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NORTHWEST PIPELINE CORPORATION

(Registrant)

/s/ R. Rand Clark

R. Rand Clark

Controller

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, 2006


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

295 Chipeta Way, Salt Lake City, Utah (Address of principal executive offices)		84108 (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 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 Act). Yes o No þ

State the aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant.

No voting or non-voting common equity 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 February 28, 2007
Common stock, $1 par value		1,000 shares

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 2006, Williams is a reporting entity under the Sarbanes-Oxley Act of 2002. Northwest is not an accelerated filer and therefore not required in 2006 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, 2006, our system, having long-term firm transportation agreements with peaking capacity of approximately 3.4 MMDth* of gas per day, was comprised of approximately 3,900 miles of mainline and lateral transmission pipelines and 41 transmission compressor stations. Our compression facilities have a combined sea level-rated capacity of approximately 473,000 horsepower.

In 2006, we served a total of 141 transportation and storage customers. Our transportation customers include distribution companies, municipalities, interstate and intrastate pipelines, gas marketers and direct industrial users. In 2006, our two largest customers were Puget Sound Energy, Inc. and Northwest Natural Gas Co., which accounted for approximately 19.9 percent and 10.9 percent, respectively, of our total operating revenues. No other customer accounted for more than 10 percent of our total operating revenues in 2006. 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 7.0 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 been deferred pending the resolution of this matter.

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.

On October 4, 2006, the FERC issued its Order on Petition for Declaratory Order, providing clarification on issues relating to Duke’s obligation to reimburse us for future tax expenses in connection with the buying out of Duke’s facilities reimbursement agreement and terminating the related transportation agreement associated with service on the Grays Harbor lateral. The FERC did not directly address the tariff interpretation issues that we had presented.

On November 3, 2006, we filed a request for rehearing of the FERC’s Order on Petition for Declaratory Order. Our request for rehearing seeks a FERC determination of our tariff language concerning mid-term contractual buyouts. It also seeks to clarify some of the underlying principles of a possible buyout calculation as suggested by the FERC in its Order on Petition for Declaratory Order.

Based upon the above, we do not anticipate any adverse impact to our results of operations or financial position from this matter.

CAPITAL PROJECTS

Capacity Replacement Project

In 2003, we experienced two breaks in a segment of one of our natural gas pipelines in western Washington. In response to these breaks, we received Corrective Action Orders (CAO) from the Office of Pipeline Safety (OPS). We elected to idle the pipeline segment until its integrity could be assured, and began the process of replacing the capacity served by the pipeline segment.

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In September 2005, we received a FERC certificate authorizing us to construct and operate the “Capacity Replacement Project.” This project entailed 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. As of December 2006, all of the facilities and abandonment of the 26-inch pipeline were completed. The final cost of the project, including some minor post-construction work, is estimated to be $325 million.

The rate case we filed on June 30, 2006 seeks to recover, among other things, the capitalized costs relating to the Capacity Replacement Project.

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 from the Parachute area to the Greasewood area in northwest Colorado. In August 2006, the FERC granted us the requested certificate and we commenced construction of the facilities. The planned lateral will provide new capacity of 450 MDth/day through a 30-inch diameter line and is estimated to cost $86 million. We anticipate beginning service on the expansion in March 2007.

Greasewood Lateral Project

In March 2006, we executed an agreement with a shipper for 200 MDth/day of capacity on a proposed new lateral to be constructed from the vicinity of Greasewood, Colorado, to our mainline system near Sands Springs, Colorado. On February 20, 2007, following a meeting with representatives of the shipper, we decided to postpone applying with the FERC for a certificate to construct the proposed Greasewood Lateral Project. We will be continuing to work with potential shippers to determine whether to proceed with the project at a future date.

OPERATING STATISTICS

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


	Year Ended December 31,
	2006		2005		2004
	(In trillion British Thermal Units)
Total Throughput		676		673		650

Average Daily Transportation Volumes		1.9		1.8		1.8
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)		.9		.8		.6


(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.

REGULATORY MATTERS

Our transportation and storage rates are established through the FERC ratemaking process. Key factors affecting our rates are (1) costs of providing service, including depreciation expense, (2) the inclusion of an allowed rate of return on capital assets, including the equity component of the capital structure and related income taxes and (3) contract demand and volume throughput assumptions. As a

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result of these proceedings, certain revenues collected previously may be subject to refund. We record estimates of rate refund liabilities considering our estimated outcome of the regulatory proceedings and advice of counsel, which are discounted and risk weighted.

General Rate Case (Docket No. RP06-416)

On June 30, 2006, we filed a general rate case under Section 4 of the Natural Gas Act. Significant costs that contributed to the need to file this rate case include: construction of the Capacity Replacement Project, an increase in reliability and integrity expenditures, and an increase in other operating costs. On July 31, 2006, the FERC issued an Order accepting our filing and suspended the effective date of the new rates for five months, to become effective January 1, 2007, subject to refund. On January 31, 2007, we filed a stipulation and settlement agreement that resolves all outstanding issues in our pending rate case. That settlement is either supported or not opposed by both the intervening parties and FERC staff. It is expected to be uncontested. The settlement specified an annual cost of service of $404 million and establishes that general system firm transportation rates on our system will increase from $0.30760 to $0.40984 per Dth, effective January 1, 2007. The settlement is subject to FERC approval. We anticipate the approval process will be completed by mid-2007.

TRANSACTIONS WITH AFFILIATES

We engage in transactions with Williams and other Williams subsidiaries. See “Item 8. Financial Statements and Supplementary Data — Notes to Financial Statements — 1. Summary of Significant Accounting Policies and 8. Transactions with Major Customers and Affiliates.”

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, and the Pipeline Safety Improvement Act of 2002 which regulate safety requirements in the design, construction, operation and maintenance of interstate gas transmission facilities. The FERC’s Standards of Conduct govern the relationship between natural gas transmission providers and their “marketing affiliates” as defined by the rule. The standards of conduct are intended to prevent natural gas transmission providers from preferentially benefiting their marketing affiliates by requiring the employees of a transmission provider to function independently from employees of marketing affiliates and by restricting the information that transmission providers may provide to marketing affiliates.

Environmental Matters

We are subject to the National Environmental Policy Act and federal, state and local laws and regulations relating to environmental quality control. Management believes that capital expenditures and operation and maintenance expenses required to meet applicable environmental standards and regulations are generally recoverable in rates. For these reasons, management believes that compliance with applicable environmental requirements is not likely to have a material effect upon our competitive position or earnings. See “Item 8. Financial Statements and Supplementary Data — Notes to Financial Statements — 3. Contingent Liabilities and Commitments — Environmental Matters.”

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

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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 include “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. These statements 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;

	•		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. Many of the factors that will determine these results are beyond our ability to control or project. Specific factors which could cause actual results to differ from those in the forward-looking statements include:

	•		availability of supplies (including the uncertainties inherent in assessing and estimating future natural gas reserves), market demand, volatility of prices, and increased costs of capital;

	•		inflation, interest rates, and general economic conditions;

	•		the strength and financial resources of our competitors;

	•		development of alternative energy sources;

	•		the impact of operational and development hazards;

	•		costs of, changes in, or the results of laws, government regulations, environmental liabilities, litigation, and rate proceedings;

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	•		increasing maintenance and construction costs;

	•		changes in the current geopolitical situation;

	•		risks related to strategy and financing, including restrictions stemming from our debt agreements and our lack of investment grade credit ratings; and

	•		risk associated with future weather conditions and acts of terrorism.

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 obligations to and do not intend to update the above list to announce publicly the result of any revisions to any of the forward-looking statements to reflect future events or developments.

In addition to causing our actual results to differ, the factors listed above and referred to below may cause our intentions to change from those statements of intention set forth in this report. Such changes in our intentions may also cause our results to differ. We may change our intentions, at any time and without notice, based upon changes in such factors, our assumptions, or otherwise.

