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UNITED STATES SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D. C. 20549

FORM 10-K


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

For the fiscal year ended December 31, 2005


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

For the Transition Period from to

Commission File Number 1-7414

NORTHWEST PIPELINE CORPORATION

(Exact name of registrant as specified in its charter)


DELAWARE		87-0269236
(State or other jurisdiction of		(I.R.S. Employer
incorporation or organization)		Identification No.)

295 Chipeta Way, Salt Lake City, Utah		84108
(Address of principal executive offices)		(Zip Code)

(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 if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes o No þ

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act.
Yes o No þ

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act.


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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). 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.


Class		Outstanding at March 28, 2006

Common stock, $1 par value		1,000shares

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.

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). For 2005, Williams is a reporting entity under the Sarbanes-Oxley Act of 2002. Northwest is not an accelerated filer and therefore not required in 2005 to report 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, 2005, our system, having long term firm transportation agreements with peaking capacity of approximately 3.4 MMDth* of gas per day, was comprised of approximately 4,100 miles of mainline and lateral transmission pipelines and 42 transmission compressor stations. Our compression facilities have a combined sea level-rated capacity of approximately 462,000 horsepower.

In 2005, we served a total of 143 transportation and storage customers. Our transportation customers include distribution companies, municipalities, interstate and intrastate pipelines, gas marketers and direct industrial users. In 2005, our two largest customers were Puget Sound Energy, Inc. and Northwest Natural Gas Co., which accounted for approximately 17.6 percent and 11.0 percent, respectively, of our total operating revenues. No other customer accounted for more than 10 percent of our total operating revenues in 2005. 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.


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

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We believe that demand for natural gas in the Pacific Northwest will continue to increase and the growing preference for natural gas in response to environmental concerns supports 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 6.8 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.

Termination of the Grays Harbor Transportation Agreement

Effective January 2005, Duke Energy Trading and Marketing, LLC (Duke) terminated its firm transportation agreement related to the Grays Harbor Lateral. We invoiced Duke the amount we believe is contractually owed by Duke according to the terms of the facilities reimbursement agreement and Northwest’s tariff. Duke has paid us approximately $88 million for the remaining net book value of the lateral facilities and approximately $6 million towards the related income taxes. We have invoiced Duke for an additional $30 million, representing the additional income taxes related to the termination of the contract. This amount has not been paid to date by Duke. Accordingly, the income effects from the agreement termination have therefore been deferred pending the resolution of this matter. While the final income tax amount has not been agreed upon by Duke and us, based upon the payment already received, we do not anticipate any adverse impact to our results of operations or financial position. The monthly revenues from the Grays Harbor transportation agreement with Duke were approximately $1.6 million.

On June 16, 2005, we filed a Petition for a Declaratory Order with the FERC requesting that it rule on our interpretation of our tariff to aid in resolving the dispute with Duke. On July 15, 2005, Duke filed a motion to intervene and provided comments supporting its position concerning the issues in dispute. We anticipate that the FERC will rule on our petition during 2006.

2003 Pipeline Breaks in Washington

In December 2003, we received an Amended Corrective Action Order (ACAO) from the 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 in 2006. Through December 31, 2005, approximately $43.3 million has been spent on testing and remediation costs, including approximately $8.9 million related to one segment of pipe that we determined not to return to service and was therefore written off in the second quarter of 2004.

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On October 4, 2004, we received a notice of probable violation (NOPV) from OPS. Under the provisions of the NOPV, OPS issued a preliminary civil penalty of $100,000 for exceeding the pressure restriction on one of the segments covered under the original Corrective Action Order (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. A hearing on the proposed OPS civil penalty occurred on December 15, 2004, in Denver, Colorado and a decision is pending.

As required by OPS, we plan to replace all capacity associated with the segment affected by the ACAO 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 an application with the FERC for certificate authorization to construct and operate the “Capacity Replacement Project.” This project entails the abandonment of approximately 268 miles of the existing 26-inch pipeline, and the construction of approximately 80 miles of new 36-inch pipeline and an additional 10,760 net horsepower of compression at two existing compressor stations. The original cost of the abandoned assets and any cost of removal, net of salvage, will be charged to Accumulated Depreciation. At December 31, 2005, the net book value of the assets to be abandoned was $82.4 million. The estimated total cost of the proposed Capacity Replacement Project included in the filing is approximately $333 million, net of a $3.3 million contribution-in-aid-of-construction from a shipper that agreed to relinquish 13 MDth/d of capacity. A favorable preliminary determination was issued in May 2005 and we received and accepted the final FERC certificate in September 2005. We began construction of certain critical river crossings in late 2005. The main construction of pipeline and compression began in early 2006 with an anticipated in-service date of November 1, 2006.

We anticipate filing a rate case during the third quarter of 2006 to recover the capitalized costs relating to the restoration and replacement facilities. The new rates would become effective during the first quarter of 2007.

OPERATING STATISTICS

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


	Year Ended December 31,
	2005		2004		2003
	(In million dekatherms)
Total Throughput		673		650		682

Average Daily Throughput		1.8		1.8		1.9
Average Daily Reserved Capacity Under Long-Term Base Firm Contracts, excluding peak capacity		2.5		2.5		2.5
Average Daily Reserved Capacity Under Short-Term Firm Contracts (1)		.8		.6		.5


(1)		Includes additional capacity created from time to time through the installation of new receipt or delivery points or the segmentation of existing mainline capacity. Such capacity is generally marketed on a short-term firm basis.

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REGULATION

Interstate Gas Pipeline Operations

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.

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 through rates. We believe that compliance with applicable environmental requirements is not likely to have a material effect upon our financial position or results of operations.

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.

Item 1A. RISK FACTORS

FORWARD LOOKING STATEMENTS/RISK FACTORS AND CAUTIONARY STATEMENT FOR
PURPOSES OF THE “SAFE HARBOR” PROVISIONS OF
THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995

Certain matters contained in this report, 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 report which address activities, events or developments that we expect, believe or anticipate will exist or may occur in the future, are forward-looking statements. Forward-looking statements can be identified by various forms of words such as “anticipates,” “believes,” “could,” “may,” “should,” “continues,” “estimates,” “expects,” “forecasts,” “might,” “planned,” “potential,” “projects,” “scheduled” or similar expressions. These forward-looking statements include, among others, statements regarding:

	•		amounts and nature of future capital expenditures;

	•		expansion and growth of our business and operations;

	•		business strategy;

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	•		cash flow from operations;

	•		rate case filings;

	•		power and gas prices and demand.

Forward-looking statements are based on numerous assumptions, uncertainties and risks that could cause future events or results to be materially different from those stated or implied in this document.

Some of these risks are described in the “Risk Factors” section of this report and one should keep in mind these risk factors when considering forward-looking statements. Given the uncertainties and risk factors that could cause our actual results to differ materially from those contained in any forward-looking statement, we caution investors not to unduly rely on our forward-looking statements. We disclaim any 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. Further, the information about our intentions contained or incorporated into this report represents our intention as of the date of this report and is based on, among other things, the existing regulatory environment, industry conditions, market conditions and prices, the economy in general and our assumptions as of such date. We may change our intentions, at any time and without notice, based upon any changes in such factors, in our assumptions, or otherwise.

RISK FACTORS

You should carefully consider the following risk factors in addition to the other information in this report. Each of these factors could adversely affect our business, operating results, and financial condition as well as adversely affect the value of an investment in our securities.

Risks Inherent to our Industry and Business

Decreases in the volume of natural gas contracted or transported through our pipeline system for any of the reasons described below will adversely affect our business.

Expiration of firm transportation agreements. A substantial portion of our operating revenues are generated through firm transportation agreements that expire periodically and must be renegotiated and extended or replaced. We cannot give any assurance as to whether any of these agreements will be extended or replaced or that the terms of any renegotiated agreements will be as favorable as the existing agreements. Upon the expiration of these agreements, should customers turn back or substantially reduce their commitments, we could experience a significant decline in our revenues.

Decreases in natural gas production. 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 transmission pipeline facilities. Additionally, in some cases, new LNG import facilities built near our markets could result in less demand for our transmission facilities.

Decreases in demand of natural gas. Demand depends on the ability and willingness of shippers with access to our facilities to satisfy their demand by deliveries through our system. Any decrease in this demand could adversely after our business. Demand of natural gas is also dependent upon the impact of weather, future industrial and economic conditions, fuel conservation measures, alternative fuel requirements, governmental regulation, or technological advances fuel economy and energy generation devices, all of which are matters beyond our control.

