NORTHERN BORDER PARTNERS LP - 10-K Annual Report

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

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

FORM 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: 1-12202

NORTHERN BORDER PARTNERS, L.P.
(Exact name of registrant as specified in its charter)

DELAWARE 93-1120873
(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
- ------------------- -----------------------------------------

Common Units New York Stock Exchange

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 [X] No [ ]

Aggregate market value of the Common Units held by non-affiliates of
the registrant, based on closing prices in the daily composite list for
transactions on the New York Stock Exchange on June 28, 2002, was approximately
$1,373,496,413.

ii

NORTHERN BORDER PARTNERS, L.P.
TABLE OF CONTENTS

i

PART I

ITEM 1. BUSINESS

GENERAL

We are a publicly-traded limited partnership formed in 1993 and a
leading transporter of natural gas imported from Canada to the United States.
Our business operations are comprised of the following segments:

o Interstate Natural Gas Pipelines

o Natural Gas Gathering and Processing

o Coal Slurry Pipeline

Our interstate natural gas pipelines segment includes companies that
provide natural gas transmission services in the midwestern United States. The
companies in this segment transport gas for shippers under tariffs regulated by
the Federal Energy Regulatory Commission ("FERC"). The interstate pipelines'
revenues are derived from agreements for the receipt and delivery of gas at
points along the pipeline systems as specified in each shipper's individual
transportation contract. In mid January 2003, we expanded this segment with our
acquisition of Viking Gas Transmission Company, including a one-third interest
in Guardian Pipeline, L.L.C.

Our gas gathering and processing segment provides services for the
gathering, treating, processing and compression of natural gas and the
fractionation of natural gas liquids ("NGLs") for third parties and related
field services. We do not explore for, or produce, crude oil or natural gas, and
do not own crude oil or natural gas reserves. We have extensive gas gathering
operations in the Powder River Basin in Wyoming. We also have natural gas
gathering, processing and fractionation operations in the Williston Basin in
Montana and North Dakota, and the western Canadian sedimentary basin, in
Alberta, Canada.

Our coal slurry pipeline segment is comprised of our ownership of Black
Mesa Pipeline, Inc., a 273-mile pipeline, the only coal slurry pipeline in
operation in the United States.

We are managed under the direction of a partnership policy committee
(similar to a board of directors). The partnership policy committee consists of
three members, each of whom has been appointed by one of our general partners.
Our general partners and the general partners of our subsidiary limited
partnership, Northern Border Intermediate Limited Partnership, are Northern
Plains Natural Gas Company and Pan Border Gas Company, both subsidiaries of
Enron Corp. ("Enron"), and Northwest Border Pipeline Company, a subsidiary of
TransCanada PipeLines Limited ("TransCanada"). In this report, references to
"we", "us", "our" or the "Partnership" collectively refer to Northern Border
Partners and our subsidiary, Northern Border Intermediate Limited Partnership.
See Item 10. "Partnership Management."

Our general partners hold an aggregate 2% general partner interest in
the Partnership. Northern Plains also owns common units representing a 1.14%
limited partner interest and Sundance Assets, L.P.,

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an affiliate of Enron, holds a 6.19% limited partner interest. See Item 12.
"Security Ownership of Certain Beneficial Owners and Management." The combined
general and limited partner interests in the Partnership held by Enron and
TransCanada are 8.83% and 0.35%, respectively.

NBP Services Corporation, an Enron subsidiary, provides administrative
services for us and operating services for our natural gas gathering and
processing segment. NBP Services has approximately 135 employees and utilizes
employees and information technology systems of its affiliates to provide these
services. Northern Plains provides operating services to our interstate
pipelines and the coal slurry pipeline segment pursuant to operating agreements.
Northern Plains employs approximately 223 individuals located at our
headquarters in Omaha, Nebraska, and at various locations near the pipelines and
also utilizes employees and information technology systems of its affiliates to
provide its services. NBP Services' and Northern Plains' employees are not
represented by any labor union and are not covered by any collective bargaining
agreements.

On December 2, 2001, 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, Pan Border and NBP Services. 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," Item 13.
"Certain Relationships and Related Transactions" and Item 10. "Partnership
Management."

We make available through our website, www.northernborderpartners.com,
our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports
on Form 8-K and amendments to those reports filed or furnished pursuant to
Section 13(a) or 15(d) of the Exchange Act as soon as reasonably practicable
after we electronically file such material with, or furnish it to, the
Securities and Exchange Commission.

For additional information about our business segments and geographic
areas, see Note 14 - Notes to Consolidated Financial Statements included in this
report.

INTERSTATE NATURAL GAS PIPELINES

Our interstate pipelines segment provides natural gas transmission
services in the midwestern United States. Our interstate pipelines transport gas
for shippers under tariffs regulated by the FERC. The tariffs specify the
calculation of amounts to be paid by shippers and the general terms and
conditions of transportation service on the pipeline systems. The interstate
pipelines' revenues are derived from agreements for the receipt and delivery of
gas at points along the pipeline systems as specified in each shipper's
individual transportation contract. The interstate pipelines do not own the gas
that they transport and therefore do not assume natural gas commodity price risk
for quantities transported.

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NORTHERN BORDER PIPELINE SYSTEM

We own a 70% general partnership interest in Northern Border Pipeline
Company, a Texas general partnership. Northern Border Pipeline owns 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. The pipeline system was expanded and/or extended in 1991,
1992, 1998 and 2001. This pipeline system connects directly and through multiple
pipelines to various natural gas markets in the United States. In the year ended
December 31, 2002, we estimate that Northern Border Pipeline 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.

Our interest in Northern Border Pipeline represents the largest
proportion of our assets, earnings and cash flows. The remaining 30% general
partner interest in Northern Border Pipeline is owned by TC PipeLines
Intermediate Limited Partnership, a subsidiary limited partnership of TC
PipeLines, LP, a publicly-traded partnership ("TC PipeLines"). The general
partner of TC PipeLines and its subsidiary limited partnership is TC PipeLines
GP, Inc., which is a subsidiary of TransCanada.

Management of Northern Border Pipeline is overseen by the Northern
Border Management Committee, which is comprised of three representatives from
the Partnership (one designated by each of our general partners) and one
representative from 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 our 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. Therefore, Enron controls 57.75%
of the voting power of the management committee and has the right to select two
of its members. For a discussion of specific relationships with affiliates,
refer to Item 13. "Certain Relationships and Related Transactions."

The 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.

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The 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, the pipeline system connects with
facilities of Northern Natural Gas Company at Buford, which facilities in turn
are connected to Williston Basin Interstate and the gathering system owned by us
through Bear Paw Energy. Other locations in North Dakota where the pipeline can
receive gas are interconnections with Williston Basin Interstate Pipeline at
Glen Ullin, Amerada Hess Corporation at Watford City, and 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 at Channahon,
Illinois. For the year ended December 31, 2002, of the natural gas transported
on the 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.

To access markets, the pipeline system interconnects with pipeline
facilities of various interstate and intrastate pipeline companies and local
distribution companies, of which the larger interconnections are:

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. in Will County, Illinois;

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

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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 consuming markets in the
Midwest and to interconnecting pipeline facilities, have developed on the
pipeline system. The largest of these market centers is at Northern Border
Pipeline's Ventura, Iowa interconnection with Northern Natural Gas Company. Two
other market center locations are the Harper, Iowa connection with Natural Gas
Pipeline Company of America and the 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.

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."

Northern Border Pipeline's mix and number of shippers may change
throughout the year as a result of its shippers utilizing capacity release
provisions that allow them to release all or part of their capacity, either
permanently for the full term of their contract or temporarily. Under the terms
of Northern Border Pipeline's tariff, a temporary capacity release does not
relieve the original contract shipper from its payment obligations if the new
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 Northern Border Pipeline, 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

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expires on October 31, 2003. See Item 7. "Management's Discussion and Analysis
of Financial Condition and Results of Operations - Outlook."

MIDWESTERN GAS TRANSMISSION SYSTEM

Midwestern Gas Transmission Company, our wholly-owned subsidiary, owns
a 350-mile pipeline system extending from an interconnection with Tennessee Gas
Transmission near Portland, Tennessee to a point of interconnection with several
interstate pipeline systems near Joliet, Illinois. Midwestern Gas Transmission
serves markets in Chicago, Kentucky, southern Illinois and Indiana.

The Midwestern Gas Transmission system consists of 350 miles of 30-inch
diameter pipe with a capacity of 650 mmcfd for volumes transported from
Portland, Tennessee to the north. There are seven compressor stations with total
rated horsepower of 69,070.

