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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D. C. 20549
 FORM 10-K þ
Annual Report Pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934 
 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  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 whether the registrant (1) has filed all reports required to be filed by
Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for
such shorter period that the registrant was required to file such reports), and (2) has been
subject to such filing requirements for the past 90 days. Yes þ No o Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is
not contained herein, and will not be contained, to the best of registrants knowledge, in
definitive proxy or information statements incorporated by reference in Part III of this Form 10-K
or any amendment to this Form 10-K. þ Indicate by check mark whether the registrant is an accelerated filer (as defined in Exchange Act
Rule 12b-2). Yes o No þ State the aggregate market value of the voting stock held by non-affiliates of the registrant. No voting stock of registrant is held by non-affiliates. Indicate the number of shares outstanding of each of the registrants classes of common stock, as
of the latest practicable date. Class
    
    Outstanding at March 14, 2005Common stock, $1 par value
    
    1,000shares
 Documents Incorporated by Reference:
None The registrant meets the conditions set forth in General Instruction (I)(1)(a) and (b) of Form 10-K
and is therefore filing this Form 10-K with the reduced disclosure format.




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TABLE OF CONTENTS Heading
    
    PagePART IItem 1. BUSINESS
    
    
    1Item 2. PROPERTIES
    
    
    9Item 3. LEGAL PROCEEDINGS
    
    
    9Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS (Omitted)
    
    
    9PART IIItem 5. MARKET FOR REGISTRANTS COMMON EQUITY AND RELATED STOCK-HOLDER MATTERS
    
    
    10Item 6. SELECTED FINANCIAL DATA (Omitted)
    
    
    10Item 7. MANAGEMENTS NARRATIVE ANALYSIS OF THE RESULTS OF OPERATIONS
    
    
    10Item 7A. QUALITATIVE AND QUANTITATIVE DISCLOSURES ABOUT MARKET RISK
    
    
    16Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
    
    
    17Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
    
    
    40Item 9A. CONTROLS AND PROCEDURES
    
    
    40Item 9B. OTHER INFORMATION
    
    
    40PART IIIItem 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT (Omitted)
    
    
    40Item 11. EXECUTIVE COMPENSATION (Omitted)
    
    
    40Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT (Omitted)
    
    
    40Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS (Omitted)
    
    
    40Item 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
    
    
    40PART IVItem 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
    
    
    42Consent of Independent Registered Public Accounting FirmPower of Attorney with Certified ResolutionSection 302 Certification of Principal Executive OfficerSection 302 Certification of Principal Financial OfficerSection 906 Certification of Principal Executive Officer and Principal Financial Officer




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NORTHWEST PIPELINE CORPORATION FORM 10-K 
 PART I 
 Item 1. BUSINESS In this report, Northwest Pipeline Corporation (Northwest) is at times referred to in the
first person as we, us or our. GENERAL Northwest is a wholly-owned subsidiary of Williams Gas Pipeline Company, LLC (WGP). WGP is a
wholly-owned subsidiary of The Williams Companies, Inc. (Williams). Williams is a reporting entity
for 2004 under the Sarbanes-Oxley Act of 2002. Northwest is not an accelerated filer and therefore
not required to report in 2004 under Section 404 of the Sarbanes-Oxley Act of 2002. We are an interstate natural gas transportation company that owns and operates a natural gas
pipeline system extending from the San Juan Basin in northwestern New Mexico and southwestern
Colorado through the states of Colorado, Utah, Wyoming, Idaho, Oregon and Washington to a point on
the Canadian border near Sumas, Washington. We provide services for markets in California, New
Mexico, Colorado, Utah, Nevada, Wyoming, Idaho, Oregon and Washington directly or indirectly
through interconnections with other pipelines. Our principal business is the interstate
transportation of natural gas which is regulated by the Federal Energy Regulatory Commission
(FERC). PIPELINE SYSTEM AND CUSTOMERS Transportation and Storage At December 31, 2004, our system, having long term firm transportation agreements with peaking
capacity of approximately 3.4 MMDth* of gas per day, was composed of approximately 4,200 miles of
mainline and lateral transmission pipelines, and 42 transmission compressor stations having a
combined sea level-rated capacity of approximately 462,000 horsepower. In 2004, we served a total of 175 transportation and storage customers. Our transportation
customers include distribution companies, municipalities, interstate and intrastate pipelines, gas
marketers and direct industrial users. In 2004, our two largest customers were Puget Sound Energy,
Inc. and Northwest Natural Gas Co., which accounted for approximately 13.9 percent and 11.3
percent, respectively, of our total operating revenues. No other customer accounted for more than
10 percent of our total operating revenues in 2004. Our firm transportation and storage agreements
are generally long-term agreements with various expiration dates and account for the major portion
of our business. Additionally, we offer interruptible and short-term firm transportation services. No other interstate natural gas pipeline company presently provides significant service to our
primary gas consumer market area. However, competition with other interstate carriers exists for
expansion markets. Competition also exists with alternate fuels. Electricity and distillate fuel
oil are the primary alternate energy sources in the residential and commercial markets. In the
industrial markets, high sulfur residual fuel oil is the main alternate fuel source.   *
    
    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. -1-




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We believe that demand for natural gas in the Pacific Northwest will continue to increase and
the growing preference for natural gas in response to environmental concerns support future
expansions of our mainline capacity. Underground gas storage facilities enable us to balance daily receipts and deliveries and
provide storage services to certain major customers. We have a contract with a third party, under which gas storage services are provided to us in
an underground storage reservoir in the Clay Basin Field located in Daggett County, Utah. We are
authorized to utilize the Clay Basin Field at a seasonal storage level of 3.0 Bcf of working gas,
with a firm delivery capability of 25 MMcf of gas per day. We own a one-third interest in the Jackson Prairie underground storage facility located near
Chehalis, Washington, with the remaining interests owned by two of our distribution customers. Our
share of the firm seasonal storage service is 6.6 Bcf of working gas capacity and up to 283 MMcf
per day of peak day deliveries. Additionally, our share of the best-efforts delivery capacity is
50 MMcf per day. We also own and operate a liquefied natural gas (LNG) storage facility located near Plymouth,
Washington, which provides standby service for our customers during extreme peaks in demand. The
facility has a total LNG storage capacity equivalent to 2.3 Bcf of working gas, liquefaction
capability of 12 MMcf per day and regasification capability of 300 MMcf per day. Certain of our
major customers own the working gas stored at the LNG plant. 2003 Pipeline Breaks in Washington In December 2003, we received an Amended Corrective Action Order (ACAO) from the U.S.
Department of Transportations Office of Pipeline Safety (OPS) regarding a segment of one of our
natural gas pipelines in western Washington. The pipeline experienced two breaks in 2003 and we
subsequently idled the pipeline segment until its integrity could be assured. By June 2004 we had successfully completed our hydrostatic testing program and returned to
service 111 miles of the 268 miles of pipe affected by the ACAO. That effort has restored 131
MDth/day of the 360 MDth/day of idled capacity and is anticipated to be adequate to meet most
market conditions. To date our ability to serve the market demand has not been significantly
impacted. The restored facilities will be monitored and tested as necessary until they are ultimately
replaced. Through December 31, 2004, approximately $40 million had been spent on testing and
remediation, including $8.9 million related to one segment of pipe that we recently determined not
to return to service and was therefore written off in the second quarter of 2004. We estimate the
total testing and remediation costs will be between $40 million and $45 million. On October 4, 2004 we received a notice of probable violation (NOPV) from OPS. Under the
provisions of the NOPV, OPS has issued a preliminary civil penalty of $100,000 for exceeding the
pressure restriction on one of the segments covered under the original CAO. This penalty was
accrued in the third quarter of 2004. The incident occurred on July 15, 2003 and did not occur as
part of normal operations, but in preparation for running an internal inspection tool to test the
integrity of the line. The operating pressure dictated by the original CAO was exceeded for
approximately three hours due to the mechanical failure of an overpressure device and we
immediately reported the incident to the OPS. There was no impact on pipeline facilities, and no
additional sections of the pipeline were affected. Following the incident, new protocols were
adopted to ensure that a similar situation would not occur in the future. We requested a hearing
on the proposed OPS civil penalty, which was held in Denver, Colorado on December 15, 2004. OPS
will issue its decision in the near future. As required by OPS, we plan to replace the pipelines entire capacity by November 2006 to meet
long-term demands. We conducted a reverse open season to determine whether any existing customers
were willing to relinquish or reduce their capacity commitments to allow us to reduce the scope of
pipeline replacement facilities. That resulted in 13 MDth/day of capacity being relinquished and
incorporated into the replacement project. On November 29, 2004 we filed with the Federal Energy
Regulatory Commission a certificate application for the Capacity Replacement Project including
construction of approximately 79.5 miles of 36-inch pipeline and 10,760 net horsepower of
additional compression at two existing compressor stations and abandonment of approximately 268
miles of the existing 26-inch -2-




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pipeline. The estimated net cost of the Capacity Replacement Project included in the filing is
approximately $333 million. The majority of these costs will be spent in 2005 and 2006. We
anticipate filing a rate case to recover the capitalized costs relating to restoration and
replacement facilities following the in-service date of the replacement facilities. OPERATING STATISTICS The following table summarizes volumes and capacity for the periods indicated: Year Ended December 31,2004
    
    
    2003
    
    
    2002(In million dekatherms)Total Throughput
    
    
    650
    
    
    
    682
    
    
    
    729Average Daily Throughput Volumes
    
    
    1.8
    
    
    
    1.9
    
    
    
    2.0Average Daily Reserved Capacity Under Long-Term
Base Firm Contracts, excluding peak capacity
    
    
    2.5
    
    
    
    2.5
    
    
    
    2.3Average Daily Reserved Capacity Under Short-Term
Firm Contracts (1)
    
    
    .6
    
    
    
    .5
    
    
    
    .5
   (1)
    
    Includes additional capacity created from time to time through the installation of new
receipt or delivery points or the segmentation of existing mainline capacity. Such capacity
is generally marketed on a short-term firm basis. REGULATION We are subject to regulation by the FERC under the Natural Gas Act of 1938 (NGA) and under the
Natural Gas Policy Act of 1978, and, as such, our rates and charges for the transportation of
natural gas in interstate commerce, the extension, enlargement or abandonment of our jurisdictional
facilities, and our accounting, among other things, are subject to regulation. We hold
certificates of public convenience and necessity issued by the FERC authorizing ownership and
operation of all pipelines, facilities and properties considered jurisdictional for which
certificates are required under the NGA. We are also subject to the Natural Gas Pipeline Safety
Act of 1968, as amended by Title I of the Pipeline Safety Act of 1979, which regulates safety
requirements in the design, construction, operation and maintenance of interstate gas transmission
facilities. Order Nos. 2004, et seq. (Docket No. RM01-10-000)On November 25, 2003, the FERC issued Order
No. 2004, adopting uniform standards of conduct for transmission providers. The proposed rules
define transmission providers as interstate natural gas pipelines and public utilities that own,
operate or control electric transmission facilities. The standards regulate the conduct of
transmission providers with their energy affiliates. In Order No. 2004, the FERC defined energy
affiliates broadly, but in Order No. 2004-A, issued on April 16, 2004, the FERC, among other
things, clarified the definition of energy affiliates in a manner that narrowed its scope. On
August 2, 2004, the FERC issued Order No. 2004-B, which, among other things, further clarified the
definition of energy affiliates and deferred the implementation date for the new standards of
conduct until September 22, 2004. We posted on our electronic bulletin board our procedures
implementing the requirements of Order No. 2004 on September 22, 2004, in compliance with the new
standards of conduct. On December 21, 2004, the FERC issued Order No. 2004-C, which, among other
things, further clarified Order No. 2004-B. Certain parties have sought rehearing of Order No.
2004-C, and other parties have filed petitions for review of the FERCs Order Nos. 2004, et seq. -3-




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OWNERSHIP OF PROPERTY Our system is owned in fee simple. However, a substantial portion of our system is
constructed and maintained pursuant to rights-of-way, easements, permits, licenses or consents on
and across properties owned by others. Our compressor stations, with associated facilities, are
located in whole or in part upon lands owned by us and upon sites held under leases or permits
issued or approved by public authorities. The LNG facility is located on lands owned in fee simple
by us. Various credit arrangements restrict the sale or disposal of a major portion of our
pipeline system. FORWARD LOOKING STATEMENTS/RISK FACTORS AND CAUTIONARY STATEMENT FOR
PURPOSES OF THE SAFE HARBOR PROVISIONS OF
THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995 Certain matters discussed in this annual report, excluding historical information, include
forward-looking statements  statements that discuss our expected future results based on current
and pending business operations. We make these forward-looking statements in reliance on the safe
harbor protections provided under the Private Securities Litigation Reform Act of 1995. All statements, other than statements of historical facts, included in this Form 10-K which
address activities, events or developments which we expect, believe or anticipate will or may occur
in the future are forward-looking statements. Forward-looking statements can be identified by words
such as anticipates, believes, could, continues, estimates, expects,  forecasts,
might, planned, potential, projects, scheduled or similar expressions. These
forward-looking statements include, among others, such things as:  
    amounts and nature of future capital expenditures;
    expansion and growth of our business and operations;
    business strategy;
    cash flow from operations; and
    power and gas prices and demand. These statements are based on certain assumptions and analysis made by us in light of our
experience and our perception of historical trends, current conditions and expected future
developments as well as other factors we believe are appropriate in the circumstances. Although we
believe these forward-looking statements are based on reasonable assumptions, statements made
regarding future results are subject to a number of assumptions, uncertainties and risks that could
cause future results to be materially different from the results stated or implied in this
document. These risks and uncertainties include:  
    general economic and market conditions;
    changes in laws or regulations;
    continued availability of capital and financing;
    recovery of amounts through rates; and
    other factors, most of which are beyond our control. See the Risk Factors section of this report for a more detailed discussion of these risks
and uncertainties. -4-




