NORTHERN BORDER PIPELINE CO - 10-K Annual Report

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UNITED STATES SECURITIES AND EXCHANGE
COMMISSION
WASHINGTON, D.C. 20549

-----------------------

F O R M 10-K

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2002 Commission file number: 333-88577

NORTHERN BORDER PIPELINE COMPANY
(Exact name of registrant as specified in its charter)

TEXAS 74-2684967
(State or other jurisdiction (I.R.S. Employer
of incorporation or organization) Identification No.)

13710 FNB PARKWAY, OMAHA, NEBRASKA 68154-5200
(Address of principal executive offices)(zip code)
Registrant's telephone number, including area code: 402-492-7300

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SECURITIES REGISTERED PURSUANT TO SECTION 12(B) OF THE ACT:

Title of each class Name of each exchange on which registered
- ------------------- -----------------------------------------
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 by Rule 12b-2 of the Securities Exchange Act of 1934).
Yes [ ] No [X]

Aggregate market value of the voting and non-voting common equity held
by non-affiliates of the registrant on June 28, 2002, was $0.

NORTHERN BORDER PIPELINE COMPANY
TABLE OF CONTENTS

PAGE NO.
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PART I

Item 1. Business 1
Item 2. Properties 10
Item 3. Legal Proceedings 11
Item 4. Submission of Matters to a Vote of Security Holders 11

PART II

Item 5. Market for Registrant's Common Equity and Related
Stockholder Matters 12
Item 6. Selected Financial Data 13
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations 14
Item 7a. Quantitative and Qualitative Disclosures About
Market Risk 24
Item 8. Financial Statements and Supplementary Data 25
Item 9. Changes in and Disagreements With Accountants on
Accounting and Financial Disclosure 25

PART III

Item 10. Partnership Management 26
Item 11. Executive Compensation 28
Item 12. Security Ownership of Certain Beneficial Owners
and Management 31
Item 13. Certain Relationships and Related Transactions 31
Item 14. Controls and Procedures 32

PART IV

Item 15. Exhibits, Financial Statement Schedules and
Reports on Form 8-K. 33

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PART I

ITEM 1. BUSINESS

GENERAL

Northern Border Pipeline Company is a general partnership formed in
1978. Our general partners are Northern Border Partners, L.P. and TC PipeLines,
LP, both of which are publicly traded partnerships. Each of Northern Border
Partners and TC PipeLines holds its interest in us, 70% and 30% of voting power,
respectively, through a subsidiary limited partnership. The general partners of
Northern Border Partners and its subsidiary limited partnership are Northern
Plains Natural Gas Company and Pan Border Gas Company, both subsidiaries of
Enron Corp., and Northwest Border Pipeline Company, a subsidiary of TransCanada
PipeLines Limited. The general partner of TC PipeLines and its subsidiary
limited partnership, TC PipeLines GP, Inc., is also a subsidiary of TransCanada.

We own an interstate pipeline system that transports natural gas from
the Montana-Saskatchewan border to natural gas markets in the midwestern United
States. This pipeline system connects with multiple pipelines that provide
shippers with access to the various natural gas markets served by those
pipelines. In the year ended December 31, 2002, we estimate that we transported
approximately 20% of the total amount of natural gas imported from Canada to the
United States. Over the same period, approximately 89% of the natural gas
transported was produced in the western Canadian sedimentary basin located in
the provinces of Alberta, British Columbia and Saskatchewan.

We transport gas for shippers under a tariff regulated by the Federal
Energy Regulatory Commission ("FERC"). The tariff specifies the calculation of
amounts to be paid by shippers and the general terms and conditions of
transportation service on the pipeline system. Northern Border Pipeline's
revenues are derived from agreements for the receipt and delivery of gas at
points along the pipeline system as specified in each shipper's individual
transportation contract. Northern Border Pipeline does not own the gas that it
transports, and therefore it does not assume natural gas commodity price risk
for quantities transported.

Our management is overseen by a four-member management committee. Three
representatives are designated by Northern Border Partners, with each of its
general partners selecting one representative; and one representative is
designated by TC PipeLines. Voting power on the management committee is
allocated among Northern Border Partners' three representatives in proportion to
their general partner interests in Northern Border Partners. As a result, the
70% voting power of Northern Border Partners' three representatives on the
management committee is allocated as follows: 35% to the representative
designated by Northern Plains, 22.75% to the representative designated by Pan
Border and 12.25% to the representative designated by Northwest Border. Northern
Plains and Pan Border are subsidiaries of Enron. Therefore, Enron controls
57.75% of the voting power of the management committee and has the right to
select two of the members. On December 2, 2001,

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Enron filed a voluntary petition for Chapter 11 protection in bankruptcy court.
On March 19, 2003, Enron announced its intention to create a new pipeline
operating entity, which will include Enron's interests in Northern Plains and
Pan Border. See Item 7. "Management's Discussion and Analysis of Financial
Condition and Results of Operations - Update On The Impact Of Enron's Chapter 11
Filing On Our Business" and Item 13. "Certain Relationships and Related
Transactions."

Our pipeline system is operated by Northern Plains pursuant to an
operating agreement. As of December 31, 2002, Northern Plains employed
approximately 203 individuals located at its headquarters in Omaha, Nebraska,
and at various locations along the pipeline route and also used employees and
information technology systems of its affiliates to provide its services.
Northern Plains' employees are not represented by any labor union and are not
covered by any collective bargaining agreements.

THE PIPELINE SYSTEM

We own a 1,249-mile interstate pipeline system that transports natural
gas from the Montana-Saskatchewan border near Port of Morgan, Montana to natural
gas markets in the midwestern United States. Construction of the pipeline was
initially completed in 1982. Our pipeline system was expanded and/or extended in
1991, 1992, 1998 and 2001. Our pipeline system connects directly and through
multiple pipelines to various natural gas markets in the United States.

Our pipeline system consists of 822 miles of 42-inch diameter pipe from
the Canadian border to Ventura, Iowa capable of transporting a total of 2,374
million cubic feet per day ("mmcfd"); 30-inch diameter pipe and 36-inch diameter
pipe, each approximately 147 miles in length, capable of transporting 1,484
mmcfd in total from Ventura, Iowa to Harper, Iowa; 226 miles of 36-inch diameter
pipe and 19 miles of 30-inch diameter pipe capable of transporting 844 mmcfd
from Harper, Iowa to Manhattan, Illinois (Chicago area); and 35 miles of 30-inch
diameter pipe capable of transporting 545 mmcfd from Manhattan, Illinois to a
terminus near North Hayden, Indiana. Along the pipeline there are 16 compressor
stations with total rated horsepower of 499,000 and measurement facilities to
support the receipt and delivery of gas at various points. Other facilities
include four field offices and a microwave communication system with 51 tower
sites.

Our pipeline system has pipeline access to natural gas reserves in the
western Canadian sedimentary basin in the provinces of Alberta, British Columbia
and Saskatchewan in Canada, domestic natural gas produced within the Williston
Basin and synthetic gas produced at the Dakota Gasification plant in North
Dakota. In addition, the pipeline is capable of physically receiving natural gas
at two locations near Chicago. At its northern end, the pipeline system's gas
supplies are received through an interconnection with Foothills Pipe Lines
(Sask.) Ltd. system in Canada. The Foothills system, owned by TransCanada and
Duke Energy, is connected to TransCanada's Alberta system and the pipeline
system owned by Transgas Limited in Saskatchewan. Also at the north end, the
pipeline system connects to a domestic natural gas gathering system owned by
EnCana Corporation. In North Dakota, our pipeline system connects with
facilities of Northern Natural Gas

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Company at Buford, which facilities in turn are connected to Williston Basin
Interstate Pipeline and the gathering system owned by Bear Paw Energy, LLC, a
wholly-owned subsidiary of Northern Border Partners. Other locations in North
Dakota where we can receive gas are interconnections with Williston Basin
Interstate Pipeline at Glen Ullin and Amerada Hess Corporation at Watford City
and facilities of Dakota Gasification Company at Hebron. Near its terminus, the
pipeline system is capable of physically receiving natural gas from Northern
Illinois Gas Company at Troy Grove, Illinois and from Midwestern Gas
Transmission Company, a wholly-owned subsidiary of Northern Border Partners, at
Channahon, Illinois. For the year ended December 31, 2002, of the natural gas
transported on our pipeline system, approximately 89% was produced in Canada,
approximately 5% was produced by the Dakota Gasification plant and approximately
6% was produced in the Williston Basin.

INTERCONNECTS

Our pipeline system connects with multiple pipelines of various
interstate, intrastate and local distribution companies that provide our
shippers with access to the various natural gas markets served by those
pipelines. The larger interconnections are with the pipeline facilities of:

o Northern Natural Gas Company at Ventura, Iowa as well as multiple
smaller interconnections in South Dakota, Minnesota and Iowa;

o Natural Gas Pipeline Company of America at Harper, Iowa;

o MidAmerican Energy Company at Iowa City and Davenport, Iowa and
Cordova, Illinois;

o Alliant Power Company at Prophetstown, Illinois;

o Northern Illinois Gas Company at Troy Grove and Minooka,
Illinois;

o Midwestern Gas Transmission Company near Channahon, Illinois;

o ANR Pipeline Company near Manhattan, Illinois;

o Vector Pipeline L.P. in Will County, Illinois;

o Guardian Pipeline, L.L.C., an affiliate of Northern Border
Partners, in Will County, Illinois;

o The Peoples Gas Light and Coke Company near Manhattan, Illinois;
and

o Northern Indiana Public Service Company near North Hayden,
Indiana at the terminus of the pipeline system.

Several market centers, where natural gas transported on the pipeline
system is sold, traded and received for transport to

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significant consuming markets in the Midwest and to interconnecting pipeline
facilities, have developed on the pipeline system. The largest of these market
centers is at our Ventura, Iowa connection with Northern Natural Gas Company.
Two other market center locations are the Harper, Iowa connection with Natural
Gas Pipeline Company of America and our multiple interconnects in the Chicago
area that include connections with Northern Illinois Gas Company, The Peoples
Gas Light and Coke Company and Northern Indiana Public Service Company, as well
as four interstate pipelines.

SHIPPERS

The pipeline system serves more than 50 firm transportation shippers
with diverse operating and financial profiles. Based upon shippers' contractual
obligations, as of December 31, 2002, 91% of the firm capacity is contracted by
producers and marketers. The remaining firm capacity is contracted to local
distribution companies (6%), interstate pipelines (2%) and end-users (1%). As of
December 31, 2002, the termination dates of these contracts ranged from March
31, 2003 to December 21, 2013, and the weighted average contract life, based
upon annual contractual obligations, was approximately four and one-half years.
Contracts for approximately 42% of the capacity will expire during 2003. See
Item 7. "Management's Discussion and Analysis of Financial Condition and Results
of Operations - Outlook."

Our mix and number of shippers may change throughout the year as a
result of our shippers utilizing our capacity release provisions that allow them
to release all or part of their capacity to other shippers, either permanently
for the full term of their contract or temporarily. Under the terms of our
tariff, a temporary capacity release does not relieve the original contract
shipper from its payment obligations if the replacement shipper fails to pay.
Shippers on the pipeline system temporarily released capacity during 2002 for
varying periods of time. There were also permanent releases of capacity to other
shippers for the full term of the contracts.

As of December 31, 2002, the largest shipper, Pan-Alberta Gas (U.S.)
("Pan-Alberta") is obligated for approximately 20% of the contracted firm
capacity, of which approximately 3% of the total contracted capacity has been
temporarily released by Pan-Alberta to other shippers through October 31, 2003.
Pan-Alberta's firm contracts expire October 31, 2003. Mirant Americas Energy
Marketing, LP, who manages the assets of Pan-Alberta Gas, Ltd., including
Pan-Alberta's contracts with us, is also obligated for approximately 10% of the
contracted firm capacity. Mirant's firm contracts expire in October 2006 and
December 2008. Mirant and Pan-Alberta have agreed to maintain credit support in
accordance with our tariff, including letters of credit, that mitigate a portion
of our credit exposure. The only other shipper that held over 10% of the
contracted firm capacity at December 31, 2002, is BP Canada Energy Marketing
Corp., with approximately 12% of the contracted firm capacity, of which
approximately 8% of the total contracted capacity expires on October 31, 2003.
See Item 7. "Management's Discussion and Analysis of Financial Condition and
Results of Operations - Outlook."

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DEMAND FOR TRANSPORTATION CAPACITY

Our long-term financial condition is dependent on the continued
availability of economic western Canadian natural gas supplies for import into
the United States. Natural gas reserves may require 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 pipelines
that interconnect with the interstate pipelines' systems. 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 of western Canadian natural gas
supplies. Additional pipeline export capacity also could accelerate depletion of
these reserves. Furthermore, the availability of export capacity could also
affect the demand or value of the transport on our pipeline system.

Our business also depends on the level of demand for natural gas in the
markets the pipeline system serves. The volumes of natural gas delivered to
these markets from other sources affect the demand for both the natural gas
supplies and the use of our pipeline system. Demand for natural gas to serve
other markets also influences the ability and willingness of shippers to use our
pipeline system to meet demand in the markets that we serve.

A variety of factors could affect the demand for natural gas in the
markets that we serve. These factors include:

o economic conditions;

o fuel conservation measures;

o alternative energy requirements and prices;

o gas storage inventory levels;

o climatic conditions;

o government regulation; and

o technological advances in fuel economy and energy generation
devices.

Interstate pipelines' primary exposure to market risk occurs at the
time existing transportation contracts expire and are subject to renegotiation.
A key determinant of the value that customers can realize from firm
transportation on a pipeline is the basis differential, or market price spread,
between two points on the pipeline. The difference in natural gas prices between
the points along the pipeline where gas enters and where gas is delivered
represents the gross margin that a customer can expect to achieve from holding
transportation capacity at any point in time. This margin and its variability
become important factors in determining the transportation rate customers are
willing to pay when they renegotiate their transportation contracts. The basis
differential between markets

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can be affected by trends in production, available capacity, storage
inventories, weather and general market demand in the respective areas.

We cannot predict whether these or other factors will have an adverse
effect on demand for use of our pipeline system or how significant that adverse
effect could be.