The Midwestern Gas Transmission system connects with multiple pipeline
systems that provide its shippers access to various supply sources and markets.
Because of its position in the natural gas pipeline grid, Midwestern Gas
Transmission is designed to receive gas volumes at both ends of its system. On
the north end, Midwestern Gas Transmission can physically receive gas from ANR
Pipeline Company, Northern Border Pipeline, Natural Gas Pipeline Company of
America, Alliance Pipeline, The Peoples Gas Light and Coke Company and CMS
Trunkline Gas Company. The significant receipt point on the southern end of the
system is the interconnection with Tennessee Gas Transmission at Portland.
Additionally, Midwestern Gas Transmission is capable of receiving gas at five
other interconnections along its pipeline system. With respect to market access,
Midwestern Gas Transmission is capable of delivering natural gas at points of
interconnection with the interstate pipeline systems of ANR Pipeline Company,
Guardian Pipeline, L.L.C., Natural Gas Pipeline Company of America, Northern
Border Pipeline, and Texas Gas Transmission Company as well as interconnections
with local distribution companies such as Northern Illinois Gas Company, The
Peoples Gas Light and Coke Company, Illinois Power, and Vectren Energy Delivery
South. In addition, a number of end users and electric power generation
facilities can be served by connections off the pipeline system.

The Midwestern Gas Transmission system serves approximately 30 firm
transportation shippers. Based upon shipper contractual obligations as of
December 31, 2002, approximately 54% of the firm transportation capacity is
contracted by local distribution companies, 43% by marketers and 3% by
end-users.

For the year end December 31, 2002, Midwestern Gas Transmission's two
major customers, Northern Illinois Gas Company and Northern Indiana Public
Service Company accounted for $5.2 million (28%) and $2.9 million (16%),
respectively, of its revenues.

As of December 31, 2002, the termination dates of Midwestern Gas
Transmission's firm transportation contracts ranged from March 31, 2003 to
October 31, 2019. The weighted average contract life, based upon annual contract
obligations, was approximately two and one-half years.

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See Item 7. "Management's Discussion and Analysis of Financial Condition and
Results of Operations - Outlook."

One shipper, Enron North America Corp. ("ENA"), which has filed for
bankruptcy protection, is affiliated with two of our general partners, Northern
Plains and Pan Border. ENA's contract, which has not been terminated or rejected
by ENA, covers less than 1 percent of Midwestern Gas Transmission's firm
capacity. 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."

VIKING GAS TRANSMISSION SYSTEM

Effective January 17, 2003, we acquired Viking Gas Transmission
Company, including a one-third interest in Guardian Pipeline L.L.C. from Xcel
Energy Inc. The Viking Gas Transmission system extends from an interconnection
with TransCanada near Emerson, Manitoba to an interconnection with ANR Pipeline
Company near Marshfield, Wisconsin. Viking Gas Transmission's source of gas
supply is the western Canadian sedimentary basin. Viking Gas Transmission also
has interconnections with Northern Natural Gas Company and Great Lakes Gas
Transmission to serve markets in Minnesota, Wisconsin and North Dakota.

The Viking Gas Transmission system consists of 499 miles of 24-inch
diameter mainline pipe with a design capacity of approximately 500 mmcfd at the
origin near Emerson, Manitoba and 300 mmcfd at the terminus near Marshfield,
Wisconsin, 95 miles of 24-inch mainline looping and 79 miles of smaller diameter
laterals. There are eight compressor stations with a total horsepower of 68,650.
Based upon shipper contractual obligations as of December 31, 2002,
approximately 72% of the firm transportation capacity is contracted by local
distribution companies, 24% by marketers and 4% by end-users.

Guardian Pipeline is a 141-mile interstate natural gas pipeline system
that went into service on December 7, 2002. This system transports natural gas
from Joliet, Illinois to a point west of Milwaukee, Wisconsin. Subsidiaries of
CMS Energy Corporation and Wisconsin Energy Corporation hold the remaining
interests in this system. Wisconsin Gas Company, a subsidiary of Wisconsin
Energy Corporation, has contracted for 80% of the pipeline's 750 mmcfd capacity.
Guardian Pipeline is operated by CMS Trunkline Gas Company, which is part of the
CMS Panhandle Companies. CMS Energy announced that an agreement has been reached
to sell the CMS Panhandle Companies to a new entity owned by Southern Union
Company and AIG Highstar Capital, L.P. and also announced that it intends to
sell its one-third interest in Guardian.

DEMAND FOR INTERSTATE PIPELINE TRANSPORTATION CAPACITY

The long-term financial condition of our interstate natural gas
pipelines segment is dependent on the continued availability of economic natural
gas supplies including western Canadian natural gas 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

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and other facilities that permit natural gas to be produced and delivered to
pipelines that interconnect with our 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 natural gas
supplies. Additional pipeline export capacity also could accelerate depletion of
these reserves. Excess export capacity could also affect the demand or value of
the transport on our interstate pipelines.

Each of our interstate pipelines' 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 the pipeline systems. Demand for
natural gas to serve other markets also influences the ability and willingness
of shippers to use our pipeline systems to meet demand in the markets that our
interstate pipelines serve.

A variety of factors could affect the demand for natural gas in the
markets that our pipeline systems 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.

Our 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 rate customers are willing to pay
when they renegotiate their transportation contracts. The basis differential
between markets 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 interstate pipeline systems or how significant
that adverse effect could be.

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INTERSTATE PIPELINE COMPETITION

Northern Border Pipeline and Viking Gas Transmission 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. Their competitive positions are 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 the systems is affected by natural gas prices, the relationship
between export capacity 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 Northern Border Pipeline
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 Northern Border Pipeline, which serves various markets through
interconnections with other pipelines along its route.

The competitive impact of the Alliance Pipeline 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 both Northern Border Pipeline and
Midwestern Gas Transmission. Guardian Pipeline delivers into markets in
Wisconsin and could provide access to additional markets for Northern Border
Pipeline and Midwestern Gas Transmission shippers.

The Alliance Pipeline has also brought increased supply access for
Midwestern Gas Transmission's customers. The Alliance Pipeline receipt point
into the Midwestern Gas Transmission system near Joliet, Illinois provided 51%
of Midwestern Gas Transmission natural gas receipts during 2002.

Midwestern Gas Transmission can receive and deliver gas at either end
of its system, which makes it a header pipeline system. Consequently, Midwestern
Gas Transmission faces competition from multiple supply sources and interstate
pipelines. In the Chicago market, Midwestern Gas Transmission's competition is
from pipelines transporting gas from the gulf coast and the mid-continent and
gas sourced from Canada. In the Indiana and Western Kentucky markets, Midwestern
Gas Transmission's competition is from pipelines transporting gas from the gulf
coast and mid-continent into these markets.

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Viking Gas Transmission directly serves markets in North Dakota,
Minnesota and Wisconsin. Northern Natural Gas Company competes with Viking Gas
Transmission in these states. In addition, Viking Gas Transmission indirectly
serves Wisconsin and Michigan markets through deliveries into ANR Pipeline. The
deliveries into ANR Pipeline compete with other supply sources on ANR Pipeline,
which includes supply from the gulf coast, mid-continent and Chicago market
center.

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
systems.

INTERSTATE PIPELINE REGULATION

Our interstate pipelines are subject to extensive regulation by the
FERC, each 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 this business segment, including:

o transportation of natural gas;

o rates and charges;

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, our interstate pipelines hold certificates of public
convenience and necessity issued by the FERC covering the 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
interstate pipelines' books and records may be periodically audited by the FERC
under Section 8. We were notified in November of 2002 that Northern Border
Pipeline and Midwestern Gas Transmission are two 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. The
FERC issued its final

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report on Midwestern Gas Transmission finding it was compliant. We are awaiting
the final report on Northern Border Pipeline, but 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 for interstate
pipelines 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 service are found in the FERC approved
tariffs.

Under its tariff, an interstate pipeline is allowed to charge for its
services on the basis of stated transportation rates. Transportation rates are
established periodically in FERC proceedings known as rate cases. The tariff
also allows the interstate pipeline to 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. For our
interstate pipelines, approximately 98% of the agreed upon cost of service is
attributed to demand charges. The remaining 2% is attributed to commodity
charges based on the volumes of gas actually transported. Under the terms of
settlement in Northern Border Pipeline's 1999 rate case, neither Northern Border
Pipeline nor its existing shippers can seek rate changes until November 1, 2005,
at which time Northern Border Pipeline must file a new rate case. Midwestern Gas
Transmission and Viking Gas Transmission are under no obligation to file new
rate cases. Prior to a future rate case, the interstate pipelines will not be
permitted to increase rates if costs increase, nor will they be required to
reduce rates based on cost savings. As a result, the interstate pipelines'
earnings and cash flow will depend on future costs, contracted capacity, the
volumes of gas transported and their ability to recontract capacity at
acceptable rates.

Until new transportation rates are approved by the FERC, the interstate
pipeline continues to depreciate its transmission plant at FERC approved
depreciation rates. For our pipelines, the annual depreciation rates on
transmission plant in service are 2.25% for Northern Border Pipeline, 1.9% for
Midwestern Gas Transmission and 2.0% for Viking Gas Transmission. In order to
avoid a decline in the transportation rates established in future rate cases as
a result of accumulated depreciation, the interstate pipeline must maintain or
increase its rate base by acquiring or constructing assets that replace or add
to existing pipeline facilities or by adding new facilities.

