e10vk

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)

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)

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)

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, 2006


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		(I.R.S. Employer
incorporation or organization)		Identification No.)


2800 Post Oak Blvd., P. O. Box 1396, Houston, Texas (Address of principal executive offices)		77251 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, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act.

Large accelerated filer o Accelerated filer o Non-accelerated filer þ

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, 2007 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.

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). For 2006 Williams is a reporting entity under the Sarbanes-Oxley Act of 2002. Transco is not an accelerated filer and therefore not required in 2006 to report under Section 404 of the Sarbanes-Oxley Act of 2002.

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, 2006, we had 1,272 full time employees.

At December 31, 2006, 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 3.5 MMdt of gas per day for a system-wide delivery capacity total of approximately 8.2 MMdt of gas per day. The system is comprised of approximately 10,500 miles of mainline and branch transmission pipelines, 44 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 a 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, a 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


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.

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 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 Power Company (WPC), manages our jurisdictional merchant gas sales.

Over the past several years, we filed applications with the FERC seeking authorization to abandon certain facilities located onshore and offshore in Texas, Louisiana and Mississippi by conveyance to an affiliate, Williams Gas Processing — Gulf Coast Company. The net book value of these facilities at December 31, 2006, was approximately $277 million. Because of the various challenges to our applications and numerous outstanding regulatory issues affecting the transfer of these facilities, to date we have transferred only a small offshore system with a net book value of $3.3 million, and we have no immediate plans to transfer the remaining facilities.

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 2006 were Public Service Enterprise Group, and Keyspan Corporation, which accounted for approximately 10.2% and 7.1%, 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 2006, 2005 and 2004 are shown below.


Transco System Deliveries (TBtu)	2006		2005		2004
Market-area deliveries
Long-haul transportation		795.1		754.9		781.6
Market-area transportation		816.5		852.5		817.1

Total market-area deliveries		1,611.6		1,607.4		1,598.7
Production-area transportation		247.2		278.4		317.7

Total system deliveries		1,858.8		1,885.8		1,916.4


Average Daily Transportation Volumes (TBtu)		5.1		5.2		5.2
Average Daily Firm Reserved Capacity (TBtu)		6.6		6.6		6.6

Our total market-area deliveries for 2006 increased 4.2 TBtu (0.3%) when compared to 2005. Our production area deliveries decreased 31.2 TBtu (11.2%) when compared to 2005. The reduction is primarily due to decreased requests for deliveries to production-area interconnects.

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.

PIPELINE PROJECTS

Leidy to Long Island Expansion Project The Leidy to Long Island Expansion Project will involve an expansion of our existing natural gas transmission system in Zone 6 from the Leidy Hub in Pennsylvania to Long Island, New York. The project will provide 100,000 dekatherms per day (dt/d) of incremental firm transportation capacity, which has been fully subscribed by one shipper for a twenty-year primary term. The project facilities will include pipeline looping in Pennsylvania, pipeline looping, pipeline replacement and a natural gas compressor facility in New Jersey and appurtenant facilities in New York. We expect that over three-quarters of the project expenditures will occur in 2007. We filed an application for FERC authorization of the project in December 2005, which the FERC approved by order issued on May 18, 2006. On October 20, 2006, we filed an application to amend the FERC authorizations to reflect our ownership of certain appurtenant facilities as part of the project and to adjust the cost of facilities and rates, which the FERC approved by order issued on January 11, 2007. The estimated capital cost of the project is approximately $141 million. The target in-service date for the project is November 1, 2007.

Potomac Expansion Project The Potomac Expansion Project will involve 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 project will provide 165,000 dt/d of incremental firm transportation capacity, which has been fully subscribed by shippers under long-term firm arrangements. The estimated capital cost of the project is approximately $74 million. We filed an application for FERC approval of the project on July 17, 2006. The target in-service date for the project is November 1, 2007.

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 project will provide 142,000 dt/d of incremental firm transportation capacity, which has been fully subscribed by the shippers under long-term firm arrangements. The project facilities will include pipeline looping in Pennsylvania and New Jersey and minor compressor station modifications. The estimated capital cost of the project excluding any customer meter station upgrades is approximately $140 million. In order to accommodate certain shippers, we are planning to place the incremental firm transportation capacity into service in two phases, the first phase commencing on November 1, 2008 for 67,000 dt/d of service and the second phase commencing on November 1, 2009 for an additional 75,000 dt/d of service. The FERC has granted our request for a pre-application environmental review of the project, soliciting early input from citizens, governmental entities and other interested parties. We expect to file a formal application with the FERC in the second quarter of 2007.

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 rates became effective on September 1, 2001. Certain cost allocation, rate design and tariff matters in this proceeding have not yet been finally 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 (including the facilities addressed in the FERC’s various spin-down orders). On September 29, 2006, the FERC issued an order accepting and suspending our August 31, 2006 general rate filing to be effective March 1, 2007, subject to refund and the outcome of a hearing.

SALES SERVICE

As discussed above, WPC 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, WPC is still authorized to make gas sales on our behalf in order to manage our remaining gas purchase obligations. WPC 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 WPC for the years 2006, 2005 and 2004 are shown below.


Gas Sales Volumes (TBtu)	2006		2005		2004
Long-term sales		—		7.8		30.3
Short-term sales		3.6		6.7		13.8

Total gas sales		3.6		14.5		44.1

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, 2. Rate and Regulatory Matters, 3. Contingent Liabilities and Commitments 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, 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 tremendous change since the issuance of FERC Order 636 in 1992. Order 636 required that the natural gas sales, transportation, and other services that were formerly

provided in bundled form by pipelines be separated, resulting in non-discriminatory open access transportation services, and encouraged the establishment of market hubs. These and other factors have led to a commodity market in natural gas and to increasingly competitive markets in natural gas services, including competitive secondary markets in pipeline capacity. As a result, pipeline capacity is being used more efficiently, and peaking and storage services are increasingly effective substitutes for annual pipeline capacity. These factors have increased the risk for pipelines that customers will turn back or substantially reduce their contractual commitments. Future utilization of pipeline capacity will depend on competition from other pipeline and LNG facilities, use of alternative fuels, the general level of natural gas demand, and weather conditions.

At the state level, both local distribution company (LDC) and electric industry restructuring have affected pipeline markets. Several states have implemented changes similar to the federal changes under Order 636. New York, New Jersey, Pennsylvania, Maryland, Delaware, Georgia, Virginia and the District of Columbia have established regulations for LDC unbundling. 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, thus far, required renegotiation of` LDC contracts. The state plans have in some cases discouraged LDCs from signing long-term contracts for new capacity.

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;

	•		rate case filing; and

	•		power and 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;

	•		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, 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 our lack of investment grade credit ratings; and

	•		risk 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 report. Such changes in our intentions may also cause our results to differ. We may change our intentions, at any time and without notice, based upon changes in such factors, our assumptions, or otherwise.

Because forward-looking statements involve risks and uncertainties, we caution that there are important factors, in addition to those listed above, that may cause actual results to differ materially from those contained in the forward-looking statements. 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.

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:

	•		blowouts, cratering and explosions;

	•		uncontrollable flows of natural gas;

	•		fires;

	•		pollution and other environmental risks;

	•		natural disasters;

	•		aging pipeline infrastructure; and

	•		terrorists 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. 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 and results of operations, 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 assurance can be given that the costs of complying with environmental laws in the future will not have such an effect.

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.

