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		(I.R.S. Employer
incorporation or organization)		Identification No.)
2800 Post Oak Boulevard
P. O. Box 1396
Houston, Texas		77251
(Address of principal executive offices)		(Zip Code)

     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 definitions of “large accelerated filer,” “accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

     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.

 

 

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 nine months ended September 30, 2009 and 2008			5
Condensed Consolidated Balance Sheet as of September 30, 2009 and December 31, 2008			6
Condensed Consolidated Statement of Cash Flows for the nine months ended September 30, 2009 and 2008			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 4T. Controls and Procedures			23
PART II. OTHER INFORMATION			24
Item 1. Legal Proceedings			24
Item 1A. Risk Factors			24
Item 6. Exhibits			27
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,”

“could,” “may,” “should,” “continues,” “estimates,” “expects,” “forecasts,” “intends,” “might,” “objectives,” “planned,” “potential,” “projects,” “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 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 the current economic slowdown and the disruption of 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 proposed climate change legislation), environmental liabilities, litigation and rate proceedings;
	•		Our costs and funding obligations for defined benefit pension plans and other postretirement benefit plans;
	•		Changes in maintenance and construction costs;
	•		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 and 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, 2008, and Part II, Item 1A. Risk Factors in this Quarterly Report on Form 10-Q.

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								Nine Months Ended
		September 30,								September 30,
		2009				2008				2009				2008
						(Restated)								(Restated)
Operating Revenues:
Natural gas sales		$	17,350			$	42,631			$	80,693			$	113,282
Natural gas transportation			218,320				219,697				664,816				675,679
Natural gas storage			36,160				35,930				108,516				109,482
Other			1,291				1,176				21,595				7,210
Total operating revenues			273,121				299,434				875,620				905,653
Operating Costs and Expenses:
Cost of natural gas sales			17,319				42,630				80,661				113,354
Cost of natural gas transportation			3,024				(138	)			12,873				3,676
Operation and maintenance			62,366				55,091				183,694				165,973
Administrative and general			39,875				39,141				120,157				114,885
Depreciation and amortization			61,591				58,254				183,297				171,404
Taxes — other than income taxes			11,098				13,204				35,516				37,304
Other (income) expense, net			3,674				(6,209	)			7,677				(13,731	)
Total operating costs and expenses			198,947				201,973				623,875				592,865
Operating Income			74,174				97,461				251,745				312,788
Other (Income) and Other Deductions:
Interest expense			23,633				23,811				70,671				72,633
Interest income — affiliates			(5,245	)			(5,210	)			(14,543	)			(16,948	)
Allowance for equity and borrowed funds used during construction (AFUDC)			(4,024	)			(1,678	)			(8,958	)			(4,546	)
Equity in earnings of unconsolidated affiliates			(1,612	)			(1,533	)			(4,517	)			(4,492	)
Miscellaneous other income, net			(673	)			(1,644	)			(3,622	)			(5,184	)
Total other (income) and other deductions			12,079				13,746				39,031				41,463
Income before Income Taxes			62,095				83,715				212,714				271,325
Provision for Income Taxes			—				31,442				—				102,767
Net Income		$	62,095			$	52,273			$	212,714			$	168,558

See accompanying notes.

TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC

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

		September 30,				December 31,
		2009				2008
						(Restated)
ASSETS
Current Assets:
Cash		$	114			$	428
Receivables:
Affiliates			17,531				3,427
Advances to affiliates			243,454				186,249
Others, less allowance of $413 ($424 in 2008)			94,219				91,540
Transportation and exchange gas receivables			2,922				10,649
Inventories			66,553				87,891
Regulatory assets			77,295				86,361
Other			16,977				10,253
Total current assets			519,065				476,798
Investments, at cost plus equity in undistributed earnings			45,555				44,484
Property, Plant and Equipment:
Natural gas transmission plant			7,233,421				7,071,491
Less-Accumulated depreciation and amortization			2,430,603				2,294,112
Total property, plant and equipment, net			4,802,818				4,777,379
Other Assets:
Regulatory assets			219,774				219,472
Other			53,846				46,306
Total other assets			273,620				265,778
Total assets		$	5,641,058			$	5,564,439

See accompanying notes.

TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC

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

		September 30,				December 31,
		2009				2008
						(Restated)
LIABILITIES AND OWNER’S EQUITY
Current Liabilities:
Payables:
Affiliates		$	20,286			$	14,841
Other			100,132				126,667
Transportation and exchange gas payables			2,830				2,851
Accrued liabilities			114,822				144,046
Reserve for rate refunds			1,296				14,362
Total current liabilities			239,366				302,767
Long-Term Debt			1,278,489				1,277,679
Other Long-Term Liabilities:
Asset retirement obligations			234,677				229,360
Regulatory liabilities			65,295				49,808
Accrued employee benefits			156,344				164,799
Other			20,456				13,487
Total other long-term liabilities			476,772				457,454
Contingent liabilities and commitments (Note 3)
Owner’s Equity:
Member’s capital			1,652,434				1,652,430
Retained earnings			2,157,724				2,045,010
Accumulated other comprehensive loss			(163,727	)			(170,901	)
Total owner’s equity			3,646,431				3,526,539
Total liabilities and owner’s equity		$	5,641,058			$	5,564,439

See accompanying notes.

TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC

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

		Nine Months Ended September 30,
		2009				2008
						(Restated)
Cash flows from operating activities:
Net income		$	212,714			$	168,558
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Depreciation and amortization			184,299				172,596
Deferred income taxes			—				83,887
(Gain)/loss on sale of property, plant and equipment			—				(10,542	)
Allowance for equity funds used during construction (Equity AFUDC)			(5,860	)			(3,191	)
Changes in operating assets and liabilities:
Receivables — affiliates			(14,100	)			4,044
— others			(2,830	)			(37,444	)
Transportation and exchange gas receivables			7,727				1,805
Inventories			21,338				(5,136	)
Payables — affiliates			(11,584	)			(244	)
— others			(53,693	)			(130,790	)
Transportation and exchange gas payables			(21	)			(2,551	)
Accrued liabilities			(24,016	)			(77,066	)
Reserve for rate refunds			(13,066	)			57,025
Other, net			20,759				(56,401	)
Net cash provided by operating activities			321,667				164,550
Cash flows from financing activities:
Additions to long-term debt			—				424,332
Retirement of long-term debt			—				(350,000	)
Debt issue costs			—				(2,009	)
Change in cash overdrafts			9,591				28,081
Cash dividends and distributions			(100,000	)			(165,000	)
Net cash used in financing activities			(90,409	)			(64,596	)
Cash flows from investing activities:
Property, plant and equipment additions, net of equity AFUDC *			(160,945	)			(136,681	)
Advances to affiliates, net			(57,205	)			32,908
Advances to others, net			132				152
Purchase of ARO trust investments			(37,455	)			(23,966	)
Proceeds from sale of ARO trust investments			32,912				11,765
Other, net			(9,011	)			15,885
Net cash used in investing activities			(231,572	)			(99,937	)
Net increase (decrease) in cash			(314	)			17
Cash at beginning of period			428				119
Cash at end of period		$	114			$	136
_______________
* Increases to property, plant and equipment		$	(190,484	)		$	(125,698	)
Changes in related accounts payable and accrued liabilities			29,539				(10,983	)
Property, plant and equipment additions, net of equity AFUDC		$	(160,945	)		$	(136,681	)

See accompanying notes.

TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

General

     On December 31, 2008, Transcontinental Gas Pipe Line Corporation was converted from a corporation to a limited liability company and thereafter is known as Transcontinental Gas Pipe Line Company, LLC (Transco). Transco is a wholly-owned subsidiary of Williams Gas Pipeline Company, LLC (WGP). WGP is a wholly-owned subsidiary of The Williams Companies, Inc. (Williams). Effective December 31, 2008, we distributed our ownership interest in our wholly-owned subsidiaries to WGP. Effective September 2009, WGP contributed its ownership interests in certain of these entities to us as follows: TransCardinal Company, LLC (TransCardinal) and 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 transactions.

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

     The condensed consolidated financial statements include our accounts and the accounts of our majority-owned subsidiaries. Companies in which we and our subsidiaries own 20 percent to 50 percent of the voting common stock or otherwise exercise significant influence over operating and financial policies of the company are accounted for under the equity method. The equity method investments as of September 30, 2009 and December 31, 2008 consist of Cardinal Pipeline Company, LLC (Cardinal) with ownership interest of approximately 45% and Pine Needle LNG Company, LLC (Pine Needle) with ownership interest of 35%. Distributions associated with our equity method investments were $3.7 million and $4.2 million in the nine months ended September 30, 2009 and 2008, respectively.

     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 September 30, 2009, and results of operations for the three and nine months ended September 30, 2009 and 2008 and cash flows for the nine months ended September 30, 2009 and 2008. These condensed consolidated financial statements should be read in conjunction with the financial statements and the notes thereto included in our 2008 Annual Report on Form 10-K.

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

     Through an agency agreement, Williams Gas Marketing, Inc. (WGM), an affiliate, manages our remaining jurisdictional merchant gas sales, which excludes our cash out sales in settlement of gas imbalances. The long-term purchase agreements managed by 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, as our agent, assumes all market and credit risk associated with our jurisdictional merchant gas sales. Consequently, our merchant gas sales service has no impact on our operating income or results of operations.

     The preparation of financial statements in conformity with 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. Estimates and assumptions which, in the opinion of management, are significant to the underlying amounts included in the financial statements and for which it would be reasonably possible that future events or information could change those estimates include: 1) revenues subject to refund; 2) litigation-related contingencies; 3) environmental remediation obligations; 4) impairment assessments of long-lived assets; 5) income taxes; 6) depreciation; 7) pensions and other post-employment benefits; and 8) asset retirement obligations.

Accounting Standards Issued But Not Yet Adopted

     In August 2009, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update No. 2009-5, “Fair Value Measurements and Disclosures (Topic 820) - Measuring Liabilities at Fair Value.” This Update provides clarification that in circumstances in which a quoted price in an active market for the identical liability is not available, a reporting entity is required to measure fair value using one or more prescribed techniques. The amendments in this Update also clarify that when estimating the fair value of a liability, a reporting entity is not required to include a separate input or adjustment to other inputs relating to the existence of a restriction that prevents the transfer of the liability. Additionally, this Update clarifies that both a quoted price in an active market for the identical liability at the measurement date and the quoted price for the identical liability when traded as an asset in an active market when no adjustments to the quoted price of the asset are required are Level 1 fair value measurements. The guidance provided in this Update is effective for us beginning with the fourth quarter of 2009. We are currently evaluating this Update to determine the impact to our Consolidated Financial Statements.