Because forward-looking statements involve risks and uncertainties, we caution that there are important factors, in addition to those listed above, that may cause actual results to differ materially from those contained in the forward-looking statements. These factors are described in the following section.

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 is 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 negative effect to our results of operations.

Decreases in natural gas production. The development of the additional natural gas reserves that are essential for our gas transmission business to thrive 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 and production of additional reserves, as well as gathering, storage, pipeline transmission and import and export of natural gas supplies, adversely impacting our ability to fill the capacities of our transmission and storage 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 affected by weather, future industrial and economic conditions, fuel conservation measures, alternative fuel requirements, governmental regulation, or technological advances in fuel economy and energy generation devices, all of which are matters beyond our control.

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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 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, which, if the proposed projects succeed, could increase the competitive pressure upon us. There can be no assurance that we will be able to compete successfully against current and future competitors and any failure to do so could have a material adverse effect on our business and results of operations.

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

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;

	•		aging pipeline infrastructure; and

	•		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. These risks could result in loss of human life, personal injuries, 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, and only at levels we believe to be appropriate. The location of certain segments of our pipeline in or near populated areas, including residential areas, commercial business centers and industrial sites, could increase the level of damages resulting from these risks. 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 condition 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 obligations and retain customers, with a resulting impact on our results of operations.

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,

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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 requires significant expenditures including those for clean-up costs and damages arising out of contaminated properties. In addition, 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 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 supporting indebtedness, 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 cross-default or cross-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 the capital markets. Such disruptions could include:

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	•		further economic downturns;

	•		deteriorating capital market conditions generally;

	•		declining market prices for electricity and natural gas;

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

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 from all of the major credit rating agencies. 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.

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 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 consistent with existing debt covenants. 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.

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 to what extent our business would be impacted by deteriorating conditions in the energy sector, including declines in our customers’ creditworthiness.

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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.

Our interstate gas transmission and storage operations are subject to the FERC’s rules and regulations in accordance with the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978. The FERC’s regulatory authority extends to:

	•		transportation and sale for resale of natural gas in interstate commerce;

	•		rates and charges;

	•		construction;

	•		acquisition, extension or abandonment of services or facilities;

	•		accounts and records;

	•		depreciation and amortization policies; and

	•		operating terms and conditions of service.

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 Standards of Conduct govern the relationship between natural gas transmission providers and their “marketing affiliates” as defined by the rule. The standards of conduct are intended to prevent natural gas transmission providers from preferentially benefiting their marketing affiliates by requiring the employees of a transmission provider to function independently from employees of marketing affiliates and by restricting the information that transmission providers may provide to marketing 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 filed a rate case with the FERC on June 30, 2006 to request changes to the rates we charge. The new rates became effective January 1, 2007. On January 31, 2007, we filed a stipulation and settlement agreement that resolves all outstanding issues in our pending rate case. The settlement is subject to FERC approval. The outcome of this rate case is uncertain. There is a risk that rates set by the FERC will be lower than is necessary to provide us with an adequate return on the capital we have invested in our assets or might not be adequate to recover increases in operating costs. There is also the risk that higher rates will cause our customers to look for 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 may 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 or our affiliates are named as defendants. Both the shippers on our pipeline and the regulators have rights to challenge the rates we charge under certain circumstances. Any successful challenge could materially affect our results of operations.

Certain inquiries, investigations and court proceedings are ongoing. We might see adverse effects continue as a result of the uncertainty of these ongoing inquiries and proceedings, or additional

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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 environmental matters, disputes over gas measurement, royalty payments, suits, regulatory appeals and similar matters might result in adverse decisions against 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 disclosures in the future, which might change the way analysts measure our business or financial performance.

Accounting irregularities discovered in the past few years across various industries have forced regulators and legislators to take a renewed look at accounting practices, financial disclosures, companies’ relationships with their independent registered public accounting firm and retirement plan practices. We cannot predict the ultimate impact of any future changes in accounting regulations or practices in general with respect to public companies or the energy industry or in our operations specifically.

In addition the Financial Accounting Standards Board (FASB), the 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, liabilities and equity.

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

Institutional knowledge residing with current employees nearing retirement eligibility 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. In addition, we may not be able to retain or recruit other qualified individuals and our efforts at knowledge transfer could be inadequate. If knowledge transfer, recruiting and retention efforts are inadequate, access to significant amounts of internal historical knowledge and expertise could become unavailable to us.

Failure of the outsourcing relationships 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 and to closely monitor their performance, a deterioration in the timeliness or quality of the services performed by the outsourcing providers or 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 of our accounting, information technology, application development, and help desk services are currently provided by Williams’ outsourcing provider from service centers outside of the United States. 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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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 be less efficient, may require more personnel and capital resources to maintain and upgrade than more current systems, and 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 and results of operations.

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 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. While efforts are ongoing to maintain equipment and pipeline facilities, the current age and condition of this pipeline infrastructure could result in a material adverse impact on our business.

Acts of terrorism could have a material adverse effect on our financial condition, results of operations and cash flows.

Our assets and the assets of our customers and others may be targets of terrorist activities that could disrupt our business or cause significant harm to our operations, such as full or partial disruption to our ability to transport natural gas. Acts of terrorism as well as events occurring in response to or in connection with acts of terrorism could cause environmental repercussions that could result in a significant decrease in revenues or significant reconstruction or remediation costs, which could have a material adverse effect on our financial condition, results of operations and cash flows.

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 “Item 8. Financial Statements and Supplementary Data – Notes to Financial Statements – 3. Contingent Liabilities and Commitments – Legal Proceedings.”

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.

During the fourth quarter of 2006, we received a $65 million capital contribution of cash from WGP. This cash was used to help fund capital projects, including the Capacity Replacement and Parachute Lateral Projects.

We paid $50 million in cash dividends during 2005. No dividends were paid during 2006.

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, 2006 and 2005, we had approximately $64.8 million and $60.0 million, respectively, 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 $48.1 million and $44.2 million, respectively, of regulatory liabilities related to pension and postretirement benefits and negative salvage included on the accompanying Balance Sheet. (See “Item 8. Financial Statements and Supplementary Data – Notes to

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Financial Statements – 1. Summary of Significant Accounting Policies – Property, Plant and Equipment” for a description of levelized incremental projects.)

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 factors affecting our rates are (1) costs of providing service, including depreciation expense, (2) the inclusion of an allowed rate of return on capital assets, including the equity component of the capital structure and related income taxes, and (3) contract demand and 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. We have no pending regulatory proceedings and no potential rate refunds that would affect the rates we have charged through December 31, 2006.

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. The regulatory asset will be recovered through our net negative salvage rate recovery.

Pension and Postretirement Obligations

We participate in employee benefit plans with Williams and its subsidiaries that include pension and other postretirement benefits. Pension and other postretirement benefit expense and obligations are

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calculated by a third-party actuary and are impacted by various estimates and assumptions. These estimates and assumptions include the expected long-term rates of return on plan assets, discount rates, expected rate of compensation increase, health care trend rates, and employee demographics, including retirement age and mortality. These assumptions are reviewed annually and adjustments are made as needed.

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. During 2006, we expensed approximately $5.1 million that previously would have been capitalized.

CAPACITY REPLACEMENT PROJECT

Reference is made to “Item 1. Business – Capital Projects” on page 2.

RESULTS OF OPERATIONS

ANALYSIS OF FINANCIAL RESULTS

This analysis discusses financial results of our operations for the years 2006 and 2005. 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 increased $2.8 million, or 1 percent. Higher levels of short-term firm transportation services and park and loan services, a form of interruptible storage service, are the primary sources for this increase.

Our transportation service accounted for 96 percent and our gas storage service accounted for 3 percent of our operating revenues for each of the years ended December 31, 2006 and 2005.

