UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

FORM 10-K

For the transition period from _______________ to _______________

Commission File Number 1-7584

TRANSCONTINENTAL GAS PIPE LINE CORPORATION

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 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  [X]   No [   ]

     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.  [X]

     Indicate by check mark whether the registrant is an accelerated filer (as defined in Exchange Act Rule 12b-2). Yes  [   ]  No [X]

     The number of shares of Common Stock, par value $1.00 per share, outstanding at January 31, 2004 was 100.

     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.

Table of Contents

TRANSCONTINENTAL GAS PIPE LINE CORPORATION
FORM 10-K

TABLE OF CONTENTS

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PART I

ITEM 1. Business.

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

GENERAL

     Transco is a wholly-owned subsidiary of Williams Gas Pipeline Company, LLC (WGP). WGP is a wholly-owned subsidiary of The Williams Companies, Inc. (Williams).

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

     As of December 31, 2003, we had 1,145 full time employees.

     At December 31, 2003, 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 capacity, we can deliver an additional 3.4 MMdt of gas per day for a system-wide delivery capacity total of approximately 8.1 MMdt of gas per day. The system is composed of approximately 10,500 miles of mainline and branch transmission pipelines, 44 compressor stations, five underground storage fields, two liquefied natural gas (LNG) storage facilities and 4 processing plants. 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 are constructed and maintained pursuant to rights-of-way, easements, permits, licenses or consents on and

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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) (formerly Williams Energy Marketing & Trading Company), manages our jurisdictional merchant gas sales.

     Since May 1995, Williams Field Services Company (WFS), an affiliated company, has operated our production area facilities. Since February 1996, we have filed applications with the FERC seeking authorization to abandon certain facilities located onshore and offshore in Texas, Louisiana and Mississippi by conveyance to Williams Gas Processing — Gulf Coast Company (Gas Processing), an affiliated company. (For a discussion of five of the applications, see “Item 8. Financial Statements and Supplementary Data — Notes to Consolidated Financial Statements — 2. Contingent Liabilities and Commitments — Rate and Regulatory Matters.”)

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 three largest customers in 2003 were PSE&G Energy Resources & Trade, LLC, WPC and Philadelphia Gas Works, which accounted for approximately 8.1 percent, 7.7 percent and 6.9 percent, 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 2003, 2002 and 2001 are shown below.

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

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PIPELINE PROJECTS

Completed Projects

     In 2003 and early 2004, we completed construction of, and placed into service, two major projects, the Momentum Expansion Project and the Trenton-Woodbury Expansion Project.

     Momentum Expansion Project We have placed into service the Momentum Expansion Project, an expansion of our pipeline system from Station 65 in Louisiana to Station 165 in Virginia. The first phase, consisting of approximately 269 Mdt/d, was placed into service on May 1, 2003. On February 1, 2004, we placed into service the second and final phase of the project consisting of 54 Mdt/d. All of the expansion capacity is fully subscribed by shippers under long-term firm arrangements. The project facilities include approximately 50 miles of pipeline looping and 45,000 horsepower of compression. The revised capital cost of the project is estimated to be approximately $189 million.

     Trenton-Woodbury Expansion Project On November 1, 2003, we placed into service a 51 Mdt/d expansion of our Trenton-Woodbury Line, which runs from our mainline at Station 200 in eastern Pennsylvania, around the metropolitan Philadelphia area and southern New Jersey area, to our mainline near Station 205. All of the expansion capacity is fully subscribed by shippers under long-term firm arrangements. The project facilities include approximately 7 miles of pipeline looping at an estimated capital cost of approximately $22 million.

Future Projects

     Central New Jersey Expansion Project On January 14, 2004, we announced that we were holding an open season from January 14, 2004 to February 13, 2004 to receive requests for incremental firm transportation service to be made available through our Central New Jersey Expansion Project, a proposed expansion of our pipeline system in Zone 6 from Station 210 to locations along our Trenton-Woodbury Line. As a result of the open season, the expansion has been designed to create approximately 105 Mdt/d of new firm transportation capacity, which will be fully subscribed under a long-term arrangement with one shipper. The project facilities will include approximately 3.5 miles of pipeline loop at an estimated capital cost of $13 million. We plan to file for FERC approval of the project in the second quarter of 2004. The target in-service date for the project is November 1, 2005.

REGULATORY MATTERS

     Our transportation rates are established through the FERC ratemaking process. Key determinants in the ratemaking process are (i) volume throughput assumptions, (ii) costs of providing service, including depreciation expense, and (iii) allowed rate of return including the equity component of a pipeline’s capital structure, and related income taxes. Rate design and the allocation of costs between the demand and commodity rates also impact profitability. Pending FERC approval of pending rate filings, certain revenues collected by us may be subject to possible refunds. 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 reservation charge to customers and all variable costs are recovered through a usage charge to customers. While the use of SFV rate design limits our opportunity to earn

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incremental revenues through increased throughput, it also limits our risk associated with fluctuations in throughput.

     Order No. 2004 (Docket No. RM01-10-000) On November 25, 2003, the FERC issued Order No. 2004 adopting uniform standards of conduct for transmission providers. The proposed rules define transmission providers as interstate natural gas pipelines and public utilities that own, operate or control electric transmission facilities. The standards regulate the conduct of transmission providers with their energy affiliates. The FERC defines energy affiliates broadly to include any non-transmission provider affiliate that engages in or is involved in transmission (gas or electric) transactions, manages or controls transmission capacity or that buys, sells, trades or administers natural gas or electric energy, engages in financial transactions relating to the sale or transmission of natural gas or electricity, and Hinshaw and intrastate pipelines. Current rules regulate our conduct with our natural gas marketing affiliates. Transmission providers must comply with Order No. 2004 by June 1, 2004. Numerous parties, including Williams, have filed requests for rehearing of Order No. 2004. We filed and posted a plan and schedule for implementing the requirements of Order No. 2004 on February 9, 2004, and currently are reviewing these new standards, preparing to adopt new compliance measures and evaluating the impact of increased costs to us.

     For a discussion of additional regulatory matters, see “Item 8. Financial Statements and Supplementary Data — Notes to Consolidated Financial Statements - - 2. Contingent Liabilities and Commitments — Rate and Regulatory Matters.”

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 are made through a Firm Sales (FS) program which gives 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 which resolved an open investigation, we have notified our merchant sales customers that we will be terminating the merchant sales service when we are able to do so under the terms of any applicable contracts and FERC certificates authorizing such services. Under the FS program we must provide two-year advance notice of termination. Therefore, we notified the FS customers of our intention to terminate the FS service effective April 1, 2005. Through an agency agreement, 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 has no impact on our operating income or results of operations and, therefore, the anticipated termination of such services, pursuant to the terms of the FERC settlement will have no impact on our operating income or results of operations. For a discussion of the settlement agreement with the FERC, see “Item 8. Financial Statements and Supplementary Data — Notes to Consolidated Financial Statements – 2. Contingent Liabilities and Commitments — Rate and Regulatory Matters”.

     Our gas sales volumes managed by WPC for the years 2003, 2002 and 2001 are shown below.

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TRANSACTIONS WITH AFFILIATES

     We engage in transactions with Williams and other Williams subsidiaries. See “Item 8. Financial Statements and Supplementary Data — Notes to Consolidated Financial Statements — 1. Summary of Significant Accounting Policies, 2. Contingent Liabilities and Commitments and 7. 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.

     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, for the most part, are 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 — 2. 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 efficiencies have increased the risk for pipelines of contract non-renewal or capacity turnback.

     At the state level, both local distribution company (LDC) unbundling and electric industry restructuring are affecting our markets. Several states have implemented changes similar to the federal changes under Order 636. New York, New Jersey, Pennsylvania, Maryland, Delaware, Georgia and the District of Columbia have established regulations for LDC unbundling and are currently implementing them on a company-by-company basis. Although pipeline operators are increasingly challenged to accommodate the flexibility demanded by customers and allowed under tariffs, the changes being implemented at the state level

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have not, thus far, required renegotiation of our LDC contracts. The state plans have in some cases discouraged LDCs from signing long-term contracts for new capacity.

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 discussed in this annual report, excluding historical information, include forward-looking statements — statements that discuss our expected future results based on current and pending business operations. We make these forward-looking statements in reliance on the safe harbor protections provided under the Private Securities Litigation Reform Act of 1995.

     All statements, other than statements of historical facts, included in this Form 10-K which address activities, events or developments which we expect, believe or anticipate will or may occur in the future are forward-looking statements. Forward-looking statements can be identified by words such as “anticipates,” “believes,” “could,” “continues,” “estimates,” “expects, “ “forecasts,” “might,” “planned,” “potential,” “projects,” “scheduled” or similar expressions. These forward-looking statements include, among others, such things as:

•		amounts and nature of future capital expenditures;
•		expansion and growth of our business and operations;
•		business strategy;
•		power and gas prices and demand.

     These statements are based on certain assumptions and analysis made by us in light of our experience and our perception of historical trends, current conditions and expected future developments as well as other factors we believe are appropriate in the circumstances. Although we believe these forward-looking statements are based on reasonable assumptions, statements made regarding future results are subject to a number of assumptions, uncertainties and risks that could cause future results to be materially different from the results stated or implied in this document.

     These risks and uncertainties include:

•		general economic and market conditions;
•		changes in laws or regulations;
•		continued availability of capital and financing;
•		recovery of amounts through rates: and
•		other factors, most of which are beyond our control.

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RISK FACTORS

     You should carefully consider the following risk factors in addition to the other information in this annual 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.

     BECAUSE WE NO LONGER MAINTAIN INVESTMENT GRADE CREDIT RATINGS, OUR COUNTERPARTIES HAVE REQUIRED US TO PROVIDE HIGHER AMOUNTS OF CREDIT SUPPORT WHICH RAISES OUR COST OF DOING BUSINESS.

     Our transactions will require greater credit assurances, both to be given from, and received by, us to satisfy credit support requirements. Additionally, certain market disruptions or a further downgrade of our credit rating might further increase our cost of borrowing or further impair our ability to access one or any of the capital markets. Such disruptions could include:

•		economic downturns;
•		capital market conditions generally;
•		market prices for electricity and natural gas;
•		terrorist attacks or threatened attacks on our facilities or those of other energy companies; or
•		the overall health of the energy industry, including the bankruptcy or insolvency of other energy companies.

RISKS RELATED TO THE REGULATION OF OUR BUSINESS

     OUR GAS SALES, TRANSMISSION, AND STORAGE OPERATIONS ARE SUBJECT TO GOVERNMENT REGULATIONS AND RATE PROCEEDINGS THAT COULD HAVE AN ADVERSE IMPACT ON OUR ABILITY TO RECOVER THE COSTS OF OPERATING OUR PIPELINE FACILITIES.