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When considering forward-looking statements, one should keep in mind the risk factors
described in Rick Factors below. The risk factors could cause our actual results to differ
materially from those contained in any forward-looking statement. We disclaim any obligation to
update the above list or to announce publicly the result of any revisions to any of the
forward-looking statements to reflect future events or developments. RISK FACTORS You should carefully consider the following risk factors in addition to the other information
in this annual report. Each of these factors could adversely affect our business, operating
results, and financial condition as well as adversely affect the value of an investment in our
securities. Risks related to the regulation of our business Our gas sales, transmission, and storage operations are subject to government regulations and rate
proceedings that could have an adverse impact on our ability to recover the costs of operating our
pipeline facilities. Our interstate transmission and storage operations are subject to the FERCs rules and
regulations in accordance with the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978.
The FERCs regulatory authority extends to:  
    transportation and sale for resale of natural gas in interstate commerce;
    rates and charges;
    construction;
    acquisition, extension or abandonment of services or facilities;
    accounts and records;
    depreciation and amortization policies; and
    operating terms and conditions of service. The FERC has taken certain actions to strengthen market forces in the natural gas pipeline
industry that have led to increased competition throughout the industry. In a number of key
markets, we are facing competitive pressure from other major pipeline systems, enabling local
distribution companies and end users to choose a transmission provider based on economic and other
considerations. Our ability to compete in the natural gas pipeline industry is impacted by our
ability to offer competitively priced services and to successfully implement efficient and
effective operational systems that must also meet applicable regulatory requirements. Risk affecting our strategy and financing needs Because we no longer maintain investment grade credit ratings, our counterparties have required us
to provide higher amounts of credit support which raises our cost of doing business. Our transactions will require greater credit assurances, both to be given from, and received
by, us to satisfy credit support requirements. Additionally, certain market disruptions or a
further downgrade of our credit rating might further increase our cost of borrowing or further
impair our ability to access one or any of the capital markets. Such disruptions could include:  
    further economic downturns;
    capital market conditions generally;
    market prices for electricity and natural gas; -5-




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
    terrorist attacks or threatened attacks on our facilities or those of other energy
companies; or
    the overall health of the energy industry, including the bankruptcy or insolvency of
other energy companies. Despite Williams restructuring efforts, we may not attain investment grade ratings. Credit rating agencies perform independent analysis when assigning credit ratings. Given the
significant changes in capital markets and the energy industry over the last few years, credit
rating agencies continue to review the criteria for attaining investment grade ratings and make
changes to those criteria from time to time. Williams goal is to attain investment grade ratios.
However, there is no guarantee that the credit rating agencies will assign us investment grade
ratings even if we meet or exceed their criteria for investment grade ratios. Our debt agreements impose restrictions on us that may adversely affect our ability to operate our
business. Our debt agreements contain covenants that restrict, among other things, our ability to create
liens, sell assets, make certain distributions, and incur additional debt. In addition, our debt
agreements contain, and those we enter into in the future may contain, financial covenants and
other limitations with which we will need to comply. Our ability to comply with these covenants
may be affected by many events beyond our control, and we cannot assure you that our future
operating results will be sufficient to comply with the covenants or, in the event of a default
under any of our debt agreements, to remedy that default. Although we are currently in compliance with our financial and other covenants in our debt
agreements, our failure to comply with such financial or other covenants could result in events of
default. Upon the occurrence of an event of default under our debt agreements, the lenders could
elect to declare all amounts outstanding under a particular facility to be immediately due and
payable and terminate all commitments, if any, to extend further credit. By reason of
cross-default or cross-acceleration provisions in certain of our debt agreements, such a default or
acceleration could have a wider impact on our liquidity than might otherwise arise from a default
or acceleration of a single debt instrument. If the lenders under any of our debt agreements
accelerate the maturity of any loans or other debt outstanding, we may not have sufficient
liquidity to repay amounts outstanding under such debt agreements. Risks related to outsourcing of non-core support services. Institutional knowledge represented by former Williams employees now employed by Williams
outsourcing service provider might not be adequately preserved. Due to the large number of former Williams employees who migrated to an outsourcing provider,
access to significant amount of internal historical knowledge and expertise could become
unavailable to us, particularly if knowledge transfer initiatives are delayed or ineffective. Failure of the outsourcing relationship might negatively impact our ability to conduct our
business. Some studies indicate a high failure rate of outsourcing relationships. Although Williams has
taken steps to build a cooperative and mutually beneficial relationship with its outsourcing
providers, a failure of all or part of these relationships could lead to loss of institutional
knowledge and interruption of services necessary for us to be able to conduct our business. Williams ability to receive services from outsourcing provider locations outside of the United
States might be impacted by cultural differences, political instability, or unanticipated
regulatory requirements in jurisdictions outside the United States. Certain information technology application development, human resources, and help desk
services that are currently provided by an outsourcer will be relocated to service centers operated
by -6-




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Williams outsourcing provider outside of the United States during 2005. The economic and
political conditions in certain countries from which Williams outsourcing providers may provide
services to us present similar risks of business operations located outside of the United States,
including risks of interruption of business, war expropriation, nationalization, renegotiation,
trade sanctions or nullification of existing contracts and changes in law or tax policy, that are
greater than in the United States. Risks related to environmental matters We could incur material losses if we are held liable for the environmental condition of any of our
assets, which could include losses that exceed our current expectations. We are generally responsible for all on-site liabilities associated with the environmental
condition of our facilities and assets, which we have acquired or developed, regardless of when the
liabilities arose and whether they are known or unknown. In addition, in connection with certain
acquisitions and sales of assets, we might obtain, or be required to provide, indemnification
against certain environmental liabilities. If we incur a material liability, or the other party to
a transaction fails to meet its indemnification obligations to us, we could suffer material losses.
If a purchaser of a divested asset incurs a liability due to the environmental condition of the
divested asset, we may have a contractual obligation to indemnify that purchaser or otherwise
retain responsibility for the environmental condition of the divested asset. We may also have
liability for the environmental condition of divested assets under applicable federal or state laws
and regulations. Changes to applicable laws and regulations or changes to their interpretation may
increase our liability. Environmental conditions of divested assets may not be covered by
insurance. Even if environmental conditions could be covered by insurance, policy conditions may
not be met. We make assumptions and develop expectations about possible liability related to environmental
conditions based on current laws and regulations and current interpretations of those laws and
regulations. If the interpretation of laws or regulations, or the laws and regulations themselves,
change, our assumptions may change. Our assumptions and expectations are also based on available
information. If more information becomes available to us, our assumptions may change. Any of these
changes may result in not only increased risk related to one or more of our assets, but material
losses in excess of current estimates. Environmental regulation and liability relating to our business will be subject to environmental
legislation in all jurisdictions in which we operate, and any changes in such legislation could
negatively affect our results of operations. Our operations are subject to extensive environmental regulation pursuant to a variety of
federal, state and municipal laws and regulations. Such environmental legislation imposes, among
other things, restrictions, liabilities and obligations in connection with the generation,
handling, use, storage, transportation, treatment and disposal of hazardous substances and waste
and in connection with spills, releases and emissions of various substances into the environment.
Environmental legislation also requires that our facilities, sites and other properties associated
with our operations be operated, maintained, abandoned and reclaimed to the satisfaction of
applicable regulatory authorities. Existing environmental regulations could also be revised or
reinterpreted, new laws and regulations could be adopted or become applicable to us, or our
facilities, and future changes in environmental laws and regulations could occur. The federal
government and several states recently have proposed increased environmental regulation of many
industrial activities, including increased regulation of air quality, water quality and solid waste
management. Compliance with environmental legislation will require significant expenditures, including
expenditures for compliance with the Clean Air Act and similar legislation, for clean up costs and
damages arising out of contaminated properties, and for failure to comply with environmental
legislation and regulations which might result in the imposition of fines and penalties. The steps
we take to bring certain of our facilities into compliance could be prohibitively expensive, and we
might be required to shut down, divest, or alter the operation of those facilities, which might
cause us to incur losses. Further, our regulatory rate structure and our contracts with customers might not necessarily
allow us to recover costs incurred to comply with new environmental regulations. Also, we might not
be able to obtain or maintain from time to time all required environmental regulatory approvals for
certain development projects. If there is a delay in obtaining any required environmental
regulatory approvals or if -7-




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we fail to obtain and comply with them, the operation of our facilities could be prevented or
become subject to additional costs. Should we fail to comply with all applicable environmental
laws, we might be subject to penalties and fines imposed by regulatory authorities. Although we do
not expect that the costs of complying with current environmental legislation will have a material
adverse effect on our financial condition or results of operations, no assurance can be made that
the costs of complying with environmental legislation in the future will not have such an effect. RISKS RELATING TO ACCOUNTING STANDARDS Potential changes in accounting standards might cause us to revise our financial results and
disclosure in the future. Accounting irregularities discovered in the past few years in various industries have forced
regulators and legislators to take a renewed look at accounting practices, financial disclosures,
and companies relationships with their independent registered public accounting firms and other
accounting practices. Because it is still unclear what laws or regulations will ultimately develop,
we cannot predict the ultimate impact of any future changes in accounting regulations or practices
in general with respect to public companies or the energy industry or in our operations
specifically. In addition, the Financial Accounting Standards Board (FASB), the FERC or the
Securities and Exchange Commission (SEC) could enact new or revised accounting standards that might
impact how we are required to record revenues, expenses, assets and liabilities. RISKS RELATING TO OUR INDUSTRY The long-term financial condition of our gas transmission business is dependent on the continued
availability of natural gas reserves. The development of additional natural gas reserves requires significant capital expenditures
by others for exploration and development drilling and the installation of production, gathering,
storage, transportation and other facilities that permit natural gas to be produced and delivered
to our pipeline system. Low prices for natural gas, regulatory limitations, or the lack of
available capital for these projects could adversely affect the development of additional reserves
and production, gathering, storage and pipeline transmission and import and export of natural gas
supplies. Additional natural gas reserves might not be developed in commercial quantities and in
sufficient amounts to fill the capacities of our gathering and transmission pipeline facilities. Gas transmission activities involve numerous risks that might result in accidents and other
operating risks and costs. There are inherent in our gas transmission properties a variety of hazards and operating
risks, such as leaks, explosions and mechanical problems that could cause substantial financial
losses. In addition, these risks could result in loss of human life, significant damage to
property, environmental pollution, impairment of our operations and substantial losses to us. In
accordance with customary industry practice, we maintain insurance against some, but not all, of
these risks and losses. The occurrence of any of these events not fully covered by insurance could
have a material adverse effect on our financial position and results of operations. The location of
pipelines near populated areas, including residential areas, commercial business centers and
industrial sites could increase the level of damages resulting from these risks. We implemented an
Integrity Management Plan (IMP) in December 2004, as required by the Pipeline Safety Improvement
Act. As part of the IMP, we identified High Consequence Areas (HCA) through which our pipeline
runs. A HCA is an area where the potential consequence of a gas pipeline accident may be
significant or do considerable harm to people or property. Certain segments of our pipeline run
through HCAs. An event such as those described above in an HCA not only could cause considerable
harm to people or property, but could have a material adverse effect on our financial position and
results of operations, particularly if the event is not fully covered by insurance. Accidents or other operating risks could further result in loss of service available to our
customers. Such circumstances could adversely impact our ability to meet contractual obligation and
retain customers. -8-




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OTHER RISKS The threat of terrorist activities and the potential for continued military and other actions could
adversely affect our business. The continued threat of terrorism and the impact of continued military and other action by the
United States and its allies might lead to increased political, economic and financial market
instability and volatility in prices for natural gas, which could affect the market for our gas
transmission operations. In addition, future acts of terrorism could be directed against companies
operating in the United States, and it has been reported that terrorists might be targeting
domestic energy facilities. While we are taking steps that we believe are appropriate to increase
the security of our energy assets, there is no assurance that we can completely secure our assets
or completely protect them against a terrorist attack. These developments have subjected our
operations to increased risks and, depending on their ultimate magnitude, could have a material
adverse effect on our business. In particular, we might experience increased capital or operating
costs to implement increased security for our energy assets. Our assets and operations can be affected by weather and other natural phenomena. Our assets and operations can be adversely affected by hurricanes, earthquakes, tornadoes and
other natural phenomena and weather conditions including extreme temperatures, making it more
difficult for us to realize the historic rates of return associated with these assets and
operations. 
 Item 2. PROPERTIES See Item 1. Business. 
 Item 3. LEGAL PROCEEDINGS There are no material pending legal proceedings. We are subject to ordinary routine
litigation incidental to our business. 
 Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS Since we meet the conditions set forth in General Instruction (I)(1)(a) and (b) of Form 10-K,
this information is omitted. -9-




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PART II 
 Item 5. MARKET FOR REGISTRANTS COMMON EQUITY AND RELATED STOCKHOLDER MATTERS We are wholly-owned by WGP, a wholly-owned subsidiary of Williams; therefore, our common stock
is not publicly traded. We paid $60 million in cash dividends in 2004 and paid no cash dividends on common stock in
2003. 
 Item 6. SELECTED FINANCIAL DATA Since we meet the conditions set forth in General Instruction (I)(1)(a) and (b) of Form 10-K,
this information is omitted. 
 Item 7. MANAGEMENTS NARRATIVE ANALYSIS OF THE RESULTS OF OPERATIONS GENERAL The following discussion and analysis of results of operations, financial condition and
liquidity should be read in conjunction with the financial statements and notes thereto included
within Item 8. CRITICAL ACCOUNTING POLICIES Use of Estimates The preparation of financial statements in conformity with accounting principles generally
accepted in the United States requires management to make estimates and assumptions that affect the
amounts reported in the financial statements and accompanying notes. Actual results could differ
from those estimates. Regulatory Accounting We are regulated by the FERC. Statement of Financial Accounting Standards (SFAS) No. 71,
Accounting for the Effects of Certain Types of Regulation, provides that rate-regulated public
utilities account for and report regulatory assets and liabilities consistent with the economic
effect of the way in which regulators establish rates if the rates established are designed to
recover the costs of providing the regulated service and if the competitive environment makes it
reasonable to assume that such rates can be charged and collected. Accounting for businesses that
are regulated and apply the provisions of SFAS No. 71 can differ from the accounting requirements
for non-regulated businesses. Transactions that are recorded differently as a result of regulatory
accounting requirements include the capitalization of an equity return component on regulated
capital projects, employee related benefits, levelized depreciation and other costs and taxes
included in, or expected to be included in, future rates. As a rate-regulated entity, our
management has determined that it is appropriate to apply the accounting prescribed by SFAS No. 71,
and accordingly, the accompanying financial statements include the effects of the types of
transactions described above that result from regulatory accounting requirements. At December 31,
2004, we had approximately $22.4 million of regulatory liabilities included in Deferred Credits and
Other Noncurrent Liabilities on the accompanying Balance Sheet. At December 31, 2003, we had
approximately $18.4 million of regulatory liabilities included in Deferred Credits and Other
Noncurrent Liabilities on the accompanying Balance Sheet. Revenue Subject to Refund FERC regulations promulgate policies and procedures, which govern a process to establish the
rates that we are permitted to charge customers for natural gas services, including the
transportation and -10-