Operating expenses increased $27.9 million, or 15 percent. This increase is due primarily to a $9.7 million increase in consulting, contract, engineering, maintenance and other outside services resulting primarily from our pipeline integrity and environmental assessment efforts; an $8.9 million increase in depreciation, including a $6.0 million increase resulting from property additions and a $2.9 million increase related to the correction of an error as described in “Item 8. Financial Statements and Supplementary Data – Notes to Financial Statements – 1. Summary of Significant Accounting Policies – Reclassifications and Adjustments”; and a $5.5 million increase in outside administrative costs related primarily to information technology services. Also contributing to this increase were higher labor expenses of $3.9 million, higher materials, supplies, vehicle and other expenses of $3.9 million, and higher insurance costs of $1.6 million related primarily to pipeline operations. These increases were partially offset by lower rent expense of $6.2 million related to the correction of an error as described in “Item 8. Financial Statements and Supplementary Data – Notes to Financial Statements – 1. Summary of Significant Accounting Policies – Reclassifications and Adjustments.”

Operating income decreased $25.1 million, or 18 percent, due to the reasons discussed above.

Other income increased $6.0 million, or 57 percent, primarily due to a $10.8 million increase in the allowance for equity funds used during construction (EAFUDC) resulting from the significantly higher capital expenditures in 2006, partially offset by an adjustment of $4.7 million associated with the correction of an error related to the recognition of EAFUDC as described in ”Item 8. Financial Statements and Supplementary Data – Notes to Financial Statements – 1. Summary of Significant Accounting Policies – Reclassifications and Adjustments.”

Interest charges increased $2.9 million, or 7 percent. This increase is the result of higher interest on long-term debt of $5.5 million from the new debt issued in June 2006, offset by the $3.0 million increase in the allowance for borrowed funds used during construction related to the higher property additions in 2006.

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The provision for income taxes decreased $7.4 million, or 18 percent, due primarily to lower pre-tax income in 2006 as compared to 2005 and a $1.8 million tax benefit adjustment in 2005 as a result of additional analysis of our tax basis and book basis assets and liabilities. See “Item 8. Financial Statements and Supplementary Data – Notes to Financial Statements – 6. Income Taxes.”

On June 30, 2006, we filed a rate case with the FERC to request changes to the rates we charge. The new rates became effective January 1, 2007. On January 31, 2007, we filed a stipulation and settlement agreement that resolves all outstanding issues in our pending rate case. The settlement is subject to FERC approval. The settlement specified an annual cost of service of $404 million and, among other things, establishes an increase in our general system firm transportation rates.

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. 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.

CAPITAL RESOURCES AND LIQUIDITY

METHOD OF FINANCING

We fund our capital requirements with cash flows from operating activities, accessing capital markets, and, if required, borrowings under the Credit Agreement and advances from Williams.

In June 2006, we issued $175 million aggregate principal amount of 7 percent senior unsecured notes due 2016 to certain institutional investors in a private debt placement. In October 2006, we completed the exchange of these notes for substantially identical new notes that are registered under the Securities Act of 1933, as amended.

We have an effective shelf registration statement on file with the SEC. At December 31, 2006, $150 million of availability remained under this registration statement. While our credit ratings from certain credit rating agencies 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.

In May 2006, Williams obtained an unsecured, three-year, $1.5 billion revolving credit facility, replacing its $1.275 billion secured credit facility. The new unsecured facility contains similar terms and covenants as the secured facility, but contains additional restrictions on asset sales, certain subsidiary debt, and sale-leaseback transactions. WGP guarantees the facility and Williams guarantees obligations of Williams Partners L.P. for up to $75 million. We have access to $400 million under the facility to the extent not otherwise utilized by Williams. Interest is calculated based on a choice of two methods: a fluctuating rate equal to the lender’s base rate plus an applicable margin or a periodic fixed rate equal to the London Interbank Offered Rate plus an applicable margin. Williams is required to pay a commitment fee (currently .25 percent annually) based on the unused portion of the facility. The margins and commitment fee are based on the specific borrower’s senior unsecured long-term debt ratings. Letters of credit totaling approximately $29 million, none of which are associated with us, have been issued by the participating institutions and no revolving credit loans were outstanding at December 31, 2006. We did not access this facility during 2006.

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Our $250 million, 6.625 percent notes are payable on December 1, 2007. We intend to fund this retirement through accessing the capital markets and, if required, by borrowings under the Credit Agreement.

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).

During 2006, the rating agencies raised the credit ratings on our senior unsecured long-term debt as shown below. While the Moody’s Investor Services and Standard and Poor’s credit ratings remain below investment grade, the rise in the Fitch Ratings credit rating moves us to investment grade.


Moody’s Investors Service		Ba2 to Ba1
Standard and Poor’s		B+ to BB-
Fitch Ratings		BB+ to BBB-

Currently, the Standard and Poor’s evaluation of our credit rating is “positive outlook,” and the Fitch Ratings and Moody’s Investors Service evaluations of our credit rating are “stable outlook.”

CAPITAL EXPENDITURES

Our expenditures for property, plant and equipment additions were $473.6 million, $137.2 million and $102.2 million for 2006, 2005 and 2004, respectively. The increase in expenditures during 2006 is primarily due to the Capacity Replacement and Parachute Projects. (See “Item 1. Business – Capital Projects” on page 2.) We filed a rate case on June 30, 2006 to recover the cost of property, plant, and equipment placed into service as of December 31, 2006. Our new rates became effective on January 1, 2007, subject to refund. We anticipate 2007 capital expenditures will be between $115 million and $145 million. These expenditures will include maintenance capital expenditures, including expenditures required for the Pipeline Safety Improvement Act of 2002, and the Parachute Lateral Project.

OTHER

Contractual Obligations

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

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			2008 –		2010 –		There-
	2007		2009		2011		after		Total
Long-term debt, including current portion:
Principal	$	252.9	$	—	$	175.0	$	260.0	$	687.9
Interest		49.3		65.1		43.7		139.9		298.0

Operating leases		6.4		12.7		—		—		19.1

Purchase Obligations:
Natural gas purchase, storage, transportation and construction		62.8		5.3		4.3		2.0		74.4
Other		1.4		.6		.1		.1		2.2


Total	$	372.8	$	83.7	$	223.1	$	402.0	$	1,081.6

Regulatory Proceedings

Reference is made to “Item 8. Financial Statements and Supplementary Data — Notes to Financial Statements – 3. Contingent Liabilities and Commitments” for information about regulatory and business developments which cause operating and financial uncertainties.

CONCLUSION

Although no assurances can be given, we currently believe that the aggregate of cash flows from operating activities, supplemented, when necessary, 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, 2006. The table presents principle cash flows (at face value) and weighted-average interest rates by expected maturity dates.

December 31, 2006


	Expected Maturity Date
	2007			2008			2009			2010			2011			Thereafter			Total		Fair Value
	(millions of dollars)
Long-term debt, including current portion:

Fixed rate	$	252.9		$	—		$	—		$	175.0		$	—		$	260.0		$	687.9	$	703.8
Interest rate		7.2	%		7.5	%		7.5	%		7.2	%		7.0	%		7.0	%

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Stockholder of Northwest Pipeline Corporation

We have audited the accompanying balance sheets of Northwest Pipeline Corporation as of December 31, 2006 and 2005 and the related statements of income, comprehensive income, common stockholder’s equity, and cash flows for each of the three years in the period ended December 31, 2006. 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, 2006 and 2005, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2006, 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 discussed in Note 5 to the financial statements, in 2006 the Company adopted Statement of Financial Accounting Standards No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans – An Amendment of FASB Statements No. 87, 88, 106, and 132(R), and Statement of Financial Accounting Standards No. 123(R), Share-Based Payment — a revision of FASB Statement No. 123, Accounting for Stock-Based Compensation. As discussed in Note 1 to the financial statements, in 2006 the Company adopted the Federal Energy Regulatory Commission order on accounting for pipeline assessment costs.

