UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

FORM 10-K

For the Transition Period from _____________________ to _________________________

Commission File Number 1-7414

NORTHWEST PIPELINE CORPORATION

(801) 583-8800
(Registrant’s telephone number, including area code)

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]

State the aggregate market value of the voting stock held by non-affiliates of the registrant.

No voting stock of registrant is held by non-affiliates.

Indicate the number of shares outstanding of each of the registrant’s classes of common stock, as of the latest practicable date.

Documents Incorporated by Reference:
None

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

Table of Contents

TABLE OF CONTENTS

NORTHWEST PIPELINE CORPORATION

FORM 10-K

PART I

Item 1. BUSINESS

     In this report, Northwest Pipeline Corporation (“Northwest”) is at times referred to in the first person as “we”, “us” or “our”.

GENERAL

     Northwest 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 transportation company that owns and operates a natural gas pipeline system extending from the San Juan Basin in northwestern New Mexico and southwestern Colorado through the states of Colorado, Utah, Wyoming, Idaho, Oregon and Washington to a point on the Canadian border near Sumas, Washington. We provide services for markets in California, New Mexico, Colorado, Utah, Nevada, Wyoming, Idaho, Oregon and Washington directly or indirectly through interconnections with other pipelines. Our principal business is the interstate transportation of natural gas which is regulated by the Federal Energy Regulatory Commission (“FERC”).

PIPELINE SYSTEM AND CUSTOMERS

Transportation

     At December 31, 2003, our system, having long term firm transportation agreements with peaking capacity of approximately 3.4 MMDth* of gas per day, was composed of approximately 4,100 miles of mainline and lateral transmission pipelines, and 42 transmission compressor stations having a combined sea level-rated capacity of approximately 462,000 horsepower.

     In 2003, Pipeline transported natural gas for a total of 175 customers. We provide services for markets in California, New Mexico, Colorado, Utah, Nevada, Wyoming, Idaho, Oregon and Washington. Our transportation customers include distribution companies, municipalities, interstate and intrastate pipelines, gas marketers and direct industrial users. In 2003, our three largest transportation customers were Puget Sound Energy, Inc., Northwest Natural Gas Co., and Duke Energy Trading and Marketing LLC, which accounted for approximately 12.4 percent, 11.7 percent and 10.3 percent, respectively, of our total operating revenues. No other customer accounted for more than 10 percent of our total operating revenues in 2003. 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 and short-term firm transportation services.

     No other interstate natural gas pipeline company presently provides significant service to our primary gas consumer market area. However, competition with other interstate carriers exists for expansion markets. Competition also exists with alternate fuels. Electricity and distillate fuel oil are the primary alternate energy sources in the residential and commercial markets. In the industrial markets, high sulfur residual fuel oil is the main alternate fuel source.

*    The term “Mcf” means thousand cubic feet, “MMcf” means million cubic feet and “Bcf” means billion cubic feet. All volumes of natural gas are stated at a pressure base of 14.73 pounds per square inch absolute at 60 degrees Fahrenheit. The term “MMBtu” means one million British Thermal Units and “TBtu” means one trillion British Thermal Units. The term Dth means one dekatherm, which is equal to one MMBtu. The term MDth means thousand dekatherms. The term MMDth means million dekatherms.

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     We believe that demand for natural gas in the Pacific Northwest will continue to increase and the growing preference for natural gas in response to environmental concerns support future expansions of our mainline capacity.

     Underground gas storage facilities enable us to balance daily receipts and deliveries and provide storage services to certain major customers.

     We have a contract with a third party, under which gas storage services are provided to us in an underground storage reservoir in the Clay Basin Field located in Daggett County, Utah. We are authorized to utilize the Clay Basin Field at a seasonal storage level of 3.0 Bcf of working gas, with a firm delivery capability of 25 MMcf of gas per day.

     We own a one-third interest in the Jackson Prairie underground storage facility located near Chehalis, Washington, with the remaining interests owned by two of our distribution customers. Our share of the firm seasonal storage service is 6.4 Bcf of working gas capacity and up to 283 MMcf per day of peak day deliveries. Additionally, our share of the best-efforts delivery capacity is 50 MMcf per day.

     We also own and operate a liquefied natural gas (“LNG”) storage facility located near Plymouth, Washington, which provides standby service for our customers during extreme peaks in demand. The facility has a total LNG storage capacity equivalent to 2.3 Bcf of working gas, liquefaction capability of 12 MMcf per day and regasification capability of 300 MMcf per day. Certain of our major customers own the working gas stored at the LNG plant.

2003 Pipeline Breaks

     On May 1, 2003, a line break occurred on our 26-inch gas transmission pipeline near Lake Tapps in Pierce County, Washington. The line break did not result in ignition and there were no injuries. On May 2, 2003, the Office of Pipeline Safety (OPS) initiated an investigation and issued a Corrective Action Order (CAO) requiring us to reduce the pressure in our 26-inch line from Sumas to Washougal, Washington to 80% of Maximum Allowable Operating Pressure (MAOP), determine cause, and work to remedy the cause of the line break. We subsequently determined that the line break was caused by stress corrosion cracking (SCC) and implemented a variety of processes to ensure the integrity of our pipeline. Specifically, we completed surface and in-line inspection of certain segments of the line and were developing and executing plans to return the line to service prior to an additional line break occurring in December 2003.

