UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

FORM 10-K

þ Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the Transition Period from _____________________ to _________________________

Commission File Number 1-7414

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 þ No o

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

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

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

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). Williams is a reporting entity for 2004 under the Sarbanes-Oxley Act of 2002. Northwest is not an accelerated filer and therefore not required to report in 2004 under Section 404 of the Sarbanes-Oxley Act of 2002.

     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 and Storage

     At December 31, 2004, our system, having long term firm transportation agreements with peaking capacity of approximately 3.4 MMDth* of gas per day, was composed of approximately 4,200 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 2004, we served a total of 175 transportation and storage customers. Our transportation customers include distribution companies, municipalities, interstate and intrastate pipelines, gas marketers and direct industrial users. In 2004, our two largest customers were Puget Sound Energy, Inc. and Northwest Natural Gas Co., which accounted for approximately 13.9 percent and 11.3 percent, respectively, of our total operating revenues. No other customer accounted for more than 10 percent of our total operating revenues in 2004. Our firm transportation and storage 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.

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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 6.6 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 in Washington

     In December 2003, we received an Amended Corrective Action Order (ACAO) from the U.S. Department of Transportation’s Office of Pipeline Safety (OPS) regarding a segment of one of our natural gas pipelines in western Washington. The pipeline experienced two breaks in 2003 and we subsequently idled the pipeline segment until its integrity could be assured.

     By June 2004 we had successfully completed our hydrostatic testing program and returned to service 111 miles of the 268 miles of pipe affected by the ACAO. That effort has restored 131 MDth/day of the 360 MDth/day of idled capacity and is anticipated to be adequate to meet most market conditions. To date our ability to serve the market demand has not been significantly impacted.

     The restored facilities will be monitored and tested as necessary until they are ultimately replaced. Through December 31, 2004, approximately $40 million had been spent on testing and remediation, including $8.9 million related to one segment of pipe that we recently determined not to return to service and was therefore written off in the second quarter of 2004. We estimate the total testing and remediation costs will be between $40 million and $45 million.

     On October 4, 2004 we received a notice of probable violation (NOPV) from OPS. Under the provisions of the NOPV, OPS has issued a preliminary civil penalty of $100,000 for exceeding the pressure restriction on one of the segments covered under the original CAO. This penalty was accrued in the third quarter of 2004. The incident occurred on July 15, 2003 and did not occur as part of normal operations, but in preparation for running an internal inspection tool to test the integrity of the line. The operating pressure dictated by the original CAO was exceeded for approximately three hours due to the mechanical failure of an overpressure device and we immediately reported the incident to the OPS. There was no impact on pipeline facilities, and no additional sections of the pipeline were affected. Following the incident, new protocols were adopted to ensure that a similar situation would not occur in the future. We requested a hearing on the proposed OPS civil penalty, which was held in Denver, Colorado on December 15, 2004. OPS will issue its decision in the near future.

     As required by OPS, we plan to replace the pipeline’s entire capacity by November 2006 to meet long-term demands. We conducted a reverse open season to determine whether any existing customers were willing to relinquish or reduce their capacity commitments to allow us to reduce the scope of pipeline replacement facilities. That resulted in 13 MDth/day of capacity being relinquished and incorporated into the replacement project. On November 29, 2004 we filed with the Federal Energy Regulatory Commission a certificate application for the “Capacity Replacement Project” including construction of approximately 79.5 miles of 36-inch pipeline and 10,760 net horsepower of additional compression at two existing compressor stations and abandonment of approximately 268 miles of the existing 26-inch

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pipeline. The estimated net cost of the Capacity Replacement Project included in the filing is approximately $333 million. The majority of these costs will be spent in 2005 and 2006. We anticipate filing a rate case to recover the capitalized costs relating to restoration and replacement facilities following the in-service date of the replacement facilities.

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.

     Order Nos. 2004, et seq. (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. In Order No. 2004, the FERC defined energy affiliates broadly, but in Order No. 2004-A, issued on April 16, 2004, the FERC, among other things, clarified the definition of energy affiliates in a manner that narrowed its scope. On August 2, 2004, the FERC issued Order No. 2004-B, which, among other things, further clarified the definition of energy affiliates and deferred the implementation date for the new standards of conduct until September 22, 2004. We posted on our electronic bulletin board our procedures implementing the requirements of Order No. 2004 on September 22, 2004, in compliance with the new standards of conduct. On December 21, 2004, the FERC issued Order No. 2004-C, which, among other things, further clarified Order No. 2004-B. Certain parties have sought rehearing of Order No. 2004-C, and other parties have filed petitions for review of the FERC’s Order Nos. 2004, et seq.

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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.

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;
	•	cash flow from operations; 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.

     See the “Risk Factors” section of this report for a more detailed discussion of these risks and uncertainties.

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     When considering forward-looking statements, one should keep in mind the risk factors described in “Rick Factors” below. The risk factors could cause our actual results to differ materially from those contained in any forward-looking statement. We disclaim any obligation to update the above list or to announce publicly the result of any revisions to any of the forward-looking statements to reflect future events or developments.

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 related to the regulation of our business

Our gas sales, transmission, and storage operations are subject to government regulations and rate proceedings that could have an adverse impact on our ability to recover the costs of operating our pipeline facilities.

     Our interstate 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 have 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.

Risk 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:

	•	further economic downturns;
	•	capital market conditions generally;
	•	market prices for electricity and natural gas;

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	•	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.

Despite Williams’ restructuring efforts, we may not attain investment grade ratings.