Subsequent Events

     We have evaluated our disclosure of subsequent events through the time of filing this Form 10-Q with the SEC on October 29, 2009.

2. CHANGE IN REPORTING ENTITIES

     On December 31, 2008, we distributed our ownership interest in the following companies to WGP: Marsh Resources, LLC; TransCarolina; Pine Needle Operating; TransCardinal and Cardinal Operating. TransCarolina owns a 35 percent interest in Pine Needle, an LNG storage facility. TransCardinal owns a 45 percent interest in

Cardinal, a North Carolina intrastate natural gas pipeline company. These entities were transferred at historical cost as the entities are under common control. No gains or losses were recorded as a result of the distribution.

     Following the guidance of the FASB for when a change in the reporting entity occurs, the change shall be retrospectively applied to the financial statements of all prior periods to show financial information for the new reporting entity. The impact of these retrospective adjustments to our net income for the three and nine months ended September 30, 2008 was a decrease of $1.1 million and $3.0 million, respectively. The impact of these retrospective adjustments to our comprehensive income for the three and nine months ended September 30, 2008 was a decrease of $0.9 million and $3.0 million, respectively.

     Effective September 2009, WGP contributed its ownership interests in certain of the entities, listed above, to us as follows: TransCardinal and Cardinal Operating; TransCarolina and Pine Needle Operating. These entities were transferred at historical cost, as the entities are under common control. No gains or losses were recorded as a result of the contribution. These changes were retrospectively applied to the financial statements.

     The impact of these retrospective adjustments to our net income for the three and nine months ended September 30, 2008 was an increase of $0.9 million and $2.7 million, respectively. The impact of these retrospective adjustments to our comprehensive income for the three and nine months ended September 30, 2008 was an increase of $0.8 million and $2.7 million, respectively.

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) principally designed to recover costs associated with (a) an increase in operation and maintenance expenses and administrative and general expenses; (b) an increase in depreciation expense; (c) the inclusion of costs for asset retirement obligations; (d) an increase in rate base resulting from additional plant; and (e) an increase in rate of return and related taxes. The rates became effective March 1, 2007, subject to refund and the outcome of a hearing. On November 28, 2007, we filed with the FERC a Stipulation and Agreement (Agreement) resolving all but one issue in the rate case. On March 7, 2008, the FERC issued an order approving the Agreement without modifications. Pursuant to its terms, the Agreement became effective on June 1, 2008, and refunds of approximately $144 million were issued on July 17, 2008. We had previously provided a reserve for the refunds.

     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. The ALJ’s decision is subject to review by the FERC.

Legal Proceedings

     In 1998, the United States Department of Justice (DOJ) informed Williams that Jack Grynberg, an individual, had filed claims under the False Claims Act on behalf of himself and the federal government in the United States District Court for the District of Colorado against Williams, certain of its wholly-owned subsidiaries (including us) and approximately 300 other energy companies. Grynberg alleged violations of the False Claims Act in connection with the measurement, royalty valuation and purchase of hydrocarbons. The claim sought an unspecified amount of royalties allegedly not paid to the federal government, treble damages, a civil penalty, attorneys’ fees and costs. In 1999, the DOJ announced that it would not intervene in any of the Grynberg cases. Also in 1999, the Panel on Multi-District Litigation transferred all of these cases, including those filed against us, to the federal court in Wyoming for pre-trial purposes. The District Court dismissed all claims against Williams and its wholly-owned subsidiaries, including us. On March 17, 2009, the Tenth Circuit Court of Appeals affirmed the District Court’s dismissal. On October 5, 2009 the United States Supreme Court denied Grynberg’s petition for a writ of certiorari requesting review of the Tenth Circuit Court of Appeal’s ruling. This matter is concluded.

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 upon a number of assumptions concerning the scope of remediation that will be required at certain locations and the cost of the remedial measures. We are conducting environmental assessments and implementing a variety of remedial measures that may result in increases or decreases in the total estimated costs. At September 30, 2009, we had a balance of approximately $4.2 million for the expense portion of these estimated costs recorded in current liabilities ($0.9 million) and other long-term liabilities ($3.3 million) in the accompanying Condensed Consolidated Balance Sheet.

     We consider prudently incurred environmental assessment and remediation costs and costs associated with compliance with environmental standards to be recoverable through rates. To date, we have been permitted recovery of environmental costs, and it is our intent to continue seeking recovery of such costs through future rate filings. Therefore, these estimated costs of environmental assessment and remediation, less amounts collected, have been recorded as regulatory assets in Current Assets, in the accompanying Condensed Consolidated Balance Sheet. At September 30, 2009, we had recorded approximately $0.3 million of environmental related regulatory assets.

     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.