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storage of natural gas. Key determinants in the ratemaking process are (i) costs of providing
service, including depreciation expense, (ii) allowed rate of return, including the equity
component of a pipelines capital structure and related income taxes, and (iii) volume throughput
assumptions. As a result of the ratemaking process, certain revenues we collect may be subject to possible
refunds upon final orders in pending rate proceedings with the FERC. We record estimates of rate
refund liabilities considering our and other third-party regulatory proceedings, advice of counsel
and estimated total exposure, as discounted and risk weighted, as well as collection and other
risks. At December 31, 2004, we have no pending regulatory proceedings and no potential rate
refunds. Contingent Liabilities We record liabilities for estimated loss contingencies when we assess that a loss is probable
and the amount of the loss can be reasonably estimated. Revisions to contingent liabilities are
reflected in income in the period in which new or different facts or information become known or
circumstances change that affect the previous assumptions with respect to the likelihood or amount
of loss. Liabilities for contingent losses are based upon our managements assumptions and
estimates and advice of legal counsel or other third parties regarding the probable outcomes of the
matter. Changes in our assumptions and estimates or outcomes different from our current
assumptions and estimates could materially affect future results of operations for any particular
quarterly or annual period. Impairment of Long-Lived Assets We evaluate long-lived assets for impairment when events or changes in circumstances indicate,
in managements judgment, that the carrying value of such assets may not be recoverable. When such
a determination has been made, managements estimate of undiscounted future cash flows attributable
to the assets is compared to the carrying value of the assets to determine whether an impairment
has occurred. If an impairment of the carrying value has occurred, the amount of the impairment
recognized in the financial statements is determined by estimating the fair value of the assets and
recording a loss for the amount that the carrying value exceeds the estimated fair value. Judgments and assumptions are inherent in our managements estimate of undiscounted future
cash flows used to determine recoverability of an asset and the estimate of an assets fair value
used to calculate the amount of impairment to recognize. The use of alternate judgments and/or
assumptions could result in the recognition of different levels of impairment charges in the
financial statements. Proposed FERC Accounting Guidance In November 2004, the FERC issued proposed accounting guidance on accounting for pipeline
assessment costs. If adopted, we may be required to expense certain assessment costs that have
historically been capitalized. For 2005, the estimated impact of this proposal would be additional
expense of $8 million to $13 million. 2003 PIPELINE BREAKS Reference is made to Item 1. Business  2003 Pipeline Breaks in Washington on page 2. RESULTS OF OPERATIONS ANALYSIS OF FINANCIAL RESULTS This analysis discusses financial results of our operations for the years 2002 through 2004.
Variances due to changes in price and volume have little impact on revenues, because under our rate
design methodology, the majority of overall cost of service is recovered through firm capacity
reservation charges in our transportation rates. -11-




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2004 COMPARED TO 2003 Operating revenues increased $10.5 million, or 3 percent, due primarily to increased
transportation revenues of $30.2 million from the incremental Evergreen project placed in service
in late 2003, offset by lower firm and interruptible transportation of $12.8 million primarily due
to a decrease in basin price differentials, lower revenue of $4.7 million related to reduced equity
AFUDC resulting from the decreased capital construction program in 2004, and $1.0 million of lower
rental income due to fewer building tenants. Pipelines transportation service accounted for 96 percent and 94 percent of operating
revenues for the years ended December 31, 2004 and 2003, respectively. Additionally, gas storage
service accounted for 3 percent of operating revenues for each of the years ended December 31, 2004
and 2003, respectively. Operating expenses decreased $4.0 million, or 2 percent. This reduction was due primarily to
the write-off of capitalized software development costs of $25.6 million associated with a service
delivery system included in 2003 operating costs, which was mostly offset by the following
increases during 2004: an $8.9 million write-off of previously capitalized costs incurred on an
idled segment of our system that will not be returned to service; a $6.0 million increase in
general corporate overhead expense due to an increased share of allocated costs resulting from
changes within Williams; a $1.3 million increase in charges from Williams and WGP related primarily
to shared service charges, third-party consultation and administrative costs associated with the
Sarbanes-Oxley Act compliance activities, and efforts at Williams to evaluate and implement certain
cost reduction strategies through internal initiatives and outsourcing of certain services; a $4.6
million increase in labor and other costs resulting primarily from lower levels charged to
construction in 2004; and a $1.6 million increase in outside contractor services as a result of
various maintenance projects performed during 2004. Depreciation expense decreased by $1.1 million
resulting from a $5.4 million adjustment to correct an error related to over depreciation of
certain in-house developed system software and other general plant issues, partially offset by
additional depreciation expense due to the recent Evergreen and Rockies construction projects
placed in service during the fourth quarter of 2003 (See Property, Plant and Equipment in Note 1).
Other Taxes decreased by $1.7 million due to a $3.8 million adjustment to ad valorem taxes in 2003,
partially offset by higher ad valorem taxes resulting from property additions. Operating income increased $14.5 million, or 10 percent, due to the higher operating revenues
and lower operating costs discussed above. Other income decreased $4.2 million, or 43 percent, primarily due to a $7.8 million decrease
in AFUDC resulting from fewer construction projects in 2004, offset by a $1.8 million increase in
interest resulting from higher average levels of advances to affiliates. Interest on long-term debt increased $1.6 million due to the March 4, 2003, $175 million debt
issuance of 8.125 percent senior notes due 2010. Allowance for borrowed funds used during
construction decreased $3.1 million due to the decrease in construction resulting from the
completion of large projects in the fourth quarter of 2003. 2003 COMPARED TO 2002 Operating revenues increased $30.1 million, or 10 percent, due primarily to increased facility
charge revenues of $17.3 million from incremental projects placed in service in late 2002, new
revenues of $9.9 million from the Evergreen Project that was placed in service on October 1, 2003
and higher short term firm transportation revenues of $6.5 million primarily due to the execution
of several maximum rate contracts during the second quarter of 2003 with primary terms that extend
through July 2003, October 2003 and April 2004. These increases were partially offset by a
decrease in firm transportation of approximately $3.7 million. Our transportation service accounted for 94 percent and 95 percent of operating revenues for
the years ended December 31, 2003 and 2002, respectively. Additionally, 3 percent of operating
revenues represented gas storage service in each of the years ended December 31, 2003 and 2002. Operating expenses increased $29.8 million, or 19 percent, due primarily to a write-off of
capitalized software development costs of $25.6 million associated with a service delivery system.
Subsequent to the implementation of this system at Transcontinental Gas Pipe Line Corporation -12-




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(Transco), a subsidiary of WGP, in the second quarter of 2003 and a determination of the unique
and additional programming requirements that would be needed to complete the system for us, our
management determined that the system would not be implemented. Depreciation expense increased
$7.7 million due primarily to the increase in property resulting from completion of recent
construction projects. Ad valorem taxes increased $6.5 million primarily due to the recently
completed construction projects and other changes in state taxes. These increases were partially
offset by the establishment of regulatory assets and the related regulatory credits approved by the
FERC of approximately $6.4 million for the Evergreen Project. (Reference is made to the Property,
Plant and Equipment policy in Note 1 of the Notes to Financial Statements for information about
regulatory assets and regulatory credits.) A $3.9 million expense in 2002 for an enhanced benefit
early retirement option offered to certain Williams employee groups also reduced the increase in
operating expenses. Interest on long-term debt increased $11.6 million due to the March 4, 2003, $175 million debt
issuance of 8.125 percent senior notes due 2010. EFFECT OF INFLATION We have generally experienced increased costs in recent years due to the effect of inflation
on the cost of labor, materials and supplies, and property, plant and equipment. A portion of the
increased labor and materials and supplies cost can directly affect income through increased
operating and maintenance costs. The cumulative impact of inflation over a number of years has
resulted in increased costs for current replacement of productive facilities. The majority of our
property, plant and equipment and materials and supplies is subject to ratemaking treatment, and
under current FERC practices, recovery is limited to historical costs. While amounts in excess of
historical cost are not recoverable under current FERC practices, we believe that we will be
allowed to recover and earn a return based on the increased actual costs incurred when existing
facilities are replaced. Cost-based regulation along with competition and other market factors
limit our ability to price services or products to ensure recovery of inflations effect on costs. CAPITAL RESOURCES AND LIQUIDITY METHOD OF FINANCING We fund our capital requirements with cash flows from operating activities, by repayments of
funds advanced to Williams, accessing capital markets, and, if required, borrowings under the
Credit Agreement and advances from Williams. We have an effective registration statement on file with the SEC. At December 31, 2004,
approximately $150 million of shelf availability remains under this registration statement, which
may be used to issue debt securities. At December 31, 2004, the ability to utilize this
registration statement was restricted by certain covenants of Williams debt agreements. Interest
rates, market conditions, and industry conditions will affect amounts raised, if any, in the
capital markets. We believe any additional financing arrangements, if required, can be obtained
from the capital markets on terms that are commensurate with our current credit ratings. On May 3, 2004, Williams entered into a new three-year $1 billion secured revolving credit
facility (Credit Agreement), which is available for borrowings and letters of credit. In August of
2004, Williams expanded the credit facility by an additional $275 million. At December 31, 2004,
letters of credit totaling $422 million, none of which are associated with us, have been issued by
the participating institutions under this facility and no revolving credit loans were outstanding.
Northwest and Transcontinental Gas Pipe Line Corporation, subsidiaries of WGP, have access to $400
million each under the facility. The new facility is secured by certain Williams midstream
assets. Additionally, the facility is guaranteed by WGP. Interest is calculated based on a choice
of two methods: a fluctuating rate equal to the facilitating banks base rate plus an applicable
margin or a periodic fixed rate equal to the London Interbank Offered Rate (LIBOR) plus an
applicable margin. Williams is also required to pay a commitment fee (currently 0.375 percent
annually) based on the unused portion of the facility. The applicable margins and commitment fee
are based on the relevant borrowers senior unsecured long-term debt ratings. Upon entering into
the new $1 billion secured revolving credit facility on May 3, 2004, Williams terminated the $800
million revolving and letter of credit facility. -13-




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As a participant in Williams cash management program, we make advances to and receive
advances from Williams. At December 31, 2004, the advances due to us by Williams totaled $50
million. The advances are represented by demand notes. Effective September 2003, the interest
rate on intercompany demand notes is based upon the weighted average cost of Williams debt
outstanding at the end of each quarter. Previously, the interest rate on intercompany demand notes
was based on the LIBOR plus an applicable margin. Williams has indicated that it currently
believes that it will continue to have the financial resources and liquidity to repay these
advances. Prior to April 29, 2004, the advances were made to and received from our parent company,
WGP. WILLIAMS RECENT EVENTS In February 2003, Williams outlined its planned business strategy in response to the events
that significantly impacted the energy sector and Williams during late 2001 and 2002. The plan
focused upon migrating to an integrated natural gas business comprised of a strong, but smaller
portfolio of natural gas businesses, reducing debt and increasing Williams liquidity through
assets sales, strategic levels of financing and reductions in operating costs. The plan was
designed to address near-term and medium-term debt and liquidity issues, to de-leverage Williams
with the objective of returning to investment grade status and to develop a balance sheet capable
of supporting and ultimately growing its remaining businesses. A component of Williams plan was to
reduce the risk and liquidity requirements of its power segment while realizing the value of its
power portfolio. In 2004, Williams continued to execute certain components of the plan, and substantially
completed its plan as outlined in February 2003. Williams results for 2004 include the following.  
    Completion of planned asset sales, which resulted in proceeds of approximately
$877.8 million.
    Replacement of Williams cash-collateralized letter of credit and revolver facility
with facilities that do not encumber cash.
    Significant debt reduction of approximately $4 billion through scheduled maturities
and early redemptions.
    On June 1, 2004, Williams announced an agreement with IBM Business Consulting
Services (IBM) to aid in transforming and managing certain areas of Williams
accounting, finance, and human resources processes. Under the agreement, IBM will also
manage key aspects of Williams information technology, including enterprise wide
infrastructure and application development. The 7 1/2 year agreement began July 1, 2004,
and is expected to reduce costs in these areas while maintaining a high quality of
service. In September 2004, Williams Board of Directors approved the decision to retain Williams power
business and end its efforts to exit that business. Williams strategy is to continue managing this
business to minimize financial risk, maximize cash flow and meet contractual commitments. Williams plan for 2005 includes the following objectives:  
    increase focus and disciplined investments in the natural gas businesses;
    continue to steadily improve credit ratios and ratings with the goal of achieving
investment grade ratios;
    continue to reduce risk and liquidity requirements while maximizing cash flow in its
power segment; and
    maintain a liquidity from cash and revolving credit facilities of at least $1
billion. CREDIT RATINGS We have no guarantees of off-balance sheet debt to third parties and maintain no debt
obligations that contain provisions requiring accelerated payment of the related obligations in the
event of specified levels of declines in Williams or our credit ratings given by Moodys Investors
Service, Standard and Poors and Fitch Ratings. -14-




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In the fourth quarter of 2004, Moodys Investors Service and Fitch Ratings raised the
credit ratings on our senior unsecured long-term debt as shown below. The rating given by Standard
& Poors is B+, and has remained constant during 2004. Moodys Investors Service
    