ERNST & YOUNG LLP

Houston, Texas
February 28, 2007

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NORTHWEST PIPELINE CORPORATION

STATEMENTS OF INCOME

(Thousands of Dollars)


	Years Ended December 31,
	2006			2005			2004
OPERATING REVENUES	$	324,250		$	321,457		$	338,532


OPERATING EXPENSES:
General and administrative		56,463			49,749			51,062
Operation and maintenance		65,763			53,330			42,878
Depreciation		75,192			66,333			65,615
Regulatory credits		(4,469	)		(4,446	)		(7,180	)
Taxes, other than income taxes		15,018			15,115			17,492
Impairment charges (Note 12)		—			—			8,872


Total operating expenses		207,967			180,081			178,739


Operating income		116,283			141,376			159,793


OTHER INCOME – net:
Interest income –
Affiliated companies		3,920			3,801			4,517
Other		3,423			2,820			340
Allowance for equity funds used during construction		8,947			2,872			806
Miscellaneous other income (deductions), net		307			1,104			(385	)


Total other income — net		16,597			10,597			5,278


INTEREST CHARGES:
Interest on long-term debt		43,649			38,164			38,721
Other interest		3,824			3,389			3,368
Allowance for borrowed funds used during construction		(4,557	)		(1,529	)		(452	)


Total interest charges		42,916			40,024			41,637


INCOME BEFORE INCOME TAXES		89,964			111,949			123,434

PROVISION FOR INCOME TAXES		32,821			40,194			46,779


NET INCOME	$	57,143		$	71,755		$	76,655


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

See accompanying notes.

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NORTHWEST PIPELINE CORPORATION

BALANCE SHEETS

(Thousands of Dollars)


	December 31,
	2006		2005
ASSETS

CURRENT ASSETS:
Cash and cash equivalents	$	1,489	$	59,709
Advances to affiliates		49,980		50,000
Accounts receivable –
Trade, less allowance of $53 for 2006 and $91 for 2005		32,230		28,677
Affiliated companies		591		4,015
Income taxes due from affiliate		—		1,475
Materials and supplies, less reserves of $472 for 2006 and $263 for 2005		10,013		8,365
Exchange gas due from others		10,556		11,257
Exchange gas offset (Note 1)		4,538		9,386
Deferred income taxes		4,066		3,913
Prepayments and other		7,945		2,681


Total current assets		121,408		179,478


PROPERTY, PLANT AND EQUIPMENT, at cost		2,669,056		2,286,280
Less – Accumulated depreciation		893,033		957,385


Total property, plant and equipment		1,776,023		1,328,895


OTHER ASSETS:
Deferred charges		32,093		49,124
Regulatory assets		63,330		58,607


Total other assets		95,423		107,731


Total assets	$	1,992,854	$	1,616,104

See accompanying notes.

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NORTHWEST PIPELINE CORPORATION

BALANCE SHEETS

(Thousands of Dollars)


	December 31,
	2006			2005
LIABILITIES AND STOCKHOLDER’S EQUITY

CURRENT LIABILITIES:
Accounts payable –
Trade	$	55,403		$	25,835
Affiliated companies		13,701			3,754
Accrued liabilities –
Income taxes due to affiliate		3,090			—
Taxes, other than income taxes		6,779			8,511
Interest		7,038			7,013
Employee costs		10,759			8,731
Exchange gas due to others		15,094			20,643
Deferred contract termination income		6,045			6,045
Other		5,268			4,318
Current maturities of long-term debt (Note 4)		252,867			7,500


Total current liabilities		376,044			92,350


LONG-TERM DEBT, LESS CURRENT MATURITIES		434,208			512,580

DEFERRED INCOME TAXES		255,469			236,548

DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES		114,096			65,869

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		327,844			262,844
Retained earnings		503,055			445,912
Accumulated other comprehensive loss		(17,863	)		—


Total common stockholder’s equity		813,037			708,757


Total liabilities and stockholder’s equity	$	1,992,854		$	1,616,104

See accompanying notes.

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NORTHWEST PIPELINE CORPORATION

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


	Years Ended December 31,
	2006			2005			2004
Common stock, par value $1 per share, authorized and outstanding, 1,000 shares	$	1		$	1		$	1


Additional paid-in capital -
Balance at beginning of period		262,844			262,844			262,844
Capital contribution from parent		65,000			—			—


Balance at end of period		327,844			262,844			262,844


Retained earnings -
Balance at beginning of period		445,912			424,157			407,502
Net income		57,143			71,755			76,655
Cash dividends		—			(50,000	)		(60,000	)


Balance at end of period		503,055			445,912			424,157


Accumulated other comprehensive loss (net of tax) –
Balance at beginning of period		—			—			(388	)
Gain on cash flow hedges, net of reclassification adjustments		365			—			—
Minimum pension liability adjustment		—			—			388
Adjustment to initially apply SFAS No. 158:
Pension benefits:
Prior service cost		(308	)		—			—
Net actuarial loss		(17,920	)		—			—


Balance at end of period		(17,863	)		—			—


Total common stockholder’s equity	$	813,037		$	708,757		$	687,002

See accompanying notes.

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NORTHWEST PIPELINE CORPORATION

STATEMENTS OF CASH FLOWS
(Thousands of Dollars)


	Years Ended December 31,
	2006			2005			2004
OPERATING ACTIVITIES:
Net Income	$	57,143		$	71,755		$	76,655
Adjustments to reconcile to net cash provided by operating activities -
Depreciation		75,192			66,333			65,615
Regulatory credits		(4,469	)		(4,446	)		(7,180	)
Provision (benefit) for deferred income taxes		29,531			(18,571	)		33,524
Impairment charges		—			—			8,872
Amortization of deferred charges and credits		2,484			4,053			4,189
Allowance for equity funds used during construction		(8,947	)		(2,872	)		(806	)
Reserve for doubtful accounts		(38	)		44			—
Changes in:
Trade accounts receivable		(3,515	)		1,639			918
Affiliated receivables, including income taxes		4,899			(5,489	)		577
Exchange gas due from others		5,549			(4,632	)		(5,765	)
Materials and supplies		(1,912	)		236			899
Other current assets		(5,264	)		(800	)		685
Deferred charges		(1,610	)		(6,992	)		(5,854	)
Trade accounts payable		27,440			8,931			(6,279	)
Affiliated payables, including income taxes		13,037			(15,785	)		5,019
Exchange gas due to others		(5,549	)		4,632			5,765
Other accrued liabilities		1,192			6,440			2,422
Other deferred credits		4,095			3,659			2,592


Net cash provided by operating activities		189,258			108,135			181,848


INVESTING ACTIVITIES:
Property, plant and equipment -
Capital expenditures		(473,566	)		(137,232	)		(102,213	)
Proceeds from sales		—			—			5,033
Asset removal cost		(9,733	)		(1,568	)		—
Changes in accounts payable		2,881			6,564			(784	)
Proceeds from contract termination payment		3,348			87,917			—
Repayments from affiliates		20			—			36,356


Net cash used in investing activities		(477,050	)		(44,319	)		(61,608	)


FINANCING ACTIVITIES:
Proceeds from issuance of long-term debt		174,447			—			—
Principal payments on long-term debt		(7,500	)		(7,500	)		(7,500	)
Debt issuance costs		(2,375	)		—			—
Capital contribution from parent		65,000			—			—
Dividends paid		—			(50,000	)		(60,000	)


Net cash provided by (used in) financing activities		229,572			(57,500	)		(67,500	)


NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		(58,220	)		6,316			52,740

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


CASH AND CASH EQUIVALENTS AT END OF YEAR	$	1,489		$	59,709		$	53,393

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 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, 2006 and 2005, we had approximately $64.8 million and $60.0 million, respectively, of regulatory assets primarily related to equity funds used during construction, levelized incremental projects (See Property, Plant and Equipment.), asset retirement obligations, environmental costs and other postemployment benefits, and approximately $48.1 million and $44.2 million, respectively, of regulatory liabilities related to pension and postretirement benefits and negative salvage included on the accompanying Balance Sheet. (See Note 10.)