     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.

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The FERC has taken certain actions to strengthen market forces in the natural gas pipeline industry that has led to increased competition throughout the industry. In a number of key markets, we are facing competitive pressure from other major pipeline systems, enabling local distribution companies and end users to choose a transmission provider based on economic and other considerations. Our ability to compete in the natural gas pipeline industry is impacted by our ability to offer competitively priced services and to successfully implement efficient and effective operational systems, that must also meet applicable regulatory requirements.

     On November 25, 2003, the FERC issued a final rule, Order No. 2004, that adopted new standards of conduct for transmission providers to follow when dealing with their energy affiliates. Order No. 2004 may require substantial changes to Williams’ internal leadership structure that may have an adverse impact on Williams’ ability to effectively run its business. As a transmission provider, we must comply with the new standards of conduct and post procedures on the internet indicating how we will do so by June 1, 2004. The precise scope of the new rule is unclear and clarification has been requested from the FERC. That clarification may not be received until after the June 1 deadline, and so the new procedures we implement to meet the standards of Order No. 2004 could be found by the FERC to be inadequate in spite of our efforts to comply with the new rule.

     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. Thus far our requests have been denied.

RISKS RELATED TO ENVIRONMENTAL MATTERS

     WE COULD INCUR MATERIAL LOSSES IF WE ARE HELD LIABLE FOR THE ENVIRONMENTAL CONDITION OF ANY OF OUR ASSETS OR DIVESTED ASSETS, WHICH COULD INCLUDE LOSSES THAT EXCEED OUR CURRENT EXPECTATIONS.

     We are generally responsible for all on-site liabilities associated with the environmental condition of our facilities and assets, which we have acquired or developed, regardless of when the liabilities arose and whether they are known or unknown. In addition, in connection with certain acquisitions and sales of assets, we might obtain, or be required to provide, indemnification against certain environmental liabilities. If we incur a material liability, or the other party to a transaction fails to meet its indemnification obligations to us, we could suffer material losses. If a purchaser of a divested asset incurs a liability due to the environmental condition of the divested asset, we may have a contractual obligation to indemnify that purchaser or otherwise retain responsibility for the environmental condition of the divested asset. We may also have liability for the environmental condition of divested assets under applicable federal or state laws and regulations. Changes to applicable laws and regulations or changes to their interpretation, may increase our liability. Environmental conditions at divested assets may not be covered by insurance. Even if environmental conditions are covered by insurance, policy conditions may not be met.

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     We make assumptions and develop expectations about possible liability 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 assumptions and expectations are also based on available information. If more information becomes available to us, our assumptions may change. Any of these changes may result in not only increased risk related to one or more of our assets, but material losses in excess of current estimates.

     ENVIRONMENTAL REGULATION AND LIABILITY RELATING TO OUR BUSINESS WILL BE SUBJECT TO ENVIRONMENTAL LEGISLATION IN ALL JURISDICTIONS IN WHICH WE OPERATE, AND ANY CHANGES IN SUCH LEGISLATION COULD NEGATIVELY AFFECT OUR RESULTS OF OPERATIONS.

     Our operations are subject to extensive environmental regulation pursuant to a variety of federal, state and municipal laws and regulations. Such environmental legislation imposes, among other things, restrictions, liabilities and obligations in connection with the generation, handling, use, storage, transportation, treatment and disposal of hazardous substances and waste and in connection with spills, releases and emissions of various substances into the environment. Environmental legislation also requires that our facilities, sites and other properties associated with our operations be operated, maintained, abandoned and reclaimed to the satisfaction of applicable regulatory authorities. Existing environmental regulations could also be revised or reinterpreted, new laws and regulations could be adopted or become applicable to us or our facilities, and future changes in environmental laws and regulations could occur. The federal government and several states recently have proposed increased environmental regulation of many industrial activities, including increased regulation of air quality, water quality and solid waste management.

     Compliance with environmental legislation will require significant expenditures, including expenditures for compliance with the Clean Air Act and similar legislation, for clean up costs and damages arising out of contaminated properties, and for failure to comply with environmental legislation and regulations which might result in the imposition of fines and penalties. The steps we take to bring certain of our 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.

     Further, our regulatory rate structure and our contracts with customers might not necessarily allow us to recover capital costs incurred to comply with 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. Should we fail to comply with all applicable environmental laws, we might be subject to penalties and fines imposed by regulatory authorities. Although we do not expect that the costs of complying with current environmental legislation will have a material adverse effect on our financial condition or results of operations, no assurance can be made that the costs of complying with environmental legislation in the future will not have such an effect.

RISKS RELATING TO ACCOUNTING STANDARDS

     POTENTIAL CHANGES IN ACCOUNTING STANDARDS MIGHT CAUSE US TO REVISE OUR FINANCIAL DISCLOSURE IN THE FUTURE.

     Recently discovered accounting irregularities in various industries have forced regulators and legislators to take a renewed look at accounting practices, financial disclosures, and companies’ relationships

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with their independent auditors and other accounting practices. Because it is still unclear what laws or regulations will develop, 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 FERC or the Securities and Exchange Commission (SEC) could enact new or revised accounting standards that might impact how we are required to record revenues, expenses, assets and liabilities.

RISKS RELATING TO OUR INDUSTRY

     THE LONG-TERM FINANCIAL CONDITION OF OUR GAS TRANSMISSION BUSINESS IS DEPENDENT ON THE CONTINUED AVAILABILITY OF NATURAL GAS RESERVES.

     The development of additional natural gas reserves 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 of additional reserves and production, gathering, storage and pipeline transmission and import and export of natural gas supplies. Restricted access to areas of potential reserves also could adversely affect the development of additional reserves.

     GAS TRANSMISSION ACTIVITIES INVOLVE NUMEROUS RISKS THAT MIGHT RESULT IN ACCIDENTS AND OTHER OPERATING RISKS AND COSTS.

     There are inherent in our gas transmission properties a variety of hazards and operating risks, such as leaks, explosions and mechanical problems that could cause substantial financial losses. In addition, these risks could result in loss of human life, significant damage to property, environmental pollution, impairment of our operations and substantial losses. In accordance with customary industry practice, we maintain insurance against some, but not all, of these risks and losses. The occurrence of any of these events not fully covered by insurance could have a material adverse effect on our financial position and results of operations. The location of pipelines near populated areas, including residential areas, commercial business centers and industrial sites, could increase the level of damages resulting from these risks.

     COMPLIANCE WITH THE PIPELINE SAFETY IMPROVEMENT ACT MAY RESULT IN UNANTICIPATED COSTS AND CONSEQUENCES.

     Implementation of new Pipeline Safety Improvement Act (PSIA) regulations requires us to implement an Integrity Management Plan (IMP) by December 2004. As part of the IMP, we must identify High Consequence Areas (HCA) through which our pipeline runs. Although our investigations are ongoing, we believe that certain segments of our pipeline will be determined to run through HCAs. An HCA is defined by the rule as an area where the potential consequence of a gas pipeline accident may be significant or do considerable harm to people or property. Designing and implementing the IMP and identifying HCAs could result is significant additional costs. There is always the possibility that the assessments related to the IMP reveal an unexpected condition for which remedial action will be required.

     OTHER RISKS

     THE THREAT OF TERRORIST ACTIVITIES AND THE POTENTIAL FOR CONTINUED MILITARY AND OTHER ACTIONS COULD ADVERSELY AFFECT OUR BUSINESS.

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     The continued threat of terrorism and the impact of continued military and other action by the United States and its allies might lead to increased political, economic and financial market instability and volatility in prices for natural gas, which could affect the market for our gas transmission operations. In addition, future acts of terrorism could be directed against companies operating in the United States, and it has been reported that terrorists might be targeting domestic energy facilities. While we are taking steps that we believe are appropriate to increase the security of our energy assets, there is no assurance that we can completely secure our assets or to completely protect them against a terrorist attack. These developments have subjected our operations to increased risks and, depending on their ultimate magnitude, could have a material adverse effect on our business. In particular, we might experience increased capital or operating costs to implement increased security for our energy assets.

ITEM 2. Properties.

     See “Item 1. Business.”

ITEM 3. Legal Proceedings.

     FERC enforcement matter By order dated March 17, 2003, the FERC approved a settlement between the FERC staff and Williams, WPC and us which resolved the FERC staff’s allegations during a formal, nonpublic investigation that WPC personnel had access to our data bases and other information, and that we had failed to accurately post certain information on our electronic bulletin board. Pursuant to the terms of the settlement agreement, we will pay a civil penalty in the amount of $20 million in five equal installments. We made the first payment on May 16, 2003, and the subsequent payments are due on or before the first, second, third and fourth anniversaries of the first payment. We recorded a charge to income and established a liability of $17 million in 2002 representing the net present value of the future payments. In addition, we have notified our Firm Sales (FS) customers of our intention to terminate the FS service effective April 1, 2005 under the terms of applicable contracts and the FERC certificates authorizing such services. As part of the settlement, WPC has 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. Finally, we have agreed to the terms of a compliance plan designed to ensure future compliance with the provisions of the settlement agreement and the FERC’s rules governing the relationship of Transco and WPC.

     Royalty claims and litigation 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.

     As a result of these settlements, we have been sued by certain producers seeking indemnification. We are currently a defendant in one such lawsuit. Freeport-McMoRan, Inc., filed a lawsuit against us in the 19^th Judicial District Court in East Baton Rouge, Louisiana, in which it asserted damages, including interest

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calculated through December 31, 2003, of approximately $10 million. The case was tried in 2003 and resulted in a judgment favorable to us, which Freeport-McMoRan is appealing. On November 25, 2003, we settled a lawsuit filed by Mobil Producing Texas on August 30, 2000, in the 79^th District Court, Brooks County, Texas, in which Mobil had asserted damages, including interest, of $8 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 Transco. Mr. Grynberg has also filed claims against approximately 300 other energy companies and alleges that the defendants violated the False Claims Act in connection with the measurement, royalty valuation and purchase of hydrocarbons. The relief sought is 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, including the action filed against the Williams entities in the United States District Court for the District of Colorado. 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 remain pending against Williams, including Transco, and the other defendants.

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. On the basis of the findings to date, we estimate that over the next five years environmental assessment and remediation costs under TSCA, RCRA, CERCLA and comparable state statutes will total approximately $27 million to $30 million, measured on an undiscounted basis. 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, 2003, Transco had a balance of approximately $28 million for these estimated costs recorded in current liabilities ($5 million) and other long-term liabilities ($23 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

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been recorded as regulatory assets in current assets 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, the costs of which are included in the $27 million to $30 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 currently designated as non-attainment and we anticipate that during 2004 the EPA may designate additional new non-attainment areas which might impact our operations. Pursuant to non-attainment area requirements of the 1990 Amendments, and proposed EPA rules designed to mitigate the migration of ground-level ozone (NOx) in 22 eastern states, 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. Additionally, the EPA is expected to promulgate additional rules regarding hazardous air pollutants in 2004, which may impose controls in addition to the controls described above. 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 future cost in the range of $230 million to $260 million. If the EPA designates additional new non-attainment areas in 2004, which impact our operations, 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.