In Northern Border Pipeline's 1995 rate case, the FERC addressed the
issue of whether the federal income tax allowance included in Northern Border
Pipeline's 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

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attributable to limited partnership interests held by individuals. The
settlement of Northern Border Pipeline's 1995 rate case provided that until at
least December 2005, Northern Border Pipeline could continue to calculate the
allowance for income taxes in the manner it had historically used. In addition,
a settlement adjustment mechanism was implemented, which effectively reduces the
return on rate base. These provisions of the 1995 rate case were maintained in
the settlement of Northern Border Pipeline's 1999 rate case.

Our interstate pipelines 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 its
tariff, Northern Border Pipeline shares net interruptible transportation service
revenue and any new services revenue on an equal basis with its firm shippers
through October 31, 2003. However, Northern Border Pipeline is permitted to
retain revenue from interruptible transportation service to offset any
decontracted firm capacity. Neither Midwestern Gas Transmission nor Viking Gas
Transmission share revenue from interruptible transportation service with firm
shippers.

Our interstate pipelines are subject to the requirements of FERC Order
Nos. 497 and 566, which prohibit preferential treatment 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 and separation of
functions and staffing with our affiliates.

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's proposed policy will
have a material adverse impact on our cash management practices.

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

12

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 tariffs to clarify
provisions, to reflect current industry practices and to reflect recent FERC
rulings. In February 2003, Northern Border Pipeline filed to amend 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. 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 Northern Border Pipeline's filing and require refunds. In
its draft order, the FERC directed Northern Border Pipeline to cease collecting
electric costs through its company use gas provisions and to refund with
interest, within 90 days, all electric costs that had been collected through its
company use gas provisions. Other parties and Northern Border Pipeline will have
thirty days from the date of the order to request rehearing. Northern Border
Pipeline has established a reserve in the amount of $10 million, which we
believe is sufficient to cover the potential refunds.

NATURAL GAS GATHERING AND PROCESSING SEGMENT

Our gas gathering and processing segment provides services for the
gathering, treating, processing and compression of natural gas and the
fractionation of (NGLs) for third parties and related field services. We do not
explore for, or produce, crude oil or natural gas, and do not own crude oil or
natural gas reserves.

Bear Paw Energy, LLC, our wholly-owned subsidiary, has extensive
natural gas gathering, processing and fractionation operations in the Williston
Basin in Montana and North Dakota as well as gas gathering operations in the
Powder River Basin in Wyoming. In the Williston Basin, Bear Paw Energy as over
3,000 miles of gathering pipelines and five processing plants with 90 mmcfd of
capacity. In the Powder River Basin, Bear Paw Energy has approximately 1,100
miles of high and low pressure gathering pipelines, approximately 92 compressor
stations with approximately 130,000 installed horsepower and long-term
volumetric contracts with producers covering approximately 430,000 acres of
dedicated reserves in the Powder River Basin. Bear Paw Energy's revenues are
primarily derived under fee-based gathering agreements.

In addition, through our wholly-owned subsidiary, Crestone Energy
Ventures, L.L.C., we own a 49% interest in Bighorn Gas Gathering, L.L.C., a
33.33% interest in Fort Union Gas Gathering, L.L.C. and a 35% interest in Lost
Creek Gathering, L.L.C., which collectively own over 300 miles of gas gathering
facilities in the Powder River and Wind River Basins in Wyoming.

The Bighorn and Fort Union systems gather coalbed methane gas produced
in the Powder River Basin in northeastern Wyoming. Under various agreements, the
majority of which are long-term, producers have

13

dedicated their gas reserves to Bighorn, giving Bighorn the right to gather
natural gas produced in areas of Wyoming covering approximately 800,000 acres.
Bighorn's system is capable of gathering more than 250 mmcfd of natural gas for
delivery to the Fort Union gathering system. Fort Union has the capability of
delivering more than 634 mmcfd of gas into the interstate pipeline grid. The
Lost Creek system gathers natural gas produced from conventional gas wells in
the Wind River Basin in central Wyoming and consists of 120 miles of gathering
header. The system is capable of delivering more than 275 mmcfd of gas into the
interstate pipeline grid.

CMS Field Services, Inc. holds the remaining ownership interest in
Bighorn and is the project manager and operator. CMS Energy Corporation, the
parent of CMS Field Services, Inc. has announced it intends to sell CMS Field
Services. The Bighorn system is managed through a management committee
consisting of representatives of the owners. CMS Field Services, CIG Resources
Company, Western Gas Resources and Bargath, Inc. hold the remaining interests in
Fort Union. CMS Field Services is the managing member, Western Gas Resources is
the field operator and CIG Resources Company is the administrative manager.
Burlington Resources Trading, Inc. holds the remaining interest in Lost Creek
and is the managing member. A subsidiary of Crestone Energy Ventures is the
commercial and administrative manager. This system is operated by Elkhorn Field
Services Company, an unaffiliated third party.

Bear Paw Energy's facilities are interconnected with the facilities of
Bighorn and Fort Union, and all the gathering facilities interconnect to the
interstate gas pipeline grid serving gas markets in the Rocky Mountains, the
Midwest and California.

Bear Paw Energy's Williston Basin gathering and processing facilities
are located in eastern Montana and western North Dakota, with a small extension
into Saskatchewan, Canada. The Williston Basin system consists of approximately
3,000 miles of polyethylene and steel pipeline and 28 compressor stations with a
total rated horsepower of 28,000, in addition to plant compression of
approximately 19,000 horsepower. Most of the wells connected to the facilities
produce casinghead gas in association with crude oil. This gas is generally high
in NGLs. The NGLs are separated from the gas at our processing plants and then
fractionated into components and sold. The residue gas is sold into the
interstate market. A substantial portion of Bear Paw Energy's gathering and
processing contracts in the Williston Basin provide for the sale of the natural
gas stream to Bear Paw Energy. Upon sale of the NGLs and the residue gas
processed, Bear Paw Energy pays the producers based upon a percentage of the net
proceeds realized.

Our wholly-owned subsidiary, Border Midstream Services, Ltd. owns the
Mazeppa and Gladys gas processing plants, and a minority interest in the Gregg
Lake/Obed Pipeline, all of which are located in Alberta, Canada.

The Mazeppa Plant is a sour gas processing plant with 80 mmcfd of
capacity and 115 miles of associated gathering pipelines. Sour gas processing
involves the removal of high quantities of sulphur from the gas stream. The
Gladys Plant is a sour gas processing plant with 10 mmcfd of capacity. The Gregg
Lake/Obed Pipeline is comprised of 85

14

miles of gathering lines with a capacity of 150 mmcfd. The operations of these
facilities have been outsourced to Thermal Gas Group International Corp. and TGG
Operating Corp., both of which are third parties. The Mazeppa and Gladys plants
are staffed with 27 employees of TGG Operating Corp., of which 21 are
represented by a labor union.

The Gregg Lake/Obed Pipeline is located in west central Alberta and
consists of 85 miles of pipeline with a design capacity of 150 mmcfd. Border
Midstream receives 63% of the cash distributions until such time when it has
been reimbursed its share of the original construction costs of the Gregg Lake
portion of the pipeline, which is expected to occur in 2006. Subsequently,
Border Midstream will receive 36% of the distributions, which is equal to its
ownership interest in the entire Gregg Lake/Obed Pipeline. The pipelines are
operated by a third party, Central Alberta Midstream.

Border Midstream contracts with its customers to process gas at the
Mazeppa and Gladys plants under volumetric contracts with life of reserves
dedication from producers. The largest dedication is from Compton Petroleum
involving over one million acres. The major customers of Border Midstream are
Compton Petroleum, ConocoPhillips, and ExxonMobil. They account for
approximately 70%, 11% and 9% of revenues, respectively.

FUTURE DEMAND AND COMPETITION

Our gas gathering and processing segment competes with other natural
gas gathering, processing and pipeline companies in the production areas in the
Powder River, Wind River, Williston and western Canadian sedimentary Basins.
Primary competitors in the Powder River and Wind River Basins of Wyoming are
affiliates of Western Gas Resources and Thunder Creek Gas Gathering. Competition
for gathering and processing services in the Williston Basin is less
significant, and includes Amerada Hess and PetroHunt Corporation in localized
areas. In the western Canadian sedimentary basin, there are several gas plants
owned by AltaGas, Esso and Canadian 88 in the general vicinity of Border
Midstream's plants. Our competitive positions are affected by the pace of gas
drilling, gas production rates, gas reserves, natural gas and NGLs commodity
prices, regulation and the demand for natural gas and NGLs in North America.

