NORTHWEST PIPELINE CORP - 10-K Annual Report

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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 1934

For the fiscal year ended December 31, 2002
or

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

For the Transition Period from _________________ to ___________________

Commission File Number 1-7414

NORTHWEST PIPELINE CORPORATION
(Exact name of registrant as specified in its charter)

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

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

(801) 583-8800
(Registrant's telephone number, including area code)

Securities Registered Pursuant to Section 12(b) of the Act:

None

Securities Registered Pursuant to Section 12(g) of the Act:

None

Indicate by check mark 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 February 28, 2003
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Common stock, $1 par value 1,000 shares

Documents Incorporated by Reference:
None

The registrant meets the conditions set forth in General Instruction (I)(1)(a)
and (b) of Form 10-K and is therefore filing this Form 10-K with the reduced
disclosure format.

TABLE OF CONTENTS

PART I

NORTHWEST PIPELINE CORPORATION

FORM 10-K

PART I

ITEM 1. BUSINESS

GENERAL

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

Pipeline is 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 Colorado, Utah,
Wyoming, Idaho, Oregon and Washington to a point on the Canadian border near
Sumas, Washington. Pipeline provides services for markets in California, New
Mexico, Colorado, Utah, Nevada, Wyoming, Idaho, Oregon and Washington directly
or indirectly through interconnections with other pipelines

Pipeline has significant future opportunities to provide service to
meet the demands of growing gas markets. Pipeline's geographical position allows
access to the incremental sources of supply required by these markets.

PIPELINE SYSTEM AND CUSTOMERS

TRANSPORTATION

At December 31, 2002, Pipeline's system, having an aggregate mainline
deliverability of approximately 2.9 Bcf* of gas per day, was composed of
approximately 4,000 miles of mainline and lateral transmission pipelines, and 43
mainline compressor stations having a combined sea level-rated capacity of
approximately 348,000 horsepower.

Pipeline operates under an open-access transportation certificate
wherein gas is transported for third party shippers. In 2002, Pipeline
transported natural gas for a total of 166 customers. Pipeline provides services
for markets in California, New Mexico, Colorado, Utah, Nevada, Wyoming, Idaho,
Oregon and Washington. Transportation customers include distribution companies,
municipalities, interstate and intrastate pipelines, gas marketers and direct
industrial users. The two largest transportation customers of Pipeline in 2002
accounted for approximately 14.2 percent and 12.7 percent, respectively, of
total operating revenues. No other customer accounted for more than 10 percent
of total operating revenues in 2002. Pipeline's firm transportation agreements
are generally long-term agreements with various expiration dates and account for
the major portion of Pipeline's business. Additionally, Pipeline offers
interruptible and short-term firm transportation services.

No other interstate natural gas pipeline company presently provides
significant service to Pipeline's 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.

Pipeline believes 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 its mainline capacity.

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* 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. A dekatherm is equal to one MMBtu.

GAS STORAGE

Underground gas storage facilities enable Pipeline to balance daily
receipts and deliveries and provide storage services to certain major customers.

Pipeline has a contract with a third party, under which gas storage
services are provided to Pipeline in an underground storage reservoir in the
Clay Basin Field located in Daggett County, Utah. Pipeline is 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.

Pipeline owns a one-third interest in the Jackson Prairie underground
storage facility located near Chehalis, Washington, with the remaining interests
owned by two of Pipeline's distribution customers. Pipeline's share of the firm
seasonal storage service is 6.1 Bcf of working gas capacity and up to 283 MMcf
per day of peak day deliveries. Additionally, Pipeline's share of the
best-efforts delivery capacity is 50 MMcf per day.

Pipeline also owns and operates a liquefied natural gas ("LNG") storage
facility located near Plymouth, Washington, which provides standby service for
Pipeline's 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 Pipeline's major customers own the working gas stored at the LNG
plant.

EXPANSION PROJECTS

On August 29, 2001, Pipeline filed an application with the FERC to
construct and operate an expansion of its pipeline system designed to provide an
additional 175,000 Dekatherms ("Dth") per day of capacity to its transmission
system in Wyoming and Idaho in order to reduce reliance on displacement
capacity. The Rockies Expansion Project includes the installation of 91 miles of
pipeline loop and the upgrading or modification to six compressor stations for a
total increase of 26,057 horsepower. Pipeline reached a settlement agreement
with the majority of its firm shippers to support roll-in of the expansion costs
into its existing rates. The FERC issued a certificate in September 2002
approving the project. Pipeline filed an application with the FERC in February
2003 to amend the certificate to reflect minor facility scope changes.
Construction is scheduled to start by May 2003, with a targeted in-service date
of November 1, 2003. The current estimated cost of the expansion project is
approximately $140 million, of which approximately $16 million may be offset by
settlement funds anticipated to be received from a former customer in connection
with a contract restructuring.

On October 3, 2001, Pipeline filed an application with the FERC to
construct and operate an expansion of its 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 Evergreen Expansion Project includes installing 28 miles of pipeline loop,
upgrading, replacing or modifying five compressor stations and adding a net
total of 64,160 horsepower of compression. The FERC issued a certificate on June
27, 2002 approving the expansion and the incremental rates to be charged to
Pipeline's expansion customers. Pipeline started construction in October 2002
with completion targeted for October 1, 2003. Pipeline filed an application with
the FERC in January 2003 to amend the certificate to reflect minor facility
scope and schedule changes. The estimated cost of the expansion project is
approximately $198 million. The Evergreen Expansion customers have agreed to pay
for the cost of service of this expansion on an incremental basis. This
expansion is based on 15 and 25-year contracts and is expected to provide
approximately $42 million of operating revenues in its first 12 months of
operation.

Pipeline's October 3, 2001 application with respect to the Evergreen
Expansion Project, which was approved by the FERC on June 27, 2002, also
requested approvals to construct and operate an expansion of its pipeline system
designed to replace 56,000 Dth per day of northflow design displacement capacity
from Stanfield, Oregon to Washougal, Washington. The Columbia Gorge Project
includes upgrading, replacing or modifying five existing compressor stations and
adding a net total of 23,900 horsepower of compression. Pipeline reached a
settlement with the majority of its firm shippers 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 customers.
Pipeline's January 2003 application to amend the certificate also reflected
minor facility scope changes for the Columbia Gorge

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Expansion Project. Pipeline plans to start construction by May 2003, with a
targeted in-service date of November 1, 2003. The estimated cost of the
expansion project is approximately $43 million.

On November 1, 2002, Pipeline placed in service the Grays Harbor
Lateral project. This lateral pipeline is designed to provide 161,500 Dth per
day of firm transportation capacity to serve a new power generation plant in the
state of Washington. The Grays Harbor Lateral project was requested by one of
Pipeline's customers and included installation of 49 miles of 20-inch pipeline,
the addition of 4,700 horsepower at an existing compressor station, and a new
meter station. The cost of the lateral project is estimated to be approximately
$92 million. The customer has suspended construction of the contemplated new
power generation plant, but that does not affect its obligation to pay for the
cost of service of the lateral pipeline on an incremental rate basis. The Grays
Harbor Lateral project is based on a 30-year contract and is expected to
generate approximately $22 million of operating revenues in its first twelve
months of operation.

OPERATING STATISTICS

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

REGULATION

Pipeline is subject to regulation by the Federal Energy Regulatory
Commission ("FERC") under the Natural Gas Act of 1938 ("Natural Gas Act") and
under the Natural Gas Policy Act of 1978 ("NGPA"), and, as such, its rates and
charges for the transportation of natural gas in interstate commerce, the
extension, enlargement or abandonment of its jurisdictional facilities, and its
accounting, among other things, are subject to regulation. Pipeline holds
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.

Pipeline is 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.

OTHER REGULATORY MATTERS

GENERAL RATE CASE (DOCKET NO. RP93-5) On April 1, 1993, Pipeline began
collecting new rates, subject to refund, under its rate case filed October 1,
1992 ("1993 Rate Case"). Pipeline made refunds to customers in June 1998
totaling $27 million, including interest, reflecting the FERC's resolution of
all disputed matters in this case. Pipeline and other parties sought judicial
review of the FERC's decision concerning rate of return on equity. One party
sought judicial review of the inclusion of unpaid accruals in rate base. In July
1998, the FERC issued orders concerning its rate of return on equity policy in
rate proceedings of other pipelines adopting a formula that gives less weight to
the long-term growth component. In April 1999, the Court of Appeals for the D.C.
Circuit remanded the 1993 Rate Case to the FERC for application of its revised
rate of return on equity policy. On July 14, 1999, the FERC issued an order
requiring Pipeline to: (a) submit a surcharge plan to the FERC, (b) recalculate
rates consistent with the new weighting formula favoring short term growth, and
(c) address in a remand hearing the appropriate source for Gross Domestic
Product ("GDP") growth data. The new weighting formula generally results in a
higher authorized rate of return on equity. Pipeline and its customers resolved
by settlement those issues relating to long term GDP growth. In February 2000,
the FERC approved the long-term growth settlement and issued an order related to
return on equity issues requiring Pipeline to

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incorporate the effects of the settlement and to calculate its allowed rate of
return on equity consistent with the recently announced policy changes in other
proceedings. As a part of this recalculation of allowed return on equity, the
FERC provided that Pipeline must use the median instead of the midpoint of the
various results of Discounted Cash Flow ("DCF") analysis for a proxy group. This
resulted in a 13.67 percent return on equity for Pipeline. On April 3, 2000,
Pipeline made the necessary compliance filings to implement the FERC's decision
including the establishment of surcharges in order to recollect moneys that
shippers owe Pipeline for these corrective actions. On July 14, 2000, the FERC
issued an order denying customer rehearing requests and approving Pipeline's
compliance filing. The order reaffirmed Pipeline's right to use the median
result from the DCF proxy group analysis. Some of Pipeline's customers sought
judicial review concerning the FERC's orders with respect to return on equity
issues. On July 13, 2001, the D.C. Circuit issued its decision affirming the
FERC's earlier rulings on various rate base, accounting, and risk issues, but
remanding the case to the FERC to allow the FERC to set forth more clearly its
rationale for allowing Pipeline to utilize the median result of the DCF proxy
group analysis. On June 12, 2002, the FERC issued an Order on Remand reaffirming
its decision to utilize the median of the proxy companies in setting Pipeline's
return on equity. No requests for rehearing were filed in response to the June
12, 2002 order. This decision effectively brought the 1993 Rate Case to its
conclusion.