Basis of Presentation

Our 1983 acquisition by Williams has been accounted for using the purchase method of accounting. Accordingly, Williams performed an allocation of the purchase price 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 $72.0 million, as of December 31, 2006, 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

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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 2.86 percent, 2.96 percent and 3.00 percent for 2006, 2005 and 2004, 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 $4.5 million in 2006, $4.4 million in 2005, and $7.2 million in 2004 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 $22.1 million at December 31, 2006, and $18.6 million at December 31, 2005. Such amounts will be amortized over the primary terms of the shipper agreements as such costs are collected through rates.

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 is offset by a regulatory asset. The regulatory asset will be recovered through the net negative salvage component of depreciation included in our rates beginning January 1, 2007.

Included in our depreciation rates is a negative salvage (cost of removal) component that we have collected 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 ($18.2 million and $15.9 million at December 31, 2006 and 2005, 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, and a cumulative understatement of Operating Income and Net Income for periods prior to 2004 by $5.4 million and $3.4 million, respectively. Management believes that the effect of the adjustment was not material to 2004 income, prior quarters and years, or trends of earnings.

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NORTHWEST PIPELINE CORPORATION

NOTES TO FINANCIAL STATEMENTS

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 2006, 2005 and 2004. Equity AFUDC of $8.9 million, $2.9 million and $0.8 million for 2006, 2005 and 2004, 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, which was 7.81 percent at December 31, 2006.

Accounts Receivable and Allowance for Doubtful Receivables

Accounts receivable are stated at the historical carrying amount net of allowance for doubtful accounts. Our credit risk exposure in the event of nonperformance by the other parties is limited to the face value of the receivables. We perform ongoing credit evaluations of our customers’ financial condition and require collateral from our customers, if necessary. 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.

Materials and Supplies Inventory

All inventories are stated at lower of cost or market. We determine the cost of the inventories using the average cost method.

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

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.

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NORTHWEST PIPELINE CORPORATION

NOTES TO FINANCIAL STATEMENTS

Income Taxes

Williams and its wholly-owned subsidiaries, which includes us, file a consolidated federal income tax return. It is Williams’ policy to charge or credit us with an amount equivalent to our federal income tax expense or benefit computed as if we had filed a separate return.

We use the liability method of accounting for income taxes which requires, among other things, provisions for all temporary differences between the financial basis and the tax basis in our assets and liabilities and adjustments to the existing deferred tax balances for changes in tax rates. We reserve our gross deferred tax assets when we determine it is more likely than not they will not be recovered.

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 or deliver different quantities of gas from shippers than the quantities delivered or received 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, 2006, we have no 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 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.

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NORTHWEST PIPELINE CORPORATION

NOTES TO FINANCIAL STATEMENTS

Interest Payments

Cash payments for interest were $39.1 million, $36.9 million and $38.7 million, net of $4.6 million, $1.5 million and $0.5 million of interest capitalized (allowance for borrowed funds used during construction) in 2006, 2005 and 2004, respectively.

Recent Accounting Standards

In June 2006, the FASB issued FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes, an interpretation of FASB Statement No. 109” (FIN 48). The Interpretation clarifies the accounting for uncertainty in income taxes under FASB Statement No. 109, “Accounting for Income Taxes.” The Interpretation prescribes guidance for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. To recognize a tax position, the enterprise determines whether it is more likely than not that the tax position will be sustained upon examination, including resolution of any related appeals or litigation processes, based on the technical merits of the position. A tax position that meets the more likely than not recognition threshold is measured to determine the amount of benefit to recognize in the financial statements. The tax position is measured as the largest amount of benefit, determined on a cumulative probability basis, that is greater than 50 percent likely of being realized upon ultimate settlement.

FIN 48 is effective for fiscal years beginning after December 15, 2006. The cumulative effect of applying the Interpretation must be reported as an adjustment to the opening balance of retained earnings in the year of adoption. We adopted FIN 48 beginning January 1, 2007, as required. We expect no material impact of the cumulative effect of adopting FIN 48 on our financial statements.

FERC Order, “Accounting for Pipeline Assessment Cost” 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. During 2006, we expensed approximately $5.1 million that previously would have been capitalized.

Reclassifications and Adjustments

In the third quarter of 2006, we made an adjustment to correct an error resulting from an analysis of our regulatory assets. Property, plant and equipment includes the capitalization of equity funds used during construction (EAFUDC). The capitalization of EAFUDC creates a deferred tax liability and an associated regulatory asset. The regulatory asset was not properly reduced for certain retirements of property, plant and equipment made prior to 2000. The correction of the error resulted in a decrease to miscellaneous other income of $4.7 million and a decrease to net income of $3.0 million during 2006.

In the fourth quarter of 2006, we made adjustments to correct errors related to the accounting for our headquarters building lease expense and depreciation of leasehold improvements. The correction of the errors resulted in a decrease to general and administrative expense of $6.2 million, an increase to depreciation expense of $2.9 million and an increase to Net Income of $2.1 million during 2006.

Management concluded that the effect of these corrections is not material to prior annual or interim periods, to 2006 results, or to the trend of earnings.

2. RATE AND REGULATORY MATTERS

General Rate Case (Docket No. RP06-416)

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NORTHWEST PIPELINE CORPORATION

NOTES TO FINANCIAL STATEMENTS

operating costs. On July 31, 2006, the FERC issued an Order accepting our filing and suspended the effective date of the new rates for five months, to become effective January 1, 2007, subject to refund. On January 31, 2007, we filed a stipulation and settlement agreement that resolves all outstanding issues in our pending rate case. That settlement is either supported or not opposed by both the intervening parties and FERC staff. It is expected to be uncontested. The settlement specified an annual cost of service of $404 million and establishes that general system firm transportation rates on our system will increase from $0.30760 to $0.40984 per Dth, effective January 1, 2007. The settlement is subject to FERC approval. We anticipate the approval process will be completed by mid-2007.

3. CONTINGENT LIABILITIES AND COMMITMENTS

Legal Proceedings

In 1998, the United States Department of Justice (DOJ) informed Williams that Jack Grynberg, an individual, had filed claims in the United States District Court for the District of Colorado under the False Claims Act against Williams and certain of its wholly-owned subsidiaries including us. Mr. Grynberg had also filed claims against approximately 300 other energy companies alleging that the defendants violated the False Claims Act in connection with the measurement, royalty valuation and purchase of hydrocarbons. The relief sought was an unspecified amount of royalties allegedly not paid to the federal government, treble damages, a civil penalty, attorneys’ fees, and costs. In April 1999, the DOJ declined to intervene in any of the Grynberg qui tam cases, and in October 1999, the Panel on Multi-District Litigation transferred all of the Grynberg qui tam cases, including those filed against Williams, to the United States District Court for the District of Wyoming for pre-trial purposes. In October 2002, the court granted a motion to dismiss Grynberg’s royalty valuation claims. Grynberg’s measurement claims remained pending against Williams, including us, and the other defendants, although the defendants had filed a number of motions to dismiss these claims on jurisdictional grounds. 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. On October 20, 2006, the District Court dismissed all claims against us. Mr. Grynberg filed a Notice of Appeal from the dismissals with the Tenth Circuit Court of Appeals effective November 17, 2006.

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.

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, 2006, we have accrued liabilities totaling approximately $4.7 million for these costs which are expected to be incurred over the period from now 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.