    B1 to Ba2Fitch Ratings
    
    BB to BB+
 Currently, all of the rating agencies have our credit ratings evaluated as stable outlook. CAPITAL EXPENDITURES Our expenditures for property, plant and equipment additions were $102.2 million, $294.5
million and $181.8 million for 2004, 2003 and 2002, respectively. We anticipate 2005 capital
expenditures will be between $135 million and $160 million, all of which will be for maintenance
capital expenditures and other non-expansion related items including expenditures required for the
26-inch pipeline restoration and the Pipeline Safety Improvement Act of 2002. The remaining
expenditures required to restore the 26-inch pipeline break are planned for 2006. (Reference is
made to Item 1. Business  2003 Pipeline Breaks in Washington on page 2.) We anticipate filing a
rate case to recover these costs coincident with the in-service date of the facilities. OTHER Contractual Obligations The table below summarizes the maturity dates of the more significant contractual obligations
and commitments by period (in millions of dollars). 2005
    
    
    2006 - 2007
    
    
    2008  2009
    
    
    Thereafter
    
    
    TotalLong-term debt, including
current portion:Principal
    
    $
    7.5
    
    
    $
    260.4
    
    
    $
    0
    
    
    $
    260.0
    
    
    $
    527.9Interest
    
    
    38.4
    
    
    
    74.9
    
    
    
    40.6
    
    
    
    104.0
    
    
    
    257.9Operating leases
    
    
    8.8
    
    
    
    12.8
    
    
    
    12.7
    
    
    
    
    
    
    
    34.3Purchase Obligations:Natural gas purchase,
storage and
transportation
    
    
    15.4
    
    
    
    5.4
    
    
    
    4.8
    
    
    
    
    
    
    
    25.6Other
    
    
    .4
    
    
    
    .7
    
    
    
    .4
    
    
    
    .8
    
    
    
    2.3Total
    
    $
    70.5
    
    
    $
    354.2
    
    
    $
    58.5
    
    
    $
    364.8
    
    
    $
    848.0
 Regulatory Proceedings Reference is made to Note 2 of the Notes to Financial Statements for information about
regulatory and business developments, which cause operating and financial uncertainties. CONCLUSION Although no assurances can be given, we currently believe that the aggregate of cash flows
from operating activities, supplemented, when necessary, by repayments of funds advanced to
Williams, advances or capital contributions from Williams and borrowings under the Credit Agreement
will provide us with sufficient liquidity to meet our capital requirements. When necessary, we also
expect to access public and private markets on terms commensurate with our current credit ratings
to finance our capital requirements. -15-




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SUBSEQUENT EVENT Duke Energy Trading and Marketing, LLC (Duke) has given notice to terminate its firm
transportation agreement related to the Grays Harbor Lateral effective December 31, 2004, and pay
us a lump sum amount based on the remaining net book value of the lateral facilities and related
income taxes. In January 2005, Duke paid approximately $94 million towards this lump sum amount
and disputed a portion of the lump sum amount requested by us. As of March 14, 2005, the final
amount has not been agreed upon by Duke and us. However, based upon the payment already made, we
do not anticipate any adverse impact to our results of operations or financial position in 2005.
The monthly revenues from the Grays Harbor transportation agreement with Duke, which was terminated
as of December 31, 2004, were approximately $1.6 million. 
 Item 7A. QUALITATIVE AND QUANTITATIVE DISCLOSURES ABOUT MARKET RISK Interest Rate Risk Our interest rate risk exposure is limited to its long-term debt. All interest rates on
long-term debt are fixed in nature. The following table provides information about our long-term debt, including current
maturities, as of December 31, 2004. The table presents principle cash flows (at face value) and
weighted-average interest rates by expected maturity dates. December 31, 2004 Expected Maturity Date2005

    2006
    2007
    2008
    2009
    Thereafter
    Total
    Fair Value(millions of dollars)Long-term debt,
including current
portion:Fixed rate
    
    $
    7.5
    
    
    $
    7.5
    
    
    $
    252.9
    
    
    $
    
    
    
    $
    
    
    
    $
    260.0
    
    
    $
    527.9
    
    
    $
    562.2Interest rate
    
    
    7.3
    %
    
    
    7.2
    %
    
    
    7.3
    %
    
    
    7.8
    %
    
    
    7.8
    %
    
    
    7.4
    %
 -16-




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##### Table of Contents



Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA INDEX TO FINANCIAL STATEMENTS PageReport of independent registered public accounting firm
    
    18Statement of income for the years ended
December 31, 2004, 2003 and 2002
    
    19Balance sheet at December 31, 2004 and 2003
    
    20Statement of common stockholders equity for the years ended
December 31, 2004, 2003 and 2002
    
    22Statement of comprehensive income for the years ended
December 31, 2004, 2003, and 2002
    
    23Statement of cash flows for the years ended
December 31, 2004, 2003 and 2002
    
    24Notes to financial statements
    
    25
 -17-




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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM The Board of Directors
Northwest Pipeline Corporation We have audited the accompanying balance sheets of Northwest Pipeline Corporation as of
December 31, 2004 and 2003, and the related statements of income, common stockholders equity,
comprehensive income and cash flows for each of the three years in the period ended December 31,
2004. Our audits also included the financial statement schedule listed in the Index at Item 15(a).
These financial statements and schedules are the responsibility of the Companys management. Our
responsibility is to express an opinion on these financial statements and schedules based on our
audits. We conducted our audits in accordance with the standards of the Public Company Accounting
Oversight Board (United States). Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether the financial statements are free of material
misstatement. We were not engaged to perform an audit of the Companys internal control over
financial reporting. Our audit included consideration of internal control over financial reporting
as a basis for designing audit procedures that are appropriate in the circumstances, but not for
the purpose of expressing an opinion on the effectiveness of the Companys internal control over
financial reporting. Accordingly, we express no such opinion. An audit also includes examining,
on a test basis, evidence supporting the amounts and disclosures in the financial statements,
assessing the accounting principles used and significant estimates made by management, and
evaluating the overall financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion. In our opinion, the financial statements referred to above present fairly, in all material
respects, the financial position of Northwest Pipeline Corporation at December 31, 2004 and 2003,
and the results of its operations and its cash flows for each of the three years in the period
ended December 31, 2004, in conformity with U.S. generally accepted accounting principles. Also,
in our opinion, the related financial statement schedule, when considered in relation to the basic
financial statements taken as a whole, presents fairly in all material respects the information set
forth therein. /s/ ERNST & YOUNG LLP
 Houston, Texas
March 14, 2005 -18-




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NORTHWEST PIPELINE CORPORATION 
 STATEMENT OF INCOME (Thousands of Dollars) Years Ended December 31,2004
    
    
    2003
    
    
    2002OPERATING REVENUES
    
    $
    338,207
    
    
    $
    327,739
    
    
    $
    297,619OPERATING EXPENSES:General and administrative
    
    
    59,488
    
    
    
    49,765
    
    
    
    49,338Operation and maintenance
    
    
    34,452
    
    
    
    27,770
    
    
    
    32,279Depreciation
    
    
    65,615
    
    
    
    66,735
    
    
    
    58,988Regulatory (credits) charges
    
    
    (7,180
    )
    
    
    (6,357
    )
    
    
    28Taxes, other than income taxes
    
    
    17,492
    
    
    
    19,220
    
    
    
    12,352Impairment charges (adjustments) (Note 8)
    
    
    8,872
    
    
    
    25,643
    
    
    
    Total Operating Expenses
    
    
    178,739
    
    
    
    182,776
    
    
    
    152,985Operating income
    
    
    159,468
    
    
    
    144,963
    
    
    
    144,634OTHER INCOME  net
    
    
    5,603
    
    
    
    9,792
    
    
    
    10,374INTEREST CHARGES:Interest on long-term debt
    
    
    38,721
    
    
    
    37,144
    
    
    
    25,577Other interest
    
    
    3,368
    
    
    
    3,388
    
    
    
    2,688Allowance for borrowed funds used
during construction
    
    
    (452
    )
    
    
    (3,589
    )
    
    
    (2,638
    )Total Interest Charges
    
    
    41,637
    
    
    
    36,943
    
    
    
    25,627INCOME BEFORE INCOME TAXES
    
    
    123,434
    
    
    
    117,812
    
    
    
    129,381PROVISION FOR INCOME TAXES
    
    
    46,779
    
    
    
    44,518
    
    
    
    48,750NET INCOME
    
    $
    76,655
    
    
    $
    73,294
    
    
    $
    80,631CASH DIVIDENDS ON COMMON STOCK
    
    $
    60,000
    
    
    $
    
    
    
    $
    
 See accompanying notes. -19-




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NORTHWEST PIPELINE CORPORATION 
 BALANCE SHEET (Thousands of Dollars) December 31,2004
    
    
    2003ASSETSCURRENT ASSETS:Cash and cash equivalents
    
    $
    53,393
    
    
    $
    653Advances to affiliates
    
    
    50,000
    
    
    
    86,356Accounts receivable Trade, less reserves of $320 in each period
    
    
    30,486
    
    
    
    31,731Affiliated companies
    
    
    1
    
    
    
    578Materials and supplies, less reserves of $439 for 2004 and $284
for 2003
    
    
    8,601
    
    
    
    9,500Exchange gas due from others
    
    
    16,011
    
    
    
    10,246Deferred income taxes
    
    
    4,173
    
    
    
    4,232Prepayments and other
    
    
    855
    
    
    
    1,213Total current assets
    
    
    163,520
    
    
    
    144,509PROPERTY, PLANT AND EQUIPMENT, at cost
    
    
    2,273,333
    
    
    
    2,199,041Less  Accumulated depreciation
    
    
    933,297
    
    
    
    886,092Total property, plant and equipment
    
    
    1,340,036
    
    
    
    1,312,949OTHER ASSETS:Deferred charges
    
    
    50,019
    
    
    
    44,115Regulatory assets
    
    
    36,361
    
    
    
    29,131Total other assets
    
    
    86,380
    
    
    
    73,246Total assets
    
    $
    1,589,936
    
    
    $
    1,530,704
 See accompanying notes. -20-




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NORTHWEST PIPELINE CORPORATION BALANCE SHEET (Thousands of Dollars) December 31,2004
    
    
    2003LIABILITIES AND STOCKHOLDERS EQUITYCURRENT LIABILITIES:Accounts payable Trade
    
    $
    11,705
    
    
    $
    18,609Affiliated companies
    
    
    16,103
    
    
    
    13,076Accrued liabilities Income taxes due to affiliate
    
    
    3,436
    
    
    
    1,444Taxes, other than income taxes
    
    
    11,599
    
    
    
    8,521Interest
    
    
    7,294
    
    
    
    7,694Employee costs
    
    
    8,277
    
    
    
    7,589Exchange gas due to others
    
    
    13,939
    
    
    
    4,757Exchange gas offset (Note 1)
    
    
    2,072
    
    
    
    5,489Other
    
    
    2,367
    
    
    
    2,256Current maturities of long-term debt
    
    
    7,500
    
    
    
    7,500Total current liabilities
    
    
    84,292
    
    
    
    76,935LONG-TERM DEBT, LESS CURRENT MATURITIES
    
    
    520,062
    
    
    
    527,542DEFERRED INCOME TAXES
    
    
    255,379
    
    
    
    221,674DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES
    
    
    43,201
    
    
    
    34,594CONTINGENT LIABILITIES AND COMMITMENTSCOMMON STOCKHOLDERS EQUITY:Common stock, par value $1 per share; authorized
and outstanding, 1,000 shares
    
    
    1
    
    
    
    1Additional paid-in capital
    
    
    262,844
    
    
    
    262,844Retained earnings
    
    
    424,157
    
    
    
    407,502Accumulated other comprehensive loss
    
    
    
    
    
    
    (388
    )Total common stockholders equity
    
    
    687,002
    
    
    
    669,959Total liabilities and stockholders equity
    
    $
    1,589,936
    
    
    $
    1,530,704
 See accompanying notes. -21-




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NORTHWEST PIPELINE CORPORATION 
 STATEMENT OF COMMON STOCKHOLDERS EQUITY
(Thousands of Dollars) Years Ended December 31,2004
    
    
    2003
    
    
    2002Common stock, par value $1 per share,
authorized and outstanding, 1,000 shares
    
    $
    1
    
    
    $
    1
    
    
    $
    1Additional paid-in capital -Balance at beginning and end of period
    
    
    262,844
    
    
    
    262,844
    
    
    
    262,844Retained earnings -Balance at beginning of period
    
    
    407,502
    
    
    
    334,208
    
    
    
    253,577Net income
    
    
    76,655
    
    
    
    73,294
    
    
    
    80,631Cash dividends
    
    
    (60,000
    )
    
    
    
    
    
    
    Balance at end of period
    
    
    424,157
    
    
    
    407,502
    
    
    
    334,208Accumulated other comprehensive income Balance at beginning of period
    
    
    (388
    )
    
    
    (3,214
    )
    
    
    Minimum pension liability adjustment
    
    
    388
    
    
    
    2,826
    
    
    
    (3,214
    )Balance at end of period
    
    
    
    
    
    
    (388
    )
    
    
    (3,214
    )Total common stockholders equity
    
    $
    687,002
    
    
    $
    669,959
    
    
    $
    593,839
 See accompanying notes. -22-




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NORTHWEST PIPELINE CORPORATION 
 STATEMENT OF COMPREHENSIVE INCOME (Thousands of Dollars) Years Ended December 31,2004
    
    
    2003
    
    
    2002Net Income
    
    $
    76,655
    
    
    $
    73,294
    
    
    $
    80,631Minimum pension liability adjustment, net of tax of ($240)
for 2004, ($1,751) for 2003, and $1,991 for 2002
    
    
    388
    
    
    
    2,826
    
    
    
    (3,214
    )Total comprehensive income
    
    $
    77,043
    
    
    $
    76,120
    
    
    $
    77,417
 See accompanying notes. -23-




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NORTHWEST PIPELINE CORPORATION 
 STATEMENT OF CASH FLOWS
(Thousands of Dollars) Years Ended December 31,2004
    
    
    2003
    
    
    2002OPERATING ACTIVITIES:Net Income
    
    $
    76,655
    
    
    $
    73,294
    
    
    $
    80,631Adjustments to reconcile to net cash provided by
operating activities -Depreciation
    
