10-Q

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended June 30, 2010

OR

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

For the transition period from                      to                     

Commission File Number 1-7584

TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC

(Exact Name of Registrant as Specified in Its Charter)

Delaware (State or Other Jurisdiction of Incorporation or Organization)	74-1079400 (I.R.S. Employer Identification No.)
2800 Post Oak Boulevard P. O. Box 1396 Houston, Texas (Address of Principal Executive Offices)	77251 (Zip Code)

713-215-2000
(Registrant’s Telephone Number, Including Area Code)

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 o     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 INSTRUCTION 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 Income for the three and six months ended June 30, 2010 and 2009		5
Condensed Consolidated Balance Sheet as of June 30, 2010 and December 31, 2009		6
Condensed Consolidated Statement of Cash Flows for the six months ended June 30, 2010 and 2009		8
Notes to Condensed Consolidated Financial Statements		9
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		18
Item 3. Quantitative and Qualitative Disclosures About Market Risk		23
Item 4. Control and Procedures		23
PART II. OTHER INFORMATION		24
Item 1. Legal Proceedings		24
Item 1A. Risk Factors		24
Item 6. Exhibits		25
EX-31.1
EX-31.2
EX-32

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,”

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“scheduled,” “will,” or other similar expressions. These forward-looking 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 which 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;

• Cost of, changes in, or the results of laws, government regulations (including proposed climate change legislation and/or potential additional regulation of drilling and completion of wells), 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;

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• Changes in the current geopolitical situation;

• Our exposure to the credit risk of our customers;

• Risks related to strategy and financing, including restrictions stemming from our debt agreements, future changes in our credit rating 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 publicity 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, 2009.

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PART 1 — 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,
	2010			2009			2010			2009
				(Restated)						(Restated)
Operating Revenues:
Natural gas sales	$	15,706		$	50,324		$	43,428		$	63,343
Natural gas transportation		223,338			216,513			457,653			446,496
Natural gas storage		36,302			35,867			73,490			72,356
Other		1,335			10,550			3,159			21,238
Total operating revenues		276,681			313,254			577,730			603,433
Operating Costs and Expenses:
Cost of natural gas sales		15,706			50,324			43,428			63,342
Cost of natural gas transportation		3,808			3,174			12,337			9,849
Operation and maintenance		62,609			60,678			121,461			121,328
Administrative and general		40,055			39,962			75,171			80,282
Depreciation and amortization		62,502			60,781			124,996			121,706
Taxes — other than income taxes		11,647			11,710			24,155			24,418
Other expense, net		2,570			2,583			3,763			4,003
Total operating costs and expenses		198,897			229,212			405,311			424,928
Operating Income		77,784			84,042			172,419			178,505
Other (Income) and Other Deductions:
Interest expense		23,733			23,549			47,280			47,038
Interest income — affiliates		(16	)		(5,031	)		(2,178	)		(9,298	)
Allowance for equity and borrowed funds used during construction (AFUDC)		(3,263	)		(2,805	)		(5,831	)		(4,934	)
Equity in earnings of unconsolidated affiliates		(1,525	)		(1,530	)		(3,066	)		(2,905	)
Miscellaneous other (income) deductions, net		78			(346	)		1,314			(2,015	)
Total other (income) and other deductions		19,007			13,837			37,519			27,886
Income before Income Taxes		58,777			70,205			134,900			150,619
Provision for Income Taxes		105			—			234			—
Net Income	$	58,672		$	70,205		$	134,666		$	150,619

See accompanying notes.

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TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC

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

	June 30,		December 31,
	2010		2009
ASSETS
Current Assets:
Cash	$	112	$	108
Receivables:
Affiliates		2,834		5,132
Advances to affiliates		140,330		—
Others, less allowance of $411 ($413 in 2009)		94,236		117,148
Transportation and exchange gas receivables		12,238		7,250
Inventories		75,920		39,164
Regulatory assets		64,060		75,016
Other		20,285		11,792
Total current assets		410,015		255,610
Investments, at cost plus equity in undistributed earnings		47,427		45,488
Property, Plant and Equipment:
Natural gas transmission plant		7,444,694		7,354,805
Less-Accumulated depreciation and amortization		2,566,356		2,474,680
Total property, plant and equipment, net		4,878,338		4,880,125
Other Assets:
Regulatory assets		200,655		197,676
Other		51,551		42,884
Total other assets		252,206		240,560
Total assets	$	5,587,986	$	5,421,783

See accompanying notes.