     On December 13, 2003, we experienced another line break on the same line seventy miles south near Toledo, Washington. This line break occurred during pendency of the OPS CAO referred to above and the OPS issued an Amendment to the May 2 CAO as a result. This amendment requires us to idle the 26-inch line, conduct a detailed metallurgical analysis on the failure, finalize an integrity management program specifically for the 26-inch line, and develop a plan for the eventual replacement of the pipe. The Amendment also requires that we evaluate other facilities in the general area of the line breaks for susceptibility to SCC. We filed a request for hearing on December 29, 2003 to achieve clarity about certain requirements in the Amended CAO. This hearing occurred in Denver on January 21, 2004, and we are awaiting a final order. We continue to work closely with the OPS to obtain clarity in any requirements associated with restoring pressure in affected segments of the line, through a combination of hydrostatic testing and in-line inspection, by the summer of 2004. Working with customers, we have thus far been able to meet their firm nominations, and continue to work with customers to determine the extent to which the capacity of the 26-inch line will ultimately need to be replaced. The estimated combined cost to inspect, hydrostatically test, temporarily restore a portion of the line to service, and to ultimately replace up to the entire 360 MDth per day of capacity, if required, by the end of 2006 is estimated to range between $365 million and $430 million. Funding for these activities will be provided by the sources discussed below in Capital Resources and Liquidity, Method of Financing. (See Part II, Item 7.) We anticipate filing a rate case to recover these costs coincident with the in-service date of the facilities.

Expansion Projects

     On November 1, 2003, we placed into service most of the facilities associated with our Rockies Expansion Project, an expansion of our pipeline system designed to provide an additional 175 MDth per day of capacity to our transmission system in Wyoming and Idaho in order to reduce reliance on

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displacement capacity. The remaining facilities were placed into service on November 30, 2003. The project included the installation of 91 miles of pipeline loop and the upgrading or modification of six compressor stations for a total increase of 26,057 horsepower. A majority of our firm shippers agreed to support roll-in of the expansion costs into our existing rates. The estimated cost of the expansion project is approximately $140 million, of which approximately $16 million has been offset by settlement funds received from a former customer in connection with a contract restructuring.

     On October 1, 2003, we placed into service our Evergreen Expansion Project, an expansion of our pipeline system designed to provide 276,625 Dth per day of firm transportation service from Sumas, Washington to Chehalis, Washington to serve new power generation demand in western Washington. The project included installation of 28 miles of pipeline loop, upgrading, replacing or modifying five compressor stations and adding a net total of 64,160 horsepower of compression. The estimated cost of the expansion project is approximately $198 million, including the allocated portion of the Columbia Gorge Project discussed below. The Evergreen Expansion customers have agreed to pay for the cost of service of this expansion on an incremental basis.

     Our October 1, 2003, we placed into service our Columbia Gorge project, an expansion of our pipeline system designed to replace 56,000 Dth per day of northflow design displacement capacity from Stanfield, Oregon to Washougal, Washington. The project included upgrading, replacing or modifying five existing compressor stations and adding a net total of 23,900 horsepower of compression. A majority of our firm shippers have agreed to support roll-in of approximately 84 percent of the expansion costs into the existing rates with the remainder to be allocated to the incremental Evergreen Expansion Project customers. The estimated cost of the expansion project is approximately $43 million.

OPERATING STATISTICS

     The following table summarizes volumes and capacity for the periods indicated:

REGULATION

     We are subject to regulation by the FERC under the Natural Gas Act of 1938 (“NGA”) and under the Natural Gas Policy Act of 1978, and, as such, our rates and charges for the transportation of natural gas in interstate commerce, the extension, enlargement or abandonment of our jurisdictional facilities, and our 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 all pipelines, facilities and properties considered jurisdictional for which certificates are required 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, which regulates safety requirements in the design, construction, operation and maintenance of interstate gas transmission facilities.

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Other Regulatory Matters

     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.

Environmental Matters

     We are subject to the National Environmental Policy Act and other federal and state legislation regulating the environmental aspects of our business. Our management believes that we are in substantial compliance with existing environmental requirements. We believe that, with respect to any capital expenditures required to meet applicable standards and regulations, the FERC would grant the requisite rate relief so that, for the most part, such expenditures and a return thereon would be permitted to be recovered. We believe that compliance with applicable environmental requirements is not likely to have a material effect upon our earnings or financial position.

Safety Matters

     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 $75 million and $100 million over the 2003 to 2012 period. Developing and implementing the required public education program, including a process for measuring and evaluating the effectiveness of safety information distributed to various stakeholder groups, is expected to cost less than $1 million. Our management considers the costs associated with compliance with the rule to be prudent costs incurred in the ordinary course of business and, therefore, recoverable through our rates.

OWNERSHIP OF PROPERTY

     Our system is owned in fee simple. However, a substantial portion of our system is constructed and maintained pursuant to rights-of-way, easements, permits, licenses or consents on and across properties owned by others. Our compressor stations, with associated facilities, are located in whole or in part upon lands owned by us and upon sites held under leases or permits issued or approved by public authorities. The LNG facility is located on lands owned in fee simple by us. Various credit arrangements restrict the sale or disposal of a major portion of our pipeline system.

EMPLOYEE RELATIONS

     At December 31, 2003, we employed 375 persons, none of whom are represented under collective bargaining agreements. No strike or work stoppage in any of our operations has occurred in the past and relations with employees are good.

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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; and
•		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.

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.

