10-K

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

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

For the fiscal year ended December 31, 2007

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 CORPORATION

(Exact name of Registrant as specified in its charter)

DELAWARE	74-1079400
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
2800 Post Oak Blvd., P. O. Box 1396, Houston, Texas	77251
(Address of principal executive offices)	Zip Code
Registrant’s telephone number, including area code (713) 215-2000

SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:

None

SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:

None

          Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act
          Yes o No þ

          Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.
          Yes o No þ

          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 if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. þ

                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
(Do not check if a smaller reporting company) Smaller reporting company o 

     Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).

Yes o No þ

          No voting or non-voting common equity of registrant is held by non-affiliates.

          The number of shares of Common Stock, par value $1.00 per share, outstanding at January 31, 2008 was 100.

          Documents Incorporated by Reference: None

          The registrant meets the conditions set forth in General Instruction (I)(1)(a) and (b) of Form 10-K and is therefore filing this Form 10-K with the reduced disclosure format.

TRANSCONTINENTAL GAS PIPE LINE CORPORATION
FORM 10-K

TABLE OF CONTENTS

	PAGE
By-Laws of Transco, as Amended and Restated July 16, 2007
Consent of Independent Registered Public Accounting Firm
Power of Attorney with Certified Resolution
Certification of Principal Executive Officer Pursuant to Section 302
Certification of Principal Financial Officer Pursuant to Section 302
Certification of Principal Executive Officer and Principal Financial Officer Pursuant to Section 906

PART 1
Item 1. Business	3
Item 1A. Risk Factors	8
Item 2. Properties	17
Item 3. Legal Proceedings	17
Item 4. Submission of Matters to a Vote of Security Holders (Omitted)	17
PART II
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Repurchases of Equity Securities	17
Item 6. Selected Financial Data (Omitted)	17
Item 7. Management’s Narrative Analysis of Results of Operations	18
Item 7A. Qualitative and Quantitative Disclosures About Market Risk	26
Item 8. Financial Statements and Supplementary Data	27
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	59
Item 9A. Controls and Procedures	59
Item 9B. Other Information	60
PART III
Item 10. Directors and Executive Officers of the Registrant (Omitted)	60
Item 11. Executive Compensation (Omitted)	60
Item 12. Security Ownership of Certain Beneficial Owners and Management (Omitted)	60
Item 13. Certain Relationships and Related Transactions (Omitted)	60
Item 14. Principal Accountant Fees and Services	60
PART IV
Item 15. Exhibits and Financial Statement Schedules	61

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PART I

ITEM 1. Business.

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

GENERAL

     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).

     We are an interstate natural gas transmission company that owns a natural gas pipeline system extending from Texas, Louisiana, Mississippi and the Gulf of Mexico through the states of Alabama, Georgia, South Carolina, North Carolina, Virginia, Maryland, Pennsylvania and New Jersey to the New York City metropolitan area. We also hold a minority interest in Cardinal Pipeline Company, LLC, an intrastate natural gas pipeline located in North Carolina. Our principal business is the interstate transportation of natural gas, which the Federal Energy Regulatory Commission (FERC) regulates.

     As of December 31, 2007, we had 1,315 full time employees.

     At December 31, 2007, our system had a mainline delivery capacity of approximately 4.7 MMdt¹ of gas per day from production areas to our primary markets. Using our Leidy Line and market-area storage and transportation capacity, we can deliver an additional 3.7 MMdt of gas per day for a system-wide delivery capacity total of approximately 8.4 MMdt of gas per day. The system is comprised of approximately 10,300 miles of mainline and branch transmission pipelines, 45 compressor stations, five underground storage fields and two liquefied natural gas (LNG) storage facilities. Compression facilities at sea level rated capacity total approximately 1.5 million horsepower.

     We have natural gas storage capacity in five underground storage fields located on or near our pipeline system and/or market areas and we operate three of these storage fields. We also have storage capacity in an LNG storage facility that we operate. The total usable gas storage capacity available to us and our customers in such underground storage fields and LNG storage facility and through storage service contracts is approximately 216 Bcf of gas. In addition, through wholly-owned subsidiaries we operate and own a 35 percent interest in Pine Needle LNG Company, LLC, an LNG storage facility with 4 Bcf of storage capacity. Storage capacity permits our customers to inject gas into storage during the summer and off-peak periods for delivery during peak winter demand periods.

     Our gas pipeline facilities are generally owned in fee. However, a substantial portion of such facilities are constructed and maintained pursuant to rights-of-way, easements, permits, licenses or consents on and across real property owned by others. Compressor stations, with appurtenant facilities, are located in whole or in part either

¹ As used in this report, the term “Mcf” means thousand cubic feet, the term “MMcf” means million cubic feet, the term “Bcf” means billion cubic feet, the term “Tcf” means trillion cubic feet, the term “Mcf/d” means thousand cubic feet per day, the term “MMcf/d” means million cubic feet per day, the term “Bcf/d” means billion cubic feet per day, the term “MMBtu” means million British Thermal Units, the term “TBtu” means trillion British Thermal Units, the term “dt” means dekatherm, the term “Mdt” means thousand dekatherms, the term “Mdt/d” means thousand dekatherms per day and the term “MMdt” means million dekatherms.

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on lands owned or on sites held under leases or permits issued or approved by public authorities. The storage facilities are either owned or contracted for under long-term leases or easements.

     Through an agency agreement, one of our affiliates, Williams Gas Marketing, Inc. (WGM), formerly Williams Power Company, manages our jurisdictional merchant gas sales.

MARKETS AND TRANSPORTATION

     Our natural gas pipeline system serves customers in Texas and eleven southeast and Atlantic seaboard states including major metropolitan areas in Georgia, North Carolina, New York, New Jersey and Pennsylvania.

     Our major customers are public utilities and municipalities that provide service to residential, commercial, industrial and electric generation end users. Shippers on our pipeline system include public utilities, municipalities, intrastate pipelines, direct industrial users, electrical generators, gas marketers and producers. Our two largest customers in 2007 were Public Service Enterprise Group, and KeySpan Corporation, which accounted for approximately 11.8% and 7.2%, respectively, of our total operating revenues. Our firm transportation agreements are generally long-term agreements with various expiration dates and account for the major portion of our business. Additionally, we offer interruptible transportation services under shorter-term agreements.

     Our total system deliveries for the years 2007, 2006 and 2005 are shown below.

Transco System Deliveries (TBtu)	2007		2006		2005
Market-area deliveries
Long-haul transportation		838.6		795.1		754.9
Market-area transportation		874.9		816.5		852.5
Total market-area deliveries		1,713.5		1,611.6		1,607.4
Production-area transportation		189.9		247.2		278.4
Total system deliveries		1,903.4		1,858.8		1,885.8
Average Daily Transportation Volumes (TBtu)		5.2		5.1		5.2
Average Daily Firm Reserved Capacity (TBtu)		6.6		6.6		6.6

     Our total market-area deliveries for 2007 increased 101.9 TBtu (6.3%) when compared to 2006. The increased deliveries are primarily the result of the colder weather experienced during the winter months throughout Transco’s market area in 2007 compared to the same period in 2006 as well as warmer temperatures experienced in Transco’s southeast markets during the summer months of 2007 compared to the same period in 2006. Our production area deliveries decreased 57.3 TBtu (23.2%) when compared to 2006. The reduction in production area deliveries is due primarily to declining production from the offshore area. Despite this reduction in production area deliveries we were able to increase market area deliveries, primarily due to an increase in receipts from mainline interconnect points.

     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.

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PIPELINE PROJECTS

     The pipeline projects listed below were either completed during 2007 or are future pipeline projects for which we have customer commitments.

     Potomac Expansion Project In November 2007, we placed into service the Potomac Expansion Project, an expansion of our existing natural gas transmission system from receipt points in North Carolina to delivery points in the greater Baltimore and Washington, D.C. metropolitan areas. The second phase of the project involving installation of appurtenant facilities will be completed in fall 2008. The capital cost of the project is estimated to be approximately $88 million.

     Leidy to Long Island Expansion Project In December 2007, we placed into service the Leidy to Long Island Expansion Project, an expansion of our existing natural gas transmission system in Zone 6 from the Leidy Hub in Pennsylvania to Long Island, New York. The capital cost of the project is estimated to be approximately $169 million.

     Sentinel Expansion Project The Sentinel Expansion Project will involve an expansion of our existing natural gas transmission system from the Leidy Hub in Clinton County, Pennsylvania and from the Pleasant Valley interconnection with Cove Point LNG in Fairfax County, Virginia to various delivery points requested by the shippers under the project. The capital cost of the project is estimated to be up to approximately $169 million. Transco plans to place the project into service in phases, in late 2008 and late 2009. 

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

REGULATORY MATTERS

     Our transportation rates are established through the FERC ratemaking process. Key determinants in the ratemaking process are (1) costs of providing service, including depreciation expense, (2) allowed rate of return, including the equity component of the capital structure and related income taxes and (3) volume throughput assumptions. The allowed rate of return is determined in each rate case. Rate design and the allocation of costs between the demand and commodity rates also impact profitability. As a result of these proceedings, certain revenues may be collected subject to refund. We record estimates of rate refund liabilities considering outcomes of our regulatory proceedings, advice of counsel and estimated total exposure, as discounted and risk weighted, as well as collection and other risks.

     Since September 1, 1992, we have designed our rates using the straight fixed-variable (SFV) method of rate design. Under the SFV method of rate design, substantially all fixed costs, including return on equity and income taxes, are included in a demand charge to customers and all variable costs are recovered through a commodity charge to customers. While the use of SFV rate design limits our opportunity to earn incremental revenues through increased throughput, it also limits our risk associated with fluctuations in throughput.

     On March 1, 2001, we submitted to the FERC a general rate filing (Docket No. RP01-245) to recover increased costs.  All cost of service, throughput and throughput mix 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.  Certain cost allocation, rate design and tariff matters in this proceeding have not yet been finally resolved. 

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We believe the resolution of these matters will not have a materially adverse effect upon our future financial position.

     On August 31, 2006, we submitted to the FERC a general rate filing (Docket No. RP06-569) principally designed to recover costs associated with (a) an increase in operation and maintenance expenses and administrative and general expenses; (b) an increase in depreciation expense; (c) the inclusion of costs for asset retirement obligations; (d) an increase in rate base resulting from additional plant; and (e) an increase in rate of return and related taxes. The filing reflected an increase in annual revenues from jurisdictional service of approximately $281 million over the cost of service underlying the rates reflected in the settlement of our Docket No. RP01-245 rate proceeding, as adjusted to include the cost of service and rate base amounts for expansion projects placed in service after the September 1, 2001 effective date of the Docket No. RP01-245 rates. The filing also reflected changes to our tariff, cost allocation and rate design methods, including the refunctionalization of certain facilities from transmission plant accounts to jurisdictional gathering plant accounts consistent with various FERC orders. The rates became effective March 1, 2007, subject to refund and the outcome of a hearing. On November 28, 2007, we filed with the FERC a Stipulation and Agreement (Agreement) resolving all substantive issues in the rate case. The one issue reserved for litigation or further settlement relates to the design of the rates for service under one of Transco’s storage rate schedules. The Agreement is uncontested. On January 9, 2008, the Presiding Administrative Law Judge issued an order certifying the Agreement to the FERC, finding the Agreement to be fair and reasonable and in the public interest, and urging the FERC to approve the Agreement expeditiously. We have provided a reserve for rate refunds which we believe is adequate for any refunds that may be required.

SALES SERVICE

     As discussed above, WGM manages our jurisdictional merchant gas sales, which are made to customers pursuant to a blanket sales certificate issued by the FERC. Most of these sales were previously made through a Firm Sales (FS) program which gave customers the option to purchase daily quantities of gas from us at market-responsive prices in exchange for a demand charge payment. Pursuant to the terms of an agreement with the FERC, we terminated our remaining FS agreements effective April 1, 2005. Through an agency agreement, WGM is still authorized to make gas sales on our behalf in order to manage our remaining gas purchase obligations. 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 and the termination of the FS agreements in April 2005, have no impact on our operating income or results of operations.

     Our gas sales volumes managed by WGM for the years 2007, 2006 and 2005 are shown below.

Gas Sales Volumes (TBtu)	2007		2006		2005
Long-term sales		—		—		7.8
Short-term sales		2.0		3.6		6.7
Total gas sales		2.0		3.6		14.5

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TRANSACTIONS WITH AFFILIATES

     We engage in transactions with Williams and other Williams subsidiaries. See “Item 8. Financial Statements and Supplementary Data — Notes to Consolidated Financial Statements — 1. Summary of Significant Accounting Policies and 8. Transactions with Major Customers and Affiliates.”

REGULATION

     Interstate gas pipeline operations Our interstate transmission and storage activities are subject to regulation by the FERC under the Natural Gas Act of 1938 (NGA) and under the Natural Gas Policy Act of 1978 (NGPA), and, as such, our rates and charges for the transportation of natural gas in interstate commerce, the extension, enlargement or abandonment of jurisdictional facilities, and accounting, among other things, are subject to regulation. We hold certificates of public convenience and necessity issued by the FERC authorizing ownership and operation of pipelines, facilities and properties under the NGA. We are also subject to the Natural Gas Pipeline Safety Act of 1968, as amended by Title I of the Pipeline Safety Act of 1979, and the Pipeline Safety Improvement Act of 2002 which regulate safety requirements in the design, construction, operation and maintenance of interstate gas transmission facilities. The FERC’s Standards of Conduct govern the relationship between natural gas transmission providers and their “marketing affiliates” as defined by the rule. The standards of conduct are intended to prevent natural gas transmission providers from preferentially benefiting their marketing affiliates by requiring the employees of a transmission provider to function independently from employees of marketing affiliates and by restricting the information that transmission providers may provide to marketing affiliates.

     Intrastate gas pipeline operations Cardinal Pipeline Company (Cardinal Pipeline), LLC, a North Carolina natural gas pipeline company, is subject to the jurisdiction of the North Carolina Utilities Commission. Through wholly-owned subsidiaries, we operate and own a 45 percent interest in Cardinal Pipeline.

     Environmental We are subject to the National Environmental Policy Act and federal, state and local laws and regulations relating to environmental quality control. Management believes that, capital expenditures and operation and maintenance expenses required to meet applicable environmental standards and regulations are generally recoverable in rates. For these reasons, management believes that compliance with applicable environmental requirements is not likely to have a material effect upon our competitive position or earnings. See “Item 8. Financial Statements and Supplementary Data — Notes to Consolidated Financial Statements — 3. Contingent Liabilities and Commitments — Environmental Matters.”

COMPETITION

     The natural gas industry has undergone significant change over the past two decades. A highly-liquid competitive commodity market in natural gas and increasingly competitive markets for natural gas services, including competitive secondary markets in pipeline capacity, have developed. As a result, pipeline capacity is being used more efficiently, and peaking and storage services are increasingly effective substitutes for annual pipeline capacity.

     Local distribution company (LDC) and electric industry restructuring by states have affected pipeline markets. Although pipeline operators are increasingly challenged to accommodate the flexibility demanded by customers and allowed under tariffs, the changes implemented at the state level have not required renegotiation of` LDC contracts. The state plans have in some cases discouraged LDCs from signing long-term contracts for new capacity.

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     Several states are considering re-regulation and extending price caps because many regulators and legislators are of the opinion that deregulation has not worked. States are in the process of developing new energy plans that will encourage utilities to encourage energy saving measures and diversify their energy supplies to include renewable sources. This could lower the growth of gas demand. Resistance to coal-fired electricity generation could increase it.

     These factors have increased the risk that customers will reduce their contractual commitments for pipeline capacity. Future utilization of pipeline capacity will depend on competition from LNG imported into markets and new pipelines from the Rockies and other new producing areas, many of which are utilizing MLP structures with a lower cost of capital, as well as the growth of natural gas demand.

Item 1A. Risk Factors.

FORWARD LOOKING STATEMENTS/RISK FACTORS AND CAUTIONARY
STATEMENT FOR PURPOSES OF THE “SAFE HARBOR” PROVISIONS OF
THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995

     Certain matters contained in this report include “forward-looking statements” within the meaning of section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. These statements discuss our expected future results based on current and pending business operations. We make those forward-looking statements in reliance on the safe harbor protections provided under the Private Securities Litigation Reform Act of 1995.

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

• amounts and nature of future capital expenditures;

• expansion and growth of our business and operations;

• business strategy;

• cash flow from operations or results of operations;

• rate case filing; and

• natural gas prices and demand.

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

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

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• inflation, interest rates and general economic conditions;

• the strength and financial resources of our competitors;

• development of alternative energy sources;

• the impact of operational and development hazards;

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

• increasing maintenance and construction costs;

• changes in the current geopolitical situation;

• risks related to strategy and financing, including restrictions stemming from our debt agreements, and future changes in our credit rating;

• risks associated with future weather conditions; and

• acts of terrorism.

     Given the uncertainties and risk factors that could cause our actual results to differ materially from those contained in any forward-looking statement, we caution investors not to unduly rely on our forward-looking statements. We disclaim any obligations 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 document. 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. These factors include the following:

  RISK FACTORS

     You should carefully consider the following risk factors in addition to the other information in this report. Each of these factors could adversely affect our business, operating results, and financial condition as well as adversely affect the value of an investment in our securities.

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Risks Inherent to our Industry and Business

Decreases in the volume of natural gas contracted or transported through our pipeline system for any of the reasons described below will adversely affect our business.

     Expiration of firm transportation agreements. A substantial portion of our operating revenues is generated through firm transportation agreements that expire periodically and must be renegotiated and extended or replaced. We cannot give any assurance as to whether any of these agreements will be extended or replaced or that the terms of any renegotiated agreements will be as favorable as the existing agreements. Upon the expiration of these agreements, should customers turn back or substantially reduce their commitments, we could experience a negative effect to our results of operations.

     Decreases in natural gas production. The development of the additional natural gas reserves that are essential for our gas transmission business to thrive requires significant capital expenditures by others for exploration and development drilling and the installation of production, gathering, storage, transportation and other facilities that permit natural gas to be produced and delivered to our pipeline system. Low prices for natural gas, regulatory limitations, or the lack of available capital for these projects could adversely affect the development and production of additional reserves, as well as gathering, storage, pipeline transmission and import and export of natural gas supplies, adversely impacting our ability to fill the capacities of our gathering, transmission and processing facilities. Additionally, in some cases, new liquefied natural gas (LNG) import facilities built near our markets could result in less demand for our gathering and transmission facilities.

     Decreases in demand for natural gas. Demand depends on the ability and willingness of shippers with access to our facilities to satisfy their demand by deliveries through our system. Any decrease in this demand could adversely affect our business. Demand for natural gas is also affected by weather, future industrial and economic conditions, fuel conservation measures, alternative fuel requirements, governmental regulation, or technological advances in fuel economy and energy generation devices, all of which are matters beyond our control.

     Competitive pressures. Although most of our pipeline system’s current capacity is fully contracted, the FERC has taken certain actions to strengthen market forces in the natural gas pipeline industry that have led to increased competition throughout the industry. In a number of key markets, interstate pipelines are now facing competitive pressure from other major pipeline systems, enabling local distribution companies and end users to choose a transmission provider based on considerations other than location. Other entities could construct new pipelines or expand existing pipelines that could potentially serve the same markets as our pipeline system. Any such new pipelines could offer transportation services that are more desirable to shippers because of locations, facilities, or other factors. These new pipelines could charge rates or provide service to locations that would result in greater net profit for shippers and producers and thereby force us to lower the rates charged for service on our pipeline in order to extend our existing transportation service agreements or to attract new customers We are aware of proposals by competitors to expand pipeline capacity in certain markets we also serve which, if the proposed projects proceed, could increase the competitive pressure upon us. There can be no assurance that we will be able to compete successfully against current and future competitors and any failure to do so could have a material adverse effect on our business and results of operations.

Our gathering and transporting activities involve numerous risks that might result in accidents and other operating risks and hazards.

     Our operations are subject to all the risks and hazards typically associated with the transportation of natural gas. These operating risks include, but are not limited to:

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• blowouts, cratering and explosions;

• uncontrollable flows of natural gas;

• fires;

• pollution and other environmental risks;

• natural disasters;

• aging pipeline infrastructure; and

• terrorist attacks or threatened attacks on our facilities or those of other energy companies.

     In addition, there are inherent in our gas gathering and transporting properties a variety of hazards and operating risks, such as leaks, explosions and mechanical problems that could cause substantial financial losses. In addition, these risks could result in loss of human life, personal injuries, significant damage to property, environmental pollution, impairment of our operations and substantial losses to us. In accordance with customary industry practice, we maintain insurance against some, but not all, of these risks and losses, and only at levels we believe to be appropriate. The location of certain segments of our pipeline in or near populated areas, including residential areas, commercial business centers and industrial sites, could increase the level of damages resulting from these risks. In spite of our precautions, an event could cause considerable harm to people or property, and could have a material adverse effect on our financial condition, particularly if the event is not fully covered by insurance. Accidents or other operating risks could further result in loss of service available to our customers. Such circumstances could adversely impact our ability to meet contractual obligations and retain customers, with a resulting impact on our results of operations.