     Credit rating agencies perform independent analysis when assigning credit ratings. Given the significant changes in capital markets and the energy industry over the last few years, credit rating agencies continue to review the criteria for attaining investment grade ratings and make changes to those criteria from time to time. Williams’ goal is to attain investment grade ratios. However, there is no guarantee that the credit rating agencies will assign us investment grade ratings even if we meet or exceed their criteria for investment grade ratios.

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

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

     Although we are currently in compliance with our financial and other covenants in our debt agreements, our failure to comply with such financial or other covenants could result in events of default. Upon the occurrence of an event of default under our debt agreements, the lenders could elect to declare all amounts outstanding under a particular facility to be immediately due and payable and terminate all commitments, if any, to extend further credit. By reason of cross-default or cross-acceleration provisions in certain of our debt agreements, such a default or acceleration could have a wider impact on our liquidity than might otherwise arise from a default or acceleration of a single debt instrument. If the lenders under any of our debt agreements accelerate the maturity of any loans or other debt outstanding, we may not have sufficient liquidity to repay amounts outstanding under such debt agreements.

Risks related to outsourcing of non-core support services.

Institutional knowledge represented by former Williams employees now employed by Williams’ outsourcing service provider might not be adequately preserved.

     Due to the large number of former Williams employees who migrated to an outsourcing provider, access to significant amount of internal historical knowledge and expertise could become unavailable to us, particularly if knowledge transfer initiatives are delayed or ineffective.

Failure of the outsourcing relationship might negatively impact our ability to conduct our business.

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

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

     Certain information technology application development, human resources, and help desk services that are currently provided by an outsourcer will be relocated to service centers operated by

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Williams’ outsourcing provider outside of the United States during 2005. The economic and political conditions in certain countries from which Williams’ outsourcing providers may provide services to us present similar risks of business operations located outside of the United States, including risks of interruption of business, war expropriation, nationalization, renegotiation, trade sanctions or nullification of existing contracts and changes in law or tax policy, that are greater than in the United States.

Risks related to environmental matters

We could incur material losses if we are held liable for the environmental condition of any of our assets, which could include losses that exceed our current expectations.

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

Environmental regulation and liability relating to our business will be subject to environmental legislation in all jurisdictions in which we operate, and any changes in such legislation could negatively affect our results of operations.

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

     Compliance with environmental legislation will require significant expenditures, including expenditures for compliance with the Clean Air Act and similar legislation, for clean up costs and damages arising out of contaminated properties, and for failure to comply with environmental legislation and regulations which might result in the imposition of fines and penalties. The steps we take to bring certain of our facilities into compliance could be prohibitively expensive, and we might be required to shut down, divest, or alter the operation of those facilities, which might cause us to incur losses.

     Further, our regulatory rate structure and our contracts with customers might not necessarily allow us to recover 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

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we fail to obtain and comply with them, the operation of our facilities could be prevented or become subject to additional costs. Should we fail to comply with all applicable environmental laws, we might be subject to penalties and fines imposed by regulatory authorities. Although we do not expect that the costs of complying with current environmental legislation will have a material adverse effect on our financial condition or results of operations, no assurance can be made that the costs of complying with environmental legislation in the future will not have such an effect.

RISKS RELATING TO ACCOUNTING STANDARDS

Potential changes in accounting standards might cause us to revise our financial results and disclosure in the future.

     Accounting irregularities discovered in the past few years in various industries have forced regulators and legislators to take a renewed look at accounting practices, financial disclosures, and companies’ relationships with their independent registered public accounting firms and other accounting practices. Because it is still unclear what laws or regulations will ultimately 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. Additional natural gas reserves might not be developed in commercial quantities and in sufficient amounts to fill the capacities of our gathering and transmission pipeline facilities.

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 to us. 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. We implemented an Integrity Management Plan (IMP) in December 2004, as required by the Pipeline Safety Improvement Act. As part of the IMP, we identified High Consequence Areas (HCA) through which our pipeline runs. A HCA is an area where the potential consequence of a gas pipeline accident may be significant or do considerable harm to people or property. Certain segments of our pipeline run through HCAs. An event such as those described above in an HCA not only could cause considerable harm to people or property, but could have a material adverse effect on our financial position and results of operations, particularly if the event is not fully covered by insurance.

     Accidents or other operating risks could further result in loss of service available to our customers. Such circumstances could adversely impact our ability to meet contractual obligation and retain customers.

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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 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.

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

     Our assets and operations can be adversely affected by hurricanes, earthquakes, tornadoes and other natural phenomena and weather conditions including extreme temperatures, making it more difficult for us to realize the historic rates of return associated with these assets and operations.

Item 2. PROPERTIES

     See “Item 1. Business.”

Item 3. LEGAL PROCEEDINGS

     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 $60 million in cash dividends in 2004 and paid no cash dividends on common stock in 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, 2004, we had approximately $22.4 million of regulatory liabilities included in Deferred Credits and Other Noncurrent Liabilities on the accompanying Balance Sheet. At December 31, 2003, we had approximately $18.4 million of regulatory liabilities included in Deferred Credits and Other Noncurrent Liabilities on the accompanying Balance Sheet.

Revenue Subject to Refund

     FERC regulations promulgate policies and procedures, which govern a process to establish the rates that we are permitted to charge customers for natural gas services, including the transportation and

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storage of natural gas. Key determinants in the ratemaking process are (i) costs of providing service, including depreciation expense, (ii) allowed rate of return, including the equity component of a pipeline’s capital structure and related income taxes, and (iii) volume throughput assumptions.