Competitive pressures. Although most of our pipeline system’s current capacity is contracted under firm transportation service agreements The FERC has taken certain actions to strengthen market

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forces in the natural gas pipeline industry that have led to increased competition throughout the industry. In a number of key markets, interstate pipelines are now facing competitive pressure from other major pipeline systems, enabling local distribution companies and end users to choose a transmission provider based on considerations other than location. Other entities could construct new pipelines or expand existing pipelines that could potentially serve the same markets as our pipeline system. Any such new pipelines could offer transportation services that are more desirable to shippers because of locations, facilities, or other factors. These new pipelines could charge rates or provide service to locations that would result in greater net profit for shippers and producers and thereby force us to lower the rates charged for service on our pipeline in order to extend our existing transportation service agreements or to attract new customers We are aware of proposals by competitors to expand pipeline capacity in certain markets we also serve. There can be no assurance that any such proposed project might not proceed and increase the competitive pressures upon us.

Our transporting activities involve numerous risks that might result in accidents and other operating risks and costs.

Our operations are subject to all the risks and hazards typically associated with the transportation of natural gas. These operating risks include, but are not limited to:

	•		blowouts, cratering and explosions;

	•		uncontrollable flows of natural gas;

	•		fires;

	•		pollution and other environmental risks;

	•		natural disasters;

	•		terrorist attacks or threatened attacks on our facilities or those of other energy companies.

In addition, there are inherent in our gas transporting 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 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. Certain segments of our pipeline run through such areas. In spite of our precautions, an event could cause considerable harm to people or property, and could have a material adverse effect on our financial 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.

Costs of environmental liabilities and complying with existing and future environmental regulations could exceed our current expectations.

Our operations are subject to extensive environmental regulation pursuant to a variety of federal, state and municipal laws and regulations. Such laws and regulations impose, among other things, restrictions, liabilities and obligations in connection with the generation, handling, use, storage, transportation, treatment and disposal of hazardous substances and wastes, in connection with spills, releases and emissions of various substances into the environment, and in connection with the operation, maintenance, abandonment and reclamation of our facilities.

Compliance with environmental laws will require significant expenditures including clean up costs and damages arising out of contaminated properties. The possible failure to comply with environmental laws and regulations might result in the imposition of fines and penalties. We are generally responsible for all liabilities associated with the environmental condition of our facilities and assets, whether acquired or developed, regardless of when the liabilities arose and whether they are known or unknown. In

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connection with certain acquisitions and divestitures, we could acquire, or be required to provide indemnification against environmental liabilities that could expose us to material losses, which may not be covered by insurance. In addition, the steps we could be required to take to bring certain facilities into compliance could be prohibitively expensive, and we might be required to shut down, divest, or alter the operation of those facilities, which might cause us to incur losses. Although we do not expect that the costs of complying with current environmental laws will have a material adverse effect on our financial condition or results of operations, no assurance can be given that the costs of complying with environmental laws in the future will not have such an effect.

We make assumptions and develop expectations about possible expenditures related to environmental conditions based on current laws and regulations and current interpretations of those laws and regulations. If the interpretation of laws or regulations, or the laws and regulations themselves, change, our assumptions may change. Our regulatory rate structure and our contracts with customers might not necessarily allow us to recover capital costs we incur to comply with the new environmental regulations. Also, we might not be able to obtain or maintain from time to time all required environmental regulatory approvals for certain development projects. If there is a delay in obtaining any required environmental regulatory approvals or if we fail to obtain and comply with them, the operation of our facilities could be prevented or become subject to additional costs, resulting in potentially material adverse consequences to our operations.

Risks Related to Strategy and Financing

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

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

Our failure to comply with the covenants in our debt agreements and other related transactional documents could result in events of default. Upon the occurrence of such an event of default, the lenders could elect to declare all amounts outstanding under a particular facility to be immediately due and payable and terminate all commitments, if any, to extend further credit. An event of default or an acceleration under one debt agreement could cause a cross-default or cross-acceleration of another debt agreement. Such a 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 an event of default occurs, or if other debt agreements cross-default, and the lenders under the affected debt agreements accelerate the maturity of any loans or other debt outstanding to us, we may not have sufficient liquidity to repay amounts outstanding under such debt agreements.

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

Because we do not have an investment grade credit rating, our transactions require greater credit assurances to satisfy credit support requirements. In addition, we are more vulnerable to the impact of market disruptions or a further downgrade of our credit rating that might further increase our cost of borrowing or further impair our ability to access one or any of the capital markets. Such disruptions could include:

	•		further economic downturns;

	•		deteriorating capital market conditions generally;

	•		declining market prices for electricity and natural gas;

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•

the overall health of the energy industry, including the bankruptcy or insolvency of other companies.

Williams can exercise substantial control over our dividend policy and our business and operations and may do so in a manner that is adverse to our or your interests.

We are an indirect wholly-owned subsidiary of Williams. Our board of directors, which is elected by WGP, which in turn is controlled by Williams, exercises substantial control over our business and operations and makes determinations with respect to, among other things, the following:

	•		payment of dividends and repayment of advances;

	•		decisions on financings and our capital raising activities;

	•		mergers or other business combinations;

	•		acquisition or disposition of assets.

Our board of directors could decide to increase dividends or advances to our parent entities. This could adversely affect our liquidity. Moreover, various Williams credit facilities include covenants restricting the ability of Williams entities, including us, to make advances to Williams and its other subsidiaries, which could make the terms on which we may be able to secure additional future financing less favorable.

The financial condition and liquidity of Williams affects our access to capital, our credit standing and our financial condition.

Substantially all of Williams’ operations are conducted through its subsidiaries. Williams’ cash flows are substantially derived from loans and dividends paid to it by its subsidiaries, including WGP, our parent company under which Williams’ interstate natural gas pipelines and gas pipeline joint venture investments are grouped. Williams’ cash flows are typically utilized to service debt and pay dividends on the common stock of Williams, with the balance, if any, reinvested in its subsidiaries as contributions to capital.

Our ratings and credit are impacted by Williams’ credit standing. If Williams were to experience a deterioration in its credit standing or liquidity difficulties, our access to credit and our ratings could be adversely affected.

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. Our 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.

We are exposed to the credit risk of our customers in the ordinary course of our business.

We are exposed to the credit risk of our customers in the ordinary course of our business. Generally our customers are rated investment grade or are required to make pre-payments or provide security to satisfy credit concerns. However, we cannot predict at this time to what extent our business would be impacted by deteriorating conditions in the energy sector, including declines in our customers’ creditworthiness.

Risks Related to Regulations that Affect our Industry

Our transmission and storage operations are subject to government regulations and rate proceedings that could have an adverse impact on the profitability of these operations.

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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;

	•		operating terms and conditions of service.

Regulatory actions in these areas can affect our business in many ways, including decreasing tariff rates and revenues, decreasing volumes in our pipelines, increasing our costs and otherwise altering the profitability of our business.

The FERC’s Order No. 2004 contains standards of conduct for transmission providers when dealing with “energy affiliates” as defined by the rule. The standards of conduct are intended to prevent transmission providers from preferentially benefiting their energy affiliates by requiring the employees of a transmission provider to function independently from employees of energy affiliates and by restricting the information that transmission providers may provide to energy affiliates. The inefficiencies created by the restrictions on the sharing of employees and information may increase our costs, and the restrictions on the sharing of information may have an adverse impact on our senior management’s ability to effectively obtain important information about our business. Violators of the rules are subject to potentially substantial civil penalty assessments.

The outcome of pending rate cases to set the rates we can charge customers on our pipeline might result in rates that lower our return on the capital that we have invested in our pipeline.

We anticipate that we will file a rate case with the FERC during the third quarter of 2006 to request changes to the rates we charge. The new rates would become effective during the first quarter of 2007. The outcome of this rate case is uncertain. There is a risk that rates set by the FERC will lower our return on the capital we have invested in our assets. There is also the risk that higher rates will cause us to discount our services or result in our customers seeking alternative ways to transport their natural gas.

Legal and regulatory proceedings and investigations relating to the energy industry and capital markets have adversely affected our business and many continue to do so.

Public and regulatory scrutiny of the energy industry and of the capital markets has resulted in increased regulation being either proposed or implemented. Such scrutiny has also resulted in various inquiries, investigations and court proceedings in which we are a named defendant.

Such inquiries, investigations and court proceedings are ongoing and continue to adversely affect our business as a whole. We might see these adverse effects continue as a result of the uncertainty of these ongoing inquiries and proceedings, or additional inquiries and proceedings by federal or state regulatory agencies or private plaintiffs. In addition, we cannot predict the outcome of any of these inquiries or whether these inquiries will lead to additional legal proceedings against us, civil or criminal fines or penalties, or other regulatory action, including legislation, which might be materially adverse to the operation of our business and our revenues and net income or increase our operating costs in other ways. Current legal proceedings or other matters against us including disputes over gas measurement, royalty payments, suits, regulatory appeals and similar matters might result in adverse decisions against

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us. The result of such adverse decisions, either individually or in the aggregate, could be material and may not be covered fully or at all by insurance.