Our lack of investment grade credit ratings increases our costs of doing business in many ways and increases our risks from market disruptions and further credit downgrades.

Because we do not have an investment grade credit rating from all of the major credit rating agencies,

our transactions require greater credit assurances, both to be given from and received by us, to satisfy credit support requirements. In addition, we are more vulnerable to the impact of market disruptions or a further downgrade of our credit rating that might further increase our cost of borrowing or further impair our ability to access capital markets. Such disruptions could include:

	•		economic downturns;

	•		deteriorating capital market conditions generally;

	•		declining market prices for electricity and natural gas; 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. Our goal is to attain investment grade ratios from all of the major credit rating agencies. However, there is no guarantee that the credit rating agencies will 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.

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 the profitability of these operations.

Our interstate gas sales, transmission, 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.

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. The outcome of the rate case is 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.

Accounting irregularities discovered in the past few years across various industries have forced regulators and legislators to take a renewed look at accounting practices, financial disclosures, companies’ relationships with their independent registered public accounting firm and retirement plan practices. 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 the outsourcing relationship 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.

Williams’ ability to receive services from outsourcing provider locations outside of the United States might be impacted by cultural differences, political instability, or unanticipated regulatory requirements in jurisdictions outside the United States.

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.

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

Limited capital spending for information technology infrastructure during 2001-2003 resulted in an aging server environment that may be less efficient and may require more personnel and capital resources to maintain and upgrade than more current systems, and may not be adequate for our current business needs. While efforts are ongoing to update the environment, the current age and condition of equipment could result in loss of internal and external communications, loss of data, inability to access data when needed, excessive software downtime (including downtime for critical software applications), and other disruptions that could have a material adverse impact on our business and results of operations.

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.

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 $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.

Our Board of Directors declared cash dividends on common stock in the amounts of $20 million on March 31, 2005, $25 million on June 30, 2005, $35 million on September 30, 2005 and $45 million on December 30, 2005.

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.

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

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, 2006, we had accrued approximately $2 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 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.

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 benefits plan expense and obligations are calculated by a third-party actuary and 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 2006, we expensed approximately $8 million that previously would have been capitalized.

RESULTS OF OPERATIONS

2006 COMPARED TO 2005

Operating Income and Net Income Our operating income for 2006 was $250.0 million compared to operating income of $342.1 million for 2005. Net income for 2006 was $117.3 million compared to net income of $185.3 million for 2005.

The lower operating income of $92.1 million was primarily the result of increases in cost of natural gas transportation, operation and maintenance expenses, administrative and general expenses, depreciation and amortization expenses and taxes other than income taxes, partially offset by a decrease in other expenses as discussed below. The decrease in net income of $68.0 million was mostly attributable to the decreased operating income, partially offset by lower net expenses as discussed below in Other Income and Other Deductions.

Transportation Revenues Our operating revenues related to transportation services increased $3.9 million to $771.9 million for 2006 when compared to 2005. The higher transportation revenues were primarily due to an increase of $9.3 million for the portion of a change in the effective state income tax rate which is recoverable from customers. The recoverable portion is more than offset by a $15.9 million net increase in tax expense included in Provision for Income Taxes. This increase in transportation revenues is partially offset by a $4.0 million decrease of reimbursable costs that are offset in operating expenses and recovered in our rates.

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, WPC 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 WPC 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 WPC. WPC 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 decreased $146.0 million to $142.3 million for 2006 when compared to 2005. The decrease was primarily due to a lower volume of merchant sales because of the termination of the FS agreements during 2005. There were also lower cash out sales volumes related to the monthly settlement of imbalances.

Storage Revenues Our operating revenues related to storage services of $119.8 million for 2006 were comparable to revenues of $122.1 million for 2005.

Other Revenues Our other operating revenues increased $6.5 million to $14.5 million for 2006, when compared to 2005, primarily due to an increase in environmental mitigation credit sales.

Operating Costs and Expenses Excluding the cost of natural gas sales of $142.2 million for 2006 and $288.3 million for 2005, our operating expenses were approximately $100.0 million higher than the comparable period in 2005. This increase was primarily attributable to higher cost of natural gas transportation, operation and maintenance expenses, administrative and general expenses, depreciation and amortization expense and taxes other than income taxes, partially offset by lower other expenses. The higher cost of natural gas transportation of $17.2 million is primarily due to the absence of a 2005 positive adjustment of $14.2 million associated with the resolution of our 1999 Fuel Tracker filing. Additionally, there was a $3.5 million decrease in 2006 of reimbursable costs that are recovered in our rates. The increase in operation and maintenance expense of $32.0 million is due primarily to higher outside services of $7.3 million and higher material and supplies expenses of $5.1 million due primarily to integrity management assessment costs, and higher contract labor and services of $10.8 million. The 2005 hurricanes in the Gulf of Mexico caused a shortage of contractors resulting in a large premium for offshore services. The increase in administrative and general expense of $44.9 million is mostly due to higher employee labor and benefits costs of $16.3 million, increased information systems costs of $10.9 million and higher property insurance of $12.8 million due to increased premiums on offshore facilities. The increase in depreciation and amortization of $10.1 million was primarily due to higher expense associated with asset retirement obligations. The increase in taxes other than income taxes of $7.5 million is due to higher property taxes resulting from increased property values and additional capital spending and increased franchise taxes resulting from settlements of prior years state audits. The lower other operating costs and expenses of $11.7 million were primarily due to a

regulatory credit associated with asset retirement obligation depreciation expense of $7.8 million and a $2.0 million reduction of accrued liabilities for royalty claims associated with certain producer indemnities. See “Item 1. Financial Statements – Notes to Consolidated Financial Statements – 3. Contingent Liabilities and Commitments.”

Other Income and Other Deductions Other income and other deductions resulted in $1.9 million lower net expense in 2006 compared to 2005. A $5.0 million decrease in interest expense resulted from the reduction of accrued liabilities for royalty claims associated with certain producer indemnities. (See “Item 1. Financial Statements – Notes to Consolidated Financial Statements – 3. Contingent Liabilities and Commitments.”) The increase in interest income – affiliates of $4.1 million was mostly due to an increase in intercompany demand notes resulting from a lower amount of dividends paid to WGP in 2006 compared to 2005. These amounts were offset by increased interest expense primarily associated with the issuance of the 6.4 % notes.

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. 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, 2006, $200 million of availability remained under this registration statement. While our credit ratings from certain credit rating agencies remain below investment grade, the shelf registration may only be utilized to issue debt securities if such securities are guaranteed by Williams. However, we can raise capital through private debt offerings as well as offerings registered pursuant to offering-specific registration statements, without a guaranty from Williams. 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 on terms that are commensurate with our current credit ratings.

subsidiary debt and sale-leaseback transactions. The facility is guaranteed by WGP, and Williams guarantees obligations of Williams Partners L.P. for up to $75 million. We have access to $400 million under the 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 LIBOR plus an applicable margin. Williams is required to pay a commitment fee (currently 0.25 % annually) based on the unused portion of the facility. The margins and commitment fee are based on the specific borrower’s senior unsecured long-term debt ratings. Letters of credit totaling approximately $29 million, none of which are associated with us, have been issued by the participating institutions and no revolving credit loans were outstanding at December 31, 2006. Transco did not access this facility during 2006. Significant financial covenants under the credit agreement include the following:

	•		Williams’ ratio of debt to capitalization must be no greater than 65 percent.