Costs of environmental liabilities and complying with existing and future environmental regulations could exceed our current expectations.

     Our operations are subject to extensive environmental regulation pursuant to a variety of federal, state and municipal laws and regulations. Such laws and regulations impose, among other things, restrictions, liabilities and obligations in connection with the generation, handling, use, storage, transportation, treatment and disposal of hazardous substances and wastes, in connection with spills, releases and emissions of various substances into the environment, and in connection with the operation, maintenance, abandonment and reclamation of our facilities.

     Compliance with environmental laws requires significant expenditures including those for clean up costs and damages arising out of contaminated properties. In addition, the possible failure to comply with environmental laws and regulations might result in the imposition of fines and penalties. We are generally responsible for all liabilities associated with the environmental condition of our facilities and assets, whether acquired or developed, regardless of when the liabilities arose and whether they are known or unknown. In connection with certain acquisitions and divestitures, we could acquire, or be required to provide indemnification against environmental liabilities that could expose us to material losses, which may not be covered by insurance. In addition, the steps we could be required to take to bring certain facilities into compliance could be prohibitively expensive, and we might be required to shut down, divest or alter the operation of those facilities, which might cause us to incur losses. Although we do not expect that the costs of complying with current environmental laws will have a material adverse effect on our financial condition or results of operations, no

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assurance can be given that the costs of complying with environmental laws in the future will not have such an effect.

     Changes in federal laws or regulations could reduce the availability or increase the cost of our interstate pipeline capacity or gas supply, and thereby reduce our earnings. Congress and certain states have for some time been considering various forms of legislation related to greenhouse gas emissions. There is a possibility that, when and if enacted, the final form of such legislation could increase our costs of compliance with environmental laws.

     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. Our regulatory rate structure and our contracts with customers might not necessarily allow us to recover capital costs we incur to comply with the new environmental regulations. Also, we might not be able to obtain or maintain from time to time all required environmental regulatory approvals for certain development projects. 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 results of operations.

Risks Related to Strategy and Financing

Our debt agreements impose restrictions on us that may adversely affect our ability to operate our business.

     Certain of our debt agreements contain covenants that restrict or limit, among other things, our ability to create liens, sell assets, make certain distributions and incur additional debt. In addition, our debt agreements contain, and those we enter into in the future may contain, financial covenants and other limitations with which we will need to comply. Our ability to comply with these covenants may be affected by many events beyond our control, and we cannot assure you that our future operating results will be sufficient to comply with the covenants or, in the event of a default under any of our debt agreements, to remedy that default.

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

A downgrade of our credit ratings could impact our costs of doing business in certain ways and maintaining current credit ratings is within the control of independent third parties.

      A downgrade of our credit ratings might increase our cost of borrowing. Our ability to access capital markets could also be limited by a downgrade of our credit rating and other disruptions. Such disruptions could include:

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• economic downturns;

• deteriorating capital market conditions generally;

• declining market prices for natural gas;

• terrorist attacks or threatened attacks on our facilities or those of other energy companies; and

• the overall health of the energy industry, including the bankruptcy or insolvency of other energy companies.

     Credit rating agencies perform independent analysis when assigning credit ratings. Given the significant changes in capital markets and the energy industry over the last few years, credit rating agencies continue to review the criteria for attaining investment grade ratings and make changes to those criteria from time to time. While we are currently rated investment grade by three of the major credit rating agencies, no assurance can be given that the credit rating agencies will continue to assign us investment grade ratings even if we meet or exceed their criteria for investment grade ratios.

Williams can exercise substantial control over our dividend policy and our business and operations and may do so in a manner that is adverse to our interests.

     We are an indirect wholly-owned subsidiary of Williams. Our board of directors, which is elected by WGP, which in turn is controlled by Williams, exercises substantial control over our business and operations and makes determinations with respect to, among other things, the following:

• payment of dividends and repayment of advances;

• decisions on financings and our capital raising activities;

• mergers or other business combinations; and

• acquisition or disposition of assets.

     Our board of directors could decide to increase dividends or advances to our parent entities consistent with existing debt covenants. This could adversely affect our liquidity. Moreover, various Williams credit facilities include covenants restricting the ability of Williams entities, including us, to make advances to Williams and its other subsidiaries, which could make the terms on which we may be able to secure additional future financing less favorable.

The financial condition and liquidity of Williams affects our access to capital, our credit standing and our financial condition.

     Substantially all of Williams’ operations are conducted through its subsidiaries. Williams’ cash flows are substantially derived from loans and dividends paid to it by its subsidiaries, including WGP, our parent company under which Williams’ interstate natural gas pipelines and gas pipeline joint venture investments are grouped. Williams’ cash flows are typically utilized to service debt and pay dividends on the common stock of Williams, with the balance, if any, reinvested in its subsidiaries as contributions to capital.

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     Our ratings and credit are impacted by Williams’ credit standing. If Williams were to experience deterioration in its credit standing or liquidity difficulties, our access to credit and our ratings could be adversely affected.

We are exposed to the credit risk of our customers in the ordinary course of our business.

     We are exposed to the credit risk of our customers in the ordinary course of our business. Generally our customers are rated investment grade or are required to make pre-payments or provide security to satisfy credit concerns. However, we cannot predict to what extent our business would be impacted by deteriorating conditions in the energy sector, including declines in our customers’ creditworthiness.

Risks Related to Regulations that Affect our Industry

Our gas sales, transmission, and storage operations are subject to government regulations and rate proceedings that could have an adverse impact on our results of operations.

     Our interstate gas sales, transportation, and storage operations are subject to the FERC’s rules and regulations in accordance with the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978. The FERC’s regulatory authority extends to:

• transportation and sale for resale of natural gas in interstate commerce;

• rates and charges;

• construction;

• acquisition, extension or abandonment of services or facilities;

• accounts and records;

• depreciation and amortization policies; and

• operating terms and conditions of service.

     Regulatory actions in these areas can affect our business in many ways, including decreasing tariff rates and revenues, decreasing volumes in our pipelines, increasing our costs and otherwise altering the profitability of our business.

     The FERC’s Standards of Conduct govern the relationship between natural gas transmission providers and their “marketing affiliates” as defined by the rule. The standards of conduct are intended to prevent natural gas transmission providers from preferentially benefiting their marketing affiliates by requiring the employees of a transmission provider to function independently from employees of marketing affiliates and by restricting the information that transmission providers may provide to marketing affiliates. The inefficiencies created by the restrictions on the sharing of employees and information may increase our costs, and the restrictions on the sharing of information may have an adverse impact on our senior management’s ability to effectively obtain important information about our business. Violators of the rules are subject to potentially substantial civil penalty assessments.

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     Unlike other pipelines that own facilities in the offshore Gulf of Mexico, we charge our transportation customers a separate fee to access our offshore facilities. The separate charge that we assess, which we refer to as an “IT feeder” charge, is charged only when the facilities are used, and typically is paid by producers or marketers. This means that we recover the costs included in the “IT feeder” charge only if our facilities are used, and because it is typically paid by producers and marketers it generally results in netback prices to producers that are slightly lower than the netbacks realized by producers transporting on other interstate pipelines. Longer term, this rate design disparity could result in producers bypassing our offshore facilities in favor of alternative transportation facilities. We have asked the FERC to allow us to eliminate the IT feeder charge and charge for transportation on our offshore facilities in the same manner as the other pipelines. Our requests have been denied.

The outcome of pending rate cases to set the rates we can charge customers on our pipeline might result in rates that lower our return on the capital that we have invested in our pipeline.

     On August 31, 2006, we filed a rate case with the FERC to request changes to the rates we charge. We have sought FERC approval of a settlement of the significant issues in the rate case but until FERC approves the settlement, the outcome of the rate case remains uncertain. There is a risk that rates set by the FERC will lower our return on the capital we have invested in our assets or might not be adequate to recover increases in operating costs. There is also the risk that higher rates will cause us to discount our services or result in our customers seeking alternative ways to transport their natural gas.

Legal and regulatory proceedings and investigations relating to the energy industry and capital markets have adversely affected our business and may continue to do so.

     Public and regulatory scrutiny of the energy industry and of the capital markets has resulted in increased regulation being either proposed or implemented. Such scrutiny has also resulted in various inquiries, investigations and court proceedings in which we or our affiliates are named as defendants. Both the shippers on our pipeline and regulators have rights to challenge the rates we charge under certain circumstances. Any successful challenge could materially affect our results of operations.

     Certain inquiries, investigations and court proceedings are ongoing. We might see adverse effects continue as a result of the uncertainty of these ongoing inquiries and proceedings, or additional inquiries and proceedings by federal or state regulatory agencies or private plaintiffs. In addition, we cannot predict the outcome of any of these inquiries or whether these inquiries will lead to additional legal proceedings against us, civil or criminal fines or penalties, or other regulatory action, including legislation, which might be materially adverse to the operation of our business and our revenues and net income or increase our operating costs in other ways. Current legal proceedings or other matters against us including environmental matters, disputes over gas measurement and royalty payments, suits, regulatory appeals and similar matters might result in adverse decisions against us. The result of such adverse decisions, either individually or in the aggregate, could be material and may not be covered fully or at all by insurance.

Risks Related to Accounting Standards

Potential changes in accounting standards might cause us to revise our financial results and disclosures in the future, which might change the way analysts measure our business or financial performance.

     Regulators and legislators continue to take a renewed look at accounting practices, financial disclosures, companies’ relationships with their independent registered public accounting firms, and retirement plan practices.

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We cannot predict the ultimate impact of any future changes in accounting regulations or practices in general with respect to public companies or the energy industry or in our operations specifically.

     In addition, the Financial Accounting Standards Board (FASB), the Securities and Exchange Commission (SEC) or the FERC could enact new accounting standards or FERC orders that might impact how we are required to record revenues, expenses, assets, liabilities and equity.

Risks Related to Employees, Outsourcing of Non-Core Support Activities, and Technology

Institutional knowledge residing with current employees nearing retirement eligibility might not be adequately preserved.

     In our business, institutional knowledge resides with employees who have many years of service. As these employees reach retirement age, we may not be able to replace them with employees of comparable knowledge and experience. In addition, we may not be able to retain or recruit other qualified individuals and our efforts at knowledge transfer could be inadequate. If knowledge transfer, recruiting and retention efforts are inadequate, access to significant amounts of internal historical knowledge and expertise could become unavailable to us.

Failure of or the disruptions to our outsourcing relationships might negatively impact our ability to conduct our business.

     Some studies indicate a high failure rate of outsourcing relationships. Although Williams has taken steps to build a cooperative and mutually beneficial relationship with its outsourcing providers and to closely monitor their performance, a deterioration in the timeliness or quality of the services performed by the outsourcing providers or a failure of all or part of these relationships could lead to loss of institutional knowledge and interruption of services necessary for us to be able to conduct our business.

     Certain of our accounting, information technology, application development, and help desk services are currently provided by Williams’ outsourcing provider from service centers outside of the United States. The economic and political conditions in certain countries from which Williams’ outsourcing providers may provide services to us present similar risks of business operations located outside of the United States, including risks of interruption of business, war, expropriation, nationalization, renegotiation, trade sanctions or nullification of existing contracts and changes in law or tax policy, that are greater than in the United States.

Risks Related to Weather, other Natural Phenomena and Business Disruption

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

     Our assets and operations, especially those located offshore, can be adversely affected by hurricanes, 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.

Our current pipeline infrastructure is aging and may adversely affect our ability to conduct our business.

     Some portions of our pipeline infrastructure are more than 40 years in age which may impact our ability to provide reliable service. While efforts are ongoing to maintain equipment and pipeline facilities, the current age and condition of this pipeline infrastructure could result in a material adverse impact on our business.

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Acts of terrorism could have a material adverse effect on our financial condition, results of operations and cash flows.

     Our assets and the assets of our customers and others may be targets of terrorist activities that could disrupt our business or cause significant harm to our operations, such as full or partial disruption to our ability to transmit natural gas. Acts of terrorism as well as events occurring in response to or in connection with acts of terrorism could cause environmental repercussions that could result in a significant decrease in revenues or significant reconstruction or remediation costs, which could have a material adverse effect on our financial condition, results of operation and cash flows.

ITEM 2. Properties.

     See “Item 1. Business.”

ITEM 3. Legal Proceedings.

     The information called for by this item is provided in “Item 8. Financial Statements and Supplementary Data – Notes to Consolidated Financial Statements — 3. Contingent Liabilities and Commitments — Legal Proceedings”, which information is incorporated by reference into this item.

ITEM 4. Submission of Matters to a Vote of Security Holders.

     Since we meet the conditions set forth in General Instruction (I)(1)(a) and (b) of Form 10-K, this information is omitted.

PART II

ITEM 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Repurchases of Equity Securities.

     We are an indirect wholly-owned subsidiary of Williams; therefore, our common stock is not publicly traded.

     Our Board of Directors declared and we paid cash dividends on common stock in the amounts of $20 million on March 30, 2007, $20 million on June 29, 2007, $40 million on September 28, 2007 and $30 million on December 31, 2007.

     Our Board of Directors declared and we paid cash dividends on common stock in the amounts of $40 million on March 31, 2006, $40 million on June 30, 2006, $15 million on September 29, 2006 and $10 million on December 29, 2006.

ITEM 6. Selected Financial Data.

     Since we meet the conditions set forth in General Instruction (I)(1)(a) and (b) of Form 10-K, this information is omitted.

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ITEM 7. Management’s Narrative Analysis of the Results of Operations.

GENERAL

     The following discussion and analysis of results of operations and capital resources and liquidity should be read in conjunction with the consolidated financial statements and notes thereto included within Item 8.

CRITICAL ACCOUNTING POLICIES

     Use of estimates The preparation of financial statements in conformity with U.S. generally accepted accounting principles requires management to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes. Actual results could differ from those estimates.

     Regulatory Accounting We are regulated by the FERC. Statement of Financial Accounting Standards (SFAS) No. 71, “Accounting for the Effects of Certain Types of Regulation,” provides that rate-regulated public utilities account for and report regulatory assets and liabilities consistent with the economic effect of the way in which regulators establish rates if the rates established are designed to recover the costs of providing the regulated service and if the competitive environment makes it probable that such rates can be charged and collected. Accounting for businesses that are regulated and apply the provisions of SFAS No. 71 can differ from the accounting requirements for non-regulated businesses. Transactions that are recorded differently as a result of regulatory accounting requirements include the capitalization of an equity return component on regulated capital projects, capitalization of other project costs, retirements of general plant assets, employee related benefits, environmental costs, negative salvage, asset retirement obligations and other costs and taxes included in, or expected to be included in, future rates. As a rate-regulated entity, our management has determined that it is appropriate to apply the accounting prescribed by SFAS No. 71 and, accordingly, the accompanying consolidated financial statements include the effects of the types of transactions described above that result from regulatory accounting requirements. A summary of regulatory assets and liabilities is included in Item 8. Financial Statements and Supplementary Data — Notes to Consolidated Financial Statements - 10. Regulatory Assets and Liabilities.

     Revenue subject to refund FERC regulations promulgate policies and procedures which govern a process to establish the rates that we are permitted to charge customers for natural gas sales and services, including the transportation and storage of natural gas. Key determinants in the ratemaking process are (1) costs of providing service, including depreciation expense, (2) allowed rate of return, including the equity component of the capital structure and related taxes and (3) volume throughput assumptions.

     As a result of the ratemaking process, certain revenues collected by us may be subject to possible refunds upon final orders in pending rate proceedings with the FERC. We record estimates of rate refund liabilities considering our and other third party regulatory proceedings, advice of counsel and estimated total exposure, as discounted and risk weighted, as well as collection and other risks. Depending on the results of these proceedings, the actual amounts allowed to be collected from customers could differ from management’s estimate. In addition, as a result of rate orders, tariff provisions or regulations, we are required to refund or credit certain revenues to our customers. At December 31, 2007, we had accrued approximately $98 million for potential amounts to be refunded or credited.

     Contingent liabilities We record liabilities for estimated loss contingencies when we assess that a loss is probable and the amount of the loss can be reasonably estimated. Revisions to contingent liabilities are reflected

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in income in the period in which new or different facts or information become known or circumstances change that affect the previous assumptions with respect to the likelihood or amount of loss. Liabilities for contingent losses are based upon our assumptions and estimates, and advice of legal counsel or other third parties regarding the probable outcomes of the matter. As new developments occur or more information becomes available, our assumptions and estimates of these liabilities may change. Changes in our assumptions and estimates or outcomes different from our current assumptions and estimates could materially affect future results of operations for any particular quarterly or annual period.

     Impairment of long-lived assets We evaluate long-lived assets for impairment when events or changes in circumstances indicate, in management’s judgment, that the carrying value of such assets may not be recoverable. When such a determination has been made, management’s estimate of undiscounted future cash flows attributable to the assets is compared to the carrying value of the assets to determine whether an impairment has occurred. If an impairment of the carrying value has occurred, the amount of the impairment recognized in the consolidated financial statements is determined by estimating the fair value of the assets and recording a loss for the amount that the carrying value exceeds the estimated fair value.

     Judgments and assumptions are inherent in management’s estimate of undiscounted future cash flows used to determine recoverability of an asset and the estimate of an asset’s fair value used to calculate the amount of impairment to recognize. The use of alternate judgments and/or assumptions could result in the recognition of different levels of impairment charges in the consolidated financial statements.

     Asset Retirement Obligations We record an asset and a liability equal to the present value of each expected future asset retirement obligation (ARO). The ARO asset is depreciated in a manner consistent with the depreciation of the underlying physical asset. We measure changes in the liability due to passage of time by applying an interest method of allocation. This amount is recognized as an increase in the carrying amount of the liability and offset by a regulatory asset, as such amounts are expected to be recovered in future rates.

     Pension and Postretirement Obligations We participate in employee benefit plans with Williams and its subsidiaries that include pension and other postretirement benefits. Pension and other postretirement benefit plan expense and obligations are impacted by various estimates and assumptions. These estimates and assumptions include the expected long-term rates of return on plan assets, discount rates, expected rate of compensation increase, health care trend rates, and employee demographics, including retirement age and mortality. These assumptions are reviewed annually and adjustments are made as needed.

     FERC Accounting Guidance On June 30, 2005, the FERC issued an order, “Accounting for Pipeline Assessment Costs,” to be applied prospectively effective January 1, 2006. The order requires companies to expense certain assessment costs that we have historically capitalized. During 2007 and 2006, we expensed approximately $10 million and $8 million, respectively that previously would have been capitalized.

RESULTS OF OPERATIONS

2007 COMPARED TO 2006

     Operating Income and Net Income Our operating income for 2007 was $327.4 million compared to operating income of $250.0 million for 2006. Net income for 2007 was $172.6 million compared to net income of $117.3 million for 2006. The increase in operating income of $77.4 million (30.9%) was due primarily to an increase in operating revenues, partially offset by increases in depreciation and amortization expenses, other

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operating costs and expenses and other less significant variances, as discussed below. The increase in net income of $55.3 million (47.2%) was mostly attributable to the higher operating income partly offset by an increase in interest expense as discussed below in Other Income and Other Deductions.

     Transportation Revenues Our operating revenues related to transportation services increased $77.4 million (10.0%) to $849.2 million for 2007 when compared to 2006. The higher transportation revenues were primarily due to the effects of placing into effect, subject to refund, the rates in Docket No. RP06-569, on March 1, 2007 and slightly higher market area deliveries.

     Sales Revenues We make jurisdictional merchant gas sales pursuant to a blanket sales certificate issued by the FERC, with most of those sales previously having been made through a Firm Sales (FS) program which gave customers the option to purchase daily quantities of gas from us at market-responsive prices in exchange for a demand charge payment. Pursuant to the terms of an agreement with the FERC, we terminated our remaining FS agreements effective April 1, 2005.

     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 and the termination of the FS agreements in April 2005 have no impact on our operating income or results of operations.

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

     Operating revenues related to our sales services increased $49.8 million to $192.0 million for 2007 when compared to 2006. The 35.0% increase was primarily due to the sales of $59.2 million of excess top gas from our Eminence storage field and an increase in cash out sales of $3.3 million related to monthly settlements of imbalances, partially offset by a lower volume in merchant sales of $12.3 million because of the termination of the FS agreements during 2005. Transco requested authorization from the FERC to sell the excess Eminence top gas inventory and retain any gain on the sales.  The FERC authorized the top gas sales, but consolidated the issue of Transco’s request to retain the gain on the sales with Transco’s general rate case. One of the provisions of the pending Agreement in the Docket No. RP06-569 rate case (See Note 2 of Notes to the Consolidated Financial Statements) requires that Transco share 50% of the gain with its customers. Therefore, the entire gain on the sales of the excess top gas, which was $19.0 million, has been deferred pending final approval of the Agreement.

