pressure and prescribed various remedial actions. After completion of some of the remedial actions PHMSA approved our requests to restore the affected pipelines to normal operating pressure. By letter dated April 29, 2010, PHMSA confirmed that the remaining remedial actions should be completed by December 31, 2010. This deadline was subsequently extended by PHMSA to September 30, 2011. In 2009, PHMSA proposed, and we paid, a $1.0 million civil penalty related to this matter.

Other Matters.

     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 material adverse effect upon our future liquidity or financial position.

Other Commitments.

     Commitments for construction and gas purchases We have commitments for construction and acquisition of property, plant and equipment of approximately $263.8 million at June 30, 2011. We have commitments for gas purchases of approximately $2.6 million at June 30, 2011. See Note 1 for our discussion of our agency agreement with WPXEM.

3. DEBT AND FINANCING ARRANGEMENTS.

Credit Facility.

     In June 2011, we entered into a new $2 billion five-year senior unsecured revolving credit facility agreement (new credit facility) with Williams Partners L.P. (WPZ) and Northwest Pipeline GP (Northwest) as co-borrowers. The new agreement which is considered a modification to a previous borrowing arrangement for accounting purposes, replaced the existing $1.75 billion credit facility agreement that was scheduled to expire February 17, 2013. The new credit facility may, under certain conditions, be increased up to an additional $400 million. The full amount of the new credit facility is available to WPZ. We may borrow up to $400 million under the new credit facility to the extent not otherwise utilized by WPZ and Northwest.

     Under the new credit facility, WPZ is required to maintain a ratio of debt to EBITDA (each as defined in the credit facility) that must be no greater than 5 to 1. For the fiscal quarter and the two following fiscal quarters in which one or more acquisitions for a total aggregate purchase price equal to or greater than $50 million has been executed, WPZ is required to maintain a ratio of debt to EBITDA of no greater than 5.5 to 1.00. For us and our consolidated subsidiaries, the ratio of debt to capitalization (defined as net worth plus debt) must be no greater than 65 percent. At June 30, 2011, we are in compliance with these financial covenants.

     Each time funds are borrowed, the borrower may choose from two methods of calculating interest: a fluctuating base rate equal to Citibank N.A’s adjusted base rate plus an applicable margin, or a periodic fixed rate equal to London Interbank Offered Rate (LIBOR) plus an applicable margin. The borrower is required to pay a commitment fee (currently 0.25 percent) based on the unused portion of the new credit facility. The applicable margin and the commitment fee are determined for each borrower by reference to a pricing schedule based on such borrower’s senior unsecured long-term debt ratings. The new credit facility contains various covenants that limit, among other things, a borrower’s and its respective material subsidiaries’ ability to grant certain liens supporting indebtedness, a borrower’s ability to merge or consolidate, sell all or substantially all of its assets, enter into certain affiliate transactions, make certain distributions during an event of default, make investments and allow any material change in the nature of its business.

     The new credit facility includes customary events of default. If an event of default with respect to a borrower occurs under the new credit facility, the lenders will be able to terminate the commitments for all borrowers and accelerate the maturity of any loans of the defaulting borrower and exercise other rights and remedies.

     Letter of credit capacity under our new credit facility is $1.3 billion. At June 30, 2011, no letters of credit have been issued and the full $400 million under the new credit facility was available.

Current Maturities of Long-Term Debt.

     The current maturities of long-term debt at June 30, 2011 are associated with $300 million of 7 percent Notes that mature on August 15, 2011. It is our intent to refinance the Notes in the third quarter 2011.

4.  FAIR VALUE MEASUREMENTS.

     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):

			June 30,				December 31,
			2011				2010
Money market funds		$	5.4			$	1.6
U.S. equity funds			12.4				17.4
International equity funds			6.6				6.0
Municipal bond funds			15.2				15.4
Total		$	39.6			$	40.4

     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 such transfers occurred during the period ended June 30, 2011.

5.  FINANCIAL INSTRUMENTS.

Fair value of financial instruments.