RISKS AFFECTING OUR STRATEGY AND FINANCING NEEDS

     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:

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•		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 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 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.

     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 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.

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.

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     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.

     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 increased risk related to one or more of our assets.

     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 to 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 could 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 or alter the operation of those facilities, which might cause us to incur losses.

     Further, our regulatory rate structure and our contracts with clients 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.

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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, companies’ relationships with their independent auditors and retirement plan 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 could also 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.

     Accidents or other operating risks could further result in loss of service available to our customers. Such circumstances could adversely impact our ability to meet contractual obligations and retain customers. For example, our 26-inch segment of pipe from Sumas to Washougal, Washington was idled in 2003 after a line break associated with SCC. Efforts are underway to determine what measures are required to restore the capacity reduction resulting from the line break and satisfy customer needs. SCC is caused by a specific combination of stress and exposure to environmental factors such as soil acidity, moisture, and electro chemical properties that occurs in older pipelines. This type of corrosion cracking is a very complex technical phenomenon and, while the industry is making progress in developing methods to predict and identify SCC, there are still many unknowns. An integrity assessment of our pipeline is under way.

     Potential customer impact arising from our 2003 line break may include potential shortages in our ability to satisfy customer requirements, obligations to provide reservation charge credits to customers in times of constrained capacity, and solicitation of our existing customers by others for potential new pipeline projects that would compete directly with us. The size of reservation charge credits in particular is sensitive to actual market requirements and difficult to predict. From a market and rate recovery standpoint, it will be critical for us to expedite our response to the diminished capacity arising out of the 2003 line break. Critical to the ability to respond will be regulatory approval of any such response plan by the Department of Transportation — OPS and the Washington Utilities and Transportation commission. Such approvals will be subject to the same uncertainty inherent in any government approval process.

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

     Implementation of the 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 HCA’s. 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 HCA’s could result in significant additional costs. There is always the possibility that the assessments related to the IMP might 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.

     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

     Other than as described in Note 2 of the Notes to Financial Statements and above under Item 1 — Business, there are no material pending legal proceedings. We are subject to ordinary routine litigation incidental to our business.

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 wholly-owned by WGP, a wholly-owned subsidiary of Williams; therefore, our common stock is not publicly traded.

     We paid no cash dividends on common stock in 2002 or 2003.

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, financial condition and liquidity should be read in conjunction with the 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 financial statements and accompanying notes. Actual results could differ from those estimates.

Regulatory Accounting

     We are regulated by the FERC. Statement of Financial Accounting Standards (“SFAS”) No. 71, “Accounting for the Effects of Certain Types of Regulation,” provides that rate-regulated public utilities account for and report regulatory assets and liabilities consistent with the economic effect of the way in which regulators establish rates if the rates established are designed to recover the costs of providing the regulated service and if the competitive environment makes it 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, levelized depreciation 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 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 $16.1 million of regulatory assets included in Other Assets: Deferred Charges and approximately $11.8 million of regulatory liabilities included in Deferred Credits and Other Noncurrent Liabilities on the accompanying Balance Sheet. At December 31, 2002, we had approximately $14.1 million of regulatory assets included in Other Assets: Deferred Charges and approximately $11.0 million of regulatory liabilities included in Deferred Credits and Other Noncurrent Liabilities on the accompanying Balance Sheet.

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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 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 we collect 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 have no pending regulatory proceedings and no potential rate refunds.

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 management’s 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 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 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.

2003 PIPELINE BREAKS

     Reference is made to “Item 1. Business — 2003 Pipeline Breaks” on page 2.

WILLIAMS’ RECENT EVENTS

     In February 2003, Williams outlined its planned business strategy in response to the events that 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 asset sales, strategic levels of financing 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 capable of supporting and ultimately growing its remaining businesses.

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     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 cost debt.
•		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, a 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 plans 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; and
•		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.

RESULTS OF OPERATIONS

ANALYSIS OF FINANCIAL RESULTS

     This analysis discusses financial results of our operations for the years 2001 through 2003. Variances due to changes in price and volume have little impact on revenues, because under our rate design methodology, the majority of overall cost of service is recovered through firm capacity reservation charges in our transportation rates.

2003 COMPARED TO 2002

     Operating revenues increased $30.1 million, or 10 percent, due primarily to increased facility charge revenues of $17.3 million from incremental projects placed in service in late 2002, new revenues of $9.9 million from the Evergreen Project that was placed in service on October 1, 2003 and higher short term firm transportation revenues of $6.5 million primarily due to the execution of several maximum rate contracts during the second quarter of 2003 with primary terms that extend through July 2003, October 2003 and April 2004. These increases were partially offset by a decrease in firm transportation of approximately $3.7 million.

     Our transportation service accounted for 94 percent and 95 percent of operating revenues for the years ended December 31, 2003 and 2002, respectively. Additionally, 3 percent of operating revenues represented gas storage service in each of the years ended December 31, 2003 and 2002.