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.

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PART II

ITEM 5. Market for Registrant’s Common Equity and Related Stockholder Matters.

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

     Our Board of Directors declared cash dividends on common stock in the amounts of $85 million on March 31, 2003, $70 million on June 30, 2003, $50 million on September 30, 2003 and $40 million on December 31, 2003.

     Our Board of Directors declared a cash dividend on common stock in the amount of $200 million on November 15, 2002.

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

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

     Regulatory Accounting We are regulated by the 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 reasonable to assume 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, employee related benefits, and other costs and taxes included in, or expected to be included in, future rates. As a rate-regulated entity, we have 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. At December 31, 2003, we had approximately $144 million of regulatory assets included in Other Assets and approximately $51 million

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of regulatory liabilities included in Other Long-Term Liabilities: Other in the accompanying Consolidated Balance Sheet. At December 31, 2002, we had approximately $138 million of regulatory assets included in Other Assets and approximately $49 million of regulatory liabilities included in Other Long-Term Liabilities: Other in the accompanying Consolidated Balance Sheet.

     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 (i) volume throughput assumptions, (ii) costs of providing service, including depreciation expense, and (iii) allowed rate of return including the equity component of a pipeline’s capital structure, and related income taxes.

     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. At December 31, 2003, we had accrued approximately $11 million for potential refunds applicable to all regulatory proceedings. Depending on the results of these proceedings, the actual amounts allowed to be collected from customers could differ from management’s estimate.

     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, advice of legal counsel or other third parties regarding the probable outcomes of the matter. 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.

WILLIAMS’ RECENT EVENTS

     In February 2003, Williams outlined its planned business strategy in response to the events which impacted the energy sector and Williams during late 2001 and much of 2002. The plan focused upon migrating to an integrated natural gas business comprised of a strong, but smaller portfolio of natural gas businesses, reducing debt and increasing Williams’ liquidity through assets sales, strategic levels of financing

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and reductions in operating costs. The plan was designed to address near-term and medium-term debt and liquidity issues, to de-leverage Williams with the objective of returning to investment grade status and to develop a balance sheet and cash flows capable of supporting and ultimately growing its remaining businesses.

     During 2003, Williams successfully executed the following critical components of its restructuring plan:

•		generated cash proceeds of approximately $3.0 billion from the sale of assets.
•		repaid $3.2 billion of debt through scheduled maturities and early extinguishment of debt and accessed the public debt markets available to Williams primarily to refinance $2.0 billion of higher debt cost.
•		sustained core business earnings capacity through completed gas pipeline system expansions, continued drilling activity at Williams’ exploration and production segment and continued investment in deepwater activities within Williams’ midstream segment.
•		continued rationalization of its cost structure, including a 28 percent reduction in selling, general and administrative (SG&A) costs of continuing operations and a 39 percent reduction in general corporate expenses.

     Williams completed tender offers that prepaid approximately $721 million of the $1.4 billion of its senior unsecured 9.25 percent notes that mature in the first quarter of 2004.

     Williams is pursuing a strategy of exiting the power business. However, market conditions have contributed to the difficulty of, and could delay, full, immediate exit from this business. In 2003, Williams generated in excess of $600 million from the sale, termination or liquidation of power contracts and assets. During the year, Williams continued to manage its portfolio to reduce risk, to generate cash and to fulfill contractual commitments. Williams is also pursuing its goal to resolve the remaining legal and regulatory issues associated with the business.

     Entering 2004, Williams’ plan is to focus upon the following objectives:

•		sustain solid core business performance, including increased capital allocation to exploration and production activities;
•		continue reduction of debt, including scheduled maturities and early retirements, and selective refinancing of certain instruments;
•		maintain investment discipline.

     Key execution steps include the completion of planned asset sales, which are estimated to generate proceeds of approximately $800 million in 2004, additional reductions of Williams’ SG&A costs, the replacement of its cash-collateralized letter of credit and revolver facility with facilities that do not encumber cash and continuing efforts to exit from the power business.

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RESULTS OF OPERATIONS

2003 COMPARED TO 2002

     Operating Income and Net Income Our operating income for 2003 was $370.0 million compared to operating income of $300.8 million for 2002. Net income for 2003 was $194.3 million compared to net income of $163.0 million for 2002.

     The higher operating income of $69.2 million was primarily the result of higher transportation revenues, lower administrative and general cost and lower other operating costs and expenses as discussed below. The increase in net income of $31.3 million was attributable to the increased operating income, partially offset by the higher deductions, as discussed below in Other Income and Other Deductions.

     Transportation Revenues Our operating revenues related to transportation services increased $52.6 million to $797.0 million for 2003 when compared to 2002. The higher transportation revenues were primarily due to increased demand revenues of $60.7 million resulting from (1) new expansion projects (Sundance placed into service on May 1, 2002, Market Link Phase 2 placed into service on November 1, 2002, Momentum Phase 1 placed into service on May 1, 2003 and Trenton-Woodbury placed into service on November 1, 2003) and (2) approved settlement rates, implemented pursuant to the Settlement approved on July 23, 2002, to recover costs associated with increased rate base, rate of return and expenses contained in Transco’s general rate case (Docket No. RP01-245). In addition, transportation revenues are higher due to an increase of $13.6 million in commodity revenues and a higher level of reimbursable costs of $6.3 million that are included in operating expenses and recovered in our rates. The increases were partially offset by a decrease of $27.9 million associated with the reversal of rate refund liabilities and other adjustments pursuant to the settlement of the general rate case in the third quarter of 2002.

     Our total market-area deliveries for 2003 decreased 27.5 TBtu, or 2%, when compared to 2002. This is primarily the result of significantly reduced weather-related power generation load. Our production area deliveries increased 117.1 TBtu, or 65%, when compared to 2002. This is primarily due to higher deliveries to production area storage and higher deliveries in the production area as a result of new offshore production.

     Sales Revenues We make jurisdictional merchant gas sales to customers pursuant to a blanket sales certificate issued by the FERC, with most of those sales being made through a Firm Sales (FS) program which gives 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 which resolved an open investigation, we have notified our merchant sales customers that we will be terminating the merchant sales service when we are able to do so under the terms of any applicable contracts and FERC certificates authorizing such services. Under the FS program we must provide two-year advance notice of termination. Therefore, we notified the FS customers of our intention to terminate the FS service effective April 1, 2005. Through an agency agreement, 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 has no impact on our operating income or results of operations and, therefore, the anticipated termination of such services, pursuant to the terms of the FERC settlement will have no impact on our operating income or results of operations. For a discussion of the settlement agreement with the FERC, see “Item 8. Financial Statements and Supplementary Data — Notes to Consolidated Financial Statements – 2. Contingent Liabilities and Commitments — Rate and Regulatory Matters”.

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     Through an agency agreement, WPC manages our jurisdictional merchant gas sales, excluding 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.

     Operating revenues related to our sales services increased $90.9 million to $471.6 million for 2003, when compared to 2002. The increase was primarily due to a higher average sales price of $5.42 per dt in 2003 compared to $3.29 per dt in 2002, partially offset by a lower volume of merchant sales.

     In addition to our merchant gas sales, we also have cash out sales, which settle gas imbalances with shippers. The cash out sales have no impact on our operating income or results of operations.

     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 most transportation imbalances generated after August 1, 1991 are settled on a monthly basis through cash out sales or purchases.

     Storage Revenues Our operating revenues related to storage services decreased $11.3 million to $124.4 million for 2003, when compared to 2002. The decrease was primarily due to a change in rate design (implementation of rolled-in rate treatment in Docket No. RP95-197) to recover certain costs through transportation rates which were previously recovered through certain storage rates.

     Other Revenues Our other operating revenues increased $4.9 million to $20.4 million for 2003, when compared to 2002, primarily due to increases in environmental mitigation credit sales, liquids revenue and Parking and Borrowing Service revenue.

     Operating Costs and Expenses Excluding the cost of natural gas sales of $471.6 million for 2003 and $380.7 million for 2002, our operating expenses were approximately $23.0 million lower than the comparable period in 2002. This decrease was primarily attributable to the lower cost of natural gas transportation, administrative and general expense, and other operating costs and expenses, partially offset by increases in depreciation and amortization expense and taxes other than income taxes. The lower cost of natural gas transportation was due to a $14.6 million decrease in nontracked fuel expense primarily resulting from pricing differentials related to volumes of gas used in operations, partially offset by higher tracked fuel expense of $5.4 million and a $4.0 million charge in the third quarter of 2003 associated with the write-off of certain receivables. The lower administrative and general expense was primarily due to lower labor cost of $15.0 million resulting mostly from a reduced workforce and lower employee benefits expenses as a result of the enhanced-benefit early retirement option offered to certain Williams employee groups during 2002. The lower other operating costs and expenses were primarily due to a $7.2 million reduction of reserves in the third quarter of 2003 for claims associated with certain producer indemnities as a result of recent settlements and court rulings and a $17 million charge in 2002 associated with a FERC penalty (see “Item 8. Financial Statements and Supplementary Data — Notes to Consolidated Financial Statements – 2. Contingent Liabilities and Commitments – Rate and Regulatory Matters”). Also, our charitable contribution commitments were $2.5 million lower in 2003 compared to 2002. Depreciation and amortization increased $22.3 million due primarily to the increase in property resulting from completion of recent construction projects. The higher taxes other

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than income taxes of $6.5 million was primarily due to lower taxes in 2002 as a result of a refund of state franchise taxes.

     Other Income and Other Deductions Other income and other deductions resulted in $29.9 million higher expense in 2003 compared to 2002. Interest expense was lower primarily due to the $3 million charge recorded in 2002 associated with the October 10, 2002 FERC order in Transco’s 1999 fuel tracker proceeding. The lower interest income – affiliates of $8.1 million was primarily due to a reduction in intercompany demand notes resulting from dividends paid to WGP. The allowance for funds used during construction was $17.5 million lower due to a lower amount of capital projects under construction. The impairment of an investment in an unconsolidated affiliate recorded in 2002 was due to the $12.3 million impairment of our investment in Independence Pipeline Company. Miscellaneous other (income) deductions, net reflected higher deductions primarily as a result of a gain of $11.0 million recorded in 2002 associated with the disposition of securities received through a mutual insurance company reorganization.