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TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC

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

	June 30,			December 31,
	2010			2009
LIABILITIES AND OWNER’S EQUITY
Current Liabilities:
Payables
Affiliates	$	45,783		$	24,409
Other		74,531			88,780
Transportation and exchange gas payables		5,174			1,434
Accrued liabilities		80,405			116,226
Reserve for rate refunds		186			564
Total current liabilities		206,079			231,413
Long-Term Debt		1,279,348			1,278,770
Other Long-Term Liabilities:
Asset retirement obligations		235,816			229,401
Regulatory liabilities		95,643			72,021
Accrued employee benefits		—			6,476
Other		8,290			9,145
Total other long-term liabilities		339,749			317,043
Contingent liabilities and commitments (Note 3)
Owner’s Equity:
Member’s capital		1,652,434			1,652,434
Loans to parent		—			(237,526	)
Retained earnings		2,111,043			2,180,367
Accumulated other comprehensive loss		(667	)		(718	)
Total owner’s equity		3,762,810			3,594,557
Total liabilities and owner’s equity	$	5,587,986		$	5,421,783

See accompanying notes.

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TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC

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

	Six Months Ended June 30,
	2010			2009
				(Restated)
Cash flows from operating activities:
Net income	$	134,666		$	150,619
Adjustments to reconcile net income to net cash provided by (used in) operating activities
Depreciation and amortization		124,886			122,365
Allowance for equity funds used during construction (Equity AFUDC)		(3,993	)		(3,240	)
Changes in operating assets and liabilities:
Receivables — affiliates		3,789			(15,559	)
— others		22,912			(13,315	)
Transportation and exchange gas receivables		(4,988	)		731
Inventories		(42,197	)		10,256
Payables — affiliates		3,529			(19,844	)
— others		6,081			(15,753	)
Transportation and exchange gas payables		3,740			(1,976	)
Accrued liabilities		(2,615	)		(15,248	)
Reserve for rate refunds		(378	)		(11,951	)
Other, net		14,020			(1,138	)
Net cash provided by operating activities		259,452			185,947
Cash flows from financing activities:
Change in cash overdrafts		(4,674	)		(3,658	)
Cash distributions		(203,791	)		(50,000	)
Net cash used in financing activities		(208,465	)		(53,658	)
Cash flows from investing activities:
Property, plant and equipment additions, net of equity AFUDC*		(138,677	)		(67,400	)
Disposal of property, plant and equipment		4,925			789
Advances to affiliates, net		95,507			(57,778	)
Purchase of ARO trust investments		(33,145	)		(24,012	)
Proceeds from sale of ARO trust investments		20,812			16,025
Other, net		(405	)		306
Net cash used in investing activities		(50,983	)		(132,070	)
Net increase in cash		4			219
Cash at beginning of period		108			428
Cash at end of period	$	112		$	647

*    Increases to property, plant and equipment	$	(107,660	)	$	(61,217	)
Changes in related accounts payable and accrued liabilities		(31,017	)		(6,183	)
Property, plant and equipment additions, net of equity AFUDC	$	(138,677	)	$	(67,400	)
Supplemental disclosures of significant non-cash transactions:
Loans to Parent reclassified to equity	$	—		$	(16,613	)

See accompanying notes.

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TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

1. BASIS OF PRESENTATION.

     Unless the context clearly indicates otherwise, references in this report to “we,” “us,” “our” or like terms refer to Transcontinental Gas Pipe Line Company, LLC (Transco) and its majority-owned subsidiaries. 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.

     On December 31, 2009, Transco was a wholly-owned subsidiary of Williams Gas Pipeline Company, LLC (WGP). WGP was a wholly-owned subsidiary of The Williams Companies, Inc. (Williams). On February 17, 2010, Williams completed a strategic restructuring which involved contributing substantially all of its domestic midstream and pipeline businesses, which includes us, to Williams Partners L.P. (WPZ). WPZ, a master limited partnership with publicly traded units, is controlled by and consolidated with Williams. Effective February 17, 2010, we are a wholly owned subsidiary of WPZ, approximately 82 percent of whose limited partnership interests and all of whose general partnership interest as of such date were owned by Williams.

     Effective September 2009, WGP contributed its ownership interests in the following entities to us: TransCardinal Company, LLC (TransCardinal), Cardinal Operating Company, LLC (Cardinal Operating), TransCarolina LNG Company, LLC (TransCarolina) and Pine Needle Operating Company, LLC (Pine Needle Operating). Accordingly, we have adjusted financial and operating information retrospectively to reflect the effects of these common control transactions.

     The condensed consolidated financial statements include our accounts and the accounts of our majority-owned subsidiaries. Companies in which we and our subsidiaries own 20 percent to 50 percent of the voting common stock or otherwise exercise significant influence over operating and financial policies of the company are accounted for under the equity method. The equity method investments as of June 30, 2010 and December 31, 2009 consist of Cardinal with ownership interest of approximately 45 percent and Pine Needle with ownership interest of 35 percent. Distributions associated with our equity method investments were $1.2 million in the six months ended June 30, 2010. In addition, distributions totaling $2.4 million were received by WGP during the six months ended June 30, 2009 in which it owned the equity method investments.