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     Operating expenses increased $29.8 million, or 19 percent, due primarily to a write-off of capitalized software development costs of $25.6 million associated with a service delivery system. Subsequent to the implementation of this system at Transcontinental Gas Pipe Line Corporation (“Transco”), a subsidiary of WGP, in the second quarter of 2003 and a determination of the unique and additional programming requirements that would be needed to complete the system for us, our management determined that the system would not be implemented. Depreciation expense increased $7.7 million due primarily to the increase in property resulting from completion of recent construction projects. Ad valorem taxes increased $6.5 million primarily due to the recently completed construction projects and other changes in state taxes. These increases were partially offset by the establishment of regulatory assets and the related regulatory credits approved by the FERC of approximately $6.4 million for the Evergreen Project. (Reference is made to the Property, Plant and Equipment policy in Note 1 of the Notes to Financial Statements for information about regulatory assets and regulatory credits.) A $3.9 million expense in 2002 for an enhanced benefit early retirement option offered to certain Williams employee groups also reduced the increase in operating expenses.

     Interest on long-term debt increased $11.6 million due to the March 4, 2003, $175 million debt issuance of 8.125 percent senior notes due 2010.

2002 COMPARED TO 2001

     Operating revenues increased $12.4 million, or 4 percent, due primarily to facility charge revenues of $3.6 million from incremental projects put into service during 2002, new reservation charges of approximately $1.5 million and higher short term firm transportation revenues of $6.4 million, partially offset by a $1.6 million decrease in tracked fuel costs and Gas Research Institute charges billed to customers.

     Our transportation service accounted for 95 percent of operating revenues for each of the years ended December 31, 2002 and 2001. Additionally, 3 percent of operating revenues represented gas storage service in each of the years ended December 31, 2002 and 2001.

     Operating expenses increased $3.2 million, or 2 percent, due primarily to a $6.6 million increase in retirement plan expenses, including $3.9 million related to an enhanced-benefit early retirement option offered to certain Williams employee groups, higher allocated general and administrative costs from Williams, and a $1.1 million charge for an abandoned project. These increases were partially offset by the decrease in tracked fuel costs and Gas Research Institute charges collectible from customers, a $1.2 million reduction in employee benefit costs and $3.8 million lower labor and other employee related costs resulting primarily from recent staff reductions in connection with the early retirement option and organizational changes across Williams. The increased level of capital spending compared to 2001, which has resulted in a greater percentage of employee labor and expenses being dedicated to capital projects, including the expansion projects discussed below, has also contributed to offsetting the increase in operating expenses during 2002.

     Other income (net) increased $8.1 million primarily due to reduced charitable contribution commitments.

     Other interest charges decreased $2.6 million resulting from the RP95-409 rate case settlement refund paid to customers in August 2001.

     Allowance for borrowed funds used during construction increased $2.2 million as a result of the increase in expenditures for capital projects, including expansion projects.

EFFECT OF INFLATION

     We have generally experienced increased costs in recent years 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 operating and maintenance 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 materials and supplies 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 the increased actual

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costs incurred when existing facilities are replaced. Cost-based regulation along with competition and other market factors limit our ability to price services or products to ensure recovery of 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 have 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 SEC. At December 31, 2003, approximately $150 million of shelf availability remains under this registration statement, which may be used to issue debt securities. 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. However, the ability to utilize this registration statement is restricted by certain covenants associated with Williams’ $800 million 8.625 percent senior unsecured notes that were issued in 2003.

     On March 4, 2003, we issued $175 million of 8.125 percent senior notes due 2010. We used the proceeds for general corporate purposes, including the funding of capital expenditures.

     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 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 percent 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 secured 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 London Interbank Offered Rate (“LIBOR”) plus 0.75 percent, or 1.87 percent 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 percent.

     As a participant in Williams’ cash management program, we make advances to and receive advances from Williams through our parent company, WGP. At December 31, 2003, the advances due to us by WGP totaled $86.4 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.

     Order Nos. 634 and 634-A (Docket No. RM02-14-000) On August 1, 2002, the FERC issued a 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 percent of total capitalization. On June 26, 2003, the FERC issued an Interim Rule (Order No. 634), which replaced the earlier NOPR on cash management described above. The Interim Rule required 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

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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 percent of total capitalization and when it subsequently returns to or exceeds 30 percent. 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.

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 and Poor’s and Fitch Ratings.

     In the second quarter of 2003, Moody’s Investors Service 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

     Our expenditures for property, plant and equipment additions were $294.5 million, $181.8 million and $94.9 million for 2003, 2002 and 2001, respectively. We anticipate 2004 capital expenditures will total approximately $117 million, of which approximately $100 million will be for maintenance capital expenditures and other non-expansion related items including expenditures required for the 26-inch line and the Pipeline Safety Improvement Act of 2002. The remaining expenditures required to restore the 26-inch line are planned for 2005 and 2006. Funding for these activities will be provided by 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. We anticipate filing a rate case to recover these costs coincident with the in-service date of the facilities.

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OTHER

Contractual Obligations

     The table below summarizes the maturity dates of the more significant contractual obligations and commitments by period (in millions of dollars).

Regulatory and Legal Proceedings

     Reference is made to Note 2 of the Notes to Financial Statements for information about judicial and business developments, which cause operating and financial uncertainties.

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 or capital contributions 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

Interest Rate Risk

     Our interest rate risk exposure is limited to its long-term debt. All interest rates on long-term debt are fixed in nature.

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     The following table provides information about our long-term debt, including current maturities, as of December 31, 2003. The table presents principle cash flows (at face value) and weighted-average interest rates by expected maturity dates.

December 31, 2003

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Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

INDEX TO FINANCIAL STATEMENTS

     All schedules have been omitted since the required information is not present or is not present in amounts sufficient to require submission of the schedule or because the information required is included in the financial statements and notes thereto.