     The carrying amount and estimated fair values of our financial instruments as of June 30, 2011 and December 31, 2010 are as follow (in thousands):

		June 30, 2011								December 31, 2010
		Carrying								Carrying
		Amount				Fair Value				Amount				Fair Value
Financial assets:
Cash		$	100			$	100			$	148			$	148
Short-term financial assets			210,554				210,554				108,985				108,985
ARO Trust investments			39,635				39,635				40,413				40,413
Long-term financial assets			7,476				7,476				144				144
Financial liabilities:
Long-term debt, including current portion			1,280,577				1,414,594				1,279,950				1,432,866

     For cash and short-term financial assets (third-party notes receivable and 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. For ARO Trust investments, the ARO Trust invests in a moderate risk portfolio that is reported at fair value. For long-term financial assets (long-term receivables), the carrying amount is a reasonable estimate of fair value because the interest rate is a variable rate. The fair value of our publicly traded long-term debt is valued using period-end traded bond market prices.

6.  TRANSACTIONS WITH AFFILIATES.

     Prior to The Williams Companies, Inc. (Williams) restructuring in February 2010, we were a participant in Williams’ cash management program, whereby we made advances to and received advances from Williams. The interest rate on these intercompany demand notes was based upon the weighted average cost of Williams’ debt outstanding at the end of each quarter. We received interest income from advances to Williams of $2.2 million during the six months ended June 30, 2010.

     Subsequent to Williams’ restructuring in February 2010, we became a participant in WPZ’s cash management program, and we make advances to and receive advances from WPZ. At June 30, 2011 and December 31, 2010, the advances due us by WPZ totaled approximately $208.5 million and $108.8 million, respectively. The advances are represented by demand notes. 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 June 30, 2011, the interest rate was 0.01 percent. The interest income from these advances to WPZ was minimal during the six months ended June 30, 2011 and June 30, 2010.

     Included in our operating revenues for the six months ending June 30, 2011 and 2010 are revenues received from affiliates of $9.9 million and $12.4 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 manages our jurisdictional merchant gas sales. The agency fees billed by WPXEM for the six months ended June 30, 2011 and 2010 were not significant.

     Included in our cost of sales for the six months ended June 30, 2011 and 2010 is purchased gas cost from affiliates, excluding the agency fees discussed above, of $4.5 million and $2.8 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, WPXEM 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 six months ended June 30, 2011 and 2010, are $27.0 million and $26.9 million, respectively, for such corporate expenses charged by Williams, WPZ, 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 six months ended June 30, 2011 and 2010, we recorded reductions in operating expense of $2.1 million and $3.8 million, respectively, for services provided to and reimbursed by WFS under terms of the operating agreement.

     Distributions totaling $101.0 million were declared and paid during the six months ended June 30, 2011. An additional distribution of $51.0 million was declared and paid in July 2011. Two distributions totaling approximately $203.8 million were declared and paid to Williams Gas Pipeline Company, LLC (WGP) and a $0.2 million non cash distribution was made to WGP during the six months ended June 30, 2010. In the six months ended June 30, 2011, Williams Partners Operating, LLC (WPO) made contributions totaling $86.0 million to us to fund a portion of our expenditures for additions to property, plant and equipment. In July 2011, WPO made an additional $14.0 million contribution.

     We have no employees. Services are provided to us by an affiliate, Transco Pipeline Services LLC (TPS), a Delaware limited liability company. On February 17, 2010, we entered into an administrative services agreement pursuant to which 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 $95.2 million and $74.4 million in the six months ended June 30, 2011 and 2010, respectively. Such expenses are primarily included in “Administrative and general” and “Operations and maintenance” expenses on the accompanying Condensed Consolidated Statement of Income.

7. COMPREHENSIVE INCOME.

     Comprehensive income is as follows (in thousands):

		Three months ended June 30,								Six months ended June 30,
		2011				2010				2011				2010
Net income		$	55,464			$	58,672			$	137,150			$	134,666
Equity interest in unrealized gain/(loss) on interest rate hedge			(271	)			28				(240	)			51
Total comprehensive income		$	55,193			$	58,700			$	136,910			$	134,717

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 2010 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 six months ended June 30, 2011 was $173.9 million compared to $172.4 million for the six months ended June 30, 2010. Net income for the six months ended June 30, 2011 was $137.1 million compared to $134.7 million for the six months ended June 30, 2010. The increase in Operating income of $1.5 million (0.9 percent) was primarily due to a $10.1 million reversal of project feasibility costs from expense to capital associated with the Northeast Supply Link Expansion Project and higher Natural gas transportation revenues in 2011 compared to 2010, partially offset by an increase in Operating Costs and Expenses. The increase in Net income of $2.4 million (1.8 percent) was mostly attributable to an increase in Operating income and a favorable change in Other (Income) and Other Deductions.