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NORTHWEST PIPELINE CORPORATION

NOTES TO FINANCIAL STATEMENTS

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 $75 million and $105 million over the remaining assessment period of 2007 through 2012. As a result of the June 30, 2005, FERC order described in Note 1, a portion of this amount will be expensed. Management considers the costs associated with compliance with the rule to be prudent costs incurred in the ordinary course of business and, therefore, recoverable through our rates.

Other Matters

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

Summary

Litigation, arbitration, regulatory matters, 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 on our future financial position.

Other Commitments

We have commitments for construction and acquisition of property, plant and equipment of approximately $55.2 million at December 31, 2006.

Termination of the Grays Harbor Transportation Agreement

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NORTHWEST PIPELINE CORPORATION

NOTES TO FINANCIAL STATEMENTS

Based upon the above, we do not anticipate any adverse impact to our results of operations or financial position from this matter.

4. DEBT, FINANCING ARRANGEMENTS AND LEASES

Debt Covenants

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. Our ratio of debt to capitalization must be no greater than 55 percent. We are in compliance with this covenant as our ratio of debt to capitalization, as calculated under this covenant, is approximately 44 percent at December 31, 2006.

Long-Term Debt

Long-term debt consists of the following:


	December 31,
	2006		2005
	(Thousands of Dollars)
6.625%, payable 2007	$	250,000	$	250,000
7%, payable 2016		174,477		—
7.125%, payable 2025		84,785		84,774
8.125%, payable 2010		175,000		175,000
9%, payable 2004 through 2007		2,813		10,306

Total long-term debt		687,075		520,080

Less current maturities		252,867		7,500


Total long-term debt, less current maturities	$	434,208	$	512,580

As of December 31, 2006, 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)
2007	$	252,867
2008		—
2009		—
2010		175,000
2011		—
Thereafter		260,000


Total	$	687,867

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NORTHWEST PIPELINE CORPORATION

NOTES TO FINANCIAL STATEMENTS

Line-of-Credit Arrangements

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 annual rental payments required under operating leases, which have initial or remaining noncancelable lease terms in excess of one year:


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

	$	19,065

Less: noncancelable subleases		8,241


Total	$	10,824

Operating lease rental expense, net of sublease revenues, amounted to ($1.2) million, $5.3 million, and $6.2 million for 2006, 2005 and 2004, respectively. (See Note 1 — Reclassifications and Adjustments.)

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NORTHWEST PIPELINE CORPORATION

NOTES TO FINANCIAL STATEMENTS

5. EMPLOYEE BENEFIT PLANS

SFAS No. 158 Adoption

In September 2006, the FASB issued SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans — an amendment of FASB Statements No. 87, 88, 106 and 132(R)” (SFAS No. 158). This Statement requires sponsors of defined benefit pension and other postretirement benefit plans to recognize the funded status of their pension and other postretirement benefit plans in the statement of financial position, measure the fair value of plan assets and benefit obligations as of the date of the fiscal year-end statement of financial position, and provide additional disclosures. On December 31, 2006, we adopted the recognition and disclosure provisions of SFAS No. 158 related to our participation in Williams’ sponsored pension and other postretirement benefit plans, the effect of which has been reflected in the accompanying financial statements as of December 31, 2006, as described below. The adoption had no impact on the financial statements at December 31, 2005 or 2004. SFAS No. 158’s provisions regarding the change in the measurement date of postretirement benefit plans are not applicable as we already use a measurement date of December 31. There is no effect on our Statement of Income for the year ended December 31, 2006, or for any periods presented related to the adoption of SFAS No. 158, nor will our future operating results be affected by the adoption.

Prior to the adoption of SFAS No. 158, accounting rules allowed for the delayed recognition of certain actuarial gains and losses caused by differences between actual and assumed outcomes, as well as charges or credits caused by plan changes impacting the benefit obligations which were attributed to participants’ prior service. These unrecognized net actuarial gains or losses and unrecognized prior service costs or credits represented the difference between the plans’ funded status and the amount recognized on the Balance Sheet. In accordance with SFAS No. 158, we recorded adjustments to accumulated other comprehensive loss, net of income taxes, to recognize the funded status of the pension plans on our Balance Sheet. We recorded an offsetting adjustment to regulatory liabilities for the other postretirement benefit plans. FERC ratemaking policies allow for any differences between the actuarially determined costs and amounts currently being recovered in rates related to other postretirement benefits to be collected in future rates. The detail of the effect of adopting SFAS No. 158 is provided in the following table.

The adjustments recorded to accumulated other comprehensive loss and regulatory liabilities will be recognized as components of net periodic pension expense or net periodic other postretirement benefit expense and amortized over future periods in accordance with SFAS No. 87, “Employers’ Accounting for Pensions” and SFAS No. 106 “Employers’ Accounting for Postretirement Benefits Other Than Pensions” in the same manner as prior to the adoption of SFAS No. 158. Actuarial gains and losses that arise in subsequent periods and are not recognized as net periodic pension or other postretirement benefit expense in the same period will now be recognized in other comprehensive loss and regulatory liabilities. These amounts will be recognized subsequently as a component of net periodic pension or other postretirement benefit expense following the same basis as the amounts recognized in accumulated other comprehensive loss and regulatory liabilities upon adoption of SFAS No. 158.

The effects of adopting SFAS No. 158 to our Balance Sheet at December, 31, 2006, are as follows:

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NORTHWEST PIPELINE CORPORATION

NOTES TO FINANCIAL STATEMENTS


	Prior to		Effect of			After
	SFAS No. 158		SFAS No. 158			SFAS No. 158
	Adoption (1)		Adoption (1)			Adoption (1)
	(Thousands of Dollars)
Balances related to pension plans within:
Assets:
Noncurrent assets	$	19,021	$	(18,109	)	$	912
Regulatory assets
Liabilities:		83		(83	)		—
Current liabilities		—		79			79
Noncurrent liabilities		3,377		10,941			14,318
Regulatory liabilities		16,562		—			16,562
Deferred income tax liabilities		—		(10,984	)		(10,984	)
Stockholder’s Equity:
Accumulated other comprehensive loss		—		(18,228	)		(18,228	)

Balances related to other postretirement benefits plans within:
Assets:
Noncurrent assets
Liabilities:		13,639		25			13,664
Regulatory liabilities		13,329		25			13,354


(1)		Amounts in brackets represent a reduction within the line item balance included on the Balance Sheet.

Prior to the adoption of SFAS No. 158, we had computed an additional minimum pension liability of $83 thousand. The effect of recognizing this additional minimum pension liability is included in the regulatory assets amount under the “Prior to SFAS No. 158 Adoption” column within the table above.

Accumulated other comprehensive loss at December 31, 2006 includes the following:


	Pension Benefits
	Gross			Net of Tax
	(Thousands of Dollars)
Amounts not yet recognized in net periodic benefit expense:
Unrecognized prior service cost	$	(494)		$	(308	)
Unrecognized net actuarial losses		(28,717	)		(17,920	)

Amounts expected to be recognized in net periodic benefit expense in 2007:
Prior service cost		77			48
Net actuarial losses		1,969			1,229

Regulatory liabilities include unrecognized prior service costs of $3,231 thousand and unrecognized net actuarial gains of $3,256 thousand. These amounts have not yet been recognized in net periodic other postretirement benefit expense.

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NORTHWEST PIPELINE CORPORATION

NOTES TO FINANCIAL STATEMENTS

Pension plans

We participate in noncontributory defined benefit pension plans with Williams and its subsidiaries that provide pension benefits for our eligible participants employees. Cash contributions related to our participation in the plans totaled $3.3 million in 2006, $3.7 million in 2005 and $3.6 million in 2004. These amounts are currently recoverable in our rates. Amounts expensed in each year were equal to the cash contributions. Any difference between the annual actuarially determined cost and amounts funded are recorded as an adjustment to the regulatory asset or liability. The amounts of pension benefit costs deferred as a regulatory liability at December 31, 2006 and 2005 are $16.6 million and $17.5 million, respectively.