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REPORT OF INDEPENDENT AUDITORS

The Board of Directors
Northwest Pipeline Corporation

     We have audited the accompanying balance sheets of Northwest Pipeline Corporation as of December 31, 2003 and 2002, and the related 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. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements 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 financial position of Northwest Pipeline Corporation at December 31, 2003 and 2002, and the 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.

	/s/ ERNST & YOUNG LLP

Houston, Texas
February 18, 2004

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NORTHWEST PIPELINE CORPORATION

STATEMENT OF INCOME

(Thousands of Dollars)

See accompanying notes.

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NORTHWEST PIPELINE CORPORATION

BALANCE SHEET

(Thousands of Dollars)

See accompanying notes.

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NORTHWEST PIPELINE CORPORATION

BALANCE SHEET

(Thousands of Dollars)

See accompanying notes.

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NORTHWEST PIPELINE CORPORATION

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

See accompanying notes.

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NORTHWEST PIPELINE CORPORATION

STATEMENT OF COMPREHENSIVE INCOME

(Thousands of Dollars)

See accompanying notes.

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NORTHWEST PIPELINE CORPORATION

STATEMENT OF CASH FLOWS
(Thousands of Dollars)

See accompanying notes.

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NORTHWEST PIPELINE CORPORATION

NOTES TO FINANCIAL STATEMENTS

1.  SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Corporate Structure and Control

     Northwest Pipeline Corporation (“Northwest”) 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, Northwest Pipeline Corporation is at times referred to in the first person as “we”, “us” or “our”.

Nature of Operations

     We own and operate an interstate pipeline system for the mainline transmission of natural gas. This system extends from the San Juan Basin in northwestern New Mexico and southwestern Colorado through Colorado, Utah, Wyoming, Idaho, Oregon and Washington to a point on the Canadian border near Sumas, Washington.

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, levelized depreciation 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 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 $16.1 million of regulatory assets included in Other Assets: Deferred Charges and approximately $11.8 million of regulatory liabilities included in Deferred Credits and Other Noncurrent Liabilities on the accompanying Balance Sheet. At December 31, 2002, we had approximately $14.1 million of regulatory assets included in Other Assets: Deferred Charge and approximately $11.0 million of regulatory liabilities included in Deferred Credits and Other Noncurrent Liabilities on the accompanying Balance Sheet.

Basis of Presentation

     Our 1983 acquisition by Williams has been 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 at the time of the acquisition. Williams has not pushed down the purchase price allocation (amounts in excess of original cost) of $84.9 million, as of December 31, 2003, to us as current FERC policy does not permit us to recover amounts in excess of original cost through our rates. The accompanying financial statements reflect our original basis in our assets and liabilities.

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 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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NORTHWEST PIPELINE CORPORATION

NOTES TO FINANCIAL STATEMENTS

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; and 7) pension and other post-employment benefits.

Property, Plant and Equipment

     Property, plant and equipment (“plant”), consisting principally of natural gas transmission facilities, is recorded at original cost. 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. Routine maintenance, repairs and renewal costs are charged to income as incurred. Gains or losses from the ordinary sale or retirement of plant are charged or credited to accumulated depreciation.

     Depreciation is provided by the straight-line method for property, plant and equipment. The annual weighted average composite depreciation rate recorded for transmission and storage plant was 3.00 percent, 2.94 percent and 2.98 percent for 2003, 2002 and 2001, respectively, including an allowance for negative salvage.

     The incremental Evergreen Project was placed in service on October 1, 2003. The levelized rate design of this project created a revenue stream that will remain constant over the respective 25-year and 15-year contract terms. The related levelized depreciation is lower than book depreciation in the early years and higher than book depreciation in the later years of the contract terms. The depreciation component of the levelized incremental rates will equal the accumulated book depreciation by the end of the primary contract terms. FERC has approved the accounting for the differences between book depreciation and the Evergreen Project’s levelized depreciation as a regulatory asset with the offsetting credit recorded to a regulatory credit on the accompanying Income Statement.

     During 2003, we recorded regulatory credits totaling $6.4 million in the accompanying Statement of Income. Of that amount, approximately $2.2 million relates primarily to the levelized depreciation for the Evergreen Project discussed above. In addition, a regulatory asset of approximately $4.2 million was also recognized related to depreciation and accrued income associated with incremental Evergreen compression facilities that were placed in-service prior to the full project completion on October 1, 2003. Such amounts will be amortized over the primary terms of the Evergreen shipper agreements as such costs are collected through rates.

     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 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 not recorded asset retirement liabilities for our pipeline transmission assets, since 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. Accordingly, the impact of adopting SFAS No. 143 did not have a material effect on our financial position or results of operations. The adoption of SFAS No. 143 had no material impact to operating income or net income.

     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 143, the negative salvage component of Accumulated Depreciation, $11.6 million and $9.8 million at December 31, 2003 and 2002, respectively, was reclassified to a Noncurrent Regulatory Liability.

Allowance for Borrowed and Equity 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.

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NORTHWEST PIPELINE CORPORATION

NOTES TO FINANCIAL STATEMENTS

     The composite rate used to capitalize AFUDC was approximately 10.1 percent, 10.0 percent and 9.9 percent for 2003, 2002 and 2001, respectively. Equity AFUDC of $8.6 million, $5.5 million and $.8 million for 2003, 2002 and 2001, respectively, is reflected in Other Income — net.