     The condensed consolidated financial statements have been prepared from our books and records. Certain information and footnote disclosures normally included in financial statements prepared in accordance with U.S. generally accepted accounting principles (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, 2010, and results of operations for the three and six months ended June 30, 2010 and 2009, and cash flows for the six months

9

ended June 30, 2010 and 2009. These condensed consolidated financial statements should be read in conjunction with the consolidated financial statements and the notes thereto included in our 2009 Annual Report on Form 10-K.

     As a participant in Williams’ cash management program, we made advances to and received advances from Williams. The advances were represented by demand notes. 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. In accordance with Williams’ restructuring of its business, our participation in the Williams’ cash management program terminated on February 28, 2010. On January 31, 2010, our Management Committee authorized a cash distribution which included the amount of our outstanding advances and associated interest receivable which was paid February 16, 2010. Accordingly, the note advance balance and related interest outstanding at December 31, 2009 were reflected as a reduction of our owner’s equity as the advances were not available to us as working capital. As a result of the restructuring, we became a participant in WPZ’s cash management program on March 1, 2010.

     Through an agency agreement, Williams Gas Marketing, Inc. (WGM), 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 WGM 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 WGM. WGM 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 non-operating income to operating income, related to oil and gas royalities, have been made to the 2009 financial statements to conform to the 2010 presentation.

2. RESTATEMENT AND CHANGE IN REPORTING ENTITY.

     As discussed in our 2009 Annual Report on Form 10-K, on January 20, 2010, we concluded that our financial statements for the year ended December 31, 2008 should be restated due to the manner in which we had presented and recognized pension and postretirement obligations in certain benefit plans for which Williams is the plan sponsor. We concluded that the impact of the error is not material to any of the three quarterly periods of 2009.

     Effective September 2009, WGP contributed its ownership interests in the following entities to us: TransCardinal, Cardinal Operating, TransCarolina and Pine Needle Operating. These entities were transferred at historical cost, as the entities were under common control. No gains or losses were recorded as a result of the contributions. These changes were retrospectively applied to the financial statements. The impact of these retrospective adjustments to our net income for the three and six months ended June 30, 2009 was an increase of $1.5 million and $2.9 million, respectively. The impact of these retrospective adjustments to our comprehensive income for the three and six months ended June 30, 2009 was an increase of $1.8 million and $3.2 million, respectively.

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3. CONTINGENT LIABILITIES AND COMMITMENTS.

Rate Matters.

     On March 1, 2001, we submitted to the Federal Energy Regulatory Commission (FERC) a general rate filing (Docket No. RP01-245) to recover increased costs. All cost of service, throughput and throughput mix, cost allocation and rate design issues in this rate proceeding have been resolved by settlement or litigation. The resulting rates were effective from September 1, 2001 to March 1, 2007. A tariff matter in this proceeding has not yet been resolved.

     On August 31, 2006, we submitted to the FERC a general rate filing (Docket No. RP06-569) 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. Two parties have requested rehearing of the FERC’s order.

Environmental Matters.

     Since 1989, we have had studies underway to test some of our facilities for the presence of toxic and hazardous substances to determine to what extent, if any, remediation may be necessary. We have responded to data requests from the U.S. Environmental Protection Agency (EPA) and state agencies regarding such potential contamination of certain of our sites. On the basis of the findings to date, we estimate that environmental assessment and remediation costs under various federal and state statutes will total approximately $8 million to $10 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, 2010, we had a balance of approximately $4.4 million for the expense portion of these estimated costs recorded in current liabilities ($0.8 million) and other long-term liabilities ($3.6 million) in the accompanying Condensed Consolidated Balance Sheet. At June 30, 2009, we had a balance of approximately $4.4 million for the expense portion of these estimated costs recorded in current liabilities ($0.9 million) and other long-term liabilities ($3.5 million).

     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 $8 million to $10 million range discussed above.

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     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 $8 million to $10 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 EPA currently anticipates finalization of the new ground-level ozone standard in August 2010 and anticipates designation of new eight-hour non-attainment areas under the new August 2010 ozone NAAQS standards in July 2011. 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.

     Additionally, in August 2010, the EPA is expected to promulgate National Emission Standards for hazardous air pollutants (NESHAP) regulations that will impact our operations. The emission control additions required to comply with the pending hazardous air pollutant regulations are estimated to include costs in the range of $10 million to $15 million through 2013, the expected compliance date.

     Furthermore, EPA promulgated the Greenhouse Gas (GHG) Mandatory Reporting Rule on October 30, 2009, which requires facilities that emit 25,000 metric tons or more CO₂ equivalent per year from stationary fossil fuel combustion sources to report GHG emissions to EPA annually beginning March 31, 2011 for calendar year 2010. Subsequently, EPA proposed additional reporting requirements on April 12, 2010 to address fugitive/vented GHG emissions from petroleum and natural gas facilities. Final promulgation of the additional reporting requirements is expected by late 2010, with an effective date of January 1, 2011. At such time, 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 EPA annually beginning March 31, 2012 for calendar year 2011. Compliance with this reporting obligation is estimated to cost $5 million to $7 million over the next four to five years.