GENERAL RATE CASE (DOCKET NO. RP95-409) On February 1, 1996, Pipeline
began collecting new rates, subject to refund, under the provisions of its rate
case filed August 1, 1995 ("1995 Rate Case"). During the first quarter of 1998,
the Administrative Law Judge ("ALJ") issued an Initial Decision. The ALJ found
that the facts of this case continue to support Pipeline's capital structure of
55 percent equity and 45 percent debt. The ALJ also determined that Pipeline
fits within the average risk range for determining pipeline return on equity and
allowed a return on equity of 11.2 percent. On June 1, 1999, the FERC issued its
order affirming many aspects of the ALJ's initial decision, but finding that the
return on equity issue should be resolved by using the FERC's new policy
concerning rate of return determinations. This resulted in an allowed return on
equity of 12.22 percent. On September 29, 2000, the FERC issued its Order on
Rehearing, which, for the most part, reaffirmed the FERC's earlier June 1, 1999
decision. Pipeline made a compliance filing on October 16, 2000. On July 11,
2001, the FERC issued an Order accepting Pipeline's compliance filings, subject
to Pipeline making some minor rate related changes relating to billing
determinants and cost of service recovery for facilities subject to
reimbursement agreements. On August 31, 2001, Pipeline made refunds to customers
totaling $43.1 million, including interest. Some shippers filed petitions for
review concerning return on equity issues. On October 25, 2002, the United
States Court of Appeals for the D. C. Circuit affirmed the FERC's decision in
its treatment of return on equity issues. This decision effectively brought the
1995 Rate Case to its conclusion.

NOTICE OF PROPOSED RULEMAKING (DOCKET NO. RM01-10-000) On September 27,
2001, the FERC issued a Notice of Proposed Rulemaking ("NOPR") proposing to
adopt 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 proposed standards would regulate the conduct of transmission providers with
their energy affiliates. The FERC proposed to define energy affiliates broadly
to include any transmission provider affiliate that engages in or is involved in
transmission (gas or electric) transactions, or manages or controls transmission
capacity, or buys, sells, trades or administers natural gas or electric energy
or engages in financial transactions relating to the sale or transmission of
natural gas or electricity. Current rules regulate the conduct of Pipeline and
its gas marketing affiliates. The FERC's staff analysis of the proposed
rulemaking proposed redefining energy affiliates to exclude affiliated
transmission providers. If the proposed rules are adopted as proposed, these new
standards would require new compliance measures by Pipeline.

NOTICE OF INQUIRY (DOCKET NO. PL02-6-000) On July 17, 2002, the FERC
issued a Notice of Inquiry to seek comments on its negotiated rate policies and
practices. The FERC states that it is undertaking a review of the recourse rate
as a viable alternative and safeguard against the exercise of market power of
interstate gas pipelines, as well as the entire spectrum of issues related to
its negotiated rate program. Pipeline has negotiated certain rates under the
FERC's existing negotiated rate program, and participated in comments filed in
this proceeding by Williams in support of the FERC's existing negotiated rate
program.

NOTICE OF PROPOSED RULEMAKING (DOCKET NO. RM02-14-000) On August 1,
2002, the FERC issued a NOPR that proposes restrictions on various types of cash
management programs employed by

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companies in the energy industry such as Williams and its subsidiaries,
including Pipeline. In addition to stricter guidelines regarding the accounting
for and documentation of cash management or cash pooling programs, the FERC
proposal, if made final, would preclude 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 that the FERC-regulated affiliate maintains stockholders equity of
at least 30 percent of total capitalization. Williams' and Pipeline's current
credit ratings are not investment grade. Pipeline participated in comments filed
in this proceeding on August 28, 2002 by the Interstate Natural Gas Association
of America. On September 25, 2002, the FERC convened a technical conference to
discuss issues raised in the comments filed by parties in this proceeding.

ENVIRONMENTAL MATTERS

Pipeline is subject to the National Environmental Policy Act and other
federal and state legislation regulating the environmental aspects of its
business. Management believes that Pipeline is in substantial compliance with
existing environmental requirements. Pipeline believes 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. Pipeline
believes that compliance with applicable environmental requirements is not
likely to have a material effect upon Pipeline's earnings or financial position.

SAFETY MATTERS

In January 2003, the U. S. Department of Transportation Office of
Pipeline Safety issued a Notice of Proposed Rulemaking entitled "Pipeline
Integrity Management in High Consequence Areas". The proposed rule incorporates
the requirements of the Pipeline Safety Improvement Act of 2002 that was enacted
in December 2002. It would require 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. The final rule is expected to be issued in late 2003. Pipeline at
this time cannot predict the exact costs that would be required under the
proposed rule. These costs of the baseline assessment are anticipated to be
incurred over the next ten years. Pipeline considers the costs associated with
compliance with the proposed rule to be prudent costs incurred in the ordinary
course of business and, therefore, recoverable through its rates.

OWNERSHIP OF PROPERTY

Pipeline's system is owned in fee simple. However, a substantial
portion of Pipeline's system is constructed and maintained pursuant to
rights-of-way, easements, permits, licenses or consents on and across properties
owned by others. The compressor stations of Pipeline, with associated
facilities, are located in whole or in part upon lands owned by Pipeline 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
Pipeline. Various credit arrangements restrict the sale or disposal of a major
portion of its pipeline system.

EMPLOYEE RELATIONS

At December 31, 2002, Pipeline employed 376 persons, none of whom are
represented under collective bargaining agreements. No strike or work stoppage
in any of Pipeline's operations has occurred in the past and relations with
employees are good.

FORWARD LOOKING STATEMENTS

Certain matters discussed in this annual report, excluding historical
information, include forward-looking statements --statements that discuss
Pipeline's expected future results based on current and pending business
operations. Pipeline makes these forward-looking statements in reliance on the
safe harbor protections provided under the Private Securities Litigation Reform
Act of 1995.

Forward-looking statements can be identified by words such as
"anticipates," "believes," "could," "continues," "estimates," "expects,"
"forecasts," "might," "planned," "potential," "projects," "scheduled" or

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similar expressions. Although Pipeline believes 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.

Events in 2002 significantly impacted the risk environment businesses
face and raised a level of uncertainty in the capital markets. Beliefs and
assumptions as to what constitutes appropriate levels of capitalization and
fundamental value have changed abruptly. The financial collapse of the energy
industry combined with the meltdown of the telecommunications industry are both
new realities that have had and will likely continue to have specific impacts on
all companies, including Pipeline.

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 Pipeline's business, operating results, and financial condition
as well as adversely affect the value of an investment in Pipeline's securities.

WILLIAMS' STRATEGY TO STRENGTHEN ITS BALANCE SHEET AND IMPROVE
LIQUIDITY DEPENDS ON WILLIAMS' ABILITY TO DIVEST SUCCESSFULLY CERTAIN ASSETS.

On February 20, 2003, Williams announced its intention to sell an
additional $2.25 billion in assets, properties and investments. At December 31,
2002, Williams had debt obligations of $3.8 billion that will mature between now
and March 2004. Because Williams' cash flow from operations will be insufficient
alone to repay all such debt and Williams' access to capital markets is limited,
in part as a result of the loss of its investment grade ratings, Williams will
depend on its sales of assets to generate sufficient net cash proceeds to enable
the payment of maturing obligations.

Williams' secured credit facilities limit its ability to sell certain
assets and require generally that one-half of all net proceeds from asset sales
be applied (a) to repayment of certain long-term debt, (b) to cash
collateralization of designated letters of credit, and (c) to reduction of the
lender commitments under the secured facilities. The timing of and the net cash
proceeds realized from such sales are dependent on locating and successfully
negotiating sales with prospective buyers, regulatory approvals, industry
conditions, and lender consents. If the realized cash proceeds are insufficient
or are materially delayed, Williams might not have sufficient funds on hand to
pay maturing indebtedness, including advances from Pipeline which are payable
upon demand, or to implement its strategy.

BECAUSE PIPELINE NO LONGER MAINTAINS INVESTMENT GRADE CREDIT RATINGS,
COUNTERPARTIES MIGHT REQUIRE IT TO PROVIDE INCREASING AMOUNTS OF CREDIT SUPPORT,
WHICH WOULD RAISE THE COST OF DOING BUSINESS.

Pipeline's transactions will require greater credit assurances, both to
be given from, and received by, it to satisfy credit support requirements.
Additionally, certain market disruptions or a further downgrade of Pipeline's
credit rating might further increase its cost of borrowing or further impair its
ability to access one or any of the capital markets. Such disruptions could
include:

o further economic downturns;

o capital market conditions generally;

o market prices for electricity and natural gas;

o terrorist attacks or threatened attacks on Pipeline's facilities
or those of other energy companies; or

o the overall health of the energy industry, including the
bankruptcy of energy companies.

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RISKS RELATED TO THE REGULATION OF PIPELINE'S BUSINESS

PIPELINE'S TRANSMISSION AND STORAGE OPERATIONS ARE SUBJECT TO
GOVERNMENT REGULATIONS AND RATE PROCEEDINGS THAT COULD HAVE AN ADVERSE IMPACT ON
ITS ABILITY TO RECOVER THE COSTS OF OPERATING ITS PIPELINE FACILITIES.

Pipeline's 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:

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

o rates and charges;

o construction;

o acquisition, extension or abandonment of services or facilities;

o accounts and records;

o depreciation and amortization policies; and

o 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, interstate pipelines 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. Pipeline's ability to compete in the natural
gas pipeline industry is impacted by its ability to offer competitively priced
services.