Risks Related to Accounting Standards

Potential changes in accounting standards might cause us to revise our financial results and disclosure in the future, which might change the way analysts measure our business or financial performance.

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, companies’ relationships with their independent auditors and retirement plan 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, the energy industry or in our operations specifically.

In addition the Financial Accounting Standards Board (FASB), the Securities and Exchange Commission (SEC) or the FERC could enact new accounting standards or FERC orders that might impact how we are required to record revenues, expenses, assets and liabilities.

Risks Related to Employees, Outsourcing of Non-Core Support Activities.

Institutional knowledge residing with current employees or former Williams employees now employed by Williams’ outsourcing service providers might not be adequately preserved.

In our business, institutional knowledge resides with employees who have many years of service. As these employees reach retirement age, we may not be able to replace them with employees of comparable knowledge and experience. Other qualified individuals could leave us or refuse our offers of employment if our recruiting and retention efforts are unsuccessful. Our efforts at knowledge transfer could be inadequate.

Due to the large number of former Williams employees who were migrated to an outsourcing provider in 2004, access to significant amounts 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 accounting, information technology application development, human resources, and help desk services that are currently provided by Williams’ outsourcing provider were relocated to service centers 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.

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Risks Related to Weather, Other Natural Phenomena and Business Disruption

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

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

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

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

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

Some portions of our pipeline infrastructure are 50 years in age which may impact our ability to provide reliable service. Additionally, the current age and condition of our pipeline infrastructure may result in significant increases in the level of expenditures needed to maintain our equipment and facilities.

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. (See Note 2 of the Notes to Financial Statements.)

Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

Since we meet the conditions set forth in General Instruction (I)(1)(a) and (b) of Form 10-K, this information is omitted.

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PART II

Item 5. MARKET FOR REGISTRANT’S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS

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

We paid $50 million and $60 million in cash dividends during 2005 and 2004, respectively.

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 Part II Item 8 of this document.

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 probable that such rates can be charged and collected. Accounting for businesses that are regulated and apply the provisions of SFAS No. 71 can differ from the accounting requirements for non-regulated businesses. Transactions that are recorded differently as a result of regulatory accounting requirements include the capitalization of an equity return component on regulated capital projects, employee related benefits, levelized depreciation, negative salvage/asset retirement obligations, environmental costs 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, 2005, we had approximately $60.0 million of regulatory assets primarily related to equity funds used during construction, levelized incremental projects, asset retirement obligations, environmental costs and other postemployment benefits, and approximately $26.7 million of regulatory liabilities related to postretirement benefits and negative salvage included on the accompanying Balance Sheet. At December 31, 2004, we had approximately $36.4 million of regulatory assets primarily related to equity funds used during construction, levelized incremental projects and other postemployment benefits, and approximately $22.4 million of regulatory liabilities related to postretirement benefits and negative salvage included on the accompanying Balance Sheet.

-12-

Revenue Subject to Refund

FERC regulations promulgate policies and procedures, which govern a process to establish the rates that we are permitted to charge customers for natural gas services, including the transportation and storage of natural gas. Key determinants in the ratemaking process are (i) costs of providing service, including depreciation expense, (ii) allowed rate of return, including the equity component of the 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, 2005, we have no pending regulatory proceedings and no potential rate refunds.

Contingent Liabilities

We record liabilities for estimated loss contingencies, including environmental matters, when we assess that a loss is probable and the amount of the loss can be reasonably estimated. Revisions to contingent liabilities are reflected in income in the period in which new or different facts or information become known or circumstances change that affect the previous assumptions with respect to the likelihood or amount of loss. Liabilities for contingent losses are based upon our assumptions and estimates, and advice of legal counsel or other third parties regarding the probable outcomes of the matter. As new developments occur or more information becomes available, our assumptions and estimates of these liabilities may change. Changes in our assumptions and estimates or outcomes different from our current assumptions and estimates could materially affect future results of operations for any particular quarterly or annual period.

Impairment of Long-Lived Assets

We evaluate long-lived assets for impairment when events or changes in circumstances indicate, in management’s judgment, that the carrying value of such assets may not be recoverable. When such a determination has been made, management’s estimate of undiscounted future cash flows attributable to the assets is compared to the carrying value of the assets to determine whether an impairment has occurred. If an impairment of the carrying value has occurred, the amount of the impairment recognized in the 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.

Asset Retirement Obligations

We record an asset and a liability equal to the present value of each expected future asset retirement obligation (ARO). The ARO asset is depreciated in a manner consistent with the depreciation of the underlying physical asset. We measure changes in the liability due to passage of time by applying an interest method of allocation. This amount is recognized as an increase in the carrying amount of the liability and offset by a regulatory asset.

FERC Accounting Guidance

On June 30, 2005, the FERC issued an order, “Accounting for Pipeline Assessment Cost,” to be applied prospectively effective January 1, 2006. The Order requires companies to expense certain pipeline integrity-related assessment costs that we have historically capitalized. We anticipate expensing approximately $7 million to $10 million of costs expected to be incurred in 2006 that would have been capitalized prior to the Order becoming effective.

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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 2005 and 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.

Operating revenues decreased $17.1 million, or 5%, due primarily to the termination of the Grays Harbor agreement as described in “Item 1. Business — Termination of the Grays Harbor Transportation Agreement” on page 2.

Our transportation service accounted for 96 percent of our operating revenues for the years ended December 31, 2005 and 2004, respectively. Additionally, gas storage service accounted for 3 percent of our operating revenues for each of the years ended December 31, 2005 and 2004.

Operating expenses increased $1.3 million, or 1 percent. This increase is due primarily to $3.0 million in higher charges related to the rental of facilities, $2.7 million lower net regulatory credits associated with our incremental facilities, $2.3 million in higher labor costs, $2.1 million in higher outside administrative charges related primarily to outsourced information technology services, and a $1.9 million expense for amounts paid to a third party to modify a pipeline assessment tool, owned by the third party, for use in our 26-inch pipelines. These increases were partially offset by the 2004 write-off of $8.9 million of previously capitalized costs incurred on an idled segment of our system that will not return to service and $2.7 million in favorable adjustments in 2005 to ad valorem taxes reflecting negotiated assessment reductions. Depreciation expense increased $0.7 million due primarily to a $5.4 million adjustment made in 2004 to correct an error related to the over-depreciation of certain in-house developed system software and other general plant assets. This increase was mostly offset by lower depreciation in 2005 resulting from the retirement of the Grays Harbor Lateral.

Operating income decreased $18.4 million, or 12 percent, due to the reasons discussed above.

Other income increased $5.3 million, or 101 percent, primarily due to a $2.5 million increase in interest income on higher levels of short term investments and a $2.1 million increase in the allowance for equity funds used during construction resulting from the rising capital expenditures in 2005.

The higher capital expenditures in 2005 also resulted in a $1.1 million increase in the allowance for borrowed funds used during construction.

The provision for income taxes decreased $6.6 million due primarily to lower pre-tax income in 2005 as compared to 2004 and a $1.8 million tax benefit adjustment as a result of additional analysis of our tax basis and book basis assets and liabilities. The 2005 effective income tax rate has been reduced as a result of this adjustment and favorable settlements on federal and state income tax matters. (See Note 5 of the Notes to Financial Statements.)

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 based upon inflation’s effect on costs.

-14-

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 shelf registration statement on file with the SEC. At December 31, 2005, $200 million of availability remained under this registration statement. While our credit ratings remain below investment grade, the shelf registration may only be utilized to issue debt securities if such securities are guaranteed by Williams. However, we can raise capital through private debt offerings as well as offerings registered pursuant to offering-specific registration statements, without a guaranty from Williams. Interest rates, market conditions, and industry conditions will affect amounts raised, if any, in the capital markets. We believe any additional financing arrangements, if required, can be obtained from the capital markets on terms that are commensurate with our current credit ratings.

During May 2005, we, together with Williams and Transcontinental Gas Pipe Line Corporation (Transco), an affiliate, amended and restated our $1.275 billion secured revolving credit facility (Credit Agreement), which is available for borrowings and letters of credit, resulting in certain changes, including the following:

	•		added Williams Partners L.P. as a borrower for up to $75 million;

	•		provided Williams’ guarantee for the obligations of Williams Partners L.P. under this agreement;

	•		released certain Williams’ midstream assets held as collateral and replaced them with the common stock of Transco; and

	•		reduced commitment fees and margins.

