##### Table of Contents



UNITED STATES
SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D. C. 20549
 FORM 10-K [X]
    
    Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934For the fiscal year ended December 31, 2003or[   ]
    
    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  [X]   No  [ ] 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.   [X] Indicate by check mark whether the registrant is an accelerated filer (as
defined in Exchange Act Rule 12b-2).
Yes [ ]   No[X] 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 12, 2004Common stock, $1 par value
    
    1,000 shares
 Documents Incorporated by Reference:
None The registrant meets the conditions set forth in General Instruction (I)(1)(a)
and (b) of Form 10-K and is therefore filing this Form 10-K with the reduced
disclosure format.




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TABLE OF CONTENTS  PART IItem 1. BUSINESSItem 2. PROPERTIESItem 3. LEGAL PROCEEDINGSItem 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERSPART IIItem 5. MARKET FOR REGISTRANTS COMMON EQUITY AND RELATED STOCKHOLDER MATTERSItem 6. SELECTED FINANCIAL DATAItem 7. MANAGEMENTS NARRATIVE ANALYSIS OF THE RESULTS OF OPERATIONSItem 7A. QUALITATIVE AND QUANTITATIVE DISCLOSURES ABOUT MARKET RISKItem 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATAREPORT OF INDEPENDENT AUDITORSSTATEMENT OF INCOMEBALANCE SHEETSTATEMENT OF COMMON STOCKHOLDERS EQUITYSTATEMENT OF COMPREHENSIVE INCOMESTATEMENT OF CASH FLOWSNOTES TO FINANCIAL STATEMENTSItem 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSUREItem 9A. CONTROLS AND PROCEDURESPART IIIItem 14. PRINCIPAL ACCOUNTANT FEES AND SERVICESPART IVItem 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-KSIGNATURESEXHIBIT INDEXConsent of Independent AuditorsPower of Attorney with Certified ResolutionSection 302 CertificationSection 302 CertificationSection 906 Certification    Table of Contents  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
    
    
    18Item 9.
    
    CHANGES IN AND DISAGREEMENTS WITH
ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
    
    
    41Item 9A.
    
    CONTROLS AND PROCEDURES
    
    
    41PART IIIItem 10.
    
    DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT (Omitted)
    
    
    41Item 11.
    
    EXECUTIVE COMPENSATION (Omitted)
    
    
    41Item 12.
    
    SECURITY OWNERSHIP OF CERTAIN
BENEFICIAL OWNERS AND MANAGEMENT (Omitted)
    
    
    41Item 13.
    
    CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS (Omitted)
    
    
    41Item 14.
    
    PRINCIPAL ACCOUNTANT FEES AND SERVICES
    
    
    41PART IVItem 15.
    
    EXHIBITS, FINANCIAL STATEMENT
SCHEDULES AND REPORTS ON FORM 8-K
    
    
    43




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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). 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 At December 31, 2003, our system, having long term firm transportation
agreements with peaking capacity of approximately 3.4 MMDth* of gas per day,
was composed of approximately 4,100 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 2003, Pipeline transported natural gas for a total of 175 customers.
We provide services for markets in California, New Mexico, Colorado, Utah,
Nevada, Wyoming, Idaho, Oregon and Washington. Our transportation customers
include distribution companies, municipalities, interstate and intrastate
pipelines, gas marketers and direct industrial users. In 2003, our three
largest transportation customers were Puget Sound Energy, Inc., Northwest
Natural Gas Co., and Duke Energy Trading and Marketing LLC, which accounted for
approximately 12.4 percent, 11.7 percent and 10.3 percent, respectively, of our
total operating revenues. No other customer accounted for more than 10 percent
of our total operating revenues in 2003. Our firm transportation 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 6.4 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 On May 1, 2003, a line break occurred on our 26-inch gas transmission
pipeline near Lake Tapps in Pierce County, Washington. The line break did not
result in ignition and there were no injuries. On May 2, 2003, the Office of
Pipeline Safety (OPS) initiated an investigation and issued a Corrective Action
Order (CAO) requiring us to reduce the pressure in our 26-inch line from Sumas
to Washougal, Washington to 80% of Maximum Allowable Operating Pressure (MAOP),
determine cause, and work to remedy the cause of the line break. We
subsequently determined that the line break was caused by stress corrosion
cracking (SCC) and implemented a variety of processes to ensure the integrity
of our pipeline. Specifically, we completed surface and in-line inspection of
certain segments of the line and were developing and executing plans to return
the line to service prior to an additional line break occurring in December
2003. On December 13, 2003, we experienced another line break on the same line
seventy miles south near Toledo, Washington. This line break occurred during
pendency of the OPS CAO referred to above and the OPS issued an Amendment to
the May 2 CAO as a result. This amendment requires us to idle the 26-inch
line, conduct a detailed metallurgical analysis on the failure, finalize an
integrity management program specifically for the 26-inch line, and develop a
plan for the eventual replacement of the pipe. The Amendment also requires that
we evaluate other facilities in the general area of the line breaks for
susceptibility to SCC. We filed a request for hearing on December 29, 2003 to
achieve clarity about certain requirements in the Amended CAO. This hearing
occurred in Denver on January 21, 2004, and we are awaiting a final order. We
continue to work closely with the OPS to obtain clarity in any requirements
associated with restoring pressure in affected segments of the line, through a
combination of hydrostatic testing and in-line inspection, by the summer of
2004. Working with customers, we have thus far been able to meet their firm
nominations, and continue to work with customers to determine the extent to
which the capacity of the 26-inch line will ultimately need to be replaced.
The estimated combined cost to inspect, hydrostatically test, temporarily
restore a portion of the line to service, and to ultimately replace up to the
entire 360 MDth per day of capacity, if required, by the end of 2006 is
estimated to range between $365 million and $430 million. Funding for these
activities will be provided by the sources discussed below in Capital Resources
and Liquidity, Method of Financing. (See Part II, Item 7.) We anticipate
filing a rate case to recover these costs coincident with the in-service date
of the facilities. Expansion Projects On November 1, 2003, we placed into service most of the facilities
associated with our Rockies Expansion Project, an expansion of our pipeline
system designed to provide an additional 175 MDth per day of capacity to our
transmission system in Wyoming and Idaho in order to reduce reliance on -2-




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displacement capacity. The remaining facilities were placed into service on
November 30, 2003. The project included the installation of 91 miles of
pipeline loop and the upgrading or modification of six compressor stations for
a total increase of 26,057 horsepower. A majority of our firm shippers agreed
to support roll-in of the expansion costs into our existing rates. The
estimated cost of the expansion project is approximately $140 million, of which
approximately $16 million has been offset by settlement funds received from a
former customer in connection with a contract restructuring. On October 1, 2003, we placed into service our Evergreen Expansion
Project, an expansion of our pipeline system designed to provide 276,625 Dth
per day of firm transportation service from Sumas, Washington to Chehalis,
Washington to serve new power generation demand in western Washington. The
project included installation of 28 miles of pipeline loop, upgrading,
replacing or modifying five compressor stations and adding a net total of
64,160 horsepower of compression. The estimated cost of the expansion project
is approximately $198 million, including the allocated portion of the Columbia
Gorge Project discussed below. The Evergreen Expansion customers have agreed
to pay for the cost of service of this expansion on an incremental basis. Our October 1, 2003, we placed into service our Columbia Gorge project, an
expansion of our pipeline system designed to replace 56,000 Dth per day of
northflow design displacement capacity from Stanfield, Oregon to Washougal,
Washington. The project included upgrading, replacing or modifying five
existing compressor stations and adding a net total of 23,900 horsepower of
compression. A majority of our firm shippers have agreed to support roll-in of
approximately 84 percent of the expansion costs into the existing rates with
the remainder to be allocated to the incremental Evergreen Expansion Project
customers. The estimated cost of the expansion project is approximately $43
million. OPERATING STATISTICS The following table summarizes volumes and capacity for the periods
indicated: Year Ended December 31,2003
    
    2002
    
    2001(In million dekatherms)Total throughput
    
    
    682
    
    
    
    729
    
    
    
    734Average Daily Transportation Volumes
    
    
    1.9
    
    
    
    2.0
    
    
    
    2.0Average Daily Reserved Capacity Under Base Firm
Contracts, excluding peak capacity
    
    
    2.5
    
    
    
    2.3
    
    
    
    2.2Average
Daily Reserved Capacity Under Short-Term Firm Contracts (1)
    
    
    .5
    
    
    
    .5
    
    
    