2002 COMPARED TO 2001

     Operating Income and Net Income Our operating income for 2002 was $300.8 million compared to operating income of $235.6 million for 2001. Net income for 2002 was $163.0 million compared to net income of $132.6 million for 2001.

     The higher operating income of $65.2 million was primarily the result of higher gas transportation demand revenues, the effects of the favorable settlement of our general rate case (Docket No. RP01-245) totaling $12.2 million in 2002, an $18.3 million charge to other operating costs and expenses in 2001 resulting from an unfavorable court decision, partially offset by a $17 million charge to other operating costs and expenses in 2002 associated with a FERC penalty, and other items, as discussed below. The increase in net income was attributable to the increase in operating income, partially offset by the higher deductions, as discussed below.

     Transportation Revenues Our operating revenues related to transportation services increased $79 million to $744 million for 2002 when compared to 2001. The higher transportation revenues were primarily due to increased demand revenues of $69.5 million resulting from (1) new expansion projects (MarketLink Phase 1 and Sundance, placed into service on December 19, 2001 and May 1, 2002, respectively) and (2) new rates to recover costs associated with increased rate base, rate of return and expenses contained in our general rate case (Docket No. RP01-245), which was effective September 1, 2001; the recognition of $11.0 million of revenues associated with the reversal of rate refund liabilities and other adjustments pursuant to the settlement of the general rate case in the third quarter of 2002.

     Our total market-area deliveries for 2002 increased 189.6 TBtu, or 13%, when compared to 2001. This is primarily the result of increased deliveries associated with new expansion projects and peaking power plants. Our production area deliveries decreased 22.3 TBtu, or 11%, when compared to 2001. This is primarily due to lower interruptible transportation, resulting from lower deliveries to other pipelines in the production area.

     Sales Revenues Our operating revenues related to sales services, including our cash out sales in settlement of gas imbalances, decreased $284 million to $381 million for 2002, when compared to 2001. The decrease was primarily due to a lower average sales price of $3.29 per dt in 2002 versus $5.08 per dt in 2001 and a lower volume of merchant sales.

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     Storage Revenues Our operating revenues related to storage services decreased $5 million to $136 million for 2002 when compared to 2001. This revenue decrease was primarily due to lower demand revenues in 2002 resulting from the effects of our general rate case (Docket No. RP01-245), which was effective September 1, 2001, and decreased revenues to recover lower storage rates charged by others.

     Other Revenues Other operating revenues increased $5 million to $15 million for 2002 when compared to 2001, primarily due to higher environmental mitigation credit sales and services of $9 million partially offset by lower interest received on late payments from customers and lower liquids revenues.

     Operating Costs and Expenses Excluding the cost of natural gas sales of $381 million and $665 million for 2002 and 2001, respectively, our operating expenses were approximately $14 million higher in 2002 compared to 2001. The higher cost of natural gas transportation, administrative and general expense, and depreciation and amortization expense were partially offset by lower operation and maintenance expense, lower taxes other than income taxes and lower other operating costs and expenses. The higher cost of natural gas transportation of $6.4 million was primarily due to a $5.2 million reduction in 2001 related to regulatory approval of the recovery of prior year’s gas costs in our 1999 fuel tracker filing, partially offset by lower tracked fuel expense of $5.2 million in 2002 and a $3.4 million charge in 2001 for transportation and exchange gas imbalances resulting from Enron Corp.’s bankruptcy filing. The higher administrative and general expense of $22.1 million was primarily due to higher employee benefits expenses, which includes an additional pension benefit expense of $6.8 million associated with an enhanced-benefit early retirement option offered to certain Williams employee groups, the recording of $1.8 million of severance costs applicable to employees whose positions have been eliminated, a $3.6 million charge related to a cancelled computer systems project and higher property and liability insurance of $3.3 million. Depreciation and amortization increased $9.0 million due to plant and property additions and $5.0 million due to increased environmental mitigation development costs. These depreciation and amortization increases were partially offset by a decrease of $1.1 million in connection with the settlement of the general rate case (Docket No. RP01-245) in the third quarter of 2002. The lower operation and maintenance expense of $11.4 million was primarily attributable to decreases in contractual and professional services of $3.5 million, telecommunications costs of $1.6 million and other supplies and expenditures of $2.7 million. The lower taxes other than income taxes of $5.5 million was primarily due to a refund of state franchise taxes. The lower other operating costs and expenses of $10.1 million was primarily due to a charge of $18.3 million recorded in 2001 associated with the unfavorable court decision in our royalty claims proceeding with Texaco, Inc. and lower charitable contributions of $8.3 million in 2002, partially offset by a $17 million charge in 2002 associated with a FERC penalty (see “Item 8. Financial Statements and Supplementary Data — Notes to Consolidated Financial Statements – 2. Contingent Liabilities and Commitments — Rate and Regulatory Matters”).

     Other Income and Other Deductions Other income and other deductions resulted in $5.7 million higher deductions in 2002 compared to 2001. Interest expense was $3.5 million higher primarily due to a greater level of long-term debt outstanding in 2002 and the $3 million charge associated with the October 10, 2002 FERC order in our 1999 fuel tracker proceeding, mostly offset by the accruals in 2001 resulting from the unfavorable court decision in our royalty claims proceeding with Texaco, Inc. Interest income from affiliates was $4.3 million lower due primarily to lower interest rates, which are based on the London Interbank Offering Rate (LIBOR), on intercompany demand notes. The impairment of an investment in an unconsolidated affiliate in 2002 was due to the $12.3 million impairment of our investment in Independence Pipeline Company resulting from the FERC’s issuance of an order on July 19, 2002, vacating Independence’s certificate to construct the Independence Pipeline project. Miscellaneous other (income) deductions, net reflected higher income of $11.9 million primarily as a result of a gain of $11.0 million associated with the

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disposition of securities received through a mutual insurance company reorganization and lower costs of $2.9 million related to our sale of receivables program which expired in July 2002.

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 maintenance and operating costs. 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 inventory is subject to ratemaking treatment, and under current FERC practices, recovery is limited to historical costs. While amounts in excess of historical cost are not recoverable under current FERC practices, we believe that we will be allowed to recover and earn a return based on increased actual cost 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, by repayments of funds advanced to WGP, by accessing capital markets, and, if required, by borrowings under the Credit Agreement and advances from WGP. Historically, we also funded our capital requirements through a sale of receivables program. In July 2002, our sale of receivables program expired and was not renewed.

     We have an effective registration statement on file with the Securities and Exchange Commission. At December 31, 2003, $200 million of shelf availability remains under this registration statement which may be used to issue debt securities. However, the ability to utilize this registration statement is currently restricted by certain covenants associated with Williams’ $800 million 8.625% senior unsecured notes that were issued in 2003. Interest rates and market conditions will affect amounts borrowed, if any, under this arrangement. 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.

     On June 6, 2003, Williams entered into a two-year $800 million revolving and letter of credit facility (Credit Agreement), primarily for the purpose of issuing letters of credit. Williams, Transco and Northwest Pipeline Corporation, a subsidiary of WGP, have access to all unborrowed amounts under the facility. The facility must be secured by cash and/or acceptable government securities with a market value of at least 105% of the then outstanding aggregate amount available for drawing under all letters of credit, plus the aggregate amount of all loans then outstanding. The new credit facility replaced a $1.1 billion credit line entered into in July 2002 that was comprised of a $700 million revolving credit facility and a $400 million letter of credit facility secured by substantially all of Williams’ midstream assets. The lenders released these assets as collateral upon repayment of the old credit facility, and they were not pledged in support of the new facility. The interest rate on the new facility is variable at the LIBOR plus 0.75% or 1.87% at December 31, 2003. As of December 31, 2003, letters of credit totaling $353 million have been issued by the participating financial institutions under this facility and remain outstanding. No revolving credit loans were outstanding. At December 31, 2003, the amount of restricted investments securing this facility was $381 million, which collateralized the facility at approximately 108%.

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     On July 3, 2002, we issued $325 million of Series A notes (8.875% Notes), which pay interest on January 15 and July 15 each year, beginning January 15, 2003. The 8.875% Notes were issued at a discount to yield 9.25%. The 8.875% Notes mature on July 15, 2012, but are subject to redemption anytime, at our option, in whole or part, at a specified redemption price, plus accrued and unpaid interest to the date of redemption. In January 2003, we completed the exchange of all the Series A notes for an equal amount of Series B notes. We did not receive any cash proceeds from this exchange. The terms of the Series B notes are substantially identical to those of the Series A notes, except that the transfer restrictions and registration rights relating to the Series A notes do not apply to the Series B notes. The net proceeds of the sale of the 8.875% Notes were used to repay $150 million of variable rate notes that matured on July 31, 2002 and $125 million of 8 7/8% Notes that matured on September 15, 2002 and for general corporate purposes.

     As a participant in Williams’ cash management program, we have advances to and from Williams through our parent company, WGP. At December 31, 2003, the advances due to us by WGP totaled $47.5 million. The advances are represented by demand notes. Effective September 2003, the interest rate on intercompany demand notes is based upon the weighted average cost of Williams’ debt outstanding at the end of each quarter. Previously, the interest rate on intercompany demand notes was based on the LIBOR plus an applicable margin. Williams has indicated that it currently believes that it will continue to have the financial resources and liquidity to repay these advances made by WGP which in turn allows WGP to repay us.

     On August 1, 2002, the FERC issued a Notice of Proposed Rulemaking (NOPR) that proposed restrictions on various types of cash management programs employed by companies in the energy industry such as Williams and its subsidiaries, including us. In addition to stricter guidelines regarding the accounting for and documentation of cash management or cash pooling programs, the FERC proposal would have precluded public utilities, natural gas companies and oil pipeline companies from participating in such programs unless the parent company and its FERC-regulated affiliate maintain investment-grade credit ratings and the FERC-regulated affiliate maintains stockholder’s equity of at least 30% of total capitalization. On June 26, 2003, the FERC issued an Interim Rule (Order No. 634), which replaces the earlier NOPR on cash management described above. The Interim Rule requires FERC-regulated entities to have their cash management programs in writing and to have all such programs specify (i) the duties and responsibilities of administrators and participants, (ii) the methods for calculating interest and for allocating interest and expenses, and (iii) restrictions on borrowing from the programs. The Interim Rule also sought industry comment on new reporting requirements that would require FERC-regulated entities to file their cash management programs with the FERC and to notify the FERC when their proprietary capital ratio drops below 30% of total capitalization and when it subsequently returns to or exceeds 30%. On October 23, 2003, the FERC issued Order No. 634-A, which adopted the filing and reporting requirements proposed in the Interim Rule, with certain modifications. On February 11, 2004, the FERC issued a Final Rule (Order No. 646), which amends its financial reporting regulations and as part of those amendments eliminated the notification requirement related to a FERC-regulated entity’s proprietary capital ratio adopted in Order No 634-A. The FERC found that the amended financial reporting requirements will provide the FERC with the information necessary to monitor the FERC-regulated entity’s proprietary capital ratio.