Transportation Revenues.

     Operating revenues: Natural gas transportation for the six months ended June 30, 2011 increased $20.7 million (4.5 percent) over the same period in 2010. The increase was primarily due to higher transportation demand revenues of $16.2 million, ($11.3 million from our 85 North Phase I and II projects placed in service in July 2010 and May 2011, respectively and $4.9 million from the Mobile Bay South Phase I and II projects placed in service in May 2010 and May 2011, respectively), and $6.0 million higher revenues which recover electric power costs. Electric power costs are recovered from customers through transportation rates resulting in no net impact on our operating income or results of operations. These increases were partially offset by a decrease of $3.2 million from lower commodity revenues resulting from declining production attached to our IT Feeder laterals.

Sales Revenues.

     Operating revenues: Natural gas sales increased $9.9 million (22.8 percent) for the six months ended June 30, 2011 compared to the same period in 2010. The increase was primarily due to higher cash out sales of $5.1 million and higher system management gas sales of $12.0 million, partially offset by lower Hester base gas and Eminence excess top gas sales of $6.0 million and lower merchant sales of $1.3 million. Cash out, system management gas, and merchant sales were 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 $53.3 million for the six months ended June 30, 2011 and $43.4 million for the comparable period in 2010, our operating costs and expenses for the six months ended June 30, 2011 increased approximately $17.1 million (4.7 percent) over the comparable period in 2010. This increase was primarily attributable to:

	•		A $6.0 million (48.8 percent) increase in Cost of natural gas transportation primarily due to higher electric power costs. Electric power costs are recovered from customers through transportation rates resulting in no net impact on our operating income or results of operations;
	•		A $6.3 million (5.2 percent) increase in Operation and maintenance costs primarily resulting from costs incurred to ensure the safety of the surrounding area associated with our Eminence storage field leak, and;

	•		An $8.1 million (10.8 percent) increase in Administrative and general costs primarily resulting from an increase in employee related benefit costs, and;
	•		A $5.3 million (4.2 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.
	•		Partially offset by a $9.9 million favorable increase (260.5 percent) in Other (income) expense, net primarily due to a $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. These costs will be included in the capital costs of the project, which we believe are probable of recovery through the project rates.

Other (Income) and Other Deductions.

     Other (income) and other deductions for the six months ended June 30, 2011 decreased $0.9 million (2.4 percent) over the same period in 2010. The decrease was primarily due to higher Allowance for equity and borrowed funds used during construction (AFUDC) of $3.6 million due to higher construction spending in 2011 as compared to 2010 and lower Miscellaneous other (income) deductions, net of $0.6 million primarily due to a lower amount of reimbursements for tax gross-up related to reimbursable projects, partially offset by a $2.2 million decrease in Interest income – affiliates due to a lower rate on the note advance to WPZ compared to the rate previously received from Williams.

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. To date, 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. Therefore, we intend to file an application seeking authorization from the FERC to abandon these four caverns. We estimate the cost to abandon the caverns, which will be capital in nature, will be approximately $67 million, which is expected to be spent in 2011, 2012 and the first half of 2013. To the extent available, the abandonment costs will be funded from the ARO Trust. As of June 30, 2011, we have incurred approximately $24 million of abandonment costs. This estimate is subject to change as work progresses and additional information becomes known. 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 six months ended June 30, 2011, we incurred $6.6 million of expense related primarily to costs to ensure the safety of the surrounding area.

Recent Events.

     During the second quarter of 2011, Williams became a member of Oil Insurance Limited (OIL), an energy industry mutual insurance company which shares losses among its members, in which we participate. In addition to certain property insurance coverage, Williams also purchased named windstorm coverage from OIL. The named windstorm insurance provides coverage up to $150 million per occurrence (60 percent of $250 million of losses in excess of our $100 million deductible), with an annual aggregate limit of $300 million and subject to an aggregate per-event shared limit of $750 million for all members.

Capital Expenditures.

     Our capital expenditures for the six months ended June 30, 2011 were $160.8 million, compared to $138.7 million for the six months ended June 30, 2010. The $22.1 million increase is primarily due to higher spending on expansion projects in 2011. Our capital expenditures estimate for 2011 and future capital projects are discussed in our 2010 Annual Report Form 10-K. The following describes those projects and certain new capital projects proposed by us.