     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. We anticipate that additional facilities may be subject to increased controls within three years. For many of these facilities, we are developing more cost effective and innovative compressor engine control designs. Due to the developing nature of federal and state emission regulations, it is not possible to precisely determine the ultimate emission control costs. However, the emission control additions required to comply with current Act requirements, the 1990 Amendments, the hazardous air pollutant regulations and the individual state implementation plans for NOx reductions are estimated to include costs in the range of $5 million to $10 million for the period 2009 through 2012. 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. Designation of new eight-hour ozone non-attainment areas will result in additional federal and state regulatory actions that would likely impact our operations and increase the cost of additions to property, plant and equipment. In September 2009, the EPA announced it would reconsider the 2008 NAAQS for ground level ozone to ensure that the standards are clearly grounded in science, and are protective of both public health and the environment. As a result, the EPA has delayed designation of new eight-hour ozone non-attainment areas under the 2008 standards until the reconsideration is complete. Additionally, the EPA is expected to promulgate additional hazardous air pollutant regulations in 2010 that will likely impact our operations. We are unable at this time to estimate with any certainty the cost of additions that may be required to meet new regulations, although we believe that some of those costs are included in the range discussed above. Management considers costs associated with compliance with the environmental laws and regulations described above to be prudent costs incurred in the ordinary course of business and, therefore, recoverable through our rates.

     By letter dated September 20, 2007, the EPA required us to provide information regarding natural gas compressor stations in the states of Mississippi and Alabama as part of 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 $200 million and $250 million over the remaining assessment period of 2009 through 2012. Management considers the costs associated with compliance with the rule to be prudent costs incurred in the ordinary course of business and, therefore, recoverable through our rates.

     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 prescribes various remedial actions that must be undertaken before the lines can be restored to normal operating pressure. On October 6, 2008, we filed a request for hearing with PHMSA to challenge the CAO but asked that the hearing be stayed pending discussions with PHMSA to modify certain aspects of the order. PHMSA approved the request for stay. On November 7, 2008, PHMSA approved our request to restore the first of the three affected pipelines to normal operating pressure. On December 24, 2008, PHMSA approved our request to restore the second of the three affected pipelines to normal operating pressure. On May 6, 2009, PHMSA approved our request to restore the last of the three affected pipelines to normal operating pressure. In August 2009, PHMSA issued to us a Notice of Probable Violation and Proposed Civil Penalty of $1.0 million as a result of the incident. In September 2009, we paid the penalty.

Other Matters

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

Summary

     Litigation, arbitration, regulatory matters, environmental matters and safety matters are subject to inherent uncertainties. Were an unfavorable ruling to occur, there exists the possibility of a material adverse impact on the results of operations in the period in which the ruling occurs. Management, including internal counsel, currently believes that the ultimate resolution of the foregoing matters, taken as a whole and after consideration of amounts accrued, insurance coverage, recovery from customers or other indemnification arrangements will not have a 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 $206 million at September 30, 2009. We have commitments for gas purchases of approximately $67 million at September 30, 2009. See Note 1 of Notes to Condensed Consolidated Financial Statements for our discussion of our agency agreement with WGM.

4. DEBT AND FINANCING ARRANGEMENTS

Revolving Credit and Letter of Credit Facility

     Williams has a $1.5 billion unsecured revolving credit facility (Credit Facility) with a maturity date of May 1, 2012. We have access to $400 million under the Credit Facility to the extent not utilized by Williams. Lehman Commercial Paper Inc., which is committed to fund up to $70 million of the Credit Facility, filed for bankruptcy in October of 2008. Williams expects that its ability to borrow under this facility is reduced by this committed amount. Consequently, we expect our ability to borrow under the Credit Facility is reduced by approximately $18.7 million. The committed amounts of other participating banks remain in effect. As of September 30, 2009, no letters of credit have been issued by the participating institutions. There were no revolving credit loans outstanding as of September 30, 2009. Our ratio of debt to capitalization must be no greater than 55 percent under the Credit Facility. At September 30, 2009, we are in compliance with this covenant.

5. FAIR VALUE MEASUREMENTS

     Pursuant to the terms of the Agreement approved by the FERC in March 2008 (see Note 3 of Notes to Condensed Consolidated Financial Statements), we collect in rates the amounts necessary to fund our asset retirement obligations (ARO). In accordance with the Agreement, we deposit monthly, into an external trust account, the revenues specifically designated for ARO. We established the ARO trust account (ARO Trust) in June 2008. The ARO Trust carries a moderate risk portfolio. We apply the fair value measurements to the financial instruments held in our ARO Trust. However, in accordance with the Accounting Standards Codification 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 amounting to $20.6 million at September 30, 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.

6. FINANCIAL INSTRUMENTS AND GUARANTEES

     Fair value of financial instruments The carrying amount and estimated fair values of our financial instruments as of September 30, 2009 and December 31, 2008 are as follows (in thousands):

		September 30, 2009								December 31, 2008
		Carrying								Carrying
		Amount				Fair Value				Amount				Fair Value
Financial assets:
Cash		$	114			$	114			$	428			$	428
Short-term financial assets			243,978				243,978				186,638				186,638
Long-term financial assets			523				523				655				655
Financial liabilities:
Long-term debt, including current portion			1,278,489				1,402,496				1,277,679				1,154,943

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

     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 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 determined using indicative period-end traded bond market prices. At September 30, 2009 and December 31, 2008, 100 percent of our long-term debt was publicly traded. As a participant in Williams’ cash management program, we make advances to and receive advances from Williams. Advances are stated at the historical carrying amounts. As of September 30, 2009 and December 31, 2008, we had advances to affiliates of $243.5 million and $186.2 million, respectively. Advances to affiliates are due on demand.