The pace of gas drilling may be impacted by, among other things, the
ability of producers to obtain and maintain the necessary drilling and
production permits in a timely and economic manner, as well as commodity prices.
In addition, the regulation of discharge of the significant volumes of water
produced in association with coalbed methane production can be a deterrent to
producers in determining whether to drill or produce. The time period during
which coalbed methane wells dewater before significant gas production becomes
available may be unpredictable. Water quality may vary substantially, and
disposal alternatives and associated costs affect producers' decisions to drill
or produce. On January 17, 2003, the Bureau of Land Management ("BLM") released
two final environmental impact statements ("EIS") regarding oil and natural gas
development on Federal lands. One EIS pertains to oil and gas development on
BLM-administered public lands and federal mineral leases within the Powder River
Basin in northeastern Wyoming. The other EIS pertains to statewide oil and
natural gas development in Montana. The protest period for these EIS's

15

closed on February 18, 2003. The result of any protests, as well as recommended
mitigation measures, may affect drilling and production activity on
BLM-administered public lands and on federal mineral leases in the Powder River
Basin. Approximately 65% of the Powder River Basin acreage is on federal lands.

In providing gas gathering, processing and other services, we may
require acreage dedication, long term commitment and/or volume commitments from
gas producers. Once a gathering and processing position is established, the term
of the dedication, the likely economic reserve life and the cost of building
duplicative facilities mitigates the competitive effect in the vicinity.
Development of future gas gathering and processing facilities will be staged to
reflect the growth in number of wells and field production, economics,
permitting considerations and other factors impacting producers' decisions to
drill and produce.

We differentiate ourselves by the terms of services offered, our
flexibility and additional value-added services provided. Our relationships with
producers allow us to offer integrated services through all our gathering and
processing facilities, as well. We also provide a variety of delivery choices,
wide coverage area and operational efficiencies. We seek to improve operational
profitability by increasing natural gas throughput through new connections,
expansion, acquisitions, operational efficiencies and prudent deployment of
capital.

COAL SLURRY PIPELINE

Black Mesa Pipeline, Inc., our wholly-owned subsidiary, owns a
273-mile, 18-inch diameter coal slurry pipeline which originates at a coal mine
in Kayenta, Arizona. The coal slurry pipeline transports crushed coal suspended
in water. It traverses westward through northern Arizona to the 1,500 megawatt
Mohave Power Station located in Laughlin, Nevada. The coal slurry pipeline is
the sole source of fuel for the Mohave Power Station, which consumes an average
of 4.8 million tons of coal annually. The capacity of the pipeline is fully
contracted to Peabody Western Coal, the coal supplier for the Mohave Power
Station, through the year 2005. The source of water used is from an aquifer in
The Navajo Nation and Hopi Tribe joint use area. The Navajo Nation and Hopi
Tribe have not agreed to continued use of water after December 31, 2005. If
efforts by the parties to obtain sources of water are not successful and the
Mohave Plant is closed, it would be necessary to shut down Black Mesa in 2006.
Southern California Edison, as one of the owners of the Mohave Plant, has filed
a petition before the California Public Utility Commission ("CPUC") requesting
that the CPUC either recognize the end of Mohave's coal-fired operations as of
the end of 2005 with appropriate ratemaking accounts or authorize expenditures
for pollution control activities required for future operation. This proceeding
is pending.

Approximately 59 people are employed in the operations of Black Mesa,
of which 26 are eligible to be represented by a labor union, the United Mine
Workers of America ("UMWA"). Black Mesa's collective bargaining agreement with
the UMWA was renewed for an additional year in February 2002. The UMWA has
indicated its intent to begin discussion of a new contract for 2003.

16

ENVIRONMENTAL AND SAFETY MATTERS

Our interstate pipeline and U.S. gathering and processing operations
are subject to federal, state and local laws and regulations relating to safety
and the protection of the environment, which include, as applicable, the
Resource Conservation and Recovery Act, the Comprehensive Environmental
Response, the Compensation and Liability Act of 1980, as amended, the 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 our interstate 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 our interstate
pipelines to carry out the prescribed evaluations and implementation of programs
to ensure the safety of our facilities. The Act and subsequent regulations have
prescribed timelines and the implementation may have an impact on the costs that
pipelines incur.

In Canada, our processing plants and gathering facilities are subject
to Canadian, provincial and local laws and regulations relating to safety and
the protection of the environment, which include the following Alberta laws: the
Energy Resources Conservation Act, the Oil and Gas Conservation Act, the
Pipeline Act, and the Environmental Protection and Enhancement Act.

Black Mesa is subject to a judgment and Consent Decree entered in the
United States District Court of Arizona in July 2001. Under the Consent Decree,
the United States Environmental Protection Agency ("EPA"), the Arizona
Department of Environmental Quality ("ADEQ") and Black Mesa agreed to the
payment of penalties for alleged violations of federal and state law due to
unplanned discharges of coal slurry from Black Mesa's pipeline from December
1997 through July 1999. The Consent Decree also sets forth certain preventative
measures, reporting requirements and associated penalties for failure to comply
in the future. Since the Consent Decree was entered, there have been several
unplanned slurry discharges that have been reported to the EPA and ADEQ. In
December 2002, the EPA and ADEQ demanded payment of stipulated penalties
determined pursuant to the Consent Decree in the amount of $176,000. Black Mesa
has paid $47,000 of this amount and after informal discussions with the EPA and
ADEQ, Black Mesa agreed to pay $127,250.

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
and gas processing 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

17

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

Northern Border Pipeline, Midwestern Gas Transmission, Viking Gas
Transmission and Guardian Pipeline hold the right, title and interest in their
pipeline systems. With respect to real property, the pipeline systems fall 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 systems across
certain property was obtained through exercise of the power of eminent domain.
The interstate pipeline systems continue to have the power of eminent domain in
each of the states in which they operate, although Northern Border Pipeline may
not have the power of eminent domain with respect to Native American tribal
lands.

Approximately 90 miles of Northern Border Pipeline's system 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. Northern Border
Pipeline does have the right of eminent domain with respect to allotted lands.

In 1980, Northern Border Pipeline 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 Northern Border Pipeline the right and privilege to construct
and operate its 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, Northern Border Pipeline 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.

Bear Paw Energy, Border Midstream, Bighorn, Lost Creek and Fort Union
hold the right, title and interest in their gathering and processing facilities,
which consist of low and high pressure gas gathering lines, compression and
measurement installations and treating, processing and fractionation facilities.
The real property rights for these facilities are derived through fee ownership,
leases, easements, rights-of-way and permits.

18

Black Mesa holds title to its pipeline and pump stations. The real
property rights for Black Mesa facilities are derived through fee ownership,
leases, easements, rights-of-way and permits. Black Mesa holds rights-of-way
grants from private landowners as well as The Navajo Nation and the Hopi Tribe.
These rights-of-way grants extend for terms at least through December 31, 2005,
the date that Black Mesa's transportation contract with Peabody Western Coal is
presently scheduled to end.

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 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
governmental approvals. We believe that Northern Border Pipeline will obtain
regulatory recovery of the costs resulting from the settlement, which will
result in no material adverse impact to 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 - Environmental and Safety Matters" for the
discussion on the Consent Decree entered against Black Mesa and "Business - Coal
Slurry Pipeline" for the discussion on the proceeding before the California
Public Utility Commission related to Black Mesa's continuation of service beyond
2005.

See Item 1. "Business - Interstate Pipeline Regulation" for the
discussion on the proceedings before 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 financial condition.

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 UNITS AND RELATED SECURITY HOLDER
MATTERS

Our common units are traded on the New York Stock Exchange. The
following table sets forth, for the periods indicated, the high and low sale
prices per common unit, as reported on the New York Stock Exchange Composite
Tape, and the amount of cash distributions per common unit declared for each
quarter:

As of March 19, 2003, there were approximately 1,500 record holders of
common units and approximately 58,700 beneficial owners of the common units,
including common units held in street name. On March 20, 2003, the last reported
sale price of our common units on the New York Stock Exchange was $37.73 per
common unit.

We currently have 43,809,714 common units outstanding, representing a
98% limited partner interest. The common units are the only outstanding limited
partner interests. Thus, our equity consists of general partner interests
representing in the aggregate a 2% interest and common units representing in the
aggregate a 98% limited partner interest.

The general partners are entitled to 2% of all cash distributions, and
the holders of common units are entitled to the remaining 98% of all cash
distributions, except that the general partners are entitled to incentive
distributions if the amount distributed with respect to any quarter exceeds
$0.605 per common unit ($2.42 annualized). Under the incentive distribution
provisions, the general partners are entitled to 15% of amounts distributed in
excess of $0.605 per common unit, 25% of amounts distributed in excess of $0.715
per common unit ($2.86 annualized) and 50% of amounts distributed in excess of
$0.935 per common unit ($3.74 annualized). The amounts that trigger incentive
distributions at various levels are subject to adjustment in certain events, as
described in the Partnership Agreement. On January 22, 2003, we declared a
distribution of $0.80 per unit ($3.20 per unit on an annualized basis), payable
February 14, 2003 to the general partners and unitholders of record at January
31, 2003.