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 was based on the London Interbank Offering Rate (“LIBOR”) plus an applicable margin.

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 reserved or written off in the period of such determination.

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 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 financial statements.

Income Taxes

     We are included in Williams’ consolidated federal income tax return. Our federal income tax provisions are computed as though separate tax returns are filed. Deferred income taxes are computed using the liability method and are provided on all temporary differences between the financial basis and the tax basis of our assets and liabilities.

Deferred Charges

     We amortize deferred charges over varying periods consistent with the FERC approved accounting treatment for such deferred items. Unamortized debt expense, debt discount and losses on reacquired long-term debt are amortized by the bonds outstanding method over the related debt repayment periods.

Cash and Cash Equivalents

     Cash equivalents are stated at cost plus accrued interest, which approximates fair value. Cash equivalents are highly liquid investments with an original maturity of three months or less.

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NORTHWEST PIPELINE CORPORATION

NOTES TO FINANCIAL STATEMENTS

Exchange Gas Imbalances

     In the course of providing transportation services to our customers, we may receive different quantities of gas from shippers than the quantities delivered on behalf of those shippers. These transactions result in imbalances, which are typically settled through the receipt or delivery of gas in the future. Customer imbalances to be repaid or recovered in-kind are recorded as exchange gas due from others or due to others in the accompanying balance sheets. These imbalances are valued at the average of the spot market rates at the Canadian border and the Rocky Mountain market as published in “Inside FERC’s Gas Market Report.” 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. The exchange gas offset represents the gas balance in our system representing the difference between the exchange gas due to us from customers and the exchange gas that we owe to customers.

Revenue Recognition

     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 may be subject to possible refunds upon final orders in pending rate proceedings with the FERC. We record estimates of rate refund liabilities considering our and other third party regulatory proceedings, advice of counsel and estimated total exposure, as discounted and risk weighted, as well as collection and other risks.

Environmental Matters

     We are subject to federal, state, and local environmental laws and regulations. Environmental expenditures are expensed or capitalized depending on their future economic benefit and potential for rate recovery. We believe that, with respect to any expenditures required to meet applicable standards and regulations, the FERC would grant the requisite rate relief so that substantially all of such expenditures would be permitted to be recovered. We believe that compliance with applicable environmental requirements is not likely to have a material effect upon our financial position.

Interest Payments

     Cash payments for interest were $29.1 million, $22.9 million and $39.9 million, net of $3.6 million, $2.6 million and $0.4 million of interest capitalized (allowance for borrowed funds used during construction) in 2003, 2002 and 2001, respectively.

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NORTHWEST PIPELINE CORPORATION

NOTES TO FINANCIAL STATEMENTS

Employee Stock-Based Awards

     Williams’ 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 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 Williams awards made in 2003, 2002, and 2001. Also included in the 2003 pro forma expense is $84,756 of incremental expense associated with a stock option exchange program. (See Note 4.) Pro forma amounts for 2002 include compensation expense from Williams awards made in 2002 and 2001 and from certain Williams awards made in 1999. Pro forma amounts for 2001 include compensation expense from Williams awards made in 2001 and from certain Williams awards made in 1999.

     Since compensation expense from Williams 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 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 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

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NOTES TO FINANCIAL STATEMENTS

requirements of this statement effective December 31, 2002. The adoption had no effect on our 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 result in an expense to the employer that should be recognized in the income statement. See “Employee Stock-Based Awards” in this note.

     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 VIE’s expected losses if they occur or receive portions of the VIE’s 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 VIE’s expected losses if they occur, receive a majority of the VIE’s expected residual returns if they occur, or both. If no party will absorb a majority of the expected losses or expected residual return, no party will consolidate the VIE. The Interpretation also requires disclosure of significant variable interests in unconsolidated VIE’s. The Interpretation is effective for all new VIE’s created or acquired after January 31, 2003. For VIE’s 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 these 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 VIE’s as defined by the Interpretation.

Reclassifications

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

2. CONTINGENT LIABILITIES AND COMMITMENTS

Legal Proceedings

     In 1998, the United States Department of Justice (“DOJ”) informed Williams that Jack Grynberg, an individual, had filed claims in the United States District Court for the District of Colorado under the False Claims Act against Williams and certain of its wholly-owned subsidiaries including us. Mr. Grynberg had also filed claims against approximately 300 other energy companies and alleged that the defendants violated the False Claims Act in connection with the measurement, royalty valuation and purchase of hydrocarbons. The relief sought was an unspecified amount of royalties allegedly not paid to the federal government, treble damages, a civil penalty, attorneys’ fees and costs. In April 1999, the DOJ declined to intervene in any of the Grynberg qui tam cases; 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 the National Environmental Policy Act and other federal and state legislation regulating the environmental aspects of its business. Management believes that we are in substantial compliance with existing environmental requirements. We believe that, with respect to any capital expenditures required to meet applicable standards and regulations, the FERC would grant the requisite rate relief so that, for the most part, such expenditures and a return thereon would be permitted to be

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NOTES TO FINANCIAL STATEMENTS

recovered. As a result, we believe that compliance with applicable environmental requirements is not likely to have a material effect upon our earnings or financial position.

Safety Matters

     In December 2003, the United States Department of Transportation Office of Pipeline Safety issued a final rule pursuant 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 $75 million and $100 million over the 2003 to 2012 period. Developing and implementing the required public education program, including a process for measuring and evaluating the effectiveness of safety information distributed to various stakeholder groups, is expected to cost less than $1 million. Our management considers the costs associated with compliance with the rule to be prudent costs incurred in the ordinary course of business and, therefore, recoverable through our rates.