     In February 2010, EPA promulgated a final rule establishing a new one-hour NO₂ National Ambient Air Quality Standard. The effective date of the new NO₂ standard was April 12, 2010. This new standard

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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, these estimated costs of environmental assessment and remediation, less amounts collected, have been recorded as regulatory assets in Current Assets, in the accompanying Condensed Consolidated Balance sheet. We had no environmental related regulatory assets at June 30, 2010. At June 30, 2009, we had recorded approximately $0.8 million of environmental related regulatory assets.

     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. In July 2009, the EPA requested additional information pertaining to these compressor stations; in August 2009, we submitted the requested information.

Safety Matters.

     Pipeline Integrity Regulations. We have developed an Integrity Management Plan that meets the United States Department of Transportation Pipeline and Hazardous Materials Safety Administration (PHMSA) final rule pursuant to the requirements of the Pipeline Safety Improvement Act of 2002. In meeting the integrity regulations, we have identified high consequence areas and completed our baseline assessment plan. We are on schedule to complete the required assessments within specified timeframes. Currently, we estimate that the cost to perform required assessments and remediation will be between $140 million and $200 million over the remaining assessment period of 2010 through 2012, the majority of which are capital expenditures. Management considers the cost 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 (CAO) 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. 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.

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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 $188 million at June 30, 2010. We have commitments for gas purchases of approximately $46 million at June 30, 2010. See Note 1 of Notes to Condensed Consolidated Financial Statements for our discussion of our agency agreement with WGM.

4. DEBT, FINANCING ARRANGEMENT AND LEASES.

Revolving Credit and Letter of Credit Facility.

     Prior to Williams’ restructuring of its business, we participated in Williams’ unsecured $1.5 billion revolving credit facility (Credit Facility) with a maturity date of May 1, 2012. As part of the restructuring, we were removed as borrowers under the Credit Facility, and on February 17, 2010, we entered into a new $1.75 billion three-year senior unsecured revolving credit facility (the “New Credit Facility”) with WPZ and Northwest Pipeline GP (“Northwest”), as co-borrowers, and Citibank N.A., as administrative agent, and certain other lenders named therein. The full amount of the New Credit Facility is available to WPZ, and may, under certain conditions, be increased by up to an additional $250 million. We may borrow up to $400 million under the New Credit Facility to the extent not otherwise utilized by WPZ and Northwest. At closing, WPZ borrowed $250 million under the New Credit Facility to repay the term loan outstanding under its existing senior unsecured credit agreement. As of June 30, 2010, no loans are outstanding and no letters of credit are issued under the New Credit Facility.

     Interest on borrowings under the New Credit Facility is payable at rates per annum equal to, at the option of the borrower: (1) a fluctuating base rate equal to Citibank, N.A.’s adjusted base rate plus an applicable margin, or (2) a periodic fixed rate equal to London Interbank Offered Rate (LIBOR) plus an applicable margin. The adjusted base rate will be the highest of (i) the federal funds rate plus 0.5 percent, (ii) Citibank N.A.’s publicly announced base rate, and (iii) one-month LIBOR plus 1.0 percent. WPZ pays a commitment fee (currently 0.5 percent) based on the unused portion of the New Credit Facility. The applicable margin and the commitment fee are based on the specific borrower’s senior unsecured long-term debt ratings.

     The New Credit Facility contains various covenants that limit, among other things, the borrower’s and its respective subsidiaries’ ability to incur indebtedness, grant certain liens supporting indebtedness, merge or consolidate, sell all or substantially all of its assets, enter into certain affiliate transactions, make certain distributions during an event of default, and allow any material change in the nature of their business.

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     Under the New Credit Facility, WPZ is required to maintain a ratio of debt to Earnings Before Income Taxes, Interest, Depreciation and Amortization (EBITDA) (each as defined in the New Credit Facility) of no greater than 5.00 to 1.00 for itself and its consolidated subsidiaries. The debt to EBITDA ratio is measured on a rolling four-quarter basis. For us and our consolidated subsidiaries, the ratio of debt to capitalization (defined as net worth plus debt) is not permitted to be greater than 55 percent. Each of the above ratios is tested at the end of each fiscal quarter (with the first full year measured on an annualized basis). At June 30, 2010, we are in compliance with this covenant.

     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 the loans of the defaulting borrower under the New Credit Facility and exercise other rights and remedies.

5. FAIR VALUE MEASUREMENTS.

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

     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 fair value balances based on the observability of those inputs. The three levels of the fair value hierarchy are as follows:

• Level 1 — Quoted prices in active markets for identical assets or liabilities that we have the ability to access. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Our Level 1 consists of financial instruments in our ARO Trust totaling $32.7 million at June 30, 2010 and $22.0 million at December 31, 2009. These financial instruments include money market funds, U.S. equity funds, international equity funds and municipal bond funds.