In 2000, the FERC issued Order No. 637, which sets forth revisions to
its policies governing the regulation of interstate natural gas pipelines that
it finds necessary to adjust its current regulatory model to the needs of
evolving markets. The FERC, however, determined that any fundamental changes to
its regulatory policy will be considered after further study and evaluation of
the evolving marketplace. Order No. 637 revised the FERC's pricing policy to
waive through September 30, 2002, the maximum price ceilings for short-term
releases of capacity of less than one year and to permit pipelines to file
proposals to implement seasonal rates for short-term services and
term-differentiated rates. Certain parties requested rehearing of Order No. 637
and eventually appealed certain issues to the District of Columbia Circuit Court
of Appeals. The D.C. Circuit remanded as to certain issues, and on October 31,
2002, the FERC issued its order on remand. Rehearing requests for that order are
now pending with the FERC. Given the extent of the FERC's regulatory power,
Pipeline cannot give any assurance regarding the likely regulations under which
it will operate its natural gas transmission and storage business in the future
or the effect of regulation on its financial position and results of operations.

The FERC has proposed to broaden its regulations that restrict
relations between jurisdictional natural gas companies, or "jurisdictional
companies," and marketing affiliates. In addition, the proposed rules would
limit communications between jurisdictional companies and all other companies
engaged in energy activities. The rulemaking is pending at the FERC and the
precise scope and effect of the rule is unclear. If adopted as proposed, the
rule could affect the way Pipeline manages its gas transmission activities.

RISKS RELATED TO ENVIRONMENTAL MATTERS

PIPELINE COULD INCUR MATERIAL LOSSES IF IT IS HELD LIABLE FOR THE
ENVIRONMENTAL CONDITION OF ANY OF ITS ASSETS.

Pipeline is generally responsible for all on-site liabilities
associated with the environmental condition of its facilities and assets, which
it has acquired or developed, regardless of when the liabilities

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arose and whether they are known or unknown. In addition, in connection with
certain acquisitions and sales of assets, Pipeline might obtain, or be required
to provide, indemnification against certain environmental liabilities. If
Pipeline incurs a material liability, or the other party to a transaction fails
to meet its indemnification obligations to Pipeline, it could suffer material
losses.

ENVIRONMENTAL REGULATION AND LIABILITY - PIPELINE'S BUSINESS WILL BE
SUBJECT TO ENVIRONMENTAL LEGISLATION IN ALL JURISDICTIONS IN WHICH IT OPERATES,
AND ANY CHANGES IN SUCH LEGISLATION COULD NEGATIVELY AFFECT ITS RESULTS OF
OPERATIONS.

Pipeline's 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 Pipeline's facilities,
sites and other properties associated with its 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
Pipeline or its 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 Pipeline takes to bring certain of its facilities into compliance could be
prohibitively expensive, and it might be required to shut down or alter the
operation of those facilities, which might cause it to incur losses.

Further, Pipeline's regulatory rate structure and its contracts with
clients might not necessarily allow it to recover capital costs incurred to
comply with new environmental regulations. Also, Pipeline 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 Pipeline fails to obtain and
comply with them, the operation of its facilities could be prevented or become
subject to additional costs. Should Pipeline fail to comply with all applicable
environmental laws, it might be subject to penalties and fines imposed by
regulatory authorities. Although Pipeline does not expect that the costs of
complying with current environmental legislation will have a material adverse
effect on its financial condition or results of operations, no assurance can be
made that the costs of complying with environmental legislation in the future
will not have such an effect.

RISKS RELATING TO ACCOUNTING POLICIES

POTENTIAL CHANGES IN ACCOUNTING POLICIES FOR THE ENERGY INDUSTRY MIGHT
CAUSE PIPELINE TO REVISE ITS FINANCIAL ACCOUNTING AND/OR DISCLOSURE IN THE
FUTURE, WHICH MIGHT CHANGE THE WAY ANALYSTS MEASURE ITS BUSINESS OR FINANCIAL
PERFORMANCE.

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, Pipeline 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 its operations
specifically. In addition, the Financial Accounting Standards Board ("FASB"),
the FERC or the SEC could enact new accounting standards that might impact how
Pipeline is required to record revenues, expenses, assets and liabilities.

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RISKS RELATING TO PIPELINE'S INDUSTRY

THE LONG-TERM FINANCIAL CONDITION OF PIPELINE'S 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 Pipeline's
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.

GAS TRANSMISSION ACTIVITIES INVOLVE NUMEROUS RISKS THAT MIGHT RESULT IN
ACCIDENTS AND OTHER OPERATING RISKS AND COSTS.

There are inherent in Pipeline's 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 its operations and substantial losses. In
accordance with customary industry practice, Pipeline maintains 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 Pipeline's 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.

OTHER RISKS

RECENT TERRORIST ACTIVITIES AND THE POTENTIAL FOR MILITARY AND OTHER
ACTIONS COULD ADVERSELY AFFECT PIPELINE'S BUSINESS.

The continued threat of terrorism and the impact of retaliatory
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 Pipeline's 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 Pipeline is
taking steps that it believes are appropriate to increase the security of its
energy assets, there is no assurance that Pipeline can completely secure its
assets or to completely protect them against a terrorist attack. These
developments have subjected Pipeline's operations to increased risks and,
depending on their ultimate magnitude, could have a material adverse effect on
Pipeline's business. In particular, Pipeline might experience increased capital
or operating costs to implement increased security for its energy assets.

The insurance industry has also been disrupted by these events. As a
result, the availability of insurance covering risks that Pipeline and its
competitors typically insure against might decrease. In addition, the insurance
that Pipeline is able to obtain might have higher deductibles, higher premiums
and more restrictive policy terms.

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 Items 1 and 2 - Business and Properties, there are no material
pending legal proceedings. Pipeline is subject to ordinary routine litigation
incidental to its business.

-9-

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

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

-10-

PART II

ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS

Pipeline is wholly-owned by WGP, a wholly-owned subsidiary of Williams;
therefore, Pipeline's common stock is not publicly traded.

No cash dividends were paid on common stock by Pipeline in 2002. In
2001, Pipeline paid cash dividends on common stock of $20 million.

ITEM 6. SELECTED FINANCIAL DATA

Since Pipeline meets 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

REGULATORY ACCOUNTING

Pipeline is 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, and other costs and taxes
included in, or expected to be included in, future rates. As a rate-regulated
entity, Pipeline follows the accounting prescribed by SFAS No. 71 and the
accompanying financial statements include the effects of the types of
transactions described above that result from regulatory accounting
requirements.

REVENUE SUBJECT TO REFUND

FERC regulations promulgate policies and procedures, which govern a
process to establish the rates that Pipeline is 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 collected by
Pipeline may be subject to possible refunds upon final orders in pending rate
proceedings with the FERC. Pipeline records estimates of rate refund liabilities
considering Pipeline 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, 2002, Pipeline has no pending
regulatory proceedings and no potential rate refunds.

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CONTINGENT LIABILITIES

Pipeline establishes reserves for estimated loss contingencies when it
is management's assessment 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 different facts or information become known or
circumstances change that affect the previous assumptions with respect to the
likelihood or amount of loss. Reserves for contingent liabilities are based upon
management's assumptions and estimates, advice of legal counsel or other third
parties regarding the probable outcomes of the matter. Should the outcome differ
from the assumptions and estimates, revisions to the estimated reserves for
contingent liabilities would be required.

IMPAIRMENT OF LONG-LIVED ASSETS

Pipeline evaluates 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.

WILLIAMS' RECENT EVENTS

In 2002, Williams faced many challenges including credit and liquidity
constraints following the deterioration of its sector of the energy industry in
the wake of the Enron collapse and the assumption of payment obligations and
performance on guarantees associated with its former telecommunications
subsidiary, Williams Communications Group, Inc.(WCG). With the deterioration of
the energy industry, the credit rating agencies' requirements for investment
grade companies became more stringent. Williams' credit rating was lowered below
an investment grade rating in the middle of 2002. During 2002 and more recently,
Williams has sold a significant amount of assets and/or businesses and outlined
plans to sell more assets to satisfy maturing debt obligations and strengthen
its short-term liquidity position. In regards to the short-term, Williams, at
December 31, 2002, has maturing notes payable and long-term debt totaling
approximately $3.8 billion (which includes certain contractual fees and deferred
interest associated with an underlying debt) through the first quarter of 2004.

During December 2001 and the first quarter of 2002, Williams announced
plans to strengthen its balance sheet and support retention of its investment
grade ratings. The plans included reducing capital expenditures during the
balance of 2002, future sales of assets to generate proceeds to be used to
reduce outstanding debt and the lowering of expenses, in part through an
enhanced-benefit early retirement program which concluded during the second
quarter. Toward these plans and in satisfaction of continued liquidity demands,
Williams completed debt issuances and sold one of its regulated interstate
pipelines.

During the second quarter, Williams experienced liquidity constraints,
the effect of which limited Williams Energy Marketing & Trading's (WEM&T)
ability to manage market risk and exercise hedging strategies as market
liquidity deteriorated. During May 2002, major rating agencies lowered their
credit ratings on Williams' unsecured long-term debt; however, the ratings
remained investment grade for the balance of the quarter.

Williams experienced a substantial net loss for the second quarter of
2002 resulting primarily from a segment loss incurred by its energy marketing
and trading segment. In July 2002, the major rating agencies downgraded
Williams' unsecured long-term debt credit ratings to below investment grade,
reflecting the uncertainty associated with Williams' energy trading business,
short-term cash requirements facing Williams and the increased level of debt
Williams had incurred to meet the WCG payment

-12-

obligations and guarantees. Concurrent with these events, Williams was unable to
complete a renewal of its unsecured short-term bank facility which expired on
July 24, 2002. Subsequently, Williams obtained two secured facilities totaling
$1.3 billion and amended its existing credit agreement, which expires in July
2005, to make it secured. These facilities include pledges of certain assets and
contain financial ratios and other covenants that must be maintained. If such
provisions of these agreements are not adhered to, then Williams' lenders can
declare all amounts outstanding to be immediately due and payable. In addition,
the Williams board of directors reduced the Williams common stock dividend for
the third quarter from the prior level of 20 cents per share to 1 cent per
share. Williams also sold assets during 2002 and is pursuing the sale of other
assets to enhance liquidity.