INTERSTATE PIPELINE COMPETITION

We compete with other pipeline companies that transport natural gas
from the western Canadian sedimentary basin or that transport natural gas to
end-use markets in the midwest. Our competitive position is affected by the
availability of Canadian natural gas for export, the availability of other
sources of natural gas and demand for natural gas in the United States. Demand
for transportation services on our system is affected by natural gas prices, the
relationship between export capacity from and production in the western Canadian
sedimentary basin and natural gas shipped from producing areas in the United
States. Shippers of natural gas produced in the western Canadian sedimentary
basin also have other options to transport Canadian natural gas to the United
States, including transportation on the Alliance Pipeline, on TransCanada's
pipeline system through various interconnects with U.S. interstate pipelines or
to markets on the West Coast.

The Alliance Pipeline competes directly with us in the transportation
of natural gas from the western Canadian sedimentary basin to the Chicago area.
Because it transports liquids-rich natural gas, the Alliance Pipeline has no
interconnections with other pipelines upstream of the liquids extraction
facilities, which are located near Chicago. This contrasts with our pipeline
system, which serves various markets through interconnections with other
pipelines along its route.

The competitive impact of the Alliance Pipeline in the Chicago market
area has been mitigated by the continuing development of additional capacity to
ship natural gas from the Chicago area to other markets in the United States.
Vector Pipeline L.P. interconnects with the Alliance Pipeline and transports gas
eastward to a terminus in eastern Canada. Guardian Pipeline was placed into
service in December 2002 and interconnects with Northern Border Pipeline.
Guardian Pipeline delivers into markets in Wisconsin and could provide access to
additional markets for our shippers.

Natural gas is also produced in the United States and transported by
competing pipeline systems to the same markets as those served by our pipeline
system.

FERC REGULATION

We are subject to extensive regulation by the FERC as a "natural gas
company" under the Natural Gas Act. Under the Natural Gas Act and the Natural
Gas Policy Act, the FERC has jurisdiction with respect to virtually all aspects
of our business, including:

o transportation of natural gas;

o rates and charges;

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o construction of new facilities;

o extension or abandonment of service and facilities;

o accounts and records;

o depreciation and amortization policies;

o the acquisition and disposition of facilities; and

o the initiation and discontinuation of services.

Where required, we hold certificates of public convenience and
necessity issued by the FERC covering our facilities, activities and services.
Under Section 8 of the Natural Gas Act, the FERC has the power to prescribe the
accounting treatment for items for regulatory purposes. Our books and records
may be periodically audited by the FERC under Section 8. We were notified in
November 2002 that we are one of the companies selected by the FERC to undergo
an industry-wide audit of FERC-assessed annual charges. The overall audit
objective is to determine compliance with FERC accounting requirements and
regulations as they relate to the calculation and assessment of annual charges
by validating the accuracy of the data filed annually with the FERC. The audit
covers the period of January 1, 2001 to December 31, 2001. Based on our
discussion with them, the FERC is intending to issue its final report by the end
of the second quarter of 2003. We do not believe the results of the audit will
have a material adverse impact on our results of operation or financial
position.

The FERC regulates the rates and charges for transportation in
interstate commerce. Natural gas companies may not charge rates exceeding rates
judged just and reasonable by the FERC. Generally, rates are based on the cost
of service including recovery of and a return on the pipeline's actual
historical cost investment. In addition, the FERC prohibits natural gas
companies from unduly preferring or unreasonably discriminating against any
person with respect to pipeline rates or terms and conditions of service. Some
types of rates may be discounted without further FERC authorization and rates
may be negotiated subject to FERC approval. The rates and terms and conditions
for our service are found in our FERC approved tariff.

Transportation rates are established periodically in FERC proceedings
known as rate cases. Under our tariff, we are allowed to charge for our services
on the basis of stated transportation rates established in our 1999 rate case.
We may also provide services under negotiated and discounted rates. Firm
shippers that contract for the stated transportation rate are obligated to pay a
monthly demand charge, regardless of the amount of natural gas they actually
transport, for the term of their contracts. Approximately 98% of the agreed upon
cost of service or revenue level is attributed to demand charges. The remaining
2% of the agreed upon revenue level is attributed to commodity charges based on
the volumes of gas actually transported. Under the terms of settlement in our
1999 rate case, neither our existing shippers nor we can seek rate changes until
November 1, 2005, at which time we must file a rate case. Prior to this rate
case, we will not be permitted to increase rates if costs

7

increase, nor will we be required to reduce rates based on cost savings. As a
result, our earnings and cash flow will depend on future costs, contracted
capacity, the volumes of gas transported and our ability to recontract capacity
at acceptable rates.

Until new transportation rates are approved by FERC, we continue to
depreciate our transmission plant at the FERC approved annual depreciation rate.
Our annual depreciation rate on transmission plant in service is 2.25%. In order
to avoid a decline in transportation rates set in future rate cases as a result
of accumulated depreciation, we must maintain or increase our rate base by
acquiring or constructing assets that replace or add to existing pipeline
facilities or by adding new facilities.

In our 1995 rate case, the FERC addressed the issue of whether the
federal income tax allowance included in our proposed cost of service was
reasonable in light of previous FERC rulings. In those rulings, the FERC held
that an interstate pipeline is not entitled to a tax allowance for income
attributable to limited partnership interests held by individuals. The
settlement of our 1995 rate case provided that until at least December 2005, we
could continue to calculate the allowance for income taxes in the manner we had
historically used. In addition, a settlement adjustment mechanism was
implemented, which effectively reduced the return on rate base. These provisions
of the 1995 rate case were maintained in the settlement of our 1999 rate case.

We also provide interruptible transportation service. Interruptible
transportation service is transportation in circumstances when capacity is
available after satisfying firm service requests. The maximum rate that may be
charged to interruptible shippers is calculated as the sum of the firm
transportation maximum reservation charge and commodity rate. Under our tariff,
we share net interruptible transportation service revenue and any new services
revenue on an equal basis with our firm shippers through October 31, 2003.
However, we are permitted to retain revenue from interruptible transportation
service to offset any decontracted firm capacity.

We are subject to the requirements of FERC Order Nos. 497 and 566,
which prohibit preferential treatment by interstate natural gas pipelines of
their marketing affiliates and govern how information may be provided to those
marketing affiliates. In September 2001, the FERC issued a Notice of Proposed
Rulemaking proposing new standards of conduct that would apply uniformly to
natural gas pipelines and transmitting public utilities. FERC is proposing one
set of standards to govern relationships between regulated transmission
providers and all energy affiliates. Should a final rule be issued in this
proceeding, we may be subject to standards that could result in additional
costs.

On August 1, 2002, FERC issued a Notice of Proposed Rulemaking
regarding the Regulation of Cash Management and is proposing to establish limits
on the amount of funds that can be transferred from the regulated subsidiary to
its non-regulated parent. We do not expect that the FERC proposed policy will
have an impact on our cash management practices.

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On July 17, 2002, FERC issued a Notice of Inquiry Concerning Natural
Gas Pipeline Negotiated Rate Policies and Practices. In this proceeding the FERC
is evaluating its negotiated rate program and has invited all segments of the
industry to provide comments. The outcome of this inquiry may change the
existing FERC policy concerning the types of negotiated rates that it allows and
may have an undetermined impact on the pricing practices for a pipeline's
transportation services.

Recent FERC orders in proceedings involving other natural gas pipelines
have addressed certain aspects of the pipelines' creditworthiness provisions set
forth in their tariffs. In addition, industry groups such as the North American
Energy Standards Board are studying creditworthiness standards and may recommend
that the FERC promulgate changes in such standards on an industry-wide basis.
The enactment of some of these recommendations may have the effect of easing
certain creditworthiness standards and parameters currently reflected in our
tariff. At this stage of the proceedings, however, we cannot predict the
ultimate impact, if any, such changes would have on us.

From time to time, we file to make changes to our tariff to clarify
provisions, to reflect current industry practices and to reflect recent FERC
rulings. In February 2003, we filed to amend the definition of company use gas,
which is gas supplied by our shippers for our operations, to clarify the
language by adding detail to the broad categories that comprise company use gas.
Relying upon the currently effective version of the tariff, we included in our
collection of company use gas, quantities that were equivalent to the cost of
electric power at our electric-driven compressor stations during the period of
June 2001 through January 2003. Several parties have filed protests of this
change and have requested that the FERC order refunds. At its meeting on March
26, 2003, the FERC voted to reject our filing and require refunds. In its draft
order, the FERC directed us to cease collecting electric costs through our
company use gas provisions and to refund with interest, within 90 days, all
electric costs that had been collected through our company use gas provisions.
Other parties and us will have thirty days from the date of the order to request
rehearing. A reserve in the amount of $10 million was established, which we
believe is sufficient to cover the potential refunds.

ENVIRONMENTAL AND SAFETY MATTERS

Our operations are subject to federal, state and local laws and
regulations relating to safety and the protection of the environment, which
include the Resource Conservation and Recovery Act, the Comprehensive
Environmental Response, Compensation and Liability Act of 1980, as amended,
Clean Air Act, as amended, the Clean Water Act, as amended, the Natural Gas
Pipeline Safety Act of 1969, as amended, and the Pipeline Safety Act of 1992.

The Pipeline Safety Improvement Act ("Act") was signed into law in
December 2002. The Act contains numerous provisions that increase federal
inspection and safety requirements for the pipelines. As a result, the Secretary
of Transportation and various government agencies are required to develop and
implement regulations under the Act in order for the pipelines to carry out the
prescribed evaluations and implementation of programs to ensure the safety of
its facilities. The Act and subsequent regulations have prescribed timelines
and the

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implementation may have an impact on the costs that pipelines incur.

Although we believe that our operations and facilities are in general
compliance in all material respects with applicable environmental and safety
regulations, risks of substantial costs and liabilities are inherent in pipeline
operations, and we cannot provide any assurances that we will not incur such
costs and liabilities. Moreover, it is possible that other developments, such as
increasingly strict environmental and safety laws, regulations and enforcement
policies thereunder, and claims for damages to property or persons resulting
from our operations, could result in substantial costs and liabilities to us. If
we are unable to recover such resulting costs, earnings and cash distributions
could be adversely affected.

ITEM 2. PROPERTIES

We hold the right, title and interest in our pipeline system. With
respect to real property, the pipeline system falls into two basic categories:
(a) parcels which are owned in fee, such as sites for compressor stations, meter
stations, pipeline field offices, and microwave towers; and (b) parcels where
the interest derives from leases, easements, rights-of-way, permits or licenses
from landowners or governmental authorities permitting the use of such land for
the construction and operation of the pipeline system. The right to construct
and operate the pipeline system across certain property was obtained through
exercise of the power of eminent domain. We continue to have the power of
eminent domain in each of the states in which we operate, although we may not
have the power of eminent domain with respect to Native American tribal lands.

Approximately 90 miles of our pipeline are located on fee, allotted and
tribal lands within the exterior boundaries of the Fort Peck Indian Reservation
in Montana. Tribal lands are lands owned in trust by the United States for the
Fort Peck Tribes and allotted lands are lands owned in trust by the United
States for an individual Indian or Indians. We do have the right of eminent
domain with respect to allotted lands.

In 1980, we entered into a pipeline right-of-way lease with the Fort
Peck Tribal Executive Board, for and on behalf of the Assiniboine and Sioux
Tribes of the Fort Peck Indian Reservation. This pipeline right-of-way lease,
which was approved by the Department of the Interior in 1981, granted to us the
right and privilege to construct and operate our pipeline on certain tribal
lands. This pipeline right-of-way lease expires in 2011.

In conjunction with obtaining a pipeline right-of-way lease across
tribal lands located within the exterior boundaries of the Fort Peck Indian
Reservation, we also obtained a right-of-way across allotted lands located
within the reservation boundaries. Most of the allotted lands are subject to a
perpetual easement either granted by the Bureau of Indian Affairs for and on
behalf of individual Indian owners or obtained through condemnation. Several
tracts are subject to a right-of-way grant that has a term of 15 years, expiring
in 2015.

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ITEM 3. LEGAL PROCEEDINGS

On July 31, 2001, the Assiniboine and Sioux Tribes of the Fort Peck
Indian Reservation filed a lawsuit in Tribal Court against us to collect more
than $3 million in back taxes, together with interest and penalties. The lawsuit
relates to a utilities tax on certain of our properties within the Fort Peck
Indian Reservation. We and the Tribes, through a mediation process, have held
settlement discussions and have reached a settlement in principle on pipeline
right-of-way lease and taxation issues, subject to final documentation and
necessary governmental approvals. We believe that we will obtain regulatory
recovery of the costs resulting from the settlement, which will result in no
material adverse impact on our results of operations or financial position. See
Item 7. "Management's Discussion and Analysis of Financial Condition and Results
of Operations - Risk Factors and Information Regarding Forward-Looking
Statements."

See Item 1. "Business - FERC Regulation" for a discussion on the
proceeding before the FERC.

We are not currently parties to any other legal proceedings that,
individually or in the aggregate, would reasonably be expected to have a
material adverse impact on our results of operations or financial position.

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

There were no matters submitted to a vote of security holders during
2002.

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PART II

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

The general partnership interests of Northern Border Pipeline Company
are not traded in an established public market. See Item 12. "Security Ownership
of Certain Beneficial Owners and Management."

The payment of distributions to our general partners is restricted
under the terms of the 2002 Pipeline Credit Agreement and the 1992 Senior Notes.
See Note 5, "Credit Facilities and Long-Term Debt," in the Notes to Financial
Statements referred to in Item 8. "Financial Statements and Supplementary Data."
Under the most restrictive covenants, approximately $99 million of partners'
capital could be distributed as of December 31, 2002.

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ITEM 6. SELECTED FINANCIAL DATA
(in thousands, except other financial and operating data)

The following table sets forth, for the periods and at the dates
indicated, selected historical financial data for us. The selected financial
information should be read in conjunction with the Financial Statements and the
Notes and Item 7. "Management's Discussion and Analysis of Financial Condition
and Results of Operations," which are included elsewhere in this report.

- ----------
(1) "Earnings" means the sum of pre-tax income from continuing operations
and fixed charges. "Fixed charges" means the sum of (a) interest
expensed and capitalized; (b) amortized premiums, discounts and
capitalized expenses related to indebtedness; and (c) an estimate of
interest within rental expenses.