     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” and amended by SFAS No. 138, “Accounting for Certain Derivatives Instruments and Certain Hedging Activities.” We adopted these standards effective January 1,

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2001. 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, 2003 and 2002, our equity interest in an unrealized loss on Pine Needle’s hedge was $1.1 million and $1.7 million, respectively. The swap agreement initially had a notional amount of $53.5 million of debt, of which $49.8 million was still outstanding at December 31, 2003. 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).

     In the second quarter of 2003, Moody’s Investors Services and Fitch Ratings raised the credit ratings on our senior unsecured long-term debt as shown below. The rating given by Standard & Poor’s is B+ which did not change during 2003.

     Currently, Moody’s Investors Service and Standard & Poor’s have our credit ratings on “developing outlook” and “negative outlook”, respectively. During 2002, our credit ratings were downgraded to below investment grade due to concerns about the sufficiency of Williams’ operating cash flow in relation to its debt as well as the adequacy of Williams’ liquidity. The credit rating level has remained below investment grade throughout 2003. The ratings remain under review pending the execution of Williams’ plan to strengthen its financial position. We expect that interest rates on future financings will be reflective of the ratings at the time of the financing.

CAPITAL EXPENDITURES

     As shown in the table below, our capital expenditures and investments in affiliates for 2003 included $105 million for market-area projects, primarily for the Momentum, Trenton-Woodbury and MarketLink projects, $12 million for supply-area projects and $78 million for maintenance of existing facilities and other projects. We are estimating approximately $191 million of capital expenditures in the year 2004 related to expansion projects in the market area, primarily the Momentum project, supply area projects and the maintenance of existing facilities, including expenditures required under the Federal Clean Air Act and Clean Air Act Amendments of 1990 and the Pipeline Safety Improvement Act of 2002.

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OTHER CAPITAL REQUIREMENTS, CONTRACTUAL OBLIGATIONS AND CONTINGENCIES

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

(1) Includes 10 years of pipeline easement obligations for contracts with indefinite termination dates.

     Not included in the total contractual obligations is a $3 million monthly obligation to an affiliate associated with an operating agreement whereby the affiliate operates many of our production area facilities. The operating agreement can be terminated by either party with thirty days notice. FERC Order No. 2004 may require that this contract be terminated by June 1, 2004.

     Rate and regulatory refunds As discussed in Note 2 of the Notes to Consolidated Financial Statements included in Item 8 herein, we filed a general rate case (Docket No. RP01-245) and placed new rates into effect on September 1, 2001. On July 23, 2002, the FERC issued an order approving the Settlement in the rate case. The Settlement became effective October 1, 2002. Rate refunds required under

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the Settlement, covering the period September 1, 2001 through September 30, 2002, totaled approximately $140 million, including interest, and were paid in late November 2002.

     Regulatory and legal proceedings As discussed in Note 2 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 2 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 WGP, advances from Williams and borrowings under the Credit Agreement will provide us with sufficient liquidity to meet our capital requirements. When necessary, we also expect to 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

     At December 31, 2003, our debt portfolio included only fixed rate issues. The following table provides information about our long-term debt, including current maturities, as of December 31, 2003. The table presents principal cash flows and weighted-average interest rates by expected maturity dates.

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ITEM 8. Financial Statements and Supplementary Data

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REPORT OF INDEPENDENT AUDITORS

The Board of Directors
Transcontinental Gas Pipe Line Corporation

     We have audited the accompanying consolidated balance sheets of Transcontinental Gas Pipe Line Corporation as of December 31, 2003 and 2002, and the related consolidated statements of income, common stockholder’s equity, comprehensive income, and cash flows for each of the three years in the period ended December 31, 2003. 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 auditing standards generally accepted in the 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. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as 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, 2003 and 2002, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2003, in conformity with accounting principles generally accepted in the United States. 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.

                   /s/ ERNST & YOUNG LLP

Houston, Texas
February 18, 2004

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TRANSCONTINENTAL GAS PIPE LINE CORPORATION

CONSOLIDATED STATEMENT OF INCOME
(Thousands of Dollars)

See accompanying notes.

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TRANSCONTINENTAL GAS PIPE LINE CORPORATION

CONSOLIDATED BALANCE SHEET
(Thousands of Dollars)

See accompanying notes.

31

TRANSCONTINENTAL GAS PIPE LINE CORPORATION

CONSOLIDATED BALANCE SHEET
(Thousands of Dollars)

See accompanying notes.

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TRANSCONTINENTAL GAS PIPE LINE CORPORATION

CONSOLIDATED STATEMENT OF COMMON STOCKHOLDER’S EQUITY
(Thousands of Dollars)

See accompanying notes.

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TRANSCONTINENTAL GAS PIPE LINE CORPORATION

CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME
(Thousands of Dollars)

See accompanying notes.

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TRANSCONTINENTAL GAS PIPE LINE CORPORATION

CONSOLIDATED STATEMENT OF CASH FLOWS
(Thousands of Dollars)

35

TRANSCONTINENTAL GAS PIPE LINE CORPORATION

CONSOLIDATED STATEMENT OF CASH FLOWS
(Thousands of Dollars)

See accompanying notes.

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TRANSCONTINENTAL GAS PIPE LINE CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

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

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

     Nature of operations We are an interstate natural gas transmission company which 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 reasonable to assume 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, employee related benefits, 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. At December 31, 2003, we had approximately $144 million of regulatory assets included in Other Assets and approximately $51 million of regulatory liabilities included in Other Long-Term Liabilities: Other in the

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accompanying Consolidated Balance Sheet. At December 31, 2002, we had approximately $138 million of regulatory assets included in Other Assets and approximately $49 million of regulatory liabilities included in Other Long-Term Liabilities: Other in the accompanying Consolidated Balance Sheet.

     Basis of presentation The acquisition of Transco Energy Company (TEC) and its subsidiaries, including us, by Williams 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. 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 through our parent company, WGP. 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. Effective September 2003, the interest rate on intercompany demand notes is based upon the weighted average cost of Williams’ debt outstanding at the end of each quarter. Previously, the interest rate on intercompany demand notes was based on the London Interbank Offering Rate (LIBOR) plus an applicable margin.

     Through an agency agreement, Williams Power Company (WPC) (formerly Williams Energy Marketing & Trading Company), an affiliate of ours, manages all jurisdictional merchant gas sales for us, receives all margins associated with such business and, as our agent, assumes all market and credit risk associated with our jurisdictional merchant gas sales. Consequently, our merchant gas sales have no impact on our operating income or results of operations. For a discussion of a settlement with the FERC affecting our jurisdictional merchant gas sales, see “Note 2. Contingent Liabilities and Commitments.”

     Our Board of Directors declared cash dividends on common stock in the amounts of $85 million on March 31, 2003, $70 million on June 30, 2003, $50 million on September 30, 2003, and $40 million on December 31, 2003.

     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 percent to 50 percent of the voting common stock or otherwise exercise significant influence over operating and financial policies of the company are accounted for under the equity method. The equity investments as of December 31, 2003 and 2002 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%.

     Use of estimates The preparation of financial statements in conformity with accounting principles generally accepted in the United States 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

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

     Contingent liabilities We record liabilities for estimated loss contingencies when we assess that a loss is probable and the amount of the loss can be reasonably estimated. Revisions to contingent liabilities are reflected in income in the period in which new or different facts or information become known or circumstances change that affect the previous assumptions with respect to the likelihood or amount of loss. Liabilities for contingent losses are based upon our assumptions and estimates, advice of legal counsel or other third parties regarding the probable outcomes of the matter. 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.

     Property, plant and equipment Property, plant and equipment is recorded at cost, adjusted in 1995 to reflect the allocation of the purchase price as discussed above. 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 net 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. Depreciation rates used for major regulated gas plant facilities at December 31, 2003, 2002, and 2001 are as follows:

     Under the terms of a settlement in our general rate case in Docket No. RP01-245, which established rates effective September 1, 2001, we agreed to reduce the depreciation rate for small offshore transmission facilities and discontinue depreciation on onshore production and gathering facilities. The reduction in the depreciation rate had no effect on operating or net income due to an offsetting reduction in operating revenues, but did result in lower cash flows from operations. The reduction in the rate was recorded in 2002, retroactive to September 1, 2001.

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     Effective January 1, 2003, Williams and its subsidiaries, including us, adopted SFAS No. 143, “Accounting for Asset Retirement Obligations.” The statement requires that the fair value of a liability for an asset retirement obligation (ARO) be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made, and that the associated asset retirement costs be capitalized as part of the carrying amount of the long-lived asset.

     We have determined that asset retirement obligations exist for our offshore transmission platforms. At the end of the useful life of each respective asset, we are legally obligated to dismantle offshore transmission platforms. The asset retirement obligation as of December 31, 2003 was $11.6 million.

     Included in our depreciation rates is a negative salvage (cost of removal) component that we currently collect in rates. We therefore accrue the estimated costs of removal of long-lived assets through depreciation expense. In connection with the adoption of SFAS No. 143, a portion of the negative salvage component of Accumulated Depreciation equal to the asset retirement obligation was reclassified to a Noncurrent ARO Regulatory Liability.

     We have not recorded asset retirement liabilities for pipeline transmission assets and gas gathering systems. A reasonable estimate of the fair value of the retirement obligations for these assets cannot be made as the remaining life of these assets is not currently determinable. In connection with the adoption of SFAS No. 143, the remaining portion of the negative salvage component of Accumulated Depreciation that represents cost of removal for pipeline transmission assets and gas gathering systems was reclassified to a Noncurrent Regulatory Liability, which totaled $25.2 million as of December 31, 2003.

     In connection with the adoption of SFAS No. 143, the negative salvage component of Accumulated Depreciation of $35.0 million as of December 31, 2002 was reclassified to a Noncurrent Regulatory Liability in the accompanying Consolidated Balance Sheet.

     The adoption of SFAS No. 143 did not have a material impact to our operating income or net income.

     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. Beginning January 1, 2002, the impairment evaluation of tangible long-lived assets is measured pursuant to the guidelines of SFAS No. 144. 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, 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 redetermined when related events or circumstances change.

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     We evaluate our 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 $3.7 million, $7.9 million, and $7.4 million, for 2003, 2002 and 2001, respectively. The allowance for equity funds was $9.3 million, $22.7 million, and $21.6 million, for 2003, 2002 and 2001, 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. Due to our customer base, we have not historically experienced recurring credit losses in connection with our receivables. As a result, receivables determined to be uncollectible are fully written off in the period of such determination. At December 31, 2003 and 2002, we had no allowance for doubtful accounts.