As part of the effort to reduce future operating expenses, certain
employee positions are being eliminated through organizational changes. In the
second quarter of 2002, Pipeline accrued $3.9 million of pension benefits
expense associated with an enhanced-benefit early retirement option offered to
certain Williams employee groups. In the third and fourth quarters, Pipeline
accrued $0.5 million of severance costs applicable to employees whose positions
have been eliminated.

On February 20, 2003, Williams outlined its planned business strategy
for the next several years and believes it to be a comprehensive response to the
events, which have impacted the energy sector and Williams during 2002. The plan
focuses on retaining a strong, but smaller, portfolio of natural-gas businesses
and bolstering Williams' liquidity through more asset sales, limited levels of
financing at the subsidiary level and additional reductions in its operating
costs. The plan is designed to provide Williams with a clear strategy to address
near-term and medium-term liquidity issues and further de-leverage the company
with the objective of returning to investment grade status by 2005, while
retaining businesses with favorable returns and opportunities for growth in the
future. As part of this plan, Williams expects to generate proceeds, net of
related debt, of nearly $4 billion from asset sales during 2003, including
approximately $2.25 billion in newly announced offerings combined with those
assets already under contract or in negotiations for sale. The specific assets
and the timing of such sales are dependent on various factors, including
negotiations with prospective buyers, regulatory approvals, industry conditions,
lender consents to sales of collateral and the short-and long-term liquidity
requirements of Williams.

The energy trading sector has experienced deteriorating conditions
because of credit and regulatory concerns, and these have significantly reduced
WEM&T's ability to attract new business. Williams has announced its intention to
further reduce its commitment and exposure to its energy marketing and risk
management business. This reduction could be realized by entering into a joint
venture arrangement with a third party or a sale of a portion or all of the
marketing and trading portfolio. WEM&T, as well as several unaffiliated energy
trading companies, are Pipeline customers. Pipeline cannot predict at this time
to what extent business may be impacted by the deteriorating conditions in the
energy trading sector, however, generally such companies have continued to
perform their contractual commitments to Pipeline.

At December 31, 2002, Williams has maturing notes payable and long-term
debt totaling approximately $3.8 billion (which includes certain contractual
fees and deferred interest associated with an underlying debt) through the first
quarter of 2004. Williams has indicated that available liquidity to meet these
requirements and fund a reduced level of capital expenditures will be dependent
on several factors, including the cash flows of retained businesses, the amount
of proceeds raised from the sale of assets and the price of natural gas. Future
cash flows from operations may also be affected by the timing and nature of the
sale of assets. Because of recent asset sales, anticipated asset sales and
available secured credit facilities, Williams has indicated that it currently
believes that it has the financial resources and liquidity to meet future cash
requirements through the first quarter of 2004. In the event that Williams'
financial condition does not improve or becomes worse, or if it fails to
complete assets sales and reduce its commitment to its energy marketing and risk
management business, Williams may have to consider other options including the
possibility of seeking protection in a bankruptcy proceeding.

RESULTS OF OPERATIONS

ANALYSIS OF FINANCIAL RESULTS

This analysis discusses financial results of Pipeline's operations for
the years 2000 through 2002. Variances due to changes in price and volume have
little impact on revenues, because under Pipeline's

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rate design methodology, the majority of overall cost of service is recovered
through firm capacity reservation charges in its transportation rates.

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.

Pipeline's transportation service accounted for 91 percent and 93
percent of operating revenues for the years ended December 31, 2002 and 2001,
respectively. Additionally, 3 percent of operating revenues represented gas
storage service in each of the years ended December 31, 2002 and 2001. Other
revenues related to Pipeline's transportation services represented 3 percent and
2 percent of operating revenues for the years ended December 31, 2002 and 2001,
respectively.

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 resulting from the consolidation of several Pipeline administrative
functions into 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 the decrease in operating expenses during 2002.

Operating income increased $9.2 million, or 7 percent, due to the
higher revenues discussed above, partially offset by the higher operating
expenses.

Other income (net) increased $8.1 million primarily due to reduced
charitable contribution commitments reflecting Pipeline's desire to reduce
non-income producing related expenses.

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.

2001 COMPARED TO 2000

Operating revenues decreased $11.2 million, or 4 percent, due primarily
to the recognition in 2000 of a $10.2 million surcharge resulting from a
favorable FERC decision on return on equity related to the 1993 rate case.

Pipeline's transportation service accounted for 93 percent and 94
percent of operating revenues for the years ended December 31, 2001 and 2000,
respectively. Additionally, 3 percent of operating revenues represented gas
storage service in each of the years ended December 31, 2001 and 2000.

Operating expenses increased $3.3 million, or 2 percent, due primarily
to higher depreciation in 2001 and the receipt in 2000 of $2.1 million in
environmental liability insurance settlements, partially offset by decreased
rental expense reflected in general and administrative expense.

Operating income decreased $14.4 million, or 10 percent, due to reasons
identified above.

Other income decreased $8.4 million primarily resulting from the
recognition in 2000 of $7.0 million of interest on the 1993 rate case surcharge
revenues discussed above in operating revenues and higher charitable
contributions in 2001.

-14-

Other interest expense decreased $1.0 million due primarily to the
payment of the 1995 rate case refund in August of 2001.

EFFECT OF INFLATION

Pipeline generally has 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 Pipeline's property, plant and equipment and materials and
supplies is subject to rate-making 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, Pipeline believes it will
be allowed to recover and earn a return based on the increased actual costs
incurred when existing facilities are replaced. Cost-based regulation along with
competition and other market factors limit Pipeline's ability to price services
or products to ensure recovery of inflation's effect on costs.

CAPITAL RESOURCES AND LIQUIDITY

METHOD OF FINANCING

Pipeline funds its capital requirements with cash flows from operating
activities, by accessing capital markets, by repayments of funds advanced to
WGP, by borrowings under the Credit Agreement and, if required, by advances from
WGP. Historically, Pipeline also funded its capital requirements through a sale
of receivables program. In July 2002, Pipeline's sale of receivables program
expired and was not renewed.

Pipeline has an effective registration statement on file with the
Securities and Exchange Commission. At December 31, 2002, 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. With the downgrade in
Pipeline's credit ratings (discussed below), interest rates on future financings
will be higher, but Pipeline believes any additional financing arrangements, if
required, can be obtained from the capital markets on terms that are
commensurate with its current credit ratings.

On March 4, 2003, Pipeline sold $175 million of senior notes due 2010
to certain institutional investors in an offering exempt from the registration
requirements of the Securities Act of 1933. Pipeline intends to use the proceeds
for general corporate purposes, including the funding of capital expenditures.

Williams and certain of its subsidiaries, including Pipeline, are
parties to a $700 million credit agreement ("Credit Agreement"), under which
Pipeline can borrow up to $400 million to the extent the funds available under
the Credit Agreement have not been borrowed by Williams or other subsidiaries.
The Credit Agreement expires in July 2005. Interest rates vary with current
market conditions based on the base rate of Citibank N.A., federal funds rate or
the London Interbank Offered Rate ("LIBOR"). The Credit Agreement contains
restrictions, which limit, under certain circumstances, the issuance of
additional debt, the attachment of liens on any assets and any change of
ownership of Pipeline. As Williams completes certain asset sales, the
commitments from participating banks in the Credit Agreement will be reduced to
$400 million, and with further asset sales could be reduced below that amount,
but Pipeline will continue to have borrowing capacity up to the lesser of $400
million or the amount that Williams would be able to borrow to the extent the
funds available under the Credit Agreement have not been borrowed by Williams or
other participating subsidiaries or that otherwise would be required to remain
available to Williams. At December 31, 2002, the commitment from participating
banks had been reduced to $463 million, the borrowing capacity available to
Pipeline was $400 million, and Pipeline had no outstanding borrowings under this
agreement. Pipeline's assets have not been pledged to secure any indebtedness of
Williams or its other affiliates, either under the Credit Agreement or pursuant
to any other credit facility of Williams and its other affiliates.

As a participant in Williams' cash management program, Pipeline makes
advances to and receives advances from Williams through Pipeline's parent
company, WGP. At December 31, 2002, the advances due Pipeline by WGP totaled
$17.3 million. The advances are represented by demand notes. The interest

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rate on intercompany demand notes is the LIBOR on the first day of the month
plus an applicable margin based on Pipeline's current credit ratings as
determined by Moody's Investors Service and Standard and Poor's. Due to recent
asset sales, anticipated asset sales in the future and recently negotiated
secured borrowing facilities, Williams has indicated that it currently believes
that it will continue to have the financial resources and liquidity to repay
these advances made by Pipeline.

In the event that Williams' financial condition does not improve or
becomes worse, or if it fails to realize sufficient proceeds from the remaining
planned asset sales, it may have to consider other options including the
possibility of seeking protection in a bankruptcy proceeding. Pipeline cannot
predict with certainty what impact such action, if it were to occur, would have
on it. Under the equitable doctrine of substantive consolidation, a bankruptcy
court may consolidate and pool the assets and liabilities of a subsidiary with
those of its parent. Pipeline cannot provide assurance that Williams, WGP or
their creditors would not attempt to advance substantive consolidation claims in
the event of a Williams bankruptcy proceeding or, if advanced, how a bankruptcy
court would resolve the issue. If a bankruptcy court were to allow the
substantive consolidation of Pipeline's assets and liabilities in the context of
a bankruptcy filing, Pipeline's financial condition, operations and ability to
meet its obligations would be materially adversely affected.

NOTICE OF PROPOSED RULEMAKING (DOCKET NO. RM02-14-000) On August 1, 2002, the
FERC issued a NOPR that proposes restrictions on various types of cash
management programs employed by companies in the energy industry such as
Williams and its subsidiaries, including Pipeline. In addition to stricter
guidelines regarding the accounting for and documentation of cash management or
cash pooling programs, the FERC proposal, if made final, would preclude 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.
Williams' and Pipeline's current credit ratings are not investment grade.
Pipeline participated in comments filed in this proceeding on August 28, 2002 by
the Interstate Natural Gas Association of America. On September 25, 2002, the
FERC convened a technical conference to discuss issues raised in the comments
filed by parties in this proceeding.