20

EQUITY COMPENSATION PLAN INFORMATION

Effective November 1, 2001, Northern Plains and NBP Services adopted
the Amended and Restated Northern Border Phantom Unit Plan as an incentive to
attract and retain employees who are essential to the services provided to us
and our subsidiaries. The Administrative Committee under the Plan, which are
appointees of Northern Plains and NBP Services, may grant either phantom units
which are based upon the general partner distribution rate or phantom LP units
which are based on the price of our common units. The Administrative Committee
has complete authority to determine the terms and conditions of a grant,
including the identity of the participants, the time of grant, time and
provisions for settlement and duration of a grant. During the duration of a
grant, the participant's account is credited with distributions paid with
respect to the underlying security. Upon settlement of the phantom units and
phantom LP units, the participant will receive common units or cash or a
combination thereof, as determined by the Administrative Committee. The
settlement value of the phantom units is determined by using a value derived
from the general partner distribution rate and common unit distribution yield on
the settlement date. The settlement payment for the phantom LP units is
determined by the closing price of the common units on the settlement date.

(1) Under our partnership agreement, the Partnership Policy Committee has the
sole authority, without the approval of the unitholders, to adopt employee
benefit or incentive plans or issue common units pursuant to any employee
benefit or incentive plan maintained or sponsored by a general partner or its
affiliates.

(2) Based upon the closing price of the common units on December 31, 2002 and
assumes that all outstanding phantom units were settled in common units as of
December 31, 2002.

(3) The Plan limits the number of grants of phantom units and phantom LP units
to an aggregate of 200,000. This assumes all grants are phantom LP units.

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

The following table sets forth, for the periods and at the dates
indicated, selected historical financial data for us. The selected consolidated
financial information should be read in conjunction with the Consolidated
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.

22

(1) "Earnings" means the sum of pre-tax income from continuing operations
(before adjustment for minority interests in consolidated subsidiaries
or income from equity investees), fixed charges, amortization of
capitalized interest and distributions from equity investees, less
capitalized interest and the minority interests in pre-tax income of
subsidiaries that have not incurred 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.

(2) Includes results of operations for Bear Paw Energy (March 2001),
Midwestern Gas Transmission (May 2001) and Border Midstream Services
(April 2001) since dates of acquisition.

(3) Includes results of operations for Crestone Energy Ventures and Crestone
Gathering Services, L.L.C. since date of acquisition in September 2000.
The gathering activities of Crestone Gathering have been integrated with
those of Bear Paw Energy.

23

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 Consolidated 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 Consolidated Financial Statements included elsewhere in this report.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

Certain amounts included in or affecting our Consolidated 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
Consolidated Financial Statements included elsewhere in this report. Certain of
our accounting policies are of more significance in our financial statement
preparation process than others. 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." 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 future recovery of the regulatory assets is
probable by considering such factors as regulatory changes and the impact of
competition. 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, Northern Border Pipeline has reflected regulatory assets of $10.5
million, which are being recovered from its 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 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,"
which we adopted on January 1, 2001. 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

24

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. At December 31, 2002, our
balance sheet included assets from derivative financial instruments of $36.7
million and liabilities from derivative financial instruments of $4.1 million.
Our accounting for goodwill changed effective January 1, 2002, when we adopted
SFAS No. 142, "Goodwill and Other Intangible Assets." The comparative impact of
no longer amortizing goodwill is shown in Note 4, Notes to Consolidated
Financial Statements included elsewhere in this report.

RESULTS OF OPERATIONS

Our operating results for 2002 and 2001 were significantly influenced
by the acquisitions we made in the first half of 2001 and in September 2000.
During 2001, we made the following acquisitions: Bear Paw Energy on March 30;
the Mazeppa and Gladys gas processing plants, gas gathering systems and a
minority interest in the Gregg Lake/Obed Pipeline on April 4, which are included
in the operating results of Border Midstream Services; and Midwestern Gas
Transmission on May 1. In September 2000, we purchased interests in gas
gathering businesses in the Powder and Wind River basins in Wyoming. Our 2002
operating results also benefited from the change in accounting for goodwill.

Our net income was $113.7 million in 2002 ($2.44 per unit), compared to
net income of $87.8 million in 2001 ($2.12 per unit) and $76.7 million in 2000
($2.50 per unit). The increase in net income in 2002 over 2001 resulted from the
acquisitions made in 2001, Northern Border Pipeline's completion of Project
2000, which was a pipeline expansion and extension placed in service in October
2001, a decline in interest rates and the effect of the change in accounting
for goodwill. The increase in net income in 2001 over 2000 resulted from the
acquisitions made in 2001 and 2000 and improved performance by Northern Border
Pipeline. Northern Border Pipeline's operating results benefited from lower
interest rates that reduced its interest expense, lower operations and
maintenance expenses and higher revenues. Although our net income increased
between 2000 and 2001, our net income per unit decreased due to an increase in
our average number of common units outstanding. Additional common units were
issued during 2001 to partially finance our acquisitions and to repay amounts
borrowed on our debt facilities. As a result of adopting SFAS No. 142, we are no
longer amortizing goodwill (see Note 4 - Notes to Consolidated Financial
Statements). Our 2001 operating results included $13.3 million of goodwill
amortization or $0.34 per unit. Goodwill amortization for 2001 by business
segment was as follows: interstate natural gas pipelines - $0.9 million; natural
gas gathering and processing - $12.0 million; and coal slurry - $0.4 million.
Our 2000 operating results included $2.7 million of goodwill amortization or
$0.09 per unit. Goodwill amortization for 2000 by business segment was as
follows: natural gas gathering and processing - $2.3 million; and coal slurry -
$0.4 million.

INTERSTATE NATURAL GAS PIPELINES

Our interstate natural gas pipeline segment reported earnings of $107.5
million in 2002. In 2001, excluding the impact of goodwill

25

amortization, the segment reported earnings of $103.2 million. In 2000, the
segment reported earnings of $89.0 million. The increase in 2002 and 2001
earnings from the prior year resulted from our acquisition of Midwestern Gas
Transmission in 2001 and Northern Border Pipeline's completion of Project 2000.
The 2001 results included eight months and three months of revenues and expenses
for Midwestern Gas Transmission and Project 2000, respectively.

Operating revenues for our interstate natural gas pipeline segment were
$339.4 million in 2002, $322.6 million in 2001 and $311.0 million in 2000. The
increase in operating revenues in 2002 over 2001 resulted from an $8.8 million
increase in Midwestern Gas Transmission's revenues and an $8.0 million increase
in Northern Border Pipeline's revenues. Midwestern Gas Transmission's revenues
in 2002 reflect an increase in contracted capacity as compared to the same
period in 2001. Midwestern Gas Transmission's revenues in 2001 reflected only
eight months of operations. For 2002, Northern Border Pipeline reflected
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 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 $9.5 million of revenues from Midwestern Gas Transmission acquired effective
May 2001 and an increase in revenues for Northern Border Pipeline of $2.1
million. Northern Border Pipeline reflected additional revenues associated with
the completion of Project 2000 in October 2001.

Operations and maintenance expenses for our interstate natural gas
pipeline segment were $48.6 million in 2002, $36.9 million in 2001 and $41.5
million in 2000. The increase in expenses in 2002 over 2001 resulted from an
increase in Northern Border Pipeline's expense by $7.8 million and an increase
in Midwestern Gas Transmission's expense by $3.9 million. Northern Border
Pipeline's expenses in 2002 reflected 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 -
Interstate Natural Gas Pipelines - Interstate Pipeline Regulation"). From 2001
to 2002, Northern Border Pipeline also had an increase in regulatory commission
expense and decreases in employee benefits expenses, administrative expenses and
bad debt expense. The 2001 expense included $1.3 million of bad debt expense
related to ENA. Midwestern Gas Transmission's expense increase for 2002 over
2001 was due to increases in employee benefit expenses and administrative
expenses and 2001 results had included only eight months of activity.

The decrease in operations and maintenance expense in 2001 from 2000
reflects a decrease in Northern Border Pipeline's expense by $7.8 million
partially offset by $3.2 million of expense from Midwestern Gas Transmission.
Northern Border Pipeline's operations and maintenance expense decreased due
primarily to a reduction in regulatory commission expense, decreased employee
payroll, employee benefits expenses and administrative expenses and decreased
costs to operate two of its

26

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, excluding goodwill
amortization, for our interstate natural gas pipeline segment were $61.0 million
in 2002, $58.9 million in 2001 and $57.3 million in 2000. The increase between
2001 and 2002 reflects a $1.2 million increase in Northern Border Pipeline's
expense due to Project 2000 and a $0.9 million increase from Midwestern Gas
Transmission. The increase in depreciation and amortization expenses between
2000 and 2001 is due primarily to Midwestern Gas Transmission.