Mobile Bay South II Expansion Project

     The Mobile Bay South II Expansion Project involves the addition of compression at our Station 85 in Choctaw County, Alabama and modifications to existing facilities at our Station 83 in Mobile County, Alabama to allow us to provide additional firm transportation service southbound on the Mobile Bay line from Station 85 to various

delivery points. In July 2010 we received approval from the FERC. The capital cost of the project is estimated to be approximately $33 million, and it provides 380 thousand dekatherms per day (Mdt/d) of incremental firm capacity. The project was placed into service on May 1, 2011.

85 North Expansion Project

     The 85 North Expansion Project involves an expansion of our existing natural gas transmission system from Station 85 in Choctaw County, Alabama to various delivery points as far north as North Carolina. In September 2009 we received approval from the FERC. The capital cost of the project is estimated to be approximately $222 million, and it provides 309 Mdt/d of incremental firm capacity. The first phase, for 90 Mdt/d, was placed into service in July 2010, and the second phase for the remaining 219 Mdt/d was placed into service on May 1, 2011.

Pascagoula Expansion Project

     The Pascagoula Expansion Project involves the construction of a new pipeline to be jointly owned with Florida Gas Transmission connecting our existing Mobile Bay Lateral to the outlet pipeline of a LNG import terminal currently under construction in Mississippi. In July 2010 we received approval from the FERC. Our share of the capital cost of the project is estimated to be approximately $30 million. We plan to place the project into service in September 2011, and our share of its capacity will be 467 Mdt/d.

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 October 2010 we filed an application with 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 Mdt/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 Mdt/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 Mdt/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 Mdt/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 anticipate filing an application with the FERC in the fourth quarter of 2011. 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 Mdt/d.

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 the 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 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.

Second Quarter 2011 Changes in Internal Controls.

     There have been no changes during the second quarter of 2011 that have materially affected, or are reasonably likely to materially affect, our Internal Controls.

PART II – OTHER INFORMATION.

ITEM 1. LEGAL PROCEEDINGS.

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

ITEM 1A. RISK FACTORS.

     Part 1, Item 1A. Risk Factors in our Annual Report on Form 10-K for the year ended December 31, 2010, included certain risk factors that could materially affect our business, financial condition or future results. Those Risk Factors have not materially changed, except as set forth below:

Our costs of testing, maintaining or repairing our facilities may exceed our expectations and the FERC or competition in our markets may not allow us to recover such costs in the rates we charge for our services.

     We could experience unexpected leaks or ruptures on our gas pipeline system, or be required by regulatory authorities to test or undertake modifications to our systems that could result in a material adverse impact on our business, financial condition and results of operations if the costs of testing, maintaining or repairing our facilities exceed current expectations and the FERC or competition in our markets do not allow us to recover such costs in the rates we charge for our service. For example, in response to a recent third party pipeline rupture, PHMSA issued an Advisory Bulletin which, among other things, advises pipeline operators that if they are relying on design,

construction, inspection, testing, or other data to determine the pressures at which their pipelines should operate, the records of that data must be traceable, verifiable and complete. Locating such records and, in the absence of any such records, verifying maximum pressures through physical testing or modifying or replacing facilities to meet the demands of such pressures, could significantly increase our costs. Additionally, failure to locate such records could result in reductions of allowable operating pressures, which would reduce available capacity on our pipeline.

Restrictions in our debt agreements and our leverage may affect our future financial and operating flexibility.

     Our total outstanding long-term debt (including current portion) as of June 30, 2011, was $1,280.6 million.

     Our debt service obligations and restrictive covenants in our credit facility and the indentures governing our senior unsecured notes could have important consequences. For example, they could:

	•		Make it more difficult for us to satisfy our obligations with respect to our senior unsecured notes and our other indebtedness, which could in turn result in an event of default on such other indebtedness or our outstanding notes;
	•		Impair our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions, or other purposes;
	•		Diminish our ability to withstand a continued or future downturn in our business or the economy generally;
	•		Require us to dedicate a substantial portion of our cash flow from operations to debt service payments, thereby reducing the availability of cash for working capital, capital expenditures, acquisitions, general corporate purposes, or other purposes;
	•		Limit our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate; and
	•		Place us at a competitive disadvantage compared to our competitors that have proportionately less debt.