At December 31, 2005, we had recorded an additional minimum pension liability of $28 thousand. As required by FERC accounting guidance, this balance was recorded as a regulatory asset instead of accumulated other comprehensive loss.

Postretirement benefits other than pensions

We participate in a plan with Williams and its subsidiaries that provides certain retiree health care and life insurance benefits for our eligible participants that were hired prior to January 1, 1992. The accounting for the plan anticipates future cost-sharing changes to the plan that are consistent with Williams’ expressed intent to increase the retiree contribution level, generally in line with health care cost increases. Cash contributions totaled $2.4 million in each of the years 2006, 2005, and 2004. We recover the actuarially determined cost of postretirement benefits through rates that are set through periodic general rate filings. Any differences between the annual actuarially determined cost and amounts currently being recovered in rates are recorded as an adjustment to a regulatory asset or liability and any unrecovered amounts will be collected through future rate adjustments. The amounts of postretirement benefits costs deferred as a regulatory liability at December 31, 2006 and 2005 are $13.4 million and $10.8 million, respectively. Amounts expensed in each year were equal to the cash contributions.

Defined contribution plan

Our employees participate in a Williams’ defined contribution plan. We recognized compensation expense of $1.8 million in 2006, $1.5 million in 2005 and $1.3 million in 2004.

Stock-Based Compensation

Plan Information

The Williams Companies, Inc. 2002 Incentive Plan (the “Plan”) was approved by stockholders on May 16, 2002, and amended and restated on May 15, 2003, and January 23, 2004. The Plan provides for Williams common-stock-based awards to both employees and nonmanagement directors. The Plan permits the granting of various types of awards including, but not limited to, stock options 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.

Williams currently bills us directly for compensation expense related to stock-based compensation awards granted directly to our employees. We are also billed for our proportionate share of both WGP’s and Williams’ stock-based compensation expense through various allocation processes.

Accounting for Stock-Based Compensation

Prior to January 1, 2006, we accounted for the Plan under the recognition and measurement provisions of Accounting Principles Board (APB) Opinion No. 25, “Accounting for Stock Issued to Employees” and related interpretations, as permitted by FASB Statement No. 123, “Accounting for Stock-Based Compensation” (SFAS No. 123). Compensation cost for stock options was not recognized in our Statement of Income for 2005, as all Williams stock options granted under the Plan had an exercise price equal to the market value of the underlying Williams common stock on the date of the grant. Prior to January 1, 2006, compensation cost was recognized for deferred share awards. Effective January 1,

-38-

NORTHWEST PIPELINE CORPORATION

NOTES TO FINANCIAL STATEMENTS

2006, we adopted the fair value recognition provisions of FASB Statement No. 123(R), “Share-Based Payment” (SFAS No. 123(R)), using the modified-prospective method. Under this method, compensation cost recognized in 2006 includes: (1) compensation cost for all Williams share-based payments granted through December 31, 2005, but for which the requisite service period had not been completed as of December 31, 2005, based on the grant date fair value estimated in accordance with the original provisions of SFAS No. 123, and (2) compensation cost for most Williams share-based payments granted subsequent to December 31, 2005, based on the grant date fair value estimated in accordance with the provisions of SFAS No. 123(R). The performance targets for certain performance based deferred shares have not been established, and therefore, expense is not currently recognized. Results for prior periods have not been restated.

Total stock-based compensation expense, included in administrative and general expenses, for the year ended December 31, 2006 was $0.9 million, excluding amounts allocated from WGP and Williams.

6. INCOME TAXES

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


	December 31,
	2006		2005
	(Thousands of Dollars)
Property, plant and equipment	$	269,276	$	220,057
Regulatory assets		15,800		12,303
Loss on reacquired debt		3,962		4,521
Other — net		5,808		8,024


Deferred tax liabilities		294,846		244,905


Accrued liabilities		29,225		2,569
Accrued benefits		14,218		9,701


Deferred tax assets		43,443		12,270


Net deferred tax liabilities	$	251,403	$	232,635


Reflected as:
Deferred income taxes — current asset	$	4,066	$	3,913
Deferred income taxes — noncurrent liability		255,469		236,548

	$	251,403	$	232,635

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NORTHWEST PIPELINE CORPORATION

NOTES TO FINANCIAL STATEMENTS

The provision for income taxes includes:


	Year Ended December 31,
	2006		2005			2004
	(Thousands of Dollars)
Current:
Federal	$	2,940	$	52,292		$	11,406
State		350		6,473			1,849

		3,290		58,765			13,255


Deferred:
Federal		26,388		(16,373	)		30,128
State		3,143		(2,198	)		3,396

		29,531		(18,571	)		33,524

Total provision	$	32,821	$	40,194		$	46,779

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


	Year Ended December 31,
	2006			2005			2004
	(Thousands of Dollars)
Provision at statutory Federal income tax rate of 35 percent	$	31,487		$	39,182		$	43,202
Increase (decrease) in tax provision resulting from -
State income taxes net of Federal tax benefit		2,270			2,779			3,409
Book/tax basis reconciliation adjustment		(723	)		(1,835	)		—
Other — net		(213	)		68			168

Provision for income taxes	$	32,821		$	40,194		$	46,779

Effective tax rate		36.48	%		35.90	%		37.90	%

We provide for income taxes using the asset and liability method as required by SFAS 109, “Accounting for Income Taxes.” During 2006 and 2005, respectively, as a result of additional analysis of our tax basis and book basis assets and liabilities, we recorded a $0.7 million and a $1.8 million tax benefit adjustment to reduce the overall deferred income tax liabilities on the Balance Sheet. Management concluded that the effect of these corrections is not material to prior annual or interim periods, to 2006 and 2005 results, or to the trend of earnings.

Net cash payments (received from) made to Williams for income taxes were ($1.3) million, $63.7 million and $11.3 million in 2006, 2005 and 2004, respectively.

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NORTHWEST PIPELINE CORPORATION

NOTES TO FINANCIAL STATEMENTS

7. 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 $688 million and $704 million, respectively, at December 31, 2006, and $520 million and $542 million, respectively, at December 31, 2005.

8. 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,
	2006		2005		2004
	(Thousands of Dollars)
Puget Sound Energy, Inc.	$	64,428	$	56,480	$	46,997
Northwest Natural Gas Co.		35,242		35,420		38,067

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 participant in Williams’ cash management program, we make advances to and receive advances from Williams. At December 31, 2006, the advances due to us by Williams totaled approximately $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, which was 7.81 percent at December 31, 2006. We received interest income from advances to these affiliates of $3.9 million, $3.8 million, and $4.5 million during 2006, 2005 and 2004, respectively. Such interest income is included in Other Income — net on the accompanying Statement of Income.

Williams’ corporate overhead expenses allocated to us were $18.7 million, $19.0 million and $20.3 million for 2006, 2005 and 2004, 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 $15.6 million, $9.8 million and $7.9 million for 2006, 2005 and 2004, respectively. These expenses are included in General and Administrative Expense on the accompanying Statement of Income.

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NORTHWEST PIPELINE CORPORATION

NOTES TO FINANCIAL STATEMENTS

During the periods presented, our revenues include transportation and exchange transactions and rental of communication facilities with subsidiaries of Williams. Combined revenues for these activities totaled $3.4 million, $2.4 million and $2.0 million for 2006, 2005 and 2004, 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.

9. ASSET RETIREMENT OBLIGATIONS

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 (ARO) 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.