     Storage Revenues Our operating revenues related to storage services of $141.1 million for 2007 compared to revenues of $119.8 million for 2006. The increase of $21.3 million (17.8%) was primarily due to the effects of placing into effect, subject to refund, the rates in Docket No. RP06-569, on March 1, 2007.

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     Other Revenues Our other operating revenues increased $3.9 million (26.9%) to $18.5 million for 2007, when compared to 2006, primarily due to an increase in revenues from the Park and Loan service of $11.0 million due to a combination of increased volumes and the effect of placing into effect, subject to refund, the rates in Docket No. RP06-569 on March 1, 2007, offset partially by a decrease of $6.7 million in environmental mitigation credit sales.

     Operating Costs and Expenses Excluding the cost of natural gas sales of $191.8 million for 2007 and $142.2 million for 2006, our operating expenses were approximately $25.5 million (3.9%) higher than the comparable period in 2006. This increase was primarily attributable to:

• An increase in depreciation and amortization of $19.3 million primarily due to higher expense associated with negative salvage included in the rates in Docket No. RP06-569, effective March 1, 2007, subject to refund.

• Other operating costs and expenses were $18.6 million higher primarily due to increased expenses associated with our asset retirement obligations (AROs) due to the new rates in Docket No. RP06-569, effective March 1, 2007, subject to refund (See Note 2). In 2006, depreciation expense and accretion expense for AROs of $7.8 million was deferred as a regulatory asset to be recovered through the rates in Docket RP06-569. Effective March 1, 2007, we began collecting amounts for AROs and started amortizing the regulatory asset to expense. In addition, in 2007 we recognized accretion expense of $8.5 million. The variance was also due to the absence of a 2006 reduction of $2.0 million of accrued liabilities for royalty claims associated with certain producer indemnities.

• A decrease in cost of natural gas transportation of $5.9 million primarily due to $3.3 million lower transportation by others associated with agreements that terminated in the third quarter of 2006 and $2.7 million lower fuel expense resulting from favorable pricing differentials between cost recoveries at spot prices and expenses recognized at weighted average prices.

• A decrease in operation and maintenance expense of $6.2 million primarily due to lower costs associated with other material and supplies, and outside and miscellaneous contractual services of $14.0 million, partly offset by higher employee and benefit costs of $ 8.1 million resulting from higher levels of employment in addition to slightly higher level of compensation.

     Other Income and Other Deductions Other income and other deductions resulted in $6.0 million (13.4%) higher net expense in 2007 compared to 2006. This was primarily due to the absence of a 2006 decrease in interest expense of $5.0 million resulting from the reduction of accrued liabilities for royalty claims associated with certain producer indemnities.

EFFECT OF INFLATION

     We generally have experienced increased costs due to the effect of inflation on the cost of labor, materials and supplies, and property, plant and equipment. A portion of the increased labor and materials and supplies cost can directly affect income through increased operation and maintenance expenses. The cumulative impact of inflation over a number of years has resulted in increased costs for current replacement of productive facilities. The majority of our property, plant and equipment and material and supplies inventory is subject to ratemaking treatment, and under current FERC practices, recovery is limited to historical costs. We believe that we will be allowed to recover and earn a return based on increased actual costs incurred when existing facilities are replaced.

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     Cost based regulation along with competition and other market factors limit our ability to price services or products based upon inflation’s effect on costs.

CAPITAL RESOURCES AND LIQUIDITY

METHOD OF FINANCING

     We fund our capital requirements with cash flows from operating activities, repayments of advances to Williams, accessing capital markets, and, if required, borrowings under the credit agreement described below and advances from Williams.

     We have an effective shelf registration statement on file with the Securities and Exchange Commission. At December 31, 2007, $200 million of availability remained under this registration statement. We can also raise capital through private debt offerings as well as offerings registered pursuant to offering-specific registration statements. Interest rates, market conditions, and industry conditions will affect amounts raised, if any, in the capital markets. We believe any additional financing arrangements, if required, can be obtained from the capital markets.

     Williams has an unsecured, $1.5 billion 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 otherwise utilized by Williams. Interest is calculated based on a choice of two methods: a fluctuating rate equal to the lender’s base rate plus an applicable margin or a periodic fixed rate equal to the London Interbank Offered Rate (LIBOR) plus an applicable margin. Williams is required to pay a commitment fee (currently 0.125 percent) based on the unused portion of the Credit Facility. The margins and commitment fee are generally based on the specific borrower’s senior unsecured long-term debt ratings. Significant financial covenants under the credit agreement include the following:

• Williams’ ratio of debt to capitalization must be no greater than 65 percent. At December 31, 2007, Williams was in compliance with this covenant as their ratio of debt to capitalization, as calculated under this covenant, is approximately 51 percent.

• Our ratio of debt to capitalization must be no greater than 55 percent. At December 31, 2007, we are in compliance with this covenant as our ratio of debt to capitalization, as calculated under this covenant, is approximately 31 percent.

     In January 2008, we borrowed $100 million under the Credit Facility to retire $100 million of 6.25% notes (6.25% Notes) that matured on January 15, 2008. The 6.25% Notes, which were issued in January 1998, were retired at the scheduled maturity date with no gain or loss recorded. We intend to refinance the amount borrowed under the Credit Facility.

     As a participant in Williams’ cash management program, we have advances to and from Williams. At December 31, 2007, the advances due to us by Williams totaled $223.7 million. The advances are represented by demand notes. In mid 2008, we intend to recall a large portion of these advances in order to pay rate refunds to our customers after final approval of the Agreement in Docket No. RP06-569. 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 December 31, 2007, the interest rate was 7.83%.

     Through a wholly-owned subsidiary, we hold a 35% interest in Pine Needle LNG Company, LLC (Pine Needle). On March 20, 1998, Pine Needle executed an interest rate swap agreement with a bank, which swapped

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floating rate debt into 6.58% fixed rate debt. This interest rate swap qualifies as a cash flow hedge transaction under the accounting and reporting standards established by SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” as amended by SFAS No. 138, “Accounting for Certain Derivative Instruments and Certain Hedging Activities.” As such, our equity interest in the changes in fair value of Pine Needle’s hedge is recognized in other comprehensive income. For the years ended December 31, 2007 and 2006, our cumulative equity interest in an unrealized loss on Pine Needle’s hedge was $0.4 million and $0.2 million, respectively. The swap agreement initially had a notional amount of $53.5 million, of which $32.6 million was still outstanding at December 31, 2007. The interest rate swap is settled quarterly. The swap agreement was effective March 31, 1999 and terminates on December 31, 2013, which is also the date of the last principal payment on this long-term debt.

Credit Ratings

     We have no guarantees of off-balance sheet debt to third parties and maintain no debt obligations that contain provisions requiring accelerated payment of the related obligations in the event of specified levels of declines in Williams’ or our credit ratings given by Moody’s Investors Service, Standard & Poor’s and Fitch Ratings (rating agencies).

     During 2007, the rating agencies raised the credit ratings on our senior unsecured long-term debt as shown below. The rise in the Moody’s Investor Services and Standard & Poor’s credit ratings moves us to investment grade. Fitch Ratings had increased our credit rating to investment grade in 2006.

Moody’s Investors Services	Ba1 to Baa2
Standard & Poor’s	BB- to BBB-
Fitch Ratings	BBB- to BBB

     With respect to Moody’s, a rating of “Baa” or above indicates an investment grade rating. A rating below “Baa” is considered to have speculative elements. A “Ba” rating indicates an obligation that is judged to have speculative elements and is subject to substantial credit risk. The “1”, “2” and “3” modifiers show the relative standing within a major category. A “1” indicates that an obligation ranks in the higher end of the broad rating category, “2” indicates a mid-range ranking, and “3” ranking at the lower end of the category.

     With respect to Standard & Poor’s, a rating of “BBB” or above indicates an investment grade rating. A rating below “BBB” indicates that the security has significant speculative characteristics. A “BB” rating indicates that Standard & Poor’s believes the issuer has the capacity to meet its financial commitment on the obligation, but adverse business conditions could lead to insufficient ability to meet financial commitments. Standard & Poor’s may modify its ratings with a “+” or a “-” sign to show the obligor’s relative standing within a major rating category.

     With respect to Fitch, a rating of “BBB” or above indicates an investment grade rating. A rating below “BBB” is considered speculative grade. A “BB” rating from Fitch indicates that there is a possibility of credit risk developing, particularly as the result of adverse economic change over time; however, business or financial alternatives may be available to allow financial commitments to be met. Fitch may add a “+” or a “-” sign to show the obligor’s relative standing within a major rating category.

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CAPITAL EXPENDITURES

     We categorize our capital expenditures as either maintenance capital expenditures or expansion capital expenditures. Maintenance capital expenditures are those expenditures required to maintain the existing operating capacity and service capability of our assets, including replacement of system components and equipment that are worn, obsolete, completing their useful life, or necessary to remain in compliance with environmental laws and regulations. Expansion capital expenditures improve the service capability of the existing assets, extend useful lives, increase transmission or storage capacities from existing levels, reduce costs or enhance revenues. As shown in the table below, our capital expenditures for 2007 included $201 million for expansion projects, primarily for Leidy to Long Island, Sentinel and Potomac and $174 million for maintenance of existing facilities and other projects including expenditures required under the Pipeline Safety Improvement Act of 2002. We are estimating approximately $200 million to $240 million of capital expenditures in the year 2008 related to the maintenance of existing facilities, including pipeline safety expenditures, and expansion projects, primarily the Sentinel project.

Capital Expenditures	2007		2006		2005
			(In millions)
Expansion Projects	$	201.0	$	33.7	$	20.3
Maintenance of Existing Facilities and Other Projects		174.4		309.1		233.4
Total Capital Expenditures	$	375.4	$	342.8	$	253.7

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OTHER CAPITAL REQUIREMENTS, CONTRACTUAL OBLIGATIONS AND CONTINGENCIES

     Contractual obligations The table below summarizes the maturity dates of our contractual obligations by period (in millions).

				2009-		2011-		There-
	2008			2010		2012		after		Total
Long-term debt, including current portion:
Principal	$	175	(1)	$	—	$	625	$	408	$	1,208
Interest		83			155		134		256		628
Capital leases		—			—		—		—		—
Operating leases		6			13		14		9		42
Purchase obligations:
Natural gas purchase, storage and transportation		93			110		86		48		337
Other		102	(2)		6		5		1		114
Total	$	459		$	284	$	864	$	722	$	2,329

(1)	See Item 8, Note 4 of the Notes to the Consolidated Financial Statements. Includes $100 million 6.25% Notes due January 15, 2008, reclassified as long-term debt on the Consolidated Balance Sheet, as a result of subsequent refinancing through the borrowing under the $1.5 billion Credit Facility.
(2)	Obligations primarily associated with Property, Plant and Equipment expenditures.

     Regulatory and legal proceedings As discussed in Notes 2 and 3 of the Notes to Consolidated Financial Statements included in Item 8 herein, we are involved in several pending regulatory and legal proceedings. Because of the complexities of the issues involved in these proceedings, we cannot predict the actual timing of resolution or the ultimate amounts, which might have to be refunded or paid in connection with the resolution of these pending regulatory and legal proceedings.

     Environmental matters As discussed in Note 3 of the Notes to Consolidated Financial Statements included in Item 8 herein, we are subject to extensive federal, state and local environmental laws and regulations which affect our operations related to the construction and operation of our pipeline facilities. We consider environmental assessment and remediation costs and costs associated with compliance with environmental standards to be recoverable through rates, as they are prudent costs incurred in the ordinary course of business. To date, we have been permitted recovery of environmental costs incurred, and it is our intent to continue seeking recovery of such costs, as incurred, through rate filings.

     Long-term gas purchase contracts We have long-term gas purchase contracts containing variable prices that are currently in the range of estimated market prices. However, due to contract expirations and estimated deliverability declines, our estimated purchase commitments under such gas purchase contracts are not material to our total gas purchases.

CONCLUSION

     Although no assurances can be given, we currently believe that the aggregate of cash flows from operating activities, supplemented, when necessary, by repayments of funds advanced to Williams, advances or capital contributions from Williams and borrowings under the Credit Agreement will provide us with sufficient liquidity

25

to meet our capital requirements. In addition, we access public and private markets on terms commensurate with our current credit ratings to finance our capital requirements.

ITEM 7A. Qualitative and Quantitative Disclosures About Market Risk

     Due to variable rate issues in our debt portfolio, our interest rate risk exposure is influenced by short-term rates, primarily London Interbank Offered Rate (LIBOR) on borrowings from commercial banks. To mitigate the impact of fluctuations in short-term interest rates, we maintain a significant portion of our debt portfolio in fixed rate debt.

     The following tables provide information about our long-term debt, including current maturities, as of December 31, 2007. The tables present principal cash flows and weighted-average interest rates by expected maturity dates.

	Expected Maturity Date
December 31, 2007	2008			2009			2010			2011
				(Dollars in millions)
Long-term debt:
Fixed rate	$	100	(1)	$	—		$	—		$	300
Interest rate		7.49	%		7.53	%		7.53	%		7.59	%
Variable rate	$	75		$	—		$	—		$	—
Interest rate (6.52% to 6.64% for 2007)

	Expected Maturity Date
December 31, 2007	2012			Thereafter			Total		Fair Value
				(Dollars in millions)
Long-term debt:
Fixed rate	$	325		$	408		$	1,133	$	1,221
Interest rate		7.45	%		7.09	%
Variable rate	$	—		$	—		$	75	$	75
Interest rate (6.52% to 6.64% for 2007)

(1) See Item 8, Note 4 of the Notes to the Consolidated Financial Statements. Includes $100 million 6.25% Notes due January 15, 2008, reclassified as long-term debt on the Consolidated Balance Sheet, as a result of subsequent refinancing through the borrowing under the $1.5 billion Credit Facility.

26

ITEM 8. Financial Statements and Supplementary Data

	Page
Management’s Report on Internal Control over Financial Reporting		28
Report of Independent Registered Public Accounting Firm		29
Consolidated Statement of Income		30
Consolidated Balance Sheet		31-32
Consolidated Statement of Common Stockholder’s Equity		33
Consolidated Statement of Comprehensive Income		34
Consolidated Statement of Cash Flows		35-36
Notes to Consolidated Financial Statements		37-58

27

MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER
FINANCIAL REPORTING

     Transcontinental Gas Pipe Line Corporation’s (Transco) management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rules 13a-15(f) under the Securities Exchange Act of 1934) and for the assessment of the effectiveness of internal control over financial reporting. Our internal control system was designed to provide reasonable assurance to our management and Board of Directors regarding the preparation and fair presentation of financial statements in accordance with accounting principles generally accepted in the United States. Our internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of record that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of our assets; (ii) provide reasonable assurance that transactions are recorded as to permit preparation of financial statements in accordance with generally accepted accounting principles, and that our receipts and expenditures are being made only in accordance with authorization of our management and Board of Directors; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on our financial statements.

     All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of change in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

     Our management assessed the effectiveness of Transco’s internal control over financial reporting as of December 31, 2007. In making this assessment, management used the criteria set forth by the Committee of

     Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control – Integrated Framework. Management’s assessment included an evaluation of the design of our internal control over financial reporting and testing of the operational effectiveness of our internal control over financial reporting. Based on our assessment we believe that, as of December 31, 2007, Transco’s internal control over financial reporting is effective based on those criteria.

     This annual report does not include an attestation report of the company’s registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by the company’s registered public accounting firm pursuant to temporary rules of the Securities and Exchange Commission that permit the company to provide only management’s report in this annual report.

28

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors of Transcontinental Gas Pipe Line Corporation

     We have audited the accompanying consolidated balance sheets of Transcontinental Gas Pipe Line Corporation as of December 31, 2007 and 2006, and the related consolidated statements of income, comprehensive income, common stockholder’s equity, and cash flows for each of the three years in the period ended December 31, 2007. Our audits also included the financial statement schedule listed in the Index at Item 15(a). These financial statements and schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and schedule based on our audits.

     We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Company’s internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

     In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Transcontinental Gas Pipe Line Corporation at December 31, 2007 and 2006, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2007, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein.

ERNST & YOUNG LLP               

Houston, Texas
February 25, 2008

29

TRANSCONTINENTAL GAS PIPE LINE CORPORATION

CONSOLIDATED STATEMENT OF INCOME

(Thousands of Dollars)

	Years Ended December 31,
	2007			2006			2005
Operating Revenues:
Natural gas sales	$	192,006		$	142,252		$	288,294
Natural gas transportation		849,246			771,855			767,919
Natural gas storage		141,098			119,750			122,117
Other		18,455			14,534			8,083
Total operating revenues		1,200,805			1,048,391			1,186,413
Operating Costs and Expenses:
Cost of natural gas sales		191,841			142,248			288,256
Cost of natural gas transportation		5,518			11,414			(5,815	)
Operation and maintenance		225,791			232,002			200,030
Administrative and general		164,928			165,367			120,471
Depreciation and amortization		225,120			205,860			195,744
Taxes – other than income taxes		51,334			51,146			43,669
Other (income) expense, net		8,915			(9,679	)		1,973
Total operating costs and expenses		873,447			798,358			844,328
Operating Income		327,358			250,033			342,085
Other (Income) and Other Deductions:
Interest expense — affiliates		463			942			—
— other		94,641			85,064			79,661
Interest income — affiliates		(15,764	)		(14,310	)		(10,172	)
—other		(748	)		(762	)		(851	)
Allowance for equity and borrowed funds used during construction (AFUDC)		(12,951	)		(11,148	)		(9,270	)
Equity in earnings of unconsolidated affiliates		(6,730	)		(7,498	)		(7,185	)
Miscellaneous other (income) deductions, net		(8,008	)		(7,382	)		(5,352	)
Total other (income) and other deductions		50,903			44,906			46,831
Income before Income Taxes		276,455			205,127			295,254
Provision for Income Taxes		103,872			87,876			109,939
Net Income	$	172,583		$	117,251		$	185,315

See accompanying notes.

30

TRANSCONTINENTAL GAS PIPE LINE CORPORATION

CONSOLIDATED BALANCE SHEET

(Thousands of Dollars)

	December 31,
	2007		2006
ASSETS
Current Assets:
Cash	$	119	$	315
Receivables:
Trade less allowance of $462 ($503 in 2006)		105,427		73,378
Affiliates		6,307		7,814
Advances to affiliates		223,657		190,399
Other		9,576		11,067
Transportation and exchange gas receivables		10,724		7,075
Inventories:
Gas in storage, at LIFO		55		25,361
Gas in storage, at original cost		809		811
Gas available for customer nomination, at average cost		25,686		10,901
Materials and supplies, at lower of average cost or market		28,570		27,748
Deferred income taxes		38,588		17,414
Other		33,619		28,557
Total current assets		483,137		400,840
Investments, at cost plus equity in undistributed earnings		44,730		44,820
Property, Plant and Equipment:
Natural gas transmission plant		6,840,377		6,480,478
Less – Accumulated depreciation and amortization		2,113,561		1,939,430
Total property, plant and equipment, net		4,726,816		4,541,048
Other Assets		256,169		300,587
	$	5,510,852	$	5,287,295

See accompanying notes.

31

TRANSCONTINENTAL GAS PIPE LINE CORPORATION

CONSOLIDATED BALANCE SHEET
(Thousands of Dollars)

	December 31,
	2007			2006
LIABILITIES AND STOCKHOLDER’S EQUITY
Current Liabilities:
Payables:
Trade	$	74,030		$	83,517
Affiliates		15,530			23,007
Cash Overdrafts		12,243			29,901
Transportation and exchange gas payables		7,245			14,693
Accrued liabilities:
Federal income taxes payable to affiliate		53,630			—
State income taxes		5,327			—
Other taxes		15,244			15,038
Interest		29,331			29,338
Deferred cash out		7,648			15,823
Employee benefits		36,197			32,494
Other		56,928			22,443
Reserve for rate refunds		98,035			2,232
Current maturities of long-term debt		75,000			—
Total current liabilities		486,388			268,486
Long-Term Debt		1,127,370			1,201,458
Other Long-Term Liabilities:
Deferred income taxes		1,027,441			1,013,282
Asset retirement obligations		141,416			136,171
Other		113,737			129,462
Total other long-term liabilities		1,282,594			1,278,915
Contingent liabilities and commitments (Note 3)
Cumulative Redeemable Preferred Stock, without par value:
Authorized 10,000,000 shares: none issued or outstanding		—			—
Cumulative Redeemable Second Preferred Stock, without par value:
Authorized 2,000,000 shares: none issued or outstanding		—			—
Common Stockholder’s Equity:
Common Stock $1.00 par value:
100 shares authorized, issued and outstanding		—			—
Premium on capital stock and other paid-in capital		1,652,430			1,652,430
Retained earnings		977,434			914,851
Accumulated other comprehensive loss		(15,364	)		(28,845	)
Total common stockholder’s equity		2,614,500			2,538,436
	$	5,510,852		$	5,287,295

See accompanying notes.