	•		Our ratio of debt to capitalization must be no greater than 55 percent. At December 31, 2006, we are in compliance with this covenant as our ratio of debt to capitalization, as calculated under this covenant is approximately 32 percent.

	•		Williams’ ratio of EBITDA to interest, on a rolling four quarter basis, must be no less than 2.5 for the period ending December 31, 2007 and 3.0 for the remaining term of the agreement.

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 are being 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.

As a participant in Williams’ cash management program, we have advances to and from Williams. At December 31, 2006, the advances due to us by Williams totaled $190.4 million. The advances are represented by demand notes. The interest rate on intercompany demand notes is based upon the weighted average cost of Williams’ debt outstanding at the end of each quarter. At December 31, 2006, the interest rate was 7.81%.

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 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, 2006 and 2005, our cumulative equity interest in an unrealized loss on Pine Needle’s hedge was $0.2 million and $0.4 million, respectively. The swap agreement initially had a notional amount of $53.5 million of debt, of which $37.5 million was still outstanding at December 31, 2006. 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 2006, the rating agencies raised the credit ratings on our senior unsecured long-term debt as shown below. While the Moody’s Investor Services and Standard & Poor’s credit ratings remain below investment grade, the rise in the Fitch Ratings credit rating moves us to investment grade.


Moody’s Investors Services		Ba2 to Ba1
Standard & Poor’s		B+ to BB-
Fitch Ratings		BB+ to BBB-

Currently, the Standard and Poor’s evaluation of our credit rating is “positive outlook” and the Fitch and Moody’s Investors Services evaluations of our credit rating are “stable outlook.”

CAPITAL EXPENDITURES

As shown in the table below, our capital expenditures for 2006 included $29 million for expansion projects, primarily for Leidy to Long Island, Sentinel and Potomac and $301 million for maintenance of existing facilities and other projects including expenditures required under the Federal Clean Air Act and Clean Air Act Amendments of 1990 and the Pipeline Safety Improvement Act of 2002. We are estimating approximately $310 million to $390 million of capital expenditures in the year 2007 related to the maintenance of existing facilities, including pipeline safety expenditures, and expansion projects, primarily the Leidy to Long Island and Potomac projects.


Capital Expenditures	2006		2005		2004
			(In millions)
Expansion Projects	$	29.4	$	22.0	$	10.1
Maintenance of Existing Facilities and Other Projects		300.5		222.9		143.5


Total Capital Expenditures	$	329.9	$	244.9	$	153.6

OTHER CAPITAL REQUIREMENTS, CONTRACTUAL OBLIGATIONS AND CONTINGENCIES

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


				2008-		2010-		There-
	2007			2009		2011		after		Total
Long-term debt, including current portion:
Principal	$	—		$	175	$	300	$	733	$	1,208

Interest		89			161		155		312		717

Capital leases		—			—		—		—		—

Operating leases		6			12		13		15		46
Purchase obligations:
Natural gas purchase, storage and transportation		99			151		88		76		414

Other		139	⁽¹⁾		7		5		2		153

Other long-term liabilities, including current portion:
FERC penalty		4			—		—		—		4


Total	$	337		$	506	$	561	$	1,138	$	2,542


(1)		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 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, 2006. The tables present principal cash flows and weighted-average interest rates by expected maturity dates.


December 31, 2006	Expected Maturity Date
	2007			2008			2009			2010
	(Dollars in millions)
Long-term debt:
Fixed rate	$	—		$	100		$	—		$	—
Interest rate		7.23	%		7.45	%		7.53	%		7.53	%
Variable rate	$	—		$	75		$	—		$	—
Interest rate (5.43% to 6.79% for 2006)


December 31, 2006	Expected Maturity Date
	2011			Thereafter			Total		Fair Value
	(Dollars in millions)
Long-term debt:
Fixed rate	$	300		$	733		$	1,133	$	1,195
Interest rate		7.60	%		7.14	%
Variable rate	$	—		$	—		$	75	$	75
Interest rate (5.43% to 6.79% for 2006)

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, 2006 and 2005, 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, 2006. 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 audit 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, 2006 and 2005, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2006, 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.

As discussed in Note 5 to the financial statements, in 2006 the Company adopted Statement of Financial Accounting Standards No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans -An Amendment of FASB Statements No. 87, 88, 106, and 132(R), and Statement of Financial Accounting Standards No. 123(R), Share-Based Payment – a revision of FASB Statement No. 123, Accounting for Stock-Based Compensation. As discussed in Note 1 to the financial statements, in 2006 the Company adopted the Federal Energy Regulatory Commission order on Accounting for Pipeline Assessment Costs.

ERNST & YOUNG LLP

Houston, Texas
February 27, 2007

TRANSCONTINENTAL GAS PIPE LINE CORPORATION

CONSOLIDATED STATEMENT OF INCOME

(Thousands of Dollars)


	Years Ended December 31,
	2006			2005			2004
Operating Revenues:
Natural gas sales	$	142,252		$	288,294		$	403,181
Natural gas transportation		771,855			767,919			784,605
Natural gas storage		119,750			122,117			122,951
Other		14,534			8,083			9,079

Total operating revenues		1,048,391			1,186,413			1,319,816


Operating Costs and Expenses:
Cost of natural gas sales		142,248			288,256			401,632
Cost of natural gas transportation		11,414			(5,815	)		20,883
Operation and maintenance		232,002			200,030			191,200
Administrative and general		165,367			120,471			118,719
Depreciation and amortization		205,860			195,744			196,021
Taxes – other than income taxes		51,146			43,669			42,077
Other (income) expense, net		(9,679	)		1,973			3,182

Total operating costs and expenses		798,358			844,328			973,714


Operating Income		250,033			342,085			346,102


Other (Income) and Other Deductions:
Interest expense — affiliates		942			—			—
— other		85,064			79,661			88,742
Interest income — affiliates		(14,310	)		(10,172	)		(12,555	)
— other		(762	)		(851	)		(1,192	)
Allowance for equity and borrowed funds used during construction (AFUDC)		(11,148	)		(9,270	)		(8,327	)
Equity in earnings of unconsolidated affiliates		(7,498	)		(7,185	)		(7,073	)
Miscellaneous other (income) deductions, net		(7,382	)		(5,352	)		(4,868	)

Total other (income) and other deductions		44,906			46,831			54,727


Income before Income Taxes		205,127			295,254			291,375
Provision for Income Taxes		87,876			109,939			111,921


Net Income	$	117,251		$	185,315		$	179,454

See accompanying notes.

TRANSCONTINENTAL GAS PIPE LINE CORPORATION

CONSOLIDATED BALANCE SHEET

(Thousands of Dollars)


	December 31,
	2006		2005
ASSETS

Current Assets:
Cash	$	315	$	362
Receivables:
Trade less allowance of $503 ($509 in 2005)		73,378		87,348
Affiliates		7,814		4,374
Advances to affiliates		190,399		130,307
Other		11,067		6,479
Transportation and exchange gas receivables		7,075		9,906
Inventories:
Gas in storage, at LIFO		26,172		25,289
Gas available for customer nomination, at average cost		10,901		29,617
Materials and supplies, at lower of average cost or market		27,748		27,774
Deferred income taxes		17,414		15,283
Other		28,557		17,825

Total current assets		400,840		354,564


Investments, at cost plus equity in undistributed earnings		44,820		44,108


Property, Plant and Equipment:
Natural gas transmission plant		6,475,172		6,134,951
Less – Accumulated depreciation and amortization		1,939,430		1,776,946

Total property, plant and equipment, net		4,535,742		4,358,005


Other Assets		300,587		251,969


	$	5,281,989	$	5,008,646

See accompanying notes.