    
    65,615
    
    
    
    66,735
    
    
    
    58,988Regulatory (credits) charges
    
    
    (7,180
    )
    
    
    (6,357
    )
    
    
    28Provision for deferred income taxes
    
    
    33,524
    
    
    
    51,735
    
    
    
    15,956Impairment charges
    
    
    8,872
    
    
    
    25,643
    
    
    
    Amortization of deferred charges and credits
    
    
    4,189
    
    
    
    4,523
    
    
    
    139Allowance for equity funds used during construction
    
    
    (806
    )
    
    
    (8,600
    )
    
    
    (5,496
    )Reserve for doubtful accounts
    
    
    
    
    
    
    (166
    )
    
    
    348Changes in:Accounts receivable and exchange gas due from
others
    
    
    (3,943
    )
    
    
    (7,682
    )
    
    
    (12,639
    )Materials and supplies
    
    
    899
    
    
    
    1,010
    
    
    
    499Other current assets
    
    
    358
    
    
    
    14,137
    
    
    
    (653
    )Deferred charges
    
    
    (5,854
    )
    
    
    (1,546
    )
    
    
    (948
    )Accounts payable, income taxes due to
affiliate and exchange gas due to others
    
    
    2,672
    
    
    
    12,654
    
    
    
    (2,940
    )Other accrued liabilities
    
    
    4,269
    
    
    
    (6,294
    )
    
    
    2,931Other deferred credits
    
    
    2,578
    
    
    
    (253
    )
    
    
    (359
    )Other
    
    
    
    
    
    
    (25
    )
    
    
    2Net cash provided by operating activities
    
    
    181,848
    
    
    
    218,808
    
    
    
    136,487INVESTING ACTIVITIES:Property, plant and equipment -Capital expenditures
    
    
    (102,213
    )
    
    
    (294,524
    )
    
    
    (181,843
    )Proceeds from sales
    
    
    5,033
    
    
    
    
    
    
    
    4,586Asset removal cost
    
    
    
    
    
    
    (1,898
    )
    
    
    Changes in accounts payable
    
    
    (784
    )
    
    
    (14,782
    )
    
    
    (14,257
    )Repayments from (Advances to) affiliates
    
    
    36,356
    
    
    
    (69,074
    )
    
    
    54,791Net cash used in investing activities
    
    
    (61,608
    )
    
    
    (380,278
    )
    
    
    (136,723
    )FINANCING ACTIVITIES:Proceeds from issuance of long-term debt
    
    
    
    
    
    
    175,000
    
    
    
    Principal payments on long-term debt
    
    
    (7,500
    )
    
    
    (7,500
    )
    
    
    Debt issuance costs
    
    
    
    
    
    
    (5,584
    )
    
    
    Dividends paid
    
    
    (60,000
    )
    
    
    
    
    
    
    Net cash (used in) provided by financing activities
    
    
    (67,500
    )
    
    
    161,916
    
    
    
    NET INCREASE (DECREASE) IN CASH AND CASH
EQUIVALENTS
    
    
    52,740
    
    
    
    446
    
    
    
    (236
    )CASH AND CASH EQUIVALENTS AT BEGINNING OF
YEAR
    
    
    653
    
    
    
    207
    
    
    
    443CASH AND CASH EQUIVALENTS AT END OF YEAR
    
    $
    53,393
    
    
    $
    653
    
    
    $
    207
 See accompanying notes. -24-




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NORTHWEST PIPELINE CORPORATION 
 NOTES TO FINANCIAL STATEMENTS  1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
 Corporate Structure and Control Northwest Pipeline Corporation (Northwest) is a wholly-owned subsidiary of Williams Gas
Pipeline Company LLC (WGP). WGP is a wholly-owned subsidiary of The Williams Companies, Inc.
(Williams). In this report, Northwest Pipeline Corporation is at times referred to in the first person as
we, us or our. Nature of Operations We own and operate an interstate pipeline system for the mainline transmission of natural gas.
This system extends from the San Juan Basin in northwestern New Mexico and southwestern Colorado
through Colorado, Utah, Wyoming, Idaho, Oregon and Washington to a point on the Canadian border
near Sumas, Washington. Regulatory Accounting We are regulated by the Federal Energy Regulatory Commission (FERC). Statement of Financial
Accounting Standards (SFAS) No. 71, Accounting for the Effects of Certain Types of Regulation,
provides that rate-regulated public utilities account for and report regulatory assets and
liabilities consistent with the economic effect of the way in which regulators establish rates if
the rates established are designed to recover the costs of providing the regulated service and if
the competitive environment makes it reasonable to assume that such rates can be charged and
collected. Accounting for businesses that are regulated and apply the provisions of SFAS No. 71 can
differ from the accounting requirements for non-regulated businesses. Transactions that are
recorded differently as a result of regulatory accounting requirements include the capitalization
of an equity return component on regulated capital projects, employee related benefits, levelized
depreciation and other costs and taxes included in, or expected to be included in, future rates.
As a rate-regulated entity, our management has determined that it is appropriate to apply the
accounting prescribed by SFAS No. 71 and accordingly, the accompanying financial statements include
the effects of the types of transactions described above that result from regulatory accounting
requirements. At December 31, 2004, we had approximately $22.4 million of regulatory liabilities
included in Deferred Credits and Other Noncurrent Liabilities on the accompanying Balance Sheet.
At December 31, 2003, we had approximately $18.4 million of regulatory liabilities included in
Deferred Credits and Other Noncurrent Liabilities on the accompanying Balance Sheet. Basis of Presentation Our 1983 acquisition by Williams has been accounted for using the purchase method of
accounting. Accordingly, an allocation of the purchase price was assigned to our assets and
liabilities, based on their estimated fair values at the time of the acquisition. Williams has not
pushed down the purchase price allocation (amounts in excess of original cost) of $80.6 million, as
of December 31, 2004, to us as current FERC policy does not permit us to recover amounts in excess
of original cost through our rates. The accompanying financial statements reflect our original
basis in our assets and liabilities. Use of Estimates The preparation of financial statements in conformity with accounting principles generally
accepted in the United States requires management to make estimates and assumptions that affect the
amounts reported in the financial statements and accompanying notes. Actual results could differ
from those estimates. Estimates and assumptions which, in the opinion of management, are significant to the
underlying amounts included in the financial statements and for which it would be reasonably
possible that future events or information could change those estimates include: 1) revenues
subject to refund; 2) litigation- -25-




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NORTHWEST PIPELINE CORPORATION NOTES TO FINANCIAL STATEMENTS   Property, Plant and Equipment Property, plant and equipment (plant), consisting principally of natural gas transmission
facilities, is recorded at original cost. We account for repair and maintenance costs under the
guidance of FERC regulations. The FERC identifies installation, construction and replacement costs
that are to be capitalized. Routine maintenance, repairs and renewal costs are charged to income
as incurred. Gains or losses from the ordinary sale or retirement of plant are charged or credited
to accumulated depreciation. Depreciation is provided by the straight-line method for property, plant and equipment. The
annual weighted average composite depreciation rate recorded for transmission and storage plant was
3.00 percent, 3.00 percent and 2.94 percent for 2004, 2003 and 2002, respectively, including an
allowance for negative salvage. The incremental Evergreen Project was placed in service on October 1, 2003. The levelized
rate design of this project created a revenue stream that will remain constant over the respective
25-year and 15-year contract terms. The related levelized depreciation is lower than book
depreciation in the early years and higher than book depreciation in the later years of the
contract terms. The depreciation component of the levelized incremental rates will equal the
accumulated book depreciation by the end of the primary contract terms. FERC has approved the
accounting for the differences between book depreciation and the Evergreen Projects levelized
depreciation as a regulatory asset with the offsetting credit recorded to a regulatory credit on
the accompanying Income Statement. During 2004, we recorded regulatory credits totaling $7.2 million in the accompanying
Statement of Income. These credits relate primarily to the levelized depreciation for the
Evergreen Project discussed above. Such amounts will be amortized over the primary terms of the
Evergreen shipper agreements as such costs are collected through rates. Included in our depreciation rates is a negative salvage (cost of removal) component that we
currently collect in rates. We therefore accrue the estimated costs of removal of long-lived
assets through depreciation expense. In connection with the adoption of SFAS No. 143, the negative
salvage component of Accumulated Depreciation, $14.0 million and $11.6 million at December 31, 2004
and 2003, respectively, was reclassified to a Noncurrent Regulatory Liability. During 2004, Pipeline made an adjustment to depreciation expense in the amount of $5.4
million. The adjustment was a correction of an error related to depreciation of certain in-house
developed system software and other general plant assets. These assets, which were retired in prior
years, continued to be depreciated, resulting in an over-depreciation of the assets. The error, and
correction thereof, resulted in an increase of 2004 Operating Income by $5.4 million, an
understatement of 2003 Operating Income by $3.1 million and a cumulative understatement of
Operating Income for periods prior to 2003 by $2.3 million. Management believes that the effect of
the adjustment is not material to 2004 income, prior quarters and years, or trends of earnings. Allowance for Borrowed and Equity Funds Used During Construction Allowance for funds used during construction (AFUDC) represents the estimated cost of borrowed
and equity funds applicable to utility plant in process of construction and are included as a cost
of property, plant and equipment because it constitutes an actual cost of construction under
established regulatory practices. The FERC has prescribed a formula to be used in computing
separate allowances for borrowed and equity AFUDC. The composite rate used to capitalize AFUDC was approximately 10.0 percent, 10.1 percent and
10.0 percent for 2004, 2003 and 2002, respectively. Equity AFUDC of $0.8 million, $8.6 million and
$5.5 million for 2004, 2003 and 2002, respectively, is reflected
in Other Income - net. -26-




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NORTHWEST PIPELINE CORPORATION NOTES TO FINANCIAL STATEMENTS  Advances to Affiliates As a participant in Williams cash management program, we make advances to and receive
advances from Williams. The advances are represented by demand notes. Advances are stated at the
historical carrying amounts. Interest income is recognized when chargeable and collectibility is
reasonably assured. The interest rate on intercompany demand notes is based upon the weighted
average cost of Williams debt outstanding at the end of each quarter. Prior to April 29, 2004,
the advances were made to and received from our parent company, WGP. Accounts Receivable and Allowance for Doubtful Receivables Accounts receivable are stated at the historical carrying amount net of reserves or
write-offs. Due to our customer base, we have not historically experienced recurring credit losses
in connection with our receivables. As a result, receivables determined to be uncollectible are
reserved or written off in the period of such determination. Impairment of Long-Lived Assets We evaluate long-lived assets for impairment when events or changes in circumstances indicate,
in managements judgment, that the carrying value of such assets may not be recoverable. When such
a determination has been made, managements estimate of undiscounted future cash flows attributable
to the assets is compared to the carrying value of the assets to determine whether an impairment
has occurred. If an impairment of the carrying value has occurred, the amount of the impairment
recognized in the financial statements is determined by estimating the fair value of the assets and
recording a loss for the amount that the carrying value exceeds the estimated fair value. Judgments and assumptions are inherent in managements estimate of undiscounted future cash
flows used to determine recoverability of an asset and the estimate of an assets fair value used
to calculate the amount of impairment to recognize. The use of alternate judgments and/or
assumptions could result in the recognition of different levels of impairment charges in the
financial statements. Income Taxes We are included in Williams consolidated federal income tax return. Our federal income tax
provisions are computed as though separate tax returns are filed. Deferred income taxes are
computed using the liability method and are provided on all temporary differences between the
financial basis and the tax basis of our assets and liabilities. Deferred Charges We amortize deferred charges over varying periods consistent with the FERC approved accounting
treatment for such deferred items. Unamortized debt expense, debt discount and losses on
reacquired long-term debt are amortized by the bonds outstanding method over the related debt
repayment periods. Cash and Cash Equivalents Cash equivalents are stated at cost plus accrued interest, which approximates fair value. Cash
equivalents are highly liquid investments with an original maturity of three months or less. Exchange Gas Imbalances In the course of providing transportation services to our customers, we may receive different
quantities of gas from shippers than the quantities delivered on behalf of those shippers. These
transactions result in imbalances, which are typically settled through the receipt or delivery of
gas in the future. Customer imbalances to be repaid or recovered in-kind are recorded as exchange
gas due from others or due to others in the accompanying balance sheets. These imbalances are
valued at the -27-




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NORTHWEST PIPELINE CORPORATION NOTES TO FINANCIAL STATEMENTS   Revenue Recognition Revenues from the transportation of gas are recognized in the period the service is provided
based on contractual terms and the related transported volumes. As a result of the ratemaking
process, certain revenues collected may be subject to possible refunds upon final orders in pending
rate proceedings with the FERC. We record estimates of rate refund liabilities considering our and
other third party regulatory proceedings, advice of counsel and estimated total exposure, as
discounted and risk weighted, as well as collection and other risks. Environmental Matters We are subject to federal, state, and local environmental laws and regulations. Environmental
expenditures are expensed or capitalized depending on their future economic benefit and potential
for rate recovery. We believe that, with respect to any expenditures required to meet applicable
standards and regulations, the FERC would grant the requisite rate relief so that substantially all
of such expenditures would be permitted to be recovered. We believe that compliance with
applicable environmental requirements is not likely to have a material effect upon our financial
position. Interest Payments Cash payments for interest were $38.7 million, $29.1 million and $22.9 million, net of $0.5
million, $3.6 million and $2.6 million of interest capitalized (allowance for borrowed funds used
during construction) in 2004, 2003 and 2002, respectively. Employee Stock-Based Awards Williams employee stock-based awards are accounted for under Accounting Principles Board
(APB) Opinion No. 25, Accounting for Stock Issued to Employees and related interpretations.
Williams fixed-plan common stock options generally do not result in compensation expense, because
the exercise price of the stock options equals the market price of the underlying stock on the date
of grant. The Williams plans are described more fully in Note 4. The following table illustrates
the effect on net income if we had applied the fair value recognition provisions of SFAS No. 123,
Accounting for Stock-Based Compensation. Years Ended December 31,2004
    