32

TRANSCONTINENTAL GAS PIPE LINE CORPORATION

CONSOLIDATED STATEMENT OF COMMON STOCKHOLDER’S EQUITY

(Thousands of Dollars)

	Years Ended December 31,
	2007			2006			2005
Common Stock:
Balance at beginning and end of period	$	—		$	—		$	—
Premium on Capital Stock and Other Paid-in Capital:
Balance at beginning and end of period		1,652,430			1,652,430			1,652,430
Retained Earnings:
Balance at beginning of period		914,851			902,600			842,285
Add (deduct):
Net income		172,583			117,251			185,315
Cash dividends on common stock		(110,000	)		(105,000	)		(125,000	)
Balance at end of period		977,434			914,851			902,600
Accumulated Other Comprehensive Income/(Loss):
Interest Rate Hedge:
Balance at beginning of period		(249	)		(408	)		(920	)
Add (deduct):
Net gain/(loss), net of tax of $96 in 2007, $(102) in 2006 and $(305) in 2005		(150	)		159			512
Balance at end of period		(399	)		(249	)		(408	)
Pension Benefits:
Balance at beginning of period		(28,596	)		—			—
Add (deduct):
Prior service credit, net of tax of $633 in 2007		(1,023	)		—			—
Net actuarial gain, net of tax of $(9,076) in 2007		14,654			—			—
Adjustment to initially apply SFAS No. 158:
Prior service credit, net of tax of $(917) in 2006		—			1,480			—
Net actuarial loss, net of tax of $18,629 in 2006		—			(30,076	)		—
Balance at end of period		(14,965	)		(28,596	)		—
Balance at end of period		(15,364	)		(28,845	)		(408	)
Total Common Stockholder’s Equity	$	2,614,500		$	2,538,436		$	2,554,622

See accompanying notes.

33

TRANSCONTINENTAL GAS PIPE LINE CORPORATION

CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME

(Thousands of Dollars)

	Years Ended December 31,
	2007			2006		2005
Net Income	$	172,583		$	117,251	$	185,315
Pension Benefits:
Amortization of prior service cost, net of tax of $633 in 2007		(1,023	)		—		—
Amortization of net actuarial gain and reclassifications, net of tax of $(9,076) in 2007		14,654			—		—
Equity interest in unrealized gain/(loss) on interest rate hedge, net of tax of $96 in 2007, $(102) in 2006 and $(305) in 2005		(150	)		159		512
Total Comprehensive Income	$	186,064		$	117,410	$	185,827

See accompanying notes.

34

TRANSCONTINENTAL GAS PIPE LINE CORPORATION

CONSOLIDATED STATEMENT OF CASH FLOWS

(Thousands of Dollars)

	Years Ended December 31,
	2007			2006			2005
Cash flows from operating activities:
Net income	$	172,583		$	117,251		$	185,315
Adjustments to reconcile net income to net cash Provided by operating activities:
Depreciation and amortization		226,755			204,508			198,361
Deferred income taxes		(15,362	)		73,259			(916	)
Allowance for equity funds used during construction (Equity AFUDC)		(9,439	)		(8,355	)		(6,455	)
Changes in operating assets and liabilities:
Receivables — affiliates		1,507			(3,440	)		(2,427	)
— other		(30,559	)		6,392			17,193
Transportation and exchange gas receivable		(3,649	)		2,831			(4,096	)
Inventories		9,701			17,859			(5,108	)
Payables — affiliates		(7,477	)		(4,805	)		(10,839	)
— other		(1,994	)		22,578			(9,859	)
Transportation and exchange gas payable		(7,448	)		(34,964	)		25,037
Accrued liabilities		70,974			(41,414	)		22,793
Reserve for rate refunds		95,803			(1,531	)		(5,156	)
Other, net		35,685			(45,722	)		(18,854	)
Net cash provided by operating activities		537,080			304,447			384,989
Cash flows from financing activities:
Additions to long-term debt		—			200,000			—
Retirement of long-term debt		—			—			(200,000	)
Debt issue costs		(10	)		(3,202	)		(255	)
Common stock dividends paid		(110,000	)		(105,000	)		(125,000	)
Change in cash overdrafts		(17,658	)		1,440			7,869
Net cash provided by (used in) financing activities		(127,668	)		93,238			(317,386	)

(continued)

35

TRANSCONTINENTAL GAS PIPE LINE CORPORATION

CONSOLIDATED STATEMENT OF CASH FLOWS
(Thousands of Dollars)

	Years Ended December 31,
	2007			2006			2005
Cash flows from investing activities:
Property, plant and equipment:
Additions, net of equity AFUDC		(375,447	)		(342,843	)		(253,710	)
Changes in accounts payable		(7,493	)		8,524			15,251
Changes in accrued liabilities		18,609			3,321			(2,652	)
Advances to affiliates, net		(33,258	)		(60,092	)		172,458
Advances to others, net		835			981			(428	)
Other, net		(12,854	)		(7,623	)		1,664
Net cash used in investing activities		(409,608	)		(397,732	)		(67,417	)
Net increase (decrease) in cash		(196	)		(47	)		186
Cash at beginning of period		315			362			176
Cash at end of period	$	119		$	315		$	362
Supplemental disclosures of cash flow information:
Cash paid during the year for:
Interest (exclusive of amount capitalized)	$	86,081		$	81,063		$	77,297
Income taxes paid		57,880			39,913			123,797
Income tax refunds received		(177	)		—			(122	)

See accompanying notes.

36

TRANSCONTINENTAL GAS PIPE LINE CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Summary of Significant Accounting Policies	37
2. Rate And Regulatory Matters	43
3. Contingent Liabilities and Commitments	44
4. Debt, Financing Arrangements and Leases	47
5. Employee Benefit Plans	49
6. Income Taxes	52
7. Financial Instruments and Guarantees	54
8. Transactions with Major Customers and Affiliates	55
9. Asset Retirement Obligations	56
10. Regulatory Assets and Liabilities	57
11. Quarterly Information (Unaudited)	58

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

     Corporate structure and control Transcontinental Gas Pipe Line Corporation (Transco) is a wholly-owned subsidiary of Williams Gas Pipeline Company, LLC (WGP). WGP is a wholly-owned subsidiary of The Williams Companies, Inc. (Williams).

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

     Nature of operations We are an interstate natural gas transmission company that owns a natural gas pipeline system extending from Texas, Louisiana, Mississippi and the Gulf of Mexico through the states of Alabama, Georgia, South Carolina, North Carolina, Virginia, Maryland, Pennsylvania and New Jersey to the New York City metropolitan area. The system serves customers in Texas and the eleven southeast and Atlantic seaboard states mentioned above, including major metropolitan areas in Georgia, North Carolina, New York, New Jersey and Pennsylvania. We also hold a minority interest in an intrastate natural gas pipeline in North Carolina.

     Regulatory accounting We are regulated by the Federal Energy Regulatory Commission (FERC). Statement of Financial Accounting Standards (SFAS) No. 71, “Accounting for the Effects of Certain Types of Regulation,” provides that rate-regulated public utilities account for and report regulatory assets and liabilities consistent with the economic effect of the way in which regulators establish rates if the rates established are designed to recover the costs of providing the regulated service and if the competitive environment makes it probable that such rates can be charged and collected. Accounting for businesses that are regulated and apply the provisions of SFAS No. 71 can differ from the accounting requirements for non-regulated businesses. Transactions that are recorded differently as a result of regulatory accounting requirements include the capitalization of an equity return component on regulated capital projects, capitalization of other project costs, retirements of general plant assets, employee related benefits, environmental costs, negative salvage, asset retirement obligations, and other costs and taxes included in, or expected to be included in, future rates. As a rate-regulated entity, our management has determined that it is appropriate to apply the accounting prescribed

37

by SFAS No. 71 and, accordingly, the accompanying consolidated financial statements include the effects of the types of transactions described above that result from regulatory accounting requirements.

     Basis of presentation Williams’ acquisition of Transco Energy Company and its subsidiaries, including us, in 1995 was accounted for using the purchase method of accounting. Accordingly, an allocation of the purchase price was assigned to our assets and liabilities based on their estimated fair values. The purchase price allocation to us primarily consisted of a $1.5 billion allocation to property, plant and equipment and adjustments to deferred taxes based upon the book basis of the net assets recorded as a result of the acquisition. The amount allocated to property, plant and equipment is being depreciated on a straight-line basis over 40 years, the estimated useful lives of these assets at the date of acquisition, at approximately $36 million per year. At December 31, 2007, the remaining property, plant and equipment allocation was approximately $1.0 billion. Current FERC policy does not permit us to recover through rates amounts in excess of original cost.

     As a participant in Williams’ cash management program, we have advances to and from Williams. These advances are represented by demand notes. We currently expect to receive payment of these advances within the next twelve months and have recorded such advances as current in the accompanying Consolidated Balance Sheet. 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 December 31, 2007, the interest rate was 7.83%.

     Through an agency agreement, Williams Gas Marketing, Inc. (WGM) (formerly Williams Power Company), an affiliate of ours, manages all jurisdictional merchant gas sales for us, receives all margins associated with such business and, as our agent, assumes all market and credit risk associated with our jurisdictional merchant gas sales. Consequently, our merchant gas sales have no impact on our operating income or results of operations.

     Our Board of Directors declared and we paid cash dividends on common stock in the amounts of $110 million, $105 million and $125 million for 2007, 2006 and 2005, respectively.

     Principles of consolidation The consolidated financial statements include our accounts and the accounts of our majority-owned subsidiaries. Companies in which we and our subsidiaries own 20 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 investments as of December 31, 2007 and 2006 primarily consist of Cardinal Pipeline Company, LLC with ownership interest of approximately 45% and Pine Needle LNG Company, LLC (Pine Needle) with ownership interest of 35%. We received distributions associated with our equity investments in the amounts of $5.8 million, $7.0 million and $7.5 million in 2007, 2006 and 2005, respectively.

     Use of estimates The preparation of financial statements in conformity with U.S. generally accepted accounting principles requires management to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes. Actual results could differ from those estimates. Estimates and assumptions which, in the opinion of management, are significant to the underlying amounts included in the financial statements and for which it would be reasonably possible that future events or information could change those estimates include: 1) revenues subject to refund; 2) litigation-related contingencies; 3) environmental remediation obligations; 4) impairment assessments of long-lived assets; 5) deferred and other income taxes; 6) depreciation; 7) pensions and other post-employment benefits; and 8) asset retirement obligations.

38

     Revenue recognition Revenues for sales of products are recognized in the period of delivery and revenues from the transportation and storage of gas are recognized in the period the service is provided based on contractual terms and the related volumes. As a result of the ratemaking process, certain revenues collected by us may be subject to possible refunds upon final orders in pending rate proceedings with the FERC. We record estimates of rate refund liabilities considering our and other third party regulatory proceedings, advice of counsel and estimated total exposure, as discounted and risk weighted, as well as collection and other risks.

     Contingent liabilities We record liabilities for estimated loss contingencies when we assess that a loss is probable and the amount of the loss can be reasonably estimated. Revisions to contingent liabilities are reflected in income in the period in which new or different facts or information become known or circumstances change that affect the previous assumptions with respect to the likelihood or amount of loss. Liabilities for contingent losses are based upon our assumptions and estimates, and advice of legal counsel or other third parties regarding the probable outcomes of the matter. As new developments occur or more information becomes available, our assumptions and estimates of these liabilities may change. Changes in our assumptions and estimates or outcomes different from our current assumptions and estimates could materially affect future results of operations for any particular quarterly or annual period.

     Environmental Matters We are subject to federal, state, and local environmental laws and regulations. Environmental expenditures are expensed or capitalized depending on their economic benefit and potential for rate recovery. We believe that any expenditures required to meet applicable environmental laws and regulations are prudently incurred in the ordinary course of business and that substantially all of such expenditures would be permitted to be recovered through rates. We believe that compliance with applicable environmental requirements is not likely to have a material effect upon our financial position or results of operations.

     Property, plant and equipment Property, plant and equipment is recorded at cost. The carrying values of these assets are also based on estimates, assumptions and judgments relative to capitalized costs, useful lives and salvage values. These estimates, assumptions and judgments reflect FERC regulations, as well as historical experience and expectations regarding future industry conditions and operations. Gains or losses from the ordinary sale or retirement of property, plant and equipment are credited or charged to accumulated depreciation; certain other gains or losses are recorded in operating income.

     We provide for depreciation using the straight-line method at FERC prescribed rates, including negative salvage for offshore transmission facilities. Depreciation of general plant is provided on a group basis at straight-line rates. Included in our depreciation rates is a negative salvage (cost of removal) component that we currently collect in rates. Depreciation rates used for major regulated gas plant facilities at December 31, 2007, 2006, and 2005 are as follows:

Category of Property	2007 (1)			2006			2005
Gathering facilities		0.01%-0.91	%		0%-3.80	%		0%-3.80	%
Storage facilities		0.40%-3.30	%		2.50	%		2.50	%
Onshore transmission facilities		0.69%-5.00	%		2.35	%		2.35	%
Offshore transmission facilities		0.01%-1.00	%		0.85%-1.50	%		0.85%-1.50	%

(1) Changes in depreciation rates in 2007 due to placing into effect, subject to refund, the rates in Docket No. RP06-569 on March 1, 2007.

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     We record an asset and a liability equal to the present value of each expected future asset retirement obligation (ARO). The ARO asset is depreciated in a manner consistent with the depreciation of the underlying physical asset. We measure changes in the liability due to passage of time by applying an interest method of allocation. The depreciation of the ARO asset and accretion of the ARO liability are recognized as an increase to a regulatory asset, as management expects to recover such amounts in future rates. The regulatory asset will be amortized commensurate with our collection of those costs in rates.

     Impairment of long-lived assets and investments We evaluate the long-lived assets of identifiable business activities for impairment when events or changes in circumstances indicate, in our management’s judgment, that the carrying value of such assets may not be recoverable. When an indicator of impairment has occurred, we compare our management’s estimate of undiscounted future cash flows attributable to the assets to the carrying value of the assets to determine whether an impairment has occurred. We apply a probability-weighted approach to consider the likelihood of different cash flow assumptions and possible outcomes including selling in the near term or holding for the remaining estimated useful life. If an impairment of the carrying value has occurred, we determine the amount of the impairment recognized in the financial statements by estimating the fair value of the assets and recording a loss for the amount that the carrying value exceeds the estimated fair value.

     For assets identified to be disposed of in the future and considered held for sale in accordance with SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” we compare the carrying value to the estimated fair value less the cost to sell to determine if recognition of an impairment is required. Until the assets are disposed of, the estimated fair value, which includes estimated cash flows from operations until the assumed date of sale, is recalculated when related events or circumstances change. We had no impairments during the years ended December 31, 2007, 2006, and 2005.

     We evaluate our equity method investments for impairment when events or changes in circumstances indicate, in our management’s judgment, that the carrying value of such investments may have experienced an other-than-temporary decline in value. When evidence of loss in value has occurred, we compare our estimate of fair value of the investment to the carrying value of the investment to determine whether an impairment has occurred. If the estimated fair value is less than the carrying value and we consider the decline in value to be other than temporary, the excess of the carrying value over the fair value is recognized in the financial statements as an impairment.

     Judgments and assumptions are inherent in our management’s estimate of undiscounted future cash flows used to determine recoverability of an asset and the estimate of an asset’s fair value used to calculate the amount of impairment to recognize. The use of alternate judgments and/or assumptions could result in the recognition of different levels of impairment charges in the financial statements.

     Accounting for repair and maintenance costs We account for repair and maintenance costs under the guidance of FERC regulations. The FERC identifies installation, construction and replacement costs that are to be capitalized. All other costs are expensed as incurred.

     Allowance for funds used during construction Allowance for funds used during construction (AFUDC) represents the estimated cost of borrowed and equity funds applicable to utility plant in process of construction and are included as a cost of property, plant and equipment because it constitutes an actual cost of construction under established regulatory practices. The FERC has prescribed a formula to be used in computing separate allowances for borrowed and equity AFUDC. The allowance for borrowed funds used

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during construction was $3.5 million, $2.8 million and $2.8 million, for 2007, 2006 and 2005, respectively. The allowance for equity funds was $9.4 million, $8.3 million, and $6.5 million, for 2007, 2006 and 2005, respectively.

     Accounting for income taxes Williams and its wholly-owned subsidiaries, which includes us, file a consolidated federal income tax return. It is Williams’ policy to charge or credit us with an amount equivalent to our federal income tax expense or benefit computed as if we had filed a separate return.

     We use the assets and liability method of accounting for income taxes, as required by SFAS 109, “Accounting for Income Taxes”, which requires, among other things, provisions for all temporary differences between the financial basis and the tax basis in our assets and liabilities and adjustments to the existing deferred tax balances for changes in tax rates.

     Accounts receivable and allowance for doubtful receivables Accounts receivable are stated at the historical carrying amount net of reserves or write-offs. Our credit risk exposure in the event of nonperformance by the other parties is limited to the face value of the receivables. We perform ongoing credit evaluations of our customer’s financial condition and require collateral from our customers, if necessary. Due to our customer base, we have not historically experienced recurring credit losses in connection with our receivables. Receivables determined to be uncollectible are reserved or written off in the period of determination. At both December 31, 2007 and 2006, we had recorded reserves of $0.5 million for uncollectible accounts.

     Gas imbalances 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 behalf of us than the quantities of gas received from us. These transactions result in gas transportation and exchange imbalance receivables and payables which are recovered or repaid in cash or through the receipt or delivery of gas in the future and are recorded in the accompanying Consolidated Balance Sheet. Settlement of imbalances requires agreement between the pipelines and shippers as to allocations of volumes to specific transportation contracts and timing of delivery of gas based on operational conditions. Our tariff includes a method whereby most transportation imbalances are settled on a monthly basis. Each month a portion of the imbalances are not identified to specific parties and remain unsettled. These are generally identified to specific parties and settled in subsequent periods. We believe that amounts that remain unidentified to specific parties and unsettled at year end are valid balances that will be settled with no material adverse effect upon our financial position, results of operations or cash flows. Management has implemented a policy of continuing to carry on the books any unidentified T&E imbalances for a three-year period. At the end of the three year period a final assessment will be made of their continued validity. Absent a valid reason for maintaining the imbalance, any remaining balance will be reversed. Certain imbalances are being recovered or repaid in cash or through the receipt or delivery of gas upon agreement of the parties as to the allocation of the gas volumes, and as permitted by pipeline operating conditions. These imbalances have been classified as current assets and current liabilities at December 31, 2007 and 2006. We utilize the average cost method of accounting for gas imbalances.

     Deferred cash out Most transportation imbalances are settled in cash on a monthly basis (cash out). We are required by our tariff to refund revenues received from the cash out of transportation imbalances in excess of costs incurred during the annual August through July reporting period. Revenues received in excess of costs incurred are deferred until refunded in accordance with the requirement.

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     Gas inventory We utilize the last-in, first-out (LIFO) method of accounting for inventory gas in storage. If inventories valued using the LIFO cost method were valued at current replacement cost, the amounts would increase minimally at December 31, 2007 and by $22.1 million at December 31, 2006. The basis for determining current cost at the end of each year is the December monthly average gas price delivered to pipelines in Texas and Louisiana. We utilize the average cost method of accounting for gas available for customer nomination. Liquefied natural gas in storage is valued at original cost.

     In 2007, Transco requested authorization from the FERC to sell our excess Eminence top gas inventory and retain any gain on the sales. The FERC authorized the top gas sales, but consolidated the issue of Transco’s request to retain the gain on the sales with Transco’s general rate case. One of the provisions of the pending Agreement in the Docket No. RP06-569 rate case (See Note 2 of Notes to the Consolidated Financial Statements) requires that Transco share 50% of the gain with its customers. During 2007, approximately $59.2 million of excess top gas was sold and is reflected in operating revenues on our Consolidated Statement of Income. The entire gain on the sales of the excess top gas, which was $19.0 million, has been deferred pending final approval of the Agreement. Of the $19 million deferred gain, $10.8 million is related to LIFO liquidation. The cost of gas sold and deferral of the entire gain related to the sale of excess top gas are reflected in operating cost and expense on our Consolidated Income Statement; therefore, the sale of the excess top gas does not affect our Net Income on the Consolidated Income Statements.