TRANSCONTINENTAL GAS PIPE LINE CORPORATION

CONSOLIDATED BALANCE SHEET
(Thousands of Dollars)


	December 31,
	2006			2005
LIABILITIES AND STOCKHOLDER’S EQUITY

Current Liabilities:
Payables:
Trade	$	83,517		$	52,415
Affiliates		23,007			27,812
Cash Overdrafts		29,901			28,461
Transportation and exchange gas payables		14,693			49,657
Accrued liabilities:
Federal income taxes payable to affiliate		—			18,425
State income taxes		—			4,356
Other taxes		15,038			15,365
Interest		29,338			26,428
Deferred cash out		15,823			39,842
Employee benefits		32,494			42,459
Other		17,137			20,080
Reserve for rate refunds		2,232			3,763
Current maturities of long-term debt		—			—

Total current liabilities		263,180			329,063


Long-Term Debt		1,201,458			1,000,623


Other Long-Term Liabilities:
Deferred income taxes		1,013,282			955,503
Asset retirement obligations		136,171			53,596
Other		129,462			115,239

Total other long-term liabilities		1,278,915			1,124,338


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		914,851			902,600
Accumulated other comprehensive loss		(28,845	)		(408	)

Total common stockholder’s equity		2,538,436			2,554,622


	$	5,281,989		$	5,008,646

See accompanying notes.

TRANSCONTINENTAL GAS PIPE LINE CORPORATION

CONSOLIDATED STATEMENT OF COMMON STOCKHOLDER’S EQUITY

(Thousands of Dollars)


	Years Ended December 31,
	2006			2005			2004
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		902,600			842,285			787,831
Add (deduct):
Net income		117,251			185,315			179,454
Cash dividends on common stock		(105,000	)		(125,000	)		(125,000	)


Balance at end of period		914,851			902,600			842,285


Accumulated Other Comprehensive Income/(Loss):
Interest Rate Hedge:
Balance at beginning of period		(408	)		(920	)		(1,144	)
Add (deduct):
Net gain/(loss)		159			512			224

Balance at end of period		(249	)		(408	)		(920	)

Pension Benefit Obligation:
Balance at beginning of period		—			—			—
Add (deduct):
Adjustment to initially apply SFAS No. 158, net of tax		(28,596	)		—			—

Balance at end of period		(28,596	)		—			—

Balance at end of period		(28,845	)		(408	)		(920	)

Total Common Stockholder’s Equity	$	2,538,436		$	2,554,622		$	2,493,795

See accompanying notes.

TRANSCONTINENTAL GAS PIPE LINE CORPORATION

CONSOLIDATED STATEMENT OF CASH FLOWS

(Thousands of Dollars)


	Years Ended December 31,
	2006			2005			2004
Cash flows from operating activities:
Net income	$	117,251		$	185,315		$	179,454
Adjustments to reconcile net income to net cash Provided by operating activities:
Depreciation and amortization		204,508			198,361			198,247
Deferred income taxes		73,259			(916	)		31,814
Allowance for equity funds used during construction (Equity AFUDC)		(8,355	)		(6,455	)		(6,091	)
Changes in operating assets and liabilities:
Receivables — affiliates		(3,440	)		(2,427	)		7,413
— other		6,392			17,193			22,794
Transportation and exchange gas receivable		2,831			(4,096	)		16,946
Inventories		17,859			(5,108	)		4,151
Payables — affiliates		(4,805	)		(10,839	)		(23,757	)
— other		21,443			(6,105	)		(26,022	)
Transportation and exchange gas payable		(34,964	)		25,037			7,285
Accrued liabilities		(41,414	)		22,793			34,264
Reserve for rate refunds		(1,531	)		(5,156	)		(1,691	)
Other, net		(45,722	)		(18,854	)		14,954

Net cash provided by operating activities		303,312			388,743			459,761


Cash flows from financing activities:
Additions to long-term debt		200,000			—			75,000
Retirement of long-term debt		—			(200,000	)		—
Debt issue costs		(3,202	)		(255	)		(356	)
Common stock dividends paid		(105,000	)		(125,000	)		(125,000	)
Change in cash overdrafts		1,440			7,869			(1,341	)

Net cash provided by (used in) financing activities		93,238			(317,386	)		(51,697	)

(continued)

TRANSCONTINENTAL GAS PIPE LINE CORPORATION

CONSOLIDATED STATEMENT OF CASH FLOWS
(Thousands of Dollars)


	Years Ended December 31,
	2006			2005			2004
Cash flows from investing activities:
Property, plant and equipment:
Additions, net of equity AFUDC		(339,522	)		(256,362	)		(150,434	)
Changes in accounts payable		9,659			11,497			(3,156	)
Advances to affiliates, net		(60,092	)		172,458			(252,818	)
Advances to others, net		981			(428	)		(2,313	)
Other, net		(7,623	)		1,664			533

Net cash used in investing activities		(396,597	)		(71,171	)		(408,188	)


Net increase (decrease) in cash		(47	)		186			(124	)
Cash at beginning of period		362			176			300

Cash at end of period	$	315		$	362		$	176


Supplemental disclosures of cash flow information:
Cash paid during the year for:
Interest (exclusive of amount capitalized)	$	81,063		$	77,297		$	83,334
Income taxes paid		39,913			123,797			51,346
Income tax refunds received		—			(122	)		(46	)

See accompanying notes.

TRANSCONTINENTAL GAS PIPE LINE CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


1. Summary of Significant Accounting Policies			36
2. Rate And Regulatory Matters			41
3. Contingent Liabilities and Commitments			42
4. Debt, Financing Arrangements and Leases			46
5. Employee Benefit Plans			48
6. Income Taxes			52
7. Financial Instruments and Guarantees			53
8. Transactions with Major Customers and Affiliates			54
9. Asset Retirement Obligations			55
10. Regulatory Assets and Liabilities			56
11. Quarterly Information (Unaudited)			57

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).

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

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, 2006, the remaining property, plant and equipment allocation was approximately $1 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, 2006, the interest rate was 7.81%.

Through an agency agreement, Williams Power Company (WPC), 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 cash dividends on common stock in the amounts of $105 million, $125 million and $125 million for 2006, 2005 and 2004, 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, 2006 and 2005 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 $7.0 million, $7.5 million and $7.5 million in 2006, 2005 and 2004, 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.

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.

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, 2006, 2005, and 2004 are as follows:


Category of Property	Depreciation Rates
Gathering facilities		0%-3.80	%
Storage facilities		2.50	%
Onshore transmission facilities		2.35	%
Offshore transmission facilities		0.85%-1.50	%

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.

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 at December 31, 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 during construction was $2.8 million, $2.8 million and $2.2 million, for 2006, 2005 and 2004, respectively. The allowance for equity funds was $ 8.3 million, $6.5 million, and $6.1 million, for 2006, 2005 and 2004, 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 liability method of 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 December 31, 2006 and 2005, we had recorded reserves of $0.5 million and $0.5 million, respectively, 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. 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, 2006 and 2005. 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.

Gas inventory We utilize the last-in, first-out (LIFO) method of accounting for inventory gas in storage. The excess of current cost over the LIFO value on the Consolidated Balance Sheet dated December 31, 2006 is approximately $22.1 million. The basis for determining current cost is the December 2006 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.