    
    2003
    
    
    2002(Thousands of Dollars)Net income, as reported
    
    $
    76,655
    
    
    $
    73,294
    
    
    $
    80,631Deduct: Total stock-based employee
compensation expense determined under
fair value based method for all
awards, net of tax
    
    
    787
    
    
    
    626
    
    
    
    365Pro forma net income
    
    $
    75,868
    
    
    $
    72,668
    
    
    $
    80,266
 Pro forma amounts for 2004 include compensation expense from Williams awards made in 2004,
2003, 2002, and 2001. Also included in the 2004 pro forma expense is $169,683 of incremental
expense associated with a stock option exchange program. (See Note 4.) Pro forma amounts for 2003
include compensation expense from Williams awards made in 2003, 2002, and 2001. Also included in
the 2003 -28-




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NORTHWEST PIPELINE CORPORATION NOTES TO FINANCIAL STATEMENTS   Since compensation expense from Williams stock options is recognized over the future years
vesting period for pro forma disclosure purposes and additional awards are generally made each
year, pro forma amounts may not be representative of future years amounts. Recent Accounting Pronouncements In December 2004, the Financial Accounting Standards Board (FASB) issued revised SFAS No. 123.
 Share-Based Payment. The statement requires that compensation cost for all share based awards to
employees be recognized in the financial statements at fair value. The statement is effective for
us as of the interim reporting period that begins July 1, 2005. We intend to adopt the revised
statement as of the interim reporting period beginning July 1, 2005. The revised Statement allows either a modified prospective application or a modified
retrospective application for adoption. Williams will use the modified prospective application for
adoption, and thus, will apply the statement to new awards and to awards modified, repurchased, or
cancelled after July 1, 2005. Also, for unvested stock awards outstanding as of July 1, 2005,
compensation costs for the portion of these awards for which the requisite service has not been
rendered will be recognized as the requisite service is rendered after July 1, 2005. Compensation
costs for these awards will be based on fair value at the original grant date as estimated for the
pro forma disclosure under SFAS No. 123, as amended by SFAS No. 148, Accounting for Stock-Based
Compensation Transition and Disclosurean amendment of SFAS No. 123. The modified retrospective
application would have required restating periods prior to July 1, 2005, on a basis consistent with
the pro forma disclosures required by SFAS No. 123, Accounting for Stock-Based Compensation, as
amended by SFAS No. 148. Since we plan to use the modified prospective application, we will not
restate prior periods. Certain of Williams stock awards currently result in compensation cost under APB No. 25 and
related guidance. These stock awards are subject to vesting provisions and Williams policy is to
adjust compensation cost for forfeitures when they occur. Upon the July 1, 2005 adoption of the
statement, Williams must adjust net income for previously recognized compensation cost, net of
income taxes, related to the estimated number of these outstanding stock awards that are expected
to be forfeited. This adjustment will be recognized in net income as the cumulative effect of a
change in accounting principle. We have not estimated the amount of the adjustment for expected
forfeitures. We currently present pro forma disclosure of net income as if compensation cost from all
Williams stock awards were recognized based on the fair value recognition provisions of SFAS No.
123, Accounting for Stock-Based Compensation. We have not determined the Statements impact on
net income beyond presentation of the pro forma disclosures. The Statement requires use of
valuation techniques including option pricing models to estimate the fair value of employee stock
awards. We are evaluating the appropriateness of several option pricing models, including a
Black-Scholes model and a lattice model (such as a binomial model). Application of these two
models could result in different estimates of fair value with resulting differences in compensation
costs. Proposed FERC Accounting GuidanceIn November 2004, the FERC issued proposed accounting
guidance on accounting for pipeline assessment costs. If adopted, we may be required to expense
certain assessment costs that have historically been capitalized. For 2005, the estimated impact
of this proposal would be an additional expense of $8 million to $13 million (unaudited). Reclassifications Certain reclassifications have been made in the 2003 and 2002 financial statements to conform
to the 2004 presentation. -29-




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NORTHWEST PIPELINE CORPORATION NOTES TO FINANCIAL STATEMENTS  2. CONTINGENT LIABILITIES AND COMMITMENTS
 Legal Proceedings In 1998, the United States Department of Justice (DOJ) informed Williams that Jack Grynberg,
an individual, had filed claims in the United States District Court for the District of Colorado
under the False Claims Act against Williams and certain of its wholly-owned subsidiaries including
us. Mr. Grynberg has also filed claims against approximately 300 other energy companies and alleges
that the defendants violated the False Claims Act in connection with the measurement, royalty
valuation and purchase of hydrocarbons. The relief sought is an unspecified amount of royalties
allegedly not paid to the federal government, treble damages, a civil penalty, attorneys fees, and
costs. In April 1999, the DOJ declined to intervene in any of the Grynberg qui tam cases, including
the action filed against the Williams entities in the United States District Court for the District
of Colorado. In October 1999, the Panel on Multi-District Litigation transferred all of the
Grynberg qui tam cases, including those filed against Williams, to the United States District Court
for the District of Wyoming for pre-trial purposes. In October 2002, the court granted a motion to
dismiss Grynbergs royalty valuation claims. Grynbergs measurement claims remain pending against
Williams, including us, and the other defendants, although the defendants have filed a number of
motions to dismiss these claims on jurisdictional grounds. Oral argument on these motions has been
set for March 17, 2005, and we expect a decision in the second quarter of 2005. Environmental Matters We are subject to the National Environmental Policy Act and other federal and state
legislation regulating the environmental aspects of its business. Management believes that we are
in substantial compliance with existing environmental requirements. We believe that, with respect
to any capital expenditures required to meet applicable standards and regulations, the FERC would
grant the requisite rate relief so that, for the most part, such expenditures and a return thereon
would be permitted to be recovered. As a result, we believe that compliance with applicable
environmental requirements is not likely to have a material effect upon our earnings or financial
position. Safety Matters Pipeline Integrity RegulationsWe have developed an Integrity Management Plan that meets the
United States Department of Transportation Office of Pipeline Safety (OPS) final rule pursuant to
the requirements of the Pipeline Safety Improvement Act of 2002. In meeting the Integrity
Regulations, we have identified the high consequence areas, including a baseline assessment and
periodic reassessments to be completed within specified timeframes. Currently, we estimate that
the cost to perform required assessments and repairs will be between $75 million and $100 million
over the remaining assessment period of 2005 through 2012. Management considers the costs
associated with compliance with the rule to be prudent costs incurred in the ordinary course of
business and, therefore, recoverable through our rates. Other Matters Williams responded to a subpoena from the Commodities Futures Trading Commission (CFTC) and
inquiries from the FERC related to investigations involving natural gas storage inventory issues.
We own and operate natural gas storage facilities. On August 30, 2004, the CFTC announced that it
had concluded its investigation. The FERC inquiries related to the sharing of non-public data
concerning inventory levels and the potential uses of such data in natural gas trading. The FERC
investigation is continuing and Williams is engaged in discussions with FERC staff regarding the
ultimate disposition of the matter. In addition to the foregoing, various other proceedings are pending against us incidental to
our operations. -30-




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##### Table of Contents



NORTHWEST PIPELINE CORPORATION NOTES TO FINANCIAL STATEMENTS  Summary
 Litigation, arbitration, regulatory matters, environmental matters, and safety matters are
subject to inherent uncertainties. Were an unfavorable ruling to occur, there exists the
possibility of a material adverse impact on the results of operations in the period in which the
ruling occurs. Management, including internal counsel, currently believes that the ultimate
resolution of the foregoing matters, taken as a whole and after consideration of amounts accrued,
insurance coverage, recovery from customers or other indemnification arrangements, will not have a
material adverse effect upon our future financial position. Other Commitments We have commitments for construction and acquisition of property, plant and equipment of
approximately $7.4 million at December 31, 2004. 2003 Pipeline Breaks in Washington In December 2003, we received an Amended Corrective Action Order (ACAO) from OPS regarding a
segment of one of our natural gas pipelines in western Washington. The pipeline experienced two
breaks in 2003 and we subsequently idled the pipeline segment until its integrity could be assured. By June 2004 we had successfully completed our hydrostatic testing program and returned to
service 111 miles of the 268 miles of pipe affected by the ACAO. That effort has restored 131
MDth/day of the 360 MDth/day of idled capacity and is anticipated to be adequate to meet most
market conditions. To date our ability to serve the market demand has not been significantly
impacted. The restored facilities will be monitored and tested as necessary until they are ultimately
replaced. Through December 31, 2004, approximately $40 million has been spent on testing and
remediation costs, including approximately $8.9 million related to one segment of pipe that we
recently determined not to return to service and was therefore written off in the second quarter of
2004. On October 4, 2004 we received a notice of probable violation (NOPV) from OPS. Under the
provisions of the NOPV, OPS has issued a preliminary civil penalty of $100,000 for exceeding the
pressure restriction on one of the segments covered under the original CAO. This penalty was
accrued in the third quarter of 2004. The incident occurred on July 15, 2003 and did not occur as
part of normal operations, but in preparation for running an internal inspection tool to test the
integrity of the line. The operating pressure dictated by the original CAO was exceeded for
approximately three hours due to the mechanical failure of an overpressure device and we
immediately reported the incident to the OPS. There was no impact on pipeline facilities, and no
additional sections of the pipeline were affected. Following the incident, new protocols were
adopted to ensure that a similar situation would not occur in the future. We requested a hearing
on the proposed OPS civil penalty, which was held in Denver, Colorado on December 15, 2004. OPS
will issue its decision in the near future. As required by OPS, we plan to replace the pipelines entire capacity by November 2006 to meet
long-term demands. We conducted a reverse open season to determine whether any existing customers
were willing to relinquish or reduce their capacity commitments to allow us to reduce the scope of
pipeline replacement facilities. That resulted in 13 MDth/day of capacity being relinquished and
incorporated into the replacement project. On November 29, 2004, we filed with the FERC a
certificate of application for the Capacity Replacement Project, including construction of
approximately 79.5 miles of 36-inch pipeline and 10,760 net horsepower of additional compression at
two existing compressor stations and abandonment of approximately 268 miles of the existing 26-inch
pipeline. The estimated net cost of the Capacity Replacement Project included in the filing is
approximately $333 million. The majority of these costs will be spent in 2005 and 2006. We
anticipate filing a rate case to recover the capitalized costs relating to restoration and
replacement facilities following the in-service date of the replacement facilities. -31-




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NORTHWEST PIPELINE CORPORATION NOTES TO FINANCIAL STATEMENTS  3. DEBT, FINANCING ARRANGEMENTS AND LEASES
 Debt Covenants The terms of our debt indentures restrict the issuance of mortgage bonds. The indentures
contain provisions for the acceleration of repayment or the reset of interest rates under certain
conditions. Our debt indentures also contain restrictions, which, under certain circumstances,
limit the issuance of additional debt and restrict the disposal of a major portion of our natural
gas pipeline system. Long-Term Debt Long-term debt consists of the following: December 31,2004
    
    
    2003(Thousands of Dollars)6.625%, payable 2007
    
    $
    250,000
    
    
    $
    250,0007.125%, payable 2025
    
    
    84,763
    
    
    
    84,7518.125%, payable 2010
    
    
    175,000
    
    
    
    175,0009%, payable 2004 through 2007
    
    
    17,799
    
    
    
    25,291Total long-term debt
    
    
    527,562
    
    
    
    535,042Less current maturities
    
    
    7,500
    
    
    
    7,500Total long-term debt, less current maturities
    
    $
    520,062
    
    
    $
    527,542
 As of December 31, 2004, cumulative sinking fund requirements and other maturities of
long-term debt (at face value) for each of the next five years are as follows: (Thousands of Dollars)2005
    
    $
    7,5002006
    
    
    7,5002007
    
    
    252,8672008
    
    
    2009
    
    
    Thereafter
    
    
    260,000Total
    
    $
    527,867
 Line-of-Credit Arrangements On May 3, 2004, Williams entered into a new three-year, $1 billion secured revolving credit
facility, which is available for borrowings and letters of credit. In August 2004, Williams
expanded the credit facility by an additional $275 million. At December 31, 2004, letters of credit
totaling $422 million, none of which are associated with us, have been issued by the participating
institutions under this facility and no revolving credit loans were outstanding. Northwest and
Transcontinental Gas Pipe Line Corporation, a subsidiary of WGP, have access to $400 million each
under the facility. The new facility is secured by certain Williams midstream assets. Additionally,
the facility is guaranteed by WGP. Interest is calculated based on a choice of two methods: a
fluctuating rate equal to the facilitating banks base rate plus an applicable margin or a periodic
fixed rate equal to the London Interbank Offered Rate (LIBOR) plus an applicable margin. Williams
is also required to pay a commitment fee (currently 0.375 percent -32-




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NORTHWEST PIPELINE CORPORATION NOTES TO FINANCIAL STATEMENTS   Leases Our leasing arrangements include mostly premise and equipment leases that are classified as
operating leases. The major operating lease is a leveraged lease, which became effective during 1982 for our
headquarters building. The agreement has an initial term of approximately 27 years, with options
for consecutive renewal terms of approximately 9 years and 10 years. The major component of the
lease payment is set through the initial and first renewal terms of the lease. Various purchase
options exist under the building lease, including options involving adverse regulatory
developments. We sublease portions of our headquarters building to third parties under agreements with
varying terms. Following are the estimated future minimum yearly rental payments required under
operating leases, which have initial or remaining noncancelable lease terms in excess of one year: (Thousandsof Dollars)2005
    
    $
    8,8232006
    
    
    6,3702007
    
    
    6,3712008
    
    
    6,3702009
    
    
    6,370$
    34,304Less: noncancelable
subleases
    
    
    14,513Total
    
    $
    19,791
 Operating lease rental expense amounted to $6.2 million, $5.2 million, and $5.4 million for
2004, 2003 and 2002, respectively. 4. EMPLOYEE BENEFIT PLANS Pension and Postretirement Medical Plans Our employees are covered by Williams noncontributory defined benefit pension plans and
Williams health care plan that provide postretirement medical benefits to certain retired
employees. Contributions for pension and postretirement medical benefits related to our
participation in these plans were $5.9 million, $8.9 million and $5.9 million in 2004, 2003 and
2002, respectively. These amounts are currently recoverable in our rates. Defined Contribution Plan Our employees are also covered by Williams defined contribution plan. Our costs related to
this plan totaled $1.3 million, $1.5 million and $2.3 million in 2004, 2003 and 2002, respectively. -33-