• Level 2 — Inputs are other than quoted prices in active markets included in Level 1, that are either directly or indirectly observable. These inputs are either directly observable in the marketplace or indirectly observable through corroboration with market data for substantially the full contractual term of the asset or liability being measured. We do not have any Level 2 measurements.

• Level 3 — Includes inputs that are not observable for which there is little, if any market activity for the asset or liability being measured. These inputs reflect management’s best estimate of the assumptions market participants would use in determining fair value. We do not have any Level 3 measurements.

     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 in or out of Level 1 and Level 2 occurred during the period ended June 30, 2010.

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6. FINANCIAL INSTRUMENTS AND GUARANTEES.

     Fair value of financial instruments. The carrying amount and estimated fair values of our financial instruments as of June 30, 2010 and December 31, 2009 are as follow (in thousands);

	June 30, 2010				December 31, 2009
	Carrying		Fair		Carrying		Fair
	Amount		Value		Amount		Value
Financial assets:
Cash	$	112	$	112	$	108	$	108
Short-term financial assets		140,537		140,537		—		—
ARO Trust Investments		32,714		32,714		21,977		21,977
Long-term financial assets		247		247		373		373
Financial liabilities:
Long-term debt, including current portion		1,279,348		1,419,383		1,278,770		1,417,300

     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 indicative period-end traded bond market prices. At June 30, 2010 and December 31, 2009, 100 percent of long-term debt was publicly traded. As a participant in Williams’ or WPZ’s cash management program, we made advances to and received advances from Williams and WPZ. Advances were stated at the historical carrying amounts. At June 30, 2010, the advances due us by WPZ total $140.3 million and are reflected in current assets. At December 31, 2009, the advances due us by Williams totaled $186.1 million and were reflected as a reduction of owner’s equity. Advances to affiliates are due on demand. However, in connection with the restructuring of Williams’ business in February 2010, our Management Committee authorized a distribution which included an amount equivalent to our advance balance and related interest outstanding. Accordingly, our advance balance and related interest receivable at December 31, 2009 were reflected as a reduction of owner’s equity as the advances were not available to us as working capital.

7. TRANSACTIONS WITH AFFILIATES.

     As a participant in Williams’ cash management program, 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. In accordance with Williams’ restructuring of its business, our participation in the Williams’ cash management program terminated on February 28, 2010. We received interest income from advances to Williams of $2.2 million and $9.3 million during the six months ended June 30, 2010 and 2009, respectively.

     In connection with Williams’ restructuring in February 2010, our Management Committee authorized a distribution which included an amount equivalent to our advance balance and related interest outstanding. Accordingly, our advance balance and related interest receivable at December 31, 2009 were reflected as a reduction of owner’s equity as the advances were not available to us as working capital.

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     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, 2010, the advances due us by WPZ totaled approximately $140.3 million. 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, 2010, the interest rate was 0.01 percent. The interest income from these advances to WPZ was minimal during the six months ended June 30, 2010.

     Included in our operating revenues for the six months ending June 30, 2010 and 2009 are revenues received from affiliates of $12.4 million and $10.2 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, WGM manages our remaining jurisdictional merchant gas sales. The agency fees billed by WGM under the agency agreement for the six months ending June 30, 2010 and 2009 were not significant.

     Included in our cost of sales for the six months ending June 30, 2010 and 2009 is purchased gas cost from affiliates of $2.8 million and $3.0 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, WGM 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 charges its subsidiary companies for management services provided by it and other affiliated companies. Included in our administrative and general expenses for the six months ending June 30, 2010 and 2009, are $26.9 million and $25.9 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 ending June 30, 2010 and 2009, we recorded reductions in operating expense of $3.8 million and $3.7 million, respectively, for services provided to and reimbursed by WFS under terms of the operating agreement.

     Two distributions totaling approximately $203.8 million were declared and paid to WGP and a $0.2 million non cash distribution was made to WGP during the six months ended June 30, 2010. A cash distribution of $50.0 million was paid during the quarter ended June 30, 2009. No distributions were paid in the quarter ended March 31, 2009.

     As part of Williams’ restructuring of its business, effective as of February 16, 2010, all of our former employees were transferred to our 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 will provide personnel, facilities, goods and equipment not otherwise provided by us that are necessary to operate our business. In return, we will reimburse TPS for all direct and indirect

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expenses it incurs or payments it makes (including salary, bonus, incentive compensation and benefits) in connection with these services.