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

7. TRANSACTIONS WITH AFFILIATES

     As a participant in Williams’ cash management program, we make advances to and receive advances from Williams. At September 30, 2009 and December 31, 2008, the advances due to us by Williams totaled approximately $243.5 million and $186.2 million, respectively. The advances are represented by demand notes. The interest rate on intercompany demand notes is based upon the weighted average cost of Williams’

debt outstanding at the end of each quarter. At September 30, 2009, the interest rate was 8.01 percent. We received interest income from advances to Williams of $14.5 million and $16.9 million during the nine months ended September 30, 2009 and 2008, respectively.

     Included in our operating revenues for the nine months ending September 30, 2009 and 2008 are revenues received from affiliates of $15.3 million and $27.7 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, WGM manages our remaining jurisdictional merchant gas sales. The agency fees billed by WGM under the agency agreement for the nine months ending September 30, 2009 and 2008 were not significant.

     Included in our cost of sales for the nine months ending September 30, 2009 and 2008 is purchased gas cost from affiliates of $4.1 million and $10.0 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 has a policy of charging subsidiary companies for management services provided by the parent company and other affiliated companies. Included in our administrative and general expenses for the nine months ending September 30, 2009 and 2008, are $37.0 million and $35.8 million, respectively, for such corporate expenses charged by Williams and other affiliated companies. Management considers the cost of these services to be reasonable.

     Pursuant to an operating agreement, we serve as contract operator on certain Williams Field Services Company (WFS) facilities. For the nine months ending September 30, 2009 and 2008, we recorded reductions in operating expenses of $7.4 million and $5.9 million, respectively, for services provided to WFS under terms of the operating agreement.

     Distributions of $50 million were paid during each of the quarters ended June 30, 2009 and September 30, 2009, respectively. No distributions were paid in the quarter ended March 31, 2009. In October 2009, we declared a cash distribution of $45 million.

8. COMPREHENSIVE INCOME

     Comprehensive income is as follows (in thousands):

		Three Months								Nine Months
		Ended September 30,								Ended September 30,
		2009				2008				2009				2008
						(Restated)								(Restated)
Net income		$	62,095			$	52,273			$	212,714			$	168,558
Equity interest in unrealized gain/(loss) on interest rate hedge, net of tax in 2008			8				(168	)			268				43
Pension benefits, net of tax in 2008
Amortization of prior service credit			(7	)			(122	)			(20	)			(366	)
Amortization of net actuarial loss			2,313				428				6,926				1,283
Total comprehensive income		$	64,409			$	52,411			$	219,888			$	169,518

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 Financial Statements, Notes and Management’s Discussion and Analysis contained in Items 7 and 8 of our 2008 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 nine months ended September 30, 2009 was $251.7 million compared to operating income of $312.8 million for the nine months ended September 30, 2008. Net income for the nine months ended September 30, 2009 was $212.7 million compared to $168.6 million for the nine months ended September 30, 2008. The decrease in Operating income of $61.1 million (19.5 percent) was due primarily to the absence of a $10.4 million gain recognized in 2008 related to the sale of our South Texas assets and a $9.5 million gain recognized in 2008 related to the sale of Eminence top gas, a decrease in Natural gas transportation, higher Cost of natural gas transportation, higher Operation and maintenance costs, higher Administrative and general expenses, and higher Depreciation and amortization costs, partially offset by an increase in Other revenues. The increase in Net income of $44.1 million (26.2 percent) was mostly attributable to the absence of Provision for income taxes in 2009, compared to a provision of $102.8 million in 2008, due to our conversion from a corporation to a limited liability company on December 31, 2008, partially offset by the lower Operating income.

Transportation Revenues

     Operating revenues: Natural gas transportation for the nine months ended September 30, 2009 was $664.8 million, compared to $675.7 million for the nine months ended September 30, 2008. The $10.9 million (1.6 percent) decrease was primarily due to lower transportation demand revenues of $6.2 million, $4.7 million

lower transportation commodity revenues on lower volumes transported, the absence of a benefit recognized in 2008 of $2.9 million to revenue amounts reserved in prior months in connection with our general rate case filing, and $4.9 million lower 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 were partially offset by increased revenues of $6.5 million from the Sentinel expansion project which was placed in service in December 2008 and increased revenues of $0.9 million related to gathering revenues which were diminished last year due to Hurricane Ike.

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

     As shown in the table below, our total market-area deliveries for the nine months ended September 30, 2009 decreased 9.7 trillion British Thermal Units (TBtu) (0.8 percent) when compared to the same period in 2008. The decreased deliveries are due to a reduction in industrial loads due to poor economic conditions, milder temperatures in the market area in the nine months ended September 30, 2009 as compared to the same period of 2008, and decreased volumes due to gas wells shut-in and/or damages to gathering lines in the Gulf of Mexico caused by Hurricane Ike. The increase in market area transportation and decrease in long haul transportation is primarily the result of increased receipt volumes at market area pipeline interconnects. Our production-area deliveries for the nine months ended September 30, 2009 decreased 4.4 TBtu (2.9 percent) compared to the same period in 2008. The decrease in production area deliveries is primarily the result of increased deliveries of volumes at market area pipeline interconnects rather than the production area.