Through July 2002, Pipeline, 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. Pipeline acted
as the servicing agent for the sold receivables. The sale of receivables program
expired on July 25, 2002, and on July 26, 2002, Pipeline completed the
repurchase of $15 million of trade accounts receivable previously sold. For
2002, cash inflows from the SPE were approximately $112 million. The sales of
these receivables resulted in a net charge to results of operations of
approximately $0.2 million and $0.7 million in 2002 and 2001, respectively.

CREDIT RATINGS

Pipeline has no guarantees of off-balance sheet debt to third parties
and maintains no debt obligations that contain provisions requiring accelerated
payment of the related obligations in the event of specified levels of declines
in Williams' or Pipeline's credit ratings given by Moody's Investor's Service,
Standard and Poor's and Fitch Ratings (rating agencies).

During 2002, the rating agencies reduced Pipeline's credit ratings on
its senior unsecured long-term debt, as follows:

Moody's Investor's Service...................................Baa1 to B3
Standard and Poor's..........................................BBB+ to B+
Fitch Ratings................................................BBB+ to BB-

Currently, Moody's Investor's Service and Standard and Poor's have
Pipeline's credit ratings on "negative outlook" and "negative watch",
respectively. The rating agencies have reduced Pipeline's credit ratings 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 ratings remain
under review pending the execution of Williams' plan to strengthen its financial
position. With the reduced credit ratings, Pipeline expects interest rates on
future financings will be higher than they otherwise would have been.

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CAPITAL EXPENDITURES

Pipeline's expenditures for property, plant and equipment additions
were $181.8 million, $94.9 million and $47.9 million for 2002, 2001 and 2000,
respectively. Pipeline anticipates 2003 capital expenditures will total
approximately $330 million, of which approximately $63 million will be for
maintenance capital expenditures and other non-expansion related items.

EXPANSION PROJECTS

ROCKIES EXPANSION PROJECT On August 29, 2001, Pipeline filed an application with
the FERC to construct and operate an expansion of its pipeline system designed
to provide an additional 175,000 dekatherms ("Dth") per day of capacity to its
transmission system in Wyoming and Idaho in order to reduce reliance on
displacement capacity. The Rockies Expansion Project includes 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. Pipeline reached a
settlement agreement with the majority of its firm shippers to support roll-in
of the expansion costs into its existing rates. The FERC issued a certificate in
September 2002 approving the project. Pipeline filed an application with the
FERC in February 2003 to amend the certificate to reflect minor facility scope
changes. Construction is scheduled to start by May 2003, with a targeted
in-service date of November 1, 2003. The current estimated cost of the expansion
project is approximately $140 million, of which approximately $16 million may be
offset by settlement funds anticipated to be received from a former customer in
connection with a contract restructuring.

EVERGREEN EXPANSION PROJECT On October 3, 2001, Pipeline filed an application
with the FERC to construct and operate an expansion of its 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 Evergreen Expansion Project includes installing 28
miles of pipeline loop, upgrading, replacing or modifying five compressor
stations and adding a net total of 64,160 horsepower of compression. The FERC
issued a certificate on June 27, 2002 approving the expansion and the
incremental rates to be charged to our expansion customers. Pipeline started
construction in October 2002 with completion targeted for October 1, 2003.
Pipeline filed an application with the FERC in January 2003 to amend the
certificate to reflect minor facility scope and schedule changes. The estimated
cost of the expansion project is approximately $198 million. The Evergreen
Expansion customers have agreed to pay for the cost of service of this expansion
on an incremental basis. This expansion is based on 15 and 25 year contracts and
is expected to provide approximately $42 million of operating revenues in its
first 12 months of operation.

COLUMBIA GORGE EXPANSION PROJECT Pipeline's October 3, 2001 application with
respect to the Evergreen Expansion Project, which was approved by the FERC on
June 27, 2002, also requested approvals to construct and operate an expansion of
its pipeline system designed to replace 56,000 Dth per day of northflow design
displacement capacity from Stanfield, Oregon to Washougal, Washington. The
Columbia Gorge Project includes upgrading, replacing or modifying five existing
compressor stations and adding a net total of 23,900 horsepower of compression.
Pipeline reached a settlement with the majority of its firm shippers to support
roll-in of 84 percent of the expansion costs into the existing rates with the
remainder to be allocated to the incremental Evergreen Expansion customers.
Pipeline's January 2003 application to amend the certificate also reflected
minor facility scope changes for the Columbia Gorge Expansion Project. Pipeline
plans to start construction by May 2003, with a targeted in-service date of
November 1, 2003. The estimated cost of the expansion project is approximately
$43 million.

GRAYS HARBOR LATERAL PROJECT On November 1, 2002, Pipeline placed in service the
Grays Harbor Lateral project. This lateral pipeline is designed to provide
161,500 Dth per day of firm transportation capacity to serve a new power
generation plant in the state of Washington. The Grays Harbor Lateral project
was requested by one of Pipeline's customers and included installation of 49
miles of 20-inch pipeline, the addition of 4,700 horsepower at an existing
compressor station, and a new meter station. The cost of the lateral project is
estimated to be approximately $92 million. The customer has suspended
construction of the contemplated new power generation plant but that does not
affect its obligation to pay for the cost of service of the lateral pipeline on
an incremental rate basis. The Grays Harbor Lateral project is based on a
30-year contract and is expected to generate approximately $22 million of
operating revenues in its first twelve months of operation.

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OTHER

CONTRACTUAL OBLIGATIONS

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

REGULATORY AND LEGAL PROCEEDINGS

Reference is made to Note 2 of the Notes to Financial Statements for
information about regulatory, judicial and business developments, which cause
operating and financial uncertainties.

CONCLUSION

Although no assurances can be given, Pipeline currently believes that
the aggregate of cash flows from operating activities, the issuance of $175
million of senior notes in the first quarter of 2003, supplemented, when
necessary, by repayments of funds advanced to WGP, advances or capital
contributions from Williams and borrowings under the Credit Agreement will
provide Pipeline with sufficient liquidity to meet its capital requirements.
When necessary, Pipeline also expects to access public and private markets on
terms commensurate with its current credit ratings to finance its capital
requirements.

ITEM 7A. QUALITATIVE AND QUANTITATIVE DISCLOSURES ABOUT MARKET RISK

INTEREST RATE RISK

Pipeline's interest rate risk exposure is limited to its long-term
debt. All interest rates on long-term debt are fixed in nature.

The following table provides information as of December 31, 2002, about
Pipeline's long-term debt, including current maturities. The table presents
principle cash flows (at face value) and weighted average interest rates by
expected maturity dates.

December 31, 2002
(Millions of Dollars)

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

INDEX TO FINANCIAL STATEMENTS

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.

-19-

REPORT OF INDEPENDENT AUDITORS

The Board of Directors
Northwest Pipeline Corporation

We have audited the accompanying balance sheet of Northwest Pipeline
Corporation as of December 31, 2002 and 2001, and the related statements of
income, cash flows, and common stockholder's equity for each of the three years
in the period ended December 31, 2002. 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, 2002 and 2001, and the results of its operations and
its cash flows for each of the three years in the period ended December 31,
2002, in conformity with accounting principles generally accepted in the United
States.

/s/ ERNST & YOUNG LLP

Houston, Texas
February 21, 2003

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NORTHWEST PIPELINE CORPORATION

STATEMENT OF INCOME

(Thousands of Dollars)

See accompanying notes.

-21-

NORTHWEST PIPELINE CORPORATION

BALANCE SHEET

(Thousands of Dollars)

See accompanying notes.

-22-

NORTHWEST PIPELINE CORPORATION

BALANCE SHEET

(Thousands of Dollars)

See accompanying notes.

-23-

NORTHWEST PIPELINE CORPORATION

STATEMENT OF CASH FLOWS
(Thousands of Dollars)

See accompanying notes.

-24-

NORTHWEST PIPELINE CORPORATION

STATEMENT OF COMMON STOCKHOLDER'S EQUITY
(Thousands of Dollars)

See accompanying notes.

-25-

NORTHWEST PIPELINE CORPORATION

NOTES TO FINANCIAL STATEMENTS

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

CORPORATE STRUCTURE AND CONTROL

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

NATURE OF OPERATIONS

Pipeline owns and operates a 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

Pipeline is 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, and other costs and taxes
included in, or expected to be included in, future rates. As a rate-regulated
entity, Pipeline's 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.

BASIS OF PRESENTATION

Pipeline's 1983 acquisition by Williams has been accounted for using
the purchase method of accounting. Accordingly, an allocation of the purchase
price was assigned to the assets and liabilities of Pipeline, 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 $89.2
million, as of December 31, 2002, to Pipeline as current FERC policy does not
permit Pipeline to recover through its rates amounts in excess of original cost.
The accompanying financial statements reflect Pipeline's original basis in its
assets and liabilities.

ACCOUNTING ESTIMATES

The preparation of consolidated financial statements in conformity with
accounting principles generally accepted in the United States requires
management to make estimates and assumptions that affect the reported amounts of
assets, liabilities, revenues, expenses and disclosure of contingent assets and
liabilities. On an ongoing basis, Pipeline evaluates its estimates, including
those related to revenues subject to refund, bad debts, materials and supplies
obsolescence, property, plant and equipment and other long-lived assets, income
taxes, pensions and other postretirement benefits and contingent liabilities.
Pipeline bases its estimates on historical experience and on various other
assumptions that are believed to be reasonable under the circumstances, the
results of which form the basis for making judgments about the carrying values
of assets and liabilities that are not readily apparent from other sources.
Actual results could differ from such estimates.

PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment ("plant"), consisting principally of
natural gas transmission facilities, is recorded at original cost. Pipeline
accounts for repair and maintenance costs under the

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NORTHWEST PIPELINE CORPORATION

NOTES TO FINANCIAL STATEMENTS

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 3.08 percent, 3.09 percent and
3.16 percent for 2002, 2001 and 2000, respectively, including an allowance for
negative salvage.