     Our ability to repay, extend or refinance our existing debt obligations and to obtain future credit will depend primarily on our operating performance, which will be affected by general economic, financial, competitive, legislative, regulatory, business and other factors, many of which are beyond our control. Our ability to refinance existing debt obligations or obtain future credit will also depend upon the current conditions in the credit markets and the availability of credit generally. If we are unable to meet our debt service obligations, or obtain future credit on favorable terms, if at all, we could be forced to restructure or refinance our indebtedness, seek additional equity capital, or sell assets. We may be unable to obtain financing or sell assets on satisfactory terms, or at all.

     We are not prohibited under our indentures from incurring additional indebtedness. Our incurrence of significant additional indebtedness would exacerbate the negative consequences mentioned above, and could adversely affect our ability to repay our senior notes.

Our debt agreements and Williams’ and WPZ’s public indentures contain financial and operating restrictions that may limit our access to credit and affect our ability to operate our business. In addition, our ability to obtain credit in the future will be affected by Williams’ and WPZ’s credit ratings.

     Our public indentures contain various covenants that, among other things, limit our ability to grant certain liens to support indebtedness, merge, or sell all or substantially all of our assets. In addition, our credit facility contains certain financial covenants and restrictions on our ability and our material subsidiaries’ ability to grant certain liens to support indebtedness, our ability to merge or consolidate or sell all or substantially all of our assets, allow any material change in the nature of our business, enter into certain affiliate transactions, and make certain distributions during the continuation of an event of default. These covenants could adversely affect our ability to finance our future operations or capital needs or engage in, expand or pursue our business activities and prevent us from

engaging in certain transactions that might otherwise be considered beneficial to us. Our ability to comply with these covenants may be affected by events beyond our control, including prevailing economic, financial and industry conditions. If market or other economic conditions deteriorate, our current assumptions about future economic conditions turn out to be incorrect or unexpected events occur, our ability to comply with these covenants may be significantly impaired.

     Williams’ and WPZ’s public indentures contain covenants that restrict their and our ability to incur liens to support indebtedness. These covenants could adversely affect our ability to finance our future operations or capital needs or engage in, expand or pursue our business activities and prevent us from engaging in certain transactions that might otherwise be considered beneficial to us. Williams’ and WPZ’s ability to comply with the covenants contained in their respective debt instruments may be affected by events beyond our and their control, including prevailing economic, financial and industry conditions. If market or other economic conditions deteriorate, Williams’ or WPZ’s ability to comply with these covenants may be negatively impacted.

     Our failure to comply with the covenants in our debt agreements could result in events of default. Upon the occurrence of such an event of default, the lenders could elect to declare all amounts outstanding under a particular facility to be immediately due and payable and terminate all commitments, if any, to extend further credit. Certain payment defaults or an acceleration under our public indentures or other material indebtedness could cause a cross-default or cross-acceleration of our credit facility. Such a cross-default or cross-acceleration could have a wider impact on our liquidity than might otherwise arise from a default or acceleration of a single debt instrument. If an event of default occurs, or if our credit facility cross-defaults, and the lenders under the affected debt agreements accelerate the maturity of any loans or other debt outstanding to us, we may not have sufficient liquidity to repay amounts outstanding under such debt agreements.

     Substantially all of Williams’ and WPZ’s operations are conducted through their respective subsidiaries. Williams’ and WPZ’s cash flows are substantially derived from loans, dividends and distributions paid to them by their respective subsidiaries. Williams’ and WPZ’s cash flows are typically utilized to service debt and pay dividends or distributions on their equity, with the balance, if any, reinvested in their respective subsidiaries as loans or contributions to capital. Due to our relationship with Williams and WPZ, our ability to obtain credit will be affected by Williams’ and WPZ’s credit ratings. If Williams or WPZ were to experience deterioration in their respective credit standing or financial condition, our access to credit and our ratings could be adversely affected. Any future downgrading of a Williams or WPZ credit rating would likely also result in a downgrading of our credit rating. A downgrading of a Williams or WPZ credit rating could limit our ability to obtain financing in the future upon favorable terms, if at all.

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).
10.1*		Credit Agreement, dated as of June 03, 2011, by and among Williams Partners L.P., Transcontinental Gas Pipe Line Company, LLC, Northwest Pipeline GP, the lenders and Citibank, N.A., as Administrative Agent.
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.

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: August 4, 2011		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).
10.1*		Credit Agreement, dated as of June 03, 2011, by and among Williams Partners L.P., Transcontinental Gas Pipe Line Company, LLC, Northwest Pipeline GP, the lenders and Citibank, N.A., as Administrative Agent.
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.