    .4
   (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. -3-




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Other Regulatory Matters Order No. 2004 (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. The FERC defines energy
affiliates broadly to include any non-transmission provider affiliate that
engages in or is involved in transmission (gas or electric) transactions,
manages or controls transmission capacity, or that buys, sells, trades or
administers natural gas or electric energy, engages in financial transactions
relating to the sale or transmission of natural gas or electricity, and Hinshaw
and intrastate pipelines. Current rules regulate our conduct with our natural
gas marketing affiliates. Transmission providers must comply with Order No.
2004 by June 1, 2004. Numerous parties, including Williams, have filed
requests for rehearing of Order No. 2004. We filed and posted a plan and
schedule for implementing the requirements of Order No. 2004 on February 9,
2004, and currently are reviewing these new standards, preparing to adopt new
compliance measures and evaluating the impact of increased costs to us. Environmental Matters We are subject to the National Environmental Policy Act and other federal
and state legislation regulating the environmental aspects of our business.
Our 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. We
believe that compliance with applicable environmental requirements is not
likely to have a material effect upon our earnings or financial position. Safety Matters In December 2003, the United States Department of Transportation Office of
Pipeline Safety issued a final rule pursuant to the requirements of the
Pipeline Safety Improvement Act of 2002 that was enacted in December 2002. The
rule requires gas pipeline operators to develop integrity management programs
for transmission pipelines that could affect high consequence areas in the
event of pipeline failure, 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 2003 to 2012 period. Developing
and implementing the required public education program, including a process for
measuring and evaluating the effectiveness of safety information distributed to
various stakeholder groups, is expected to cost less than $1 million. Our
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. 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. EMPLOYEE RELATIONS At December 31, 2003, we employed 375 persons, none of whom are
represented under collective bargaining agreements. No strike or work stoppage
in any of our operations has occurred in the past and relations with employees
are good. -4-




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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; 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. 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 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: -5-




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
    
    economic downturns;
    
    capital market conditions generally;
    
    market prices for electricity and natural gas;
    
    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. RISKS RELATED TO THE REGULATION OF OUR BUSINESS OUR 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 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 has 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. On November 25, 2003, the FERC issued a final rule, Order No. 2004, that
adopted new standards of conduct for transmission providers to follow when
dealing with their energy affiliates. Order No. 2004 may require substantial
changes to Williams internal leadership structure that may have an adverse
impact on Williams ability to effectively run its business. As a transmission
provider, we must comply with the new standards of conduct and post procedures
indicating how we will do so by June 1, 2004. The precise scope of the new
rule is unclear and clarification has been requested from the FERC. That
clarification may not be received until after the June 1 deadline, and so the
new procedures we implement to meet the standards of Order No. 2004 could be
found by the FERC to be inadequate in spite of our efforts to comply with the
new rule. RISKS RELATED TO ENVIRONMENTAL MATTERS WE COULD INCUR MATERIAL LOSSES IF WE ARE HELD LIABLE FOR THE ENVIRONMENTAL
CONDITION OF ANY OF OUR ASSETS OR DIVESTED ASSETS. -6-




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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 at divested assets may not be covered by insurance. Even if
environmental conditions are 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 increased risk
related to one or more of our assets. 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 to 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 could 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 or alter the
operation of those facilities, which might cause us to incur losses. Further, our regulatory rate structure and our contracts with clients
might not necessarily allow us to recover capital 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 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. -7-




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RISKS RELATING TO ACCOUNTING STANDARDS POTENTIAL CHANGES IN ACCOUNTING STANDARDS MIGHT CAUSE US TO REVISE OUR
FINANCIAL DISCLOSURE IN THE FUTURE. Recently discovered accounting irregularities in various industries have
forced regulators and legislators to take a renewed look at accounting
practices, financial disclosures, companies relationships with their
independent auditors and retirement plan practices. Because it is still unclear
what laws or regulations will 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. Restricted access
to areas of potential reserves could also adversely affect the development of
additional reserves. 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. 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. Accidents or other operating risks could further result in loss of service
available to our customers. Such circumstances could adversely impact our
ability to meet contractual obligations and retain customers. For example, our
26-inch segment of pipe from Sumas to Washougal, Washington was idled in 2003
after a line break associated with SCC. Efforts are underway to determine what
measures are required to restore the capacity reduction resulting from the line
break and satisfy customer needs. SCC is caused by a specific combination of
stress and exposure to environmental factors such as soil acidity, moisture,
and electro chemical properties that occurs in older pipelines. This type of
corrosion cracking is a very complex technical phenomenon and, while the
industry is making progress in developing methods to predict and identify SCC,
there are still many unknowns. An integrity assessment of our pipeline is
under way. Potential customer impact arising from our 2003 line break may include
potential shortages in our ability to satisfy customer requirements,
obligations to provide reservation charge credits to customers in times of
constrained capacity, and solicitation of our existing customers by others for
potential new pipeline projects that would compete directly with us. The size

of reservation charge credits in particular is sensitive to actual market
requirements and difficult to predict. From a market and rate recovery
standpoint, it will be critical for us to expedite our response to the
diminished capacity arising out of the 2003 line break. Critical to the
ability to respond will be regulatory approval of any such response plan by the
Department of Transportation  OPS and the Washington Utilities and
Transportation commission. Such approvals will be subject to the same
uncertainty inherent in any government approval process. -8-




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COMPLIANCE WITH THE PIPELINE SAFETY IMPROVEMENT ACT MAY RESULT IN
UNANTICIPATED COSTS AND CONSEQUENCES. Implementation of the new Pipeline Safety Improvement Act (PSIA)
regulations requires us to implement an Integrity Management Plan (IMP) by
December 2004. As part of the IMP, we must identify High Consequence Areas
(HCA) through which our pipeline runs. Although our investigations are
ongoing, we believe that certain segments of our pipeline will be determined to
run through HCAs. An HCA is defined by the rule as an area where the
potential consequence of a gas pipeline accident may be significant or do
considerable harm to people or property. Designing and implementing the IMP
and identifying HCAs could result in significant additional costs. There is
always the possibility that the assessments related to the IMP might reveal an
unexpected condition for which remedial action will be required. 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 to
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. 
 Item 2. PROPERTIES See Item 1. Business. 
 Item 3. LEGAL PROCEEDINGS Other than as described in Note 2 of the Notes to Financial Statements and
above under Item 1  Business, 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 no cash dividends on common stock in 2002 or 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, 2003, we had approximately
$16.1 million of regulatory assets included in Other Assets: Deferred Charges
and approximately $11.8 million of regulatory liabilities included in Deferred
Credits and Other Noncurrent Liabilities on the accompanying Balance Sheet. At
December 31, 2002, we had approximately $14.1 million of regulatory assets
included in Other Assets: Deferred Charges and approximately $11.0 million of
regulatory liabilities included in Deferred Credits and Other Noncurrent
Liabilities on the accompanying Balance Sheet. -10-




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Revenue Subject to Refund FERC regulations promulgate policies and procedures, which govern a
process to establish the rates that we are permitted to charge customers for
natural gas services, including the transportation and storage of natural gas.
Key determinants in the ratemaking process are (i) volume throughput
assumptions, (ii) costs of providing service, including depreciation expense
and (iii) allowed rate of return, including the equity component of a
pipelines capital structure and related income taxes. 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, 2003, 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, 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. 2003 PIPELINE BREAKS Reference is made to Item 1. Business  2003 Pipeline Breaks on page 2. WILLIAMS RECENT EVENTS In February 2003, Williams outlined its planned business strategy in
response to the events that impacted the energy sector and Williams during late
2001 and much of 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 asset
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. -11-




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During 2003, Williams successfully executed the following critical
components of its restructuring plan:  
    
    generated cash proceeds of approximately $3.0 billion
from the sale of assets.
    
    repaid $3.2 billion of debt through scheduled
maturities and early extinguishment of debt and accessed the
public debt markets available to Williams primarily to refinance
$2.0 billion of higher cost debt.
    
    sustained core business earnings capacity through
completed gas pipeline system expansions, continued drilling
activity at Williams exploration and production segment and
continued investment in deepwater activities within Williams
midstream segment.
    
    continued rationalization of its cost structure,
including a 28 percent reduction in selling, general and
administrative (SG&A) costs of continuing operations and a 39
percent reduction in general corporate expenses. Williams completed tender offers that prepaid approximately $721 million
of the $1.4 billion of its senior unsecured 9.25 percent notes that mature in
the first quarter of 2004. Williams is pursuing a strategy of exiting the power business. However,
market conditions have contributed to the difficulty of, and could delay, a
full, immediate exit from this business. In 2003, Williams generated in excess
of $600 million from the sale, termination or liquidation of power contracts
and assets. During the year, Williams continued to manage its portfolio to
reduce risk, to generate cash and to fulfill contractual commitments. Williams
is also pursuing its goal to resolve the remaining legal and regulatory issues
associated with the business. Entering 2004, Williams plans to focus upon the following objectives:  
    
    sustain solid core business performance, including
increased capital allocation to
exploration and production activities;
    
    continue reduction of debt, including scheduled
maturities and early retirements, and selective refinancing of
certain instruments; and
    
    maintain investment discipline. Key execution steps include the completion of planned asset sales, which
are estimated to generate proceeds of approximately $800 million in 2004,
additional reductions of Williams SG&A costs, the replacement of its
cash-collateralized letter of credit and revolver facility with facilities that
do not encumber cash and continuing efforts to exit from the power business. RESULTS OF OPERATIONS ANALYSIS OF FINANCIAL RESULTS This analysis discusses financial results of our operations for the years
2001 through 2003. 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. 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. -12-