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NORTHWEST PIPELINE CORPORATION NOTES TO FINANCIAL STATEMENTS  Employee Stock-Based Awards
 On May 16, 2002, Williams stockholders approved The Williams Companies, Inc. 2002 Incentive
Plan (the Plan). The Plan provides for common-stock-based-awards to its employees and employees of
its subsidiaries. Upon approval by the stockholders, all prior Williams stock plans were
terminated resulting in no further grants being made from those plans. However, Williams options
outstanding in those prior plans remain in those plans with their respective terms and provisions. The Plan permits the granting of various types of awards including, but not limited to, stock
options, restricted stock and deferred stock. Awards may be granted for no consideration other
than prior and future services or based on certain financial performance targets being achieved.
The purchase price per share for stock options may not be less than the market price of the
underlying stock on the date of grant. Stock options generally become exercisable after three
years from the date of grant and generally expire ten years after grant. On May 15, 2003, Williams shareholders approved a Williams stock option exchange program.
Under this program, eligible employees were given a one-time opportunity to exchange certain
outstanding Williams options for a proportionately lesser number of Williams options at an exercise
price to be determined at the grant date of the new options. Surrendered Williams options were
cancelled June 26, 2003, and replacement Williams options were granted on December 29, 2003. We
did not recognize any expense pursuant to the Williams stock option exchange. However, for
purposes of pro forma disclosures, we recognized additional expense related to these new Williams
options. The remaining pro forma expense on the cancelled Williams options was being amortized
through year-end 2004. The following summary provides information about our employees stock option activity related
to Williams common stock for 2004, 2003 and 2002 (options in thousands): 2004
    
    
    2003
    
    
    2002Weighted
    
    
    
    
    
    
    Weighted
    
    
    
    
    
    
    WeightedAverage
    
    
    
    
    
    
    Average
    
    
    
    
    
    
    AverageExercise
    
    
    
    
    
    
    Exercise
    
    
    
    
    
    
    ExerciseOptions
    
    
    Price
    
    
    Options
    
    
    Price
    
    
    Options
    
    
    PriceOutstanding  beginning of year
    
    
    1,235
    
    
    $
    16.02
    
    
    
    1,511
    
    
    $
    19.40
    
    
    
    1,291
    
    
    $
    24.38Granted
    
    
    141
    
    
    $
    9.93
    
    
    
    165
    *
    
    $
    10.00
    
    
    
    527
    
    
    $
    7.27Exercised
    
    
    (183
    )
    
    $
    7.18
    
    
    
    (7
    )
    
    $
    8.06
    
    
    
    (26
    )
    
    $
    9.59Forfeited/expired
    
    
    (45
    )
    
    $
    24.02
    
    
    
    (522
    )**
    
    $
    25.45
    
    
    
    (484
    )
    
    $
    24.59Employee transfers, net
    
    
    55
    
    
    
    
    
    
    
    88
    
    
    
    
    
    
    
    203
    
    
    
    Outstanding  end of year
    
    
    1,203
    
    
    $
    15.99
    
    
    
    1,235
    
    
    $
    16.02
    
    
    
    1,511
    
    
    $
    19.40Exercisable at year end
    
    
    1,033
    
    
    $
    16.97
    
    
    
    734
    
    
    $
    23.35
    
    
    
    1,040
    
    
    $
    24.45
   *
    
    All of the 2003 Williams stock options granted relate to the Williams stock option
exchange program described above.**
    
    Includes 413 options that were cancelled on June 26, 2003, under the Williams stock option
exchange program, described above. -34-




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NORTHWEST PIPELINE CORPORATION NOTES TO FINANCIAL STATEMENTS   Stock Options Outstanding
    
    
    Stock Options ExercisableWeightedAverageWeighted
    
    
    Remaining
    
    
    
    
    
    
    WeightedRange of Exercise
    
    
    
    
    
    Average
    
    
    Contractual
    
    
    
    
    
    
    AveragePrices
    
    Options
    
    
    Exercise Price
    
    
    Life (years)
    
    
    Options
    
    
    Exercise Price$2.27 to
   $2.58
    
    
    274
    
    
    $
    2.58
    
    
    
    7.7
    
    
    
    273
    
    
    $
    2.58$5.40 to    $9.93
    
    
    172
    
    
    $
    9.67
    
    
    
    8.2
    
    
    
    22
    
    
    $
    7.89$10.00 to $42.29
    
    
    757
    
    
    $
    22.27
    
    
    
    2.8
    
    
    
    738
    
    
    $
    22.561,203
    
    
    $
    15.99
    
    
    
    4.9
    
    
    
    1,033
    
    
    $
    16.97
 The estimated fair value at the date of grant of options for Williams common stock granted in
2004, 2003 and 2002, using the Black-Scholes option-pricing model is as follows: 2004
    
    
    2003(a)
    
    
    2002Weighted-average grant date fair value
of options for Williams common stock
granted during the year
    
    $
    4.54
    
    
    $
    2.95
    
    
    $
    2.77AssumptionsDividend yield
    
    
    0.4
    %
    
    
    1.0
    %
    
    
    1.0
    %Volatility
    
    
    50
    %
    
    
    50
    %
    
    
    56
    %Risk-free interest rate
    
    
    3.3
    %
    
    
    3.1
    %
    
    
    3.6
    %Expected life (years)
    
    
    5.0
    
    
    
    5.0
    
    
    
    5.0
  (a)
    In 2003, stock options granted to our employees were solely related to the employee stock
option exchange described above. The weighted-average fair value of these options is $1.58,
which is the difference in the fair value of the new options granted and the fair value of the
exchanged options. The assumptions used in the fair value calculation of the new options
granted were: 1) dividend yield of .40 percent; 2) volatility of 50 percent; 3) weighted
average expected remaining life of 3.4 years; and 4) weighted average risk free interest rate
of 1.99 percent. -35-




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NORTHWEST PIPELINE CORPORATION NOTES TO FINANCIAL STATEMENTS  5. INCOME TAXES
 Significant components of the deferred tax liabilities and assets are as follows: December 31,2004
    
    
    2003(Thousands of Dollars)Property, plant and equipment
    
    $
    238,430
    
    
    $
    208,605Regulatory assets
    
    
    12,853
    
    
    
    10,269Loss on reacquired debt
    
    
    5,127
    
    
    
    5,780Other  net
    
    
    1,053
    
    
    
    1,016Deferred tax liabilities
    
    
    257,463
    
    
    
    225,670Regulatory liabilities
    
    
    
    
    
    
    74Accrued liabilities
    
    
    4,173
    
    
    
    4,472Loss carryovers
    
    
    
    
    
    
    3,514Minimum tax credits
    
    
    2,084
    
    
    
    168Deferred tax assets
    
    
    6,257
    
    
    
    8,228Net deferred tax liabilities
    
    $
    251,206
    
    
    $
    217,442Reflected as:Deferred income taxes  current asset
    
    $
    4,173
    
    
    $
    4,232Deferred income taxes  noncurrent liability
    
    
    255,379
    
    
    
    221,674$
    251,206
    
    
    $
    217,442
 The provision for income taxes includes: Year Ended December 31,2004
    
    
    2003
    
    
    2002(Thousands of Dollars)Current:Federal
    
    $
    11,406
    
    
    $
    (6,058
    )
    
    $
    29,305State
    
    
    1,849
    
    
    
    (1,159
    )
    
    
    3,48913,255
    
    
    
    (7,217
    )
    
    
    32,794Deferred:Federal
    
    
    30,128
    
    
    
    45,636
    
    
    
    14,461State
    
    
    3,396
    
    
    
    6,099
    
    
    
    1,49533,524
    
    
    
    51,735
    
    
    
    15,956Total provision
    
    $
    46,779
    
    
    $
    44,518
    
    
    $
    48,750
 -36-




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NORTHWEST PIPELINE CORPORATION NOTES TO FINANCIAL STATEMENTS   Year Ended December 31,2004
    
    
    2003
    
    
    2002(Thousands of Dollars)Provision at statutory Federal income tax
rate of 35 percent
    
    $
    43,202
    
    
    $
    41,235
    
    
    $
    45,283Increase
(decrease) in tax provision resulting from - State income taxes net of Federal tax benefit
    
    
    3,409
    
    
    
    3,211
    
    
    
    3,240Other  net
    
    
    168
    
    
    
    72
    
    
    
    227Provision for income taxes
    
    $
    46,779
    
    
    $
    44,518
    
    
    $
    48,750Effective tax rate
    
    
    37.90
    %
    
    
    37.79
    %
    
    
    37.68
    %
 Net cash payments made to Williams for income taxes were $11.3 million, $3.5 million and $29.7
million in 2004, 2003 and 2002, respectively. 6. FINANCIAL INSTRUMENTS Disclosures About the Fair Value of Financial Instruments The following methods and assumptions were used to estimate the fair value of each class of
financial instruments for which it is practicable to estimate that value: Cash,
cash equivalents and advances to affiliate  The carrying amounts of these items
approximates their fair value. Long-term
debt  The fair value of our publicly traded long-term debt is valued using
year-end traded market prices. Private debt is valued based on the prices of similar securities
with similar terms and credit ratings. We used the expertise of an outside investment-banking firm
to estimate the fair value of long-term debt. The carrying amount and estimated fair value of our
long term debt, including current maturities, were $528 million and $562 million, respectively, at
December 31, 2004, and $535 million and $573 million, respectively, at December 31, 2003. 7. TRANSACTIONS WITH MAJOR CUSTOMERS AND AFFILIATES Concentration of Off-Balance-Sheet and Other Credit Risk During the periods presented, more than 10 percent of our operating revenues were generated
from each of the following customers: Year Ended December 31,2004
    
    
    2003
    
    
    2002(Thousands of Dollars)Puget Sound Energy, Inc.
    
    $
    46,997
    
    
    $
    40,732
    
    
    $
    42,116Northwest Natural Gas Co.
    
    
    38,067
    
    
    
    38,437
    
    
    
    37,815Duke Energy Trading and Marketing LLC
    
    
    (a
    )
    
    
    33,739
    
    
    
    (a
    )
 (a) Revenues were under 10 percent in this year. -37-




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NORTHWEST PIPELINE CORPORATION NOTES TO FINANCIAL STATEMENTS  Our major customers are located in the Pacific Northwest. As a general policy, collateral is
not required for receivables, but customers financial condition and credit worthiness are
regularly evaluated and historical collection losses have been minimal. Related Party Transactions As a subsidiary of Williams, we engage in transactions with Williams and other Williams
subsidiaries characteristic of group operations. As a participant in Williams cash management
program, we make advances to and receive advances from Williams. At December 31, 2004, the
advances due to us by Williams totaled $50.0 million. The advances are represented by demand
notes. Effective September 2003, the interest rate on intercompany demand notes is based upon the
weighted average cost of Williams debt outstanding at the end of each quarter. Previously, the
interest rate on intercompany demand notes was based on the LIBOR plus an applicable margin. Prior
to April 29, 2004, the advances were made to and received from our parent company, WGP. We
received interest income from advances to these affiliates of $4.5 million, $2.7 million, and $1.6
million during 2004, 2003 and 2002, respectively. Such interest income is included in Other Income
 net on the accompanying Statement of Income. Williams corporate overhead expenses allocated to us were $20.3 million, $14.2 million and
$9.7 million for 2004, 2003 and 2002, respectively. Such expenses have been allocated to us by
Williams primarily based on the Modified Massachusetts formula, which is a FERC approved method
utilizing a combination of net revenues, gross payroll and gross plant for the allocation base. In
addition, Williams or an affiliate has provided executive, data processing, legal, accounting,
internal audit and other administrative services to us on a direct charge basis, which totaled $7.9
million, $6.8 million and $4.6 million for 2004, 2003 and 2002, respectively. These expenses are
included in General and Administrative Expense on the accompanying Statement of Income. During the periods presented, our revenues include transportation and exchange transactions
with subsidiaries of Williams. Combined revenues for these activities totaled $2.0 million, $1.6
million and $2.2 million for 2004, 2003 and 2002, respectively. We have entered into various other transactions with certain related parties, the amounts of
which were not significant. These transactions and the above-described transactions are made on
the basis of commercial relationships and prevailing market prices or general industry practices. 8. IMPAIRMENTS In the second quarter of 2004, we wrote off $8.9 million of previously capitalized costs
related to one segment of pipe that we recently determined not to return to service. (See the
discussion of the 2003 Pipeline Breaks in Washington in Note 2 above.) In June 2003, we wrote off software development costs of $25.5 million associated with a
service delivery system. Subsequent to the implementation of this system at Transcontinental Gas
Pipe Line Corporation in the second quarter of 2003 and a determination of the unique and
additional programming requirements that would be needed to complete the system for us, management
determined that the system would not be implemented. In August 2003, we wrote off an additional
$0.1 million of software development costs for the remaining component of the service delivery
system. -38-




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NORTHWEST PIPELINE CORPORATION NOTES TO FINANCIAL STATEMENTS  9. QUARTERLY INFORMATION (UNAUDITED)
 The following is a summary of unaudited quarterly financial data for 2004 and 2003: Quarter of 2004First
    
    
    Second
    
    
    Third
    
    
    Fourth(Thousands of Dollars)Operating revenues
    
    $
    85,476
    
    
    $
    83,381
    
    
    $
    83,160
    
    
    $
    86,190Operating income
    
    $
    42,247
    
    
    
    30,008
    
    
    
    45,040
    
    
    
    42,173Net income
    
    
    20,957
    
    
    
    13,073
    
    
    
    22,016
    
    
    
    20,609
 Second quarter operating income includes the $8.9 million write off of previously capitalized
costs incurred on an idled segment of our system that will not return to service due to the
pipeline breaks in 2003. Third quarter operating income includes a $5.4 million adjustment to
correct an error related to depreciation of certain in-house developed system software and other
general plant issues. These assets, which were retired in prior years, continued to be
depreciated, resulting in an over-depreciation of the assets. (See Property, Plant and Equipment in
Note 1.) Quarter of 2004First
    