     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, 2004, 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 and 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.

Proposed FERC Accounting Guidance

     In November 2004, the FERC issued proposed accounting guidance on accounting for pipeline assessment costs. If adopted, we may be required to expense certain assessment costs that have historically been capitalized. For 2005, the estimated impact of this proposal would be additional expense of $8 million to $13 million.

2003 PIPELINE BREAKS

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

RESULTS OF OPERATIONS

ANALYSIS OF FINANCIAL RESULTS

     This analysis discusses financial results of our operations for the years 2002 through 2004. 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.

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2004 COMPARED TO 2003

     Operating revenues increased $10.5 million, or 3 percent, due primarily to increased transportation revenues of $30.2 million from the incremental Evergreen project placed in service in late 2003, offset by lower firm and interruptible transportation of $12.8 million primarily due to a decrease in basin price differentials, lower revenue of $4.7 million related to reduced equity AFUDC resulting from the decreased capital construction program in 2004, and $1.0 million of lower rental income due to fewer building tenants.

     Pipeline’s transportation service accounted for 96 percent and 94 percent of operating revenues for the years ended December 31, 2004 and 2003, respectively. Additionally, gas storage service accounted for 3 percent of operating revenues for each of the years ended December 31, 2004 and 2003, respectively.

     Operating expenses decreased $4.0 million, or 2 percent. This reduction was due primarily to the write-off of capitalized software development costs of $25.6 million associated with a service delivery system included in 2003 operating costs, which was mostly offset by the following increases during 2004: an $8.9 million write-off of previously capitalized costs incurred on an idled segment of our system that will not be returned to service; a $6.0 million increase in general corporate overhead expense due to an increased share of allocated costs resulting from changes within Williams; a $1.3 million increase in charges from Williams and WGP related primarily to shared service charges, third-party consultation and administrative costs associated with the Sarbanes-Oxley Act compliance activities, and efforts at Williams to evaluate and implement certain cost reduction strategies through internal initiatives and outsourcing of certain services; a $4.6 million increase in labor and other costs resulting primarily from lower levels charged to construction in 2004; and a $1.6 million increase in outside contractor services as a result of various maintenance projects performed during 2004. Depreciation expense decreased by $1.1 million resulting from a $5.4 million adjustment to correct an error related to over depreciation of certain in-house developed system software and other general plant issues, partially offset by additional depreciation expense due to the recent Evergreen and Rockies construction projects placed in service during the fourth quarter of 2003 (See Property, Plant and Equipment in Note 1). Other Taxes decreased by $1.7 million due to a $3.8 million adjustment to ad valorem taxes in 2003, partially offset by higher ad valorem taxes resulting from property additions.

     Operating income increased $14.5 million, or 10 percent, due to the higher operating revenues and lower operating costs discussed above.

     Other income decreased $4.2 million, or 43 percent, primarily due to a $7.8 million decrease in AFUDC resulting from fewer construction projects in 2004, offset by a $1.8 million increase in interest resulting from higher average levels of advances to affiliates.

     Interest on long-term debt increased $1.6 million due to the March 4, 2003, $175 million debt issuance of 8.125 percent senior notes due 2010. Allowance for borrowed funds used during construction decreased $3.1 million due to the decrease in construction resulting from the completion of large projects in the fourth quarter of 2003.

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.

     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

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(“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.

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 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 Williams, accessing capital markets, and, if required, borrowings under the Credit Agreement and advances from Williams.

     We have an effective registration statement on file with the SEC. At December 31, 2004, approximately $150 million of shelf availability remains under this registration statement, which may be used to issue debt securities. At December 31, 2004, the ability to utilize this registration statement was restricted by certain covenants of Williams’ debt agreements. Interest rates, market conditions, and industry conditions will affect amounts raised, if any, in the capital markets. We believe any additional financing arrangements, if required, can be obtained from the capital markets on terms that are commensurate with our current credit ratings.

     On May 3, 2004, Williams entered into a new three-year $1 billion secured revolving credit facility (Credit Agreement), which is available for borrowings and letters of credit. In August of 2004, Williams expanded the credit facility by an additional $275 million. At December 31, 2004, letters of credit totaling $422 million, none of which are associated with us, have been issued by the participating institutions under this facility and no revolving credit loans were outstanding. Northwest and Transcontinental Gas Pipe Line Corporation, subsidiaries of WGP, have access to $400 million each under the facility. The new facility is secured by certain Williams’ midstream assets. Additionally, the facility is guaranteed by WGP. Interest is calculated based on a choice of two methods: a fluctuating rate equal to the facilitating bank’s base rate plus an applicable margin or a periodic fixed rate equal to the London Interbank Offered Rate (LIBOR) plus an applicable margin. Williams is also required to pay a commitment fee (currently 0.375 percent annually) based on the unused portion of the facility. The applicable margins and commitment fee are based on the relevant borrower’s senior unsecured long-term debt ratings. Upon entering into the new $1 billion secured revolving credit facility on May 3, 2004, Williams terminated the $800 million revolving and letter of credit facility.

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     As a participant in Williams’ cash management program, we make advances to and receive advances from Williams. At December 31, 2004, the advances due to us by Williams totaled $50 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. Prior to April 29, 2004, the advances were made to and received from our parent company, WGP.

WILLIAMS’ RECENT EVENTS

     In February 2003, Williams outlined its planned business strategy in response to the events that significantly impacted the energy sector and Williams during late 2001 and 2002. The plan focused upon migrating to an integrated natural gas business comprised of a strong, but smaller portfolio of natural gas businesses, reducing debt and increasing Williams’ liquidity through assets sales, strategic levels of financing 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. A component of Williams’ plan was to reduce the risk and liquidity requirements of its power segment while realizing the value of its power portfolio.