13

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS

Our discussion and analysis of our financial condition and operations
are based on our Financial Statements, which were prepared in accordance with
accounting principles generally accepted in the United States of America. You
should read the following discussion and analysis in conjunction with our
Financial Statements included elsewhere in this report.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

Certain amounts included in or affecting our Financial Statements and
related disclosures must be estimated, requiring us to make certain assumptions
with respect to values or conditions that cannot be known with certainty at the
time the financial statements are prepared. The preparation of financial
statements in conformity with accounting principles generally accepted in the
United States of America requires management to make estimates and assumptions
that affect the reported amounts of assets and liabilities and disclosure of
contingent assets and liabilities at the date of the financial statements and
the reported amounts of revenues and expenses during the reporting period.
Actual results could differ from those estimates. Any effects on our business,
financial position or results of operations resulting from revisions to these
estimates are recorded in the period in which the facts that give rise to the
revision become known.

Our significant accounting policies are summarized in Note 2 - Notes to
Financial Statements included elsewhere in this report. Certain of our
accounting policies are of more significance in our financial statement
preparation process than others. Our accounting policies conform to Statement of
Financial Accounting Standards ("SFAS") No. 71, "Accounting for the Effects of
Certain Types of Regulation." Accordingly, certain assets that result from the
regulated ratemaking process are recorded that would not be recorded under
accounting principles generally accepted in the United States of America for
nonregulated entities. We continually assess whether the regulatory assets are
probable of future recovery by considering such factors as regulatory changes
and the impact of competition. If future recovery ceases to be probable, we
would be required to write-off the regulatory assets at that time. At December
31, 2002, we have reflected regulatory assets of $10.5 million, which are being
recovered from our shippers over varying periods of time. Our long-lived assets
are stated at original cost. We must use estimates in determining the economic
useful lives of those assets. For utility property, no retirement gain or loss
is included in income except in the case of retirements or sales of entire
regulated operating units. The original cost of utility property retired is
charged to accumulated depreciation and amortization, net of salvage and cost of
removal. Our accounting for financial instruments follows SFAS No. 133,
"Accounting for Derivative Instruments and Hedging Activities." SFAS No. 133
requires that every derivative instrument be recorded on the balance sheet as
either an asset or liability measured at its fair value. The statement requires
that changes in the derivative's fair value be recognized currently in earnings
unless specific hedge accounting criteria are met. Special accounting for
qualifying hedges allows a derivative's gains and losses to offset related
results on the hedged item in the

14

income statement. At December 31, 2002, our balance sheet included assets from
derivative financial instruments of $21.2 million.

RESULTS OF OPERATIONS

Our net income to partners was $142.7 million in 2002, compared to net
income of $140.5 million in 2001 and $127.1 million in 2000. Our 2002 operating
results benefited from increased operating revenues from Project 2000, which was
our pipeline expansion and extension placed in service in October 2001, and
reductions in interest expense due to lower interest rates. Partially offsetting
these increases to our operating results were higher operations and maintenance
expenses for 2002 as compared to 2001. Our 2001 results also included a
write-off for an uncollectible receivable. Our increase in net income in 2001
over 2000 resulted from reductions in interest rates, which reduced our interest
expense for 2001 as compared to 2000. We were also able to control our operating
costs in 2001 resulting in reductions to operations and maintenance expenses as
compared to 2000.

Operating revenues were $321.1 million in 2002, $313.1 million in 2001
and $311.0 million in 2000. The increase in operating revenues in 2002 over 2001
resulted from additional revenues of approximately $10.3 million related to
Project 2000. The impact of the additional revenues associated with Project 2000
was partially offset by uncollected revenues associated with the transportation
capacity formerly held by Enron North America Corp. ("ENA"), which filed for
Chapter 11 bankruptcy protection in December 2001 (see "Update On The Impact Of
Enron's Chapter 11 Filing On Our Business"). For 2002, the revenues lost on this
capacity totaled approximately $1.8 million. The increase in operating revenues
in 2001 over 2000 was primarily due to additional revenues associated with the
completion of Project 2000 in October 2001.

Operations and maintenance expenses were $41.4 million in 2002, $33.7
million in 2001 and $41.5 million in 2000. The 2002 expense included a $10.0
million reserve for costs that may arise from the treatment of previously
collected quantities of natural gas used in utility operations to cover electric
power costs (see Item 1. "Business - FERC Regulation"). In 2002, we also had an
increase in regulatory commission expense and decreases in employee benefits
expenses, administrative expenses and bad debt expense, as compared to 2001. The
2001 expense included $1.3 million of bad debt expense related to ENA. The
decrease in operations and maintenance expense in 2001 from 2000 reflects a
decrease in regulatory commission expense, decreased employee payroll, employee
benefits expenses and administrative expenses and decreased costs to operate two
of our electric-powered compressor units as a result of collected quantities of
natural gas used in utility operations to cover electric power costs.

Depreciation and amortization expenses were $58.7 million in 2002,
$57.5 million in 2001 and $57.3 million in 2000. The increase between 2001 and
2002 reflects a $1.2 million increase due to Project 2000.

Taxes other than income were $28.4 million in 2002, $25.6 million in
2001 and $28.0 million in 2000. The increase in 2002 from 2001 is due primarily
to adjustments to ad valorem taxes. We periodically review and adjust our
estimates of ad valorem taxes. Reductions to

15

previous estimates in 2001 exceeded reductions to previous estimates in 2002 by
approximately $2.1 million. The decrease in taxes other than income in 2001 from
2000 was also due to a decrease in use taxes. As a result of a ruling by the
Minnesota Supreme Court, we filed for a refund of use taxes previously paid on
exempt purchases. We received the refund in March 2002.

Interest expense was $51.5 million in 2002, $55.4 million in 2001 and
$65.2 million in 2000. Both 2002 and 2001 interest expense decreased from prior
year levels due to a decrease in our average interest rate as well as a decrease
in our average debt outstanding. The 2001 results included $0.9 million of
interest expense capitalized primarily related to construction of Project 2000
facilities.

Other income (expense) was $1.8 million in 2002, ($0.4 million) in 2001
and $8.1 million in 2000. In 2002, we recorded income of approximately $0.6
million for amounts received for previously vacated microwave frequency bands
and income of $0.2 million due to a reduction in reserves previously
established. The amount for 2001 includes a charge of approximately $1.5 million
for an uncollectible receivable from a telecommunications company that had
purchased excess capacity on our communication system and a $0.7 million charge
for reserves established. We recorded an allowance for equity funds used during
construction of $0.9 million in 2001 primarily due to Project 2000. In 2000, we
had recorded approximately $1.7 million of income from the sale of excess
capacity on our communication system. Other income for 2000 also included $5.6
million of income due to a reduction in reserves previously established for
regulatory issues as the result of the settlement of our rate case.

LIQUIDITY AND CAPITAL RESOURCES

SUMMARY OF CERTAIN CONTRACTUAL OBLIGATIONS

- -------------
(a) See Note 7 - Notes to Financial Statements.

DEBT AND CREDIT FACILITIES

We have entered into a $175 million three-year credit agreement ("2002
Pipeline Credit Agreement") with certain financial institutions in May 2002. The
2002 Pipeline Credit Agreement replaced a previous credit agreement. The 2002
Pipeline Credit Agreement is to be used to refinance existing indebtedness and
for general business purposes. At

16

December 31, 2002, $89 million was outstanding under the 2002 Pipeline Credit
Agreement at an average interest rate of 2.05%. The 2002 Pipeline Credit
Agreement requires the maintenance of a ratio of EBITDA (net income plus
interest expense, income taxes and depreciation and amortization) to interest
expense of greater than 3 to 1. The 2002 Pipeline Credit Agreement also requires
the maintenance of the ratio of indebtedness to EBITDA of no more than 4.5 to 1.
At December 31, 2002, we were in compliance with these covenants.

At December 31, 2002, we had outstanding $65 million of Series D Senior
Notes issued in a $250 million private placement under a July 1992 note purchase
agreement. The Series D Senior Notes mature in August 2003. We anticipate
borrowing under the 2002 Pipeline Credit Agreement to repay the Series D Senior
Notes.

In April 2002, we completed a private offering of $225 million of 6.25%
Senior Notes due 2007 ("2002 Pipeline Senior Notes"). In September 2001, we
completed a private offering of $250 million of 7.50% Senior Notes due 2021
("2001 Pipeline Senior Notes"). In August 1999, we completed a private offering
of $200 million of 7.75% Senior Notes due 2009 ("1999 Pipeline Senior Notes").
The 2002 Pipeline Senior Notes, 2001 Pipeline Senior Notes and 1999 Pipeline
Senior Notes (collectively "Pipeline Senior Notes") were subsequently exchanged
in registered offerings for notes with substantially identical terms. The
indentures under which the Pipeline Senior Notes were issued do not limit the
amount of unsecured debt we incur, but they do contain material financial
covenants, including restrictions on incurrence of secured indebtedness. The
proceeds from the Pipeline Senior Notes were used to reduce indebtedness
outstanding.

We entered into interest rate swap agreements with notional amounts
totaling $225 million in May 2002. Under the interest rate swap agreements, we
make payments to counterparties at variable rates based on the London Interbank
Offered Rate and in return receive payments based on a 6.25% fixed rate. The
swaps were entered into to hedge the fluctuations in the market value of the
2002 Pipeline Senior Notes. At December 31, 2002, the average effective interest
rate on our interest rate swap agreements was 2.70%.

Short-term liquidity needs will be met by operating cash flows and
through the 2002 Pipeline Credit Agreement. Long-term capital needs may be met
through the ability to issue long-term indebtedness.

CASH FLOWS FROM OPERATING ACTIVITIES

Cash flows provided by operating activities were $223.5 million in
2002, $197.3 million in 2001 and $176.0 million in 2000. The $26.2 million
increase in 2002 from 2001 was primarily due to increases in operating revenues
and the impact of rate case refunds in 2001. In 2001, we realized net cash
outflows of approximately $4.7 million related to our rate case refunds. During
the first quarter of 2001, we made refunds to our shippers totaling $6.8
million, which included approximately $2.1 million collected in the first
quarter of 2001 with the remainder collected previously. The $21.3 million
increase in 2001 from 2000 was primarily due to increased earnings and changes
in working capital.

17

CASH FLOWS FROM INVESTING ACTIVITIES

Our capital expenditures were $8.4 million for 2002 as compared to
$54.7 million for 2001 and $15.5 million for 2000. The 2002, 2001 and 2000
amounts include $0.3 million, $49.0 million and $7.4 million, respectively, for
Project 2000. The remaining capital expenditures for 2002, 2001 and 2000 were
primarily related to renewals and replacements of existing facilities.

Total capital expenditures for 2003 are estimated to be $11 million
primarily related to renewals and replacements of existing facilities. We
currently anticipate funding our 2003 capital expenditures primarily by
borrowing on debt facilities and using operating cash flows.

CASH FLOWS FROM FINANCING ACTIVITIES

Cash flows used in financing activities were $200.8 million for the
year ended December 31, 2002 as compared to $160.7 million for the same period
in 2001 and $148.7 million for the same period in 2000. Distributions to our
partners were $164.1 million, $143.0 million and $134.9 million for 2002, 2001
and 2000, respectively. The increase in distributions was primarily due to our
improved operating results.

For 2002, 2001 and 2000, our borrowings on long-term debt totaled
$431.9 million, $385.4 million and $75.0 million, respectively, which were
primarily used to repay previously existing indebtedness. For 2002, we received
net proceeds from the 2002 Pipeline Senior Notes of approximately $223.5
million. The net proceeds from the issuance of the 2001 Pipeline Senior Notes
totaled approximately $247.2 million in 2001. Our borrowings under our credit
agreements were $207.0 million in 2002, $136.0 million in 2001 and $75.0 million
in 2000. Total payments on debt were $468.0 million, $374.0 million and $111.0
million in 2002, 2001 and 2000, respectively.

In April 2002, we received $2.4 million from the termination of forward
starting interest rate swaps upon issuance of the 2002 Pipeline Senior Notes
(see Note 6 - Notes to Financial Statements). In September 2001, we paid
approximately $4.1 million to terminate interest rate swap agreements upon
issuance of the 2001 Pipeline Senior Notes. The swaps were entered into to hedge
the fluctuations in Treasury rates and spreads between the execution date of the
swaps and the issuance of the 2002 and 2001 Pipeline Senior Notes. For 2001, we
recognized a decrease in bank overdraft of $22.4 million. At December 31, 2000,
we reflected the bank overdraft primarily due to rate refund checks outstanding.

NEW ACCOUNTING PRONOUNCEMENTS

In the third quarter of 2001, the Financial Accounting Standards Board
SFAS No. 143, "Accounting for Asset Retirement Obligations" and in 2002, the
FASB issued SFAS No. 145, "Rescission of FASB Statements No. 4, No. 44 and No.
64, Amendments to FASB Statements No. 13 and Technical Corrections" and SFAS No.
146, "Accounting for Costs Associated with Exit or Disposal Activities." See
Note 9 - Notes to Financial Statements.

18

UPDATE ON THE IMPACT OF ENRON'S CHAPTER 11 FILING ON OUR BUSINESS

On December 2, 2001, Enron filed a voluntary petition for bankruptcy
protection under Chapter 11 of the United States Bankruptcy Code. Certain wholly
owned Enron subsidiaries also filed for Chapter 11 bankruptcy protection on
December 2, 2001 and thereafter. We have not filed for bankruptcy protection.
Northern Plains, Pan Border and Northwest Border are the general partners of
Northern Border Partners, our 70% general partner. Each of Northern Plains and
Pan Border are wholly owned subsidiaries of Enron, and Northwest Border is a
wholly owned subsidiary of TransCanada. Northern Plains and Pan Border were not
among the Enron companies that filed for Chapter 11 protection.

The business of Enron and its subsidiaries that have filed for
bankruptcy protection are currently being administered under the direction and
control of the bankruptcy court. An unsecured creditors committee has been
appointed in the Chapter 11 cases. The creditors committee is responsible for
general oversight of the bankruptcy case, and has the power, among other things,
to: investigate the acts, conduct, assets, liabilities, and financial condition
of the debtor, the operation of the debtor's business and the desirability of
the continuance of such business; participate in the formulation of a plan of
reorganization; and file acceptances or rejections to such a plan. Factors taken
into account by Enron in making its business decisions, while in Chapter 11, may
include decisions with respect to its investment in Northern Plains, Pan Border
and Northern Border Partners, which decisions may affect Northern Border
Pipeline.

CURRENT EFFECTS

Enron's filing for bankruptcy protection has impacted us. At the time
of the filing of the bankruptcy petition, we had a number of contractual
relationships with Enron and its subsidiaries. Northern Plains provided and
continues to provide operating and administrative services for us. Northern
Plains has continued to meet their operational and administrative service
obligations under the existing agreement, and we believe they will continue to
do so.