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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 (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. 2002 COMPARED TO 2001 Operating revenues increased $12.4 million, or 4 percent, due primarily to
facility charge revenues of $3.6 million from incremental projects put into
service during 2002, new reservation charges of approximately $1.5 million and
higher short term firm transportation revenues of $6.4 million, partially
offset by a $1.6 million decrease in tracked fuel costs and Gas Research
Institute charges billed to customers. Our transportation service accounted for 95 percent of operating revenues
for each of the years ended December 31, 2002 and 2001. Additionally, 3
percent of operating revenues represented gas storage service in each of the
years ended December 31, 2002 and 2001. Operating expenses increased $3.2 million, or 2 percent, due primarily to
a $6.6 million increase in retirement plan expenses, including $3.9 million
related to an enhanced-benefit early retirement option offered to certain
Williams employee groups, higher allocated general and administrative costs
from Williams, and a $1.1 million charge for an abandoned project. These
increases were partially offset by the decrease in tracked fuel costs and Gas
Research Institute charges collectible from customers, a $1.2 million reduction
in employee benefit costs and $3.8 million lower labor and other employee
related costs resulting primarily from recent staff reductions in connection
with the early retirement option and organizational changes across Williams.
The increased level of capital spending compared to 2001, which has resulted in
a greater percentage of employee labor and expenses being dedicated to capital
projects, including the expansion projects discussed below, has also
contributed to offsetting the increase in operating expenses during 2002. Other income (net) increased $8.1 million primarily due to reduced
charitable contribution commitments. Other interest charges decreased $2.6 million resulting from the RP95-409
rate case settlement refund paid to customers in August 2001. Allowance for borrowed funds used during construction increased $2.2
million as a result of the increase in expenditures for capital projects,
including expansion projects. 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 -13-




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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 WGP, by accessing capital
markets, and, if required, by borrowings under the Credit Agreement and
advances from WGP. Historically, we have also funded our capital requirements
through a sale of receivables program. In July 2002, our sale of receivables
program expired and was not renewed. We have an effective registration statement on file with the SEC. At
December 31, 2003, approximately $150 million of shelf availability remains
under this registration statement, which may be used to issue debt securities.
Interest rates and market conditions will affect amounts borrowed, if any,
under this arrangement. 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. However, the ability to utilize
this registration statement is restricted by certain covenants associated with
Williams $800 million 8.625 percent senior unsecured notes that were issued in
2003. On March 4, 2003, we issued $175 million of 8.125 percent senior notes due
2010. We used the proceeds for general corporate purposes, including the
funding of capital expenditures. On June 6, 2003, Williams entered into a two-year $800 million revolving
and letter of credit facility (Credit Agreement), primarily for the purpose
of issuing letters of credit. Williams, Transco and Northwest have access to
all unborrowed amounts under the facility. The facility must be secured by
cash and/or acceptable government securities with a market value of at least
105 percent of the then outstanding aggregate amount available for drawing
under all letters of credit, plus the aggregate amount of all loans then
outstanding. The new credit facility replaced a $1.1 billion credit line
entered into in July 2002 that was comprised of a $700 million secured
revolving credit facility and a $400 million letter of credit facility secured
by substantially all of Williams midstream assets. The lenders released these
assets as collateral upon repayment of the old credit facility, and they were
not pledged in support of the new facility. The interest rate on the new
facility is variable at the London Interbank Offered Rate (LIBOR) plus 0.75
percent, or 1.87 percent at December 31, 2003. As of December 31, 2003,
letters of credit totaling $353 million have been issued by the participating
financial institutions under this facility and remain outstanding. No
revolving credit loans were outstanding. At December 31, 2003, the amount of
restricted investments securing this facility was $381 million, which
collateralized the facility at approximately 108 percent. As a participant in Williams cash management program, we make advances to
and receive advances from Williams through our parent company, WGP. At
December 31, 2003, the advances due to us by WGP totaled $86.4 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 made by WGP, which in turn allows WGP to repay us. Order Nos. 634 and 634-A (Docket No. RM02-14-000)On August 1, 2002, the
FERC issued a NOPR that proposed restrictions on various types of cash
management programs employed by companies in the energy industry such as
Williams and its subsidiaries, including us. In addition to stricter
guidelines regarding the accounting for and documentation of cash management or
cash pooling programs, the FERC proposal would have precluded public utilities,
natural gas companies and oil pipeline companies from participating in such
programs unless the parent company and its FERC-regulated affiliate maintain
investment-grade credit ratings and the FERC-regulated affiliate maintains
stockholders equity of at least 30 percent of total capitalization. On June
26, 2003, the FERC issued an Interim Rule (Order No. 634), which replaced the
earlier NOPR on cash management described above. The Interim Rule required
FERC-regulated entities to have their cash management programs in writing and
to have all such programs specify (i) the duties and responsibilities of
administrators and participants, (ii) the methods for calculating -14-




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interest and for allocating interest and expenses, and (iii) restrictions on
borrowing from the programs. The Interim Rule also sought industry comment on
new reporting requirements that would require FERC-regulated entities to file
their cash management programs with the FERC and to notify the FERC when their
proprietary capital ratio drops below 30 percent of total capitalization and
when it subsequently returns to or exceeds 30 percent. On October 23, 2003,
the FERC issued Order No. 634-A, which adopted the filing and reporting
requirements proposed in the Interim Rule, with certain modifications. On
February 11, 2004, the FERC issued a Final Rule (Order No. 646), which amends
its financial reporting regulations and as part of those amendments eliminated
the notification requirement related to a FERC-regulated entitys proprietary
capital ratio adopted in Order No. 634-A. The FERC found that the amended
financial reporting requirements will provide the FERC with the information
necessary to monitor the FERC regulated entitys proprietary capital ratio. 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. In the second quarter of 2003, 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+, which did not change
during 2003. Moodys Investors Service
    
    B3 to B1Fitch Ratings
    
    BB- to BB
 Currently, Moodys Investors Service and Standard & Poors have our credit
ratings on developing outlook and negative outlook, respectively. During
2002, our credit ratings were downgraded to below investment grade due to
concerns about the sufficiency of Williams operating cash flow in relation to
its debt as well as the adequacy of Williams liquidity. The credit rating
level has remained below investment grade throughout 2003. The ratings remain
under review pending the execution of Williams plan to strengthen its
financial position. We expect that interest rates on future financings will be
reflective of the ratings at the time of the financing. CAPITAL EXPENDITURES Our expenditures for property, plant and equipment additions were $294.5
million, $181.8 million and $94.9 million for 2003, 2002 and 2001,
respectively. We anticipate 2004 capital expenditures will total approximately
$117 million, of which approximately $100 million will be for maintenance
capital expenditures and other non-expansion related items including
expenditures required for the 26-inch line and the Pipeline Safety Improvement
Act of 2002. The remaining expenditures required to restore the 26-inch line
are planned for 2005 and 2006. Funding for these activities will be provided
by cash flows from operating activities, by repayments of funds advanced to
WGP, by accessing capital markets and, if required, by borrowings under the
Credit Agreement and advances from WGP. We anticipate filing a rate case to
recover these costs coincident with the in-service date of the facilities. -15-




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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 -
    
    2007 -
    
    There-2004
    
    2006
    
    2008
    
    after
    
    TotalLong-term debt,
including current
portion:Principal
    
    $
    7.5
    
    
    $
    15.0
    
    
    $
    252.9
    
    
    $
    260.0
    
    
    $
    535.4Interest
    
    
    39.1
    
    
    
    76.2
    
    
    
    57.4
    
    
    
    124.3
    
    
    
    297.0Capital leases
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Operating leases
    
    
    8.8
    
    
    
    15.2
    
    
    
    12.7
    
    
    
    6.4
    
    
    
    43.1Purchase Obligations:Natural gas purchase,
storage and
transportation
    
    
    21.6
    
    
    
    6.6
    
    
    
    5.3
    
    
    
    
    
    
    
    33.5Other
    
    
    .4
    
    
    
    .8
    
    
    
    .5
    
    
    
    .7
    
    
    