     Reserve for Inventory Obsolescence We perform an annual review of Materials and Supplies inventories, including a quarterly analysis of parts that may no longer be useful due to planned replacements of compressor engines and other components on our system. Based on this assessment, we record a reserve for the value of the inventory which can no longer be used for maintenance and repairs on our pipeline. There was a minimal reserve at December 31, 2007 and at December 31, 2006.

     Cash flows from operating activities and cash equivalents We use the indirect method to report cash flows from operating activities, which requires adjustments to net income to reconcile to net cash flows provided by operating activities. We include short-term, highly-liquid investments that have a maturity of three months or less as cash equivalents.

     Recent Accounting Standards In September 2006, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards (SFAS) No. 157, “Fair Value Measurements” (SFAS No. 157). This Statement establishes a framework for fair value measurements in the financial statements by providing a definition of fair value, provides guidance on the methods used to estimate fair value and expands disclosures about fair value measurements. SFAS No. 157 is effective for fiscal years beginning after November 15, 2007. In December 2007, the FASB issued proposed FASB Staff Position (FSP) No. FAS 157-b deferring the effective date of SFAS No. 157 to fiscal years beginning after November 15, 2008 for all non-financial assets and liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually). SFAS No. 157 requires two distinct transition approaches; (i) cumulative-effect adjustment to beginning retained earnings for certain financial instrument transactions and (ii) prospectively as of the date of adoption through earnings or other comprehensive income, as applicable. On January 1, 2008, we adopted SFAS No. 157 applying a prospective transition for our assets and liabilities that are measured at fair value on a recurring basis with no material impact to our Consolidated Financial Statements. SFAS No. 157 expands disclosures about assets and liabilities measured at fair value on a recurring basis effective beginning with the first quarter 2008 reporting.

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     In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities — Including an Amendment of FASB Statement No. 115” (SFAS No. 159). SFAS No. 159 establishes a fair value option permitting entities to elect to measure eligible financial instruments and certain other items at fair value. Unrealized gains and losses on items for which the fair value option has been elected will be reported in earnings. The fair value option may be applied on an instrument-by-instrument basis, is irrevocable and is applied only to the entire instrument. SFAS No. 159 is effective as of the beginning of the first fiscal year beginning after November 15, 2007, and should not be applied retrospectively to fiscal years beginning prior to the effective date. On the adoption date, an entity may elect the fair value option for eligible items existing at that date and the adjustment for the initial remeasurement of those items to fair value should be reported as a cumulative effect adjustment to the opening balance of retained earnings. Subsequent to January 1, 2008, the fair value option can only be elected when a financial instrument or certain other item is entered into. On January 1, 2008, we did not elect the fair value option for any existing eligible financial instruments or certain other items.

     FERC Accounting Guidance On June 30, 2005, the FERC issued an order, “Accounting for Pipeline Assessment Costs,” to be applied prospectively effective January 1, 2006. The order requires companies to expense certain assessment costs that we have historically capitalized. During 2007 and 2006, we expensed approximately $10 million and $8 million, respectively that previously would have been capitalized.

     Reclassification Certain reclassifications have been made in the 2006 and 2005 financial statements to conform to the 2007 presentation including changes in capital related accounts payable as investing activities in the consolidated statement of cash flows.

2. RATE AND REGULATORY MATTERS

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

     On August 31, 2006, we submitted to the FERC a general rate filing (Docket No. RP06-569) principally designed to recover costs associated with (a) an increase in operation and maintenance expenses and administrative and general expenses; (b) an increase in depreciation expense; (c) the inclusion of costs for asset retirement obligations; (d) an increase in rate base resulting from additional plant; and (e) an increase in rate of return and related taxes. The filing reflected an increase in annual revenues from jurisdictional service of approximately $281 million over the cost of service underlying the rates reflected in the settlement of our Docket No. RP01-245 rate proceeding, as adjusted to include the cost of service and rate base amounts for expansion projects placed in service after the September 1, 2001 effective date of the Docket No. RP01-245 rates. The filing also reflected changes to our tariff, cost allocation and rate design methods, including the refunctionalization of certain facilities from transmission plant accounts to jurisdictional gathering plant accounts consistent with various FERC orders. The rates became effective March 1, 2007, subject to refund and the outcome of a hearing. On November 28, 2007, we filed with the FERC a Stipulation and Agreement (Agreement) resolving all substantive issues in the rate case. The one issue reserved for litigation or further settlement relates to the design of the rates for service under one of Transco’s storage rate schedules. The Agreement is uncontested. On January 9, 2008, the Presiding Administrative Law Judge issued an order

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certifying the Agreement to the FERC, finding the Agreement to be fair and reasonable and in the public interest, and urging the FERC to approve the Agreement expeditiously. We have provided a reserve for rate refunds which we believe is adequate for any refunds that may be required.

3. CONTINGENT LIABILITIES AND COMMITMENTS

Legal Proceedings

     In 1998, the United States Department of Justice (DOJ) informed Williams that Jack Grynberg, an individual, had filed claims in the United States District Court for the District of Colorado under the False Claims Act against Williams and certain of its wholly-owned subsidiaries including us. Mr. Grynberg had also filed claims against approximately 300 other energy companies and alleged that the defendants violated the False Claims Act in connection with the measurement, royalty valuation and purchase of hydrocarbons. The relief sought was an unspecified amount of royalties allegedly not paid to the federal government, treble damages, a civil penalty, attorneys’ fees, and costs. In April 1999, the DOJ declined to intervene in any of the Grynberg qui tam cases, and in October 1999, the Panel on Multi-District Litigation transferred all of the Grynberg qui tam cases, including those filed against Williams, to the United States District Court for the District of Wyoming for pre-trial purposes. In October 2002, the court granted a motion to dismiss Grynberg’s royalty valuation claims. Grynberg’s measurement claims remained pending against Williams, including us, and the other defendants, although the defendants have filed a number of motions to dismiss these claims on jurisdictional grounds. In May 2005, the court-appointed special master entered a report which recommended that many of the cases be dismissed, including the case pending against us and certain of the Williams defendants. On October 20, 2006, the District Court dismissed all claims against us. Mr. Grynberg filed a Notice of Appeal from the dismissals with the Tenth Circuit Court of Appeals effective November 17, 2006.

Environmental Matters

     Since 1989, we have had studies underway to test some of our facilities for the presence of toxic and hazardous substances to determine to what extent, if any, remediation may be necessary. We have responded to data requests from the U.S. Environmental Protection Agency (EPA) and state agencies regarding such potential contamination of certain of our sites. On the basis of the findings to date, we estimate that environmental assessment and remediation costs under various federal and state statutes will total approximately $10 million to $12 million (including both expense and capital expenditures), measured on an undiscounted basis, and will be spent over the next five to seven years. This estimate depends upon a number of assumptions concerning the scope of remediation that will be required at certain locations and the cost of the remedial measures. We are conducting environmental assessments and implementing a variety of remedial measures that may result in increases or decreases in the total estimated costs. At December 31, 2007, we had a balance of approximately $5.7 million for the expense portion of these estimated costs recorded in current liabilities ($0.9 million) and other long-term liabilities ($4.8 million) in the accompanying Consolidated Balance Sheet.

     We consider prudently incurred environmental assessment and remediation costs and costs associated with compliance with environmental standards to be recoverable through rates. To date, we have been permitted recovery of environmental costs, and it is our intent to continue seeking recovery of such costs, through future rate filings. Therefore, these estimated costs of environmental assessment and remediation, less amounts collected, have also been recorded as regulatory assets in Current Assets: Other and Other Assets in

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the accompanying Consolidated Balance Sheet. At December 31, 2007, we had recorded approximately $4.0 million of environmental related regulatory assets.

     We have used lubricating oils containing polychlorinated biphenyls (PCBs) and, although the use of such oils was discontinued in the 1970s, we have discovered residual PCB contamination in equipment and soils at certain gas compressor station sites. We have worked closely with the EPA and state regulatory authorities regarding PCB issues, and we have a program to assess and remediate such conditions where they exist. In addition, we commenced negotiations with certain environmental authorities and other parties concerning investigative and remedial actions relative to potential mercury contamination at certain gas metering sites. All such costs are included in the $10 million to $12 million range discussed above.

     We have been identified as a potentially responsible party (PRP) at various Superfund and state waste disposal sites. Based on present volumetric estimates and other factors, our estimated aggregate exposure for remediation of these sites is less than $500,000. The estimated remediation costs for all of these sites have been included in the environmental reserve discussed above. Liability under The Comprehensive Environmental Response, Compensation and Liability Act (and applicable state law) can be joint and several with other PRPs. Although volumetric allocation is a factor in assessing liability, it is not necessarily determinative; thus, the ultimate liability could be substantially greater than the amounts described above.

     We are also subject to the federal Clean Air Act and to the federal Clean Air Act Amendments of 1990 (1990 Amendments), which added significantly to the existing requirements established by the federal Clean Air Act. Pursuant to requirements of the 1990 Amendments, and EPA rules designed to mitigate the migration of ground-level ozone (NOx), we are planning installation of air pollution controls on existing sources at certain facilities in order to reduce NOx emissions. We anticipate that additional facilities may be subject to increased controls within five years. For many of these facilities, we are developing more cost effective and innovative compressor engine control designs. Due to the developing nature of federal and state emission regulations, it is not possible to precisely determine the ultimate emission control costs. However, the emission control additions required to comply with current federal Clean Air Act requirements, the 1990 Amendments, the hazardous air pollutant regulations, and the individual state implementation plans for NOx reductions are estimated to include costs in the range of $25 million to $30 million for the period 2008 through 2010. EPA’s designation of eight-hour ozone non-attainment areas will result in new federal and state regulatory action that may impact our operations. As a result, the cost of additions to property, plant and equipment is expected to increase. We are unable at this time to estimate with any certainty the cost of additions that may be required to meet new regulations, although it is believed that some of those costs are included in the ranges discussed above. Management considers costs associated with compliance with the environmental laws and regulations described above to be prudent costs incurred in the ordinary course of business and, therefore, recoverable through our rates.

     By letter dated September 20, 2007, the EPA required Transco to provide information regarding natural gas compressor stations in the states of Mississippi and Alabama as part of EPA’s investigation of Transco’s compliance with the Clean Air Act. By January 2008, we responded with 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 final rule

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pursuant to the requirements of the Pipeline Safety Improvement Act of 2002. In meeting the Integrity Regulations, we have identified the high consequence areas, including a baseline assessment and periodic reassessments to be completed within specified timeframes. Currently, we estimate that the cost to perform required assessments and remediation will be between $250 million and $300 million over the remaining assessment period of 2008 through 2012. Management considers the costs associated with compliance with the rule to be prudent costs incurred in the ordinary course of business and, therefore, recoverable through our rates.

Other Matters

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

Summary

     Litigation, arbitration, regulatory matters, environmental matters and safety matters are subject to inherent uncertainties. Were an unfavorable ruling to occur, there exists the possibility of a material adverse impact on the results of operations in the period in which the ruling occurs. Management, including internal counsel, currently believes that the ultimate resolution of the foregoing matters, taken as a whole and after consideration of amounts accrued, insurance coverage, recovery from customers or other indemnification arrangements, will not have a materially adverse effect upon our future financial position.

Other Commitments

     Commitments for construction and gas purchases We have commitments for construction and acquisition of property, plant and equipment of approximately $103 million at December 31, 2007, which is expected to be spent in 2008. We have commitments for gas purchases of approximately $176 million at December 31, 2007, which is expected to be spent over the next eleven years.

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4. DEBT, FINANCING ARRANGEMENTS AND LEASES

     Long-term debt At December 31, 2007 and 2006, long-term debt issues were outstanding as follows (in thousands):

	2007			2006
Debentures:
7.08% due 2026	$	7,500		$	7,500
7.25% due 2026		200,000			200,000
Total debentures		207,500			207,500
Notes:
6.25% due 2008		100,000			100,000
Floating Rate due 2008		75,000			75,000
7% due 2011		300,000			300,000
8.875% due 2012		325,000			325,000
6.4% due 2016		200,000			200,000
Total notes		1,000,000			1,000,000
Total long-term debt issues		1,207,500			1,207,500
Unamortized debt premium and discount		(5,130	)		(6,042	)
Current maturities		(75,000	)		—
Total long-term debt, less current maturities	$	1,127,370		$	1,201,458

     Aggregate minimum maturities (face value) applicable to long-term debt outstanding at December 31, 2007 are as follows (in thousands):

2008:
6.25% Notes	$	100,000	(1)
Floating Rate Notes	$	75,000
	$	175,000

⁽¹⁾ Due on January 15, 2008, reclassified as long-term debt as a result of subsequent refinancing through the borrowing under the $1.5 billion Credit Facility.

2011:
7% Notes	$	300,000
2012:
8.875% Notes	$	325,000

     There are no maturities applicable to long-term debt outstanding for the years 2009 and 2010.

     No property is pledged as collateral under any of our long-term debt issues.

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Revolving Credit and Letter of Credit Facility

     Williams has an unsecured, $1.5 billion 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 otherwise utilized by Williams. Interest is calculated based on a choice of two methods: a fluctuating rate equal to the lender’s base rate plus an applicable margin or a periodic fixed rate equal to the London Interbank Offered Rate (LIBOR) plus an applicable margin. Williams is required to pay a commitment fee (currently 0.125 percent) based on the unused portion of the Credit Facility. The margins and commitment fee are generally based on the specific borrower’s senior unsecured long-term debt ratings. Significant financial covenants under the Credit Facility include the following:

• Williams’ ratio of debt to capitalization must be no greater than 65 percent. At December 31, 2007, Williams was in compliance with this covenant as their ratio of debt to capitalization, as calculated under this covenant, is approximately 51 percent.

• Our ratio of debt to capitalization must be no greater than 55 percent. At December 31, 2007, we are in compliance with this covenant as our ratio of debt to capitalization, as calculated under this covenant, is approximately 31 percent.

Retirement of Long-Term Debt

     In January 2008, we borrowed $100 million under the Credit Facility to retire $100 million of 6.25% notes (6.25% Notes) that matured on January 15, 2008. The 6.25% Notes, which were issued in January 1998, were retired at the scheduled maturity date with no gain or loss recorded. We intend to refinance the $100 million borrowed under the Credit Facility.

Current Maturities of Long-Term Debt

     The current maturities of long-term debt at December 31, 2007 are associated with $75 million of Floating Rate Notes that mature on April 15, 2008. The $100 million of 6.25% notes, due January 15, 2008, have been classified as long-term debt in our consolidated balance sheet at December 31, 2007, as a result of the subsequent refinancing through the borrowing under the $1.5 billion Credit Facility.

Issuance of Long-Term Debt

     On April 11, 2006, we issued $200 million aggregate principal amount of unsecured notes to certain institutional investors in a private debt placement which pay interest at 6.4% per annum on April 15 and October 15 each year, beginning October 15, 2006 (6.4% Notes). The 6.4% Notes mature on April 15, 2016, but are subject to redemption at any time, at our option, in whole or part, at a specified redemption price, plus accrued and unpaid interest to the date of redemption. The net proceeds of the sale were used for general corporate purposes, including the funding of capital expenditures. In October 2006, we completed the exchange of the 6.4% Notes for substantially identical new notes that are registered under the Securities Act of 1933, as amended.

     Restrictive covenants At December 31, 2007, none of our debt instruments restrict the amount of dividends distributable to WGP.

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     Lease obligations On October 23, 2003, we entered into a lease agreement for space in the Williams Tower in Houston, Texas. The lease term runs through March 31, 2014 with a one-time right to terminate on March 29, 2009, with notification due March 29, 2008. It is management’s intent not to terminate the lease agreement.

     On July 1, 2006, we entered into a sublease agreement with our affiliate, Williams Field Services Company, for space in the Williams Tower. The lease term runs through March 31, 2014.

     On May 1, 2007, we entered into an agreement to sublease space in the Williams Tower to our affiliate, Williams Field Services Company. The lease term runs through March 29, 2014.

     The future minimum lease payments under our various operating leases, including the Williams Tower lease are as follows (in thousands):

	Operating Leases
	Williams Tower		Other Leases		Total
2008	$	6,085	$	156	$	6,241
2009		6,344		159		6,503
2010		6,573		163		6,736
2011		6,645		166		6,811
2012		6,828		138		6,966
Thereafter		8,657		265		8,922
Total net minimum obligations	$	41,132	$	1,047	$	42,179

     Our lease expense was $9.5 million in 2007, $12.8 million in 2006, and $14.1 million in 2005.

5. EMPLOYEE BENEFIT PLANS

     Pension plans We participate in noncontributory defined benefit pension plans sponsored by Williams that provide pension benefits for eligible participants. Cash contributions related to our participation in the plans totaled $10.2 million in 2007, $10.9 million in 2006, and $14.0 million in 2005. Pension expense for 2007, 2006 and 2005 totaled $6.4 million, $7.3 million and $3.6 million, respectively.

     On December 31, 2006, we adopted the recognition and disclosure provisions of SFAS No.158 related to our participation in Williams’ sponsored pension and other postretirement benefit plans. In accordance with SFAS No. 158, we recorded adjustments to accumulated other comprehensive income (loss), net of income taxes, to recognize the funded status of our pension plans on our consolidated balance sheet. The adjustments recorded to accumulated other comprehensive income (loss) will be recognized as components of net periodic benefit expense and amortized over future periods in accordance with SFAS No. 87, “Employers’ Accounting for Pensions” in the same manner as prior to the adoption of SFAS No. 158. Actuarial gains and losses that arise in subsequent periods and are not recognized as net periodic benefit expense in the same period will now be recognized in other comprehensive income (loss). These amounts will be recognized subsequently as a component of net periodic benefit expense following the same basis as the amounts recognized in accumulated other comprehensive income (loss) upon adoption of SFAS No. 158.

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     Accumulated other comprehensive loss at December 31 includes the following:

	Pension Benefits
	2007			2006
	(Millions)
Amounts not yet recognized in net periodic benefit expense:
Prior service credit	$	0.7		$	2.4
Net actuarial losses		(25.0	)		(48.7	)

     Net actuarial losses of $1.3 million and prior service credit of $0.8 million related to the pension plans that are included in accumulated other comprehensive loss at December 31, 2007 are expected to be amortized in net periodic benefit expense in 2008.

     The allocation of the purchase price to the assets and liabilities of Transco based on estimated fair values resulted in the recording of an additional pension liability in 1995, for the amount that the projected benefit obligation exceeded the plan assets. The remaining amount of additional pension costs deferred at December 31, 2007 and 2006, is $3.3 million and $3.9 million, respectively, and is expected to be recovered through future rates generally over the average remaining service period for active employees.

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

     Postretirement benefits other than pensions We participate in a plan sponsored by Williams that provides certain retiree health care and life insurance benefits for eligible participants that were hired prior to January 1, 1996. The accounting for the plan anticipates future cost-sharing changes to the plan that are consistent with Williams’ expressed intent to increase the retiree contribution level, generally in line with health care cost increases. Cash contributions totaled $6.0 million in 2007, $3.8 million in 2006, and $3.5 million in 2005. Net periodic postretirement benefit expense for 2007, 2006 and 2005 totaled $4.3 million, $5.1 million and $5.8 million, respectively.

     In accordance with SFAS No. 158, we recorded an adjustment to regulatory assets and regulatory liabilities for our other postretirement benefit plans. We have been allowed by rate case settlements to collect in future rates any differences between the actuarially determined costs and amounts currently being recovered in rates related to other postretirement benefits. The adjustments recorded to the regulatory assets and regulatory liabilities will be recognized as components of net periodic benefit expense and amortized over future periods in accordance with SFAS No. 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions” in the same manner as prior to the adoption of SFAS No. 158. Actuarial gains and losses that arise in subsequent periods and are not recognized as net periodic benefit expense in the same period will now be recognized in regulatory assets and regulatory liabilities. These amounts will be recognized subsequently as a component of net

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periodic benefit expense following the same basis as the amounts recognized in regulatory assets and regulatory liabilities upon adoption of SFAS No. 158.

      As a result of adopting SFAS No. 158, at December 31, 2007 regulatory assets and regulatory liabilities include prior service credits and net actuarial gains related to other postretirement benefit plans of $5.7 million and $19.5 million, respectively. These amounts have not yet been recognized in net periodic benefit expense. At December 31, 2006, regulatory assets included prior service credits of $7.8 million and net actuarial gains of $4.9 million related to the other postretirement benefit plans.

     Net actuarial gains of $0.2 million and prior service credit of $2.1 million related to our other post retirement benefit plans that are included in regulatory liabilities at December 31, 2007 are expected to be recognized in net periodic benefit expense in 2008. However, any differences between the annual actuarially determined cost and amounts currently being recovered in rates are recorded as an adjustment to revenues and collected or refunded through future rate adjustments.