     Securitizations and transfers of financial instruments Through July 2002, we had agreements to sell, on an ongoing basis, certain of our trade accounts receivable through revolving securitization structures under which we retained servicing responsibilities as well as a subordinate interest in the transferred receivables. We accounted for the securitization of trade accounts receivable in accordance with SFAS No. 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities.” As

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a result, the related receivables were removed from the Consolidated Balance Sheet and a retained interest was recorded for the amount of receivables sold in excess of cash received. The sale of receivables program expired on July 25, 2002 and was not renewed.

     We determined the fair value of our retained interests based on the present value of future expected cash flows using our management’s best estimates of various factors, including credit loss experience and discount rates commensurate with the risks involved. These assumptions were updated periodically based on actual results, thus the estimated credit loss and discount rates utilized were materially consistent with historical performance. The fair value of the servicing responsibility was estimated based on internal costs, which approximate market. Costs associated with the sale of receivables are included in miscellaneous other (income) deductions, net on the Consolidated Statement of Income.

     Advances to affiliates As a participant in Williams’ cash management program, we make advances to and receive advances from Williams through WGP. The advances are represented by demand notes. Advances are stated at the historical carrying amounts. Interest income is recognized when chargeable and collectibility is reasonably assured. Effective September 2003, the interest rate on intercompany demand notes is based upon the weighted average cost of Williams’ debt outstanding at the end of each quarter. Previously, the interest rate on intercompany demand notes was based on the LIBOR plus an applicable margin.

     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 generated after August 1, 1991 are settled on a monthly basis. Imbalances predating August 1, 1991 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, 2003 and 2002.

     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, 2003 is approximately $26 million. The basis for determining current cost is the December 2003 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.

     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.

     Comprehensive income In 1998, Pine Needle executed an interest rate swap agreement with a bank, which swapped floating rate debt into 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

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Derivative Instruments and Hedging Activities” and amended by SFAS No. 138, “Accounting for Certain Derivatives Instruments and Certain Hedging Activities.” We adopted these standards effective January 1, 2001. As such, our equity interest in the changes in fair value of Pine Needle’s hedge is recognized in other comprehensive income (loss), net of tax.

     At December 31, 2002, we recorded a minimum pension liability of $7.4 million, net of $4.6 million tax, which was included as a component of our other comprehensive loss for the year 2002. The minimum pension liability was reversed in 2003.

     Employee stock-based awards Employee stock-based awards are accounted for under Accounting Principles Board (APB) Opinion No. 25, “Accounting for Stock Issued to Employees” and related interpretations. Williams’ fixed-plan common stock options generally do not result in compensation expense because the exercise price of the stock options equals the market price of the underlying stock on the date of grant. The Williams’ plans are described more fully in Note 4. The following table illustrates the effect on our net income if we had applied the fair value recognition provisions of SFAS No. 123,“Accounting for Stock-Based Compensation”.

     Pro forma amounts for 2003 include compensation expense from awards made in 2003, 2002 and 2001. Also included in the 2003 pro forma expense is $0.4 million of incremental expense associated with a stock option exchange program (See Note 4). Pro forma amounts for 2002 include compensation expense from awards made in 2002 and 2001 and from certain awards made in 1999. Pro forma amounts for 2001 include compensation expense from awards made in 2001 and from certain awards made in 1999.

     Since compensation expense from stock options is recognized over the future years’ vesting period for pro forma disclosure purposes and additional awards are generally made each year, pro forma amounts may not be representative of future years’ amounts.

     Recent accounting standards The FASB issued SFAS No. 146, “Accounting for Costs Associated with Exit or Disposal Activities.” This statement addresses financial accounting and reporting for costs associated with exit or disposal activities and nullifies Emerging Issues Task Force (EITF) Issue No. 94-3,“Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring).” This statement requires that a liability for a cost associated with an exit or disposal activity be recognized and measured initially at fair value only when the liability is incurred. The provisions of the statement are effective for exit or disposal activities that are initiated

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after December 31, 2002; hence, initial adoption of this statement on January 1, 2003, did not have any impact on our results of operations or financial position.

     The FASB issued SFAS No. 148, “Accounting for Stock-Based Compensation – Transition and Disclosure,” which is effective for fiscal years ending after December 15, 2002. SFAS No. 148 amends SFAS No. 123, “Accounting for Stock-Based Compensation,” to permit two additional transition methods for a voluntary change to the fair value based method of accounting for stock-based employee compensation from the intrinsic method under APB Opinion No. 25, “Accounting for Stock Issued to Employees.” The prospective method of transition under SFAS No.123 is an option to the entities that adopt the recognition provisions under this statement in a fiscal year beginning before December 15, 2003. In addition, SFAS No.148 amends the disclosure requirements of SFAS No.123 to require prominent disclosures in both annual and interim financial statements concerning the method of accounting used for stock-based employee compensation and the effects of that method on reported results of operations. Under SFAS No.148, pro forma disclosures are required in a specific tabular format in the “Summary of Significant Accounting Policies”. We have adopted the disclosure requirements of this statement effective December 31, 2002. The adoption had no effect on our consolidated financial position or results of operations. We continue to account for Williams’ stock-based compensation plans under APB Opinion No. 25. The FASB has announced it will be issuing an Exposure Draft on equity-based compensation. In deliberations on this matter, the FASB has concluded that equity-based compensation awards to employees results in an expense to the employer that should be recognized in the income statement. See “Employee stock-based awards” in this note.

     The FASB issued FASB Interpretation (FIN) No. 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others.” This Interpretation requires the initial recognition at fair value of guarantees issued or modified after December 31, 2002, and expands the disclosure requirements for guarantees. Initial adoption of this Interpretation did not have any impact on our results of operations or financial position.

     In January 2003, the FASB issued Interpretation No. 46, “Consolidation of Variable Interest Entities.” The Interpretation defines a variable interest entity (VIE) as an entity in which equity investors do not have the characteristics of a controlling financial interest or do not have sufficient equity at risk for the entity to finance its activities without additional subordinated financial support from other parties. The investments or other interests that will absorb portions of the VIEs expected losses if they occur or receive portions of the VIEs expected residual returns if they occur are called variable interests. Variable interests may include, but are not limited to, equity interests, debt instruments, beneficial interests, derivative instruments and guarantees. The Interpretation requires an entity to consolidate a VIE if that entity will absorb a majority of the VIEs expected losses if they occur, receive a majority of the VIEs expected residual returns if they occur, or both. If no party will absorb a majority of the expected losses or expected residual returns, no party will consolidate the VIE. The Interpretation also requires disclosure of significant variable interests in unconsolidated VIEs. The Interpretation is effective for all new VIEs created or acquired after January 31, 2003. For VIEs created or acquired prior to February 1, 2003, the provisions of the Interpretation were initially to be effective for the first interim or annual period beginning after June 15, 2003. However, in October 2003, the FASB delayed the effective date of the Interpretation on the entities to the first period beginning after December 15, 2003. Additionally, in December 2003, the FASB issued a revision to the Interpretation to clarify certain provisions and to exempt certain entities from its requirements. The revised Interpretation will require full implementation in the first quarter of 2004. We do not have any VIEs as defined by the Interpretation.

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     EITF Issue No. 01-8, “Determining Whether An Arrangement Contains a Lease,” became effective on July 1, 2003 and provides guidance for determining whether certain contracts are executory service arrangements or leases pursuant to SFAS No. 13. A prospective transition is provided for whereby the consensus is to be applied to arrangements consummated or modified after July 1, 2003. We do not have any such agreements, as defined by the Interpretation, at December 31, 2003.

     Reclassifications Certain reclassifications have been made in the 2002 and 2001 financial statements to conform to the 2003 presentation.

2. CONTINGENT LIABILITIES AND COMMITMENTS

Rate and Regulatory Matters

     FERC enforcement matter By order dated March 17, 2003, the FERC approved a settlement between the FERC staff and Williams, WPC and us which resolved the FERC staff’s allegations during a formal, nonpublic investigation that WPC personnel had access to our data bases and other information, and that we had failed to accurately post certain information on our electronic bulletin board. Pursuant to the terms of the settlement agreement, we will pay a civil penalty in the amount of $20 million in five equal installments. We made the first payment on May 16, 2003, and the subsequent payments are due on or before the first, second, third and fourth anniversaries of the first payment. We recorded a charge to income and established a liability of $17 million in 2002 representing the net present value of the future payments. In addition, we have notified our Firm Sales (FS) customers of our intention to terminate the FS service effective April 1, 2005 under the terms of applicable contracts and the FERC certificates authorizing such services. As part of the settlement, WPC has 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. Finally, we have agreed to the terms of a compliance plan designed to ensure future compliance with the provisions of the settlement agreement and the FERC’s rules governing the relationship of Transco and WPC.

     General rate case (Docket No. RP01-245) On March 1, 2001, we submitted to the FERC a general rate filing principally designed to recover costs associated with an increase in rate base resulting from additional plant, an increase in rate of return and related taxes, and an increase in operation and maintenance expenses.

     In July, 2002, the FERC approved a Stipulation and Agreement (Settlement) which resolved all cost of service, throughput and throughput mix issues in this rate case proceeding with the exception of one cost of service issue related to the valuation of certain right-of-way access for the installation of a fiber optic system by a then Transco affiliate, the resolution of which is to be applied prospectively. In the third quarter of 2002, as a result of the FERC’s approval of the Settlement, we recorded additional revenues of $28 million, reduced depreciation expense by $3 million, reversed interest expense of $0.5 million, and reduced our estimated reserve for rate refunds by $24.5 million. Rate refunds required under the Settlement totaling approximately $140 million, including interest, were paid in November 2002. We had previously provided a reserve for the refunds. The other issues not resolved by the Settlement include various cost allocation, rate design and tariff matters.

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     On December 3, 2002, an Administrative Law Judge (ALJ) issued his initial decision on the issues not resolved by the Settlement. In the initial decision, the ALJ determined, among other things, that (1) our existing treatment of the arrangement with our former affiliate relating to right of way is just and reasonable (2) our proposal to roll-in the costs of the Cherokee, Pocono and SunBelt projects is unjust and unreasonable, and (3) our recovery of the costs of the Mobile Bay expansion project on a rolled-in basis is unjust and unreasonable. As to the Mobile Bay issue, the ALJ determined that we had the burden of establishing that roll-in of that project is just and reasonable, but did not address the issue of any potential refunds. Our current rates are based on the roll-in of the Mobile Bay expansion project. The ALJ’s initial decision is subject to review by the FERC.