		Nine months
		Ended September 30,
Transco System Deliveries (TBtu)		2009				2008
Market-area deliveries:
Long-haul transportation			502.0				577.6
Market-area transportation			765.5				699.6
Total market-area deliveries			1,267.5				1,277.2
Production-area transportation			146.4				150.8
Total system deliveries			1,413.9				1,428.0
Average Daily Transportation Volumes (TBtu)			5.2				5.2
Average Daily Firm Reserved Capacity (TBtu)			6.8				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 agreements and our remaining jurisdictional merchant gas sales, which excludes our cash out sales in settlement of gas imbalances. The long-term purchase agreements managed by 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, as our agent, assumes all market and credit risk associated with our jurisdictional merchant gas sales. Consequently, our merchant gas sales service has no impact on our operating income or results of operations.

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

     Operating revenues: Natural gas sales were $80.7 million for the nine months ended September 30, 2009 compared to $113.3 million for the same period in 2008. The $32.6 million (28.8 percent) decrease was primarily due to lower cash-out sales. These sales were offset in our costs 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 nine months ended September 30, 2009 was comparable for the same period in 2008.

Other Revenues

     Operating revenues: Other increased $14.4 million (200.0 percent) to $21.6 million for the nine months ended September 30, 2009, when compared to the same period in 2008, due to an increase of Park and Loan Service revenue as a result of higher gas volumes parked and/or loaned by customers in 2009. We do not expect this level of Park and Loan Service revenues to continue through the remainder of 2009.

Operating Costs and Expenses

     Excluding the Cost of natural gas sales of $80.7 million for the nine months ended September 30, 2009 and $113.4 million for the comparable period in 2008, our operating expenses for the nine months ended September 30, 2009 were approximately $63.7 million (13.3 percent) higher than the comparable period in 2008. This increase was primarily attributable to:

•

An increase in Cost of natural gas transportation costs of $9.2 million (248.6 percent) primarily resulting from:

	•		A $12.5 million increase due to higher fuel expense in 2009 resulting from less favorable pricing differentials between cost recoveries at spot prices and expenses recognized at weighted average prices in 2009;
	•		A $1.6 million increase associated with the write-off of certain receivables; and

•

Partially offset by $4.9 million lower electric power costs in 2009. Electric power costs are recovered from customers through transportation rates resulting in no net impact on our operating income or results of operations.

•

An increase in Operation and maintenance costs of $17.7 million (10.7 percent) primarily resulting from:

	•		A $7.9 million increase related to miscellaneous contractual services, other outside services, helicopter and aircraft usage, boat usage, and contract labor primarily related to Hurricane Ike damage assessment;
	•		A $5.8 million increase related to labor and labor related costs, primarily higher salaries, other incentive compensation costs, and pension costs; and
	•		A $4.0 million net increase in various other costs.

•

An increase in Administrative and general costs of $5.3 million (4.6 percent) primarily resulting from:

	•		A $6.9 million increase related to labor and labor related costs, primarily higher salaries, other incentive compensation costs, and pension costs;
	•		A $3.4 million increase in allocated corporate expenses;
	•		Partially offset by $2.7 million lower charges associated with a 2008 pipeline rupture; and
	•		A $1.4 million decrease in information systems costs.

	•		An increase in Depreciation and amortization costs of $11.9 million (6.9 percent) primarily resulting from rate adjustments recorded in March 2008, for the period March 2007 through July 2007, due to final settlement rates, an increase in ARO depreciation expense, and an increase in the depreciation base due to additional plant placed in-service.
	•		An increase in Other (income) expenses, net of $21.4 million (156.2 percent) in expense primarily resulting from:

	•		The absence of a $10.4 million gain recognized in 2008 related to the sale of our South Texas assets;
	•		The absence of a $9.5 million gain recognized in 2008 related to the sale of Eminence top gas sold in 2007. In 2007, the gain was deferred pending a FERC Order on our March 2007 fuel tracker filing, which was issued in May 2008; and
	•		A $3.0 million increase in project development costs.

Other (Income) and Other Deductions

     Other (income) and other deductions for the nine months ended September 30, 2009 were $39.0 million compared to $41.5 million for the same period in 2008. The $2.5 million decrease (6.0 percent) was primarily due to:

	•		Higher Allowance for equity and borrowed funds used during construction (AFUDC) of $4.5 million due to higher construction spending in 2009 as compared to 2008;
	•		Lower Interest expense of $1.9 million primarily due to a decrease in interest expense on rate refunds partially offset by an increase in interest on long-term debt;
	•		Partially offsetting these were a decrease in Interest income — affiliates of $2.4 million due to overall lower average advances to affiliates in 2009 as compared to the same period in 2008; and
	•		Lower Miscellaneous other income, net of $1.6 million primarily due to decrease in AFUDC equity gross-up as we no longer provide for income taxes.