Taxes other than income for our interstate natural gas pipeline segment
were $29.2 million in 2002, $26.1 million in 2001 and $28.0 million in 2000. The
increase in 2002 from 2001 is primarily due to a $2.8 million increase in
Northern Border Pipeline's expense and a $0.3 million increase in expense for
Midwestern Gas Transmission. Northern Border Pipeline periodically reviews and
adjusts its estimates of ad valorem taxes. Reductions to 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, Northern Border Pipeline filed for a refund of use taxes previously paid
on exempt purchases. Northern Border Pipeline received the refund in March 2002.

Interest expense for our interstate natural gas pipeline segment, which
relates to Northern Border Pipeline's financing activities, 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 average
interest rates as well as a decrease in average debt outstanding. The segment
also recorded $0.9 million of interest expense capitalized in 2001 primarily
related to construction of Project 2000 facilities.

Other income for our interstate natural gas pipeline segment was $1.2
million in 2002, $0.0 million in 2001 and $8.1 million in 2000. The 2002 amount
includes income of approximately $0.6 million for previously vacated microwave
frequency bands and income of $0.2 million due to a reduction in reserves
previously established for Minnesota use taxes. 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 Northern Border
Pipeline's communication system and a $0.7 million charge for reserves
established. Income tax expense for Midwestern Gas Transmission, which is netted
in other income, increased $1.1 million in 2002 over 2001. Northern Border
Pipeline recorded an allowance for equity funds used during construction of $0.9
million in 2001 primarily due to Project 2000. In 2000, Northern Border Pipeline
had recorded approximately $1.7 million of income from the sale of excess
capacity on its communication system. Other income for 2000 also included $5.6
million of income due to a reduction in reserves previously established for
regulatory issues by Northern Border Pipeline as the result of the settlement of
its rate case.

27

Minority interests in net income, which represent the 30% minority
interest in Northern Border Pipeline, were $42.8 million for 2002, $42.1 million
for 2001 and $38.1 million for 2000. The increases in 2002 and 2001 from prior
year results were due to increased net income for Northern Border Pipeline.

NATURAL GAS GATHERING AND PROCESSING

Our natural gas gathering and processing segment reported earnings of
$38.3 million in 2002. Excluding the impact of goodwill amortization, the
segment reported earnings of $32.3 million and $3.7 million in 2001 and 2000,
respectively. The increase in 2002 and 2001 earnings over the prior year
resulted from our acquisitions made in 2001 and 2000. The 2001 results included
nine months of activity for Bear Paw Energy and Border Midstream Services. The
2000 results included three months of activity for the assets acquired in
September 2000.

Operating revenues for our natural gas gathering and processing segment
were $134.7 million in 2002, $116.8 million in 2001 and $7.5 million in 2000.
The increase in operating revenues in 2002 over 2001 was primarily due to the
acquisitions we made in 2001. The 2001 revenues for the segment included only
nine months of activity for Bear Paw Energy and Border Midstream Services.
Revenues for 2001 included $8.3 million recorded from gas gathering and
administrative services under a master services agreement with ENA that was
terminated in 2001. The increase in operating revenues in 2001 over 2000 was
primarily due to the acquisitions made beginning in March 2001 and September
2000.

Product purchases for our natural gas gathering and processing segment
were $50.6 million in 2002 and $39.7 million in 2001. In conjunction with its
gathering and processing activities, Bear Paw Energy purchases the natural gas
stream from producers. The price Bear Paw Energy pays the producers is based
upon a percentage of the revenues it receives upon sale of the natural gas
liquids and residue that it processes in its facilities. The increase in 2002
over 2001 was due to the 2001 results only including nine months of activity for
Bear Paw Energy.

Operations and maintenance expenses for our natural gas gathering and
processing segment were $43.2 million in 2002, $43.2 million in 2001 and $5.1
million in 2000. The nine months of activity for Bear Paw Energy in the 2001
expense included bad debt expense of $7.5 million related to ENA's bankruptcy.
See "Update On The Impact of Enron's Chapter 11 Filing On Our Business" and Item
13. "Certain Relationships and Related Transactions." The increase in expense
between 2000 and 2001 was primarily due to the acquisitions made in 2001 and
2000 and the bad debt expense for ENA.

Depreciation and amortization expenses, excluding goodwill
amortization, for our natural gas gathering and processing segment were $13.3
million in 2002, $8.6 million in 2001 and $0.2 million in 2000. The increase in
2002 and 2001 expense over prior year levels was due primarily to the
acquisitions made in 2001 and 2000.

Other income (expenses) from our natural gas gathering and processing
segment were ($0.4 million) in 2002, $1.2 million in 2001 and $0.0 million in
2000. The decrease in 2002 from 2001 was primarily

28

due to additional income tax expense for Border Midstream Services of $0.8
million. Other income for 2001 included $0.7 million from a gain on sale of gas
processing assets and income from well connects.

Equity earnings from our unconsolidated affiliates, excluding the
impact of goodwill amortization, were $14.6 million in 2002, $8.0 million in
2001 and $1.6 million in 2000. The increase in equity earnings in 2002 over 2001
was primarily due to an increase in gathering volumes and the acquisitions made
in 2001. The 2001 results included nine months of activity for Gregg Lake/Obed
Pipeline. The increase in equity earnings in 2001 over 2000 was primarily due to
the acquisitions made in late September 2000. The 2000 results included three
months of activity.

COAL SLURRY

Our coal slurry pipeline segment reported earnings of $4.1 million in
2002 on revenues of $21.5 million. In 2001, excluding the impact of goodwill
amortization, the segment reported earnings of $4.9 million on revenues of $22.1
million. In 2000, excluding the impact of goodwill amortization, the segment
reported earnings of $3.1 million on revenues of $21.2 million. The 2002 results
were impacted by unplanned coal slurry discharges, which increased the segments
operations and maintenance expense by $1.1 million over 2001. The 2001 results
were impacted by an increase in tons of coal shipped and the repayment of Black
Mesa Pipeline's debt in June 2001. Interest expense was $0.7 million in 2001 and
$1.7 million in 2000.

OTHER

Items not attributable to any segment include certain of our general
and administrative expenses, interest expense on our debt, other income and
expense items and an extraordinary loss on reacquired debt. Our general and
administrative expenses not allocated to any segment were $5.5 million in 2002,
$3.1 million in 2001 and $2.3 million in 2000. The amount of general and
administrative expenses recorded in each year has increased due to the
acquisitions made in 2001 and 2000.

Interest expense on our debt was $30.6 million in 2002, $33.1 million
in 2001 and $14.6 million in 2000. The decrease in expense for 2002 from 2001
was primarily due to a decrease in interest rates partially offset by an
increase in average debt outstanding related to the acquisitions made in 2001.
The increase in expense for 2001 from 2000 was primarily due an increase in
average debt outstanding related to the acquisitions made in 2001 and 2000. In
2000, we issued $250 million of 8 -7/8% Senior Notes and in 2001, we issued $225
million of 7.10% Senior Notes.

Other income (expenses) not allocated to any segment were ($0.1
million) in 2002, ($2.0 million) in 2001 and $0.5 million in 2000. The amount
for 2001 included a non-recurring charge of $2.4 million, primarily related to a
loss on a forward purchase of Canadian dollars to fund our acquisition of Border
Midstream Service's gathering and processing assets. Income from temporary cash
investments decreased $0.4 million in 2002 from 2001.

29

The extraordinary loss from debt restructuring of $1.2 million recorded
in 2001, related to the repayment of Black Mesa's 10.7% Secured Senior Notes.
The total repayment of approximately $13.6 million consisted of remaining
principal and interest of $12.4 million and an early payment premium of $1.2
million.

LIQUIDITY AND CAPITAL RESOURCES

SUMMARY OF CERTAIN CONTRACTUAL OBLIGATIONS AND COMMERCIAL COMMITMENTS

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

(b) See Note 11 - Notes to Consolidated Financial Statements.

We have guaranteed the performance of our unconsolidated affiliates in
connection with their credit agreements that expire in March 2009 and September
2009. Collectively at December 31, 2002, the amount of both guarantees was $4.4
million.

Upon closing of the acquisition of Viking Gas Transmission, we agreed
to guarantee our ownership share (33%) of Guardian Pipeline's indebtedness. The
amount of our guarantee is $60 million. Pursuant to the terms of Guardian
Pipeline's debt agreements, the guarantee is removed upon Guardian Pipeline
meeting certain conditions, which we expect to occur in the second quarter of
2003.