     In 2004, Williams continued to execute certain components of the plan, and substantially completed its plan as outlined in February 2003. Williams’ results for 2004 include the following.

	•	Completion of planned asset sales, which resulted in proceeds of approximately $877.8 million.
	•	Replacement of Williams’ cash-collateralized letter of credit and revolver facility with facilities that do not encumber cash.
	•	Significant debt reduction of approximately $4 billion through scheduled maturities and early redemptions.
	•	On June 1, 2004, Williams announced an agreement with IBM Business Consulting Services (IBM) to aid in transforming and managing certain areas of Williams’ accounting, finance, and human resources processes. Under the agreement, IBM will also manage key aspects of Williams’ information technology, including enterprise wide infrastructure and application development. The 7 1/2 year agreement began July 1, 2004, and is expected to reduce costs in these areas while maintaining a high quality of service.

     In September 2004, Williams Board of Directors approved the decision to retain Williams’ power business and end its efforts to exit that business. Williams’ strategy is to continue managing this business to minimize financial risk, maximize cash flow and meet contractual commitments.

     Williams’ plan for 2005 includes the following objectives:

	•	increase focus and disciplined investments in the natural gas businesses;
	•	continue to steadily improve credit ratios and ratings with the goal of achieving investment grade ratios;
	•	continue to reduce risk and liquidity requirements while maximizing cash flow in its power segment; and
	•	maintain a liquidity from cash and revolving credit facilities of at least $1 billion.

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.

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     In the fourth quarter of 2004, 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+, and has remained constant during 2004.

     Currently, all of the rating agencies have our credit ratings evaluated as “stable outlook”.

CAPITAL EXPENDITURES

     Our expenditures for property, plant and equipment additions were $102.2 million, $294.5 million and $181.8 million for 2004, 2003 and 2002, respectively. We anticipate 2005 capital expenditures will be between $135 million and $160 million, all of which will be for maintenance capital expenditures and other non-expansion related items including expenditures required for the 26-inch pipeline restoration and the Pipeline Safety Improvement Act of 2002. The remaining expenditures required to restore the 26-inch pipeline break are planned for 2006. (Reference is made to “Item 1. Business – 2003 Pipeline Breaks in Washington” on page 2.) We anticipate filing a rate case to recover these costs coincident with the in-service date of the facilities.

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 Proceedings

     Reference is made to Note 2 of the Notes to Financial Statements for information about regulatory 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 Williams, 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.

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SUBSEQUENT EVENT

      Duke Energy Trading and Marketing, LLC (Duke) has given notice to terminate its firm transportation agreement related to the Grays Harbor Lateral effective December 31, 2004, and pay us a lump sum amount based on the remaining net book value of the lateral facilities and related income taxes. In January 2005, Duke paid approximately $94 million towards this lump sum amount and disputed a portion of the lump sum amount requested by us. As of March 14, 2005, the final amount has not been agreed upon by Duke and us. However, based upon the payment already made, we do not anticipate any adverse impact to our results of operations or financial position in 2005. The monthly revenues from the Grays Harbor transportation agreement with Duke, which was terminated as of December 31, 2004, were approximately $1.6 million.

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.

     The following table provides information about our long-term debt, including current maturities, as of December 31, 2004. The table presents principle cash flows (at face value) and weighted-average interest rates by expected maturity dates.

December 31, 2004

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Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

INDEX TO FINANCIAL STATEMENTS

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors
Northwest Pipeline Corporation

     We have audited the accompanying balance sheets of Northwest Pipeline Corporation as of December 31, 2004 and 2003, 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, 2004. Our audits also included the financial statement schedule listed in the Index at Item 15(a). These financial statements and schedules are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and schedules based on our audits.

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

     In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Northwest Pipeline Corporation at December 31, 2004 and 2003, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2004, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein.

Houston, Texas
March 14, 2005

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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

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, 2004, we had approximately $22.4 million of regulatory liabilities included in Deferred Credits and Other Noncurrent Liabilities on the accompanying Balance Sheet. At December 31, 2003, we had approximately $18.4 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 $80.6 million, as of December 31, 2004, 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 or information could change those estimates include: 1) revenues subject to refund; 2) litigation-

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NORTHWEST PIPELINE CORPORATION

NOTES TO FINANCIAL STATEMENTS

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, 3.00 percent and 2.94 percent for 2004, 2003 and 2002, 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 2004, we recorded regulatory credits totaling $7.2 million in the accompanying Statement of Income. These credits relate primarily to the levelized depreciation for the Evergreen Project discussed above. Such amounts will be amortized over the primary terms of the Evergreen shipper agreements as such costs are collected through rates.

     Included in our depreciation rates is a negative salvage (cost of removal) component that we currently collect in rates. We therefore accrue the estimated costs of removal of long-lived assets through depreciation expense. In connection with the adoption of SFAS No. 143, the negative salvage component of Accumulated Depreciation, $14.0 million and $11.6 million at December 31, 2004 and 2003, respectively, was reclassified to a Noncurrent Regulatory Liability.

     During 2004, Pipeline made an adjustment to depreciation expense in the amount of $5.4 million. The adjustment was a correction of an error related to depreciation of certain in-house developed system software and other general plant assets. These assets, which were retired in prior years, continued to be depreciated, resulting in an over-depreciation of the assets. The error, and correction thereof, resulted in an increase of 2004 Operating Income by $5.4 million, an understatement of 2003 Operating Income by $3.1 million and a cumulative understatement of Operating Income for periods prior to 2003 by $2.3 million. Management believes that the effect of the adjustment is not material to 2004 income, prior quarters and years, or trends of earnings.

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.

     The composite rate used to capitalize AFUDC was approximately 10.0 percent, 10.1 percent and 10.0 percent for 2004, 2003 and 2002, respectively. Equity AFUDC of $0.8 million, $8.6 million and $5.5 million for 2004, 2003 and 2002, respectively, is reflected in Other Income - net.

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NORTHWEST PIPELINE CORPORATION

NOTES TO FINANCIAL STATEMENTS

Advances to Affiliates

     As a participant in Williams’ cash management program, we make advances to and receive advances from Williams. 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. The interest rate on intercompany demand notes is based upon the weighted average cost of Williams’ debt outstanding at the end of each quarter. Prior to April 29, 2004, the advances were made to and received from our parent company, WGP.

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.

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

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NORTHWEST PIPELINE CORPORATION

NOTES TO FINANCIAL STATEMENTS

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 $38.7 million, $29.1 million and $22.9 million, net of $0.5 million, $3.6 million and $2.6 million of interest capitalized (allowance for borrowed funds used during construction) in 2004, 2003 and 2002, respectively.

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 2004 include compensation expense from Williams awards made in 2004, 2003, 2002, and 2001. Also included in the 2004 pro forma expense is $169,683 of incremental expense associated with a stock option exchange program. (See Note 4.) Pro forma amounts for 2003 include compensation expense from Williams awards made in 2003, 2002, and 2001. Also included in the 2003

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NORTHWEST PIPELINE CORPORATION

NOTES TO FINANCIAL STATEMENTS

     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 Pronouncements

     In December 2004, the Financial Accounting Standards Board (FASB) issued revised SFAS No. 123. “ Share-Based Payment.” The statement requires that compensation cost for all share based awards to employees be recognized in the financial statements at fair value. The statement is effective for us as of the interim reporting period that begins July 1, 2005. We intend to adopt the revised statement as of the interim reporting period beginning July 1, 2005.

     The revised Statement allows either a modified prospective application or a modified retrospective application for adoption. Williams will use the modified prospective application for adoption, and thus, will apply the statement to new awards and to awards modified, repurchased, or cancelled after July 1, 2005. Also, for unvested stock awards outstanding as of July 1, 2005, compensation costs for the portion of these awards for which the requisite service has not been rendered will be recognized as the requisite service is rendered after July 1, 2005. Compensation costs for these awards will be based on fair value at the original grant date as estimated for the pro forma disclosure under SFAS No. 123, as amended by SFAS No. 148, “Accounting for Stock-Based Compensation Transition and Disclosure–an amendment of SFAS No. 123.” The modified retrospective application would have required restating periods prior to July 1, 2005, on a basis consistent with the pro forma disclosures required by SFAS No. 123, “Accounting for Stock-Based Compensation,” as amended by SFAS No. 148. Since we plan to use the modified prospective application, we will not restate prior periods.

     Certain of Williams’ stock awards currently result in compensation cost under APB No. 25 and related guidance. These stock awards are subject to vesting provisions and Williams’ policy is to adjust compensation cost for forfeitures when they occur. Upon the July 1, 2005 adoption of the statement, Williams must adjust net income for previously recognized compensation cost, net of income taxes, related to the estimated number of these outstanding stock awards that are expected to be forfeited. This adjustment will be recognized in net income as the cumulative effect of a change in accounting principle. We have not estimated the amount of the adjustment for expected forfeitures.

     We currently present pro forma disclosure of net income as if compensation cost from all Williams’ stock awards were recognized based on the fair value recognition provisions of SFAS No. 123, “Accounting for Stock-Based Compensation.” We have not determined the Statement’s impact on net income beyond presentation of the pro forma disclosures. The Statement requires use of valuation techniques including option pricing models to estimate the fair value of employee stock awards. We are evaluating the appropriateness of several option pricing models, including a Black-Scholes model and a lattice model (such as a binomial model). Application of these two models could result in different estimates of fair value with resulting differences in compensation costs.

     Proposed FERC Accounting Guidance In November 2004, the FERC issued proposed accounting guidance on accounting for pipeline assessment costs. If adopted, we may be required to expense certain assessment costs that have historically been capitalized. For 2005, the estimated impact of this proposal would be an additional expense of $8 million to $13 million (unaudited).

Reclassifications

     Certain reclassifications have been made in the 2003 and 2002 financial statements to conform to the 2004 presentation.

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NORTHWEST PIPELINE CORPORATION

NOTES TO FINANCIAL STATEMENTS

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 has also filed claims against approximately 300 other energy companies and alleges that the defendants violated the False Claims Act in connection with the measurement, royalty valuation and purchase of hydrocarbons. The relief sought is an unspecified amount of royalties allegedly not paid to the federal government, treble damages, a civil penalty, attorneys’ fees, and costs. In April 1999, the DOJ declined to intervene in any of the Grynberg qui tam cases, including the action filed against the Williams entities in the United States District Court for the District of Colorado. In October 1999, the Panel on Multi-District Litigation transferred all of the Grynberg qui tam cases, including those filed against Williams, to the United States District Court for the District of Wyoming for pre-trial purposes. In October 2002, the court granted a motion to dismiss Grynberg’s royalty valuation claims. Grynberg’s measurement claims remain pending against Williams, including us, and the other defendants, although the defendants have filed a number of motions to dismiss these claims on jurisdictional grounds. Oral argument on these motions has been set for March 17, 2005, and we expect a decision in the second quarter of 2005.

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 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

     Pipeline Integrity Regulations We have developed an Integrity Management Plan that meets the United States Department of Transportation Office of Pipeline Safety (OPS) final rule pursuant to the requirements of the Pipeline Safety Improvement Act of 2002. In meeting the Integrity Regulations, we have identified the high consequence areas, including a baseline assessment and periodic reassessments to be completed within specified timeframes. Currently, we estimate that the cost to perform required assessments and repairs will be between $75 million and $100 million over the remaining assessment period of 2005 through 2012. Management considers the costs associated with compliance with the rule to be prudent costs incurred in the ordinary course of business and, therefore, recoverable through our rates.

Other Matters

     Williams responded to a subpoena from the Commodities Futures Trading Commission (CFTC) and inquiries from the FERC related to investigations involving natural gas storage inventory issues. We own and operate natural gas storage facilities. On August 30, 2004, the CFTC announced that it had concluded its investigation. The FERC inquiries related to the sharing of non-public data concerning inventory levels and the potential uses of such data in natural gas trading. The FERC investigation is continuing and Williams is engaged in discussions with FERC staff regarding the ultimate disposition of the matter.

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

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NORTHWEST PIPELINE CORPORATION

NOTES TO FINANCIAL STATEMENTS

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

Other Commitments

     We have commitments for construction and acquisition of property, plant and equipment of approximately $7.4 million at December 31, 2004.

2003 Pipeline Breaks in Washington

     In December 2003, we received an Amended Corrective Action Order (ACAO) from OPS regarding a segment of one of our natural gas pipelines in western Washington. The pipeline experienced two breaks in 2003 and we subsequently idled the pipeline segment until its integrity could be assured.

     By June 2004 we had successfully completed our hydrostatic testing program and returned to service 111 miles of the 268 miles of pipe affected by the ACAO. That effort has restored 131 MDth/day of the 360 MDth/day of idled capacity and is anticipated to be adequate to meet most market conditions. To date our ability to serve the market demand has not been significantly impacted.

     The restored facilities will be monitored and tested as necessary until they are ultimately replaced. Through December 31, 2004, approximately $40 million has been spent on testing and remediation costs, including approximately $8.9 million related to one segment of pipe that we recently determined not to return to service and was therefore written off in the second quarter of 2004.

     On October 4, 2004 we received a notice of probable violation (NOPV) from OPS. Under the provisions of the NOPV, OPS has issued a preliminary civil penalty of $100,000 for exceeding the pressure restriction on one of the segments covered under the original CAO. This penalty was accrued in the third quarter of 2004. The incident occurred on July 15, 2003 and did not occur as part of normal operations, but in preparation for running an internal inspection tool to test the integrity of the line. The operating pressure dictated by the original CAO was exceeded for approximately three hours due to the mechanical failure of an overpressure device and we immediately reported the incident to the OPS. There was no impact on pipeline facilities, and no additional sections of the pipeline were affected. Following the incident, new protocols were adopted to ensure that a similar situation would not occur in the future. We requested a hearing on the proposed OPS civil penalty, which was held in Denver, Colorado on December 15, 2004. OPS will issue its decision in the near future.

     As required by OPS, we plan to replace the pipeline’s entire capacity by November 2006 to meet long-term demands. We conducted a reverse open season to determine whether any existing customers were willing to relinquish or reduce their capacity commitments to allow us to reduce the scope of pipeline replacement facilities. That resulted in 13 MDth/day of capacity being relinquished and incorporated into the replacement project. On November 29, 2004, we filed with the FERC a certificate of application for the “Capacity Replacement Project”, including construction of approximately 79.5 miles of 36-inch pipeline and 10,760 net horsepower of additional compression at two existing compressor stations and abandonment of approximately 268 miles of the existing 26-inch pipeline. The estimated net cost of the Capacity Replacement Project included in the filing is approximately $333 million. The majority of these costs will be spent in 2005 and 2006. We anticipate filing a rate case to recover the capitalized costs relating to restoration and replacement facilities following the in-service date of the replacement facilities.

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NORTHWEST PIPELINE CORPORATION

NOTES TO FINANCIAL STATEMENTS

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.

Long-Term Debt

     Long-term debt consists of the following:

     As of December 31, 2004, 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 May 3, 2004, Williams entered into a new three-year, $1 billion secured revolving credit facility, which is available for borrowings and letters of credit. In August 2004, Williams expanded the credit facility by an additional $275 million. At December 31, 2004, letters of credit totaling $422 million, none of which are associated with us, have been issued by the participating institutions under this facility and no revolving credit loans were outstanding. Northwest and Transcontinental Gas Pipe Line Corporation, a subsidiary of WGP, have access to $400 million each under the facility. The new facility is secured by certain Williams midstream assets. Additionally, the facility is guaranteed by WGP. Interest is calculated based on a choice of two methods: a fluctuating rate equal to the facilitating bank’s base rate plus an applicable margin or a periodic fixed rate equal to the London Interbank Offered Rate (LIBOR) plus an applicable margin. Williams is also required to pay a commitment fee (currently 0.375 percent

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NORTHWEST PIPELINE CORPORATION

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 $6.2 million, $5.2 million, and $5.4 million for 2004, 2003 and 2002, respectively.

4. EMPLOYEE BENEFIT PLANS

Pension and Postretirement Medical Plans

     Our employees are covered by Williams’ noncontributory defined benefit pension plans 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 $5.9 million, $8.9 million and $5.9 million in 2004, 2003 and 2002, respectively. These amounts are currently recoverable in our rates.

Defined Contribution Plan

     Our employees are also covered by Williams’ defined contribution plan. Our costs related to this plan totaled $1.3 million, $1.5 million and $2.3 million in 2004, 2003 and 2002, respectively.

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NORTHWEST PIPELINE CORPORATION

NOTES TO FINANCIAL STATEMENTS

     On May 16, 2002, Williams’ stockholders approved The Williams Companies, Inc. 2002 Incentive Plan (the Plan). The Plan provides for common-stock-based-awards to its employees and employees of its subsidiaries. Upon approval by the stockholders, all prior 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 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 pro forma expense on the cancelled Williams options was being amortized through year-end 2004.

     The following summary provides information about our employees’ stock option activity related to Williams’ common stock for 2004, 2003 and 2002 (options in thousands):

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NORTHWEST PIPELINE CORPORATION

NOTES TO FINANCIAL STATEMENTS

     The estimated fair value at the date of grant of options for Williams common stock granted in 2004, 2003 and 2002, 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.

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NORTHWEST PIPELINE CORPORATION

NOTES TO FINANCIAL STATEMENTS

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

     The provision for income taxes includes:

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NORTHWEST PIPELINE CORPORATION

NOTES TO FINANCIAL STATEMENTS

     Net cash payments made to Williams for income taxes were $11.3 million, $3.5 million and $29.7 million in 2004, 2003 and 2002, 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 $528 million and $562 million, respectively, at December 31, 2004, and $535 million and $573 million, respectively, at December 31, 2003.

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.

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NORTHWEST PIPELINE CORPORATION

NOTES TO FINANCIAL STATEMENTS

     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.

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. At December 31, 2004, the advances due to us by Williams totaled $50.0 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. Prior to April 29, 2004, the advances were made to and received from our parent company, WGP. We received interest income from advances to these affiliates of $4.5 million, $2.7 million, and $1.6 million during 2004, 2003 and 2002, respectively. Such interest income is included in Other Income – net on the accompanying Statement of Income.

     Williams’ corporate overhead expenses allocated to us were $20.3 million, $14.2 million and $9.7 million for 2004, 2003 and 2002, 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 $7.9 million, $6.8 million and $4.6 million for 2004, 2003 and 2002, 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 $2.0 million, $1.6 million and $2.2 million for 2004, 2003 and 2002, 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.

8. IMPAIRMENTS

     In the second quarter of 2004, we wrote off $8.9 million of previously capitalized costs related to one segment of pipe that we recently determined not to return to service. (See the discussion of the 2003 Pipeline Breaks in Washington in Note 2 above.)

     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.

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NORTHWEST PIPELINE CORPORATION

NOTES TO FINANCIAL STATEMENTS

     The following is a summary of unaudited quarterly financial data for 2004 and 2003:

     Second quarter operating income includes the $8.9 million write off of previously capitalized costs incurred on an idled segment of our system that will not return to service due to the pipeline breaks in 2003. Third quarter operating income includes a $5.4 million adjustment to correct an error related to depreciation of certain in-house developed system software and other general plant issues. These assets, which were retired in prior years, continued to be depreciated, resulting in an over-depreciation of the assets. (See Property, Plant and Equipment in Note 1.)

     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.

10. SUBSEQUENT EVENTS (Unaudited)

      Duke Energy Trading and Marketing, LLC (Duke) has given notice to terminate its firm transportation agreement related to the Grays Harbor Lateral effective December 31, 2004, and pay us a lump sum amount based on the remaining net book value of the lateral facilities and related income taxes. In January 2005, Duke paid approximately $94 million towards this lump sum amount and disputed a portion of the lump sum amount requested by us. As of March 14, 2005, the final amount has not been agreed upon by Duke and us. However, based upon the payment already made, we do not anticipate any adverse impact to our results of operations or financial position in 2005. The monthly revenues from the Grays Harbor transportation agreement with Duke, which was terminated as of December 31, 2004, were approximately $1.6 million.

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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 Rule 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 these Disclosure Controls are effective at a reasonable assurance level.

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

     Notwithstanding the above, management concludes that its current controls are effective at a reasonable assurance level. In addition, there has been no material change in our Internal Controls that occurred during the registrant’s fourth quarter.

Item 9B.

None.

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 auditor services totaled $709 thousand in 2004 and $449 thousand in 2003, and include fees associated with the annual audit, the reviews for our quarterly reports on Form 10-Q, services performed in connection with other filings with the Securities and Exchange Commission and audit consultations. Additionally, audit fees for 2004 include fees related to the audit of Williams’ assessment and the effectiveness of internal controls over financial reporting as required by Section 404 of the Sarbanes-Oxley Act of 2002. Williams was required to report under Section 404 as of December 31, 2004. There were no audit-related, tax or other fees in 2004 or 2003.

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     As a wholly-owned subsidiary of Williams, we do not have a separate audit committee. The Williams audit committee policies and procedures for pre-approving audit and non-audit services will be filed with the Williams Proxy Statement to be filed with the Securities and Exchange Commission on or before April 11, 2005.

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PART IV

Item 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES

(a) 1. Financial Statements

Index

(a) 2. Financial Statement Schedules

NORTHWEST PIPELINE CORPORATION
SCHEDULE II – VALUATION AND QUALIFYING ACCOUNTS
(Thousands of Dollars)

     All other schedules have been omitted because they are not required to be filed.

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(a) 3 and b. Exhibits:

(2)

Plan of acquisition, reorganization, arrangement, liquidation or succession:

	*(a)	Merger Agreement, dated as of September 20, 1983, between Williams and Northwest Energy Company (Energy) (Exhibit 18 to Energy schedule 14D-9 (Amendment No. 3) dated September 22, 1983).
	*(b)	The Plan of Merger, dated as of November 7, 1983, between Energy and a subsidiary of Williams (Exhibit 2(b) to Northwest report on Form 10-K, No. 1-7414, filed March 22, 1984).

(3)

Articles of incorporation and by-laws:

	*(a)	Restated Certificate of Incorporation (Exhibit 3a to Amendment No. 1 to Registration Statement on Form S-1, No. 2-55-273, filed January 13, 1976).
	*(b)	By-laws, as amended (Exhibit 3c to Registration Statement on Form S-1, No. 2-55273, filed December 30, 1975).

(4)

Instruments defining the rights of security holders, including indentures:

	*(a)	Senior Indenture, dated as of August 1, 1992, between Northwest and Continental Bank, N.A., relating to Pipeline’s 9% Debentures, due 2022 (Exhibit 4.1 to Registration Statement on Form S-3, No. 33-49150, filed July 2, 1992).
	*(b)	Senior Indenture, dated as of November 30, 1995 between Northwest and Chemical Bank, relating to Pipeline’s 7.125% Debentures, due 2025 (Exhibit 4.1 to Registration Statement on Form S-3, No. 33-62639, filed September 14, 1995).
	*(c)	Senior indenture, dated as of December 8, 1997 between Northwest and The Chase Manhattan Bank, relating to Pipeline’s 6.625% Debentures, due 2007 (Exhibit 4.1 to Registration Statement on Form S-3, No. 333-35101, filed September 8, 1997).
	*(d)	Indenture dated March 4, 2003, between Northwest and JP Morgan Chase Bank, as Trustee (filed as Exhibit 4.1 to The Williams Companies, Inc. Form 10-Q for the quarter ended March 31, 2003, Commission File Number 1-4174).

(10) Material contracts:

(a)

*(1)

Form of Transfer Agreement, dated July 1, 1991, between Northwest and Gas Processing (Exhibit 10(c)(8) to Pipeline Report on Form 10-K, No. 1-7414, filed March 26, 1992).

		*(2)	Form of Operating Agreement, dated July 1, 1991, between Northwest and Williams Field Services Company (Exhibit 10(c)(9) to Pipeline Report on Form 10-K, No. 1-7414, filed March 26, 1992).
		*(1)	U.S $1,000,000,000 Credit Agreement dated as of May 3, 2004, among Williams, Northwest, Transcontinental Gas Pipe Line Corporation, as Borrowers, Citicorp USA, Inc., as Administrative Agent and Collateral Agent, Citibank, N.A. and Bank of America, N.A., as Issuing Banks, the banks named therein as Banks, Bank of America, N.A., as Syndication Agent, JPMorgan Chase Bank, The Bank of Nova Scotia, The Royal Bank of Scotland plc as Co-Documentation Agents, Citigroup Global Markets Inc. and Banc of America Securities LLC as Joint Lead Arrangers and Co-Book Runners (filed as Exhibit 10.4 to Williams Form 10-Q filed May 6, 2004 Commission File Number 1-4174).
		*(2)	Letter of Credit Commitment Increase Agreement dated August 4, 2004, by and among The Williams Companies, Inc., Citicorp USA in its capacity as Agent under the Credit Agreement dated as of May 3, 2004 among the Borrower, Northwest Pipeline Corporation, Transcontinental Gas Pipe Line Corporation, the Agent, the

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			Collateral Agent, the Banks and Issuing Banks party thereto and Citibank, N.A. and Bank of America, N.A. (filed as Exhibit 10.1 to The Williams Companies, Inc. Form 10-Q for the quarter ended September 30, 2004 Commission File Number 1-4174).
		*(3)	Revolving Credit Commitment Increase Agreement dated August 4, 2004, by and among The Williams Companies, Inc., Citicorp USA, Inc. in its capacity as Agent under the Credit Agreement dated as of May 3, 2004 among the Borrower, Northwest Pipeline Corporation, Transcontinental Gas Pipe Line Corporation, the Agent, the Collateral Agent and the Banks and Issuing Banks party thereto, the Issuing Banks and Citicorp USA, Inc. (filed as Exhibit 10.2 to The Williams Companies, Inc. Form 10-Q for the quarter ended September 30, 2004 Commission File Number 1-4174).
		*(4)	Amendment Agreement dated as of October 19, 2004, among Williams, Northwest, Transcontinental Gas Pipeline Corporation, as Borrowers, the banks, financial institutions and other institutional lenders that are parties to the Credit Agreement dated as of May 3, 2004, among the Borrowers, the Banks, Citicorp USA, Inc., as agent and Citibank, N.A. and Bank of America, N.A., as issuers of letters of credit under the Credit Agreement, the Agent and the Issuing Banks (filed as Exhibit 10.29 to Williams Form 10-K filed March 11, 2005 Commission File Number 1-4174).

(23) Consent of Independent Registered Public Accounting Firm

(24) Power of Attorney with Certified Resolution

(31) Section 302 Certifications

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

(32) Section 906 Certification

(a)

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

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SIGNATURES

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

Date: March 14, 2005

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