At December 31, 2005, letters of credit totaling $378 million, none of which are associated with us, have been issued and no revolving credit loans were outstanding. We and Transco each have access to $400 million under this facility to the extent not utilized by Williams. 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 rate to LIBOR plus an applicable margin. We are required to pay a commitment fee (currently 0.325 percent annually) based on the unused portion of the facility. The applicable margin and commitment fee are based on the relevant borrower’s senior unsecured long-term debt ratings.

As a participant in Williams’ cash management program, we make advances to and receive advances from Williams. At December 31, 2005, the advances due to us by Williams totaled $50 million. The advances are represented by demand notes. The interest rate on intercompany demand notes is based upon the weighted average cost of Williams’ debt outstanding at the end of each quarter. 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.

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 (rating agencies).

The credit ratings on our senior unsecured long-term debt did not change during 2005 and are shown below.

-15-


Moody’s Investors Service		Ba2
Standard and Poor’s		B+
Fitch Ratings		BB+

During 2005, Standard and Poor’s upgraded their evaluation of our credit rating outlook from stable to positive, while the Moody’s Investors Service and Fitch Ratings evaluations remained unchanged with a stable outlook. In March 2006, Fitch Ratings raised their evaluation of our credit rating outlook to positive.

CAPITAL EXPENDITURES

Our expenditures for property, plant and equipment additions were $137.2 million, $102.2 million and $294.5 million for 2005, 2004 and 2003, respectively. We anticipate 2006 capital expenditures will be between $435 million and $475 million. These expenditures will primarily be for the Capacity Replacement Project associated with the 2003 pipeline breaks in Washington and for the Parachute Lateral Project discussed below, but will also include maintenance capital expenditures and other non-expansion related items including expenditures required for the Pipeline Safety Improvement Act of 2002. The remaining expenditures required to replace the capacity of the 26-inch pipeline 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 during the third quarter of 2006 to recover these costs. The new rates would become effective during the first quarter of 2007.

Parachute Lateral Project

In January 2006, we filed an application with the FERC to construct a 38-mile lateral that would provide additional transportation capacity in northwest Colorado. The planned lateral would increase capacity by 450 MDth/day through a 30-inch diameter line and is estimated to cost $55 million. We anticipate beginning service on the expansion in January 2007.

OTHER

Contractual Obligations

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


			2007 -		2009 -		There-
	2006		2008		2010		after		Total
Long-term debt, including current portion:
Principal	$	7.5	$	252.9	$	175.0	$	85.0		$	520.4
Interest		37.8		57.4		33.4		90.8			219.4

Operating leases		6.4		12.8		6.3		—			25.5

Purchase Obligations:
Natural gas purchase, storage, transportation and construction		87.1		5.1		2.7		—			94.9
Other		.5		.9		.6		.1			2.1


Total	$	139.3	$	329.1	$	218.0	$	175.9		$	862.3

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.

-16-

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.

Item 7A. QUALITATIVE AND QUANTITATIVE DISCLOSURES ABOUT MARKET RISK

Interest Rate Risk

Our interest rate risk exposure is limited to our 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, 2005. The table presents principle cash flows (at face value) and weighted-average interest rates by expected maturity dates.

December 31, 2005


	Expected Maturity Date
	2006			2007			2008			2009			2010			Thereafter			Total		Fair Value
	(millions of dollars)
Long-term debt, including current portion:
Fixed rate	$	7.5		$	252.9		$	—		$	—		$	175.0		$	85.0		$	520.4	$	541.8
Interest rate		7.2	%		7.3	%		7.8	%		7.8	%		7.4	%		7.1	%

-17-

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, 2005 and 2004, 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, 2005. Our audits also included the financial statement schedule listed in the Index at Item 15(a). These financial statements and schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and schedule based on our audits.

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

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Northwest Pipeline Corporation at December 31, 2005 and 2004, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2005, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein.

As explained in Note 1 to the financial statements, effective December 31, 2005, the Company adopted FASB Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations.”


		/s/ ERNST & YOUNG LLP

Houston, Texas
March 8, 2006

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NORTHWEST PIPELINE CORPORATION

STATEMENT OF INCOME

(Thousands of Dollars)


	Years Ended December 31,
	2005			2004			2003
OPERATING REVENUES	$	321,457		$	338,532		$	323,353


OPERATING EXPENSES:
General and administrative		49,749			51,062			45,693
Operation and maintenance		53,330			42,878			31,842
Depreciation		66,333			65,615			66,735
Regulatory credits		(4,446	)		(7,180	)		(6,357	)
Taxes, other than income taxes		15,115			17,492			19,220
Impairment charges (Note 8)		—			8,872			25,643


Total operating expenses		180,081			178,739			182,776


Operating income		141,376			159,793			140,577


OTHER INCOME — net		10,597			5,278			14,178


INTEREST CHARGES:
Interest on long-term debt
Other interest		38,164			38,721			37,144
Allowance for borrowed funds used during construction		3,389			3,368			3,388
		(1,529	)		(452	)		(3,589	)


Total interest charges		40,024			41,637			36,943


INCOME BEFORE INCOME TAXES		111,949			123,434			117,812

PROVISION FOR INCOME TAXES		40,194			46,779			44,518


NET INCOME	$	71,755		$	76,655		$	73,294


CASH DIVIDENDS ON COMMON STOCK	$	50,000		$	60,000		$	—

See accompanying notes.

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NORTHWEST PIPELINE CORPORATION

BALANCE SHEET

(Thousands of Dollars)


	December 31,
	2005		2004
ASSETS

CURRENT ASSETS:
Cash and cash equivalents	$	59,709	$	53,393
Advances to affiliates		50,000		50,000
Accounts receivable —
Trade, less reserves of $91 for 2005 and $320 for 2004		27,779		29,462
Affiliated companies		4,015		1
Income taxes due from affiliate		1,475		—
Materials and supplies, less reserves of $263 for 2005 and $439 for 2004		8,365		8,601
Exchange gas due from others		11,257		16,011
Exchange gas offset (Note 1)		9,386		—
Deferred income taxes		3,913		4,173
Prepayments and other		2,179		1,879


Total current assets		178,078		163,520

PROPERTY, PLANT AND EQUIPMENT, at cost		2,286,280		2,273,333
Less — Accumulated depreciation		957,385		933,297


Total property, plant and equipment		1,328,895		1,340,036


OTHER ASSETS:
Deferred charges		49,124		50,019
Regulatory assets		60,007		36,361


Total other assets		109,131		86,380


Total assets	$	1,616,104	$	1,589,936

See accompanying notes.

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NORTHWEST PIPELINE CORPORATION

BALANCE SHEET

(Thousands of Dollars)


	December 31,
	2005		2004
LIABILITIES AND STOCKHOLDER’S EQUITY
CURRENT LIABILITIES:
Accounts payable —
Trade	$	26,535	$	9,901
Affiliated companies		3,754		16,103
Accrued liabilities —
Income taxes due to affiliate		—		3,436
Taxes, other than income taxes		8,511		11,599
Interest		7,013		7,294
Employee costs		8,731		7,828
Exchange gas due to others		20,643		13,939
Exchange gas offset (Note 1)		—		2,072
Deferred contract termination income		6,045		—
Other		3,618		3,783
Current maturities of long-term debt		7,500		7,500


Total current liabilities		92,350		83,455


LONG-TERM DEBT, LESS CURRENT MATURITIES		512,580		520,062

DEFERRED INCOME TAXES		236,548		255,379

DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES		65,869		44,038

CONTINGENT LIABILITIES AND COMMITMENTS

COMMON STOCKHOLDER’S EQUITY:
Common stock, par value $1 per share; authorized and outstanding, 1,000 shares		1		1
Additional paid-in capital		262,844		262,844
Retained earnings		445,912		424,157


Total common stockholder’s equity		708,757		687,002


Total liabilities and stockholder’s equity	$	1,616,104	$	1,589,936

See accompanying notes.