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, 2006 and $0.7 million at December 31, 2005.

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 June 2006, the Financial Accounting Standards Board (FASB) issued FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes, an interpretation of FASB Statement No. 109” (FIN 48). The Interpretation clarifies the accounting for uncertainty in income taxes under FASB Statement No. 109, “Accounting for Income Taxes.” 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. To recognize a tax position, the enterprise determines whether it is more likely than not that the tax position will be sustained upon examination, including resolution of any related appeals or litigation processes, based on the technical merits of the position. A tax position that meets the more likely than not recognition threshold is measured to determine the amount of benefit to recognize in the financial statements. The tax position is measured at the largest amount of benefit, determined on a cumulative basis, that is greater than 50 percent likely of being realized upon ultimate settlement.

FIN 48 is effective for fiscal years beginning after December 15, 2006. The cumulative effect of applying the Interpretation must be reported as an adjustment to the opening balance of retained earnings in the year of adoption. We adopted the Interpretation beginning January 1, 2007, as required. We expect no material impact of the cumulative effect of adopting FIN 48 on our Consolidated Financial Statements.

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 pipeline integrity-related assessment costs that we have historically capitalized. During 2006, the application of this order resulted in $8 million of such costs being expensed. We anticipate expensing approximately $5 million to $10 million in 2007 that previously would have been capitalized.

Reclassification Certain reclassifications have been made in the 2005 balance sheet to conform to the 2006 presentation.

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 rates became effective on September 1, 2001. 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.

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 (including the facilities addressed in the FERC’s various spin-down orders discussed below). On September 29, 2006, the FERC issued an order accepting and suspending our August 31, 2006 general rate filing to be effective March 1, 2007, subject to refund and the outcome of a hearing.

Over the past several years, we filed applications with the FERC seeking authorization to abandon certain facilities located onshore and offshore in Texas, Louisiana and Mississippi by conveyance to an affiliate, Williams Gas Processing — Gulf Coast Company. The net book value of these facilities at December 31, 2006, was approximately $277 million. Because of the various challenges to our applications and outstanding regulatory issues affecting the transfer of these facilities, to date we have transferred only a small offshore system with a net book value of $3.3 million, and we have no immediate plans to transfer the remaining facilities. Therefore, these facilities are not considered assets held for sale.

3. CONTINGENT LIABILITIES AND COMMITMENTS

Legal Proceedings.

By order dated March 17, 2003, the FERC approved a settlement between the FERC staff and Williams, WPC and us which resolved certain FERC staff’s allegations. As part of the settlement, WPC agreed, subject to certain exceptions, that it will not enter into new transportation agreements that would increase the transportation capacity it holds on certain affiliated interstate gas pipelines, including Transco. We also agreed to pay a civil penalty in five equal installments totaling $20 million, and the final $4 million installment will be paid in 2007.

A producer had asserted a claim for damages against us for indemnification relating to prior royalty payments. The Louisiana Court of Appeals denied the producer’s appeal and affirmed a lower court’s judgment in our favor. On March 31, 2006, the Louisiana Supreme Court denied the producer’s request for further review. Consequently, we reversed in the first quarter of 2006 a related liability which resulted in an increase to pre-tax income of approximately $7.0 million.

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 certain of the Williams defendants, including us. 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.

We were named as a defendant in two class action petitions for damages filed in the United States District Court for the Eastern District of Louisiana in September and October 2005 arising from hurricanes that struck Louisiana in 2005. The class plaintiffs, purporting to represent persons, businesses and entities in the State of Louisiana who suffered damage as a result of the winds and storm surge from the hurricanes, alleged that the operating activities of the two sub-classes of defendants, which included all oil and gas pipelines that dredged pipeline canals or installed pipelines in the marshes of south Louisiana (including us) and all oil and gas exploration and production companies which drilled for oil and gas or dredged canals in the marshes of south Louisiana, altered marshland ecology and caused marshland destruction which otherwise would have averted all or almost all of the destruction and loss of life caused by the hurricanes. Plaintiffs requested that the court allow the lawsuits to proceed as class actions and sought legal and equitable relief in an unspecified amount. On September 28, 2006, the court granted the defendants’ joint motion and dismissed the class action petitions against all defendants, including Transco. On November 20, 2006, in an additional class action filed in August 2006 containing substantially identical allegations against the same defendants, including Transco, the court similarly granted the defendants’ joint motion and dismissed the additional class action.

Environmental Matters

We are subject to extensive federal, state and local environmental laws and regulations which affect our operations related to the construction and operation of pipeline facilities. Appropriate governmental authorities enforce these laws and regulations with a variety of civil and criminal enforcement measures, including monetary penalties, assessment and remediation requirements and injunctions as to future compliance. Our use and disposal of hazardous materials are subject to the requirements of the federal Toxic Substances Control Act (TSCA), the federal Resource Conservation and Recovery Act (RCRA) and comparable state statutes. The Comprehensive Environmental Response, Compensation and Liability Act (CERCLA), also known as “Superfund,” imposes liability, without regard to fault or the legality of the original act, for release of a “hazardous substance” into the environment. Because these laws and regulations change from time to time, practices that have been acceptable to the industry and to the regulators have to be changed and assessment and monitoring have to be undertaken to determine whether those practices have damaged the environment and whether remediation is required. 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 TSCA, RCRA, CERCLA and comparable state statutes will total approximately $11 million to $13 million, measured on an undiscounted basis, and will be spent over the next three to five 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, 2006, we had a balance of approximately $5.7 million for the expense portion of these estimated costs recorded in current liabilities ($1.2 million) and other long-term liabilities ($4.5 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 have also been recorded as regulatory assets in Current Assets: Other and Other Assets in the accompanying Consolidated Balance Sheet.

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 programs concerning investigative and remedial actions relative to potential mercury contamination at certain gas metering sites. All such costs are included in the $11 million to $13 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 CERCLA (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. The 1990 Amendments required that the EPA issue new regulations, mainly related to stationary sources, air toxics, ozone non-attainment areas and acid rain. During the last few years we have been installing new emission control devices required for new or modified facilities in areas designated as non-attainment by EPA. We operate some of our facilities in areas of the country designated as non-attainment with the one-hour ozone standard. In April 2004, EPA designated eight-hour ozone non-attainment areas. We also operate facilities in areas of the country now designated as non-attainment with the eight-hour ozone standard. Pursuant to non-attainment area 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 $35 million to $40 million subsequent to 2006, through 2010. EPA’s designation of eight-hour 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.

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 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 $325 million and $375 million over the remaining assessment period of 2007 through 2012. As a result of the June 30, 2005 FERC order described in Note 1, a portion of this amount will be expensed. 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 $149 million at December 31, 2006. We have commitments for gas purchases of approximately $196 million at December 31, 2006.

4. DEBT, FINANCING ARRANGEMENTS AND LEASES

Long-term debt At December 31, 2006 and 2005, long-term debt issues were outstanding as follows (in thousands):


	2006			2005
Debentures:
7.08% due 2026	$	7,500		$	7,500
7.25% due 2026		200,000			200,000

Total debentures		207,500			207,500

Notes:
6-1/4% 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			—

Total notes		1,000,000			800,000

Total long-term debt issues		1,207,500			1,007,500
Unamortized debt premium and discount		(6,042	)		(6,877	)
Current maturities		—			—


Total long-term debt, less current maturities	$	1,201,458		$	1,000,623

Aggregate minimum maturities (face value) applicable to long-term debt outstanding at December 31, 2006 are as follows (in thousands):


2008:
6-1/4% Note	$	100,000
Floating Rate Note	$	75,000

	$	175,000


2011:
7% Note	$	300,000

There are no maturities applicable to long-term debt outstanding for the years 2007, 2009 and 2010.