DEBT AND CREDIT FACILITIES AND ISSUANCE OF COMMON UNITS

Northern Border Pipeline and we have entered into revolving credit
facilities, which are used for refinancing existing indebtedness, capital
expenditures, acquisitions and general business purposes. Northern Border
Pipeline entered into a $175 million three-year credit agreement ("2002 Pipeline
Credit Agreement") with certain financial institutions in May 2002. We entered
into a $200 million

30

three-year revolving credit agreement with certain financial institutions ("2001
Partnership Credit Agreement") in March 2001. Both credit agreements replaced
prior credit agreements. At December 31, 2002, $89 million was outstanding under
the 2002 Pipeline Credit Agreement at an average interest rate of 2.05% and $35
million was outstanding under the 2001 Partnership Credit Agreement at an
average interest rate of 2.27%.

The 2002 Pipeline Credit Agreement and 2001 Partnership Credit
Agreement require Northern Border Pipeline and us to maintain ratios of EBITDA
(net income plus minority interests in net income, interest expense, income
taxes and depreciation and amortization) to interest expense of greater than 3
to 1. The credit agreements also require the maintenance of the ratio of
indebtedness to adjusted EBITDA (EBITDA adjusted for pro forma operating results
of acquisitions made during the year) of no more than 4.5 to 1. At December 31,
2002, we were in compliance with these covenants.

At December 31, 2002, Northern Border Pipeline 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. Northern Border Pipeline anticipates borrowing under the 2002
Pipeline Credit Agreement to repay the Series D Senior Notes.

In April 2002, Northern Border Pipeline completed a private offering of
$225 million of 6.25% Senior Notes due 2007 ("2002 Pipeline Senior Notes"). In
September 2001, Northern Border Pipeline completed a private offering of $250
million of 7.50% Senior Notes due 2021 ("2001 Pipeline Senior Notes"). In August
1999, Northern Border Pipeline 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 Northern Border Pipeline may 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.

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. 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 Northern Border Pipeline's
interest rate swap agreements was 2.70%.

In March 2001, we completed a private offering of $225 million of 7.10%
Senior Notes due 2011 ("2001 Partnership Senior Notes"). In June 2000, we
completed a private offering of $150 million of 8 -7/8% Senior Notes due 2010
("2000 Partnership Senior Notes") and in September 2000, we completed an
additional private offering of $100 million of 2000 Partnership Senior Notes.
The 2001 and 2000

31

Partnership Senior Notes were subsequently exchanged in registered offerings for
notes with substantially identical terms. The indentures under which the 2001
and 2000 Partnership Senior Notes were issued do not limit the amount of
unsecured debt we may incur, but they do contain material financial covenants,
including restrictions on incurrence, assumption or guarantee of secured
indebtedness. The indentures also contain provisions that would require us to
offer to repurchase the 2001 and 2000 Partnership Senior Notes, if either
Standard & Poor's Rating Services or Moodys' Investor Services, Inc. rate the
notes below investment grade and the investment grade rating is not reinstated
for a period of 40 days. We used the proceeds from the 2001 and 2000 Partnership
Senior Notes to fund our acquisitions in 2001 and 2000.

In the third quarter of 2001, we entered into interest rate swap
agreements with notional amounts totaling $225 million that expire in March
2011. Under the interest rate swap agreements, we make payments to
counterparties at variable rates based on the London Interbank Offered Rate and
in return receives payments based on a 7.10% fixed rate. The swaps were entered
into to hedge the fluctuations in the market value of the 2001 Partnership
Senior Notes. At December 31, 2002, the average effective interest rate on our
interest rate swap agreements was 3.97%.

In conjunction with the issuance of additional common units, our
general partners are required to make capital contributions to maintain a 2%
general partner interest in accordance with the partnership agreements. In July
2002, we sold 2,186,700 common units. In April and May of 2001, we sold 407,550
and 4,000,000 common units, respectively. In November 2000, we sold 2,156,250
common units. The net proceeds from the sale of common units and the general
partners' capital contributions totaled approximately $75.4 million, $172.2
million and $60.7 million in 2002, 2001 and 2000, respectively, and were
primarily used to repay indebtedness outstanding.

On January 17, 2003, we acquired all of the common stock of Viking Gas
Transmission including a one-third interest in Guardian Pipeline for
approximately $162 million, which included the assumption of $40 million of
debt. We financed the acquisition under the 2001 Partnership Credit Agreement.
Effective with the closing of the Viking Gas Transmission acquisition, we
amended the 2001 Partnership Credit Agreement to increase the ratio of
consolidated funded debt to adjusted consolidated EBITDA from no more than 4.50
to 1 to no more than 4.75 to 1 through June 2003 at which time the ratio will
revert to 4.50.

Short-term liquidity needs will be met by our operating cash flows and
through the 2001 Partnership Credit Agreement and the 2002 Pipeline Credit
Agreement. Long-term capital needs may be met through our ability to issue
long-term indebtedness as well as additional limited partner interests.

CASH FLOWS FROM OPERATING ACTIVITIES

Cash flows provided by operating activities were $243.1 million in
2002, $233.9 million in 2001 and $169.6 million in 2000. The $9.2 million
increase from 2001 to 2002 reflects a $3.7 million increase in distributions
received from our unconsolidated affiliates. During

32

2001, we realized net cash outflows of $4.7 million related to Northern Border
Pipeline's rate case, which included $2.1 million of amounts collected subject
to refund less refunds issued in early 2001 totaling $6.8 million.

The $64.3 million increase in operating cash flows from 2000 to 2001
was primarily due to our gas gathering and processing businesses acquired in
2001 and in September of 2000. Other cash flows from operating activities for
2001 also included $7.1 million of distributions received from our
unconsolidated affiliates as compared to distributions received in 2000 of $0.9
million. Related party payables increased $17.1 million between 2000 and 2001
primarily related to amounts due to Northern Plains and NBP Services
Corporation. As discussed in Item 13. "Certain Relationships and Related
Transactions," Northern Plains and NBP Services Corporation provide us with
administrative and operating services.

CASH FLOWS FROM INVESTING ACTIVITIES

Cash used in investing activities was $54.4 million in 2002 compared to
$482.7 million in 2001 and $258.0 million in 2000. In 2001 and 2000, we spent
higher amounts primarily related to the acquisitions we made in both years and
for Northern Border Pipeline's Project 2000 facilities.

Our capital expenditures were $49.9 million in 2002, which included
$33.7 million for the natural gas gathering and processing segment and $15.7
million for the interstate natural gas pipelines segment. For 2001, our capital
expenditures were $126.4 million, which included $69.1 million for gas gathering
and processing facilities and $57.0 million for interstate natural gas pipeline
facilities. For 2000, our capital expenditures were $19.7 million, which
included $15.5 million for interstate natural gas pipeline facilities and $3.8
million for gas gathering and processing facilities. The 2001 and 2000
expenditures for interstate natural gas pipeline facilities included $49.0
million and $7.4 million, respectively, for Northern Border Pipeline's Project
2000.

Our cash used in acquisitions was $1.6 million in 2002, as compared to
$345.1 million in 2001 and $229.5 million in 2000. In 2001, we acquired
Midwestern Gas Transmission and the assets of Border Midstream Services in April
2001 and Bear Paw Energy in March 2001. The purchase of Bear Paw Energy also
required us to issue 5.7 million common units valued at $183.0 million, for a
total purchase price of $381.7 million. In 2000, we acquired gas gathering
businesses in the Powder River and Wind River basins in Wyoming.

Our investments in unconsolidated affiliates of $3.0 million in 2002
and $11.2 million in 2001 primarily reflect capital contributions to Bighorn.
Our investment in 2000 of $8.8 million reflects capital contributions of $11.8
million to Bighorn, net of a $3.5 million payment received from ENA. As part of
the terms of the purchase agreement when we acquired gas gathering businesses in
2000, ENA agreed to fund an equity investment in Lost Creek.

As discussed previously, we acquired Viking Gas Transmission in January
2003 for approximately $162 million, which

33

included the assumption of $40 million of debt. Total capital expenditures for
2003 are estimated to be $51 million. Capital expenditures for the interstate
pipelines are estimated to be $17 million, including approximately $11 million
for Northern Border Pipeline. Northern Border Pipeline currently anticipates
funding its 2003 capital expenditures primarily by borrowing on debt facilities
and using operating cash flows. Capital expenditures for gas gathering and
processing facilities are estimated to be $32 million for 2003. Funds required
to meet the capital requirements for 2003 are anticipated to be provided from
our debt borrowings, issuance of additional limited partnership interests and
operating cash flows.

CASH FLOWS FROM FINANCING ACTIVITIES

Cash flows used in financing activities were $170.8 million for 2002,
as compared to cash provided by financing activities of $230.1 for 2001 and
$100.8 million for 2000. Our cash distributions to our unitholders and our
general partners in 2002, 2001 and 2000 were $147.0 million, $120.9 million and
$80.4 million, respectively. The increase in 2002 and 2001 over prior year
results is due to both an increase in the number of common units outstanding and
an increase in the distribution rate. The distribution paid in each quarter of
2002 was $0.80 per unit as compared to $0.70 per unit paid in the first quarter
of 2001 and $0.7625 per unit paid in the second quarter, third quarter and
fourth quarter of 2001. For 2000, the distribution paid was $0.65 per unit in
the first, second and third quarter and $0.70 per unit in the fourth quarter.