ENA, a wholly owned subsidiary of Enron that is in bankruptcy, was a
party to shipper contracts obligating ENA to pay for 3.5% of our capacity.
Through the proceeding, ENA rejected and terminated all their contracts on us.
We contracted portions of that capacity with others for varying terms. For 2002,
we experienced lost revenues of approximately $1.8 million for ENA's capacity.
We have claims against ENA for damages for breach of contract and other claims.

We filed claims against ENA's bankruptcy estate related to these
agreements. These claims will likely be deemed to be unsecured claims against
certain of the Enron related Chapter 11 companies. We are uncertain regarding
the ultimate amount of damages for breach of contract or other claims that we
will be able to establish in the bankruptcy proceeding, and we cannot predict
the amounts that we will collect or the timing of collection. We believe,
however, that any such delay in collecting or failure to collect will not have a
material adverse effect on our financial condition, and any amounts collected
will not be material to us.

19

Northern Plains has advised us that under the Operating Agreement with
Northern Plains increased costs may be incurred for health care expenses and
pension benefits. Such costs are projected to increase as a result of actual
medical claims experience, pension investment returns and effects of the Enron
bankruptcy filing. While the determination of reimbursement of such costs by us
under the agreement will be made at the time of occurrence, we estimate an
increase of $3 million over 2002 levels.

Enron is the grantor of the Enron Gas Pipeline Employee Benefit Trust
(the "Trust"), which when taken together with the Enron Corp. Medical Plan for
Inactive Participants (the "Plan") constitutes a "voluntary employees'
beneficiary association" or "VEBA" under Section 501(c)(9) of the Internal
Revenue Code. In October 2002, Northern Plains was advised that Enron had
notified the committee, that has administrative and fiduciary oversight related
to the Trust and the Plan, that Enron had made the determination to begin
necessary steps to partition the assets of the Trust and the related liabilities
of the Plan among all of the participating employers of the Trust. The Trust was
established as a regulatory requirement for inclusion of certain costs for
post-employment medical benefits in the rates established for the affected
pipelines, including us. Enron requested the enrolled actuary to prepare an
analysis and recommendation for the allocation of the Trust's assets and
associated liabilities among all the participating employers. Enron has advised
our management that it intends to seek bankruptcy court approval for the
termination of the Trust and for the participating employers to establish a
separate trust adequate to receive the assets.

On May 2, 2002, Enron presented to the creditors' committee a proposal
under which specified core energy assets of Enron would be separated from
Enron's bankruptcy estate and operated prospectively as a new integrated power
and pipeline company. On August 27, 2002, Enron announced that it had commenced
a formal sales process for its interests in certain major assets, including
Northern Plains and Pan Border. However, on March 19, 2003, Enron announced that
its Board of Directors had voted to move forward with the creation of a new
pipeline operating entity rather than sell its interests in its North American
pipelines. This new company, temporarily referred to as "PipeCo", will include
Northern Plains and Pan Border. Enron's announcement also stated that Enron
expects PipeCo to be governed by an independent board of directors and afforded
protection from joint and several Enron group liabilities and that upon
resolution of Enron's Chapter 11 bankruptcy case, it anticipates that shares of
PipeCo will be distributed to creditors in connection with the Plan of
Reorganization. Enron also stated that it is evaluating the potential sale of a
minority interest in PipeCo. The formation of PipeCo will require various Enron
Board, bankruptcy court and other regulatory approvals, as well as the consent
of the Enron's Official Unsecured Creditors' Committee.

Enron's filing for bankruptcy protection and related developments have
had other impacts on our business and management. Arthur Andersen LLP resigned
as our auditors in early 2002, and we retained KPMG LLP as our new auditors.
Enron has received several requests for information from different agencies and
committees of the United States House of Representatives and Senate. Some of the
information requested from Enron may include information about us. In addition,
we are aware that the Senate Committee on Governmental Affairs has issued a
subpoena to

20

Enron requesting documents disclosing Enron's communications with the SEC and
the FERC, as well as information on compensation matters. As a result of Enron's
indirect ownership interest in us, we have been asked to comply with the mandate
of the subpoena in such a manner that may be determined by the Committee on
Governmental Affairs of the Senate of the United States.

POSSIBLE EFFECTS

While Northern Plains and Pan Border have not filed for Chapter 11
bankruptcy protection, their stock is owned by Enron, which is in bankruptcy. As
noted above, Enron could sell its interest in Northern Plains and/or Pan Border,
or take other action with respect to their investment in Northern Border
Partners. Enron could also cause Northern Plains and Pan Border to file for
bankruptcy protection. We have had no indication from Enron that it intends to
cause such companies to file for bankruptcy protection.

We are managed by a four-member management committee. Three
representatives are designated by Northern Border Partners, with each of its
general partners selecting one representative, and one representative is
designated by TC PipeLines. The vote among Northern Border Partners'
representatives is in proportion to their general partner interests in Northern
Border Partners. As a result, the 70% voting interest of Northern Border
Partners' three representatives is allocated 35%, 22.75% and 12.25% among
Northern Plains, Pan Border and Northwest Border, respectively. If Enron were to
sell the stock of Northern Plains and Pan Border, the purchaser would have the
right to appoint a majority of our management committee and control our
activities, except for those activities requiring a unanimous vote which include
changes to our cash distribution policy, certain expansions and extensions of
the pipeline, some transfers of general partner interests and settlement of rate
cases.

If Northern Plains and Pan Border were to file for bankruptcy
protection, Northern Border Partners' Partnership Agreement provides that they
would automatically be deemed to have withdrawn as general partners of Northern
Border Partners. It is possible that the enforceability of the automatic
withdrawal provisions in this partnership agreement may be challenged. The
success and impact of a challenge are unknown. Upon the occurrence of such an
event of withdrawal, the remaining general partner of Northern Border Partners
would have the right to purchase the withdrawing partners' general partnership
interests. If the remaining general partner does not purchase such general
partnership interests, the limited partners of Northern Border Partners would
have the right to elect new general partners. In the event that the remaining
general partner does not elect to purchase the general partner interests or a
successor is not so elected by the limited partners, then the partnership shall
be dissolved. In either event of purchase or election, the party acquiring the
general partner interests currently held by Northern Plains and Pan Border would
have the right to appoint a majority of our management committee and control our
activities, except for those activities requiring a unanimous vote.

Northern Plains also serves as our operator. If Northern Plains were to
file for bankruptcy protection, it could potentially be removed

21

as operator. Certain of Northern Border Pipeline's credit agreements provide
that it would be an event of default thereunder if Northern Plains is replaced
as operator without the consent of the lenders thereunder.

Other than the items identified above, we are not aware of any claims
made against us that arise out of the Enron bankruptcy cases. We continue to
monitor developments at Enron, to assess the impact on us of our existing
agreements and relationships with Enron and its subsidiaries, and to take
appropriate action to protect our interests.

OUTLOOK

We will continue to focus on safe, efficient, and reliable operations
and the further development of our pipeline. We intend to maintain our position
as a low cost transporter of Canadian gas to the midwestern U.S. and provide
highly valued services to our customers. Growth may occur through incremental
projects intended to access new markets or supply areas and supported by
long-term contracts. We are currently working with producers and marketers to
develop the contractual support for a new 300-mile pipeline project, the Bison
Pipeline, to connect the coal bed methane reserves in the Powder River Basin to
markets served by us.

We are in re-contracting discussions with our customers for contracts
that will expire prior to November 1, 2003, which represents approximately 42%
of our system capacity. Similar to other industries, the value of capacity on
interstate pipelines is driven by supply and demand conditions. In particular,
the relationship between gas prices in Canada and prices in the midwestern U.S.
markets will determine the underlying value of transportation. This
relationship, and natural gas markets overall, has been volatile, which is also
an important factor in contracting for firm transportation capacity. Under our
FERC tariff, we may concurrently solicit bids for available capacity from other
parties subject to the existing customer's rights to match the best offer.
During 2002, after completion of this process, we received only bids to extend
service from mid-September 2003 to October 31, 2003 and all other existing
customers' rights to match an offer were terminated. We are now in a position to
contract with interested parties on a first come, first served basis. Based on
current conditions, contracts for service on our pipeline may require discounts
from maximum transportation rates established in our tariff and/or shorter
duration than our existing contract portfolio. Additionally, we may enter into
negotiated rate contracts involving charges established on the basis of
Canadian-midwestern U.S. gas price differentials or other factors.

In February 2003, we filed to amend the definition of company use gas,
which is gas supplied by our shippers for our operations, to clarify the
language by adding detail to the broad categories that comprise company use gas
(See Item 1. "Business - FERC Regulation"). Relying upon the currently effective
version of the tariff, we included in our collection of company use gas,
quantities that were equivalent to the cost of electric power at our
electric-driven compressor stations, resulting in cost savings of approximately
$8 million annually. Pending the final outcome of this FERC

22

proceeding, we may not realize electric power cost savings to the same extent
for 2003.

RISK FACTORS AND INFORMATION REGARDING FORWARD-LOOKING STATEMENTS

Statements in this Annual Report that are not historical information
are forward-looking statements within the meaning of Section 27A of the
Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934.
These forward-looking statements are identified as any statement that does not
relate strictly to historical or current facts. Forward-looking statements are
not guarantees of performance. They involve risks, uncertainties and
assumptions. The future results of our operations may differ materially from
those expressed in these forward-looking statements. Such forward-looking
statements include:

o the discussions in "Management's Discussion and Analysis of
Financial Condition and Results of Operations - Update On The Impact
Of Enron's Chapter 11 Filing On Our Business";

o the discussions in "Management's Discussion and Analysis of
Financial Condition and Results of Operations -- Outlook"; and

o the discussions in "Management's Discussion and Analysis of
Financial Condition and Results of Operations -- Liquidity and
Capital Resources."

Although we believe that our expectations regarding future events are
based on reasonable assumptions within the bounds of our knowledge of our
business, we cannot assure you that our goals will be achieved or that our
expectations regarding future developments will be realized.

With this in mind, you should consider the following important factors
that could cause actual results to differ materially from those in the
forward-looking statements:

o The war with Iraq, increasing military tension with regard to North
Korea, as well as the terrorist attacks of September 11, 2001 and
subsequent unrest, have caused instability in the world's financial
and commercial markets and have contributed to volatility in prices
for natural gas. In addition, since the September 11, 2001 attacks,
the United States government has issued warnings that energy assets,
including our nation's pipeline infrastructure, may be a target of
future terrorist attacks.

o Any shipper's failure to perform its contractual obligations could
adversely impact our cash flows and financial condition. Some of our
shippers or their owners have experienced a deterioration of their
financial condition. Should one or more file for bankruptcy
protection, our ability to recover amounts owed or to resell the
capacity would be impacted.

o Since Northern Plains, our operator, is a wholly-owned subsidiary of
Enron and depends on Enron and certain of its

23

affiliates for some services it provides to us, potential further
developments in the Enron Chapter 11 proceeding may cause Northern
Plains to be unable to perform under its agreement or to incur
increases in costs to continue or replace the services provided by
Enron and its affiliates. Most recently, Enron announced its
intention to create a new pipeline operating entity, which will
include Northern Plains. See "Update On The Impact Of Enron's
Chapter 11 Filing On Our Business" above.

o Our ability to recontract capacity as existing contracts terminate
for maximum transportation rates will be subject to a number of
factors including availability of natural gas supplies from the
western Canadian sedimentary basin, the demand for natural gas in
our market areas and the basis differential between the receipt and
delivery points on our system. See "Outlook" above and Item 1.
"Business - Demand For Transportation Capacity."

o We are subject to extensive regulation by the FERC governing all
aspects of our business, including our transportation rates. Under
our 1999 rate case settlement, neither our existing customers nor we
can seek rate changes until November 2005, at which time we are
obligated to file a rate case. We cannot predict what challenges we
may have to our rates in the future. See Item 1. "Business - FERC
Regulation."

o Our operations are subject to federal and state agencies for
environmental protection and operational safety. We may incur
substantial costs and liabilities in the future as a result of
stricter environmental and safety laws, regulations and enforcement
policies. See Item 1. "Business - Environmental and Safety Matters."

o Our ability to operate the pipeline on certain tribal lands will
depend on our success in renegotiating before 2011 our right-of-way
rights on tribal lands within the Fort Peck Reservation. See Item 2.
"Properties." We and the Tribes, through a mediation process, have
held settlement discussions and have reached a settlement in
principle on the pipeline right-of-way lease and taxation issues,
subject to final documentation and necessary governmental approvals.
If we are unable to recover the costs of the proposed settlement in
our future rates, it could have a material adverse impact on our
results of operation.

ITEM 7a. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Our interest rate exposure results from variable rate borrowings from
commercial banks. To mitigate potential fluctuations in interest rates, we
attempt to maintain a significant portion of our debt portfolio in fixed rate
debt. We also use interest rate swaps as a means to manage interest expense by
converting a portion of fixed rate debt into variable rate debt to take
advantage of declining interest rates. At December 31, 2002, we had $314.0
million of variable rate debt outstanding, $225.0 million of which was
previously fixed rate

24

debt that had been converted to variable rate debt through the use of interest
rate swaps. For additional information on our debt obligations and derivative
instruments, see Note 5 and Note 6 to our Financial Statements, included
elsewhere in this report. As of December 31, 2002, approximately 62% of our debt
portfolio was in fixed rate debt.

If average interest rates change by one percent compared to rates in
effect as of December 31, 2002, annual interest expense would change by
approximately $3.1 million. This amount has been determined by considering the
impact of the hypothetical interest rates on variable rate borrowings
outstanding as of December 31, 2002.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

The information required hereunder is included in this report as set
forth in the "Index to Financial Statements" on page F-1.

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

None.

25

PART III

ITEM 10. PARTNERSHIP MANAGEMENT

Northern Border Pipeline Company is overseen by the management
committee, which is composed of the following individuals:

William R. Cordes, Chairman(1)

Stanley C. Horton(1)

Dennis J. McConaghy(2)

Paul F. MacGregor(1)

- ----------

(1) Designated by Northern Border Partners.

(2) Designated by TC PipeLines.

William R. Cordes (54) has been a member and Chairman of our management
committee since October 1, 2000. Mr. Cordes was named Chief Executive Officer of
Northern Border Partners in October 2000. Since October 2000, Mr. Cordes has
been the President and a director of Northern Plains, an Enron subsidiary and
our operator. In 1970, he started his career at Northern Natural Gas Company, an
Enron subsidiary until February 2002, where he worked in several management
positions. From June of 1993 until September of 2000, he was President of
Northern Natural and from May of 1996 until September of 2000, he was also the
President of Transwestern Pipeline, an Enron subsidiary.