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NORTHWEST PIPELINE CORPORATION

STATEMENT OF CASH FLOWS
(Thousands of Dollars)


	Years Ended December 31,
	2005			2004			2003
OPERATING ACTIVITIES:
Net Income
Adjustments to reconcile to net cash provided by operating activities -
Depreciation	$	71,755		$	76,655		$	73,294
Regulatory credits		66,333			65,615			66,735
Provision (benefit) for deferred income taxes		(4,446	)		(7,180	)		(6,357	)
Impairment charges		(18,571	)		33,524			51,735
Amortization of deferred charges and credits		—			8,872			25,643
Allowance for equity funds used during construction		4,053			4,189			4,523
Reserve for doubtful accounts		(2,872	)		(806	)		( 8,600	)
Changes in:		44			—			(166	)
Trade accounts receivable		1,639			918			1,723
Affiliated receivables, including income taxes		(5,489	)		577			197
Exchange gas due from others		(4,632	)		(5,765	)		5,764
Materials and supplies		236			899			1,010
Other current assets		(800	)		685			(1,229	)
Deferred charges		(6,992	)		(5,854	)		(1,546	)
Trade accounts payable		8,931			(6,279	)		11,244
Affiliated payables, including income taxes		(15,785	)		5,019			(5,165	)
Exchange gas due to others		4,632			5,765			(5,764	)
Other accrued liabilities		6,440			2,422			5,222
Other deferred credits		3,659			2,592			570
Other		—			—			(25	)


Net cash provided by operating activities		108,135			181,848			218,808


INVESTING ACTIVITIES:
Property, plant and equipment -
Capital expenditures		(137,232	)		(102,213	)		(294,524	)
Proceeds from sales		—			5,033			—
Asset removal cost		(1,568	)		—			(1,898	)
Changes in accounts payable		6,564			(784	)		(14,782	)
Proceeds from contract termination payment		87,917			—			—
Repayments from (Advances to) affiliates		—			36,356			(69,074	)


Net cash used in investing activities		(44,319	)		(61,608	)		(380,278	)


FINANCING ACTIVITIES:
Proceeds from issuance of long-term debt		—			—			175,000
Principal payments on long-term debt		(7,500	)		(7,500	)		(7,500	)
Debt issuance costs		—			—			(5,584	)
Dividends paid		(50,000	)		(60,000	)		—


Net cash (used in) provided by financing activities		(57,500	)		(67,500	)		161,916


NET INCREASE IN CASH AND CASH EQUIVALENTS		6,316			52,740			446

CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR		53,393			653			207


CASH AND CASH EQUIVALENTS AT END OF YEAR	$	59,709		$	53,393		$	653

See accompanying notes.

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NORTHWEST PIPELINE CORPORATION

NOTES TO FINANCIAL STATEMENTS

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Corporate Structure and Control

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

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

Nature of Operations

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

Regulatory Accounting

We are regulated by the Federal Energy Regulatory Commission (FERC). Statement of Financial Accounting Standards (SFAS) No. 71, “Accounting for the Effects of Certain Types of Regulation,” provides that rate-regulated public utilities account for and report regulatory assets and liabilities consistent with the economic effect of the way in which regulators establish rates if the rates established are designed to recover the costs of providing the regulated service and if the competitive environment makes it probable that such rates can be charged and collected. Accounting for businesses that are regulated and apply the provisions of SFAS No. 71 can differ from the accounting requirements for non-regulated businesses. Transactions that are recorded differently as a result of regulatory accounting requirements include the capitalization of an equity return component on regulated capital projects, employee related benefits, levelized depreciation, negative salvage/asset retirement obligations, environmental costs 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, 2005, we had approximately $60.0 million of regulatory assets primarily related to equity funds used during construction, levelized incremental projects, asset retirement obligations, environmental costs and other postemployment benefits, and approximately $26.7 million of regulatory liabilities related to postretirement benefits and negative salvage included on the accompanying Balance Sheet. At December 31, 2004, we had approximately $36.4 million of regulatory assets primarily related to equity funds used during construction, levelized incremental projects and other postemployment benefits, and approximately $22.4 million of regulatory liabilities related to postretirement benefits and negative salvage included 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 $76.3 million, as of December 31, 2005, to us as current FERC policy does not permit us to recover these amounts through our rates. The accompanying financial statements reflect our original basis in our assets and liabilities.

Use of Estimates

-26-

NORTHWEST PIPELINE CORPORATION

NOTES TO FINANCIAL STATEMENTS

Estimates and assumptions which, in the opinion of management, are significant to the underlying amounts included in the financial statements and for which it would be reasonably possible that future events or information could change those estimates include: 1) revenues subject to refund; 2) litigation-related contingencies; 3) environmental remediation obligations; 4) impairment assessments of long-lived assets; 5) deferred and other income taxes; 6) depreciation; 7) pension and other post-employment benefits; and 8) asset retirement obligations.

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 by class of assets for property, plant and equipment. The annual weighted average composite depreciation rate recorded for transmission and storage plant was 2.96 percent, 3.00 percent and 3.00 percent for 2005, 2004 and 2003, 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.

We recorded regulatory credits totaling $4.4 million in 2005, $7.2 million in 2004, and $6.4 million in 2003 in the accompanying Statement of Income. These credits relate primarily to the levelized depreciation for the Evergreen Project discussed above. The accompanying Balance Sheet reflects the related regulatory assets of $18.1 million at December 31, 2005, and $13.6 million at December 31, 2004. Such amounts will be amortized over the primary terms of the Evergreen shipper agreements as such costs are collected through rates.

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

We adopted the Interpretation on December 31, 2005. In accordance with the Interpretation, we estimated future retirement obligations for certain assets previously considered to have an indeterminate life. As a result, we recorded an asset retirement obligation of $15.4 million and a net increase in Property, Plant and Equipment of $0.9 million. We also recorded a $14.5 million regulatory asset for retirement costs expected to be recovered through our rates. Had we implemented the Interpretation at the beginning of 2003, the financial statement impact at December 31, 2004 would not be substantially different than the impact at December 31, 2005.

The accrued obligations relate to our gas storage and transmission facilities. At the end of the useful life of our facilities, we are legally obligated to remove certain transmission facilities including underground pipelines, major river spans, compressor stations and meter station facilities. These

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obligations also include restoration of the property sites after removal of the facilities from above and below the ground.

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, effective January 1, 2003, the negative salvage component of Accumulated Depreciation was reclassified to a Noncurrent Regulatory Liability ($15.9 million and $14.0 million at December 31, 2005 and 2004, respectively).

During 2004, we 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 and Net Income by $5.4 million and $3.4 million, respectively, an understatement of 2003 Operating Income and Net Income by $3.1 million and $1.9 million, respectively, and a cumulative understatement of Operating Income and Net Income for periods prior to 2003 by $2.3 million and $1.4 million, respectively. Management believes that the effect of the adjustment was 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 percent for 2005, 2004 and 2003. Equity AFUDC of $2.9 million, $0.8 million and $8.6 million for 2005, 2004 and 2003, respectively, is reflected in Other Income — net.

Advances to Affiliates

As a participant in Williams’ cash management program, we make advances to and receive advances from Williams. 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.

Reserve for Obsolescence

We perform an annual review of materials and supplies inventories, including an analysis of parts that may no longer be useful due to planned replacements of compressor engines and other components on our system. Based on this assessment, we record a reserve for the value of the inventory which can no longer be used for maintenance and repairs on our pipeline.

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

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NOTES TO FINANCIAL STATEMENTS

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. The exchange gas offset represents the gas balance in our system representing the difference between the exchange gas due to us from customers and the exchange gas that we owe to customers. These imbalances are valued at the average of the spot market rates at the Canadian border and the Rocky Mountain market as published in “Inside FERC’s Gas Market Report.” Settlement of imbalances requires agreement between the pipelines and shippers as to allocations of volumes to specific transportation contracts and timing of delivery of gas based on operational conditions.

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 by us may be subject to possible refunds upon final orders in pending rate proceedings with the FERC. We record estimates of rate refund liabilities considering our and other third party regulatory proceedings, advice of counsel and estimated total exposure, as discounted and risk weighted, as well as collection and other risks. At December 31, 2005, we have no pending rate proceedings or rate refund liabilities.

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

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NOTES TO FINANCIAL STATEMENTS

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 through rates. We believe that compliance with applicable environmental requirements is not likely to have a material effect upon our financial position or results of operations.

Interest Payments

Cash payments for interest were $36.9 million, $38.7 million and $29.1 million, net of $1.5 million, $0.5 million and $3.6 million of interest capitalized (allowance for borrowed funds used during construction) in 2005, 2004 and 2003, 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” (SFAS No. 123). Beginning January 1, 2006, we will adopt revised SFAS No. 123, “Share-Based Payments” (SFAS No. 123(R)). See further discussion in the “Recent Accounting Standards” section within this note.


	Years Ended December 31,
	2005			2004			2003
	(Thousands of Dollars)
Net income, as reported	$	71,755		$	76,655		$	73,294
Add: Stock-based employee compensation included in the Statement of Income, net of related tax effects		65			35			—
Deduct: Total stock-based employee compensation expense determined under fair value based method for all awards, net of related tax effects		(374	)		(787	)		(626	)

Pro forma net income	$	71,446		$	75,903		$	72,668

Pro forma amounts for 2005 include compensation expense from awards of Williams’ stock made in 2002 through 2005. (See Note 4.) Pro forma amounts for 2004 include compensation expense from Williams awards made in 2001 through 2004. Also included in 2004 pro forma expense is $169,683 of incremental expense associated with a stock option exchange program. Pro forma amounts for 2003 include compensation expense from Williams awards made in 2001 through 2003. Also included in the 2003 pro forma expense is $84,756 of incremental expense associated with a stock option exchange program.