     General rate case (Docket No. RP97-71) On November 1, 1996, we submitted to the FERC a general rate case filing principally designed to recover costs associated with increased capital expenditures.

     The filing also included a pro-forma proposal to roll-in the costs of our Leidy Line and Southern expansion incremental projects.

     All issues in this proceeding have been resolved through settlement or litigation, with the exception of the roll-in issues consolidated with Docket No. RP95-197, which is discussed below, and one issue remanded to the FERC by the United States Court of Appeals for the District of Columbia Circuit (D.C. Circuit Court) relating to the rate paid by a shipper under its firm transportation contract. The shipper has requested that the FERC reinstate its discounted transportation rate under the firm transportation contract effective on June 1, 2003 or as soon as possible thereafter, that we be directed to make refunds of amounts collected from the shipper in excess of the discounted rate since February 1, 2001, with interest, and that we be authorized to make billing adjustments to recover the cost of the refunds from our other shippers. The shipper’s request is pending before the FERC.

     General rate case (Docket No. RP95-197) Through settlement and litigation, all issues in this proceeding have been resolved, except a cost allocation issue related to our implementation of the roll-in of the costs of our Leidy Line and Southern Expansion projects.

     In April 1999, the FERC issued an order reversing a prior ALJ decision, and concluded that we had demonstrated that our proposed rolled-in rate treatment was just and reasonable. As a result, the FERC remanded to the ALJ issues regarding the implementation of our roll-in proposal. Several parties filed requests for rehearing of the FERC’s order but their requests, as well as subsequent court appeals, were denied.

     The ALJ generally ruled in favor of our implementation positions, with the major exception that the ALJ required that the roll-in of the costs of the incremental projects into Transco’s system rates be phased in over a three-year period. In October 2001,the FERC issued an order on the ALJ’s decision which generally upheld the decision, except that the FERC reversed the ALJ’s decision to phase the roll-in of the costs finding that the three-year phasing is not necessary in this case. In August 2002, we filed to implement, among other things, the FERC’s decision on the roll-in of the costs of the incremental Leidy Line and Southern expansion projects. On December 12, 2002, the FERC issued an order accepting our compliance filing effective October 1, 2002. On January 13, 2003, certain parties filed for rehearing of the FERC’s December 12, 2002 order, arguing that we improperly reallocated certain storage costs in implementing the roll-in.

     Gathering facilities spin-down order (Docket Nos. CP96-206-000 and CP96-207-000) In 1996, we filed an application with the FERC for an order authorizing the abandonment of certain facilities located

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onshore and offshore in Texas, Louisiana and Mississippi by conveyance to an affiliate,Williams Gas Processing — Gulf Coast Company (Gas Processing). The net book value of these facilities at December 31, 2003, was approximately $361 million. Concurrently, Gas Processing filed a petition for declaratory order requesting a determination that its gathering services and rates be exempt from FERC regulation under the NGA. The FERC issued an order dismissing our application and Gas Processing’s petition for declaratory order and in 2001, the FERC issued an order that denied our request for rehearing. Certain parties, including us, filed in the D.C. Circuit Court petitions for review of the FERC’s orders and in June 2003, those petitions were denied. Several parties petitioned the United States Supreme Court for review of the D.C. Circuit Court’s opinion, and on January 12, 2004, the Court denied those petitions.

     While the proceedings related to the 1996 application were pending, we filed with the FERC the applications described below seeking authorization to abandon portions of the facilities included in the 1996 application.

     North Padre Island/Central Texas Systems Spin-down Proceeding (Docket Nos. CP01-32 and CP01-34) In 2000, we filed an application with the FERC seeking authorization to abandon certain of our offshore Texas facilities by conveyance to Gas Processing. Gas Processing filed a contemporaneous request that the FERC declare that the facilities sought to be abandoned would be considered nonjurisdictional gathering facilities upon transfer to Gas Processing. The FERC approved the abandonment and the non-jurisdictional treatment of all of these facilities. Effective December 2001, we transferred to Gas Processing the North Padre Island facilities through a non-cash dividend of $3.3 million, which represents the net book value of the facilities as of that date. Parties filed petitions for review of the FERC’s 2001 order to the D.C. Circuit Court which were consolidated with the appeals of the FERC’s orders in CP96-206 and CP96-207, discussed above, and which were denied by the D.C. Circuit Court in its opinion issued in June, 2003. In 2001, Shell Offshore, Inc. filed a complaint at the FERC against Gas Processing, Williams Field Services Company (WFS) and us alleging concerted actions by these affiliates frustrated the FERC’s regulation of us. The alleged actions are related to offers of gathering service by WFS and its subsidiaries with respect to the North Padre Island facilities. In 2002, the FERC issued an order reasserting jurisdiction over that portion of the North Padre Island facilities previously transferred to WFS. The FERC also determined a gathering rate for service on these facilities, which is to be collected by us. Transco, Gas Processing and WFS each sought rehearing of the FERC’s order, and in May 2003, the FERC denied those requests for rehearing. Transco, Gas Processing and WFS have filed petitions for review of the FERC’s orders with the D.C. Circuit Court.

     With regard to the approval of the spin-down of the Central Texas facilities, a Transco customer filed a complaint with the FERC in Docket No. RP02-309 seeking the revocation of the FERC’s spin-down approval. In September 2002, the FERC issued an order requiring that, upon transfer of the Central Texas facilities, we acquire capacity on the transferred facilities and provide service to the existing customer under the original terms and conditions of service. Our request for rehearing was denied in May 2003. The FERC also required that we notify the FERC of Transco’s plans with regard to the transfer of the Central Texas facilities to Gas Processing. We replied that due to the numerous outstanding issues affecting the transfer of those facilities, we could not at that time predict the timing for the implementation of the transfer of the Central Texas facilities. We also filed a request for rehearing of the FERC’s May 2003 order. At December 31, 2003, the net book value of these facilities was $67 million including the Williams purchase price allocation pushed down to Transco.

     North High Island/West Cameron Systems and Central Louisiana System Spin-down Proceedings In 2001 the FERC issued orders authorizing us to spin down only a portion of these systems to

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Gas Processing. All legal challenges of these FERC orders have been exhausted. We have not yet transferred any of the facilities authorized for spin down.

     The net book value, at the application date, of the North High Island/West Cameron and Central Louisiana facilities included in these two applications was approximately $65 million including the Williams purchase price allocation pushed down to Transco.

     South Texas Pipeline Facilities Abandonment Proceeding In May 2003, the FERC denied our request to abandon the South Texas pipeline facilities by sale to a third party. On June 25, 2003, Transco and the third party purchaser announced that they had agreed to terminate the purchase and sale agreement for the facilities. We continue to pursue a sale of these facilities. The net book value of the South Texas pipeline facilities as of the date of our FERC application was approximately $32 million, including the Williams purchase price allocation pushed down to Transco.

     1999 Fuel Tracker (Docket No. TM99-6-29) On March 1, 1999, we made our annual filing pursuant to our FERC Gas Tariff to recalculate the fuel retention percentages applicable to our transportation and storage rate schedules, to be effective April 1, 1999. Included in the filing were two adjustments that increased the estimated gas required for operations in prior periods by approximately 8 billion cubic feet. Certain parties objected to the inclusion of those adjustments and the FERC accepted the filing to be effective April 1, 1999, subject to refund and to further FERC action. In subsequent orders, the FERC initially disallowed most of the adjustments, but later reconsidered that decision and allowed us to make the adjustments, with the requirement we collect the adjustments over a seven-year period. Although several of our customers filed for rehearing of the FERC’s decision to allow us to recover the adjustments, the FERC denied the request for rehearing, and an appeal of the FERC’s decision was filed but later dismissed. In the second quarter of 2001, we recorded a $15 million reduction in the cost of natural gas transportation and reduced the related interest expense by $3 million to reflect the regulatory approval to recover the cost of gas required for operations in prior periods.

     The FERC then issued orders in which it addressed our proposed method for recovering the permitted adjustments. The FERC determined that rather than collecting the revenue (including interest) represented by the adjustments, we should collect only the actual volumes comprising the adjustments. In the third quarter of 2002, as a result of the FERC’s determination, we recorded $3 million of interest expense that had been previously reduced in the second quarter of 2001. Certain customers filed requests for rehearing of the FERC’s decision, and the FERC denied those requests. Several parties have filed a joint petition for review in the D.C. Circuit Court of the FERC’s order. In accordance with the FERC’s order, on January 21, 2004 we distributed refunds and assessed surcharges to our customers for the period April 1, 1999 through March 31, 2003. We assessed further surcharges to our customers covering the period April 1, 2003 through January 31, 2004 on March 10, 2004. We implemented the revised fuel retention factors resulting from application of the FERC’s order on a prospective basis beginning February 1, 2004.

Legal Proceedings.

     Royalty claims and litigation 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

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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.

     As a result of these settlements, we have been sued by certain producers seeking indemnification. We are currently a defendant in one such lawsuit. Freeport-McMoRan, Inc., filed a lawsuit against us in the 19th Judicial District Court in East Baton Rouge, Louisiana in which it asserted damages, including interest calculated through December 31, 2003, of approximately $10 million. The case was tried in 2003 and resulted in a judgment favorable to us, which Freeport-McMoRan is appealing. On November 25, 2003, we settled a lawsuit filed by Mobil Producing Texas on August 30, 2000, in the 79th District Court, Brooks County, Texas, in which Mobil had asserted damages, including interest, of $8 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 has also filed claims against approximately 300 other energy companies and alleges that the defendants violated the False Claims Act in connection with the measurement, royalty valuation and purchase of hydrocarbons. The relief sought is 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, including the action filed against the Williams entities in the United States District Court for the District of Colorado. 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 remain pending against Williams, including us, and the other defendants.

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. On the basis of the findings to date, we estimate that over the next five years environmental assessment and remediation costs under TSCA, RCRA, CERCLA and comparable state statutes will total approximately $27 million to $30 million, measured on an undiscounted basis. This estimate depends upon a number of assumptions concerning the scope of remediation that will be required at certain

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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, 2003, Transco had a balance of approximately $28 million for these estimated costs recorded in current liabilities ($5 million) and other long-term liabilities ($23 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 been recorded as regulatory assets in current assets 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, the costs of which are included in the $27 million to $30 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 currently designated as non-attainment and we anticipate that during 2004 the EPA may designate additional new non-attainment areas which might impact our operations. Pursuant to non-attainment area requirements of the 1990 Amendments, and proposed EPA rules designed to mitigate the migration of ground-level ozone (NOx) in 22 eastern states, 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. Additionally, the EPA is expected to promulgate additional rules regarding hazardous air pollutants in 2004, which may impose controls in addition to the controls described above. 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 future cost in the range of $230 million to $260 million. If the EPA designates additional new non-attainment areas in 2004, which impact our operations, the cost of additions to property, plant and equipment is expected to increase. We are unable at

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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.