     The allocation of the purchase price to the assets and liabilities of Transco based on estimated fair values resulted in the recording of additional postretirement benefits other than pension liability in 1995, for the amount that the projected benefit obligation exceeded the plan assets. The remaining amount of additional postretirement benefits other than pension costs deferred at December 31, 2007 and 2006, is $5.5 million and $10.6 million, respectively, and is expected to be recovered through future rates generally over the average remaining service period for active employees.

      The total deferred postretirement benefits costs resulted in a net regulatory liability of $10.0 million at December 31, 2007 and a net regulatory asset of $8.5 million at December 31, 2006. These costs are expected to be recovered through future rates generally over the average remaining service period for active employees.

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

     Defined contribution plan Our employees participate in a Williams defined contribution plan. We recognized compensation expense of $6.0 million, $5.4 million and $4.8 million in 2007, 2006 and 2005, respectively, for company matching contributions to this plan.

     Employee Stock-Based Compensation Plan Information The Williams Companies, Inc. 2007 Incentive Plan (Plan) was approved by stockholders on May 17, 2007. The Plan provides for Williams common-stock-based awards to both employees and nonmanagement directors. The Plan permits the granting of various types of awards including, but not limited to, stock options and deferred stock. Awards may be granted for no consideration other than prior and future services or based on certain financial performance targets being achieved.

     Williams currently bills us directly for compensation expense related to stock-based compensation awards granted directly to our employees based on the fair value of the options. We are also billed for our proportionate share of both WGP’s and Williams’ stock-based compensation expense though various allocation processes.

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     Accounting for Stock-Based Compensation Prior to January 1, 2006, we accounted for the Plan under the recognition and measurement provisions of Accounting Principles Board (APB) Opinion No. 25, “Accounting for Stock Issued to Employees,” and related interpretations, as permitted by FASB Statement No. 123, “Accounting for Stock-Based Compensation” (SFAS No. 123). Compensation cost for stock options was not recognized in the Consolidated Statement of Income for 2005, as all stock options granted under the Plan had an exercise price equal to the market value of the underlying common stock on the date of the grant. Prior to January 1, 2006, compensation cost was recognized for restricted stock units. Effective January 1, 2006, we adopted the fair value recognition provisions of FASB Statement No. 123(R), “Share-Based Payment” (SFAS No. 123(R)), using the modified-prospective method. Under this method, compensation cost recognized in periods subsequent to December 31, 2005, includes: (1) compensation cost for all share-based payments granted through December 31, 2005, but for which the requisite service period had not been completed as of December 31, 2005, based on the grant date fair value estimated in accordance with the original provisions of SFAS No. 123, and (2) compensation cost for most share-based payments granted subsequent to December 31, 2005, based on the grant date fair value estimated in accordance with the provisions of SFAS No. 123(R). The performance targets for certain performance based restricted stock units have not been established and therefore expense is not currently recognized. Expense associated with these performance-based awards will be recognized in future periods when performance targets are established. Results for prior periods have not been restated.

     Total stock-based compensation expense, included in administrative and general expenses, for the years ended December 31, 2007 and 2006 was $2.1 million and $1.5 million, respectively, excluding amounts allocated from WGP and Williams.

6. INCOME TAXES

     Following is a summary of the provision for income taxes for 2007, 2006, and 2005 (in thousands):

	2007			2006		2005
Current:
Federal	$	105,847		$	13,183	$	96,420
State		13,387			1,434		14,435
		119,234			14,617		110,855
Deferred:
Federal		(13,375	)		48,785		(1,710	)
State		(1,987	)		24,474		794
		(15,362	)		73,259		(916	)
Provision for income taxes	$	103,872		$	87,876	$	109,939

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     Following is a reconciliation of the provision for income taxes at the federal statutory rate to the provision for income taxes (in thousands):

	2007			2006			2005
Taxes computed by applying the federal statutory rate	$	96,806		$	71,794		$	103,339
State income taxes (net of federal benefit)		7,410			16,840			9,599
Adjustment of excess deferred taxes		—			—			(2,996	)
Other, net		(344	)		(758	)		(3	)
Provision for income taxes	$	103,872		$	87,876		$	109,939

     We provide for income taxes using the assets and liability method as required by SFAS 109, “Accounting for Income Taxes.” During 2006, we increased the effective state tax rate as the result of a rate analysis prepared in conjunction with the Docket No. RP06-569 rate case. In addition, we recorded a regulatory asset that partially offsets the effect of the state rate increase. The overall effect on profit and loss was a decrease in net income of $5 million. During 2005, as a result of the reconciliation of our tax basis and book basis assets and liabilities, we recorded a $3.0 million tax benefit adjustment to reduce the overall deferred income tax liabilities on the Balance Sheet.

     Cash payments for income taxes (net of refunds) were $57.7 million, $39.9 million, and $123.7 million in 2007, 2006, and 2005, respectively.

     Significant components of deferred income tax liabilities and assets as of December 31, 2007 and 2006 are as follows (in thousands):

	2007		2006
Deferred tax liabilities
Property, plant and equipment	$	1,050,326	$	1,023,236
Deferred charges		29,259		32,621
Regulatory assets/liabilities, net		61,827		80,445
Investments		11,445		5,913
Total deferred tax liabilities		1,152,857		1,142,215
Deferred tax assets
Estimated rate refund liability		37,498		777
Accrued payroll and benefits		40,863		57,312
Accrued liabilities		72,589		76,172
Other		13,054		12,086
Total deferred tax assets		164,004		146,347
Overall net deferred tax liabilities	$	988,853	$	995,868

     Effective January 1, 2007, we adopted Financial Accounting Standards Board (FASB) Interpretation No. 48, “Accounting for Uncertainty in Income Taxes, an interpretation of FASB Statement No. 109” (FIN 48). The Interpretation prescribes guidance for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. The amount of unrecognized tax benefits at December 31, 2007 is immaterial.

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     We recognize related interest and penalties as a component of income tax expense. The amounts accrued for interest and penalties at December 31, 2007 are immaterial.

     During the next twelve months, we do not expect to have a material impact on our financial position for settlement of any unrecognized tax benefit associated with domestic matters under audit.

     As of December 31, 2007, the IRS examination of our consolidated U.S. income tax returns for 2002 through 2005 was in process. IRS examinations for 1996 through 2001 have been completed but the years remain open while certain issues are under review with the Appeals Division of the IRS. The statute of limitations for most states expires one year after IRS audit settlement.

7. FINANCIAL INSTRUMENTS AND GUARANTEES

     Fair value of financial instruments The carrying amount and estimated fair values of our financial instruments as of December 31, 2007 and 2006 are as follows (in thousands):

	Carrying Amount				Fair Value
	2007		2006		2007		2006
Financial assets:
Cash	$	119	$	315	$	119	$	315
Short-term financial assets		224,374		191,380		224,374		191,380
Long-term financial assets		925		1,760		925		1,760
Financial liabilities:
Long-term debt, including current portion		1,202,370		1,201,458		1,296,482		1,270,099

     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 valued using year-end traded bond market prices. Private debt is valued based on the prices of similar securities with similar terms and credit ratings. At both December 31, 2007 and 2006, approximately 94 percent of 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 December 31, 2007 and 2006, we had advances to affiliates of $224 million and $190 million, respectively. Advances to affiliates are due on demand. In mid 2008, we intend to recall a large portion of these advances in order to pay rate refunds to our customers after final approval of the Agreement in Docket No.RP06-569.

     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

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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.

8. TRANSACTIONS WITH MAJOR CUSTOMERS AND AFFILIATES

     Major Customers In 2007, operating revenues received from Public Service Enterprise Group, KeySpan Corporation, and Piedmont Natural Gas Company, our three major customers, were $141.9 million, $86.1 million, and $84.4 million, respectively. In 2006, operating revenues received from Public Service Enterprise Group, KeySpan Corporation, and Piedmont Natural Gas Company, our three major customers, were $106.7 million, $74.7 million, and $66.8 million, respectively. In 2005, our three major customers were Public Service Enterprise Group, Piedmont Natural Gas Company, and KeySpan Corporation, providing operating revenues of $112.2 million, $97.1 million, and $82.8 million, respectively.

     Affiliates Included in our operating revenues for 2007, 2006, and 2005 are revenues received from affiliates of $42.8 million, $51.5 million, and $87.1 million, respectively. The rates charged to provide sales and services to affiliates are the same as those that are charged to similarly-situated nonaffiliated customers.

     Through an agency agreement with us, WGM manages our jurisdictional merchant gas sales. For the year ended December 31, 2005, included in our cost of sales is $5.5 million representing agency fees billed to us by WGM under the agency agreement. Due to the termination of our remaining Firm Sales agreements effective April 1, 2005, the agency fees billed by WGM for 2007 and 2006 were not significant.

     Included in our cost of sales for 2007, 2006, and 2005 is purchased gas cost from affiliates, excluding the agency fees discussed above, of $9.7 million, $15.7 million, and $75.7 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 2007, 2006, and 2005 were $53.2 million, $53.4 million, and $50.6 million, respectively, for such corporate expenses charged by Williams and other affiliated companies. Management considers the cost of these services to be reasonable.

     Effective June 1, 2004 and pursuant to an operating agreement, we serve as contract operator on certain WFS facilities. Transco recorded reductions in operating expenses for services provided to WFS for $5.8 million, $6.9 million, and $7.5 million in 2007, 2006, and 2005 respectively, under terms of the operating agreement.

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     In April 2005, we sold our interest in certain gas pipeline and related facilities and equipment, located in the Ship Shoal Area, Offshore Louisiana, to Williams Mobile Bay Producer Services, L.L.C., an affiliated company, for $6.9 million. The sale of these assets was at book value, and resulted in no gain or loss.

9. ASSET RETIREMENT OBLIGATIONS

     We record an asset and a liability equal to the present value of each expected future asset retirement obligation (ARO). The ARO asset is depreciated in a manner consistent with the depreciation of the underlying physical asset. We measure changes in the liability due to passage of time by applying an interest method of allocation. The depreciation of the ARO asset and accretion of the ARO liability are recognized as an increase to a regulatory asset. The regulatory asset will be amortized commensurate with our collection of those costs in rates.

     The asset retirement obligation at December 31, 2007 and 2006 is $141 million and $136 million, respectively. The increases in the obligation in 2007 and 2006 are due primarily to obtaining additional information that revised our estimation of our asset retirement obligation for certain assets and ongoing accretion of the liability. Factors affected by the additional information included estimated settlement dates, estimated settlement costs and inflation rates.

     During 2007 and 2006, our overall asset retirement obligation changed as follows (in thousands):

	2007			2006
Beginning balance	$	136,171		$	53,596
Accretion		10,151			3,060
New obligations		2,651			—
Changes in estimates of existing obligations		(5,544	)		80,713	(1)
Property dispositions		(2,013	)		(1,198	)
Ending balance	$	141,416		$	136,171

(1) Includes $6 million related to assets inadvertently omitted in the 2005 ARO calculation. Management believes this omission is not material to the financial statements for any period presented.

     The accrued obligations relate to underground storage caverns, offshore platforms, pipelines, and gas transmission facilities. At the end of the useful life of each respective asset, we are legally obligated to plug storage caverns and remove any related surface equipment, to dismantle offshore platforms, to cap certain gathering pipelines at the wellhead connection and remove any related surface equipment, and to remove certain components of gas transmission facilities from the ground.

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10. REGULATORY ASSETS AND LIABILITIES

     The regulatory assets and regulatory liabilities resulting from our application of the provisions of SFAS No. 71 included in the accompanying Consolidated Balance Sheet at December 31, 2007 and December 31, 2006 are as follows (in millions):

	2007		2006
Regulatory Assets
Grossed-up deferred taxes on equity funds used during construction	$	91.5	$	87.7
Asset retirement obligations (1)		47.3		87.6
Deferred taxes		14.5		15.5
Deferred gas costs		—		8.6
Environmental costs		4.0		5.7
Postretirement benefits other than pension		9.9		9.4
Fuel cost		11.9		9.5
Total Regulatory Assets	$	179.1	$	224.0
Regulatory Liabilities
Negative salvage (1)	$	17.4	$	40.1
Deferred cash out		7.6		15.8
Electric power cost		1.4		4.2
Deferred gas costs		1.2		—
Postretirement benefits other than pension		19.9		0.9
Total Regulatory Liabilities	$	47.5	$	61.0

(1) $40 million of negative salvage liability was reclassified to ARO asset in 2007.

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11. QUARTERLY INFORMATION (UNAUDITED)

The following summarizes selected quarterly financial data for 2007 and 2006 (in thousands):

2007	First			Second			Third			Fourth (1)
Operating revenues	$	273,138		$	315,152		$	288,688		$	323,827
Operating expenses		199,069			230,703			205,054			238,621
Operating income		74,069			84,449			83,634			85,206
Interest expense		23,193			23,431			24,097			24,383
Other (income) and deductions, net		(9,645	)		(10,910	)		(13,943	)		(9,703	)
Income before income taxes		60,521			71,928			73,480			70,526
Provision for income taxes		22,897			27,808			27,927			25,240
Net income	$	37,624		$	44,120		$	45,553		$	45,286

2006	First (2)			Second			Third			Fourth (3)
Operating revenues	$	259,591		$	260,812		$	261,816		$	266,172
Operating expenses		179,736			192,913			209,971			215,738
Operating income		79,855			67,899			51,845			50,434
Interest expense		15,073			22,941			23,489			24,503
Other (income) and deductions, net		(8,515	)		(10,271	)		(11,313	)		(11,001	)
Income before income taxes		73,297			55,229			39,669			36,932
Provision for income taxes		27,585			21,104			15,320			23,867
Net income	$	45,712		$	34,125		$	24,349		$	13,065

(1)	Includes a $2.2 million decrease to operating expenses resulting from a reversal of a reserve related to prior cashout periods and a $2.0 million decrease to operating expenses resulting from the reversal of a liability associated with unidentified transportation and exchange gas for prior years.
(2)	Includes a $2.0 million decrease to operating expenses and a $5.0 million decrease to interest expense resulting from a reversal of excess royalties reserve.
(3)	Includes a $9.3 million increase to operating revenue resulting from a change in the effective state income tax rate. This is more than offset by $15.9 million net increase in tax expense included in provision for income taxes.

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TRANSCONTINENTAL GAS PIPE LINE CORPORTATION
SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS
(In thousands)

			ADDITIONS
			Charged to
	Beginning		Costs and								Ending
Description	Balance		Expenses		Other			Deductions			Balances
Year ended December 31, 2007:
Reserve for rate refunds	$	2,232	$	—	$	106,163	(1)	$	(10,360	)	$	98,035
Reserve for doubtful receivables		503		—		—			(41	)		462
Year ended December 31, 2006:
Reserve for rate refunds		3,763		1,542		—			(3,073	)		2,232
Reserve for doubtful receivables		509		154		—			(160	)		503
Year ended December 31, 2005:
Reserve for rate refunds		8,919		8,194		—			(13,350	)		3,763
Reserve for doubtful receivables		778		—		—			(269	)		509

(1) Additions to reserve for rate refunds primarily due to placing into effect, subject to refund, the rates in Docket No. RP06-569 on March 1, 2007.

ITEM 9. Changes In and Disagreements with Accountants on Accounting and Financial Disclosure.

     None.

ITEM 9A. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

     An evaluation of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act) (Disclosure Controls) was performed as of the end of the period covered by this report. This evaluation was performed under the supervision and with the participation of our management, including our Senior Vice President and our Vice President and Treasurer. Based upon that evaluation, our Senior Vice President and our Vice President and Treasurer have concluded that our Disclosure Controls and procedures were effective at a reasonable assurance level.

     Our management, including our Senior Vice President and our Vice President and Treasurer, does not expect that our Disclosure Controls will prevent all errors and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within the company have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty, and that breakdowns can occur because of simple error or mistake. Additionally, controls can be circumvented by the individual acts of some persons, by collusion of two or more people, or by management override of the control. The design of any system of controls also is based in part upon certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions. Because of the

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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 make modifications as necessary; our intent in this regard is that the Disclosure Controls will be modified as systems change and conditions warrant.

Changes in Internal Controls Over Financial Reporting

     There have been no changes during the fourth quarter of 2007 that have materially affected, or are reasonably likely to materially affect, our Internal Controls over financial reporting.

Management’s Report on Internal Control over Financial Reporting

     See “Management’s Report on Internal Control over Financial Reporting” set forth above in Item 8, “Financial Statements and Supplementary Data.”

ITEM 9B. Other Information

     None

PART III

     Since we meet the conditions set forth in General Instruction (I)(1)(a) and (b) of Form 10-K, the information required by Items 10, 11, 12, and 13 is omitted.

ITEM 14. Principal Accountant Fees and Services

     Fees for professional services provided by our independent registered public accounting firm in each of the last two fiscal years in each of the following categories are (in thousands):

	2007		2006
Audit Fees	$	2,240	$	2,463
Audit-Related Fees		142		203
Tax Fees		—		—
All Other Fees		—		—
Total Fees	$	2,382	$	2,666

     Fees for audit services include fees associated with the annual audit, the reviews for our quarterly reports on Form 10-Q, the reviews for other SEC filings and accounting consultation. Audit-related fees include other attest services.

     As a wholly-owned subsidiary of Williams, we do not have a separate audit committee. The Williams audit committee policies and procedures for pre-approving audit and non-audit services will be filed with the Williams Proxy Statement to be filed with the Securities and Exchange Commission on or before April 15, 2008.

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PART IV

ITEM 15. Exhibits and Financial Statement Schedules.

Page
Reference to
2007 10-K

A. Index

1. Financial Statements:

Management’s Report on Internal Control over Financial Reporting	28
Report of Independent Registered Public Accounting Firm - Ernst &Young LLP	29
Consolidated Statement of Income for the Years Ended December 31, 2007, 2006 and 2005	30
Consolidated Balance Sheet as of December 31, 2007 and 2006	31-32
Consolidated Statement of Common Stockholder’s Equity for the Years Ended December 31, 2007, 2006 and 2005	33
Consolidated Statement of Comprehensive Income for the Years Ended December 31, 2007, 2006 and 2005	34
Consolidated Statement of Cash Flows for the Years Ended December 31, 2007, 2006 and 2005	35-36
Notes to Consolidated Financial Statements	37-58

2. Financial Statement Schedules:

Schedule II — Valuation and Qualifying Accounts for the
Years ended December 31, 2007, 2006 and 2005	59
The following schedules are omitted because of the absence of the conditions under which they are required:
I, III, IV, and V.

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3. Exhibits:

The following instruments are included as exhibits to this report. Those exhibits below incorporated by reference herein are indicated as such by the information supplied in the parenthetical thereafter. If no parenthetical appears after an exhibit, copies of the instrument have been included herewith.

     ( 2) Plan of acquisition, reorganization arrangement, liquidation or succession

- Stock Option Agreement dated as of December 12, 1994 by and between The Williams Companies, Inc. and Transco Energy Company. (Exhibit 3 to Transco Energy Company Schedule 14D-9 Commission File Number 005-19963)

     ( 3) Articles of incorporation and by-laws

- 1 Second Restated Certificate of Incorporation, as amended, of Transco. (Exhibit 3.1 to Transco Form 8-K dated January 23, 1987 Commission File Number 1-7584)

a)	Certificate of Amendment, dated August 4, 1992, of the Second Restated Certificate of Incorporation (Exhibit (10)-17(a) to Transco Energy Company Form 10-K for 1993 Commission File Number 1-7513)
b)	Certificate of Amendment, dated December 23, 1986, of the Second Restated Certificate of Incorporation (Exhibit (10)-17(b) to Transco Energy Company Form 10-K for 1993 Commission File Number 1-7513)
c)	Certificate of Amendment, dated August 12, 1987, of the Second Restated Certificate of Incorporation (Exhibit (10)-17(c) to Transco Energy Company Form 10-K for 1993 Commission File Number 1-7513)

- 2 By-Laws of Transco, as Amended and Restated July 16, 2007.

     ( 4) Instruments defining the rights of security holders, including indentures

-	1	Indenture dated July 15, 1996 between Transco and Citibank, N.A., as Trustee (filed as Exhibit 4.1 to Transco Form S-3 dated April 2, 1996 Transco Registration Statement No. 333-2155)
-	2	Indenture dated January 16, 1998 between Transco and Citibank, N.A., as Trustee (filed as Exhibit 4.1 to Transco Form S-3 dated September 8, 1997 Transco Registration Statement No. 333-27311)
-	3	Indenture dated August 27, 2001 between Transco and Citibank, N.A., as Trustee (filed as Exhibit 4.1 to Transco Form S-4 dated November 8, 2001 Transco Registration Statement No. 333-72982)

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-	4	Indenture dated July 3, 2002 between Transco and Citibank, N.A., as Trustee (filed as Exhibit 4.1 to The Williams Companies, Inc. Form 10-Q for the quarterly period ended June 30, 2002 Commission File Number 1-4174)
-	5	Indenture dated December 17, 2004 between Transco and JPMorgan Chase, N.A., as trustee (filed as Exhibit 4.1 to Transco Form 8-K filed December 21, 2004)
-	6	Indenture dated April 11, 2006 between Transco and JP Morgan Chase Bank, N.A., as trustee (filed as Exhibit 4.1 to Transco Form 8-K filed April 11, 2006).