8. COMPREHENSIVE INCOME.

     Comprehensive income is as follows (in thousands):

	Three Months				Six Months
	Ended June 30,				Ended June 30,
	2010		2009*		2010		2009*
			(Restated)				(Restated)
Net income	$	57,511	$	70,205	$	133,505	$	150,619
Equity interest in unrealized gain/(loss) on interest rate hedge		28		176		51		260
Total comprehensive income	$	57,539	$	70,381	$	133,556	$	150,879

* Prior year amount has been restated to reflect accounting for pension and postretirement benefit obligations on a multi-employer accounting model (see Note 2 of Notes to Condensed Consolidated Financial Statements). The effect of the restatement decreased Total Comprehensive Income by $1.9 million and $4.6 million for the three and six months ended June 30, 2009, respectively.

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 2009 Annual Report on Form 10-K and with the Condensed Consolidated Financial Statements and Notes contained in this report.

RESULTS OF OPERATIONS.

Operating Income and Net Income.

     Operating income for the six months ended June 30, 2010 was $172.4 million compared to operating income of $178.5 million for the six months ended June 30, 2009. Net income for the six months ended June 30, 2010 was $134.7 million compared to $150.6 million for the six months ended June 30, 2009. The decrease in Operating income of $6.1 million (3.4 percent) was primarily due to lower Other revenues partially offset by higher Natural gas transportation revenues in 2010 compared to 2009. The decrease in Net income of $15.9 million (10.6 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 six months ended June 30, 2010 was $457.7 million, compared to $446.5 million for the same period in 2009. The $11.2 million (2.5 percent) increase was primarily due to higher transportation demand revenues of $13.4 million, $12.9 million from Phase II of our Sentinel expansion placed in service in November 2009 and $1.5 million from Mobile Bay

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South placed in service in May 2010 and $6.0 million higher revenues which recover electric power and certain other costs. Electric power and certain other 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 $7.5 million from lower commodity revenues resulting from lower IT Feeder revenue due to displacement of volumes as a result of new interconnects and declining production attached to our IT Feeder laterals.

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

     Our total system deliveries in trillion British Thermal Units (TBtu) for the six months ended June 30, 2010 and 2009 are shown below.

	Six Months
	Ended June 30,
Transco System Deliveries (TBtu)	2010		2009
Market-area deliveries:
Long-haul transportation		230.6		363.0
Market-area transportation		729.9		507.9
Total market-area deliveries		960.5		870.9
Production-area transportation		85.2		99.6
Total system deliveries		1,045.7		970.5
Average Daily Transportation Volumes (TBtu)		5.8		5.4
Average Daily Firm Reserved Capacity (TBtu)		7.0		6.8

Sales Revenues.

     We make jurisdictional merchant gas sales pursuant to a blanket sales certificate issued by the FERC. Through an agency agreement, WGM manages our long-term purchase agreement and our remaining jurisdictional merchant gas sales, which excludes our cash out sales in settlement of gas imbalances. The long-term purchase agreements managed by WGM 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 WGM. WGM receives all margins associated with the 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.

     In addition to our merchant gas sales, we also have cash out sales which settle gas imbalances with shippers. In the course of providing transportation services to customers, we may receive different quantities of gas from shippers than the quantities delivered on behalf of those shippers. Additionally, we transport gas on various pipeline systems which may deliver different quantities of gas on our behalf than the quantities of gas received from us. These transactions result in gas transportation and exchange

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imbalance receivables and payables. Our tariff includes a method whereby the majority of transportation imbalances are settled on a monthly basis through cash out sales or purchases. The cash out sales have no impact on our operating income or results of operations.

     Operating revenues: Natural gas sales were $43.4 million for the six months ended June 30, 2010 compared to $63.3 million for the same period in 2009. The $19.9 million (31.4 percent) decrease was primarily due to lower cash out sales of $24.5 million, partially offset by higher merchant sales of $1.2 million in 2010 and sales of Hester base gas and Eminence excess top gas of $10.4 million in 2010. Depending on operating conditions, it is possible that we may sell additional Hester base gas during the remainder of 2010, but not at levels that would be significant. Cash out 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.

Storage Revenues.

     Operating revenues: Natural gas storage for the six months ended June 30, 2010 was comparable to the same period in 2009.

Other Revenues.

     Operating revenues: Other decreased $18.0 million (84.9 percent) to $3.2 million for the six months ended June 30, 2010 when compared to the same period in 2009, primarily due to a $17.9 million decrease in Park and Loan Service revenue as a result of lower gas volumes parked and/or loaned by customers in 2010.

Other Operating Costs and Expenses.