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.

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Recent Accounting Standards

Stock-Based Awards

In December 2004, the FASB issued SFAS No. 123(R). The Statement requires that compensation costs for all share-based awards, including grants of employee stock options, to employees be recognized in the Statement of Income based on their fair values. Pro forma disclosure is no longer an alternative. The Statement, as issued by the FASB, was to be effective as of the beginning of the first interim or annual reporting period that begins after June 15, 2005. However, in April 2005, the Securities and Exchange Commission (SEC) adopted a new rule that delayed the effective date for SFAS No. 123(R) to the beginning of the next fiscal year that begins after June 15, 2005. We intend to adopt the revised Statement on January 1, 2006.

The Statement allows either a modified prospective application or a modified retrospective application for adoption. Williams will use a modified prospective application for adoption and will apply the Statement to new awards and to awards modified, repurchased, or cancelled after January 1, 2006. Also, for unvested stock awards outstanding as of January 1, 2006, 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 January 1, 2006. Compensation costs for these awards will be based on fair value at the original grant date as estimated for the pro forma disclosures under SFAS No. 123, as amended by SFAS No. 148, “Accounting for Stock-Based Compensation — Transition and Disclosure — an amendment of SFAS No. 123.” Additionally, a modified retrospective application requires restating periods prior to January 1, 2006, on a basis consistent with the pro forma disclosures required by SFAS No. 123, as amended by SFAS No. 148. Since we will use a modified prospective application, we will not restate prior periods.

Williams currently accounts for share-based awards to employees by applying the intrinsic value method in accordance with APB No. 25 and, as such, generally recognizes no compensation cost for employee stock options. We currently recognize compensation cost for deferred share awards. Adoption of the Statement’s fair value method will have an impact on our results of operations. At January 1, 2006, we have approximately $1.3 million of compensation cost from outstanding unvested stock awards to be recognized as the requisite service is rendered, primarily in 2006 or 2007. Stock-based awards will be granted during 2006. Our compensation cost as reported in pro forma disclosures required by SFAS No. 123, as amended by SFAS No. 148, may not be representative of compensation cost to be incurred in 2006 and beyond as the number and types of awards may differ and estimates of fair value may differ due to changes in the market price of Williams’ common stock and to changing capital market and employee exercise behavior assumptions.

Certain of our Williams’ stock awards currently result in compensation cost under APB No. 25 and related guidance. These stock awards are subject to vesting provisions and our policy is to adjust compensation cost for forfeitures when they occur. Upon the January 1, 2006, adoption of SFAS No. 123(R), we will adjust net income as a cumulative effect of a change in accounting principle 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. The adjustment will not be material.

We currently present pro forma disclosure of net income as if compensation costs from all Williams’ stock awards were recognized based on the fair value recognition provisions of SFAS No. 123. The Statement requires use of valuation techniques, including option pricing models, to estimate the fair value of employee stock awards. For pro forma disclosures, Williams currently uses a Black Scholes option pricing model in estimating the fair value of employee stock options and Williams intends to continue using a Black-Scholes option pricing model when we adopt SFAS No. 123(R).

FERC Order, “Accounting for Pipeline Assessment Cost”

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NOTES TO FINANCIAL STATEMENTS

approximately $7 million to $10 million of costs expected to be incurred in 2006 that would have been capitalized prior to the Order becoming effective.

Other Recent Accounting Standards

In November 2004, the FASB issued SFAS No. 151, “Inventory Costs, an amendment of ARB No. 43, Chapter 4,” which will be applied prospectively for inventory costs incurred in fiscal years beginning after June 15, 2005. The Statement amends Accounting Research Bulletin (ARB) No. 43, Chapter 4, “Inventory Pricing,” to clarify that abnormal amounts of certain costs should be recognized as current period charges and that the allocation of overhead costs should be based on the normal capacity of the production facility. The impact of this Statement on our Financial Statements will not be material.

In December 2004, the FASB issued SFAS No. 153, “Exchanges of Nonmonetary Assets, an amendment of APB Opinion No. 29,” which is effective for nonmonetary asset exchanges occurring in fiscal periods beginning after June 15, 2005. The Statement amends APB Opinion No. 29, “Accounting for Nonmonetary Transactions.” The guidance in APB Opinion No. 29 is based on the principle that exchanges of nonmonetary assets should be measured based on the fair value of the assets exchanged but includes certain exceptions to that principle. SFAS No. 153 amends APB Opinion No. 29 to eliminate the exception for nonmonetary exchanges of similar productive assets and replaces it with a general exception for exchanges of nonmonetary assets that do not have commercial substance. A nonmonetary exchange has commercial substance if the future cash flows of the entity are expected to change significantly as a result of the exchange. We will apply SFAS No. 153 as required.

In May 2005, the FASB issued SFAS No. 154, “Accounting Changes and Error Corrections — a replacement of APB Opinion No. 20 and FASB Statement No. 3,” which was effective prospectively for reporting a change in accounting principle for fiscal years beginning after December 15, 2005. The Statement changes the reporting of a change in accounting principle to require retrospective application to prior periods unless explicit transition provisions provide otherwise. The Statement is effective for any existing accounting pronouncements, including those in the transition phase when the Statement becomes effective. We will apply SFAS No. 154 as required.

Reclassifications

Operating Income was increased by $0.3 million in 2004 and decreased by $4.1 million in 2003 and Other Income was decreased by $0.3 million in 2004 and increased by $4.1 million in 2003 to reclassify amounts related to the allowance for equity funds used during construction. General and Administrative Expense was decreased and Operation and Maintenance Expense was increased by $8.4 million and $4.1 million in 2004 and 2003, respectively, to allocate benefits that had previously been classified as General and Administrative Expense to Operation and Maintenance Expense to appropriately reflect these benefits as cost of operations. Certain other reclassifications have been made in the 2004 and 2003 financial statements to conform to the 2005 presentation.

2. CONTINGENT LIABILITIES AND COMMITMENTS

Legal Proceedings

In 1998, the United States Department of Justice (DOJ) informed Williams that Jack Grynberg, an individual, had filed claims in the United States District Court for the District of Colorado under the False Claims Act against Williams and certain of its wholly-owned subsidiaries including us. Mr. Grynberg 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

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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 occurred on March 17 and 18, 2005. In May 2005, the court-appointed special master entered a report which recommended that many of the cases be dismissed, including the case pending against certain of the Williams defendants, including us. The District Court is in the process of considering whether to affirm or reject the special master’s recommendations and heard oral arguments on December 9, 2005.

Environmental Matters

We are subject to the National Environmental Policy Act and other federal and state legislation regulating the environmental aspects of our business. Except as discussed below, management believes that we are in substantial compliance with existing environmental requirements. We believe that, with respect to any additional 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 through rates. 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.

Beginning in the mid 1980’s, we evaluated many of our facilities for the presence of toxic and hazardous substances to determine to what extent, if any, remediation might be necessary. Consistent with other natural gas transmission companies, we identified polychlorinated biphenyl (PCB) contamination in air compressor systems, soils and related properties at certain compressor station sites. Similarly, we identified hydrocarbon impacts at these facilities due to the former use of earthen pits and mercury contamination at certain gas metering sites. The PCBs were remediated pursuant to a Consent Decree with the U.S. Environmental Protection Agency in the late 1980’s and we conducted a voluntary clean-up of the hydrocarbon and mercury impacts in the early 1990’s. In 2005, the Washington Department of Ecology required us to reevaluate our previous mercury clean-ups in Washington. Currently, we are assessing the actions needed to bring the sites up to Washington’s current environmental standards. At December 31, 2005, we have accrued liabilities totaling approximately $4 million for these costs which are expected to be incurred over the period from 2006 through 2009. We consider these costs associated with compliance with these environmental laws and regulations to be prudent costs incurred in the ordinary course of business and, therefore, recoverable through our rates.

Safety Matters

Pipeline Integrity Regulations We have developed an Integrity Management Plan that meets the United States Department of Transportation Pipeline and Hazardous Materials Safety Administration final rule pursuant to the requirements of the Pipeline Safety Improvement Act of 2002. In meeting the Integrity Regulations, we have identified the high consequence areas, including a baseline assessment and periodic reassessments to be completed within specified timeframes. Currently, we estimate that the cost to perform required assessments and remediation will be between $95 million and $120 million over the remaining assessment period of 2006 through 2012, a portion of which will be incurred and expensed beginning January 1, 2006 (see Note 1). 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.