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

Revolving Credit and Letter of Credit Facilities

In May 2006, Williams obtained an unsecured, three-year, $1.5 billion revolving credit facility, replacing the $1.275 billion secured revolving credit facility. The new unsecured facility contains similar terms and financial covenants as the secured facility, but contains additional restrictions on asset sales, certain subsidiary debt and sale-leaseback transactions. The facility is guaranteed by WGP, and Williams guarantees obligations of Williams Partners L.P. for up to $75 million. We have access to $400 million under the 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 0.25% annually) based on the unused portion of the facility. The margins and commitment fee are based on the specific borrower’s senior unsecured long-term debt ratings. Letters of credit totaling approximately $29 million, none of which are associated with us, have been issued by the participating institutions and no revolving credit loans were outstanding at December 31, 2006. Transco did not access this facility during 2006. Significant financial covenants under the credit agreement include the following:

	•		Williams’ ratio of debt to capitalization must be no greater than 65 percent.

	•		Our ratio of debt to capitalization must be no greater than 55 percent. At December 31, 2006, we are in compliance with this covenant as our ratio of debt to capitalization, as calculated under this covenant is approximately 32 percent.

	•		Williams’ ratio of EBITDA to interest, on a rolling four quarter basis, must be no less than 2.5 for the period ending December 31, 2007 and 3.0 for the remaining term of the agreement.

Issuance of Long-Term Debt

Restrictive covenants At December 31, 2006, none of our debt instruments restrict the amount of dividends distributable to WGP.

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.

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.

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


	Operating Leases
	Williams		Other
	Tower		Leases		Total
2007	$	5,497	$	486	$	5,983
2008		5,698		112		5,810
2009		5,936		115		6,051
2010		6,186		117		6,303
2011		6,258		121		6,379
Thereafter		14,553		381		14,934

Total net minimum obligations	$	44,128	$	1,332	$	45,460

Our lease expense was $12.8 million in 2006, $14.1 million in 2005, and $12.7 million in 2004.

5. EMPLOYEE BENEFIT PLANS

SFAS No. 158 Adoption In September 2006, the FASB issued 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)” (SFAS No. 158). This Statement requires sponsors of defined benefit pension and other postretirement benefit plans to recognize the funded status of their pension and other postretirement benefit plans in the statement of financial position, measure the fair value of plan assets and benefit obligations as of the date of the fiscal year-end statement of financial position, and provide additional disclosures. 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, the effect of which has been reflected in the accompanying consolidated financial statements as of December 31, 2006, as described below. The adoption had no impact on the consolidated financial statements at December 31, 2005 or 2004. SFAS No. 158’s provisions regarding the change in the measurement date of postretirement benefit plans are not applicable as we already use a measurement date of December 31. There is no effect on our Consolidated Statement of Income for the year ended December 31, 2006, or for any periods presented related to the adoption of SFAS No. 158, nor will our future operating results be affected by the adoption.

Prior to the adoption of SFAS No. 158, accounting rules allowed for the delayed recognition of certain actuarial gains and losses caused by differences between actual and assumed outcomes, as well as charges or credits caused by plan changes impacting the benefit obligations which were attributed to participants’ prior service. These unrecognized net actuarial gains or losses and unrecognized prior service costs or credits represented the difference between the plans’ funded status and the amount recognized on the Consolidated Balance Sheet. 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. We recorded an adjustment to regulatory asset for our other postretirement benefit plan. Our last several rate case settlement agreements allow for the impact related to any differences between revenues and expenses related to other post retirement benefits to be refiled and collected in the next rate case. These adjustments represent the previously unrecognized net actuarial gains and losses and unrecognized prior service costs or credits. The detail of the effect of adopting SFAS No. 158 is provided in the following table.

The adjustments recorded to accumulated other comprehensive income (loss) and the regulatory asset will be recognized as components of net periodic pension expense or net periodic other postretirement benefit expense and amortized over future periods in accordance with SFAS No. 87, “ Employers’ Accounting for Pensions” and 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 pension or other postretirement benefit expense in the same

period will now be recognized in other comprehensive income (loss) and regulatory assets. These amounts will be recognized subsequently as a component of net periodic pension or other postretirement benefit expense following the same basis as the amounts recognized in accumulated other comprehensive income (loss) and regulatory asset upon adoption of SFAS No. 158.

The effects of adopting SFAS No. 158 to our Consolidated Balance Sheet at December, 31, 2006, are as follows:


	Prior to		Effect of			After
	SFAS No. 158		SFAS No. 158			SFAS No. 158
	Adoption (1)		Adoption (1)			Adoption (1)
	(Millions)
Balances related to pension plans within:
Assets:
Noncurrent assets	$	70.2	$	(16.6	)	$	53.6
Regulatory assets		6.0		(2.1	)		3.9
Deferred income tax assets		—		17.7			17.7
Liabilities:
Current liabilities		—		0.5			0.5
Noncurrent liabilities		22.5		27.1			49.6
Stockholders’ equity
Accumulated other comprehensive income (loss)		—		(28.6	)		(28.6	)

Balances related to other postretirement benefits plans within:
Assets:
Regulatory assets		22.1		(12.7	)		9.4
Liabilities:
Current liabilities		10.6		(9.9	)		0.7
Noncurrent liabilities		22.6		(2.8	)		19.8
Regulatory liabilities		0.9		—			0.9


(1)		Amounts in brackets represent a reduction within the line item balance included on the Consolidated Balance Sheet.

Prior to the adoption of SFAS No. 158, we had computed an additional minimum pension liability. The effect of recognizing this additional minimum pension liability at December 31, 2006 is included in the regulatory asset amounts under the “Prior to SFAS No. 158 Adoption” column within the table above.

Accumulated other comprehensive income (loss) at December 31, 2006 includes the following:


	Pension Benefits
	Gross			Net of Tax
	(Millions)
Amounts not yet recognized in net periodic benefit expense:
Unrecognized prior service (cost) credit	$	2.4		$	1.5
Unrecognized net actuarial gains (losses)		(48.7	)		(30.1	)

Amounts expected to be recognized in net periodic benefit expense in 2007:
Prior service cost (credit)		(1.7	)		(1.0	)
Net actuarial (gains) losses		3.2			2.0

Regulatory asset includes unrecognized prior service credits and unrecognized net actuarial gains of $7.8 million and $4.9 million, respectively. These amounts have not yet been recognized in net periodic other postretirement benefit expense. The prior service credit included in regulatory asset and expected to be recognized in net periodic other postretirement benefit expense in 2007 is $2.1 million. No actuarial gains included in regulatory asset are expected to be recognized in net periodic other postretirement benefit expense in 2007.

Pension plans We participate in noncontributory defined benefit pension plans with Williams and its subsidiaries that provide pension benefits for eligible participants. Cash contributions related to our participation in the plans totaled $10.9 million in 2006, $14.0 million in 2005 and $11.3 million in 2004. Pension expense for 2006, 2005 and 2004 totaled $7.0 million, $1.5 million and a credit of $0.5 million, respectively.

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, 2006 and 2005, is $3.9 million and $4.6 million, respectively, and is expected to be recovered through future rates generally over the average remaining service period for active employees.