Provision for Income Taxes

     There was no Provision for Income Taxes for the nine months ended September 30, 2009, a decrease of $102.8 million (100.0 percent) from the same period in 2008 due to our conversion from a corporation to a single member limited liability company on December 31, 2008. Subsequent to the conversion to a single member limited liability company, we no longer provide for income tax.

Capital Expenditures

     Our capital expenditures for the nine months ended September 30, 2009 were $160.9 million, compared to $136.7 million for the nine months ended September 30, 2008. The $24.2 million increase is primarily due to higher spending on expansion projects in 2009, primarily Sentinel. Our capital expenditures estimate for 2009 and future capital projects are discussed in our 2008 Annual Report on Form 10-K. The following describes those projects and certain new capital projects proposed by us.

     Sentinel Expansion Project. The Sentinel Expansion Project involves an expansion of our existing natural gas transmission system from the Leidy Hub in Clinton County, Pennsylvania and from the Pleasant Valley interconnection with Cove Point LNG in Fairfax County, Virginia to various delivery points requested by the shippers under the project. The capital cost of the project is estimated to be approximately $229 million. Phase I was placed into service in December 2008. Phase II is expected to be placed into service in November 2009.

     Pascagoula Expansion Project. The Pascagoula Expansion Project involves the construction of a new pipeline to be jointly owned with Florida Gas Transmission connecting Transco’s existing Mobile Bay Lateral to the outlet pipeline of a proposed LNG import terminal in Mississippi. Transco’s share of the capital cost of the project is estimated to be approximately $34 million. Transco plans to place the project into service by September 2011.

     Mobile Bay South Expansion Project. The Mobile Bay South Expansion Project involves the addition of compression at Transco’s Station 85 in Choctaw County, Alabama to allow Transco to provide firm

transportation service southbound on the Mobile Bay line from Station 85 to various delivery points. The capital cost of the project is estimated to be approximately $37 million. Transco plans to place the project into service by May 2010.

     Mobile Bay South II Expansion Project. The Mobile Bay South II Expansion Project involves the addition of compression at Transco’s Station 85 in Choctaw County, Alabama and modifications to existing facilities at Transco’s Station 83 in Mobile County, Alabama to allow Transco to provide additional firm transportation service southbound on the Mobile Bay line from Station 85 to various delivery points. The capital cost of the project is estimated to be approximately $36 million. Transco plans 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. The capital cost of the project is estimated to be approximately $241 million. Transco plans to place the project into service in phases, in July 2010 and May 2011.

     Eminence Enhancement Project. The Eminence Enhancement Project involves the installation of additional compression at Transco’s Eminence Storage Field in Covington County, Mississippi which will give project customers enhanced storage injection rights. The capital cost of the project is estimated to be approximately $13 million. The project was placed into service on October 1, 2009.

     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. The capital cost of the project is estimated to be approximately $120 million. Transco plans to place the project into service in November 2012.

     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. Transco plans to place the project into service in November 2012.

Property Insurance Changes

     The overall level of named windstorm property insurance coverage for our assets in the Gulf of Mexico area has substantially decreased effective with the second quarter of 2009 as a result of significantly higher deductible amounts and significantly lower coverage limits. In addition, certain assets are not covered, including smaller offshore lateral pipelines. These uninsured assets represent a small percentage of the total insurable value of our onshore and offshore assets in the Gulf of Mexico area.

ITEM 3. Quantitative and Qualitative Disclosures About Market Risk

     None.

ITEM 4T. 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 end of the period covered by this report. This evaluation was performed under the supervision and with the participation of our management, including our Senior Vice President and our Vice President and Treasurer. Based upon that evaluation, our Senior Vice President and our Vice President and Treasurer concluded that these Disclosure Controls are effective at a reasonable assurance level.

Third-Quarter 2009 Changes in Internal Controls

     There have been no changes during the third quarter of 2009 that have materially affected, or are reasonably likely to materially affect, our Internal Controls.

PART II — OTHER INFORMATION

ITEMS 1. LEGAL PROCEEDINGS

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

ITEM 1A. RISK FACTORS

     Part I, Item 1A. Risk Factors in our Annual Report on Form 10-K for the year ended December 31, 2008, includes 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.

We are subject to risks associated with climate change.

     There is a growing belief that emissions of greenhouse gases may be linked to climate change. Climate change and the costs that may be associated with its impacts and the regulation of greenhouse gases have the potential to affect our business in many ways, including negatively impacting the costs we incur in providing

our products and services, the demand for and consumption of our products and services (due to change in both costs and weather patterns), and the economic health of the regions in which we operate, all of which can create financial risks.

Our operations are subject to governmental laws and regulations relating to the protection of the environment, including those relating to climate change, which may expose us to significant costs and liabilities and could exceed our current expectations.

     Our natural gas transportation and storage operations are subject to extensive federal, state and local environmental laws and regulations governing environmental protection, the discharge of materials into the environment and the security of chemical and industrial facilities. These laws include:

	•		the Federal Clean Air Act and analogous state laws, which impose obligations related to air emissions;
	•		the Federal Water Pollution Control Act of 1972, as renamed and amended as the Clean Water Act (CWA) and analogous state laws, which regulate discharge of wastewaters from our facilities to state and federal waters;
	•		the Federal Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA), and analogous state laws that regulate the cleanup of hazardous substances that may have been released at properties currently or previously owned or operated by us or locations to which we have sent wastes for disposal; and
	•		the Federal Resource Conservation and Recovery Act (RCRA) and analogous state laws that impose requirements for the handling and discharge of solid and hazardous waste from our facilities.