Aging Pipeline Infrastructure While well maintained pipeline facilities can operate safely for decades, there are challenges associated with operating and maintaining aging pipeline infrastructure. Increased expenditures may be required to replace obsolete equipment and deteriorating pipeline infrastructure, such as pipeline coating and cathodic protection facilities.

Other Matters

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

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NOTES TO FINANCIAL STATEMENTS

Summary

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

Other Commitments

We have commitments for construction and acquisition of property, plant and equipment of approximately $24.6 million at December 31, 2005.

Termination of the Grays Harbor Transportation Agreement

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.

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NOTES TO FINANCIAL STATEMENTS

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. A hearing on the proposed OPS civil penalty occurred on December 15, 2004, in Denver, Colorado and a decision is pending.

3. DEBT, FINANCING ARRANGEMENTS AND LEASES

Debt Covenants

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

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NOTES TO FINANCIAL STATEMENTS

Long-Term Debt

Long-term debt consists of the following:


	December 31,
	2005		2004
	(Thousands of Dollars)
6.625%, payable 2007	$	250,000	$	250,000
7.125%, payable 2025		84,774		84,763
8.125%, payable 2010		175,000		175,000
9%, payable 2004 through 2007		10,306		17,799

Total long-term debt		520,080		527,562

Less current maturities		7,500		7,500


Total long-term debt, less current maturities	$	512,580	$	520,062

As of December 31, 2005, cumulative sinking fund requirements and other maturities of long-term debt (at face value) for each of the next five years are as follows:


	(Thousands of
	Dollars)
2006	$	7,500
2007		252,867
2008		—
2009		—
2010		175,000
Thereafter		85,000

Total	$	520,367

Line-of-Credit Arrangements

	•		added Williams Partners L.P. as a borrower for up to $75 million;

	•		provided Williams’ guarantee for the obligations of Williams Partners L.P. under this agreement;

	•		released certain Williams’ midstream assets held as collateral and replaced them with the common stock of Transco; and

	•		reduced commitment fees and margins.

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NOTES TO FINANCIAL STATEMENTS

equal rate to LIBOR plus an applicable margin. We are required to pay a commitment fee (currently 0.325 percent annually) based on the unused portion of the facility. The applicable margin and commitment fee are based on the relevant borrower’s senior unsecured long-term debt ratings.

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:


	(Thousands
	of Dollars)
2006	$	6,398
2007		6,377
2008		6,376
2009		6,312

	$	25,463

Less: noncancelable subleases		11,164


Total	$	14,299

Operating lease rental expense, net of sublease revenues, amounted to $5.3 million, $6.2 million, and $5.2 million for 2005, 2004 and 2003, 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 provides postretirement medical benefits to certain retired employees. Contributions for pension and postretirement medical benefits related to our participation in these plans were $6.0 million, $5.9 million and $8.9 million in 2005, 2004 and 2003, respectively. These amounts are currently recoverable in our rates. The accompanying Balance Sheet reflects regulatory assets related to other postemployment benefits of $1.4 million and $1.5 million at December 31, 2005 and 2004, respectively.

The accompanying Balance Sheet reflects regulatory liabilities related to postretirement benefits of $10.8 million and $8.4 million at December 31, 2005 and 2004, respectively. The FERC has approved the accounting for the difference between postretirement medical expense under SFAS No. 106, “Employers’ Accounting for Postretirement Benefits Other than Pensions,” and benefit amounts contributed, as a regulatory asset or liability to be reflected in future rates.

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NOTES TO FINANCIAL STATEMENTS

Defined Contribution Plan

Our employees are also covered by Williams’ defined contribution plan. Our costs related to this plan totaled $1.5 million, $1.3 million and $1.5 million in 2005, 2004 and 2003, respectively.

Employee Stock-Based Awards

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

The following summary provides information about our employees’ stock option activity related to Williams’ common stock for 2005, 2004 and 2003 (options in thousands):


	2005					2004					2003
				Weighted					Weighted					Weighted
				Average					Average					Average
				Exercise					Exercise					Exercise
	Options			Price		Options			Price		Options			Price
Outstanding — beginning of year		1,203		$	15.99		1,235		$	16.02		1,511		$	19.40
Granted		133		$	19.29		141		$	9.93		165	*	$	10.00
Exercised		(200	)	$	11.80		(183	)	$	7.18		(7	)	$	8.06
Forfeited/expired		(41	)	$	33.50		(45	)	$	24.02		(522)	**	$	25.45
Employee transfers, net		60			—		55			—		88			—

Outstanding — end of year		1,155		$	16.18		1,203		$	15.99		1,235		$	16.02

Exercisable at year end		906		$	16.42		1,033		$	16.97		734		$	23.35


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

**		Includes 413 options that were cancelled on June 26, 2003, under the Williams stock option exchange program, described above.

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NOTES TO FINANCIAL STATEMENTS

The following summary provides information about Williams’ common stock options that are outstanding and exercisable by our employees at December 31, 2005 (options in thousands):


	Stock Options Outstanding						Stock Options Exercisable
					Weighted
					Average
			Weighted		Remaining				Weighted
Range of Exercise			Average		Contractual				Average
Prices	Options		Exercise Price		Life (years)		Options		Exercise Price
$2.27 to $10.00		600	$	6.71		6.1		493	$	6.01
$14.80 to $15.89		102	$	15.60		1.3		102	$	15.60
$19.29 to $31.56		254	$	21.82		5.7		112	$	25.04
$34.54 to $42.29		199	$	37.74		1.6		199	$	37.74

		1,155	$	16.18		4.8		906	$	16.42

The estimated fair value at the date of grant of options for Williams’ common stock granted in 2005, 2004 and 2003, using the Black-Scholes option-pricing model is as follows:


	2005			2004			2003(a)
Weighted-average grant date fair value of options for Williams common stock granted during the year	$	6.70		$	4.54		$	2.95

Assumptions
Dividend yield		1.6	%		0.4	%		1.0	%
Volatility		33.3	%		50	%		50	%
Risk-free interest rate		4.1	%		3.3	%		3.1	%
Expected life (years)		6.5			5.0			5.0

(a)

In 2003, stock options granted to our employees were solely related to the employee stock option exchange described above. The weighted-average fair value of these options is $1.58, which is the difference in the fair value of the new options granted and the fair value of the exchanged options. The assumptions used in the fair value calculation of the new options granted were: 1) dividend yield of .40 percent; 2) volatility of 50 percent; 3) weighted average expected remaining life of 3.4 years; and 4) weighted average risk free interest rate of 1.99 percent.

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

-39-

NORTHWEST PIPELINE CORPORATION

NOTES TO FINANCIAL STATEMENTS

5. INCOME TAXES

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


	December 31,
	2005		2004
	(Thousands of Dollars)
Property, plant and equipment	$	220,057	$	238,430
Regulatory assets		12,303		12,853
Loss on reacquired debt		4,521		5,127
Other — net		8,024		1,053


Deferred tax liabilities		244,905		257,463


Accrued liabilities		12,270		4,173
Minimum tax credits		—		2,084


Deferred tax assets		12,270		6,257


Net deferred tax liabilities	$	232,635	$	251,206


Reflected as:
Deferred income taxes — current asset	$	3,913	$	4,173
Deferred income taxes — noncurrent liability		236,548		255,379

	$	232,635	$	251,206

The provision for income taxes includes:


	Year Ended December 31,
	2005			2004		2003
	(Thousands of Dollars)
Current:
Federal	$	52,292		$	11,406	$	(6,058)
State		6,473			1,849		(1,159	)

		58,765			13,255		(7,217	)


Deferred:
Federal		(16,373	)		30,128		45,636
State		(2,198	)		3,396		6,099

		(18,571	)		33,524		51,735


Total provision	$	40,194		$	46,779	$	44,518

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NORTHWEST PIPELINE CORPORATION

NOTES TO FINANCIAL STATEMENTS

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


	Year Ended December 31,
	2005			2004			2003
	(Thousands of Dollars)
Provision at statutory Federal income tax rate of 35 percent
Increase (decrease) in tax provision resulting from -	$	39,182		$	43,202		$	41,235
State income taxes net of Federal tax benefit		2,779			3,409			3,211
Book/tax basis reconciliation adjustment		(1,835	)		—			—
Other — net		68			168			72


Provision for income taxes	$	40,194		$	46,779		$	44,518


Effective tax rate		35.90	%		37.90	%		37.79	%

We provide for income taxes using the asset and liability method as required by SFAS 109, “Accounting for Income Taxes.” During 2005, as a result of additional analysis of our tax basis and book basis assets and liabilities, we recorded a $1.8 million tax benefit adjustment to reduce the overall deferred income tax liabilities on the Balance Sheet. The 2005 effective income tax rate has been reduced as a result of this adjustment and favorable settlements on federal and state income tax matters.