At December 31, 2005, we had recorded an additional minimum pension liability of $2.3 million. As required by FERC accounting guidance, this balance was recorded as a regulatory asset instead of accumulated other comprehensive income. At December 31, 2006, we had recorded an additional minimum liability of $2.1 million which was eliminated due to the adoption of SFAS No.158 as it is included in our total funded obligation.

Postretirement benefits other than pensions We participate in a plan with Williams and its subsidiaries 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 $3.8 million in 2006, $3.5 million in 2005, and $2.4 million in 2004. Postretirement benefit expense for 2006, 2005 and 2004 totaled $5.1 million, $5.8 million and $4.9 million, respectively. We recover the actuarially determined cost of postretirement benefits through rates that are set through periodic general rate filings. 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 amounts of postretirement benefits costs deferred as a regulatory asset at December 31, 2006 and 2005 are $8.5 million and $24.3 million, respectively, and are expected to be recovered through future rates generally over the average remaining service period for active employees.

Defined contribution plan Our employees participate in a Williams defined contribution plan. We recognized compensation expense of $5.4 million, $4.8 million and $4.4 million in 2006, 2005 and 2004, respectively, for company matching contributions to this plan.

Employee Stock-Based Compensation Plan Information The Williams Companies, Inc. 2002 Incentive Plan (Plan) was approved by stockholders on May 16, 2002, and amended and restated on May 15, 2003, and January 23, 2004. The Plan provides for 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. We are also billed for our proportionate share of both WGP’s and Williams’ stock-based compensation expense though various allocation processes.

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 deferred share awards. 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 2006 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 deferred shares have not been established and therefore expense is not currently recognized. Results for prior periods have not been restated.

Total stock-based compensation expense, included in administrative and general expenses, for 2006 was $1.5 million, excluding amounts allocated from WGP and Williams.

6. INCOME TAXES

Following is a summary of the provision for income taxes for 2006, 2005, and 2004 (in thousands):


	2006		2005			2004
Current:
Federal	$	13,183	$	96,420		$	68,707
State		1,434		14,435			11,400

		14,617		110,855			80,107


Deferred:
Federal		48,785		(1,710	)		28,331
State		24,474		794			3,483

		73,259		(916	)		31,814


Provision for income taxes	$	87,876	$	109,939		$	111,921

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


	2006			2005			2004
Taxes computed by applying the federal statutory rate	$	71,794		$	103,339		$	101,981
State income taxes (net of federal benefit)		16,840			9,599			9,676
Adjustment of excess deferred taxes		—			(2,996	)		—
Other, net		(758	)		(3	)		264


Provision for income taxes	$	87,876		$	109,939		$	111,921

We provide for income taxes using the assets and liability method as required by SFAS No. 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 Rate Case RP06-569 resulting in additional tax expense of $15.9 million. In addition, we recorded a regulatory asset that partially offsets the effect of the state rate increase. The overall effect on our results of operations 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 Consolidated Balance Sheet.

Significant components of deferred income tax liabilities and assets as of December 31, 2006 and 2005 are as follows (in thousands):


	2006		2005
Deferred tax liabilities
Property, plant and equipment	$	1,070,051	$	993,634
Deferred charges		34,114		28,948
Regulatory liabilities		84,125		48,227
Investments		6,339		4,795

Total deferred tax liabilities		1,194,629		1,075,604


Deferred tax assets
Estimated rate refund liability		813		1,402
Accrued payroll and benefits		59,934		40,939


Deferred state income taxes		45,719		37,957
Accrued liabilities		79,656		36,099
Other		12,639		18,987

Total deferred tax assets		198,761		135,384


Overall net deferred tax liabilities	$	995,868	$	940,220

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, 2006 and 2005 are as follows (in thousands):


	Carrying Amount				Fair Value
	2006		2005		2006		2005
Financial assets:
Cash	$	315	$	362	$	315	$	362
Short-term financial assets		191,380		131,288		191,380		131,288
Long-term financial assets		1,760		2,741		1,760		2,741
Financial liabilities:
Long-term debt, including current portion		1,201,458		1,000,623		1,270,099		1,085,635

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, 2006 and 2005, approximately 94 and 93 percent, respectively, of long-term debt was publicly traded. We use the expertise of outside investment banking firms to assist with the estimate of the fair value of our long-term debt.

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, 2006 and 2005, we had advances to affiliates of $190 million and $130 million, respectively. Advances to affiliates are due on demand.

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

8. TRANSACTIONS WITH MAJOR CUSTOMERS AND AFFILIATES

Major Customers 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. In 2004, our three major customers were Piedmont Natural Gas Company, PSEG Energy Resources & Trade, LLC, and Philadelphia Gas Works providing operating revenues of $168.3 million, $115.1 million, and $92.5 million, respectively.

Affiliates Included in our operating revenues for 2006, 2005, and 2004 are revenues received from affiliates of $51.5 million, $87.1 million and $119.3 million, respectively. The rates charged to provide sales and services to affiliates are the same as those that are charged to similarly-situated nonaffiliated customers.

Through an agency agreement with us, WPC manages our jurisdictional merchant gas sales. For the years ended December 31, 2005 and 2004, included in our cost of sales is $5.5 million and $14.3 million, respectively, representing agency fees billed to us by WPC under the agency agreement. Due to the termination of our remaining Firm Sales agreements effective April 1, 2005, the agency fees billed by WPC for 2006 were not significant.

Included in our cost of sales for 2006, 2005, and 2004 is purchased gas cost from affiliates, excluding the agency fees discussed above, of $15.7 million, $75.7 million and $211.2 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, WPC 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 2006, 2005, and 2004 were $53.4 million, $50.6 million and $45.1 million, respectively, for such corporate expenses charged by Williams and other affiliated companies. Management considers the cost of these services to be reasonable.

Beginning in May 1995, Williams Field Services Company (WFS), an affiliated company, operated our production area facilities pursuant to the terms of an operating agreement. In response to FERC Order No. 2004, we terminated the operating agreement and effective June 1, 2004 we resumed operating these facilities. Included in our operation and maintenance expenses for 2004 were $15.5 million charged by WFS to operate our gas gathering facilities.

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 $6.9 million, $7.5 million and $3.8 million in 2006, 2005 and 2004 respectively, under terms of the operating agreement.

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 adopted SFAS No. 143 on January 1, 2003. We previously determined that asset retirement obligations exist for our offshore transmission platforms. In 2005 we revised our estimate for offshore transmission platforms based on a change in the estimated settlement date and a change in the estimated costs of retirements, resulting in a $23.7 million increase in the asset retirement obligation and Property, Plant and Equipment, net.

In March 2005, the FASB issued FIN No. 47, “Accounting for Conditional Asset Retirement Obligations— an interpretation of FASB Statement No.143.” The Interpretation clarifies that the term “conditional asset retirement” as used in SFAS No.143, “Accounting for Asset Retirement Obligations,” refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. The Interpretation also clarifies when an entity would have sufficient information to reasonably estimate the fair value of an asset retirement obligation (ARO).

We adopted the Interpretation on December 31, 2005. In accordance with the Interpretation, we estimated future retirement obligations for certain assets previously considered to have an indeterminate life. As a result, we recorded an increase in Asset retirement obligations of $8.8 million, and an increase in property, plant and equipment, net, of $1.4 million. We also recorded a $7.4 million regulatory asset in Other Assets for retirement costs expected to be recovered through rates.