     These laws and regulations may impose numerous obligations that are applicable to our operations including the acquisition of permits to conduct regulated activities, the incurrence of capital expenditures to limit or prevent releases of materials from our pipeline and facilities, and the imposition of substantial costs and penalties for spills, releases and emissions of various regulated substances into the environment resulting from those operations. Various governmental authorities, including the U.S. Environmental Protection Agency and analogous state agencies, and the United States Department of Homeland Security have the power to enforce compliance with these laws and regulations and the permits issued under them, oftentimes requiring difficult and costly actions. Failure to comply with these laws, regulations, and permits may result in the assessment of administrative, civil, and criminal penalties, the imposition of remedial obligations, and the issuance of injunctions limiting or preventing some or all of our operations.

     There is inherent risk of incurring significant environmental costs and liabilities in the operation of natural gas transportation and storage facilities due to the handling of petroleum hydrocarbons and wastes, the occurrence of air emissions and water discharges related to the operations, and historical industry operations and waste disposal practices. Joint and several, strict liability may be incurred without regard to fault under certain environmental laws and regulations, including CERCLA, RCRA and analogous state laws, in connection with spills or releases of natural gas and wastes on, under, or from our properties and facilities. Private parties, including the owners of properties through which our pipeline passes and facilities where our wastes are taken for reclamation or disposal, may have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with environmental laws and regulations or for personal injury

or property damage. Our insurance may not cover all environmental risks and costs or may not provide sufficient coverage if an environmental claim is made against us.

     Our business may be adversely affected by increased costs due to stricter pollution control requirements or liabilities resulting from non-compliance with required operating or other regulatory permits. Also, we might not be able to obtain or maintain from time to time all required environmental regulatory approvals for our operations. If there is a delay in obtaining any required environmental regulatory approvals, or if we fail to obtain and comply with them, the operation of our facilities could be prevented or become subject to additional costs, resulting in potentially material adverse consequences to our business, financial condition, results of operations and cash flows.

     We make assumptions and develop expectations about possible expenditures related to environmental conditions based on current laws and regulations and current interpretations of those laws and regulations. If the interpretation of laws or regulations, or the laws and regulations themselves, change, our assumptions may change, and any new capital costs incurred to comply with such changes may not be recoverable under our regulatory rate structure or our customer contracts. In addition, new environmental laws and regulations might adversely affect our activities, including storage and transportation, as well as waste management and air emissions. For instance, federal and state agencies could impose additional safety requirements, any of which could have a material adverse effect on our business, financial condition, results of operations and cash flows.

We may be subject to legislative and regulatory responses to climate change with which compliance may be costly.

     Recent scientific studies have suggested that emissions of certain gases, commonly referred to as “greenhouse gases,” may be contributing to warming of the earth’s atmosphere, and various governmental bodies have considered legislative and regulatory responses in this area. Legislative and regulatory responses related to climate change create financial risk. The United States Congress and certain states have for some time been considering various forms of legislation related to greenhouse gas emissions. There have also been international efforts seeking legally binding reductions in emissions of greenhouse gases. In addition, increased public awareness and concern may result in more state, federal, and international proposals to reduce or mitigate the emission of greenhouse gases.

     Several bills have been introduced in the United States Congress that would compel carbon dioxide emission reductions. On June 26, 2009, the U.S. House of Representatives passed the “American Clean Energy and Security Act” which is intended to decrease annual greenhouse gas emissions through a variety of measures, including a “cap and trade” system which limits the amount of greenhouse gases that may be emitted and incentives to reduce the nation’s dependence on traditional energy sources. The U.S. Senate is currently considering similar legislation, and numerous states have also announced or adopted programs to stabilize and reduce greenhouse gases. While it is not clear whether any federal climate change law will be passed this year, any of these actions could result in increased costs to (i) operate and maintain our facilities, (ii) install new emission controls on our facilities, and (iii) administer and manage any greenhouse gas emissions program. If we are unable to recover or pass through a significant level of our costs related to complying with climate change regulatory requirements imposed on us, it could have a material adverse effect on our results of operations. To the extent financial markets view climate change and emissions of greenhouse gases as a financial risk, this could negatively impact our cost of and access to capital.

Our assets and operations can be affected by weather and other natural phenomena.

     Our assets and operations can be adversely affected by hurricanes, floods, earthquakes, tornadoes and other natural phenomena and weather conditions, including extreme temperatures, making it more difficult for us to realize the historic rates of return associated with these assets and operations. Insurance may be inadequate, and in some instances, we may be unable to obtain insurance on commercially reasonable terms, if at all. A significant disruption in operations or a significant liability for which we were not fully insured could have a material adverse effect on our business, results of operations and financial condition.

     Our customers’ energy needs vary with weather conditions. To the extent weather conditions are affected by climate change or demand is impacted by regulations associated with climate change, customers’ energy use could increase or decrease depending on the duration and magnitude of the changes, leading either to increased investment or decreased revenues.

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.
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.

SIGNATURE

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

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.
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.