During 2006, we obtained additional information impacting our estimation of our ARO. Factors affected by the additional information included estimated settlement dates, estimated settlement costs and inflation rates. We adjusted the ARO related to certain assets because the additional information results in improved and the best available estimates regarding the ARO costs, lives, and inflation rates. As a result, we recorded an increase in Property Plant and Equipment of $31.6 million and a corresponding increase in Deferred Credits and Other Noncurrent Liabilities.

During 2006, our overall asset retirement obligation changed as follows (in thousands):


	2006
Beginning balance	$	15,372
Accretion		965
New obligations		1,451
Changes in estimates of existing obligations.		30,232

Ending Balance	$	48,020

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

10. REGULATORY ASSETS AND LIABILITIES

Our regulatory assets and liabilities result from our application of the provisions of SFAS No. 71 and are reflected on our balance sheet. Current regulatory assets are included in prepayments and

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NORTHWEST PIPELINE CORPORATION

NOTES TO FINANCIAL STATEMENTS

other. Regulatory liabilities are included in deferred credits and other noncurrent liabilities. These balances are presented on our balance sheet on a gross basis and are recoverable over various periods. Below are the details of our regulatory assets and liabilities as of December 31, 2006 and 2005:


	2006		2005
	(Thousands of Dollars)
Current regulatory assets — environmental costs	$	1,500	$	1,400


Non-current regulatory assets
Asset retirement obligations		15,501		14,456
Environmental costs		3,200		2,697
Grossed-up deferred taxes on equity funds used during construction		21,252		21,470
Levelized incremental projects		22,118		18,587
Other postemployment benefits		1,259		1,397


Total non-current regulatory assets		63,330		58,607


Total regulatory assets	$	64,830	$	60,007


Non-current regulatory liabilities
Negative salvage	$	18,178	$	15,883
Pension plans		16,562		17,478
Postretirement benefits		13,354		10,803


Total regulatory liabilities	$	48,094	$	44,164

11.COMPREHENSIVE INCOME

Comprehensive income is as folows:

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NORTHWEST PIPELINE CORPORATION

NOTES TO FINANCIAL STATEMENTS


	2006			2005		2004
	(Thousands of Dollars)

Net income	$	57,143		$	71,755	$	76,655
Other comprehensive income:
Cash flow hedges:
Balance at beginning of period		—			—		—
Gain on cash flow hedges		619			—		—
Reclassification cash flow hedge gain into earnings		(34	)		—		—

Balance at end of period		585

Minimum pension liability:
Balance at beginning of period		—			—		388
Minimum pension liability adjustment		—			—		(388	)

Balance at end of period		—			—		—

Other comprehensive income before taxes		585			—		—
Income tax provision on other comprehensive income		(220	)		—		—

Other comprehensive income		365			—		—

Comprehensive income	$	57,508		$	71,755	$	76,655

The gain on cash flow hedges for 2006 represents a realized gain on forward starting interest rate swaps that we entered into prior to our issuance of fixed rate, long-term debt in the second quarter 2006. The swaps, which were settled near the date of the debt issuance, hedged the variability of forecasted interest payments arising from changes in interest rates prior to the issuance of our fixed rate debt. The gain will be amortized to reduce interest expense over the life of the related debt.

12. 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 determined not to return to service.

13. QUARTERLY INFORMATION (UNAUDITED)

The following is a summary of unaudited quarterly financial data for 2006 and 2005:


	Quarter of 2006
	First		Second		Third		Fourth
	(Thousands of Dollars)
Operating revenues	$	79,638	$	79,915	$	81,088	$	83,609
Operating income		30,946		29,955		27,764		27,618
Net income		15,902		17,474		11,273		12,494

Third quarter 2006 net income includes a decrease of $3.0 million for EAFUDC related to retirements of property, plant, and equipment. Fourth quarter 2006 includes a net increase in operating income of $3.3 million and a net increase in net income of $2.1 million related to error corrections for building lease expense and for depreciation of leasehold improvements. (See Note 1 — Reclassifications and Adjustments.)

-44-


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:


	2006		2005
	(Thousands of Dollars)
Audit Fees	$	851	$	791
Audit-Related Fees		—		—
Tax Fees		—		—
All Other Fees		—		—

	$	851	$	791

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 9, 2007.

-47-

PART IV


Item 15.		EXHIBITS, FINANCIAL STATEMENT SCHEDULES

(a) 1. Financial Statements

Index


	Page
	Reference
	to 2006
	Form 10-K
Report of Independent Registered Public Accounting Firm		20

Statements of Income for the Years Ended December 31, 2006, 2005 and 2004		21

Balance Sheets at December 31, 2006 and 2005		22

Statements of Common Stockholder’s Equity for the Years Ended December 31, 2006, 2005 and 2004		24

Statements of Comprehensive Income for the Years Ended December 31, 2006, 2005 and 2004		25

Statements of Cash Flows for the Years Ended December 31, 2006, 2005 and 2004		26

Notes to Financial Statements		27

(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, 2006:
Reserve for doubtful receivables	$	91	$	(38	)	$	0		$	53
Reserve for obsolescence of materials and supplies		263		306			(97	)		472
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

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

-48-

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).

		*(e)		Indenture dated as of June 22, 2006, between Northwest Pipeline Corporation and JPMorgan Chase Bank, N.A. (Exhibit 4.1 to Form 8-K filed June 23, 2006).

(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)	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).

	*(2)	Credit Agreement, dated as of May 1, 2006, among The Williams Companies, Inc., Northwest Pipeline Corporation, Transcontinental Gas Pipe Line Corporation, and Williams Partners L.P., as Borrowers, and Citibank, N.A., as Administrative Agent (Exhibit 10.1 to The Williams Companies, Inc. Form 8-K filed May 1, 2006 Commission File Number 1-4174).

-49-


		*(3)				Registration Rights Agreement, dated as of June 22, 2006, among Northwest Pipeline Corporation and J.P. Morgan Securities Inc. and Calyon Securities (USA) Inc., acting on behalf of themselves and the several initial purchasers listed on Schedule I thereto. (Exhibit 10.1 to Form 8-K filed June 23, 2006).

(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.

-50-

SIGNATURES

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

Date: March 1, 2007

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 1, 2007

-51-


	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


Heading	Page

Item 1. BUSINESS		1

Item 1A. RISK FACTORS		5

Item 2. PROPERTIES		12

Item 3. LEGAL PROCEEDINGS		12

Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS (Omitted)		12

PART II

Item 5. MARKET FOR REGISTRANT’S COMMON EQUITY AND RELATED STOCK- HOLDER MATTERS		13

Item 6. SELECTED FINANCIAL DATA (Omitted)		13

Item 7. MANAGEMENT’S NARRATIVE ANALYSIS OF THE RESULTS OF OPERATIONS		13

Item 7A. QUALITATIVE AND QUANTITATIVE DISCLOSURES ABOUT MARKET RISK		18

Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA		19

Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE		46

Item 9A. CONTROLS AND PROCEDURES		46

Item 9B. OTHER INFORMATION		46

PART III

Item 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT (Omitted)		47

Item 11. EXECUTIVE COMPENSATION (Omitted)		47

Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT (Omitted)		47

Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS (Omitted)		47

Item 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES		47

PART IV

Item 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES		48
Consent of Independent Registered Public Accounting Firm
Power of Attorney with Certified Resolution
Section 302 Certification of Principal Executive Officer
Section 302 Certification of Principal Financial Officer
Section 906 Certification of Principal Executive Officer and 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		Allison G. Bridges
Director		Director


		NORTHWEST PIPELINE CORPORATION

		By		/s/ Richard D. Rodekohr

				Richard D. Rodekohr Vice President and
				Treasurer

2.		Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.		Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.		The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)), for the registrant and have:

	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)

1.		I have reviewed this Annual Report on Form 10-K of Northwest Pipeline Corporation;

2.		Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.		Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.		The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)), for the registrant and have:


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


/s/ Phillip D. Wright Phillip D. Wright Senior Vice President March 1, 2007