Stanley C. Horton (53) was appointed to our management committee in
December 1998. Mr. Horton is the Chairman and Chief Executive Officer of Enron
Global Services, and has held that position since August 2001. From January 1997
to August 2001, he was Chairman and Chief Executive Officer of Enron
Transportation Services Company, formerly known as the Enron Gas Pipeline Group.
From February 1996 to January 1997, he was Co-Chairman and Chief Executive
Officer of Enron Operations Corp. From June 1993 to February 1996, he was
President and Chief Operating Officer of Enron Operations Corp. He was a
Director and Chairman of the Board of EOTT Energy Corp., the general partner of
EOTT Energy Partners, L.P. until his resignation from the office of Chairman on
April 10, 2002 and then his resignation as Director on May 31, 2002. On May 1,
2001, Mr. Horton became a member of the Board of Directors of Portland General
Electric. Mr. Horton also holds the elected position of officer and/or director
of the following Enron companies that have filed for Chapter 11 bankruptcy
protection:
Calypso Pipeline, L.L.C. (Director, President and Chief Executive
Officer)
Enron Transportation Services Company (Chairman, President and Chief
Executive Officer and Director)
Enron Wind Corp.(n/k/a Enron Wind LLC) (Chairman and Director until
April 19, 2002)
Enron Wind Systems, Inc.(n/k/a Enron Wind Systems, LLC) (Director until
April 19, 2002)
Enron Wind Energy Systems Corp.(n/k/a Enron Wind Energy Systems, LLC)
(Chairman, Director until April 19, 2002)

26

Enron Wind Maintenance Corp.(n/k/a Enron Wind Maintenance, LLC)
(Chairman, Director until April 19, 2002)
Enron Wind Constructors Corp.(n/k/a Enron Wind Constructors, LLC)
(Chairman, Director until April 19, 2002)
Zond Pacific, LLC (Chairman until September 25, 2002)

Dennis J. McConaghy (51) has been a member of our management committee
since December 2000. He was appointed a director of TC PipeLines GP, Inc. (the
general partner of TC PipeLines, LP) in December 2000. His principal occupation
is Executive Vice-President Gas Development for TransCanada, a position he has
held since May 2001. From October 2000 until May 2001, Mr. McConaghy was Senior
Vice-President, Business Development of TransCanada. Prior to that time and
since June 2000, Mr. McConaghy was Senior Vice-President, Midstream/Divestments,
TransCanada. Prior to that time and since July 1998, Mr. McConaghy was
Vice-President, Corporate Strategy and Planning, TransCanada. Prior to that time
and since May 1996, Mr. McConaghy was Vice-President, Strategy and Corporate
Development, NOVA Corporation. Prior to that time and since November 1995, Mr.
McConaghy was Senior Vice-President and Chief Financial Officer, NOVA Chemicals
Ltd.

In August 2002, TransCanada designated Paul MacGregor (45) as its
member on the Partnership Policy Committee of Northern Border Partners. Mr.
MacGregor is also TC PipeLines' alternate representative on our Management
Committee. Additionally, Mr. MacGregor serves as the Vice President, Eastern
Business Development, TransCanada, a position he has held since September 1999
and as Vice President, Business Development, of the general partner of TC
PipeLines a position he has also held since April 1999. From July 1998 to
September 1999, Mr. MacGregor was Vice-President, North American Pipeline
Investments for TransCanada's Transmission division. From 1997 until July 1998,
he was Vice-President, Alberta Natural Gas Company Ltd. (energy services), a
former subsidiary of TransCanada that has since amalgamated into TransCanada.
Mr. MacGregor started his career with TransCanada in 1981 and has held various
other positions in the Facilities Planning and Evaluations, Finance and
Operations Group.

Day-to-day management and operations are the responsibility of the
operator, Northern Plains, as set forth in the operating agreement. We have no
employees or executive officers. Officers and employees of Northern Plains
provide services to our operations and we reimburse Northern Plains for such
costs. We do not compensate members of the management committee for their
services.

There is also an audit and compensation committee composed of members
appointed by the management committee. The audit and compensation committee,
consisting of Mr. Lee Hobbs, Vice President and Controller, TransCanada, and Mr.
Paul F. MacGregor, Vice President, Business Development, TC PipeLines, GP, Inc.,
oversees the annual audit process and confers with KPMG LLP, our independent
auditors. The committee is also responsible for setting up guidelines for
compensation to be paid to the executive officers of Northern Plains, each of
whom spends at least a portion of his or her time on our operations, and for
which Northern Plains is reimbursed as indicated above. Currently, there is one
vacancy on the committee.

27

ITEM 11. EXECUTIVE COMPENSATION

Jerry L. Peters (45) has served as Treasurer of Northern Plains since
October 1998, Vice President of Finance for Northern Plains since July 1994 and
director of Northern Plains since August 1994. He has also been named Vice
President, Finance for Enron Transportation Services Company. He has been
associated with Northern Plains since 1985.

The following table summarizes information regarding compensation paid
or accrued during each of the last three fiscal years to Jerry L. Peters and
William R. Cordes (the "Named Officers") by Northern Plains, our operator.
Messrs. Cordes and Peters are both employees of Northern Plains, but contribute
services to our operations, for which we reimburse Northern Plains.

SUMMARY COMPENSATION TABLE

- ----------
(1) Mr. Cordes was appointed President of Northern Plains and Chief Executive
Officer of the Partnership on October 1, 2000.

(2) Employees were able to elect to receive Northern Border phantom units, Enron
Corp. phantom stock, and/or Enron Corp. stock options in lieu of all or a
portion of an annual bonus payment. Mr. Cordes and Mr. Peters elected to
receive Northern Border phantom units in lieu of a portion of the cash bonus
payment under the Northern Border Phantom Unit Plan. Mr. Cordes received
1,914 units in 2001. Mr. Peters received 1,450 units in 2000 and 842 units
in 2001. In each case, units will be released to both five years following
the grant date.

(3) Other Annual Compensation includes cash perquisite allowances, service
awards and vacation payouts. Also, Enron maintained three deferral plans for
key employees under which payment of base salary, annual bonus and long-term
incentive awards could be deferred to a later specified date. Under the 1985
Deferral Plan, interest is credited on amounts deferred based on 150% of
Moody's seasoned corporate bond yield index with a minimum rate of 12%,
which for 2000 and 2001 was the minimum rate of 12%. No interest has been
reported as Other Annual Compensation under the 1985 Deferral Plan for
participating Named Officers because the crediting rates during 2000 and
2001 did not exceed 120% of the long-term Applicable Federal Rate of 14.38%
in effect at the time the 1985 Deferral Plan was implemented. Beginning
January 1, 1996, the 1994 Deferral Plan credits interest based on fund
elections chosen by participants. Since earnings on deferred compensation
invested in third-party investment vehicles, comparable to mutual funds,
need not be reported, no interest has been reported as Other Annual
Compensation under the 1994 Deferral Plan during 2000 and 2001.

(4) The aggregate total of shares in unreleased Enron restricted stock holdings
and their values as of December 31, 2002, for each of the Named Officers is:
Mr. Cordes, 4,295 shares valued at $258, and Mr. Peters, 1,701 shares valued
at $102. Dividend equivalents for all restricted stock awards accrue from
date of grant and are paid upon vesting. Any dividends on Enron Corp. stock
accrued and unreleased as of the date of Enron Corp's filing for bankruptcy
protection will only be released in accordance with applicable bankruptcy
law.

(5) Mr. Cordes' employment agreement, as executed in September, 2001, provided
for a grant of 882 Northern Border Phantom Units valued as of July 30, 2001
at $115.6978 per unit and granted on October 1, 2001. On June 1, 2002, a
grant of 697 Northern Border Phantom Units valued at $143.5456 per unit was
made in accordance with his employment agreement. The phantom units vest
100% on the fifth anniversary of the date of the grant.

(6) Reflects cash payments under the Enron Corp. Performance Unit Plan in 2000
for the 1996-1999 period and in 2001 for the 1997-2000 period. Payments made
under the Performance Unit

28

Plan are based on Enron's total shareholder return relative to its peers.
Enron's performance over the 1996-1999 performance period rendered a value
of $1.50 based on a ranking of second as compared to 11 industry peers. It's
performance over the 1997-2000 performance period rendered a value of $2.00
based on a ranking of first.

(7) The amounts shown include the value of Enron Common Stock allocated to
employees' special subaccounts under Enron's Employee Stock Ownership Plan,
matching contributions to employees' Enron Corp. Savings Plan, and imputed
income on life insurance benefits. Mr. Peters' employment agreement, as
executed in April, 2002, provided for a "stay" bonus in which $23,950 of the
amount was paid six months following the implementation of the agreement.
The remaining amount of $71,853 will be paid upon completion of the term of
the agreement.

STOCK OPTION GRANTS DURING 2002

Due to the bankruptcy filing by Enron Corp on December 2, 2001, there
were no grants of stock options pursuant to Enron's stock plans to the Named
Officers reflected in the Summary Compensation Table. No stock appreciation
rights were granted during 2002.

Aggregated Stock Option/SAR Exercises During 2002 and Stock Option/SAR Values as
of December 31, 2002

The following table sets forth information with respect to the Named
Officers concerning the exercise of Enron SARs and options during the last
fiscal year and unexercised Enron options and SARs held as of the end of the
fiscal year:

- ----------
(1) The dollar value in this column for Enron Corp. stock options was calculated
by determining the difference between the fair market value underlying the
options as of December 31, 2002 ($0.06) and the grant price.

RETIREMENT AND SUPPLEMENTAL BENEFIT PLANS

Enron maintains the Enron Corp. Cash Balance Plan (the "Cash Balance
Plan"), which is a noncontributory defined benefit pension plan to provide
retirement income for employees of Enron and its subsidiaries. Through December
31, 1994, participants in the Cash Balance Plan with five years or more of
service were entitled to retirement benefits in the form of an annuity based on
a formula that uses a percentage of final average pay and years of service. In
1995, Enron's Board of Directors adopted an amendment to and restatement of the
Cash Balance Plan changing the plan's name from the Enron Corp. Retirement Plan
to the Enron Corp. Cash Balance Plan. In connection with a change to the
retirement benefit formula, all employees became fully vested in retirement
benefits earned through December 31, 1994. The formula in place prior to January
1, 1995 was suspended and replaced with a benefit accrual in the form of a cash
balance of 5% of eligible annual base pay beginning January 1, 1996. Effective
January 1, 2003, Enron suspended future 5% benefit accruals under the Cash
Balance Plan. Each employee's accrued benefit will continue to be credited with
interest based on ten-year Treasury Bond yields.

Enron also maintains a noncontributory employee stock ownership plan
("ESOP"), which was merged into the Enron Corp. Savings Plan effective

29

August 30, 2002 and covered all eligible employees. Allocations to individual
employees' retirement accounts within the ESOP offset a portion of benefits
earned under the Cash Balance Plan prior to December 31, 1994. December 31, 1993
was the final date on which ESOP allocations were made to employees' retirement
accounts.

Effective December 2, 2001, Enron no longer maintains a Supplemental
Retirement Plan. The following table sets forth the estimated annual benefits
payable under normal retirement at age 65, assuming current remuneration levels
without any salary or bonus projections and participation until normal
retirement at age 65, with respect to the Named Officers under the provisions of
the foregoing retirement plans.

- --------
NOTE: The estimated annual benefits payable are based on the straight life
annuity form without adjustment for any offset applicable to a
participant's retirement subaccount in Enron's ESOP.

Severance Plans

Northern Plains' Severance Pay Plan provides for the payment of
benefits to employees who are terminated for failing to meet performance
objectives or standards or who are terminated due to reorganization or similar
business circumstances. The amount of benefits payable for performance related
terminations is based on length of service and may not exceed eight weeks' pay.
For those terminated as the result of reorganization or similar business
circumstances, the benefit is based on length of service and amount of pay up to
a maximum payment of 52 weeks of base pay. The employee must sign a Waiver and
Release of Claims Agreement in order to receive any severance benefit.

30

ITEM 12. BENEFICIAL OWNERSHIP OF PARTNERSHIP INTERESTS

The following table sets forth the beneficial ownership of general
partnership interests of Northern Border Pipeline Company. There are no limited
partnership interests.

- ----------
(1) The address of Northern Border Partners, L.P. is 13710 FNB Parkway, Omaha,
NE 68154-5200. Northern Border Partners holds its 70% general partnership
interest through Northern Border Intermediate Limited Partnership, a
subsidiary limited partnership. Northern Border Partners has three general
partners: Northern Plains Natural Gas Company, Pan Border Gas Company and
Northwest Border Pipeline Company. Northern Plains and Pan Border are
wholly-owned subsidiaries of Enron Corp. and Northwest Border is a
wholly-owned subsidiary of TransCanada PipeLines Limited.

(2) The address of TC PipeLines, LP is 110 Turnpike Road, Suite 203,
Westborough, Massachusetts 01581. TC PipeLines holds its 30% general
partnership interest through TC PipeLines Intermediate Limited Partnership,
a subsidiary limited partnership. TC PipeLines has one general partner, TC
PipeLines GP, Inc., a wholly-owned subsidiary of TransCanada PipeLines
Limited.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

We have extensive ongoing relationships with our general partners and
certain of their affiliates. Since 1980, Northern Plains, an affiliate of Enron,
has acted and will continue to act as the operator of our pipeline system
pursuant to the terms of the operating agreement with Northern Plains. The
initial term of the operating agreement expires in 2007. The operating agreement
will continue in effect thereafter on a year-to-year basis unless terminated by
us or Northern Plains upon six months written notice by either party. The
operator is entitled to reimbursement for all reasonable costs, including
overhead and administrative expenses, incurred by it and its affiliates in
connection with the performance of its responsibilities as operator. In
addition, we have agreed to indemnify the operator against any claims and
liabilities arising out of the good faith performance by the operator of its
responsibilities under our partnership agreement, to the extent the operator is
acting within the scope of its authority and in the course of our business. For
the year ended December 31, 2002, the aggregate amount charged by Northern
Plains, for its services as operator, was approximately $22.8 million. While
Northern Plains continues to perform its obligations, certain of the services
are provided through Enron and other subsidiaries. We continue to monitor and
assess the impacts of the services and relationships with Enron and its
subsidiaries. We believe that any services affected by the Enron bankruptcy
filings may be obtained from other sources in a manner that will not have a
material adverse impact on the Partnership.