    
    Second
    
    
    Third
    
    
    Fourth(Thousands of Dollars)Operating revenues
    
    $
    79,624
    
    
    $
    81,352
    
    
    $
    79,385
    
    
    $
    87,378Operating income
    
    $
    45,198
    
    
    
    16,443
    
    
    
    36,609
    
    
    
    46,713Net income
    
    
    24,306
    
    
    
    6,810
    
    
    
    18,817
    
    
    
    23,361
 Fourth quarter operating revenues include $9.9 million of new revenues from the Evergreen
Project that was placed in service on October 1, 2003. Second quarter operating income includes
the $25.5 million write-off of capitalized software development costs. 10. SUBSEQUENT EVENTS (Unaudited) Duke Energy Trading and Marketing, LLC (Duke) has given notice to terminate its firm
transportation agreement related to the Grays Harbor Lateral effective December 31, 2004, and pay
us a lump sum amount based on the remaining net book value of the lateral facilities and related
income taxes. In January 2005, Duke paid approximately $94 million towards this lump sum amount
and disputed a portion of the lump sum amount requested by us. As of March 14, 2005, the final
amount has not been agreed upon by Duke and us. However, based upon the payment already made, we
do not anticipate any adverse impact to our results of operations or financial position in 2005.
The monthly revenues from the Grays Harbor transportation agreement with Duke, which was terminated
as of December 31, 2004, were approximately $1.6 million. -39-




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##### Table of Contents



Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE None. 
 Item 9A. CONTROLS AND PROCEDURES An evaluation of the effectiveness of the design and operation of our disclosure controls and
procedures (as defined in Rule 13a-15(e) and 15(d)-(e) of the Securities Exchange Act) (Disclosure
Controls) was performed as of the end of the period covered by this report. This evaluation was
performed under the supervision and with the participation of our management, including our Senior
Vice President and Vice President and Treasurer. Based upon that evaluation, our Senior Vice
President and Vice President and Treasurer concluded that these Disclosure Controls are effective
at a reasonable assurance level. Our management, including our Senior Vice President and Vice President and Treasurer, does not
expect that our Disclosure Controls or our internal controls over financial reporting (Internal
Controls) will prevent all errors and all fraud. A control system, no matter how well conceived and
operated, can provide only reasonable, not absolute, assurance that the objectives of the control
system are met. Further, the design of a control system must reflect the fact that there are
resource constraints, and the benefits of controls must be considered relative to their costs.
Because of the inherent limitations in all control systems, no evaluation of controls can provide
absolute assurance that all control issues and instances of fraud, if any, within the company have
been detected. These inherent limitations include the realities that judgments in decision-making
can be faulty, and that breakdowns can occur because of simple error or mistake. Additionally,
controls can be circumvented by the individual acts of some persons, by collusion of two or more
people, or by management override of the control. The design of any system of controls also is
based in part upon certain assumptions about the likelihood of future events, and there can be no
assurance that any design will succeed in achieving its stated goals under all potential future
conditions. Because of the inherent limitations in a cost-effective control system, misstatements
due to error or fraud may occur and not be detected. We monitor our Disclosure Controls and
Internal Controls and make modifications as necessary; our intent in this regard is that the
Disclosure Controls and the Internal Controls will be modified as systems change and conditions
warrant. Notwithstanding the above, management concludes that its current controls are effective at a
reasonable assurance level. In addition, there has been no material change in our Internal Controls
that occurred during the registrants fourth quarter. 
 Item 9B. None. 
 PART III Since we meet the conditions set forth in General Instruction (I)(1)(a) and (b) of Form 10-K,
Items 10 through 13 are omitted. 
 Item 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES Fees for auditor services totaled $709 thousand in 2004 and $449 thousand in 2003, and include
fees associated with the annual audit, the reviews for our quarterly reports on Form 10-Q, services
performed in connection with other filings with the Securities and Exchange Commission and audit
consultations. Additionally, audit fees for 2004 include fees related to the audit of Williams
assessment and the effectiveness of internal controls over financial reporting as required by
Section 404 of the Sarbanes-Oxley Act of 2002. Williams was required to report under Section 404
as of December 31, 2004. There were no audit-related, tax or other fees in 2004 or 2003. -40-




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As a wholly-owned subsidiary of Williams, we do not have a separate audit committee. The
Williams audit committee policies and procedures for pre-approving audit and non-audit services
will be filed with the Williams Proxy Statement to be filed with the Securities and Exchange
Commission on or before April 11, 2005. -41-




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##### Table of Contents



PART IV 
 Item 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES (a) 1. Financial Statements Index PageReferenceto 2004Form 10-KReport of Independent Registered Public Accounting Firm
    
    
    18Statement of Income for the Years Ended December 31, 2004, 2003 and 2002
    
    
    19Balance Sheet at December 31, 2004 and 2003
    
    
    20Statement of Common Stockholders Equity for the Years Ended December 31, 2004, 2003 and 2002
    
    
    22Statement of Comprehensive Income for the Years Ended December 31, 2004, 2003 and 2002
    
    
    23Statement of Cash Flows for the Years Ended December 31, 2004, 2003 and 2002
    
    
    24Notes to Financial Statements
    
    
    25
 (a) 2. Financial Statement Schedules NORTHWEST PIPELINE CORPORATION
SCHEDULE II  VALUATION AND QUALIFYING ACCOUNTS
(Thousands of Dollars) Charged toBeginning
    
    
    Costs and
    
    
    
    
    
    
    EndingDescription
    
    Balance
    
    
    Expenses
    
    
    Deductions
    
    
    BalancesYear ended December 31, 2004:Reserve for doubtful receivables
    
    $
    320
    
    
    $
    0
    
    
    $
    0
    
    
    $
    320Reserve for obsolescence of
materials and supplies
    
    
    284
    
    
    
    825
    
    
    
    (670
    )
    
    
    439Year ended December 31, 2003:Reserve for doubtful receivables
    
    
    486
    
    
    
    (12
    )
    
    
    (154
    )
    
    
    320Reserve for obsolescence of
materials and supplies
    
    
    500
    
    
    
    280
    
    
    
    (496
    )
    
    
    284Year ended December 31, 2002:Reserve for doubtful receivables
    
    
    138
    
    
    
    653
    
    
    
    (305
    )
    
    
    486Reserve for obsolescence of
materials and supplies
    
    
    0
    
    
    
    500
    
    
    
    0
    
    
    
    500
 All other schedules have been omitted because they are not required to be filed. -42-




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(a) 3 and b. Exhibits:  (2)
    Plan of acquisition, reorganization, arrangement, liquidation or succession:  *(a)
    Merger Agreement, dated as of September 20, 1983, between Williams and Northwest
Energy Company (Energy) (Exhibit 18 to Energy schedule 14D-9 (Amendment No. 3) dated
September 22, 1983).*(b)
    The Plan of Merger, dated as of November 7, 1983, between Energy and a subsidiary
of Williams (Exhibit 2(b) to Northwest report on Form 10-K, No. 1-7414, filed March 22,
1984).  (3)
    Articles of incorporation and by-laws:  *(a)
    Restated Certificate of Incorporation (Exhibit 3a to Amendment No. 1 to
Registration Statement on Form S-1, No. 2-55-273, filed January 13, 1976).*(b)
    By-laws, as amended (Exhibit 3c to Registration Statement on Form S-1, No.
2-55273, filed December 30, 1975).  (4)
    Instruments defining the rights of security holders, including indentures:  *(a)
    Senior Indenture, dated as of August 1, 1992, between Northwest and Continental
Bank, N.A., relating to Pipelines 9% Debentures, due 2022 (Exhibit 4.1 to Registration
Statement on Form S-3, No. 33-49150, filed July 2, 1992).*(b)
    Senior Indenture, dated as of November 30, 1995 between Northwest and Chemical
Bank, relating to Pipelines 7.125% Debentures, due 2025 (Exhibit 4.1 to Registration
Statement on Form S-3, No. 33-62639, filed September 14, 1995).*(c)
    Senior indenture, dated as of December 8, 1997 between Northwest and The Chase
Manhattan Bank, relating to Pipelines 6.625% Debentures, due 2007 (Exhibit 4.1 to
Registration Statement on Form S-3, No. 333-35101, filed September 8, 1997).*(d)
    Indenture dated March 4, 2003, between Northwest and JP Morgan Chase Bank, as
Trustee (filed as Exhibit 4.1 to The Williams Companies, Inc. Form 10-Q for the quarter
ended March 31, 2003, Commission File Number 1-4174). (10) Material contracts:  (a)
    *(1)
    Form of Transfer Agreement, dated July 1, 1991, between Northwest and Gas
Processing (Exhibit 10(c)(8) to Pipeline Report on Form 10-K, No. 1-7414, filed March
26, 1992).  *(2)
    Form of Operating Agreement, dated July 1, 1991, between Northwest and
Williams Field Services Company (Exhibit 10(c)(9) to Pipeline Report on Form 10-K,
No. 1-7414, filed March 26, 1992).*(1)
    U.S $1,000,000,000 Credit Agreement dated as of May 3, 2004, among
Williams, Northwest, Transcontinental Gas Pipe Line Corporation, as Borrowers,
Citicorp USA, Inc., as Administrative Agent and Collateral Agent, Citibank, N.A.
and Bank of America, N.A., as Issuing Banks, the banks named therein as Banks, Bank
of America, N.A., as Syndication Agent, JPMorgan Chase Bank, The Bank of Nova
Scotia, The Royal Bank of Scotland plc as Co-Documentation Agents, Citigroup Global
Markets Inc. and Banc of America Securities LLC as Joint Lead Arrangers and Co-Book
Runners (filed as Exhibit 10.4 to Williams Form 10-Q filed May 6, 2004 Commission
File Number 1-4174).*(2)
    Letter of Credit Commitment Increase Agreement dated August 4, 2004, by
and among The Williams Companies, Inc., Citicorp USA in its capacity as Agent under
the Credit Agreement dated as of May 3, 2004 among the Borrower, Northwest Pipeline
Corporation, Transcontinental Gas Pipe Line Corporation, the Agent, the -43-




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Collateral Agent, the Banks and Issuing Banks party thereto and Citibank, N.A.
and Bank of America, N.A. (filed as Exhibit 10.1 to The Williams Companies,
Inc. Form 10-Q for the quarter ended September 30, 2004 Commission File Number
1-4174).*(3)
    Revolving Credit Commitment Increase Agreement dated August 4, 2004, by
and among The Williams Companies, Inc., Citicorp USA, Inc. in its capacity as Agent
under the Credit Agreement dated as of May 3, 2004 among the Borrower, Northwest
Pipeline Corporation, Transcontinental Gas Pipe Line Corporation, the Agent, the
Collateral Agent and the Banks and Issuing Banks party thereto, the Issuing Banks
and Citicorp USA, Inc. (filed as Exhibit 10.2 to The Williams Companies, Inc. Form
10-Q for the quarter ended September 30, 2004 Commission File Number 1-4174).*(4)
    Amendment Agreement dated as of October 19, 2004, among Williams,
Northwest, Transcontinental Gas Pipeline Corporation, as Borrowers, the banks,
financial institutions and other institutional lenders that are parties to the
Credit Agreement dated as of May 3, 2004, among the Borrowers, the Banks, Citicorp
USA, Inc., as agent and Citibank, N.A. and Bank of America, N.A., as issuers of
letters of credit under the Credit Agreement, the Agent and the Issuing Banks
(filed as Exhibit 10.29 to Williams Form 10-K filed March 11, 2005 Commission File
Number 1-4174). (23) Consent of Independent Registered Public Accounting Firm (24) Power of Attorney with Certified Resolution (31) Section 302 Certifications  (a)
    Certification of Principal Executive Officer pursuant to Rules 13a-14(a) and
15d-14(a) promulgated under the Securities Exchange Act of 1934, as amended and Item
601(b)(31) of Regulation S-K, as adopted pursuant to Section 302 of The Sarbanes-Oxley
Act of 2002.(b)
    Certification of Principal Financial Officer pursuant to Rules 13a-14(a) and
15d-14(a) promulgated under the Securities Exchange Act of 1934, as amended, and Item
601(b)(31) of Regulation S-K, as adopted pursuant to Section 302 of The Sarbanes-Oxley
Act of 2002. (32) Section 906 Certification  (a)
    Certification of Principal Executive Officer and Principal Financial Officer
pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002.   *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. -44-




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SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934,
the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto
duly authorized. NORTHWEST PIPELINE CORPORATION(Registrant)By
    
    /s/ Jeffrey P. HeinrichsJeffrey P. HeinrichsController
 Date: March 14, 2005 Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been
signed below by the following persons on behalf of the registrant in the capacities and on the
dates indicated. Signature
    
    
    
    Title/s/
    
    Steven J. Malcolm*
    
    
    
    Chairman of the BoardSteven J. Malcolm/s/
    
    Phillip D. Wright*
    
    
    
    Senior Vice President and DirectorPhillip D. Wright
    
    
    
    (Principal Executive Officer)/s/
    
    Richard D. Rodekohr*
    
    
    
    Vice President and TreasurerRichard D. Rodekohr
    
    
    
    (Principal Financial Officer)/s/
    
    Jeffrey P. Heinrichs
    
    
    
    Controller (Principal Accounting Officer)Jeffrey P. Heinrichs/s/
    
    Allison G. Bridges*
    
    
    
    Director and Vice PresidentAllison G. Bridges
 * By
    
    /s/
    
    Jeffrey P. HeinrichsJeffrey P. HeinrichsAttorney-in-fact
 Date: March 14, 2005 -45-




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EXHIBIT INDEX Exhibit23
    
    Consent of Independent Registered Public Accounting Firm24
    
    Power of Attorney with Certified Resolution31(a)
    
    Section 302 Certification of Principal Executive Officer31(b)
    
    Section 302 Certification of Principal Financial Officer32
    
    Section 906 Certification of Principal Executive Officer and Principal Financial Officer
 -46-