ALLOWANCE FOR BORROWED AND EQUITY FUNDS USED DURING CONSTRUCTION

Allowance for funds used during construction ("AFUDC") represents the
estimated cost of borrowed and equity funds applicable to utility plant in
process of construction and are included as a cost of property, plant and
equipment because it constitutes an actual cost of construction under
established regulatory practices. The FERC has prescribed a formula to be used
in computing separate allowances for borrowed and equity AFUDC.

The composite rate used to capitalize AFUDC was approximately 10.0
percent in 2002 and 9.9 percent in each of the years 2001 and 2000. Equity AFUDC
of $5.5 million, $.8 million and $.5 million for 2002, 2001 and 2000,
respectively, is reflected in other income.

ADVANCES TO AFFILIATES

As a participant in Williams' cash management program, Pipeline makes
advances to and receives 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.

ACCOUNTS RECEIVABLE AND ALLOWANCE FOR DOUBTFUL RECEIVABLES

Accounts receivable are stated at the historical carrying amount net of
reserves or write-offs. Due to its customer base, Pipeline has not historically
experienced recurring credit losses in connection with its 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

Pipeline evaluates 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.

INCOME TAXES

Pipeline is included in Williams' consolidated federal income tax
return. Pipeline's 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 Pipeline's assets and liabilities.

DEFERRED CHARGES

Pipeline amortizes deferred charges over varying periods consistent
with the FERC approved accounting treatment for such deferred items. Unamortized
debt expense, debt discount and losses on

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reacquired long-term debt are amortized by the bonds outstanding method over the
related debt repayment periods.

CASH AND CASH EQUIVALENTS

Cash equivalents are stated at cost plus accrued interest, which
approximates fair value. Cash equivalents are highly liquid investments with an
original maturity of three months or less.

EXCHANGE GAS IMBALANCES

In the course of providing transportation services to customers,
Pipeline 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.

EXCESS SYSTEM GAS

Pipeline's excess system gas is valued at the average of the spot
market rates of the Canadian border and the Rocky Mountain market as published
in "Inside FERC's Gas Market Report".

REVENUE RECOGNITION

Revenues from the transportation of gas are recognized based on
contractual terms and the related transported volumes. Pipeline is subject to
FERC regulations and, accordingly, certain revenues collected may be subject to
possible refunds upon final orders in pending rate cases. Pipeline records rate
refund liabilities considering Pipeline 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

Pipeline is 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. Pipeline believes
that, with respect to any expenditures required to meet applicable standards and
regulations, the FERC would grant the requisite rate relief so that, for the
most part, such expenditures would be permitted to be recovered. Pipeline
believes that compliance with applicable environmental requirements is not
likely to have a material effect upon Pipeline's financial position.

INTEREST PAYMENTS

Cash payments for interest were $22.9 million, $39.9 million and $25.7
million, net of $2.6 million, $0.4 million and $0.3 million of interest
capitalized (allowance for borrowed funds used during construction) in 2002,
2001 and 2000, respectively.

EMPLOYEE STOCK BASED AWARDS

Williams' employee stock-based awards are accounted for under
Accounting Principles Board ("APB") Opinion No. 25, "Accounting for Stock Issued
to Employees" and related interpretations. Williams' fixed plan common stock
options generally do not result in compensation expense, because the exercise
price of the stock options equals the market price of the underlying stock on
the date of grant. The plans are described more fully in Note 4. The following
table illustrates the effect on net income if Pipeline had applied the fair
value recognition provisions of SFAS No. 123 to stock-based compensation.

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NORTHWEST PIPELINE CORPORATION

NOTES TO FINANCIAL STATEMENTS

Pro forma amounts for 2002 include compensation expense from Williams
awards made in 2002 and 2001 and compensation expense from certain Williams
awards made in 1999.

Pro forma amounts for 2001 include compensation expense from certain
Williams awards made in 1999 and compensation expense from Williams awards made
in 2001.

Pro forma amounts for 2000 include compensation expense from certain
Williams awards made in 1999 and the total compensation expense from Williams
awards made in 2000, as these awards fully vested in 2000 as a result of
accelerated vesting provisions.

The pro forma net income effects of applying SFAS 123 recognition of
compensation expense provided for the periods shown above may not be
representative of the effects on reported net income for future years.

The fair value of each award was estimated using the Black-Scholes
options pricing model. See Note 4 for the assumptions used in the calculation of
fair value.

NEW ACCOUNTING PRONOUNCEMENTS

In June 2001, the Financial Accounting Standards Board ("FASB") issued
SFAS No. 143, "Accounting for Asset Retirement Obligations," which is effective
for fiscal years beginning after June 15, 2002. The Statement requires legal
obligations associated with the retirement of long-lived assets to be recognized
at their fair value at the time that the obligations are incurred. Upon initial
recognition of a liability, that cost should be capitalized as part of the
related long-lived asset and allocated to expense over the useful life of the
asset. Pipeline will adopt the new rules on asset retirement obligations on
January 1, 2003. The impact of adoption is to be reported as a cumulative effect
of change in accounting principle. Retirement obligations have not been
estimated for assets with currently indeterminable lives including pipeline
transmission assets and gas gathering systems accordingly, the impact of
adopting the statement is not expected to have a material effect on Pipeline's
financial position or results of operations.

The FASB issued SFAS 144, "Accounting for Impairment or Disposal of
Long-Lived Assets." SFAS 144 supersedes SFAS 121, "Accounting for Impairment of
Long-Lived Assets and for Long-Lived Assets to be Disposed of" and the
accounting and reporting provisions of APB 30, "Reporting the Results of
Operations--Reporting the Effects of Disposal of a Segment of a Business, and
Extraordinary, Unusual and Infrequently Occurring Events and Transactions." SFAS
144 retains the accounting and reporting provisions of SFAS 121 for recognition
and measurement of long-lived asset impairment and for the measurement of
long-lived assets to be disposed of by sale and the accounting and reporting
provisions of APB 30. In addition to these fundamental provisions, SFAS 144
provides guidance for determining whether long-lived assets should be tested for
impairment and specific criteria for classifying assets to be disposed of as
held for sale. The statement is effective for fiscal years beginning after
December 15, 2001. Pipeline adopted the statement as of January 1, 2002. The
adoption of this statement had no material effect on Pipeline's financial
position or results of operations.

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NORTHWEST PIPELINE CORPORATION

NOTES TO FINANCIAL STATEMENTS

In the second quarter of 2002, the FASB issued SFAS No. 145,
"Rescission of FASB Statements No. 4, 44 and 64, Amendment of SFAS No 13, and
Technical Corrections." The rescission of SFAS No. 4 "Reporting Gains and Losses
from Extinguishment of Debt," and SFAS No. 64, "Extinguishments of Debt Made to
Satisfy Sinking-Fund Requirements, " requires that gains and losses from
extinguishment of debt only be classified as extraordinary items in the event
that they meet the criteria of APB Opinion No. 30. SFAS No. 44, "Accounting for
Intangible Assets of Motor Carriers," established accounting requirements for
the effects of transition to the Motor Carriers Act of 1980 and is no longer
required now that the transitions have been completed. Finally, the amendments
to SFAS No. 13, "Accounting for Leases," require certain lease modifications
that have economic effects, which are similar to sale-leaseback transactions, be
accounted for as sale-leaseback transactions. The provisions of this Statement
related to the rescission of SFAS No. 4 to be applied in fiscal years beginning
after May 15, 2002, while the provisions related to SFAS No. 13 are effective
for transactions occurring after May 15, 2002. All other provisions of the
Statement are effective for financial statements issued on or after May 15,
2002. There was no initial impact of SFAS No. 145 on Pipeline's results of
operations and financial position.

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)." Under this Statement, a liability
for a cost associated with an exit or disposal activity is recognized at fair
value when the liability is incurred rather than at the date of an entity's
commitment to an exit plan. 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 Pipeline's results of operations or financial position.

The FASB issued SFAS 148, "Accounting for Stock-Based Compensation -
Transition and Disclosure," which is effective for fiscal years ending after
December 15, 2002. SFAS 148 amends SFAS 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 25, "Accounting for Stock
Issued to Employees." The prospective method of transition under SFAS 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
148 amends the disclosure requirements of SFAS 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 148, pro forma
disclosures will be required in a specific tabular format in the "Summary of
Significant Accounting Policies". The Pipeline has adopted the disclosure
requirements of this statement effective December 31, 2002. The adoption had no
effect on the Pipeline's consolidated financial position or results of
operations. The Pipeline continues to account for its stock-based compensation
plans under APB 25. See "Employee Stock Based Awards".

The FASB issued FASB Interpretation ("FIN") No. 45, "Guarantor's
Accounting and Disclosure Requirements for Guarantees, including Indirect
Guarantees of Indebtedness of Others." This Interpretation requires the initial
recognition at fair value of guarantees issued or modified after December 31,
2002, and expands the disclosure requirements for guarantees. Initial adoption
of this Interpretation did not have any impact on Pipeline's results of
operations or financial position. The expanded disclosure requirements have been
incorporated in this annual report.

The FASB issued FIN 46, "Consolidation of Variable Interest Entities."
FIN 46 requires companies with a variable interest in a variable interest entity
to apply this guidance to that entity as of the beginning of the first interim
period beginning after June 15, 2003 for existing interests and immediately for
new interests. The application of the guidance could result in the consolidation
of a variable interest entity. As of December 31, 2002, the Pipeline has no
variable interest entities as defined by FIN 46.

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NORTHWEST PIPELINE CORPORATION

NOTES TO FINANCIAL STATEMENTS

RECLASSIFICATIONS

Certain reclassifications have been made in the 2001 and 2000 financial
statements to conform to the 2002 presentation.