    2.4Total
    
    $
    77.4
    
    
    $
    113.8
    
    
    $
    328.8
    
    
    $
    391.4
    
    
    $
    911.4
 Regulatory and Legal Proceedings Reference is made to Note 2 of the Notes to Financial Statements for
information about judicial 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 WGP, advances or capital
contributions from Williams and borrowings under the Credit Agreement will
provide us with sufficient liquidity to meet our capital requirements. When
necessary, we also expect to access public and private markets on terms
commensurate with our current credit ratings to finance our capital
requirements. 
 Item 7A. QUALITATIVE AND QUANTITATIVE DISCLOSURES ABOUT MARKET RISK Interest Rate Risk Our interest rate risk exposure is limited to its long-term debt. All
interest rates on long-term debt are fixed in nature. -16-




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The following table provides information about our long-term debt,
including current maturities, as of December 31, 2003. The table presents
principle cash flows (at face value) and weighted-average interest rates by
expected maturity dates. December 31, 2003 Expected Maturity Date2004
    
    2005
    
    2006
    
    2007
    
    2008
    
    Thereafter
    
    Total
    
    Fair Value(millions of dollars)Long-term debt,
including current
portion:Fixed rate
    
    $
    7.5
    
    
    $
    7.5
    
    
    $
    7.5
    
    
    $
    252.9
    
    
    $
    
    
    
    $
    260.0
    
    
    $
    535.4
    
    
    $
    572.6Interest rate
    
    
    7.3
    %
    
    
    7.3
    %
    
    
    7.2
    %
    
    
    7.3
    %
    
    
    7.8
    %
    
    
    7.8
    %
 -17-




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Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA INDEX TO FINANCIAL STATEMENTS PageReport of independent auditors
    
    
    19Statement of income for the years ended
December 31, 2003, 2002 and 2001
    
    
    20Balance sheet at December 31, 2003 and 2002
    
    
    21Statement of common stockholders equity for the years ended
December 31, 2003, 2002 and 2001
    
    
    23Statement of comprehensive income for the years ended
December 31, 2003, 2002, and 2001
    
    
    24Statement of cash flows for the years ended
December 31, 2003, 2002 and 2001
    
    
    25Notes to financial statements
    
    
    26
 All schedules have been omitted since the required information is not
present or is not present in amounts sufficient to require submission of the
schedule or because the information required is included in the financial
statements and notes thereto. -18-




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REPORT OF INDEPENDENT AUDITORS The Board of Directors
Northwest Pipeline Corporation We have audited the accompanying balance sheets of Northwest Pipeline
Corporation as of December 31, 2003 and 2002, 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, 2003. These financial
statements are the responsibility of the Companys management. Our
responsibility is to express an opinion on these financial statements based on
our audits. We conducted our audits in accordance with auditing standards generally
accepted in the 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. An audit includes examining, on
a test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used
and significant estimates made by management, as well as 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, 2003 and 2002, and the results of its operations
and its cash flows for each of the three years in the period ended December 31,
2003, in conformity with accounting principles generally accepted in the United
States. /s/ ERNST & YOUNG LLP Houston, Texas
February 18, 2004 -19-




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NORTHWEST PIPELINE CORPORATION 
 STATEMENT OF INCOME (Thousands of Dollars) Years Ended December 31,2003
    
    2002
    
    2001OPERATING REVENUES
    
    $
    327,739
    
    
    $
    297,619
    
    
    $
    285,171OPERATING EXPENSES:General and administrative
    
    
    49,765
    
    
    
    49,338
    
    
    
    40,657Operation and maintenance
    
    
    27,770
    
    
    
    32,279
    
    
    
    37,000Depreciation
    
    
    66,735
    
    
    
    58,988
    
    
    
    58,654Regulatory (credits) charges
    
    
    (6,357
    )
    
    
    28
    
    
    
    Taxes, other than income taxes
    
    
    19,220
    
    
    
    12,352
    
    
    
    13,441Impairment charge (Note 8)
    
    
    25,643
    
    
    
    
    
    
    
    182,776
    
    
    
    152,985
    
    
    
    149,752Operating income
    
    
    144,963
    
    
    
    144,634
    
    
    
    135,419OTHER INCOME  net
    
    
    9,792
    
    
    
    10,374
    
    
    
    2,278INTEREST CHARGES:Interest on long-term debt
    
    
    37,144
    
    
    
    25,577
    
    
    
    25,670Other interest
    
    
    3,388
    
    
    
    2,688
    
    
    
    5,302Allowance
for borrowed funds used during construction
    
    
    (3,589
    )
    
    
    (2,638
    )
    
    
    (448
    )36,943
    
    
    
    25,627
    
    
    
    30,524INCOME BEFORE INCOME TAXES
    
    
    117,812
    
    
    
    129,381
    
    
    
    107,173PROVISION FOR INCOME TAXES
    
    
    44,518
    
    
    
    48,750
    
    
    
    40,132NET INCOME
    
    $
    73,294
    
    
    $
    80,631
    
    
    $
    67,041CASH DIVIDENDS ON COMMON STOCK
    
    $
    
    
    
    $
    
    
    
    $
    20,000
 See accompanying notes. -20-




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NORTHWEST PIPELINE CORPORATION BALANCE SHEET (Thousands of Dollars) December 31,2003
    
    2002ASSETSCURRENT ASSETS:Cash and cash equivalents
    
    $
    653
    
    
    $
    207Advances to
affiliates
    
    
    86,356
    
    
    
    17,282Accounts
receivableTrade, less reserves of $320 for 2003 and $486 for 2002
    
    
    31,731
    
    
    
    30,031Affiliated
companies
    
    
    578
    
    
    
    775Materials
and supplies, less reserves of $284 for 2003 and $500 for 2002
    
    
    9,500
    
    
    
    10,510Exchange gas due from others
    
    
    10,246
    
    
    
    1,995Exchange gas offset (Note 1)
    
    
    
    
    
    
    14,015Deferred income taxes
    
    
    4,232
    
    
    
    2,768Prepayments and other
    
    
    1,213
    
    
    
    1,335Total current assets
    
    
    144,509
    
    
    
    78,918PROPERTY, PLANT AND EQUIPMENT, at cost
    
    
    2,199,041
    
    
    
    1,937,096Less  Accumulated depreciation
    
    
    886,092
    
    
    
    832,531Total property, plant and equipment
    
    
    1,312,949
    
    
    
    1,104,565OTHER ASSETS:Deferred charges
    
    
    53,543
    
    
    
    49,190Regulatory assets
    
    
    6,385
    
    
    
    Total other assets
    
    
    59,928
    
    
    
    49,190Total assets
    
    $
    1,517,386
    
    
    $
    1,232,673
 See accompanying notes. -21-




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NORTHWEST PIPELINE CORPORATION 
 BALANCE SHEET (Thousands of Dollars) December 31,2003
    
    2002LIABILITIES AND STOCKHOLDERS EQUITYCURRENT LIABILITIES:Accounts payable-Trade
    
    $
    18,609
    
    
    $
    20,502Affiliated companies
    
    $
    13,076
    
    
    $
    7,547Accrued liabilities -Income taxes due to affiliate
    
    
    1,444
    
    
    
    12,138Taxes, other than income taxes
    
    
    8,521
    
    
    
    2,932Interest
    
    
    7,694
    
    
    
    3,117Employee costs
    
    
    930
    
    
    
    8,075Exchange gas due to others
    
    
    4,757
    
    
    
    16,010Exchange gas offset (Note 1)
    
    
    5,489
    
    
    
    Other
    
    
    2,256
    
    
    
    877Current maturities of long-term debt
    
    
    7,500
    
    
    
    7,500Total current liabilities
    
    
    70,276
    
    
    
    78,698LONG-TERM DEBT, LESS CURRENT MATURITIES
    
    
    527,542
    
    
    
    360,023DEFERRED INCOME TAXES
    
    
    221,674
    
    
    
    164,818DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES
    
    
    27,935
    
    
    
    35,295CONTINGENT 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
    
    
    407,502
    
    
    
    334,208Accumulated other comprehensive loss
    
    
    (388
    )
    
    
    (3,214
    )Total common stockholders equity
    
    
    669,959
    
    
    
    593,839Total liabilities and stockholders equity
    
    $
    1,517,386
    
    
    $
    1,232,673
 See accompanying notes. -22-




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NORTHWEST PIPELINE CORPORATION 
 STATEMENT OF COMMON STOCKHOLDERS EQUITY(Thousands of Dollars) Years Ended December 31,2003
    
    2002
    
    2001Common 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
    
    
    334,208
    
    
    
    253,577
    
    
    
    206,536Net income
    
    
    73,294
    
    
    
    80,631
    
    
    
    67,041Cash dividends
    
    
    
    
    
    
    
    
    