Other Matters

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

Summary

     Litigation, arbitration, regulatory matters and environmental 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 net income of 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

     We have commitments for construction and acquisition of property, plant and equipment of approximately $15.9 million at December 31, 2003.

     We are developing a plan to replace the capacity of our 26-inch line damaged by the pipeline breaks in 2003. The estimated combined cost to inspect, hydrostatically test, temporarily restore a portion of the line to service, and to ultimately replace up to the entire 360 MDth per day of capacity, if required, by the end of 2006 is estimated to range between $365 million and $430 million. Funding for these activities will be provided by cash flows from operating activities, by repayments of funds advanced to WGP, by accessing capital markets, and, if required, by borrowings under the $800 million revolving and letter of credit facility (See Note 3) and advances from WGP. We anticipate filing a rate case to recover these costs coincident with the in-service date of the facilities.

3. DEBT, FINANCING ARRANGEMENTS AND LEASES

Debt Covenants

     The terms of our debt indentures restrict the issuance of mortgage bonds. The indentures contain provisions for the acceleration of repayment or the reset of interest rates under certain conditions. Our debt indentures also contain restrictions, which, under certain circumstances, limit the issuance of additional debt and restrict the disposal of a major portion of our natural gas pipeline system.

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NOTES TO FINANCIAL STATEMENTS

Long-Term Debt

     Long-term debt consists of the following:

     As of December 31, 2003, cumulative sinking fund requirements and other maturities of long-term debt (at face value) for each of the next five years are as follows:

Line-of-Credit Arrangements

     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, a subsidiary of WGP, and Northwest 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 percent 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 secured 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 agreement is variable at the London Interbank Offered Rate (“LIBOR”) plus 0.75 percent, or 1.87 percent at December 31, 2003. At 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 percent.

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NOTES TO FINANCIAL STATEMENTS

Leases

     Our leasing arrangements include mostly premise and equipment leases that are classified as operating leases.

     The major operating lease is a leveraged lease, which became effective during 1982 for our headquarters building. The agreement has an initial term of approximately 27 years, with options for consecutive renewal terms of approximately 9 years and 10 years. The major component of the lease payment is set through the initial and first renewal terms of the lease. Various purchase options exist under the building lease, including options involving adverse regulatory developments.

     We sublease portions of our headquarters building to third parties under agreements with varying terms. Following are the estimated future minimum yearly rental payments required under operating leases, which have initial or remaining noncancelable lease terms in excess of one year:

     Operating lease rental expense amounted to $5.2 million, $5.4 million and $6.1 million for 2003, 2002 and 2001, respectively.

4. EMPLOYEE BENEFIT PLANS

Pension and Postretirement Medical Plans

     Our employees are covered by Williams’ non-contributory defined-benefit pension plan and Williams’ health care plan that provide postretirement medical benefits to certain retired employees. Contributions for pension and postretirement medical benefits related to our participation in these plans were $8.9 million, $5.9 million and $2.3 million in 2003, 2002 and 2001, respectively. These amounts are currently recoverable in our rates.

     At December 31, 2002, we recorded minimum pension liability of $3.2 million, net of $2.0 million tax. At December 31, 2003, we recorded a credit adjustment to the minimum pension liability of $2.8 million, net of $1.8 million tax. Minimum pension liability is included as a component of our Other Comprehensive income for the years 2003 and 2002.

Defined Contribution Plan

     Our employees are also covered by various Williams’ defined contribution plans. Our costs related to these plans totaled $1.5 million, $2.3 million and $2.1 million in 2003, 2002 and 2001, respectively.

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NOTES TO FINANCIAL STATEMENTS

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, including us. Upon approval by the stockholders, all prior Williams stock plans were terminated resulting in no further grants being made from those plans. However, Williams options outstanding in those prior plans remain in those plans with their respective terms and provisions.

     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 future 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 ten years after grant.

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

*		All of the 2003 Williams stock options granted relate to the Williams stock option exchange program described above.
**		Includes 413,455 shares that were cancelled on June 26, 2003, under the Williams stock option exchange program, described above.

(1)

Effective with the spinoff of WilTel Communications, 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.

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NOTES TO FINANCIAL STATEMENTS

     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):

     The estimated fair value at the 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:

(a)

In 2003, stock options granted to our 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 .40 percent; 2) volatility of 50 percent; 3) weighted average expected remaining life of 3.4 years; and 4) weighted average risk free interest rate of 1.99 percent.

          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 Williams stock-based awards granted to our employees is disclosed under Employee Stock-Based Awards in Note 1.

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NOTES TO FINANCIAL STATEMENTS

5. INCOME TAXES

     Significant components of the deferred tax liabilities and assets are as follows:

     The provision for income taxes includes:

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NOTES TO FINANCIAL STATEMENTS

     A reconciliation of the statutory Federal income tax rate to the provision for income taxes is as follows:

     Net cash payments made to Williams for income taxes were $3.5 million, $29.7 million and $35.9 million in 2003, 2002 and 2001, respectively.

6. FINANCIAL INSTRUMENTS

Disclosures About the Fair Value of Financial Instruments

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

Cash, cash equivalents and advances to affiliate — The carrying amounts of these items approximates their fair value.