31

See Item 7. "Management's Discussion and Analysis of Financial
Condition and Results of Operations - Update On The Impact Of Enron's Chapter 11
Filing On Our Business."

Our interests could conflict with the interests of our general partners
or their affiliates, and in such case the members of our management committee
will generally have a fiduciary duty to resolve such conflicts in a manner that
is in our best interest.

Unless otherwise provided for in a partnership agreement, the laws of
Texas generally require a general partner of a partnership to adhere to
fiduciary duty standards under which it owes its partners the highest duties of
good faith, fairness and loyalty. These rules apply to our management committee.
Because of the competing interests identified above, the Northern Border
Pipeline Company Partnership Agreement contains provisions that modify certain
of these fiduciary duties. For example:

o Our partnership agreement provides that we indemnify the members of
our management committee and Northern Plains, as the operator,
against all actions if such actions were in good faith and within
the scope of their authority in the course of our business. It also
provides that such persons will not be liable for any liabilities
incurred by us as a result of such acts.

o Our partnership agreement states that our general partners will not
be liable to third persons for our losses, deficits, liabilities or
obligations (unless our assets have been exhausted).

o Our partnership agreement requires that any contract entered into
on our behalf must contain a provision limiting the claims of
persons to our assets and expressly waiving any rights of such
persons to proceed against our general partners individually.

o Our partnership agreement relieves Northern Border Partners and TC
PipeLines, their affiliates and their transferees from any duty to
offer business opportunities to us, except that neither our general
partners or their affiliates may pursue any opportunity relating to
expansion or improvements of our pipeline system as it existed on
January 15, 1999.

ITEM 14. CONTROLS AND PROCEDURES

Our principal executive officer and principal financial officer have
evaluated the effectiveness of our "disclosure controls and procedures" as such
term is defined in Rule 13(a)-14(c) of the Securities Exchange Act of 1934, as
amended, within 90 days of the filing of this report. Based upon their
evaluation, the principal executive officer and principal financial officer
concluded that our disclosure controls and procedures are effective. There were
no significant changes in our internal controls or in other factors that could
significantly affect these controls, since the date the controls were evaluated.

32

PART IV

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K

(a) (1) AND (2) FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULES

See "Index to Financial Statements" set forth on page F-1.

(a) (3) EXHIBITS

*3.1 Northern Border Pipeline Company General Partnership
Agreement between Northern Plains Natural Gas Company,
Northwest Border Pipeline Company, Pan Border Gas Company,
TransCanada Border Pipeline Ltd. and TransCan Northern
Ltd., effective March 9, 1978, as amended (Exhibit 10.2 to
Northern Border Partners, L.P.'s Form S-1, SEC File No.
33-66158 ("Form S-1")).

*4.1 Indenture, dated as of August 17, 1999, between the
registrant and Bank One Trust Company, NA, successor to The
First National Bank of Chicago, as trustee (Exhibit 4.1 to
Northern Border Pipeline Company's Form S-4 Registration
Statement, Registration No. 333-88577 ("Form S-4")).

*4.2 Indenture, dated as of September 17, 2001, between Northern
Border Pipeline Company and Bank One Trust Company, N.A.
(Exhibit 4.2 to Northern Border Pipeline Company's
Registration Statement on Form S-4, Registration No.
333-73282 ("2001 Form S-4")).

*4.3 Indenture, dated as of April 29, 2002, between Northern
Border Pipeline Company and Bank One Trust Company, N.A.
(Exhibit 4.1 to Northern Border Pipeline Company's Form
10-Q for the quarter ended March 31, 2002).

*10.1 Operating Agreement between Northern Border Pipeline
Company and Northern Plains Natural Gas Company, dated
February 28, 1980 (Exhibit 10.3 to Form S-1).

*10.2 Note Purchase Agreement between Northern Border Pipeline
Company and the parties listed therein, dated July 15, 1992
(Exhibit 10.6 to Form S-1).

*10.3 Supplemental Agreement to the Note Purchase Agreement dated
as of June 1, 1995 (Exhibit 10.6.1 to Northern Border
Partners L.P.'s Form 10-K for the year ended December 31,
1995, SEC File No. 1-12202 ("1995 10-K")).

*10.4 Credit Agreement, dated as of May 16, 2002, among Northern
Border Pipeline Company, Bank One, NA, Citibank, N.A., Bank
of Montreal, SunTrust Bank, Wachovia Bank, National
Association, Banc One Capital Markets, Inc, and Lenders (as
defined therein) (Exhibit 10.1 to Northern Borders
Partners, L.P.'s Current Report on Form 8-K dated June 26,
2002).

*10.5 Seventh Supplement Amending Northern Border Pipeline
Company General Partnership Agreement (Exhibit 10.15 to
Form S-1).

*10.6 Eighth Supplement Amending Northern Border Pipeline Company
General Partnership Agreement (Exhibit 10.15 of Form S-4).

*10.7 Ninth Supplement Amending Northern Border Pipeline Company
General Partnership Agreement (Exhibit 10.37 to 2001 Form
S-4).

33

*10.8 Form of Conveyance, Contribution and Assumption Agreement
among Northern Plains Natural Gas Company, Northwest Border
Pipeline Company, Pan Border Gas Company, Northern Border
Partners, L.P., and Northern Border Intermediate Limited
Partnership (Exhibit 10.16 to Form S-1).

*10.9 Form of Contribution, Conveyance and Assumption Agreement
among TC PipeLines, LP and certain other parties. (Exhibit
10.2 to TC PipeLines, LP's Form S-1, SEC File No. 333-69947
("TC Form S-1")).

*10.10 Employment Agreement between Northern Plains Natural Gas
Company and William R. Cordes effective June 1, 2001
(Exhibit 10.27 to Northern Border Partners, L.P.'s
Quarterly Report on Form 10-Q for the quarter ended June
30, 2001).

*10.11 Amendment to Employment Agreement between Northern Plains
Natural Gas Company and William R. Cordes, effective
September 25, 2001 (Exhibit 10.36 to 2001 Form S-4).

*10.12 Employment Agreement between Northern Plains Natural Gas
Company and Jerry L. Peters effective April 1, 2002
(Exhibit 10.1 to Northern Border Pipeline Company's Form
10-Q for the quarter ended March 31, 2002).

*10.13 Northern Border Pipeline Company Agreement among Northern
Plains Natural Gas Company, Pan Border Gas Company,
Northwest Border Pipeline Company, TransCanada Border
PipeLine Ltd., TransCan Northern Ltd., Northern Border
Intermediate Limited Partnership, Northern Border Partners,
L.P., and the Management Committee of Northern Border
Pipeline, dated as of March 17, 1999 (Exhibit 10.21 to
Northern Border Partners, L.P.'s Form 10-K/A for the year
ended December 31, 1998, SEC File No. 1-12202 ("1998
10-K")).

*10.14 Northern Border Pipeline Company U.S. Shippers Service
Agreement between Northern Border Pipeline Company and
Pan-Alberta Gas (U.S.) Inc., dated October 1, 1993, with
Amended Exhibit A effective June 22, 1998 (Exhibit 10.25 to
TC Form S-1).

*10.15 Northern Border Pipeline Company U.S. Shippers Service
Agreement between Northern Border Pipeline Company and
Pan-Alberta Gas (U.S.) Inc. (successor to Natgas U.S.
Inc.), dated October 6, 1989, with Amended Exhibit A
effective April 2, 1999 (Exhibit 10.26 to TC Form S-1).

*10.16 Northern Border Pipeline Company U.S. Shippers Service
Agreement between Northern Border Pipeline Company and
Pan-Alberta Gas (U.S.) Inc., dated October 1, 1992, with
Amended Exhibit A effective June 22, 1998 (Exhibit 10.27 to
TC Form S-1).

*16.1 Letter of Arthur Andersen LLP, former auditors of Northern
Border Pipeline Company, dated February 11, 2002 (Exhibit
99.3 to Northern Border Pipeline Company's Form 8-K filed
on February 13, 2002).

*99.1 Northern Border Phantom Unit Plan (Exhibit 99.1 to Northern
Border Partners, L.P.'s Registration No. 333-66949 and
Exhibit 99.1 to Northern Border Partners, L.P.'s
Registration No. 333-72696).

99.2 Certification of principal executive officer pursuant to 18
U.S.C. Section 1350, as adopted pursuant to Section 906 of
the Sarbanes-Oxley Act of 2002.

34

99.3 Certification of principal financial officer pursuant to 18
U.S.C. Section 1350, as adopted pursuant to Section 906 of
the Sarbanes-Oxley Act of 2002.

*Indicates exhibits incorporated by reference as indicated; all
other exhibits are filed herewith.

(b) REPORTS

Northern Border Pipeline Company filed a Current Report on Form
8-K, dated October 2, 2002 reporting the re-audit of 1999 and 2000
financial statements by KPMG LLP and an amendment to update Item 10
of the Form 10-K for the year ended 2001 as a result of the
purchase by TransCanada PipeLines Limited of the general partner
interest formerly owned by The Williams Companies.

35

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 on this 28th day of
March, 2003.

NORTHERN BORDER PIPELINE COMPANY
(A Texas General partnership)

BY: Northern Plains Natural Gas Company,
As Operator

By: /s/ Jerry L. Peters
--------------------------------
Jerry L. Peters
Vice President, Finance and
Treasurer

Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons in the capacities and on
the dates indicated.

36

CERTIFICATION PURSUANT TO RULE 13-A OR 15d-14 OF THE SECURITIES EXCHANGE ACT OF
1934, AS ADOPTED PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, William R. Cordes, certify that:

1. I have reviewed this annual report on Form 10-K of Northern Border Pipeline
Company;

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 officer 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 we 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 officer and I have disclosed, based on our
most recent evaluation, to the registrant's auditors and audit committee of
registrant's board of directors (or persons performing the equivalent function):

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 officer and I have indicated in this annual
report whether or not there are significant changes in internal controls or in
other factors that could significantly affect internal controls subsequent to
the date of our most evaluation, including any corrective actions with regard to
significant deficiencies and material weaknesses.

Date: March 28, 2003
/s/ William R. Cordes
-----------------------------------
William R. Cordes
President, Northern Plains Natural
Gas Company

37

CERTIFICATION PURSUANT TO RULE 13-A OR 15d-14 OF THE SECURITIES EXCHANGE ACT OF
1934, AS ADOPTED PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Jerry L. Peters, certify that:

1. I have reviewed this annual report on Form 10-K of Northern Border Pipeline
Company;

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 officer 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 we 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 officer and I have disclosed, based on our
most recent evaluation, to the registrant's auditors and audit committee of
registrant's board of directors (or persons performing the equivalent function):

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 officer and I have indicated in this annual
report whether or not there are significant changes in internal controls or in
other factors that could significantly affect internal controls subsequent to
the date of our most evaluation, including any corrective actions with regard to
significant deficiencies and material weaknesses.

Date: March 28, 2003
/s/ Jerry L. Peters
------------------------------------
Jerry L. Peters
Vice President, Finance and
Treasurer
Northern Plains Natural Gas Company

38

NORTHERN BORDER PIPELINE COMPANY

INDEX TO FINANCIAL STATEMENTS

F-1

INDEPENDENT AUDITORS' REPORT

Northern Border Pipeline Company:

We have audited the accompanying balance sheets of Northern Border Pipeline
Company (a Texas partnership) as of December 31, 2002 and 2001, and the related
statements of income, comprehensive income, cash flows, and changes in partners'
equity for each of the years in the three-year 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 of America. 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 Northern Border Pipeline
Company as of December 31, 2002 and 2001, and the results of its operations and
its cash flows for each of the years in the three-year period ended December 31,
2002, in conformity with accounting principles generally accepted in the United
States of America.

KPMG LLP

January 23, 2003
Omaha, Nebraska

F-2

NORTHERN BORDER PIPELINE COMPANY

BALANCE SHEET

(IN THOUSANDS)

The accompanying notes are an integral part of these financial statements.

F-3

NORTHERN BORDER PIPELINE COMPANY

STATEMENT OF INCOME

(IN THOUSANDS)

NORTHERN BORDER PIPELINE COMPANY

STATEMENT OF COMPREHENSIVE INCOME

(IN THOUSANDS)

The accompanying notes are an integral part of these financial statements.

F-4

NORTHERN BORDER PIPELINE COMPANY

STATEMENT OF CASH FLOWS

(IN THOUSANDS)

The accompanying notes are an integral part of these financial statements.

F-5

NORTHERN BORDER PIPELINE COMPANY

STATEMENT OF CHANGES IN PARTNERS' EQUITY

(IN THOUSANDS)

The accompanying notes are an integral part of these financial statements.

F-6

NORTHERN BORDER PIPELINE COMPANY

NOTES TO FINANCIAL STATEMENTS

1. ORGANIZATION AND MANAGEMENT

Northern Border Pipeline Company (Northern Border Pipeline) is a Texas
general partnership formed in 1978. The ownership percentages of the
partners in Northern Border Pipeline (Partners) at December 31, 2002
and 2001, are as follows:

Northern Border Pipeline owns a 1,249-mile natural gas transmission
pipeline system extending from the United States-Canadian border near
Port of Morgan, Montana, to a terminus near North Hayden, Indiana.

Northern Border Pipeline is managed by a Management Committee that
includes three representatives from Northern Border Intermediate Limited
Partnership (Partnership) and one representative from TC PipeLines
Intermediate Limited Partnership (TC PipeLines). The Partnership's
representatives selected by its general partners, Northern Plains
Natural Gas Company (Northern Plains), a wholly-owned subsidiary of
Enron Corp. (Enron), Pan Border Gas Company (Pan Border), a wholly-owned
subsidiary of Northern Plains, and Northwest Border Pipeline Company, a
wholly-owned subsidiary of TransCanada PipeLines Limited and affiliate
of TC PipeLines, have 35%, 22.75% and 12.25%, respectively, of the
voting interest on the Management Committee. The representative
designated by TC PipeLines votes the remaining 30% interest. The
day-to-day management of Northern Border Pipeline's affairs is the
responsibility of Northern Plains, as defined by an operating agreement
between Northern Border Pipeline and Northern Plains. Northern Border
Pipeline is charged for the salaries, benefits and expenses of Northern
Plains. Northern Plains also utilizes Enron affiliates for management
services related to Northern Border Pipeline. For the years ended
December 31, 2002, 2001, and 2000, Northern Border Pipeline's charges
from Northern Plains and its affiliates totaled approximately $22.8
million, $29.5 million and $31.7 million, respectively. See Note 10 for
a discussion of Northern Border Pipeline's relationships with Enron and
developments involving Enron.