    
    (20,000
    )Balance at end of period
    
    
    407,502
    
    
    
    334,208
    
    
    
    253,577Accumulated
other comprehensive income 
    
    
    
    
    
    
    
    
    
    
    Balance at beginning of period
    
    
    (3,214
    )
    
    
    
    
    
    
    Minimum pension liability adjustment
    
    
    2,826
    
    
    
    (3,214
    )
    
    
    Balance at end of period
    
    
    (388
    )
    
    
    (3,214
    )
    
    
    Total common stockholders equity
    
    $
    669,959
    
    
    $
    593,839
    
    
    $
    516,422
 See accompanying notes. -23-




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NORTHWEST PIPELINE CORPORATION 
 STATEMENT OF COMPREHENSIVE INCOME (Thousands of Dollars) Years Ended December 31,2003
    
    2002
    
    2001Net Income
    
    $
    73,294
    
    
    $
    80,631
    
    
    $
    67,041Minimum pension liability adjustment, net of tax
    
    
    2,826
    
    
    
    (3,214
    )
    
    
    Total comprehensive income
    
    $
    76,120
    
    
    $
    77,417
    
    
    $
    67,041
 See accompanying notes. -24-




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NORTHWEST PIPELINE CORPORATION 
 STATEMENT OF CASH FLOWS(Thousands of Dollars) Years Ended December 31,2003
    
    2002
    
    2001OPERATING ACTIVITIES:Net Income
    
    $
    73,294
    
    
    $
    80,631
    
    
    $
    67,041Adjustments to reconcile to net cash provided by
operating activities -Depreciation
    
    
    66,735
    
    
    
    58,988
    
    
    
    58,654Regulatory (credits) charges
    
    
    (6,357
    )
    
    
    28
    
    
    
    Provision for deferred income taxes
    
    
    51,735
    
    
    
    15,956
    
    
    
    3,163Provision for loss on property
    
    
    25,643
    
    
    
    
    
    
    
    Amortization of deferred charges and credits
    
    
    4,523
    
    
    
    139
    
    
    
    1,871Allowance for equity funds used during construction
    
    
    (8,600
    )
    
    
    (5,496
    )
    
    
    (826
    )Reserve for doubtful accounts
    
    
    (166
    )
    
    
    348
    
    
    
    138Changes in:Accounts receivable and exchange gas due from
others
    
    
    (7,682
    )
    
    
    (12,639
    )
    
    
    23,469Materials and supplies
    
    
    1,010
    
    
    
    499
    
    
    
    (211
    )Other current assets
    
    
    14,137
    
    
    
    (653
    )
    
    
    (5,459
    )Deferred charges
    
    
    (1,546
    )
    

    
    (948
    )
    
    
    7,705Accounts payable, income taxes due to
affiliate and exchange gas due to others
    
    
    12,654
    
    
    
    (2,940
    )
    
    
    (19,234
    )Other accrued liabilities
    
    
    (6,294
    )
    
    
    2,931
    
    
    
    (29,609
    )Other deferred credits
    
    
    (253
    )
    
    
    (359
    )
    
    
    (653
    )Other
    
    
    (25
    )
    
    
    2
    
    
    
    (143
    )Net cash provided by operating activities
    
    
    218,808
    
    
    
    136,487
    
    
    
    105,906INVESTING ACTIVITIES:Property, plant and equipment -Capital expenditures
    
    
    (294,524
    )
    
    
    (181,843
    )
    
    
    (94,923
    )Proceeds from sales
    
    
    
    
    
    
    4,586
    
    
    
    3,155Asset removal cost
    
    
    (1,898
    )
    
    
    
    
    
    
    Changes in accounts payable
    
    
    (14,782
    )
    
    
    (14,257
    )
    
    
    25,935Repayments from (Advances to) affiliates
    
    
    (69,074
    )
    
    
    54,791
    
    
    
    (18,191
    )Net cash used by investing activities
    
    
    (380,278
    )
    
    
    (136,723
    )
    
    
    (84,024
    )FINANCING ACTIVITIES:Proceeds from issuance of long-term debt
    
    
    175,000
    
    
    
    
    
    
    
    Principal payments on long-term debt
    
    
    (7,500
    )
    
    
    
    
    
    
    (3,329
    )Debt issuance costs
    
    
    (5,584
    )
    
    
    
    
    
    
    Dividends paid
    
    
    
    
    
    
    
    
    
    
    (20,000
    )Net cash used by financing activities
    
    
    161,916
    
    
    
    
    
    
    
    (23,329
    )NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS
    
    
    446
    
    
    
    (236
    )
    
    
    (1,447
    )CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR
    
    
    207
    
    
    
    443
    
    
    
    1,890CASH AND CASH EQUIVALENTS AT END OF YEAR
    
    $
    653
    
    
    $
    207
    
    
    $
    443  See accompanying notes. -25-




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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,
2003, we had approximately $16.1 million of regulatory assets included in Other
Assets: Deferred Charges and approximately $11.8 million of regulatory
liabilities included in Deferred Credits and Other Noncurrent Liabilities on
the accompanying Balance Sheet. At December 31, 2002, we had approximately
$14.1 million of regulatory assets included in Other Assets: Deferred Charge
and approximately $11.0 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 $84.9 million, as of
December 31, 2003, 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 -26-




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NORTHWEST PIPELINE CORPORATION NOTES TO FINANCIAL STATEMENTS or information could change those estimates include: 1) revenues
subject to refund; 2) litigation-related contingencies; 3) environmental
remediation obligations; 4) impairment assessments of long-lived assets; 5)
deferred and other income taxes; 6) depreciation; and 7) pension and other
post-employment benefits. 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, 2.94 percent and
2.98 percent for 2003, 2002 and 2001, 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 2003, we recorded regulatory credits totaling $6.4 million in the
accompanying Statement of Income. Of that amount, approximately $2.2 million
relates primarily to the levelized depreciation for the Evergreen Project
discussed above. In addition, a regulatory asset of approximately $4.2 million
was also recognized related to depreciation and accrued income associated with
incremental Evergreen compression facilities that were placed in-service prior
to the full project completion on October 1, 2003. Such amounts will be
amortized over the primary terms of the Evergreen shipper agreements as such
costs are collected through rates. Effective January 1, 2003, Williams and its subsidiaries, including us,
adopted SFAS No. 143, Accounting for Asset Retirement Obligations. The
Statement requires that the fair value of a liability for an asset retirement
obligation be recognized in the period in which it is incurred if a reasonable
estimate of fair value can be made, and that the associated asset retirement
costs be capitalized as part of the carrying amount of the long-lived asset.
We have not recorded asset retirement liabilities for our pipeline transmission
assets, since a reasonable estimate of the fair value of the retirement
obligations for these assets cannot be made, as the remaining life of these
assets is not currently determinable. Accordingly, the impact of adopting SFAS
No. 143 did not have a material effect on our financial position or results of
operations. The adoption of SFAS No. 143 had no material impact to operating
income or net income. 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 143, the negative salvage component of
Accumulated Depreciation, $11.6 million and $9.8 million at December 31, 2003
and 2002, respectively, was reclassified to a Noncurrent Regulatory Liability. 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. -27-




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NORTHWEST PIPELINE CORPORATION NOTES TO FINANCIAL STATEMENTS The composite rate used to capitalize AFUDC was approximately 10.1
percent, 10.0 percent and 9.9 percent for 2003, 2002 and 2001, respectively.
Equity AFUDC of $8.6 million, $5.5 million and $.8 million for 2003, 2002 and
2001, respectively, is reflected in Other Income  net. Advances to Affiliates As a participant in Williams cash management program, we make advances to
and receive advances from Williams through WGP. 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. 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 was based on the London
Interbank Offering Rate (LIBOR) plus an applicable margin. 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. -28-




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NORTHWEST PIPELINE CORPORATION NOTES TO FINANCIAL STATEMENTS 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 average of the spot market rates at
the Canadian border and the Rocky Mountain market as published in Inside
FERCs Gas Market Report. Settlement of imbalances requires agreement between
the pipelines and shippers as to allocations of volumes to specific
transportation contracts and timing of delivery of gas based on operational
conditions. The exchange gas offset represents the gas balance in our system
representing the difference between the exchange gas due to us from customers
and the exchange gas that we owe to customers. 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 $29.1 million, $22.9 million and $39.9
million, net of $3.6 million, $2.6 million and $0.4 million of interest
capitalized (allowance for borrowed funds used during construction) in 2003,
2002 and 2001, respectively. -29-




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NORTHWEST PIPELINE CORPORATION NOTES TO FINANCIAL STATEMENTS 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 31,2003
    
    2002
    
    2001(Thousands of Dollars)Net income, as reported
    
    $
    73,294
    
    
    $
    80,631
    
    
    $
    67,041Deduct: Total stock-based employee
compensation expense determined under
fair value based method for all
awards, net of tax
    