Net cash payments made to Williams for income taxes were $63.7 million, $11.3 million and $3.5 million in 2005, 2004 and 2003, 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 $520 million and $542 million, respectively, at December 31, 2005, and $528 million and $562 million, respectively, at December 31, 2004.

-41-

NORTHWEST PIPELINE CORPORATION

NOTES TO FINANCIAL STATEMENTS

7. TRANSACTIONS WITH MAJOR CUSTOMERS AND AFFILIATES

Concentration of Off-Balance-Sheet and Other Credit Risk

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


	Year Ended December 31,
	2005			2004			2003
	(Thousands of Dollars)
Puget Sound Energy, Inc.	$	56,480		$	46,997		$	40,732
Northwest Natural Gas Co.		35,420			38,067			38,437
Duke Energy Trading and Marketing LLC		(a	)		(a	)		33,739


(a)		Revenues were under 10 percent in this year.

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

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. Advances are stated at the historical carrying amounts. As of December 31, 2005 and 2004, we had advances to Williams of $50.0 million for each period. The advances are represented by demand notes. The interest rate on intercompany demand notes is based upon the weighted average cost of Williams’ debt outstanding at the end of each quarter. 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 $3.8 million, $4.5 million, and $2.7 million during 2005, 2004 and 2003, respectively. Such interest income is included in Other Income — net on the accompanying Statement of Income.

Williams’ corporate overhead expenses allocated to us were $19.0 million, $20.3 million and $14.2 million for 2005, 2004 and 2003, 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, human resources and other administrative services to us on a direct charge basis, which totaled $9.8 million, $7.9 million and $6.8 million for 2005, 2004 and 2003, 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 $2.4 million, $2.0 million and $1.6 million for 2005, 2004 and 2003, respectively.

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

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NORTHWEST PIPELINE CORPORATION

NOTES TO FINANCIAL STATEMENTS

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 2003, we wrote off 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 in 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.

9. QUARTERLY INFORMATION (UNAUDITED)

The following is a summary of unaudited quarterly financial data for 2005 and 2004:


	Quarter of 2005
	First		Second		Third		Fourth
	(Thousands of Dollars)
Operating revenues	$	80,283	$	78,907	$	79,639	$	82,628
Operating income		37,664		34,498		36,074		33,140
Net income		18,317		17,189		18,252		17,997

Fourth quarter 2005 net income includes a $1.8 million tax benefit adjustment as a result of additional analysis of our tax basis and book basis assets and liabilities. (See Note 5.)


	Quarter of 2004
	First		Second		Third		Fourth
	(Thousands of Dollars)
Operating revenues	$	85,476	$	83,504	$	83,255	$	86,297
Operating income		42,247		30,131		45,135		42,280
Net income		20,957		13,073		22,016		20,609

Second quarter 2004 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. (See Note 8.) Third quarter 2004 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.)

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

None.

Item 9A. CONTROLS AND PROCEDURES

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

There has been no material change that occurred during the fourth fiscal quarter in our Internal Controls over financial reporting.

Item 9B.

None.

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PART III

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

Item 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

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


	2005		2004
	(Thousands of Dollars)
Audit Fees	$	791	$	709
Audit-Related Fees		—		—
Tax Fees		—		—
All Other Fees		—		—

	$	791	$	709

Fees for audit services include fees associated with the annual audit, the reviews for our quarterly reports on Form 10-Q, the reviews for other SEC filings and accounting consultations.

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 10, 2006.

-45-

PART IV

Item 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES

(a) 1. Financial Statements

Index


	Page
	Reference
	to 2005
	Form 10-K
Report of Independent Registered Public Accounting Firm		19
Statement of Income for the Years Ended December 31, 2005, 2004 and 2003		20
Balance Sheet at December 31, 2005 and 2004		21
Statement of Common Stockholder’s Equity for the Years Ended December 31, 2005, 2004 and 2003		23
Statement of Comprehensive Income for the Years Ended December 31, 2005, 2004 and 2003		24
Statement of Cash Flows for the Years Ended December 31, 2005, 2004 and 2003		25
Notes to Financial Statements		26

(a) 2. Financial Statement Schedules

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


			Charged to
	Beginning		Costs and						Ending
Description	Balance		Expenses			Deductions			Balances
Year ended December 31, 2005:
Reserve for doubtful receivables	$	320	$	44		$	(273	)	$	91
Reserve for obsolescence of materials and supplies		439		0			(176	)		263
Year ended December 31, 2004:
Reserve for doubtful receivables		320		0			0			320
Reserve for obsolescence of materials and supplies		284		825			(670	)		439
Year ended December 31, 2003:
Reserve for doubtful receivables		486		(12	)		(154	)		320
Reserve for obsolescence of materials and supplies		500		280			(496	)		284

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

-46-

(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

-47-


				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).

		*(5)		Amended and Restated Credit Agreement dated as of May 20, 2005 among The Williams Companies, Inc., Williams Partner L.P., Northwest Pipeline Corporation, Transcontinental Gas Pipe Line Corporation, and the Banks, Citibank, N.A. and Bank of America, N.A. (each, an “Issuing Bank”), and Citicorp USA, INC. as administrative agent. (filed as Exhibit 1.1 to Form 8-K filed May 26, 2005).

(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.


*Exhibits so marked have heretofore been filed with the Securities and Exchange Commission as part of the filing indicated and are incorporated herein by reference.

-48-

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.


	NORTHWEST PIPELINE CORPORATION (Registrant)
By	/s/ R. Rand Clark
	R. Rand Clark
	Controller

Date: March 28, 2006

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.


Signature		Title
/s/ Steven J. Malcolm* Steven J. Malcolm		Chairman of the Board

/s/ Phillip D. Wright* Phillip D. Wright		Senior Vice President and Director (Principal Executive Officer)

/s/ Richard D. Rodekohr* Richard D. Rodekohr		Vice President and Treasurer (Principal Financial Officer)

/s/ R. Rand Clark R. Rand Clark		Controller (Principal Accounting Officer)

/s/ Allison G. Bridges* Allison G. Bridges		Director and Vice President

* By /s/ R. Rand Clark R. Rand Clark
Attorney-in-fact

Date: March 28, 2006

-49-


Heading	Page
PART I
Item 1. BUSINESS		1
Item 1A. RISK FACTORS		4
Item 2. PROPERTIES		11
Item 3. LEGAL PROCEEDINGS		11
Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS (Omitted)		11
PART II
Item 5. MARKET FOR REGISTRANT’S COMMON EQUITY AND RELATED STOCK- HOLDER MATTERS		12
Item 6. SELECTED FINANCIAL DATA (Omitted)		12
Item 7. MANAGEMENT’S NARRATIVE ANALYSIS OF THE RESULTS OF OPERATIONS		12
Item 7A. QUALITATIVE AND QUANTITATIVE DISCLOSURES ABOUT MARKET RISK		17
Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA		18
Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE		44
Item 9A. CONTROLS AND PROCEDURES		44
Item 9B. OTHER INFORMATION		44
PART III
Item 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT (Omitted)		45
Item 11. EXECUTIVE COMPENSATION (Omitted)		45
Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT (Omitted)		45
Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS (Omitted)		45
Item 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES		45
PART IV
Item 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES		46
Consent of Independent Registered Public Accounting Firm
Power of Attorney
Section 302 Certification of Principal Executive Officer
Section 302 Certification of Principal Financial Officer
Section 906 Certification of Principal Executive Officer & Principal Financial Officer


Exhibit
23		Consent of Independent Registered Public Accounting Firm

24		Power of Attorney with Certified Resolution

31(a)		Section 302 Certification of Principal Executive Officer

31(b)		Section 302 Certification of Principal Financial Officer

32		Section 906 Certification of Principal Executive Officer and Principal Financial Officer


/s/ Phillip D. Wright		/s/ Richard D. Rodekohr

Phillip D. Wright Senior Vice President and Director (Principal Executive Officer)		Richard D. Rodekohr Vice President and Treasurer (Principal Financial Officer)


		/s/ R. Rand Clark

		R. Rand Clark Controller (Principal Accounting Officer)


/s/ Steven J. Malcolm		/s/ Allison G. Bridges

Steven J. Malcolm Director		Allison G. Bridges Director


		NORTHWEST PIPELINE CORPORATION

		By		/s/ Richard D. Rodekohr

				Richard D. Rodekohr
				Vice President and
				Treasurer

	a)		Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

	b)		Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

	c)		Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the period covered by the report that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

	a)		All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

	b)		Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.


By:		/s/ Phillip D. Wright

		Phillip D. Wright
		Senior Vice President
		(Principal Executive Officer)