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

(A) Use of Estimates

The preparation of financial statements in conformity with
accounting principles generally accepted in the United States of
America requires management to make estimates and assumptions
that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of
the financial statements and the reported amounts of revenues and
expenses during the reporting period. Actual results could differ
from those estimates.

(B) Government Regulation

Northern Border Pipeline is subject to regulation by the Federal
Energy Regulatory Commission (FERC). Northern Border Pipeline's
accounting policies conform to Statement of Financial Accounting
Standards (SFAS) No. 71, "Accounting for the Effects of Certain
Types of Regulation."

F-7

NORTHERN BORDER PIPELINE COMPANY

NOTES TO FINANCIAL STATEMENTS

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)

(B) Government Regulation (continued)

Accordingly, certain assets that result from the regulated
ratemaking process are recorded that would not be recorded under
accounting principles generally accepted in the United States of
America for nonregulated entities. Northern Border Pipeline
continually assesses whether the recovery of the regulatory
assets is probable by considering such factors as regulatory
changes and the impact of competition. Northern Border Pipeline
believes the recovery of the existing regulatory assets is
probable. If future recovery ceases to be probable, Northern
Border Pipeline would be required to write off the regulatory
assets at that time. At December 31, 2002 and 2001, Northern
Border Pipeline has reflected regulatory assets of approximately
$10.5 million and $11.5 million, respectively, in other assets on
the balance sheet. Northern Border Pipeline is recovering the
regulatory assets from its shippers over varying time periods,
which range from five to 44 years.

(C) Revenue Recognition

Northern Border Pipeline transports gas for shippers under a
tariff regulated by the FERC. The tariff specifies the
calculation of amounts to be paid by shippers and the general
terms and conditions of transportation service on the pipeline
system. Northern Border Pipeline's revenues are derived from
agreements for the receipt and delivery of gas at points along
the pipeline system as specified in each shipper's individual
transportation contract. Northern Border Pipeline does not own
the gas that it transports, and therefore it does not assume the
related natural gas commodity risk.

(D) Income Taxes

Income taxes are the responsibility of the Partners and are not
reflected in these financial statements. However, the Northern
Border Pipeline FERC tariff establishes the method of accounting
for and calculating income taxes and requires Northern Border
Pipeline to reflect in its rates the income taxes, which would
have been paid or accrued if Northern Border Pipeline were
organized during the period as a corporation. As a result, for
purposes of determining transportation rates in calculating the
return allowed by the FERC, Partners' capital and rate base are
reduced by the amount equivalent to the net accumulated deferred
income taxes. Such amounts were approximately $343 million and
$336 million at December 31, 2002 and 2001, respectively, and are
primarily related to accelerated depreciation and other
plant-related differences.

(E) Cash and Cash Equivalents

Cash equivalents consist of highly liquid investments with
original maturities of three months or less. The carrying amount
of cash and cash equivalents approximates fair value because of
the short maturity of these investments.

(F) Property, Plant and Equipment and Related Depreciation and
Amortization

Property, plant and equipment is stated at original cost. During
periods of construction, Northern Border Pipeline is permitted to

F-8

NORTHERN BORDER PIPELINE COMPANY

NOTES TO FINANCIAL STATEMENTS

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)

(F) Property, Plant and Equipment and Related Depreciation and
Amortization (continued)

capitalize an allowance for funds used during construction, which
represents the estimated costs of funds used for construction
purposes. The original cost of property retired is charged to
accumulated depreciation and amortization, net of salvage and
cost of removal. No retirement gain or loss is included in income
except in the case of retirements or sales of entire regulated
operating units.

Maintenance and repairs are charged to operations in the period
incurred. The provision for depreciation and amortization of the
transmission line is an integral part of Northern Border
Pipeline's FERC tariff. The effective depreciation rate applied
to Northern Border Pipeline's transmission plant is 2.25%.
Composite rates are applied to all other functional groups of
property having similar economic characteristics.

(G) Risk Management

Financial instruments are used by Northern Border Pipeline in the
management of its interest rate exposure. A control environment
has been established which includes policies and procedures for
risk assessment and the approval, reporting and monitoring of
financial instrument activities. Northern Border Pipeline does
not use these instruments for trading purposes. SFAS No. 133,
"Accounting for Derivative Instruments and Hedging Activities,"
as amended by SFAS No. 137 and SFAS No. 138, requires that every
derivative instrument (including certain derivative instruments
embedded in other contracts) be recorded on the balance sheet as
either an asset or liability measured at its fair value. The
statement requires that changes in the derivative's fair value be
recognized currently in earnings unless specific hedge accounting
criteria are met. Special accounting for qualifying hedges allows
a derivative's gains and losses to offset related results on the
hedged item in the income statement, and requires that a company
formally document, designate and assess the effectiveness of
transactions that receive hedge accounting. Northern Border
Pipeline adopted SFAS No. 133 beginning January 1, 2001. See Note
6 for a discussion of Northern Border Pipeline's derivative
instruments and hedging activities.

3. RATES AND REGULATORY ISSUES

Northern Border Pipeline filed a rate proceeding with the FERC in May
1999 for, among other things, a redetermination of its allowed equity
rate of return. In September 2000, Northern Border Pipeline filed a
stipulation and agreement with the FERC that documented the proposed
settlement of its 1999 rate case. The settlement was approved by the
FERC in December 2000. Under the settlement, both Northern Border
Pipeline and its existing shippers will not be able to seek rate
changes until November 1, 2005, at which time Northern Border Pipeline
must file a new rate case.

After the FERC approved the rate case settlement and prior to the end
of 2000, Northern Border Pipeline made estimated refund payments to its
shippers totaling approximately $22.7 million, primarily related to the
period from December 1999 to November 2000. During the first quarter of
2001, Northern Border Pipeline paid the remaining refund obligation to
its

F-9

NORTHERN BORDER PIPELINE COMPANY

NOTES TO FINANCIAL STATEMENTS

3. RATES AND REGULATORY ISSUES (continued)

shippers totaling approximately $6.8 million, which related to periods
through January 2001.

On March 16, 2000, the FERC issued an order granting Northern Border
Pipeline's application for a certificate to construct and operate an
expansion and extension of its pipeline system into Indiana (Project
2000). The facilities for Project 2000 were placed into service on
October 1, 2001.

In 2003, Northern Border Pipeline filed to amend its tariff for the
definition of company use gas, which is gas supplied by its shippers
for its operations, to clarify the language by adding detail to the
broad categories that comprise company use gas. Relying upon the
currently effective version of the tariff, Northern Border Pipeline
included in its collection of company use gas, quantities that were
equivalent to the cost of electric power at its electric-driven
compressor stations during the period of June 2001 through January
2003. The proposed language provides additional detail concerning the
practice of recognizing electric costs at electric powered compressor
stations in the determination of company use gas. Northern Border
Pipeline requested that the tariff change be effective April 1, 2003.
Several parties have filed protests of this change and have requested
that the FERC order refunds. While Northern Border Pipeline cannot
predict the outcome of this proceeding at this time, the accompanying
financial statements reflect a reserve of $10 million.

4. TRANSPORTATION SERVICE AGREEMENTS

Operating revenues are collected pursuant to the FERC tariff through
firm transportation service agreements. The firm service agreements
extend for various terms with termination dates that range from March
2003 to December 2013. Northern Border Pipeline also has interruptible
transportation service agreements and other transportation service
agreements with numerous shippers.

Under the capacity release provisions of Northern Border Pipeline's
FERC tariff, shippers are allowed to release all or part of their
capacity either permanently for the full term of the contract or
temporarily. A temporary capacity release does not relieve the original
contract shipper from its payment obligations if the replacement
shipper fails to pay for the capacity temporarily released to it.

At December 31, 2002, Northern Border Pipeline's largest shipper is
Pan-Alberta Gas (U.S.) Inc. (Pan-Alberta) with approximately 20% of the
contracted firm capacity, of which approximately 3% has been
temporarily released to other shippers through October 31, 2003. Mirant
Americas Energy Marketing, LP (Mirant), who manages the assets of
Pan-Alberta Gas, Ltd., including the Pan-Alberta contracts with
Northern Border Pipeline, also is obligated for approximately 10% of
the contracted firm capacity. The Pan-Alberta firm service agreements
expire in October 2003. The Mirant firm service agreements expire
in October 2006 and December 2008. The obligations of Pan-Alberta
and Mirant are supported by various credit support arrangements,
including among others, letters of credit and escrow accounts and an
upstream capacity transfer agreement. Operating revenues

F-10

NORTHERN BORDER PIPELINE COMPANY

NOTES TO FINANCIAL STATEMENTS

4. TRANSPORTATION SERVICE AGREEMENTS (continued)

from Mirant and Pan-Alberta for the years ended December 31, 2002, 2001
and 2000 were $105.5 million, $80.7 million and $78.2 million,
respectively.

At December 31, 2002, there is no contracted firm capacity held by
shippers affiliated with Northern Border Pipeline. Previously, some of
Northern Border Pipeline's shippers have been affiliated with its
general partners. Operating revenues from affiliates were $1.4 million,
$52.1 million and $58.5 million for the years ended December 31, 2002,
2001, and 2000, respectively.

5. CREDIT FACILITIES AND LONG-TERM DEBT

Detailed information on long-term debt is as follows:

Northern Border Pipeline entered into a $175 million three-year credit
agreement (2002 Pipeline Credit Agreement) with certain financial
institutions in May 2002, which is to be used to refinance existing
indebtedness and for general business purposes. The 2002 Pipeline Credit
Agreement permits Northern Border Pipeline to choose among various
interest rate options, to specify the portion of the borrowings to be
covered by specific interest rate options and to specify the interest
rate period. Northern Border Pipeline is required to pay a fee on the
principal commitment amount of $175 million.

In April 2002, Northern Border Pipeline completed a private offering of
$225 million of 6.25% Senior Notes due 2007 (2002 Pipeline Senior Notes)
and in September 2001, Northern Border Pipeline completed a private
offering of $250 million of 7.50% Senior Notes due 2021 (2001 Pipeline
Senior Notes). The 2002 Pipeline Senior Notes and 2001 Pipeline Senior
Notes were subsequently exchanged in registered offerings for notes with
substantially identical terms. The proceeds from the senior notes were
used to reduce indebtedness outstanding.

F-11

NORTHERN BORDER PIPELINE COMPANY

NOTES TO FINANCIAL STATEMENTS

5. CREDIT FACILITIES AND LONG-TERM DEBT (continued)

Interest paid, net of amounts capitalized, during the years ended
December 31, 2002, 2001 and 2000 was $55.3 million, $53.9 million and
$68.0 million, respectively.

Aggregate required repayments of long-term debt are as follows: $65
million, $89 million and $225 million for 2003, 2005 and 2007,
respectively. There are no required repayment obligations for either
2004 or 2006.

Certain of Northern Border Pipeline's long-term debt and credit
arrangements contain requirements as to the maintenance of minimum
partners' capital and debt to capitalization ratios, leverage ratios and
interest coverage ratios that restrict the incurrence of other
indebtedness by Northern Border Pipeline and also place certain
restrictions on distributions to the partners of Northern Border
Pipeline. Under the most restrictive of the covenants, as of December
31, 2002 and 2001, respectively, $99 million and $110 million of
partners' capital of Northern Border Pipeline could be distributed. The
2002 Pipeline Credit Agreement requires the maintenance of a ratio of
EBITDA (net income plus interest expense, income taxes and depreciation
and amortization) to interest expense of greater than 3 to 1. The
2002 Pipeline Credit Agreement also requires the maintenance of the
ratio of indebtedness to EBITDA of no more than 4.5 to 1. At December
31, 2002, Northern Border Pipeline was in compliance with these
covenants.

The following estimated fair values of financial instruments represent
the amount at which each instrument could be exchanged in a current
transaction between willing parties. Based on quoted market prices for
similar issues with similar terms and remaining maturities, the
estimated fair value of the 1992 Pipeline Senior Notes, 1999 Pipeline
Senior Notes, 2001 Pipeline Senior Notes and 2002 Pipeline Senior Notes
was approximately $827 million and $623 million at December 31, 2002 and
2001, respectively. Northern Border Pipeline presently intends to
maintain the current schedule of maturities for the 1992 Pipeline Senior
Notes, 1999 Pipeline Senior Notes, 2001 Pipeline Senior Notes and the
2002 Pipeline Senior Notes, which will result in no gains or losses on
their respective repayment. The fair value of Northern Border Pipeline's
variable rate debt approximates the carrying value since the interest
rates are periodically adjusted to reflect current market conditions.

6. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

As a result of the adoption of SFAS No. 133, Northern Border Pipeline
reclassified approximately $11.1 million from long-term debt to
accumulated other comprehensive income related to unamortized proceeds
from the termination of interest rate swap agreements. Also upon
adoption of SFAS No. 133, Northern Border Pipeline recorded a non-cash
loss in accumulated other comprehensive income of approximately $0.8
million, related to its outstanding interest rate swap agreement with a
notional amount of $40 million, which terminated in November 2001.

Prior to the anticipated issuance of fixed rate debt, Northern Border
Pipeline has entered into forward starting interest rate swap
agreements. The interest rate swaps have been designated as cash flow
hedges as they were entered into to hedge the fluctuations in Treasury
rates and spreads between the execution date of the swaps and the
issuance of the fixed rate debt. The notional amount of the interest
rate swaps does not exceed the expected principal amount of fixed rate
debt to be issued. Upon issuance of the fixed rate debt, the swaps were
terminated and the proceeds received or

F-12

NORTHERN BORDER PIPELINE COMPANY

NOTES TO FINANCIAL STATEMENTS

6. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES (continued)

amounts paid to terminate the swaps were recorded in accumulated other
comprehensive income and amortized to interest expense over the term of
the hedged debt.

For the year ended December 31, 2002, Northern Border Pipeline received
$2.4 million from terminated interest rate swaps. For the year ended
December 31, 2001, Northern Border Pipeline paid approximately $4.1
million to terminate interest rate swaps.