     (10) Material contracts

-	1	Transco Energy Company Tran$tock Employee Stock Ownership Plan (Transco Energy Company Registration Statement No. 33-11721)
-	2	Lease Agreement, dated October 23, 2003, between Transco and Transco Tower Limited, a Texas limited partnership as amended March 10, 2004, March 11, 2004, May 10, 2004, and June 25, 2004 (filed as Exhibit 10.2 to Transco Form 10-K filed March 30, 2005).
-	3	Registration Rights Agreement dated April 11, 2006 between Transco, Banc of America Securities LLC, Greenwich Capital Markets, Inc. and other parties listed therein, as Initial Purchasers (filed as Exhibit 10.1 to Transco Form 8-K filed April 11, 2006).
-	4	Credit Agreement, dated May 1, 2006, among The Williams Companies, Inc., Northwest Pipeline Corporation, Transcontinental Gas Pipe Line Corporation, and Williams Partners L.P., as Borrowers, and Citibank, N.A., as Administrative Agent (filed as Exhibit 10.1 to The Williams Companies, Inc. Form 8-K filed May 1, 2006 Commission File Number 1-4174).
-	5	Amendment Agreement, dated May 9, 2007, among The Williams Companies, Inc., Williams Partners L.P., Northwest Pipeline Corporation, Transcontinental Gas Pipe Line Corporation, certain banks, financial institutions and other institutional lenders and Citibank, N.A., as administrative agent (filed as Exhibit 10.1 to The Williams Companies, Inc.’s current report on Form 8-K (File No. 001-04174) filed with the SEC on May 15, 2007 and incorporated by reference as Exhibit 10.1 to our Form 8-K filed May 15, 2007).
-	6	Amendment Agreement, dated November 21, 2007, among The Williams Companies, Inc., Williams Partners L.P., Northwest Pipeline Corporation, Transcontinental Gas Pipe Line Corporation, certain banks, financial institutions and other institutional lenders and Citibank, N.A., as administrative agent (filed as Exhibit 10.1 to The Williams Companies, Inc.’s current report on Form 8-K (File No. 001-04174) filed with

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the SEC on November 28, 2007 and incorporated by reference as Exhibit 10.1 to our Form 8-K filed November 28, 2007).

     (23) Consent of Independent Registered Public Accounting Firm

     (24) Power of attorney with certified resolution

     (31) Section 302 Certifications

-	1	Certification of Principal Executive Officer pursuant to Rules 13a-14(a) and 15d-14(a) promulgated under the Securities Exchange Act of 1934, as amended, and Item 601(b)(31) of Regulation S-K, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
-	2	Certification of Principal Financial Officer pursuant to Rules 13a-14(a) and 15d-14(a) promulgated under the Securities Exchange Act of 1934, as amended, and Item 601(b)(31) of Regulation S-K, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

     (32) Section 906 Certification

- Certification of Principal Executive Officer and Principal Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

64

SIGNATURES

     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, on this 27th day of February 2008.

TRANSCONTINENTAL GAS PIPE LINE CORPORATION (Registrant)
By:	/s/ Jeffrey P. Heinrichs
	Jeffrey P. Heinrichs
	Controller

     Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below on this 27th day of February 2008, by the following persons on behalf of the registrant and in the capacities indicated.

Signature	Title
/s/ STEVEN J. MALCOLM*	Chairman of the Board
Steven J. Malcolm
/s/ PHILLIP D. WRIGHT *	Director and Senior Vice President
Phillip D. Wright	(Principal Executive Officer)
/s/ FRANK J. FERAZZI *	Director and Vice President
Frank J. Ferazzi
/s/ RICHARD D. RODEKOHR*	Vice President and Treasurer (Principal Financial
Richard D. Rodekohr	Officer)
/s/ JEFFREY P. HEINRICHS *	Controller (Principal Accounting Officer)
Jeffrey P. Heinrichs

By	/s/ JEFFREY P. HEINRICHS *
	Jeffrey P. Heinrichs
	Attorney-in-fact

65

EX-3.2

AMENDED AND RESTATED

BY-LAWS

OF

TRANSCONTINENTAL GAS PIPE LINE CORPORATION

Effective July 16, 2007

ARTICLE I

Stockholders

     Section 1.1. Annual Meetings. The Annual Meeting of Stockholders shall be held for the election of Directors on the third Thursday in October in each year, beginning with the year 2007, if such day be not a legal holiday in the state where such meeting is to be held, or, if a legal holiday, then at the same time on the next succeeding business day at the principal office of the Corporation in the State of Delaware or at such other place either within or without the State of Delaware as may be designated by the Board of Directors from time to time. Any proper business may be transacted at the Annual Meeting.

     Section 1.2. Special Meetings. Special meetings of stockholders, to be held at the principal office of the Corporation in the State of Delaware or at such other place within or without the State of Delaware and at such date and time as may be stated in the notice of the meeting, and for any purpose or purposes, unless otherwise prescribed by statute, may be called by the Board of Directors or by the Chairman of the Board or by the President, and shall be called by the President or the Secretary at the request in writing of stockholders owning a majority of the issued and outstanding shares of capital stock of the Corporation of the class or classes which would be entitled to vote on the matter or matters proposed to be acted upon at such special meeting of stockholders. Any such request shall state the purpose or purposes of the proposed meeting.

     Section 1.3. Notices of Meetings. Whenever stockholders are required or permitted to take any action at a meeting, except as provided by Section 7.3 hereof, a written notice of the meeting shall be given which shall state the place, date and hour of the meeting, and, in the case of a special meeting, the purpose or purposes for which the meeting is called. Unless otherwise provided by law, the written notice of any meeting shall be given not less than ten nor more than sixty days before the date of the meeting to each stockholder entitled to vote at such meeting. If mailed, such notice shall be deemed to be given when deposited in the United States mail, postage prepaid, directed to the stockholder at his address as it appears on the records of the Corporation.

     Section 1.4. Adjournments. Any meeting of stockholders, annual or special, may adjourn from time to time to reconvene at the same or some other place, and notice need not be

     given of any such adjourned meeting if the time and place thereof are announced at the meeting at which the adjournment is taken. At the adjourned meeting, the Corporation may transact any

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business which might have been transacted at the original meeting. If the adjournment is for more than thirty days, or if after the adjournment a new record date is fixed for the adjourned meeting, a notice of the adjourned meeting shall be given to each stockholder of record entitled to vote at the meeting.

     Section 1.5. Quorum. At any meeting of stockholders, except where otherwise provided by law or the Certificate of Incorporation or these By-laws, the holders of a majority of the outstanding shares of each class of stock entitled to vote at the meeting, present in person or represented by proxy, shall constitute a quorum. For purposes of the foregoing, two or more classes or series of stock shall be considered a single class if the holders thereof are entitled to vote together as a single class at the meeting. In the absence of a quorum the stockholders so present may, by majority vote, adjourn the meeting from time to time in the manner provided by Section 1.4 of these By-laws until a quorum shall attend. Shares of its own capital stock belonging on the record date for the meeting to the Corporation or to another Corporation, if a majority of the shares entitled to vote in the election of directors of such other Corporation is held, directly or indirectly, by the Corporation, shall neither be entitled to vote nor be counted for quorum purposes; provided, however, that the foregoing shall not limit the right of the Corporation to vote stock, including but not limited to its own stock, held by it in a fiduciary capacity.

     Section 1.6. Organization. Meetings of stockholders shall be presided over by the Chairman of the Board, or in his absence by the President, or in his absence by a Senior Vice President, or in his absence by a Vice President, or in the absence of the foregoing persons by a chairman designated by the Board of Directors, or in the absence of such designation by a chairman chosen at the meeting. The Secretary shall act as secretary of the meeting, but in his absence the chairman of the meeting may appoint any person to act as secretary of the meeting.

     Section 1.7. Voting; Proxies. Unless otherwise provided in the Certificate of Incorporation, each stockholder entitled to vote at any meeting of stockholders shall be entitled to one vote for each share of stock held by him which has voting power upon the matter in question. Each stockholder entitled to vote at a meeting of stockholders or to express consent or dissent to corporate action in writing without a meeting may authorize another person or persons to act for him by proxy, but no such proxy shall be voted or acted upon after three years from its date, unless the proxy provides for a longer period. A duly executed proxy shall be irrevocable if it states that it is irrevocable and if, and only as long as, it is coupled with an interest sufficient in law to support an irrevocable power. A stockholder may revoke any proxy which is not irrevocable by attending the meeting and voting in person or by filing an instrument in writing revoking the proxy or another duly executed proxy bearing a later date with the Secretary of the Corporation. The vote for Directors and, upon the demand of any stockholder, the vote upon any question before the meeting shall be by written ballot. All elections shall be had and all questions decided, unless otherwise provided by law, the Certificate of Incorporation or these By-laws, by a plurality vote.

     Section 1.8. Fixing Date for Determination of Stockholders of Record. In order that the Corporation may determine the stockholders entitled to notice of or to vote at any meeting of stockholders or any adjournment thereof, or to express consent to corporate action in writing without a meeting, or entitled to receive payment of any dividend or other distribution or allotment of any

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rights, or entitled to exercise any rights in respect of any change, conversion or exchange of stock, or for the purpose of any other lawful action, the Board of Directors may fix, in advance, a record date, which shall not be more than sixty nor less than ten days before the date of such meeting, nor more than sixty days prior to any other action. If no record date is fixed: (1) the record date for determining stockholders entitled to notice of or to vote at a meeting of stockholders shall be at the close of business on the day next preceding the day on which notice is given, or, if notice is waived, at the close of business on the day next preceding the day on which the meeting is held; (2) the record date for determining stockholders entitled to express consent to corporate action in writing without a meeting, when no prior action by the Board is necessary, shall be on the day on which the first written consent is expressed; and (3) the record date for determining stockholders for any other purpose shall be at the close of business on the day on which the Board adopts the resolution relating thereto. A determination of stockholders of record entitled to notice of or to vote at a meeting of stockholders shall apply to any adjournment of the meeting; provided, however, that the Board may fix a new record date for the adjourned meeting.

     Section 1.9. List of Stockholders Entitled to Vote. The Secretary shall prepare and make, at least ten days before every meeting of stockholders, a complete list of the stockholders entitled to vote at the meeting, arranged in alphabetical order, and showing the address of each stockholder and the number of shares registered in the name of each stockholder. Such list shall be open to examination of any stockholder, for any purpose germane to the meeting, during ordinary business hours, for a period of at least ten days prior to the meeting, either at a place within the city where the meeting is to be held, which place shall be specified in the notice of the meeting, or, if not so specified, at the place where the meeting is to be held. The list shall also be produced and kept at the time and place of the meeting during the whole time thereof and may be inspected by any stockholder who is present.

ARTICLE II

Board of Directors

     Section 2.1. Powers; Numbers; Qualifications. The business and affairs of the Corporation shall be managed by the Board of Directors, except as may be otherwise provided by law or in the Certificate of Incorporation. The number of Directors constituting the whole Board shall be not more than fifteen nor less than three. The authorized number of Directors within the limits above specified shall be determined by resolution of the Board of Directors.

     Section 2.2. Election; Term of Office; Resignation; Vacancies. Each Director shall hold office until the Annual Meeting of Stockholders next succeeding his election and until his successor is elected and qualified or until his earlier resignation or removal. Any Director may resign at any time upon written notice to the Board of Directors or to the President or the Secretary of the Corporation. Such resignation shall take effect at the time specified therein, and unless otherwise specified therein, no acceptance of such resignation shall be necessary to make it effective. Unless otherwise provided in the Certificate of Incorporation or these By-laws, vacancies and newly created directorships resulting from any increase in the authorized number of Directors or from any other cause may be filled by a majority of the Directors then in office, although less than a quorum.

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     Section 2.3. Regular Meetings. Regular meetings of the Board of Directors may be held at such places within or without the State of Delaware and at such times as the Board may from time to time determine, and if so determined, notice thereof need not be given.

     Section 2.4. Special Meetings. Special meetings of the Board of Directors may be held at any time or place within or without the State of Delaware whenever called by the Chairman of the Board or the President or a majority of the Directors then in office. Reasonable notice thereof shall be given by the person or persons calling the meeting.

     Section 2.5. Telephonic Meetings Permitted. Unless otherwise restricted by the Certificate of Incorporation or these By-laws, members of the Board of Directors, or any committee designated by the Board, may participate in a meeting of the Board or of such committee, as the case may be, by means of conference telephone or similar communications equipment by means of which all persons participating in the meeting can hear each other, and participation in a meeting pursuant to this By-law shall constitute presence in person at such meeting.

     Section 2.6. Quorum; Vote Required for Action. At all meetings of the Board of Directors, Directors constituting a majority of the entire Board shall constitute a quorum for the transaction of business. The vote of a majority of the Directors present at a meeting at which a quorum is present shall be the act of the Board unless the Certificate of Incorporation or these By-laws shall require a vote of a greater number. In case at any meeting of the Board a quorum shall not be present, the members of the Board present may adjourn the meeting from time to time until a quorum shall attend.

     Section 2.7. Organization. Meetings of the Board of Directors shall be presided over by the Chairman of the Board, or in his absence by a President or Senior Vice President, or in their absence by a chairman chosen at the meeting. The Secretary shall act as secretary of the meeting, but in his absence the chairman of the meeting may appoint any person to act as secretary of the meeting.

     Section 2.8. Informal Action by Directors. Any action required or permitted to be taken at any meeting of the Board of Directors, or of any committee thereof, may be taken without a meeting if all members of the Board or of such committee, as the case may be, consent thereto in writing, and the writing or writings are filed with the minutes of proceedings of the Board or committee.

ARTICLE III

Committees

     Section 3.1. Committees of the Board. The Board of Directors may designate one or more committees, each committee to consist of one or more of the Directors. The Board of Directors may designate one or more Directors as alternate members of any committee, who may replace any absent or disqualified member at any meeting of any such committee. In the absence or

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disqualification of a member of a committee, the member or members present at any meeting and not disqualified from voting, whether or not a quorum, may unanimously appoint another member of the Board of Directors to act at the meeting in the place of any absent or disqualified member. Any such committee, to the extent provided in the resolution of the Board of Directors, or in the By-laws of the Corporation, shall have and may exercise all the powers and authority of the Board of Directors in the management of the business and affairs of the Corporation, and may authorize the seal of the Corporation to be affixed to all papers which may require it; but no such committee shall have the power or authority in reference to the following matters: (i) approving or adopting, or recommending to the stockholders, any action or matter expressly required by Delaware law to be submitted to stockholders for approval; or (ii) adopting, amending or repealing any By-law of the Corporation. Each committee shall keep regular minutes and report to the Board of Directors when required.

     Section 3.2. Committee Rules. Unless the Board of Directors otherwise provides, each committee designated by the Board may make, alter and repeal rules for the conduct of its business. In the absence of a provision by the Board or a provision in the rules of such committee to the contrary, a majority of the entire authorized number of members of such committee shall constitute a quorum for the transaction of business, the vote of a majority of the members present at a meeting at the time of such if a quorum is then present shall be the act of such committee, and in other respects such committee shall conduct its business in the same manner as the Board conducts its business pursuant to Article II of these By-laws.

ARTICLE IV

Officers

     Section 4.1. General. The officers of the Corporation shall be elected by the Board of Directors and shall be a Chairman of the Board of Directors, and may be a Chief Executive Officer, President, one or more Senior Vice Presidents and one or more Vice Presidents, a Secretary, a Treasurer and such other officers as the Board of Directors may from time to time elect. Any number of offices may be held by the same person, unless otherwise prohibited by law, the Certificate of Incorporation or these By-laws. The officers of the Corporation need not be stockholders of the Corporation nor, except in the case of the Chairman of the Board of Directors, need such officers be Directors of the Corporation.

     Section 4.2. Election. The Board of Directors shall elect the officers of the Corporation who shall hold their offices for such terms and shall exercise such powers and perform such duties as shall be determined from time to time by the Board of Directors; and all officers of the Corporation shall hold office until their successors are chosen and qualified, or until their death, resignation or removal. Any officer elected by the Board of Directors may be removed at any time by the affirmative vote of a majority of the Board of Directors. Any vacancy occurring in any office of the Corporation shall be filled by the Board of Directors.

     Section 4.3. Chairman of the Board of Directors. The Chairman of the Board of Directors shall direct the policy of the Corporation, subject, however, to the control of the Board of

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Directors and of any duly authorized committee of Directors. The Chairman shall, if present, preside at all meetings of the Board of Directors and of the stockholders. The Chairman may, with the Treasurer or the Secretary, or an Assistant Treasurer or an Assistant Secretary, sign certificates for stock of the Corporation. The Chairman may sign and execute in the name of the Corporation deeds, mortgages, bonds, contracts and other instruments, except in cases where the signing and execution thereof shall be expressly delegated by the Board of Directors or by a duly authorized committee of Directors, or by these By-laws to some other officer or agent of the Corporation, or shall be required by law otherwise to be signed or executed. The Chairman shall have the power to appoint, determine the duties and fix the compensation of such agents and employees as in the Chairman’s judgment may be necessary or proper for the transaction of the business of the Corporation, including the right of removal of any officer (other than an officer who is also a Director), with or without cause, and the termination of employment of any employee. In general, the Chairman shall perform all duties incident to the office of Chairman of the Board, and such other duties as may from time to time be assigned by the Board of Directors or by any duly authorized committee of Directors.

     Section 4.4. Chief Executive Officer. The Chief Executive Officer of the Corporation, if other than the Chairman of the Board, shall, during the absence or disability of the Chairman of the Board, exercise all powers and discharge all the duties of the Chairman of the Board. The Chief Executive Officer may, with the Treasurer or the Secretary, or an Assistant Treasurer or an Assistant Secretary, sign certificates for stock of the Corporation. The Chief Executive Officer may sign and execute in the name of the Corporation deeds, mortgages, bonds, contracts and other instruments, except in cases where the signing and execution thereof shall be expressly delegated by the Board of Directors or by a duly authorized committee of Directors, or by these By-laws, to some other officer or agent of the Corporation, or shall be required by law otherwise to be signed or executed. The Chief Executive Officer shall have the power to appoint, determine the duties and fix the compensation of such agents and employees as in the judgment of the Chief Executive Officer may be necessary or proper for the transaction of the business of the Corporation, including the right of removal of any officer (other than an officer who is also a Director), with or without cause, and the termination of employment of any employee. In general, the Chief Executive Officer shall perform all duties incident to the office and such other duties as may from time to time be assigned by the Board of Directors, the Chairman of the Board or by any duly authorized committee of Directors. If no Chief Executive Officer is elected, then the President shall have all the rights and powers of the Chief Executive Officer.

     Section 4.5. President. The President shall have general supervision of the business of the Corporation. During the absence or disability of the Chairman of the Board and the Chief Executive Officer, the President shall exercise all the powers and discharge all the duties of the Chairman of the Board and the Chief Executive Officer. The President may, with the Treasurer or the Secretary, or an Assistant Treasurer or an Assistant Secretary, sign certificates for stock of the Corporation. The President may sign and execute in the name of the Corporation deeds, mortgages, bonds, contracts and other instruments, except in cases where the signing and execution thereof shall be expressly delegated by the Board of Directors or by a duly authorized committee of Directors, or by these By-laws, to some other officer or agent of the Corporation, or shall be required by law otherwise to be signed or executed. The President shall have the power to appoint, determine the duties and fix the compensation of such agents and employees as in the judgment of the President

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may be necessary or proper for the transaction of the business of the Corporation, including the right of removal of any officer (other than an officer who is also a Director), with or without cause, and the termination of employment of any employee. In general, the President shall perform all duties incident to the office of President, and such other duties as may from time to time be assigned by the Board of Directors, the Chairman of the Board or by any duly authorized committee of Directors. If no President is elected, then the Senior Vice Presidents shall have all the rights and powers of the President.

     Section 4.6. Vice Presidents. At the request of the President or in his absence or in the event of his inability or refusal to act, any Vice President shall perform the duties of the President, and when so acting, shall have all the powers of and be subject to all the restrictions upon the President; any Vice President may also sign and execute in the name of the Corporation deeds, mortgages, bonds, contracts and other instruments, except in cases where the signing and execution thereof shall be expressly delegated by the Board of Directors or by a duly authorized committee of Directors, or by these By-laws, to some other officer or agent of the Corporation, or shall be required by law otherwise to be signed or executed; and each Vice President shall perform such other duties and have such other powers as the Board of Directors from time to time may prescribe.