2. CONTINGENT LIABILITIES AND COMMITMENTS

RATE AND REGULATORY MATTERS

GENERAL RATE CASE (DOCKET NO. RP93-5) On April 1, 1993, Pipeline began
collecting new rates, subject to refund, under its rate case filed October 1,
1992 ("1993 Rate Case"). Pipeline made refunds to customers in June 1998
totaling $27 million, including interest, reflecting the FERC's resolution of
all disputed matters in this case. Pipeline and other parties sought judicial
review of the FERC's decision concerning rate of return on equity. One party
sought judicial review of the inclusion of unpaid accruals in rate base. In July
1998, the FERC issued orders concerning its rate of return on equity policy in
rate proceedings of other pipelines adopting a formula that gives less weight to
the long-term growth component. In April 1999, the Court of Appeals for the D.C.
Circuit remanded the 1993 Rate Case to the FERC for application of its revised
rate of return on equity policy. On July 14, 1999, the FERC issued an order
requiring Pipeline to: (a) submit a surcharge plan to the FERC, (b) recalculate
rates consistent with the new weighting formula favoring short term growth, and
(c) address in a remand hearing the appropriate source for Gross Domestic
Product ("GDP") growth data. The new weighting formula generally results in a
higher authorized rate of return on equity. Pipeline and its customers resolved
by settlement those issues relating to long term GDP growth. In February 2000,
the FERC approved the long-term growth settlement and issued an order related to
return on equity issues requiring Pipeline to incorporate the effects of the
settlement and to calculate its allowed rate of return on equity consistent with
the recently announced policy changes in other proceedings. As a part of this
recalculation of allowed return on equity, the FERC provided that Pipeline must
use the median instead of the midpoint of the various results of Discounted Cash
Flow ("DCF") analysis for a proxy group. This resulted in a 13.67 percent return
on equity for Pipeline. On April 3, 2000, Pipeline made the necessary compliance
filings to implement the FERC's decision including the establishment of
surcharges in order to recollect moneys that shippers owe Pipeline for these
corrective actions. On July 14, 2000, the FERC issued an order denying customer
rehearing requests and approving Pipeline's compliance filing. The order
reaffirmed Pipeline's right to use the median result from the DCF proxy group
analysis. Some of Pipeline's customers sought judicial review concerning the
FERC's orders with respect to return on equity issues. On July 13, 2001, the
D.C. Circuit issued its decision affirming the FERC's earlier rulings on various
rate base, accounting, and risk issues, but remanding the case to the FERC to
allow the FERC to set forth more clearly its rationale for allowing Pipeline to
utilize the median result of the DCF proxy group analysis. On June 12, 2002, the
FERC issued an Order on Remand reaffirming its decision to utilize the median of
the proxy companies in setting Pipeline's return on equity. No requests for
rehearing were filed in response to the June 12, 2002 order. This decision
effectively brought the 1993 Rate Case to its conclusion.

GENERAL RATE CASE (DOCKET NO. RP95-409) On February 1, 1996, Pipeline
began collecting new rates, subject to refund, under the provisions of its rate
case filed August 1, 1995 ("1995 Rate Case"). During the first quarter of 1998,
the Administrative Law Judge ("ALJ") issued an Initial Decision. The ALJ found
that the facts of this case continue to support Pipeline's capital structure of
55 percent equity and 45 percent debt. The ALJ also determined that Pipeline
fits within the average risk range for determining pipeline return on equity and
allowed a return on equity of 11.2 percent. On June 1, 1999, the FERC issued its
order affirming many aspects of the ALJ's initial decision, but finding that the
return on equity issue should be resolved by using the FERC's new policy
concerning rate of return determinations. This resulted in an allowed return on
equity of 12.22 percent. On September 29, 2000, the FERC issued its Order on
Rehearing, which, for the most part, reaffirmed the FERC's earlier June 1, 1999
decision. Pipeline made a compliance filing on October 16, 2000. On July 11,
2001, the FERC issued an Order accepting Pipeline's compliance filings, subject
to Pipeline making some minor rate related changes relating to billing
determinants and cost of service recovery for facilities subject to
reimbursement agreements. On August 31, 2001, Pipeline made refunds to customers
totaling $43.1 million, including interest. Some shippers filed petitions for
review concerning return on equity issues. On October 25,

-31-

2002, the United States Court of Appeals for the D. C. Circuit affirmed the
FERC's decision in its treatment of return on equity issues. This decision
effectively brought the 1995 Rate Case to its conclusion.

NOTICE OF PROPOSED RULEMAKING (DOCKET NO. RM01-10-000) On September 27,
2001, the FERC issued a Notice of Proposed Rulemaking ("NOPR") proposing to
adopt 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 proposed standards would regulate the conduct of transmission providers with
their energy affiliates. The FERC proposed to define energy affiliates broadly
to include any transmission provider affiliate that engages in or is involved in
transmission (gas or electric) transactions, or manages or controls transmission
capacity, or buys, sells, trades or administers natural gas or electric energy
or engages in financial transactions relating to the sale or transmission of
natural gas or electricity. Current rules regulate the conduct of Pipeline and
its gas marketing affiliates. The FERC's staff analysis of the proposed
rulemaking proposed redefining energy affiliates to exclude affiliated
transmission providers. If the proposed rules are adopted as proposed, these new
standards would require new compliance measures by Pipeline.

NOTICE OF INQUIRY (DOCKET NO. PL02-6-000) On July 17, 2002, the FERC
issued a Notice of Inquiry to seek comments on its negotiated rate policies and
practices. The FERC states that it is undertaking a review of the recourse rate
as a viable alternative and safeguard against the exercise of market power of
interstate gas pipelines, as well as the entire spectrum of issues related to
its negotiated rate program. Pipeline has negotiated certain rates under the
FERC's existing negotiated rate program, and participated in comments filed in
this proceeding by Williams in support of the FERC's existing negotiated rate
program.

NOTICE OF PROPOSED RULEMAKING (DOCKET NO. RM02-14-000) On August 1,
2002, the FERC issued a NOPR that proposes restrictions on various types of cash
management programs employed by companies in the energy industry such as
Williams and its subsidiaries, including Pipeline. In addition to stricter
guidelines regarding the accounting for and documentation of cash management or
cash pooling programs, the FERC proposal, if made final, would preclude 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.
Williams' and Pipeline's current credit ratings are not investment grade.
Pipeline participated in comments filed in this proceeding on August 28, 2002 by
the Interstate Natural Gas Association of America. On September 25, 2002, the
FERC convened a technical conference to discuss issues raised in the comments
filed by parties in this proceeding.

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
Pipeline. 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. On April 9, 1999, the DOJ announced that it was declining 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. On October 21, 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. On October 9, 2002, the court granted a motion to
dismiss Grynberg's royalty valuation claims. Grynberg's measurement claims
remain pending against Williams and the other defendants.

On June 8, 2001, fourteen Williams entities, including Pipeline, were
named as defendants in a nationwide class action lawsuit which has been pending
against other defendants, generally pipeline and

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NORTHWEST PIPELINE CORPORATION

NOTES TO FINANCIAL STATEMENTS

gathering companies, for more than one year. The plaintiffs allege that the
defendants, including the Williams defendants, have engaged in mismeasurement
techniques that distort the heating content of natural gas, resulting in an
alleged underpayment of royalties to the class of producer plaintiffs. In
September 2001, plaintiffs' counsel voluntarily dismissed two of the fourteen
Williams entities named as defendants in the lawsuit. In November 2001, the
Williams defendants, along with other coordinating defendants, filed a motion to
dismiss on non-jurisdictional grounds. In January 2002, most of the Williams
defendants, along with a group of coordinating defendants filed a motion to
dismiss for lack of personal jurisdiction. On August 19, 2002, defendants'
motion to dismiss on non-jurisdictional grounds was denied. On September 17,
2002, the plaintiffs filed a motion for class certification. The Williams
entities joined with other defendants in contesting certification of the
plaintiff class and this issue, along with the personal jurisdiction motion,
remains pending.

OTHER LEGAL AND REGULATORY MATTERS

In addition to the foregoing, various other proceedings are pending
against Pipeline incidental to its operations.

SUMMARY

While no assurances may be given, Pipeline does not believe that the
ultimate resolution of the foregoing matters, taken as a whole and after
consideration of amounts accrued, recovery from customers, insurance coverage or
other indemnification arrangements, will have a materially adverse effect upon
Pipeline's financial position, results of operations, or cash flow requirements.

OTHER COMMITMENTS

Commitments for construction and acquisition of property, plant and
equipment are approximately $354.8 million at December 31, 2002.

3. DEBT, FINANCING ARRANGEMENTS AND LEASES

DEBT COVENANTS

The terms of Pipeline's 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. Pipeline's
debt indentures also contain restrictions, which, under certain circumstances,
limit the issuance of additional debt and restrict the disposal of a major
portion of its natural gas pipeline system.

ADJUSTABLE INTEREST RATE NOTES

On May 15, 2001, under the terms of the note agreement, Pipeline
prepaid, without penalty, the outstanding $1.7 million balance of its adjustable
rate notes with accrued interest. Prepayment was made from Pipeline's operations
and available cash.

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NORTHWEST PIPELINE CORPORATION

NOTES TO FINANCIAL STATEMENTS

LONG-TERM DEBT

Long-term debt consists of the following:

As of December 31, 2002, cumulative sinking fund requirements and other
maturities of long-term debt (at face value) for each of the next five years are
as follows:

LINE-OF-CREDIT ARRANGEMENTS

Williams and certain of its subsidiaries, including Pipeline, are
parties to a $700 million credit agreement (Credit Agreement), under which
Pipeline can borrow up to $400 million to the extent the funds available under
the Credit Agreement have not been borrowed by Williams or other subsidiaries.
The Credit Agreement expires in July 2005. Interest rates vary with current
market conditions based on the base rate of Citibank N.A., federal funds rate or
the London Interbank Offered Rate. The Credit Agreement contains restrictions,
which limit, under certain circumstances, the issuance of additional debt, the
attachment of liens on any assets and any change of ownership of Pipeline. As
Williams completes certain asset sales, the commitments from participating banks
in the Credit Agreement will be reduced to $400 million, and with further asset
sales could be reduced below that amount, but Pipeline will continue to have
borrowing capacity up to the lesser of $400 million or the amount that Williams
would be able to borrow to the extent the funds available under the Credit
Agreement have not been borrowed by Williams or other participating subsidiaries
or that otherwise would be required to remain available to Williams. At December
31, 2002, the commitment from participating banks had been reduced to $463
million, the borrowing capacity available to Pipeline was $400 million, and
Pipeline had no outstanding borrowings under this agreement. Pipeline's assets
have not been pledged to secure any indebtedness of Williams or its other
affiliates, either under the Credit Agreement or pursuant to any other credit
facility of Williams and its other affiliates.