     Excluding the Cost of natural gas sales of $43.4 million for the six months ended June 30, 2010 and $63.3 million for the comparable period in 2009, our other operating costs and expenses for the six months ended June 30, 2010 were approximately $0.3 million (0.1 percent) higher than the comparable period in 2009. This increase was primarily attributable to:

• An increase in Cost of natural gas transportation of $2.5 million (25.5 percent) primarily resulting from:

• A $4.2 million increase due to higher electric power costs in 2010. Electric power costs are recovered from customers through transportation rates resulting in no net impact on our operating income or results of operations;

• Partially offset by $0.6 million lower fuel expense in 2010 resulting from more favorable pricing differentials between cost recoveries at spot prices and expenses recognized at weighted average prices than those realized in 2009; and

• A $1.4 million decrease due to lower gas supply expense resulting from a settlement of an imbalance recorded in 2009; and

• An increase in Depreciation and amortization costs of $3.3 million (2.7 percent) primarily resulting from an increase in the depreciation base due to additional plant placed in-service; and

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• Partially offset by a decrease in Administrative and general costs of $5.1 million (6.4 percent) primarily resulting from a decrease related to labor and labor related costs, primarily lower incentive compensation costs and pension costs; and

• A decrease in Other expense, net of $0.2 million (5.0 percent) primarily resulting from:

• A $7.6 million gain on the sale of Hester base gas. In October 2008, the FERC granted us authorization to abandon our Hester Storage Field. As part of the abandonment, we are selling the base gas. One of the provisions of the settlement of our Docket No. RP06-569 rate case (See Note 3 of Notes to Condensed Consolidated Financial Statements) requires that Transco share 45 percent of the gain on the sale of the base gas with its customers. (Depending on operating conditions, it is possible that we may sell additional Hester base gas during the remainder of 2010, but not at levels that would be significant.); and

• A decrease of $1.2 million in an accrued obligation associated with an unclaimed property audit;

• Partially offset by a $4.7 million increase in expense for charges related to a regulatory liability for the over collection of postretirement benefits other than pension costs to be returned to our customers. This amount is offset in revenues and therefore has no impact on operating income or results from operations;

• A $1.8 million increase related to ARO costs;

• A $1.1 million increase in project development costs; and

• A $0.6 million increase related to the amortization of prior regulatory deferrals for the difference between amounts collected in rates and amounts expensed for postretirement benefits other than pension in prior periods. This amount is offset in revenues and therefore has no impact on operating income or results from operations.

Other (Income) and Other Deductions.

     Other (income) and other deductions for six months ended June 30, 2010 were $37.5 million compared to $27.9 million for the same period in 2009. The $9.6 million net increase (34.4 percent) was primarily due to:

• A decrease in Interest income — affiliates of $7.1 million due to overall lower average advances to affiliates in 2010 as compared to the same period in 2009 and a lower interest rate on the note advance to WPZ;

• Higher Miscellaneous other (income) deductions, net of $3.3 million primarily due to a lower amount of reimbursements for tax gross-up related to reimbursable projects;

• Partially offset by higher Allowance for equity and borrowed funds used during construction (AFUDC) of $0.9 million due to higher construction spending in 2010 as compared to 2009.

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Capital Expenditures.

     Our capital expenditures for the six months ended June 30, 2010 were $138.7 million, compared to $67.4 million for the six months ended June 30, 2009. The $71.3 million increase is primarily due to higher spending on expansion projects in 2010. Our capital expenditures estimate for 2010 and future capital projects are discussed in our 2009 Annual Report on Form 10-K. The following describes those projects and certain new capital projects proposed by us.

     Mobile Bay South Expansion Project. The Mobile Bay South Expansion Project involves the addition of compression at our Station 85 in Choctaw County, Alabama to allow us to provide firm transportation service southbound on the Mobile Bay line from Station 85 to various delivery points. In May 2009 we received approval from the FERC. The capital cost of the project is estimated to be approximately $34 million. The project was placed into service in May 2010 and increased capacity by 253 thousand dekatherms per day (Mdt/d.)

     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 $36 million, and it will increase capacity by 380 Mdt/d. We plan to place the project into service by May 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 $241 million, and it will increase capacity by 308 Mdt/d. The first phase was placed into service on July 9, 2010, and the second phase is expected to be placed into service in May 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 proposed LNG import terminal in Mississippi. In July 2010 we received approval from the FERC. Our share of the capital cost of the project is estimated to be up to approximately $34 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. We anticipate filing an application with the FERC in the fourth quarter of 2010. The capital cost of the project is estimated to be approximately $214 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. We anticipate filing an application with the FERC in the fourth quarter of 2010. 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.

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     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 early 2011. The capital cost of the project is estimated to be approximately $120 million. We plan to place the project into service in November 2013, 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. The capital cost of the project is estimated to be approximately $37 million. We plan to place the project into service in November 2013, and it will increase capacity by 100 Mdt/d.

ITEM 3. Quantitative and Qualitative Disclosures About Market Risk.

     None.

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 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 2010 Changes in Internal Controls

     There have been no changes during the second quarter of 2010 that have materially affected, or are reasonably likely to materially affect, our Internal Controls.

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PART II — OTHER INFORMATION.

ITEM 1. LEGAL PROCEEDINGS.

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

ITEM 1A. RISK FACTORS.

     There are no material changes to the Risk Factors previously disclosed in Part 1, Item 1A. Risk Factors in our Annual Report on Form 10-K for the year ended December 31, 2009.