During the years ended December 31, 2002 and 2001, respectively,
Northern Border Pipeline amortized approximately $1.4 million and $1.2
million related to the terminated interest rate swap agreements as a
reduction to interest expense from accumulated other comprehensive
income. Northern Border Pipeline expects to amortize approximately $1.6
million in 2003.

Northern Border Pipeline entered into interest rate swap agreements with
notional amounts totaling $225 million in May 2002. Under the interest
rate swap agreements, Northern Border Pipeline makes payments to
counterparties at variable rates based on the London Interbank Offered
Rate and in return receives payments based on a 6.25% fixed rate. At
December 31, 2002, the average effective interest rate on Northern
Border Pipeline's interest rate swap agreements was 2.70%. Northern
Border Pipeline's interest rate swap agreements have been designated as
fair value hedges as they were entered into to hedge the fluctuations in
the market value of the 2002 Pipeline Senior Notes. The accompanying
balance sheet at December 31, 2002, reflects a non-cash gain of
approximately $21.2 million in derivative financial instruments with a
corresponding increase in long-term debt.

7. COMMITMENTS AND CONTINGENCIES

Operating Leases

Future minimum lease payments under non-cancelable operating leases on
office space are as follows (in thousands):

Capital expenditures

Total capital expenditures for 2003 are estimated to be $11 million.
Funds required to meet the capital expenditures for 2003 are anticipated
to be provided primarily from debt borrowings and operating cash flows.

Environmental Matters

Northern Border Pipeline is not aware of any material contingent
liabilities with respect to compliance with applicable environmental
laws and regulations.

F-13

NORTHERN BORDER PIPELINE COMPANY

NOTES TO FINANCIAL STATEMENTS

7. COMMITMENTS AND CONTINGENCIES (continued)

Other

On July 31, 2001, the Assiniboine and Sioux Tribes of the Fort Peck
Indian Reservation (Tribes) filed a lawsuit in Tribal Court against
Northern Border Pipeline to collect more than $3 million in back taxes,
together with interest and penalties. The lawsuit relates to a utilities
tax on certain of Northern Border Pipeline's properties within the Fort
Peck Indian Reservation. The Tribes and Northern Border Pipeline,
through a mediation process, have held settlement discussions and have
reached a settlement in principle on pipeline right-of-way lease and
taxation issues, subject to final documentation and necessary government
approvals. Northern Border Pipeline believes that the resolution of this
lawsuit will not have a material adverse impact on Northern Border
Pipeline's results of operations or financial position.

Various legal actions that have arisen in the ordinary course of
business are pending. Northern Border Pipeline believes that the
resolution of these issues will not have a material adverse impact on
Northern Border Pipeline's results of operations or financial position.

8. QUARTERLY FINANCIAL DATA (Unaudited)

9. ACCOUNTING PRONOUNCEMENTS

In 2001, the Financial Accounting Standards Board (FASB) issued SFAS No.
143, "Accounting for Asset Retirement Obligations." SFAS No. 143
requires entities to record the fair value of a liability for an asset
retirement obligation in the period in which it is incurred, if the
liability can be reasonably estimated. When the liability is initially
recorded, the carrying amount of the related asset is increased by the
same amount. Over time, the liability is accreted to its future value
and the accretion is recorded to expense. The initial adjustment to the
asset is depreciated over its useful life. Upon settlement of the
liability, an entity either settles the obligation for its recorded
amount or incurs a gain or loss. SFAS No. 143 is effective for fiscal
years beginning after June 15, 2002, with earlier application
encouraged. In some instances, Northern Border Pipeline is obligated by
contractual terms or regulatory requirements to remove facilities or
perform other remediation upon retirement. Northern Border Pipeline
expects that it will be unable to reasonably estimate and record
liabilities for its obligations that fall under the provisions of this
statement because it cannot reasonably estimate when such obligations
would be settled. The effect of adopting SFAS No. 143 is not expected to
be material to the financial statements.

F-14

NORTHERN BORDER PIPELINE COMPANY

NOTES TO FINANCIAL STATEMENTS

9. ACCOUNTING PRONOUNCEMENTS (continued)

In April 2002, the FASB issued SFAS No. 145, "Rescission of FASB
Statements No. 4, No. 44 and No. 64, Amendments to FASB Statements No.
13 and Technical Corrections." SFAS No. 146, "Accounting for Costs
Associated with Exit or Disposal Activities" was issued in June 2002.
SFAS No. 145 streamlines the reporting of debt extinguishments and
requires that only gains and losses from extinguishments meeting the
criteria in Accounting Principles Board Opinion 30 would be classified
as extraordinary. SFAS No. 146 requires that a liability for a cost
associated with an exit or disposal activity be recognized when the
liability is incurred. SFAS No. 145 is effective for fiscal years
beginning after May 15, 2002. SFAS No. 146 is effective for exit or
disposal activities that are initiated after December 31, 2002.
Northern Border Pipeline does not expect the adoption of SFAS No. 145
and SFAS No. 146 to have a material impact on its financial position,
results of operations or cash flows.

10. RELATIONSHIPS WITH ENRON

In December 2001, Enron and certain of its subsidiaries filed voluntary
petitions for Chapter 11 reorganization with the U.S. Bankruptcy Court.
Northern Plains was not included in the bankruptcy filing and
management believes that Northern Plains will continue to be able to
meet its operational and administrative service obligations under the
existing operating agreement. Enron North America Corp. (ENA), a
subsidiary of Enron, was included in the bankruptcy filing. At the time
of the bankruptcy filing, ENA had firm service agreements representing
approximately 3.5% of contracted capacity, a portion of which (1.1%)
had been temporarily released to a third party until October 31, 2002.
Northern Border Pipeline recorded a bad debt expense of approximately
$1.3 million representing ENA's unpaid November and December 2001
transportation, which is included in operations and maintenance expense
on the statement of income. On June 13, 2002, the Bankruptcy Court
approved a Stipulation and Order entered into on May 15, 2002, by ENA
and Northern Border Pipeline pursuant to which ENA agreed that all but
one of the shipper contracts, representing 1.7% of pipeline capacity,
will be deemed rejected and terminated. The remaining contract was
terminated in the third quarter of 2002. For the year ended December
31, 2002, Northern Border Pipeline has experienced lost revenues of
approximately $1.8 million related to ENA's capacity. Northern Border
Pipeline has filed proofs of claims regarding the amount of damages for
breach of contract and other claims in the bankruptcy proceeding.
However, Northern Border Pipeline cannot predict the amounts, if any,
that it will collect or the timing of collection. Northern Border
Pipeline believes, however, that any amounts collected will not be
material.

Northern Border Pipeline continues to monitor developments at Enron, to
assess the impact on Northern Border Pipeline of its existing
agreements and relationships with Enron, and to take appropriate action
to protect Northern Border Pipeline's interests.

11. SUBSEQUENT EVENTS

Northern Border Pipeline makes distributions to it general partners
approximately one month following the end of the quarter. The
distribution for the fourth quarter of 2002 of approximately $41.8
million was declared in January 2003 to be paid in February 2003.

F-15

INDEPENDENT AUDITORS' REPORT ON SCHEDULE

Northern Border Pipeline Company:

We have audited in accordance with auditing standards generally accepted in the
United States of America, the financial statements of Northern Border Pipeline
Company as of December 31, 2002 and 2001 and for each of the years in the
three-year period ended December 31, 2002 included in this Form 10-K, and have
issued our report thereon dated January 23, 2003.

Our audits were made for the purpose of forming an opinion on the basic
financial statements taken as a whole. The schedule of Northern Border Pipeline
Company listed in Item 14 of Part IV of this Form 10-K is the responsibility of
the Company's management and is presented for purposes of complying with the
Securities and Exchange Commission's rules and is not part of the basic
financial statements. This schedule has been subjected to the auditing
procedures applied in the audits of the basic financial statements and, in our
opinion, fairly states in all material respects, the financial data required to
be set forth therein in relation to the basic financial statements taken as a
whole.

KPMG LLP

January 23, 2003
Omaha, Nebraska

S-1

SCHEDULE II

NORTHERN BORDER PIPELINE COMPANY

SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 2002, 2001 AND 2000
(IN THOUSANDS)

S-2

EXHIBIT INDEX

(a) (3) EXHIBITS

*3.1 Northern Border Pipeline Company General Partnership
Agreement between Northern Plains Natural Gas Company,
Northwest Border Pipeline Company, Pan Border Gas Company,
TransCanada Border Pipeline Ltd. and TransCan Northern
Ltd., effective March 9, 1978, as amended (Exhibit 10.2 to
Northern Border Partners, L.P.'s Form S-1, SEC File No.
33-66158 ("Form S-1")).

*4.1 Indenture, dated as of August 17, 1999, between the
registrant and Bank One Trust Company, NA, successor to The
First National Bank of Chicago, as trustee (Exhibit 4.1 to
Northern Border Pipeline Company's Form S-4 Registration
Statement, Registration No. 333-88577 ("Form S-4")).

*4.2 Indenture, dated as of September 17, 2001, between Northern
Border Pipeline Company and Bank One Trust Company, N.A.
(Exhibit 4.2 to Northern Border Pipeline Company's
Registration Statement on Form S-4, Registration No.
333-73282 ("2001 Form S-4")).

*4.3 Indenture, dated as of April 29, 2002, between Northern
Border Pipeline Company and Bank One Trust Company, N.A.
(Exhibit 4.1 to Northern Border Pipeline Company's Form
10-Q for the quarter ended March 31, 2002).

*10.1 Operating Agreement between Northern Border Pipeline
Company and Northern Plains Natural Gas Company, dated
February 28, 1980 (Exhibit 10.3 to Form S-1).

*10.2 Note Purchase Agreement between Northern Border Pipeline
Company and the parties listed therein, dated July 15, 1992
(Exhibit 10.6 to Form S-1).

*10.3 Supplemental Agreement to the Note Purchase Agreement dated
as of June 1, 1995 (Exhibit 10.6.1 to Northern Border
Partners L.P.'s Form 10-K for the year ended December 31,
1995, SEC File No. 1-12202 ("1995 10-K")).

*10.4 Credit Agreement, dated as of May 16, 2002, among Northern
Border Pipeline Company, Bank One, NA, Citibank, N.A., Bank
of Montreal, SunTrust Bank, Wachovia Bank, National
Association, Banc One Capital Markets, Inc, and Lenders (as
defined therein) (Exhibit 10.1 to Northern Borders
Partners, L.P.'s Current Report on Form 8-K dated June 26,
2002).

*10.5 Seventh Supplement Amending Northern Border Pipeline
Company General Partnership Agreement (Exhibit 10.15 to
Form S-1).

*10.6 Eighth Supplement Amending Northern Border Pipeline Company
General Partnership Agreement (Exhibit 10.15 of Form S-4).

*10.7 Ninth Supplement Amending Northern Border Pipeline Company
General Partnership Agreement (Exhibit 10.37 to 2001 Form
S-4).

*10.8 Form of Conveyance, Contribution and Assumption Agreement
among Northern Plains Natural Gas Company, Northwest Border
Pipeline Company, Pan Border Gas Company, Northern Border
Partners, L.P., and Northern Border Intermediate Limited
Partnership (Exhibit 10.16 to Form S-1).

*10.9 Form of Contribution, Conveyance and Assumption Agreement
among TC PipeLines, LP and certain other parties. (Exhibit
10.2 to TC PipeLines, LP's Form S-1, SEC File No. 333-69947
("TC Form S-1")).

*10.10 Employment Agreement between Northern Plains Natural Gas
Company and William R. Cordes effective June 1, 2001
(Exhibit 10.27 to Northern Border Partners, L.P.'s
Quarterly Report on Form 10-Q for the quarter ended June
30, 2001).

*10.11 Amendment to Employment Agreement between Northern Plains
Natural Gas Company and William R. Cordes, effective
September 25, 2001 (Exhibit 10.36 to 2001 Form S-4).

*10.12 Employment Agreement between Northern Plains Natural Gas
Company and Jerry L. Peters effective April 1, 2002
(Exhibit 10.1 to Northern Border Pipeline Company's Form
10-Q for the quarter ended March 31, 2002).

*10.13 Northern Border Pipeline Company Agreement among Northern
Plains Natural Gas Company, Pan Border Gas Company,
Northwest Border Pipeline Company, TransCanada Border
PipeLine Ltd., TransCan Northern Ltd., Northern Border
Intermediate Limited Partnership, Northern Border Partners,
L.P., and the Management Committee of Northern Border
Pipeline, dated as of March 17, 1999 (Exhibit 10.21 to
Northern Border Partners, L.P.'s Form 10-K for the year
ended December 31, 1998, SEC File No. 1-12202 ("1998
10-K")).

*10.14 Northern Border Pipeline Company U.S. Shippers Service
Agreement between Northern Border Pipeline Company and
Pan-Alberta Gas (U.S.) Inc., dated October 1, 1993, with
Amended Exhibit A effective June 22, 1998 (Exhibit 10.25 to
TC Form S-1).

*10.15 Northern Border Pipeline Company U.S. Shippers Service
Agreement between Northern Border Pipeline Company and
Pan-Alberta Gas (U.S.) Inc. (successor to Natgas U.S.
Inc.), dated October 6, 1989, with Amended Exhibit A
effective April 2, 1999 (Exhibit 10.26 to TC Form S-1).

*10.16 Northern Border Pipeline Company U.S. Shippers Service
Agreement between Northern Border Pipeline Company and
Pan-Alberta Gas (U.S.) Inc., dated October 1, 1992, with
Amended Exhibit A effective June 22, 1998 (Exhibit 10.27 to
TC Form S-1).

*16.1 Letter of Arthur Andersen LLP, former auditors of Northern
Border Pipeline Company, dated February 11, 2002 (Exhibit
99.3 to Northern Border Pipeline Company's Form 8-K filed
on February 13, 2002).

*99.1 Northern Border Phantom Unit Plan (Exhibit 99.1 to Northern
Border Partners, L.P.'s Registration No. 333-66949 and
Exhibit 99.1 to Northern Border Partners, L.P.'s
Registration No. 333-72696).

99.2 Certification of principal executive officer pursuant to 18
U.S.C. Section 1350, as adopted pursuant to Section 906 of
the Sarbanes-Oxley Act of 2002.

99.3 Certification of principal financial officer pursuant to 18
U.S.C. Section 1350, as adopted pursuant to Section 906 of
the Sarbanes-Oxley Act of 2002.

*Indicates exhibits incorporated by reference as indicated; all
other exhibits are filed herewith.