    
    626
    
    
    
    365
    
    
    
    401Pro forma net income
    
    $
    72,668
    
    
    $
    80,266
    
    
    $
    66,640
 Pro forma amounts for 2003 include compensation expense from Williams
awards made in 2003, 2002, and 2001. Also included in the 2003 pro forma
expense is $84,756 of incremental expense associated with a stock option
exchange program. (See Note 4.) Pro forma amounts for 2002 include
compensation expense from Williams awards made in 2002 and 2001 and from
certain Williams awards made in 1999. Pro forma amounts for 2001 include
compensation expense from Williams awards made in 2001 and from certain
Williams awards made in 1999. 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 Standards The FASB issued SFAS No. 146, Accounting for Costs Associated with Exit
or Disposal Activities. This statement addresses financial accounting and
reporting for costs associated with exit or disposal activities and nullifies
Emerging Issues Task Force Issue No. 94-3, Liability Recognition for Certain
Employee Termination Benefits and Other Costs to Exit an Activity (including
Certain Costs Incurred in a Restructuring). This statement requires that a
liability for a cost associated with an exit or disposal activity be recognized
and measured initially at fair value only when the liability is incurred. The
provisions of the statement are effective for exit or disposal activities that
are initiated after December 31, 2002; hence, initial adoption of this
statement on January 1, 2003, did not have any impact on our results of
operations or financial position. The FASB issued SFAS No. 148, Accounting for Stock-Based Compensation -
Transition and Disclosure, which is effective for fiscal years ending after
December 15, 2002. SFAS No. 148 amends SFAS No. 123, Accounting for
Stock-Based Compensation, to permit two additional transition methods for a
voluntary change to the fair value based method of accounting for stock-based
employee compensation from the intrinsic method under APB Opinion No. 25,
Accounting for Stock Issued to Employees. The prospective method of
transition under SFAS No. 123 is an option to the entities that adopt the
recognition provisions under this statement in a fiscal year beginning before
December 15, 2003. In addition, SFAS No. 148 amends the disclosure
requirements of SFAS No. 123 to require prominent disclosures in both annual
and interim financial statements concerning the method of accounting used for
stock-based employee compensation and the effects of that method on reported
results of operations. Under SFAS No. 148, pro forma disclosures are required
in a specific tabular format in the Summary of Significant Accounting
Policies. We have adopted the disclosure -30-




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NORTHWEST PIPELINE CORPORATION NOTES TO FINANCIAL STATEMENTS requirements of this statement effective December 31, 2002. The adoption had
no effect on our financial position or results of operations. We continue to
account for Williams stock-based compensation plans under APB Opinion No. 25.
The FASB has announced it will be issuing an Exposure Draft on equity-based
compensation. In deliberations on this matter, the FASB has concluded that
equity-based compensation awards to employees result in an expense to the
employer that should be recognized in the income statement. See Employee
Stock-Based Awards in this note. In January 2003, the FASB issued Interpretation No. 46, Consolidation of
Variable Interest Entities. The Interpretation defines a variable interest
entity (VIE) as an entity in which equity investors do not have the
characteristics of a controlling financial interest or do not have sufficient
equity at risk for the entity to finance its activities without additional
subordinated financial support from other parties. The investments or other
interests that will absorb portions of the VIEs expected losses if they occur
or receive portions of the VIEs expected residual returns if they occur are
called variable interests. Variable interests may include, but are not limited
to, equity interests, debt instruments, beneficial interests, derivative
instruments and guarantees. The Interpretation requires an entity to
consolidate a VIE if that entity will absorb a majority of the VIEs expected
losses if they occur, receive a majority of the VIEs expected residual returns
if they occur, or both. If no party will absorb a majority of the expected
losses or expected residual return, no party will consolidate the VIE. The
Interpretation also requires disclosure of significant variable interests in
unconsolidated VIEs. The Interpretation is effective for all new VIEs
created or acquired after January 31, 2003. For VIEs created or acquired
prior to February 1, 2003, the provisions of the Interpretation were initially
to be effective for the first interim or annual period beginning after June 15,
2003. However, in October 2003, the FASB delayed the effective date of the
Interpretation on these entities to the first period beginning after December
15, 2003. Additionally, in December 2003, the FASB issued a revision to the
Interpretation to clarify certain provisions and to exempt certain entities
from its requirements. The revised Interpretation will require full
implementation in the first quarter of 2004. We do not have any VIEs as
defined by the Interpretation. Reclassifications Certain reclassifications have been made in the 2002 and 2001 financial
statements to conform to the 2003 presentation. 2. CONTINGENT LIABILITIES AND COMMITMENTS Legal Proceedings In 1998, the United States Department of Justice (DOJ) informed Williams
that Jack Grynberg, an individual, had filed claims in the United States
District Court for the District of Colorado under the False Claims Act against
Williams and certain of its wholly-owned subsidiaries including us. Mr.
Grynberg had also filed claims against approximately 300 other energy companies
and alleged that the defendants violated the False Claims Act in connection
with the measurement, royalty valuation and purchase of hydrocarbons. The
relief sought was an unspecified amount of royalties allegedly not paid to the
federal government, treble damages, a civil penalty, attorneys fees and costs.
In April 1999, the DOJ declined to intervene in any of the Grynberg qui tam
cases; 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. 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 -31-




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NORTHWEST PIPELINE CORPORATION NOTES TO FINANCIAL STATEMENTS 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 In December 2003, the United States Department of Transportation Office of
Pipeline Safety issued a final rule pursuant the requirements of the Pipeline
Safety Improvement Act of 2002 that was enacted in December 2002. The rule
requires gas pipeline operators to develop integrity management programs for
transmission pipelines that could affect high consequence areas in the event of
pipeline failure, 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 2003 to 2012 period. Developing and implementing the
required public education program, including a process for measuring and
evaluating the effectiveness of safety information distributed to various
stakeholder groups, is expected to cost less than $1 million. Our management
considers the costs associated with compliance with the rule to be prudent
costs incurred in the ordinary course of business and, therefore, recoverable
through our rates. Other Matters In addition to the foregoing, various other proceedings are pending
against us incidental to our operations. Summary Litigation, arbitration, regulatory matters and environmental 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 net
income of 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 materially adverse effect upon our future
financial position. Other Commitments We have commitments for construction and acquisition of property, plant
and equipment of approximately $15.9 million at December 31, 2003. We are developing a plan to replace the capacity of our 26-inch line
damaged by the pipeline breaks in 2003. The estimated combined cost to
inspect, hydrostatically test, temporarily restore a portion of the line to
service, and to ultimately replace up to the entire 360 MDth per day of
capacity, if required, by the end of 2006 is estimated to range between $365
million and $430 million. Funding for these activities will be provided by
cash flows from operating activities, by repayments of funds advanced to WGP,
by accessing capital markets, and, if required, by borrowings under the $800
million revolving and letter of credit facility (See Note 3) and advances from
WGP. We anticipate filing a rate case to recover these costs coincident with
the in-service date of the facilities. 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. -32-




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NORTHWEST PIPELINE CORPORATION NOTES TO FINANCIAL STATEMENTS Long-Term Debt Long-term debt consists of the following: December 31,2003
    
    20026.625%, payable 2007
    
    $
    250,000
    
    
    $
    250,0007.125%, payable 2025
    
    
    84,751
    
    
    
    84,7408.125%, payable 2010
    
    
    175,000
    
    
    
    9%, payable 2004 through 2007
    
    
    25,291
    
    
    
    32,783Total long-term debt
    
    
    535,042
    
    
    
    367,523Less current maturities
    
    
    7,500
    
    
    
    7,500Total long-term debt, less current maturities
    
    $
    527,542
    
    
    $
    360,023
 As of December 31, 2003, 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 ofDollars)2004
    
    $
    7,5002005
    
    
    7,5002006
    
    
    7,5002007
    
    
    252,8672008
    
    
    Thereafter
    
    
    260,000Total
    
    $
    535,367
 Line-of-Credit Arrangements On June 6, 2003, Williams entered into a two-year $800 million revolving
and letter of credit facility, primarily for the purpose of issuing letters of
credit. Williams, Transco, a subsidiary of WGP, and Northwest have access to
all unborrowed amounts under the facility. The facility must be secured by
cash and/or acceptable government securities with a market value of at least
105 percent of the then outstanding aggregate amount available for drawing
under all letters of credit, plus the aggregate amount of all loans then
outstanding. The new credit facility replaced a $1.1 billion credit line
entered into in July 2002 that was comprised of a $700 million secured
revolving credit facility and a $400 million letter of credit facility secured
by substantially all of Williams midstream assets. The lenders released these
assets as collateral upon repayment of the old credit facility, and they were
not pledged in support of the new facility. The interest rate on the new
agreement is variable at the London Interbank Offered Rate (LIBOR) plus 0.75
percent, or 1.87 percent at December 31, 2003. At December 31, 2003, letters
of credit totaling $353 million have been issued by the participating financial
institutions under this facility and remain outstanding. No revolving credit
loans were outstanding. At December 31, 2003, the amount of restricted
investments securing this facility was $381 million, which collateralized the
facility at approximately 108 percent. -33-