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ITEM 6. EXHIBITS.

     The following instruments are included as exhibits to this report.

Exhibit Number	Description
3.1	Certificate of Conversion and Certificate of Formation, dated December 24, 2008 and effective on December 31, 2008 (filed on February 26, 2009 as Exhibit 3.1 to the company’s Form 10-K), and incorporated herein by reference.
3.2	Operating Agreement of Transco dated December 31, 2008 (filed on February 26, 2009 as Exhibit 3.2 to the Company’s Form 10-K), and incorporated herein by reference.
10.1	Credit Agreement, dated as of February 17, 2010, by and among Williams Partners L.P., Transcontinental Gas Pipe Line Company, LLC, Northwest Pipeline GP, the lenders party thereto and Citibank, N.A., as Administrative Agent (filed as Exhibit 10.5 to Williams Partners L.P.’s Current Report on Form 8-K, filed on February 22, 2010 (File No. 001-32599) and incorporated by reference as Item 10.1 to our Form 8-K filed February 22, 2010).
10.2	Administrative Services Agreement, dated as of February 17, 2010, by and between Transco Pipeline Services LLC and Transcontinental Gas Pipe Line Company, LLC (filed as Exhibit 10.3 to Williams Partners L.P.’s Current Report on Form 8-K, filed on February 22, 2010 (File No. 001-32599) and incorporated by reference as Item 10.2 to our Form 8-K filed February 22, 2010).
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.

*	Filed herewith.
**	Furnished herewith.

25

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: July 29, 2010	By:	/s/ Jeffrey P. Heinrichs
		Jeffrey P. Heinrichs
		Controller and Assistant Treasurer (Principal Accounting Officer)

26

EXHIBIT INDEX.

Exhibit Number	Description
3.1	Certificate of Conversion and Certificate of Formation, dated December 24, 2008 and effective on December 31, 2008 (filed on February 26, 2009 as Exhibit 3.1 to the company’s Form 10-K), and incorporated herein by reference.
3.2	Operating Agreement of Transco dated December 31, 2008 (filed on February 26, 2009 as Exhibit 3.2 to the Company’s Form 10-K), and incorporated herein by reference.
10.1	Credit Agreement, dated as of February 17, 2010, by and among Williams Partners L.P., Transcontinental Gas Pipe Line Company, LLC, Northwest Pipeline GP, the lenders party thereto and Citibank, N.A., as Administrative Agent (filed as Exhibit 10.5 to Williams Partners L.P.’s Current Report on Form 8-K, filed on February 22, 2010 (File No. 001-32599) and incorporated by reference as Item 10.1 to our Form 8-K filed February 22, 2010).
10.2	Administrative Services Agreement, dated as of February 17, 2010, by and between Transco Pipeline Services LLC and Transcontinental Gas Pipe Line Company, LLC (filed as Exhibit 10.3 to Williams Partners L.P.’s Current Report on Form 8-K, filed on February 22, 2010 (File No. 001-32599) and incorporated by reference as Item 10.2 to our Form 8-K filed February 22, 2010).
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.

*	Filed herewith.
**	Furnished herewith.

27

EX-31.1

Exhibit 31-1

SECTION 302 CERTIFICATION

I, Phillip D. Wright, certify that:

1.	I have reviewed this Quarterly Report on Form 10-Q of Transcontinental Gas Pipe Line Company, LLC;
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.	The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
(b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
(c)	Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
(d)	Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions):

(a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
(b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: July 29, 2010

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

EX-31.2

Exhibit 31-2

SECTION 302 CERTIFICATION

I, Richard D. Rodekohr, certify that:

1.	I have reviewed this Quarterly Report on Form 10-Q of Transcontinental Gas Pipe Line Company, LLC;
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.	The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
(b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
(c)	Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
(d)	Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions):

(a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
(b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: July 29, 2010

By:	/s/ Richard D. Rodekohr
	Richard D. Rodekohr
	Vice President and Treasurer (Principal Financial Officer)

EX-32

Exhibit 32

CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

     In connection with the Quarterly Report of Transcontinental Gas Pipe Line Company, LLC (the “Company”) on Form 10-Q for the period ending June 30, 2010 (the “Report”), each of the undersigned hereby certifies, in his capacity as an officer of the Company, pursuant to 18 U.S.C. §1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002, that to his knowledge:

     (1) The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

     (2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Phillip D. Wright  

Phillip D. Wright 

Senior Vice President 
July 29, 2010

/s/ Richard D. Rodekohr  

Richard D. Rodekohr 

Vice President and Treasurer 
July 29, 2010

A signed original of this written statement required by Section 906 has been provided to the Company and will be retained by the Company and furnished to the Securities and Exchange Commission or its staff upon request.

The foregoing certification is being furnished to the Securities and Exchange Commission as an exhibit to the Report and shall not be considered filed as part of the Report.