     Other claims An interconnected pipeline has informed us of a proposed adjustment to the volumes delivered to us at an interconnect meter station in Clinton Co., Pennsylvania related to the period July 2001 through June 2002 and for September 2002. The pipeline asserts that the adjustment is necessary because obstructions in the meter tubes affected readings at the meter station, resulting in an understatement of the volumes delivered to us during those periods. The pipeline initially claimed that an adjustment ranging from approximately 263,000 dt to 739,000 dt was necessary, but subsequently submitted to us an adjustment of approximately 697,000 dt. We have disputed all aspects of the adjustment, and have requested that the pipeline provide further support of its claim. The pipeline continues to request delivery of the 697,000 dt but has not yet substantiated its claim, and the parties are continuing to discuss the matter.

Safety Matters

     Proposed Pipeline Integrity Regulations In December 2003, the United States Department of Transportation Office of Pipeline Safety issued a final rule pursuant to the requirements of the Pipeline Safety Improvement Act of 2002 that was enacted in December 2002. The rule requires gas pipeline operators to develop integrity management programs for transmission pipelines that could affect high consequence areas in the event of pipeline failure, including a baseline assessment and periodic reassessments to be completed within specified timeframes. Currently, we estimate that the cost to perform required assessments and repairs will be between $190 million and $215 million over the 2003 to 2012 period. Management considers the costs associated with compliance with the proposed rule to be prudent costs incurred in the ordinary course of business and, therefore, recoverable through our rates.

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 We have commitments for construction and acquisition of property, plant and equipment of approximately $41 million at December 31, 2003 of which the majority relates to construction materials for pipeline expansion projects.

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3. DEBT, FINANCING ARRANGEMENTS AND LEASES

     Long-term debt At December 31, 2003 and 2002, long-term debt issues were outstanding as follows (in thousands):

     Aggregate minimum maturities applicable to long-term debt outstanding at December 31, 2003 are as follows (in thousands):

     There are no maturities applicable to long-term debt outstanding for the years 2004, 2006 and 2007.

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

     On June 6, 2003, Williams entered into a two-year $800 million revolving and letter of credit facility, primarily for the purpose of issuing letters of credit. Williams, Transco and Northwest Pipeline Corporation, a subsidiary of WGP, have access to all unborrowed amounts under the facility. The facility must be secured by cash and/or acceptable government securities with a market value of at least 105% of the then outstanding aggregate amount available for drawing under all letters of credit, plus the aggregate amount of all loans then outstanding. The new credit facility replaced a $1.1 billion credit line entered into in July 2002 that was comprised of a $700 million revolving credit facility and a $400 million letter of credit facility secured by substantially all of Williams’ midstream assets. The lenders released these assets as collateral upon repayment of the old credit facility, and they were not pledged in support of the new facility. The interest rate on the new facility is variable at the LIBOR plus 0.75% or 1.87% at December 31, 2003. As of December 31, 2003, letters of credit totaling $353 million have been issued by the participating financial institutions under this facility and remain outstanding. No revolving credit loans were outstanding. At December 31, 2003, the amount of restricted investments securing this facility was $381 million, which collateralized the facility at approximately 108%.

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     On July 3, 2002, we issued $325 million of Series A notes (8.875% Notes), which pay interest on January 15 and July 15 each year, beginning January 15, 2003. The 8.875% Notes were issued at a discount to yield 9.25%. The 8.875% Notes mature on July 15, 2012, but are subject to redemption anytime, at our option, in whole or part, at a specified redemption price, plus accrued and unpaid interest to the date of redemption. In January 2003, we completed the exchange of all the Series A notes for an equal amount of Series B notes. We did not receive any cash proceeds from this exchange. The terms of the Series B notes are substantially identical to those of the Series A notes, except that the transfer restrictions and registration rights relating to the Series A notes do not apply to the Series B notes. The net proceeds of the sale of the 8.875% Notes were used to repay $150 million of variable rate notes that matured on July 31, 2002 and $125 million of 8 7/8% Notes that matured on September 15, 2002 and for general corporate purposes.

     Restrictive covenants At December 31, 2003, none of our debt instruments restrict the amount of dividends distributable to WGP.

     Lease obligations Prior to December 23, 1998, we had a 20-year lease agreement for our headquarters building (Williams Tower) which expires in 2004 (Williams Tower lease). On December 23, 1998, we assigned and transferred to Laughton, L.L.C. (Laughton), an affiliate, all our rights, title and interest in the Williams Tower lease and entered into an agreement to sublease the premises from Laughton through March 29, 2003 (Williams Tower sublease). During 2003, we entered into an agreement with Laughton to extend the Williams Tower sublease through March 29, 2004. All other terms of the Williams Tower lease are incorporated into the Williams Tower sublease, including sublease agreements between us and other parties that also expire on March 29, 2004.

     On October 23, 2003, we entered into a new lease agreement for space in the Williams Tower. The lease term runs through March 31, 2014 with a one-time right to terminate on March 29, 2009. The net rentable area in the new lease is approximately 218,000 square feet. The net rentable area in the previous lease was approximately 1,005,000 square feet.

     The future minimum lease payments under our various operating leases, including the Williams Tower sublease, net of future minimum sublease receipts under our existing sublease agreements are as follows (in thousands):

     Our lease expense was $12.6 million in 2003, $16.6 million in 2002, and $15.2 million in 2001.

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4. EMPLOYEE BENEFIT PLANS

     Pension plan We participate in non-contributory defined-benefit pension plans with Williams and its subsidiaries that provide pension benefits for our retired employees. Cash contributions related to our participation in the plans totaled $13.4 million in 2003, $27.5 million in 2002 and $14.3 million in 2001.

     The allocation of the purchase price to the assets and liabilities of Transco and TEC based on estimated fair values resulted in the recording of an additional pension liability of $19.2 million, $17.3 million of which was recorded by us, representing the amount that the projected benefit obligation exceeded the plan assets. The amounts of pension costs deferred at December 31, 2003 and 2002 are $5.0 million and $6.4 million and are expected to be recovered through future rates over the average remaining service period for active employees.

     In April 2002, Williams sold securities that were received as a result of a mutual insurance company reorganization and associated with an annuity contract that was entered into by us to fund pension benefits of participants in a terminated pension plan. The disposition of the securities resulted in a gain of $11.0 million, which we recorded as miscellaneous other (income) deductions in the quarter ended June 30, 2002. Williams deposited the proceeds from the sale in the Williams Pension Plan as a cash contribution from us and this deposit is included in the cash contributions of $27.5 million for 2002 discussed above.

     Postretirement benefits other than pensions We participate in a plan with Williams and its subsidiaries that provides certain health care and life insurance benefits for our retired employees that were hired prior to January 1, 1996. The accounting for the plan anticipates future cost-sharing changes to the written plan that are consistent with Williams’ expressed intent to increase the retiree contribution rate annually, generally in line with health care cost increases. Cash contributions totaled $0.5 million in 2003, $5.4 million in 2002 and $10.4 million in 2001. 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 collected or refunded through future rate adjustments.

     The allocation of the purchase price to the assets and liabilities of Transco and TEC based on estimated fair values resulted in the recording of a postretirement benefits liability of $86.9 million representing the amount that the accumulated postretirement benefit obligation exceeded the plan assets. The amounts of postretirement benefits costs deferred as a regulatory asset at December 31, 2003 and 2002 are $30.3 million and $32.9 million, respectively, and are expected to be recovered through future rates over the remaining amortization period of the unrecognized transition obligation.

     Defined-contribution plan Our employees participate in a Williams defined-contribution plan. We recognized compensation expense of $4.6 million, $8.4 million and $5.8 million in 2003, 2002 and 2001, respectively.

     Employee stock-based awards On May 16, 2002, Williams stockholders approved The Williams Companies, Inc. 2002 Incentive Plan (the “Plan”). The Plan provides for common-stock-based awards to its employees and employees of its subsidiaries. Upon approval by the stockholders, all prior stock plans were terminated resulting in no further grants being made from those plans. However, options outstanding in those prior plans remain in those plans with their respective terms and provisions.

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     The Plan permits the granting of various types of awards including, but not limited to, stock options, restricted stock and deferred stock. Awards may be granted for no consideration other than prior and futures services or based on certain financial performance targets being achieved. The purchase price per share for stock options may not be less than the market price of the underlying stock on the date of grant. Stock options generally become exercisable after three years from the date of the grant and generally expire 10 years after grant.

     On May 15, 2003, Williams’ shareholders approved a stock option exchange program. Under this program, eligible employees were given a one-time opportunity to exchange certain outstanding options for a proportionately lesser number of options at an exercise price to be determined at the grant date of the new options. Surrendered options were cancelled June 26, 2003, and replacement options were granted on December 29, 2003. We did not recognize any expense pursuant to the stock option exchange. However, for purposes of pro forma disclosures, we recognized additional expense related to these new options. The remaining expense on the cancelled options will be amortized through year-end 2004.

     The following summary provides information about our employees’ stock option activity related to Williams common stock for 2003, 2002 and 2001 (options in thousands):

(1)

All of the 2003 stock options granted relate to the stock option exchange program described above.

(2)

Includes 1,856 options that were cancelled on June 26, 2003, under the stock option exchange program described above.

(3)

Effective with the spinoff of WilTel Communications (WilTel), formerly Williams Communications Group on April 23, 2001, by Williams, the number and exercise price of unexercised Williams stock options were adjusted to preserve the intrinsic value of the stock options that existed prior to the spinoff.

     The following summary provides information about Williams common stock options that are outstanding and exercisable by our employees at December 31, 2003 (options in thousands):

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     The estimated fair value at date of grant of options for Williams common stock granted in 2003, 2002 and 2001, using the Black-Scholes option pricing model, is as follows:

     (1) In 2003, the stock options granted to Transco employees were solely related to the employee stock option exchange described above. The weighted average fair value of these options is $1.58, which is the difference in the fair value of the new options granted and the fair value of the exchanged options. The assumptions used in the fair value calculation of the new options granted were: 1) dividend yield of 0.4 %; 2) volatility of 50 %; 3) weighted average expected remaining life of 3.4 years; and 4) weighted average risk free interest rate of 1.99 %.

     Pro forma net income, assuming we had applied the fair-value method of SFAS No. 123, “Accounting for Stock-Based Compensation” in measuring compensation cost beginning with 1997 employee stock-based awards, is disclosed under “Employee stock-based awards” in Note 1.

5. INCOME TAXES

     Following is a summary of the provision for income taxes for 2003, 2002 and 2001 (in thousands):