     Section 4.7. Secretary. The Secretary shall keep the minutes of the meetings of the stockholders, of the Board of Directors and of any committee appointed by the Board in books provided for that purpose; he shall see that all notices are duly given in accordance with the provisions of these By-laws or as required by law; he shall be custodian of the records and of the corporate seal or seals of the Corporation; he shall see that the corporate seal is affixed to all documents, the execution of which, on behalf of the Corporation, under its seal, is duly authorized, and when so affixed may attest the same; he may sign, with the President or a Vice President, certificates of stock of the Corporation; and, in general, he shall perform all duties incident to the office of a secretary of a Corporation, and such other duties as, from time to time, may be assigned to him by the Board of Directors.

     Section 4.8. Treasurer. The Treasurer shall have charge of and be responsible for all funds, securities, receipts and disbursements of the Corporation, and shall deposit, or cause to be deposited, in the name of the Corporation, all moneys or other valuable effects in such banks, trust companies or other depositories as shall, from time to time, be selected by the Board of Directors; he shall render to the President and to the Board of Directors, whenever requested, an account of the financial condition of the Corporation; he may sign, with the President or Vice President, certificates of stock of the Corporation; and, in general, he shall perform all duties incident to the office of a treasurer of a Corporation, and such other duties as, from time to time, may be assigned to him by the Board of Directors.

     Section 4.9. Assistant Officers. The Board of Directors may appoint one or more assistant officers. Each assistant officer shall, at the request of or in the absence or disability of the officer to whom he is an assistant, perform the duties of such officer and he shall have such other authority and perform such other duties as the Board of Directors may prescribe.

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     Section 4.10. Subordinate Officers. The Board of Directors may appoint such subordinate officers as it may deem desirable. Each such officer shall hold office for such period, have such authority and perform such duties as the Board of Directors may prescribe. The Board of Directors may, from time to time, authorize any officer to appoint and remove subordinate officers and prescribe the powers and duties thereof.

     Section 4.11. Officers Holding Two or More Offices. Any number of the above offices may be held by the same person, but no officer shall execute, acknowledge or verify any instrument in more than one capacity if such instrument is required by law or by these By-laws to be executed, acknowledged or verified by two officers.

     Section 4.12. Removal. Any officer of the Corporation may be removed, with or without cause, by a vote of a majority of the entire Board of Directors at a meeting for that purpose.

     Section 4.13. Signatures. Any corporate instrument signed by an officer shall be presumed to have been so signed (a) at the request of the Board of Directors or the President, as the case may be, or (b) in the absence or because of the disability of the officer or officers otherwise authorized to so sign, or (c) because of expressly delegated or assigned authority to the officer so signing, and such signature may be relied upon by the person to whom the instrument is delivered without establishing the authority or power of the officer to so sign.

ARTICLE V

Stock

     Section 5.1. Certificates. Every holder of stock in the Corporation shall be entitled to have a certificate signed by or in the name of the Corporation by the Chairman of the Board or the President or a Vice President, and by the Treasurer or an Assistant Treasurer or the Secretary or an Assistant Secretary of the Corporation, certifying the number of shares owned by him in the Corporation. Any or all the signatures on the certificate may be a facsimile. In case any officer, transfer agent or registrar who has signed or whose facsimile signature has been placed upon a certificate shall have ceased to be such officer, transfer agent or registrar before such certificate is issued, it may be issued by the Corporation with the same effect as if he were such officer, transfer agent or registrar at the date of issue.

     Section 5.2. Lost, Stolen or Destroyed Stock Certificates; Issuance of New Certificates. The Corporation may issue a new certificate of stock in the place of any certificate theretofore issued by it, alleged to have been lost, stolen or destroyed, and the Corporation may require the owner of the lost, stolen or destroyed certificate, or his legal representative, to give the Corporation a bond sufficient to indemnify it against any claim that may be made against it on account of the alleged loss, theft or destruction of any such certificate or the issuance of such new certificate.

ARTICLE VI

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Indemnification

     Section 6.1. Power to Indemnify in Actions, Suits or Proceedings Other Than Those by or in the Right of the Corporation. Subject to Section 6.3 of this Article VI, the Corporation shall indemnify any person who was or is a party or is threatened to be made a party to any threatened, pending or completed action, suit or proceeding, whether civil, criminal, administrative or investigative (other than an action by or in the right of the Corporation) by reason of the fact that such person is or was a Director or officer of the Corporation, or is or was serving at the request of the Corporation as a director or officer of another Corporation, partnership, joint venture, trust or other enterprise, against expenses (including reasonable attorneys’ fees), judgments, fines and amounts paid in settlement actually and reasonably incurred in connection with such action, suit or proceeding if such person acted in good faith and in a manner such person reasonably believed to be in or not opposed to the best interests of the Corporation, and, with respect to any criminal action or proceeding, had no reasonable cause to believe the conduct was unlawful. The termination of any action, suit or proceeding by judgment, order, settlement, conviction, or upon a plea of nolo contendere or its equivalent, shall not, of itself, create a presumption that the person did not act in good faith and in a manner which such person reasonably believed to be in or not opposed to the best interests of the Corporation, and, with respect to any criminal action or proceeding, had reasonable cause to believe that the conduct was unlawful.

     Section 6.2. Power to Indemnify in Actions, Suits or Proceedings by or in the Right of the Corporation. Subject to Section 6.3 of this Article VI, the Corporation shall indemnify any person who was or is a party or is threatened to be made a party to any threatened, pending or completed action or suit by or in the right of the Corporation to procure a judgment in its favor by reason of the fact that such person is or was a Director or officer of the Corporation, or is or was serving at the request of the Corporation as a director or officer of another Corporation, partnership, joint venture, trust or other enterprise against expenses (including reasonable attorneys’ fees) actually and reasonably incurred in connection with the defense or settlement of such action or suit if such person acted in good faith and in a manner such person reasonably believed to be in or not opposed to the best interests of the Corporation; except that no indemnification shall be made in respect of any claim, issue or matter as to which such person shall have been adjudged to be liable to the Corporation unless and only to the extent that the Court of Chancery of the State of Delaware or the court in which such action or suit was brought shall determine upon application that, despite the adjudication of liability but in view of all the circumstances of the case, such person is fairly and reasonably entitled to indemnify for such expenses which the Court of Chancery of the State of Delaware or such other court shall deem proper.

     Section 6.3. Authorization of Indemnification. Any indemnification under this Article VI (unless ordered by a court) shall be made by the Corporation only as authorized in the specific case upon a determination that indemnification of the Director or officer is proper in the circumstances because such person has met the applicable standard of conduct set forth in Section 6.1 or Section 6.2 of this Article VI, as the case may be. Such determination shall be made (a) by the Board of Directors by a majority vote of a quorum consisting of Directors who were not parties to such action, suit or proceeding, or (b) if such a quorum is not obtainable, or, even if obtainable a quorum of disinterested Directors so directs, by independent legal counsel in a written opinion, or (c)

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by the stockholders. To the extent, however, that a Director or officer of the Corporation has been successful on the merits or otherwise in defense of any action, suit or proceeding described above, or in defense of any claim, issue or matter therein, such person shall be indemnified against expenses (including attorneys’ fees) actually and reasonably incurred in connection therewith, without the necessity of authorization in the specific case.

     Section 6.4. Good Faith Defined. For purposes of any determination under Section 6.3 of this Article VI, a person shall be deemed to have acted in good faith and in a manner such person reasonably believed to be in or not opposed to the best interests of the Corporation, or, with respect to any criminal action or proceeding, to have had no reasonable cause to believe such person’s conduct was unlawful, if such person’s action is based on the records or books of account of the Corporation or another enterprise, or on information supplied to such person by the officers of the Corporation or another enterprise in the course of their duties, or on the advice of legal counsel for the Corporation or another enterprise or on information or records given or reports made to the Corporation or another enterprise by an independent certified public accountant or by an appraiser or other expert selected with reasonable care by the Corporation or another enterprise. The term “another enterprise” as used in this Section 6.4 shall mean any other Corporation or any partnership, joint venture, trust or other enterprise of which such person is or was serving at the request of the Corporation as a director or officer. The provision of this Section 6.4 shall not be deemed to be exclusive or to limit in any way the circumstances in which a person may be deemed to have met the applicable standard of conduct set forth in Sections 6.1 or 6.2 of this Article VI, as the case may be.

     Section 6.5. Indemnification by a Court. Notwithstanding any contrary determination in the specific case under Section 6.3 of this Article VI, and notwithstanding the absence of any determination thereunder, any Director or officer may apply to any court of competent jurisdiction in the State of Delaware for indemnification to the extent otherwise permissible under Sections 6.1 and 6.2 of this Article VI. The basis of such indemnification by a court shall be a determination by such court that indemnification of the Director or officer is proper in the circumstances because such person has met the applicable standards of conduct set forth in Sections 6.1 or 6.2 of this Article VI, as the case may be. Notice of any application for indemnification pursuant to this Section 6.5 shall be given to the Corporation promptly upon the filing of such application.

     Section 6.6. Expenses Payable in Advance to Directors and Officers. Expenses incurred by an officer or Director in defending a civil or criminal action, suit or proceeding may be paid by the Corporation in advance of the final disposition of such action, suit or proceeding upon receipt of an undertaking by or on behalf of the Director or officer to repay such amount if it shall ultimately be determined that such person is not entitled to be indemnified by the Corporation as authorized in this Article VI.

     Section 6.7 Indemnification of and Advancement to Employees and Agents. Except for those indemnitees entitled to indemnification under Sections 6.1 and 6.2, the Corporation may, to the extent authorized from time to time by the Board of Directors, grant rights to indemnification and to the advancement of expenses to any employee or agent of the Corporation to the fullest extent of the provisions of this Article VI with respect to the indemnification and

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advancement of expenses of Directors and officers of the Corporation. The Board of Directors may grant rights to the advancement of expenses upon such terms and conditions as the Board of Directors deems appropriate, including but not limited to receipt of an undertaking by or on behalf of the employee or agent of the Corporation to repay such amount if it shall ultimately be determined that such person is not entitled to be indemnified by the Corporation as authorized in this Article VI.

     Section 6.8. Nonexclusivity of Indemnification and Advancement of Expenses. The indemnification and advancement of expenses provided by or granted pursuant to this Article VI shall not be deemed exclusive of any other rights to which those seeking indemnification or advancement of expenses may be entitled under any By-law, agreement, contract, vote of stockholders or disinterested Directors or otherwise, both as to action in such person’s official capacity and as to action in another capacity while holding such office, it being the policy of the Corporation that indemnification of the persons specified in Sections 6.1 and 6.2 of this Article VI shall be made to the fullest extent permitted by law. The provisions of this Article VI shall not be deemed to preclude the indemnification of any person who is not specified in Sections 6.1 and 6.2 of this Article VI but whom the Corporation has the power or obligation to indemnify under the provisions of the General Corporation Law of the State of Delaware, or otherwise.

     Section 6.9. Insurance. The Corporation may purchase and maintain insurance on behalf of any person who is or was a Director, officer, employee or agent of the Corporation, or is or was serving at the request of the Corporation as a director, officer, employee or agent of another Corporation, partnership, joint venture, trust or other enterprise against any liability asserted against such person and incurred by such person in any such capacity, or arising out of such person’s status as such, whether or not the Corporation would have the power or the obligation to indemnify such person against such liability under the provisions of this Article VI.

     Section 6.10. Meaning of “Corporation” and “Other Enterprises” for the Purposes of Article VI. For purposes of this Article VI, references to “the Corporation” shall include, in addition to the resulting Corporation, any constituent Corporation (including any constituent of a constituent) absorbed in a consolidation or merger which, if its separate existence had continued, would have had power and authority to indemnify its Directors, officers, employees or agents so that any person who is or was a director, officer, employee or agent of such constituent Corporation, or is or was serving at the request of such constituent Corporation as a director, officer, employee or agent of another Corporation, partnership, joint venture, trust or other enterprise, shall stand in the same position under the provisions of this Article VI with respect to the resulting or surviving Corporation as such person would have with respect to such constituent Corporation if its separate existence had continued.

     For purposes of this Article VI, references to “other enterprises” shall include employee benefit plans; references to “fines” shall include any excise taxes assessed on a person with respect to an employee benefit plan; and references to “serving at the request of the Corporation” shall include any service as a Director, officer, employee or agent of the Corporation which imposes duties on, or involves services by, such Director, officer, employee or agent with respect to an employee benefit plan, its participants or beneficiaries; and a person who acted in good faith and in a manner such person reasonably believed to be in the interest of the participants and beneficiaries of

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an employee benefit plan shall be deemed to have acted in a manner “not opposed to the best interests of the Corporation” as referred to in this Article VI.

     Section 6.11. Survival of Indemnification and Advancement of Expenses. The indemnification and advancement of expenses provided by, or granted pursuant to, this Article VI shall, unless otherwise provided when authorized or ratified, continue as to a person who has ceased to be a Director, officer, employee or agent and shall inure to the benefit of the heirs, executors and administrators of such person.

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ARTICLE VII

Miscellaneous

     Section 7.1. Fiscal Year. The fiscal year of the Corporation shall end on the thirty-first day of December in each year, or on such other day as may be fixed from time to time by the Board of Directors.

     Section 7.2. Seal. The Corporation may have a corporate seal which shall have inscribed thereon the name of the Corporation, the year of its organization and the words “Corporate Seal, Delaware.” The corporate seal may be used by causing it or a facsimile thereof to be impressed or affixed or in any other manner reproduced.

     Section 7.3. Waiver of Notice of Meetings of Stockholders, Directors and Committees. Whenever notice is required to be given by law or under any provision of the Certificate of Incorporation or these By-laws, a written waiver thereof, signed by the person entitled to notice, whether before or after the time stated therein, shall be deemed equivalent to notice. Attendance of a person at a meeting shall constitute a waiver of notice of such meeting, except when the person attends a meeting for the express purpose of objecting, at the beginning of the meeting, to the transaction of any business because the meeting is not lawfully called or convened. Neither the business to be transacted at, nor the purpose of, any regular or special meeting of the stockholders, directors or committees of directors need be specified in any written waiver of notice unless so required by the Certificate of Incorporation or these By-laws.

     Section 7.4. Interested Directors, Quorum. No contract or transaction between the Corporation and one or more of its Directors or officers, or between the Corporation and any other Corporation, partnership, association or other organization in which one or more of its Directors or officers are directors or officers, or have a financial interest, shall be void or voidable solely for this reason, or solely because the Director or officer is present at or participates in the meeting of the Board of Directors or committee thereof which authorizes the contract or transaction, or solely because his or their votes are counted for such purpose; if: (1) the material facts as to his relationship or interest and as to the contract or transaction are disclosed or are known to the Board or the committee, and the Board or committee in good faith authorizes the contract or transaction by the affirmative votes of a majority of the disinterested Directors, even though the disinterested Directors be less than a quorum; or (2) the material facts as to his relationship or interest and as to the contract or transaction are disclosed or are known to the stockholders entitled to vote thereon, and the contract or transaction is specifically approved in good faith by vote of the stockholders; or (3) the contract or transaction is fair as to the Corporation as of the time it is authorized, approved or ratified, by the Board, a committee thereof or the stockholders. Common or interested Directors may be counted in determining the presence of a quorum at a meeting of the Board or of a committee which authorizes the contract or transaction.

     Section 7.5. Form of Records. Any records maintained by the Corporation in the regular course of its business, including its stock ledger, books of account and minute books, may be

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kept on, or be in the form of, punch cards, magnetic tape, photographs, microphotographs or any other information storage device, provided that the records so kept can be converted into clearly legible form within a reasonable time. The Corporation shall so convert any records so kept upon the request of any person entitled to inspect the same.

     Section 7.6. Amendment of By-laws. These By-laws may be altered or repealed, and new By-laws made, by the affirmative vote of a majority of the entire Board of Directors, but the stockholders may make additional By-laws and may alter or repeal any By-law whether or not adopted by them.

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EX-23

Exhibit (23)

Consent of Independent Registered Public Accounting Firm

We consent to the incorporation by reference in the Registration Statements (Form S-3 No. 333-27311, Form S-3 No. 333-02155, Form S-4 No. 333-101788, Form S-4 No. 333-72982, and Form S-4 No. 333-136849) of Transcontinental Gas Pipe Line Corporation and in the related Prospectuses of our report dated February 25, 2008, with respect to the consolidated financial statements and schedule of Transcontinental Gas Pipe Line Corporation, included in this Annual Report (Form 10-K) for the year ended December 31, 2007.

/s/ ERNST & YOUNG LLP  

Houston, Texas
February 25, 2008

EX-24

TRANSCONTINENTAL GAS PIPE LINE CORPORATION

POWER OF ATTORNEY

     KNOW ALL MEN BY THESE PRESENTS that each of the undersigned individuals, in their capacity as a director or officer, or both, as hereinafter set forth below their signature, of TRANSCONTINENTAL GAS PIPE LINE CORPORATION, a Delaware corporation (“Transco”), does hereby constitute and appoint RICHARD D. RODEKOHR AND JEFFREY P. HEINRICHS their true and lawful attorneys and each of them (with full power to act without the other) their true and lawful attorneys for them and in their name and in their capacity as a director or officer, or both, of Transco, as hereinafter set forth below their signature, to sign Transco’s Annual Report to the Securities and Exchange Commission on Form 10-K for the fiscal year ended December 31, 2007, and any and all amendments thereto or all instruments necessary or incidental in connection therewith; and

     THAT the undersigned Transco does hereby constitute and appoint RICHARD D. RODEKOHR AND JEFFREY P. HEINRICHS its true and lawful attorneys and each of them (with full power to act without the other) its true and lawful attorney for it and in its name and on its behalf to sign said Form 10-K and any and all amendments thereto and any and all instruments necessary or incidental in connection therewith.

     Each of said attorneys shall have full power of substitution and resubstitution, and said attorneys or any of them or any substitute appointed by any of them hereunder shall have full power and authority to do and perform in the name and on behalf of each of the undersigned, in any and all capacities, every act whatsoever requisite or necessary to be done in the premises, as fully to all intents and purposes as each of the undersigned might or could do in person, the undersigned hereby ratifying and approving the acts of said attorneys or any of them or of any such substitute pursuant hereto.

     IN WITNESS WHEREOF, the undersigned have executed this instrument, all as of the 18th day of February, 2008.

/s/ Phillip D. Wright
  Phillip D. Wright
Senior Vice President and Director
(Principal Financial Officer) /s/ Richard D. Rodekohr
  Richard D. Rodekohr
Vice President and Treasurer
(Principal Executive Officer)

/s/ Jeffrey P. Heinrichs
Jeffrey P. Heinrichs
Controller
(Principal Accounting Officer)

/s/ Steven J. Malcolm
  Steven J. Malcolm
Director /s/ Frank J. Ferazzi
  Frank J. Ferazzi
Director

TRANSCONTINENTAL GAS PIPE LINE CORPORATION

By	/s/ Richard D. Rodekohr
	Richard D. Rodekohr
	Vice President and
	Treasurer

ATTEST:

/s/ Brian K. Shore
Brian K. Shore

Secretary

TRANSCONTINENTAL GAS PIPE LINE CORPORATION

          I, the undersigned, Brian K. Shore, Secretary of TRANSCONTINENTAL GAS PIPE LINE CORPORATION, a Delaware company (hereinafter called the “Company”), do hereby certify that pursuant to Section 141(f) of the General Corporation Law of Delaware, the Board of Directors of this Corporation unanimously consented, as of February 18, 2008, to the following:

          RESOLVED that the Chairman of the Board, the Senior Vice President or any Vice President of the Company be, and each of them hereby is, authorized and empowered to execute a Power of Attorney for use in connection with the execution and filing, for and on behalf of the Company, under the Securities Exchange Act of 1934, of the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2007.

          I further certify that the foregoing resolution has not been modified, revoked or rescinded and is in full force and effect.

          IN WITNESS WHEREOF, I have hereunto set my hand and affixed the corporate seal of TRANSCONTINENTAL GAS PIPE LINE CORPORATION this 18th day of February, 2008.

/s/ Brian K. Shore

Brian K. Shore

Secretary

[CORPORATE SEAL]

EX-31.1

Exhibit (31)-1

SECTION 302 CERTIFICATION

I, Phillip D. Wright, certify that:

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

a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b)	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 period covered by the report that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer 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: February 27, 2008

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

a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b)	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 period covered by the report that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer 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: February 27, 2008

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 Annual Report of Transcontinental Gas Pipe Line Corporation (the “Company”) on Form 10-K for the period ending December 31, 2007 as filed with the Securities and Exchange Commission on the date hereof (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

February 27, 2008

/s/ Richard D. Rodekohr

Richard D. Rodekohr
Vice President and Treasurer

February 27, 2008

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.