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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)2004
    
    $
    8,8222005
    
    
    8,8232006
    
    
    6,3702007
    
    
    6,3712008
    
    
    6,370Thereafter
    
    
    6,370$
    43,126Less: noncancelable
subleases
    
    
    3,780Total
    
    $
    39,346
 Operating lease rental expense amounted to $5.2 million, $5.4 million and
$6.1 million for 2003, 2002 and 2001, respectively. 4. EMPLOYEE BENEFIT PLANS Pension and Postretirement Medical Plans Our employees are covered by Williams non-contributory defined-benefit
pension plan 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 $8.9 million, $5.9 million and $2.3 million in 2003, 2002 and 2001,
respectively. These amounts are currently recoverable in our rates. At December 31, 2002, we recorded minimum pension liability of $3.2
million, net of $2.0 million tax. At December 31, 2003, we recorded a credit
adjustment to the minimum pension liability of $2.8 million, net of $1.8
million tax. Minimum pension liability is included as a component of our Other
Comprehensive income for the years 2003 and 2002. Defined Contribution Plan Our employees are also covered by various Williams defined contribution
plans. Our costs related to these plans totaled $1.5 million, $2.3 million and
$2.1 million in 2003, 2002 and 2001, respectively. -34-




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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,
including us. 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 the 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 expense on the cancelled Williams options is being amortized through
year-end 2004. The following summary provides information about our employees stock
option activity related to Williams common stock for 2003, 2002 and 2001
(options in thousands): 2003
    
    2002
    
    2001Weighted
    
    
    
    
    
    Weighted
    
    
    
    
    
    WeightedAverage
    
    
    
    
    
    Average
    
    
    
    
    
    AverageExercise
    
    
    
    
    
    Exercise
    
    
    
    
    
    ExerciseOptions
    
    Price
    
    Options
    
    Price
    
    Options
    
    PriceOutstanding - beginning of year
    
    
    1,511
    
    
    $
    19.40
    
    
    
    1,291
    
    
    $
    24.38
    
    
    
    1,200
    
    
    $
    24.02Granted
    
    
    165
    *
    
    $
    10.00
    
    
    
    527
    
    
    $
    7.27
    
    
    
    159
    
    
    $
    38.00Exercised
    
    
    (7
    )
    
    $
    8.06
    
    
    
    (26
    )
    
    $
    9.59
    
    
    
    (112
    )
    
    $
    11.82Forfeited/expired
    
    
    (522
    )**
    
    $
    25.45
    
    
    
    (484
    )
    
    $
    24.59
    
    
    
    (21
    )
    
    $
    32.81Adjustment for WCG spinoff (1)
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    111
    
    
    
    Employee transfers, net
    
    
    88
    
    
    
    
    
    
    
    203
    
    
    
    
    
    
    
    (46
    )
    
    
    Outstanding - end of year
    
    
    1,235
    
    
    $
    16.02
    
    
    
    1,511
    
    
    $
    19.40
    
    
    
    1,291
    
    
    $
    24.38Exercisable at year end
    
    
    734
    
    
    $
    23.35
    
    
    
    1,040
    
    
    $
    24.45
    
    
    
    1,102
    
    
    $
    22.58
  *
    
    All of the 2003 Williams stock options granted relate to the Williams
stock option exchange program described above.**
    
    Includes 413,455 shares that were cancelled on June 26, 2003, under the
Williams stock option exchange program, described above.  (1)
    
    Effective with the spinoff of WilTel Communications, formerly Williams
Communications Group on April 23, 2001, by Williams, the number and
exercise price of unexercised Williams stock options were adjusted to
preserve the intrinsic value of the stock options that existed prior to
the spinoff. -35-




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NORTHWEST PIPELINE CORPORATION NOTES TO FINANCIAL STATEMENTS The following summary provides information about Williams common stock
options that are outstanding and exercisable by our employees at December 31,
2003 (options in thousands): Stock Options Outstanding
    
    Stock Options ExercisableWeightedAverageWeighted
    
    Remaining
    
    
    
    
    
    WeightedRange of Exercise
    
    
    
    
    
    Average
    
    Contractual
    
    
    
    
    
    AveragePrices
    
    Options
    
    Exercise Price
    
    Life (yrs)
    
    Options
    
    Exercise Price$2.27 to $10.00
    
    
    575
    
    
    $
    5.43
    
    
    
    6.9
    
    
    
    81
    
    
    $
    7.71$10.39 to $15.89
    
    
    260
    
    
    $
    14.34
    
    
    
    2.4
    
    
    
    255
    
    
    $
    14.31$20.83 to $31.56
    
    
    170
    
    
    $
    24.88
    
    
    
    2.8
    
    
    
    169
    
    
    $
    24.88$34.54 to $42.29
    
    
    230
    
    
    $
    37.82
    
    
    
    3.5
    
    
    
    229
    
    
    $
    37.841,235
    
    
    $
    16.02
    
    
    
    4.7
    
    
    
    734
    
    
    $
    23.35
 The estimated fair value at the date of grant of options for Williams
common stock granted in 2003, 2002 and 2001, using the Black-Scholes
option-pricing model is as follows: 2003(a)
    
    2002
    
    2001Weighted-average grant date fair
value of options for Williams common
stock granted during the year
    
    $
    2.95
    
    
    $
    2.77
    
    
    $
    10.93AssumptionsDividend yield
    
    
    1.0
    %
    
    
    1.0
    %
    
    
    1.9
    %Volatility
    
    
    50
    %
    
    
    56
    %
    
    
    35
    %Risk-free interest rate
    
    
    3.1
    %
    
    
    3.6
    %
    
    
    4.8
    %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. Pro forma net income, assuming we had applied the fair-value method of
SFAS No. 123, Accounting for Stock-Based Compensation in measuring
compensation cost beginning with 1997 Williams stock-based awards granted to
our employees is disclosed under Employee Stock-Based Awards in Note 1. -36-




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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 31,2003
    
    2002(Thousands of Dollars)Property, plant and equipment
    
    $
    208,605
    
    
    $
    155,927Regulatory assets
    
    
    10,269
    
    
    
    6,223Loss on reacquired debt
    
    
    5,780
    
    
    
    6,482Other  net
    
    
    1,016
    
    
    
    799Deferred tax liabilities
    
    
    225,670
    
    
    
    169,431Regulatory liabilities
    
    
    74
    
    
    
    500Accrued liabilities
    
    
    4,472
    
    
    
    6,881Loss carryovers
    
    
    3,514
    
    
    
    Minimum tax credits
    
    
    168
    
    
    
    Deferred tax assets
    
    
    8,228
    
    
    
    7,381Net deferred tax liabilities
    
    $
    217,442
    
    
    $
    162,050Reflected as:Deferred income taxes  current asset
    
    $
    4,232
    
    
    $
    2,768Deferred income taxes  noncurrent liability
    
    
    221,674
    
    
    
    164,818$
    217,442
    
    
    $
    162,050
 The provision for income taxes includes: Year Ended December 31,2003
    
    2002
    
    2001(Thousands of Dollars)Current:Federal
    
    $
    (6,058
    )
    
    $
    29,305
    
    
    $
    33,036State
    
    
    (1,159
    )
    
    
    3,489
    
    
    
    3,933(7,217
    )
    
    
    32,794
    
    
    
    36,969Deferred:Federal
    
    
    45,636
    
    
    
    14,461
    
    
    
    2,827State
    
    
    6,099
    
    
    
    1,495
    
    
    
    33651,735
    
    
    
    15,956
    
    
    
    3,163Total provision
    
    $
    44,518
    
    
    $
    48,750
    
    
    $
    40,132
 -37-




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NORTHWEST PIPELINE CORPORATION NOTES TO FINANCIAL STATEMENTS A reconciliation of the statutory Federal income tax rate to the provision
for income taxes is as follows: Year Ended December 31,2003
    
    2002
    
    2001(Thousands of Dollars)Provision at statutory Federal income tax
rate of 35 Percent
    
    $
    41,235
    
    
    $
    45,283
    
    
    $
    37,511Increase (decrease) in tax provision resulting from -State income taxes net of Federal tax benefit
    
    
    3,211
    
    
    
    3,240
    
    
    
    2,775Other  net
    
    
    72
    
    
    
    227
    
    
    
    (154
    )Provision for income taxes
    
    $
    44,518
    
    
    $
    48,750
    
    
    $
    40,132Effective tax rate
    
    
    37.79
    %
    
    
    37.68
    %
    
    
    37.45
    %
 Net cash payments made to Williams for income taxes were $3.5 million,
$29.7 million and $35.9 million in 2003, 2002 and 2001, 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 $535 million and $573 million,
respectively, at December 31, 2003, and $368 million and $328 million,
respectively, at December 31, 2002. -38-




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NORTHWEST PIPELINE CORPORATION NOTES TO FINANCIAL STATEMENTS 7. TRANSACTIONS WITH MAJOR CUSTOMERS AND AFFILIATES Concentration of Off-Balance-Sheet and Other Credit Risk During the periods presented, more than 10 percent of our operating
revenues were generated from each of the following customers: Year Ended December 31,2003
    
    2002
    
    2001(Thousands of Dollars)Puget Sound Energy, Inc.
    