During 2006, we obtained additional information impacting our estimation of our ARO. Factors affected by the additional information included estimated settlement dates, estimated settlement costs and inflation rates. We adjusted the ARO related to certain assets because the additional information results in improved and the best available estimates regarding the ARO costs, lives, and inflation rates. During 2006 we recorded an increase in Asset retirement obligations of $82.6 million.

During 2006 and 2005, our overall asset retirement obligation changed as follows (in thousands):


	2006			2005

Beginning balance	$	53,596		$	17,888
Accretion		3,060			1,258
New obligations		—			2,969
Changes in estimates of existing obligations		80,713	⁽¹⁾		23,662
Property dispositions		(1,198	)		(979	)
Adoption of FIN 47		—			8,798

Ending balance	$	136,171		$	53,596


(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.

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, 2006 and December 31, 2005 are as follows (in millions):


	2006		2005
Regulatory Assets

Grossed-up deferred taxes on equity funds used during construction	$	87.7	$	81.7
Asset retirement obligations		87.6		22.3
Deferred taxes		15.5		6.9
Deferred gas costs		8.6		10.5
Environmental costs		5.7		8.4
Postretirement benefits other than pension		9.4		25.3
Fuel cost		9.5		1.0
Other		—		2.3

Total Regulatory Assets	$	224.0	$	158.4


Regulatory Liabilities

Negative salvage	$	40.1	$	38.5
Deferred cash out		15.8		39.8
Electric power cost		4.2		6.8
Other		0.9		3.0

Total Regulatory Liabilities	$	61.0	$	88.1

11. QUARTERLY INFORMATION (UNAUDITED)

The following summarizes selected quarterly financial data for 2006 and 2005 (in thousands):


2006	First (1)			Second			Third			Fourth (2)
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


2005	First			Second			Third (3)			Fourth
Operating revenues	$	348,945		$	263,802		$	270,891		$	302,775
Operating expenses		260,044			176,553			178,404			229,327

Operating income		88,901			87,249			92,487			73,448
Interest expense		20,120			19,672			19,782			20,087
Other (income) and deductions, net		(6,818	)		(8,394	)		(9,227	)		(8,391	)

Income before income taxes		75,599			75,971			81,932			61,752
Provision for income taxes		28,459			28,682			31,357			21,441


Net income	$	47,140		$	47,289		$	50,575		$	40,311


(1)		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.

(2)		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.

(3)		Includes a $14.2 million decrease to operating expenses resulting from a reversal of a liability related to the 1999 Fuel Tracker.

TRANSCONTINENTAL GAS PIPE LINE CORPORATION
SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS
(Thousands of Dollars)


			ADDITIONS
			Charged to
	Beginning		Costs and								Ending
Description	Balance		Expenses		Other			Deductions			Balances
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
Year ended December 31, 2004:
Reserve for rate refunds		10,610		7,417		(7,637	)		(1,471	)		8,919
Reserve for doubtful receivables		2,470		490		—			(2,182	)		778

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 Rule 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 or our internal controls over financial reporting (Internal Controls) will prevent all errors and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within 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 inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and not be detected. We monitor our

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

A material weakness is a control deficiency, or combination of control deficiencies, that results in more than a remote likelihood that a material misstatement of the annual or interim financial statements will not be prevented or detected.

During the fourth quarter of 2005 and as reported in our 2005 Annual Report on Form 10-K, we identified a material weakness in internal control over financial reporting associated with the absence of an effective control to identify to specific customers a material amount of transportation and exchange imbalance volumes, primarily for the period April 2003 to December 2004. These natural gas volumes represent gas received in excess of amounts delivered on our pipeline systems that had not been associated with specific transportation contracts and related customers, and were recorded within Transportation and Exchange Gas Payables in our consolidated balance sheet at December 31, 2005.

In 2005, we implemented controls designed to prevent the repetition of this failure of identification in future periods. In 2006 we reconciled the vast majority of the unidentified volumes for each month retroactive to April 2003. At December 31, 2006, the reconciliation process had been completed for the 2003 to 2004 period. The resulting adjustments were recorded and did not have a material effect on our 2006 financial statements. We now consider this material weakness to be remediated.

Changes in Internal Control over Financial Reporting

There have been no changes during the fourth quarter of 2006 that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.

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):


	2006		2005
Audit Fees	$	2,463	$	1,941
Audit-Related Fees		203		87
Tax Fees		—		—
All Other Fees		—		—


Total Fees	$	2,666	$	2,028

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 9, 2007.

PART IV

ITEM 15. Exhibits and Financial Statement Schedules.


	Page
	Reference to
	2006 10-K
A. Index

1. Financial Statements:

Report of Independent Registered Public Accounting Firm - Ernst &Young LLP		28

Consolidated Statement of Income for the Years Ended December 31, 2006, 2005 and 2004		29

Consolidated Balance Sheet as of December 31, 2006 and 2005		30-31

Consolidated Statement of Common Stockholder’s Equity for the Years Ended December 31, 2006, 2005 and 2004		32

Consolidated Statement of Comprehensive Income for the Years Ended December 31, 2006, 2005 and 2004		33

Consolidated Statement of Cash Flows for the Years Ended December 31, 2006, 2005 and 2004		34-35

Notes to Consolidated Financial Statements		36-57

2. Financial Statement Schedules:

Schedule II — Valuation and Qualifying Accounts for the Years ended December 31, 2006, 2005 and 2004		58

The following schedules are omitted because of the absence of the conditions under which they are required:

I, III, IV, and V.

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 April 1, 2003 (filed as Exhibit 3.2 to Transco Form 10-K filed March 30, 2005)

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

(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	U.S. $1,275,000,000 Amended and Restated Credit Agreement dated as of May 20, 2005 among The Williams Companies, Inc., Northwest Pipeline Corporation, Transcontinental Gas Pipe Line Corporation, Williams Partner L.P., as Borrowers, Citicorp USA, Inc. as Administrative Agent and Collateral Agent, Citibank, N.A. and Bank of America, N.A. as Issuing Banks and The Banks Named Herein as Banks (filed as Exhibit 1.1 to the Transco Form 8-K filed May 26, 2005)

-	4	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).

-	5	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).

(23) Consent of Independent Registered Public Accounting Firm

(24) Power of attorney with certified resolution

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 2nd day of March 2007.


	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 2nd day of March 2007, 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 Officer)

Richard D. Rodekohr

/s/ JEFFREY P. HEINRICHS *		Controller (Principal Accounting Officer)

Jeffrey P. Heinrichs

By /s/ JEFFREY P. HEINRICHS *

Jeffrey P. Heinrichs
Attorney-in-fact


	PAGE
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)		18

PART II

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Repurchases of Equity Securities		18

Item 6. Selected Financial Data (Omitted)		18

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		58

Item 9A. Controls and Procedures		58

Item 9B. Other Information		59

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
Consent of Independent Registered Public Accounting Firm
Power of Attorney with Certified Resolution
Certification of Principal Executive Officer - Section 302
Certification of Principal Financial Officer - Section 302
Certifications Pursuant to Section 906


		Page
Report of Independent Registered Public Accounting Firm		28

Consolidated Statement of Income		29

Consolidated Balance Sheet		30-31

Consolidated Statement of Common Stockholder’s Equity		32

Consolidated Statement of Comprehensive Income		33

Consolidated Statement of Cash Flows		34-35

Notes to Consolidated Financial Statements		36-57