Long-term debt — The fair value of our publicly traded long-term debt is valued using year-end traded market prices. Private debt is valued based on the prices of similar securities with similar terms and credit ratings. We used the expertise of an outside investment-banking firm to estimate the fair value of long-term debt. The carrying amount and estimated fair value of our long term debt, including current maturities, were $535 million and $573 million, respectively, at December 31, 2003, and $368 million and $328 million, respectively, at December 31, 2002.

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NOTES TO FINANCIAL STATEMENTS

7. TRANSACTIONS WITH MAJOR CUSTOMERS AND AFFILIATES

Concentration of Off-Balance-Sheet and Other Credit Risk

     During the periods presented, more than 10 percent of our operating revenues were generated from each of the following customers:

(a)

Revenues were under 10 percent in this year.

     Our major customers are located in the Pacific Northwest. As a general policy, collateral is not required for receivables, but customers’ financial condition and credit worthiness are regularly evaluated and historical collection losses have been minimal.

     We, through a wholly-owned bankruptcy remote subsidiary, sold certain trade accounts receivable to a special-purpose entity (“SPE”) in a securitization structure requiring annual renewal. We acted as the servicing agent for the sold receivables. The sale of receivables program expired on July 25, 2002, and on July 26, 2002, we completed the repurchase of $15 million of trade accounts receivable previously sold.

Related Party Transactions

     As a subsidiary of Williams, we engage in transactions with Williams and other Williams subsidiaries characteristic of group operations. As a participant in Williams’ cash management program, we make advances to and receive advances from Williams through our parent company, WGP. At December 31, 2003, the advances due us by WGP totaled $86.4 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. We received interest income from advances to these affiliates of $2.7 million, $1.6 million, and $3.1 million during 2003, 2002 and 2001, respectively. Such interest income is included in Other Income — net on the accompanying Statement of Income.

     Williams’ corporate overhead expenses allocated to us were $14.2 million, $9.7 million and $6.9 million for 2003, 2002 and 2001, respectively. Such expenses have been allocated to us by Williams primarily based on the Modified Massachusetts formula, which is a FERC approved method utilizing a combination of net revenues, gross payroll and gross plant for the allocation base. In addition, Williams or an affiliate has provided executive, data processing, legal, accounting, internal audit and other administrative services to us on a direct charge basis, which totaled $6.8 million, $4.6 million and $5.0 million for 2003, 2002 and 2001, respectively. These expenses are included in General and Administrative Expense on the accompanying Statement of Income.

     During the periods presented, our revenues include transportation and exchange transactions with subsidiaries of Williams. Combined revenues for these activities totaled $1.6 million, $2.2 million and $1.8 million for 2003, 2002 and 2001, respectively.

     We have entered into various other transactions with certain related parties, the amounts of which were not significant. These transactions and the above-described transactions are made on the basis of commercial relationships and prevailing market prices or general industry practices.

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NOTES TO FINANCIAL STATEMENTS

     We have also entered into an interconnect agreement and an operation balance agreement, each in connection with the Georgia Strait Crossing project, with an affiliate of Williams.

8. Impairments

     In June 2003, we wrote off software development costs of $25.5 million associated with a service delivery system. Subsequent to the implementation of this system at Transcontinental Gas Pipe Line Corporation in the second quarter of 2003 and a determination of the unique and additional programming requirements that would be needed to complete the system for us, management determined that the system would not be implemented. In August 2003, we wrote off an additional $0.1 million of software development costs for the remaining component of the service delivery system.

9. Quarterly Information (Unaudited)

     The following is a summary of unaudited quarterly financial data for 2003 and 2002:

     Fourth quarter operating revenues include $9.9 million of new revenues from the Evergreen Project that was placed in service on October 1, 2003. Second quarter operating income includes the $25.5 million write-off of capitalized software development costs.

     Second quarter operating revenues include a $3.9 million expense for an enhanced benefit early retirement option offered to certain Williams employee groups.

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Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

Item 9A. CONTROLS AND PROCEDURES

     An evaluation of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15(d) - (e) of the Securities Exchange Act) (“Disclosure Controls”) was performed as of the end of the period covered by this report. This evaluation was performed under the supervision and with the participation of our management, including our Senior Vice President and Vice President and Treasurer. Based upon that evaluation, our Senior Vice President and Vice President and Treasurer concluded that, subject to the limitations noted below, these Disclosure Controls and procedures are effective.

     Our management, including our Principal Executive Officer and Principal Financial Officer, does not expect that our Disclosure Controls or our internal controls over financial reporting (“Internal Controls”) will prevent all error and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within the company have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty, and that breakdowns can occur because of simple error or mistake. Additionally, controls can be circumvented by the individual acts of some persons, by collusion of two or more people, or by management override of the control. The design of any system of controls also is based in part upon certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions. Because of the inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and not be detected. We monitor our Disclosure Controls and Internal Controls and make modifications as necessary; our intent in this regard is that the Disclosure Controls and the Internal Controls will be modified as systems change and conditions warrant.

     There has been no change in our Internal Controls that occurred during the registrant’s fourth fiscal quarter that has materially affected, or is reasonably likely to materially affect, our Internal Controls.

PART III

     Since we meet the conditions set forth in General Instruction (I)(1)(a) and (b) of Form 10-K, Items 10 through 13 are omitted.

Item 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

     Fees for professional services provided by our independent auditors in each of the last two fiscal years are as follows: