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)