    $
    40,732
    
    
    $
    42,116
    
    
    $
    43,919Northwest Natural Gas Co.
    
    
    38,437
    
    
    
    37,815
    
    
    
    39,203Duke Energy Trading and Marketing LLC
    
    
    33,739
    
    
    
    (a
    )
    
    
    (a
    )
  (a)
    
    Revenues were under 10 percent in this year. Our major customers are located in the Pacific Northwest. As a general
policy, collateral is not required for receivables, but customers financial
condition and credit worthiness are regularly evaluated and historical
collection losses have been minimal. We, through a wholly-owned bankruptcy remote subsidiary, sold certain
trade accounts receivable to a special-purpose entity (SPE) in a
securitization structure requiring annual renewal. We acted as the servicing
agent for the sold receivables. The sale of receivables program expired on July
25, 2002, and on July 26, 2002, we completed the repurchase of $15 million of
trade accounts receivable previously sold. 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 through our parent company, WGP. At December
31, 2003, the advances due us by WGP totaled $86.4 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. We
received interest income from advances to these affiliates of $2.7 million,
$1.6 million, and $3.1 million during 2003, 2002 and 2001, respectively. Such
interest income is included in Other Income  net on the accompanying Statement
of Income. Williams corporate overhead expenses allocated to us were $14.2 million,
$9.7 million and $6.9 million for 2003, 2002 and 2001, 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 $6.8 million, $4.6 million and $5.0 million
for 2003, 2002 and 2001, 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 $1.6 million, $2.2 million and $1.8 million for 2003,
2002 and 2001, 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. -39-




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NORTHWEST PIPELINE CORPORATION NOTES TO FINANCIAL STATEMENTS We have also entered into an interconnect agreement and an operation
balance agreement, each in connection with the Georgia Strait Crossing project,
with an affiliate of Williams. 8. Impairments 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. 9. Quarterly Information (Unaudited) The following is a summary of unaudited quarterly financial data for 2003
and 2002: Quarter of 2003First
    
    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. Quarter of 2002First
    
    Second
    
    Third
    
    Fourth(Thousands of Dollars)Operating revenues
    
    $
    71,617
    
    
    $
    73,228
    
    
    $
    73,042
    
    
    $
    79,704Operating income
    
    
    34,034
    
    
    
    31,645
    
    
    
    37,987
    
    
    
    40,968Net income
    
    
    18,377
    
    
    
    16,683
    
    
    
    22,211
    
    
    
    23,360
 Second quarter operating revenues include a $3.9 million expense for an
enhanced benefit early retirement option offered to certain Williams employee
groups. -40-




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Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE None. 
 Item 9A. CONTROLS AND PROCEDURES An evaluation of the effectiveness of the design and operation of our
disclosure controls and procedures (as defined in Rules 13a-15(e) and 15(d) -
(e) of the Securities Exchange Act) (Disclosure Controls) was performed as of
the end of the period covered by this report. This evaluation was performed
under the supervision and with the participation of our management, including
our Senior Vice President and Vice President and Treasurer. Based upon that
evaluation, our Senior Vice President and Vice President and Treasurer
concluded that, subject to the limitations noted below, these Disclosure
Controls and procedures are effective. Our management, including our Principal Executive Officer and Principal
Financial Officer, does not expect that our Disclosure Controls or our internal
controls over financial reporting (Internal Controls) will prevent all error
and all fraud. A control system, no matter how well conceived and operated,
can provide only reasonable, not absolute, assurance that the objectives of the
control system are met. Further, the design of a control system must reflect
the fact that there are resource constraints, and the benefits of controls must
be considered relative to their costs. Because of the inherent limitations in
all control systems, no evaluation of controls can provide absolute assurance
that all control issues and instances of fraud, if any, within the company have
been detected. These inherent limitations include the realities that judgments
in decision-making can be faulty, and that breakdowns can occur because of
simple error or mistake. Additionally, controls can be circumvented by the
individual acts of some persons, by collusion of two or more people, or by
management override of the control. The design of any system of controls also
is based in part upon certain assumptions about the likelihood of future
events, and there can be no assurance that any design will succeed in achieving
its stated goals under all potential future conditions. Because of the
inherent limitations in a cost-effective control system, misstatements due to
error or fraud may occur and not be detected. We monitor our Disclosure
Controls and Internal Controls and make modifications as necessary; our intent
in this regard is that the Disclosure Controls and the Internal Controls will
be modified as systems change and conditions warrant. There has been no change in our Internal Controls that occurred during the
registrants fourth fiscal quarter that has materially affected, or is
reasonably likely to materially affect, our Internal Controls. 
 PART III Since we meet the conditions set forth in General Instruction (I)(1)(a)
and (b) of Form 10-K, Items 10 through 13 are omitted. 
 Item 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES Fees for professional services provided by our independent auditors in
each of the last two fiscal years are as follows: 2003
    
    2002(Thousands ofDollars)Audit Fees
    
    $
    449
    
    
    $
    261Audit-Related Fees
    
    
    
    
    
    
    4Tax Fees
    
    
    
    
    
    
    All Other Fees
    
    
    
    
    
    
    Total Independent Auditor Fees
    
    $
    449
    
    
    $
    265
 -41-




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Fees for audit services include fees associated with the annual audit, the
reviews for our quarterly reports on Form 10-Q, the reviews for other SEC
filings and accounting consultation. Audit-related fees include agreed-upon
procedures and other attest services. There were no tax or other fees. 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 12, 2004. -42-




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PART IV 
 Item 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K (a) 1 and 2. Financial Statements and Schedules(included in Parts II and IV of this report). The financial statements are listed in the Index to Financial Statements
on page 18. No schedules are required to be filed. (a) 3. 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 Pipeline 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 Pipeline
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 Pipeline
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 Pipeline
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 Pipeline 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
Pipeline 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
Pipeline and Williams Field Services Company (Exhibit 10(c)(9) to
Pipeline Report on Form 10-K, No. 1-7414, filed March 26, 1992).*(b)
    
    U.S. $800,000,000 Credit Agreement dated as of June 6, 2003,
among The Williams Companies, Inc., Northwest Pipeline Corporation,
Transcontinental Gas Pipe Line Corporation, as Borrowers, Citibank,
N.A., as Administrative Agent and Collateral Agent, Bank of America,
N.A., as Syndication Agent, JPMorgan Chase Bank, as Documentation
Agent,
 -43-




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Citibank, N.A. and Bank of America, N.A. as Issuing Banks, the banks
named therein as Banks and Citigroup Global Markets Inc. and Banc of
America Securities LLC as Joint Lead Arrangers and Joint Book Runners.
(filed as Exhibit 10.3 to The Williams Companies, Inc. Form 10-Q for
the quarterly period ended June 30, 2003, Commission File Number
1-4174).
  (23)
    
    Consent of Independent Auditors(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. (b) Reports on Form 8-K: None.   *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 12, 2004 Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
registrant in the capacities and on the dates indicated. Signature
    
    Title/s/Steven J. Malcolm*
Steven J. Malcolm
    
    Chairman of the Board/s/J. Douglas Whisenant*
J. Douglas Whisenant
    
    Senior Vice President, Chief Executive Officer and Director
(Principal Executive Officer)/s/Richard D. Rodekohr*
Richard D. Rodekohr
    
    Vice President and Treasurer
(Principal Financial Officer)/s/Jeffrey P. Heinrichs*
Jeffrey P. Heinrichs
    
    Controller (Principal Accounting Officer)/s/Allison G. Bridges*
Allison G. Bridges
    
    Director*  By   /s/Jeffrey P. Heinrichs
Jeffrey P. HeinrichsAttorney-in-fact
 Date: March 12, 2004 -45-




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EXHIBIT INDEX Exhibit23
    
    Consent of Independent Auditors24
    
    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