-34-

NORTHWEST PIPELINE CORPORATION

NOTES TO FINANCIAL STATEMENTS

LEASES

Pipeline's 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 Pipeline's 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.

Pipeline subleases portions of its 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:

Operating lease rental expense amounted to $5.4 million, $6.1 million
and $8.8 million for 2002, 2001 and 2000, respectively.

4. EMPLOYEE BENEFIT PLANS

PENSION AND POSTRETIREMENT MEDICAL PLANS

Pipeline's employees are covered by Williams' non-contributory
defined-benefit pension plan and Williams' health care plan that provides
postretirement medical benefits to certain retired employees. Contributions for
pension and postretirement medical benefits related to Pipeline's participation
in these plans were $5.9 million, $2.3 million and $2.8 million in 2002, 2001
and 2000, respectively. These amounts are currently recoverable in Pipeline's
rates.

At December 31, 2002, Pipeline recorded a minimum pension liability of
$3.2 million, net of $2.0 million tax, which is included as a component of
Pipeline's other comprehensive loss for the year 2002.

DEFINED CONTRIBUTION PLAN

Pipeline's employees are also covered by various Williams' defined
contribution plans. Pipeline's costs related to these plans totaled $2.3
million, $2.1 million and $1.8 million in 2002, 2001 and 2000, respectively.

-35-

NORTHWEST PIPELINE CORPORATION

NOTES TO FINANCIAL STATEMENTS

STOCK-BASED COMPENSATION

Williams has several plans providing for common-stock-based awards to
its employees and employees of its subsidiaries. The plans permit the granting
of various types of awards including, but not limited to, stock options, stock
appreciation rights, 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 and the grant price for stock appreciation rights may not be less
than the market price of the underlying stock on the date of grant. Stock
options generally become exercisable in one-third increments each year from the
anniversary of the grant or after three or five years, subject to accelerated
vesting if certain future stock prices or if specific financial performance
targets are achieved. Stock options expire 10 years after grant.

The following summary reflects stock option activity for Williams
common stock attributable to Pipeline and related information for 2002, 2001 and
2000 (options in thousands):

- ----------

(1) Effective with the spinoff of Williams Communications Group ("WCG") on
April 23, 2001, by Williams, the number of unexercised Williams stock
options and the exercise price were adjusted to preserve the intrinsic
value of the stock options that existed prior to the spinoff.

The following summary provides information about stock options granted
to employees of Pipeline that are outstanding and exercisable at December 31,
2002 (options in thousands):

-36-

NORTHWEST PIPELINE CORPORATION

NOTES TO FINANCIAL STATEMENTS

The estimated fair value at the date of grant of options for Williams
common stock granted in 2002, 2001 and 2000, using the Black-Scholes
option-pricing model is as follows:

5. INCOME TAXES

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

-37-

NORTHWEST PIPELINE CORPORATION

NOTES TO FINANCIAL STATEMENTS

The provision for income taxes includes:

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

Net cash payments made to Williams for income taxes were $29.7 million,
$35.9 million and $26.3 million in 2002, 2001 and 2000, 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 Pipeline's 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. Pipeline
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
Pipeline's long term debt,

-38-

NORTHWEST PIPELINE CORPORATION

NOTES TO FINANCIAL STATEMENTS

including current maturities, were $368 million and $328 million, respectively,
at December 31, 2002, and $368 million and $369 million, respectively, at
December 31, 2001.

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 Pipeline's
operating revenues were generated from each of the following customers:

Pipeline's 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.

Pipeline, 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. Pipeline acted as the
servicing agent for the sold receivables. The sale of receivables program
expired on July 25, 2002, and on July 26, 2002, Pipeline completed the
repurchase of $15 million of trade accounts receivable previously sold. For
2002, cash inflows from the SPE were approximately $112 million. The sales of
these receivables resulted in a net charge to results of operations of
approximately $.2 million and $.7 million in 2002 and 2001, respectively.

RELATED PARTY TRANSACTIONS

As a subsidiary of Williams, Pipeline engages in transactions with
Williams and other Williams subsidiaries characteristic of group operations. As
a participant in Williams' cash management program, Pipeline makes advances to
and receives advances from Williams through Pipeline's parent company, WGP. The
advances are represented by demand notes. The interest rate on intercompany
demand notes is LIBOR on the first day of the month plus an applicable margin
based on Pipeline's current credit ratings as determined by Moody's Investors
Service and Standard and Poor's. Pipeline received interest income from advances
to these affiliates of $1.6 million, $3.1 million, and $3.4 million during 2002,
2001 and 2000, respectively.

Williams' corporate overhead expenses allocated to Pipeline were $9.7
million, $6.9 million and $4.5 million for 2002, 2001 and 2000, respectively.
Such expenses have been allocated to Pipeline 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, aviation, accounting, internal audit and other administrative
services to Pipeline on a direct charge basis, which totaled $4.6 million, $5.0
million and $4.8 million for 2002, 2001 and 2000, respectively.

During the periods presented, Pipeline's revenues include
transportation and exchange transactions with subsidiaries of Williams. Combined
revenues for these activities totaled $2.2 million, $1.8 million and $1.2
million for 2002, 2001 and 2000, respectively.

-39-

NORTHWEST PIPELINE CORPORATION

NOTES TO FINANCIAL STATEMENTS

Pipeline has 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.

Pipeline has 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. QUARTERLY INFORMATION (UNAUDITED)

The following is a summary of unaudited quarterly financial data for
2002 and 2001:

9. SUBSEQUENT EVENT (UNAUDITED)

On March 4, 2003, Pipeline sold $175 million of senior notes due 2010
to certain institutional investors in an offering exempt from the registration
requirements of the Securities Act of 1933. Pipeline intends to use the proceeds
for general corporate purposes, including the funding of capital expenditures.

-40-

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

None.

PART III

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

ITEM 14. CONTROLS AND PROCEDURES

An evaluation of the effectiveness of the design and operation of
Pipeline's disclosure controls and procedures (as defined in Rules 13a-14(c) and
15d-14(c) of the Securities Exchange Act) was performed within the 90 days prior
to the filing date of this report. This evaluation was performed under the
supervision and with the participation of Pipeline's management, including
Pipeline's Chief Executive Officer and Vice President and Treasurer. Based upon
that evaluation, Pipeline's Chief Executive Officer and Vice President and
Treasurer concluded that these disclosure controls and procedures are effective.

There have been no significant changes in Pipeline's internal controls
or other factors that could significantly affect internal controls since the
certifying officers' most recent evaluation of those controls.

-41-

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 19. 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) First Amended and Restated Credit Agreement dated as of October
31, 2002, among Pipeline, Williams and certain affiliated
companies, as borrowers, and the banks named therein, JPMorgan
Chase Bank and Commerzbank AG, as co-syndication agents, Credit
Lyonnais New York Branch, as documentation agent, and Citicorp
USA, Inc., as agent, and Salomon Smith Barney Inc., as arranger.
(Exhibit 10.2 to Williams Form 10-Q for the quarter ended
September 30, 2002, Commission File Number 1-4174).

(10) Material contracts:

(c) *(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).

-42-

(23) Consent of Independent Auditors

(24) Power of Attorney with Certified Resolution

(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.

-43-

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. Heinrichs
--------------------------------------
Jeffrey P. Heinrichs
Controller

Date: March 18, 2003

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.

Date: March 18, 2003

-44-

Certifications

I, J. Douglas Whisenant, certify that:

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

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

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

4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant
and have:

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

b) evaluated the effectiveness of the registrant's disclosure
controls and procedures as of a date within 90 days prior to the
filing date of this annual report (the "Evaluation Date"); and

c) presented in this annual report our conclusions about the
effectiveness of the disclosure controls and procedures based on
our evaluation as of the Evaluation Date;

5. The registrant's other certifying officers and I have disclosed, based
on our most recent evaluation, to the registrant's auditors and the
audit committee of registrant's board of directors (or persons
performing the equivalent functions):

a) all significant deficiencies in the design or operation of
internal controls which could adversely affect the registrant's
ability to record, process, summarize and report financial data
and have identified for the registrant's auditors any material
weaknesses in internal controls; and

b) any fraud, whether or not material, that involves management or
other employees who have a significant role in the registrant's
internal controls; and

6. The registrant's other certifying officers and I have indicated in
this annual report whether there were significant changes in internal
controls or in other factors that could significantly affect internal
controls subsequent to the date of our most recent evaluation,
including any corrective actions with regard to significant
deficiencies and material weaknesses.

Dated: March 18, 2003 By /s/ J. Douglas Whisenant
-------------- -------------------------------------
J. Douglas Whisenant
President and Chief Executive Officer
(Principal Executive Officer)

Certifications

I, Richard D. Rodekohr, certify that:

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

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

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

4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant
and have:

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

b) evaluated the effectiveness of the registrant's disclosure
controls and procedures as of a date within 90 days prior to the
filing date of this annual report (the "Evaluation Date"); and

c) presented in this annual report our conclusions about the
effectiveness of the disclosure controls and procedures based on
our evaluation as of the Evaluation Date;

5. The registrant's other certifying officers and I have disclosed, based
on our most recent evaluation, to the registrant's auditors and the
audit committee of registrant's board of directors (or persons
performing the equivalent functions):

a) all significant deficiencies in the design or operation of
internal controls which could adversely affect the registrant's
ability to record, process, summarize and report financial data
and have identified for the registrant's auditors any material
weaknesses in internal controls; and

b) any fraud, whether or not material, that involves management or
other employees who have a significant role in the registrant's
internal controls; and

6. The registrant's other certifying officers and I have indicated in
this annual report whether there were significant changes in internal
controls or in other factors that could significantly affect internal
controls subsequent to the date of our most recent evaluation,
including any corrective actions with regard to significant
deficiencies and material weaknesses.

Dated: March 18, 2003 By /s/ Richard D. Rodekohr
-------------- ---------------------------------------
Richard D. Rodekohr
Vice President and Treasurer
(Principal Financial Officer)

EXHIBIT INDEX