In 2002, 2001 and 2000, we issued additional partnership interests of
$75.4 million, $172.2 million and $60.7 million, respectively, which were
primarily used to repay indebtedness outstanding.

For 2002, our borrowings on long-term debt totaled $499.9 million,
which were primarily used to repay previously existing indebtedness. Issuances
of long-term debt included net proceeds from the private offering of the 2002
Pipeline Senior Notes of approximately $223.5 million; borrowings under the 2001
Partnership Credit Agreement of $68.0 million; and borrowings under Northern
Border Pipeline's credit agreements of $207.0 million. Total repayments of debt
in 2002 were $567.5 million.

For 2001, our borrowings on long-term debt totaled $863.1 million,
which were used for both repayments of previously existing indebtedness and to
finance a portion of our acquisitions in March and April of 2001. Issuances of
long-term debt included net proceeds from the private offering of the 2001
Partnership Senior Notes of approximately $223.2 million; borrowings under the
2001 Partnership Credit Agreement of $232.0 million; net proceeds from the
issuance of the 2001 Pipeline Senior Notes of approximately $247.2 million; and
borrowings under Northern Border Pipeline's prior credit agreement of $136.0
million. The proceeds from the 2001 Partnership Senior Notes and the 2001
Partnership Credit Agreement were primarily used to fund the acquisitions of
Bear Paw Energy, Canadian midstream assets and Midwestern Gas Transmission
discussed previously and to repay indebtedness outstanding. Total repayments of
debt were $604.9 million in 2001.

34

For 2000, our borrowings on long-term debt were $431.1 million, which
were used for both repayments of previously existing indebtedness and to finance
a portion of our acquisitions. Issuances of long-term debt included net proceeds
from the private offering of the 2000 Partnership Senior Notes of approximately
$252.0 million; borrowings under the Partnership's credit agreements of $102.5
million; and borrowings under Northern Border Pipeline's credit agreements of
$75.0 million. Total repayments of debt were $304.8 million in 2000.

For the year ended December 31, 2001, Northern Border Pipeline
recognized a decrease in bank overdraft of $22.4 million. At December 31, 2000,
Northern Border Pipeline reflected the bank overdraft primarily due to rate
refund checks outstanding.

In April 2002, Northern Border Pipeline received $2.4 million from the
termination of forward starting interest rate swap agreements. In March 2001, we
paid approximately $4.3 million to terminate forward starting interest rate swap
agreements and in September 2001, Northern Border Pipeline paid approximately
$4.1 million to terminate interest rate swap agreements. The interest rate swaps
had been entered into to hedge the fluctuations in Treasury rates and spreads
between the execution date of the swaps and the issuance of fixed rate debt by
Northern Border Pipeline and us (see Note 8 - Notes to Consolidated Financial
Statements). In December 2000, we received $15.0 million from the termination of
interest rate swap agreements entered into in June 2000. Also in 2002, we agreed
to an increase in the variable interest rate on two of our interest rate swap
agreements. As consideration for the change to the variable interest rate, we
received approximately $18.2 million, which represented the fair value of the
financial instruments at the date of the adjustment. We used the proceeds to
repay amounts borrowed under the 2001 Partnership Credit Agreement.

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 13 - Notes to Consolidated Financial Statements.

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 our general partners. 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 filing for Chapter 11
protection.

35

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 and Pan
Border, which decisions may affect us.

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. NBP Services Corporation, a
wholly owned subsidiary of Enron that is not in bankruptcy, and Northern Plains
provided and continue to provide operating and administrative services for us
and our subsidiaries. Northern Plains and NBP Services have continued to meet
their operational and administrative service obligations under the existing
agreements, and we believe they will continue to do so.

ENA, a wholly owned subsidiary of Enron that is in bankruptcy, was a
party to transportation contracts obligating ENA to pay for 3.5% of Northern
Border Pipeline's capacity. Through the proceeding, ENA rejected and terminated
all of its contracts on Northern Border Pipeline. Northern Border Pipeline
contracted a portion of that capacity with others for varying terms. For 2002,
Northern Border Pipeline experienced lost revenues of approximately $1.8 million
for ENA's capacity. Northern Border Pipeline has claims against ENA for damages
for breach of contract and other claims.

In addition, Bear Paw Energy has claims against ENA relating to
terminated hedge transactions. In accordance with SFAS No. 133, Bear Paw Energy
ceased to account for these swap agreements as hedges. Bear Paw Energy had
previously recorded approximately $6.7 million in accumulated other
comprehensive income related to these agreements, which is being recorded into
earnings in the same periods of the originally forecasted hedges. In 2002, Bear
Paw Energy recorded approximately $4.6 million in earnings related to the
terminated hedges.

Also, Crestone Energy Ventures has claims against ENA for unpaid gas
gathering and administrative services fees.

We have 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

36

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.

Northern Plains and NBP Services have advised us that under the
Operating Agreements with Northern Plains and the Administrative Services
Agreement with NBP Services, 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 appropriate agreement will be made at the time of
occurrence, we estimate an increase of $6 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 management
has advised 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, Pan Border and NBP Services. 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, Pan Border and NBP Services. 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.

37

Enron's filing for bankruptcy protection and related developments have
had other impacts on our business and management. Arthur Andersen LLP resigned
in early 2002 as our auditors, 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 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, Pan Border and NBP Services 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 three member policy committee, with one member
appointed by each general partner. The vote of each member of the policy
committee is weighted by the general partner percentage of the general partner
appointing such member. The general partner percentages for Northern Plains, Pan
Border and Northwest Border are 50%, 32.5% and 17.5%, 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 policy committee, and control the
activities of the Partnership. If Northern Plains and Pan Border were to file
for bankruptcy relief, our Partnership Agreement provides that they would
automatically be deemed to have withdrawn as general partners of the
Partnership. 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 has 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 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. The 2001 Partnership Credit Agreement provides
that it will be a change of control (and consequently an event of default)
thereunder if subsidiaries of Enron and The Williams Companies do not control,
free of any liens, greater than 50% of general partner percentages. The Williams
Companies sold the stock of Northwest Border Pipeline Company to TransCanada.
Consequently, if Enron sells the stock of Northern Plains and Pan Border or
causes such companies to file for bankruptcy relief, the Partnership will be in
default under the 2001 Partnership Credit Agreement. In addition, the agreements
evidencing the Partnership's other material outstanding debt

38

obligations provide that an uncured default under one material debt agreement
will result in a default under other debt agreements.

Northern Plains also serves as operator of Northern Border Pipeline. If
Northern Plains were to file for bankruptcy relief, it could potentially be
removed 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.

The Administrative Services Agreement between NBP Services and us
provides that it will terminate at such time as Northern Plains is no longer a
general partner of the Partnership. Consequently, since our Partnership
Agreement provides that a general partner is automatically withdrawn as general
partner upon filing of bankruptcy, if Northern Plains were to file for
bankruptcy relief, the Administrative Services Agreement would be terminated.

Our Partnership Agreement requires that each general partner make
additional capital contributions to us when we sell common units. Enron may
determine that it is not in the best interest of its creditors and other
constituencies in bankruptcy to make these capital contributions to Northern
Plains and Pan Border. Enron could therefore decide not to allow us to pursue
acquisitions financed with the issuance of additional common units. Even if
Enron were to permit the general partners to make a capital contribution to us,
if the general partners were to subsequently file for bankruptcy relief, the
capital contribution might be subject to challenge as voidable under applicable
law.

Other than the items set forth above, we are not 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 are focused on growing our businesses, our income and cash flow and
our distributions to unitholders. Our strategy involves three main components.

INTERSTATE NATURAL GAS PIPELINES

First, we will continue to focus on safe, efficient, and reliable
operations and the further development of our regulated pipelines. 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. Any growth
in our interstate pipelines would occur through incremental projects intended to
access new markets or supply areas and would be 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 Northern Border Pipeline. In addition, Midwestern Gas Transmission's
recently completed Joliet Compression Project provides the opportunity

39

to deliver gas directly into Northern Border Pipeline, increasing natural gas
market liquidity between the pipeline systems and enhancing transportation
demand for both pipelines. Furthermore, Midwestern Gas Transmission will pursue
serving additional power plants under development in southwest Indiana and new
delivery interconnects with other interstate pipelines to grow transportation
revenues. We also intend to continue to expand the marketing of new services to
meet our customers' needs.

Northern Border Pipeline and Midwestern Gas Transmission have begun
contract extension discussions with customers for contracts that will expire
prior to November 1, 2003. Similar to other industries, the value of capacity on
interstate pipelines is driven by supply and demand conditions. In particular,
with respect to Northern Border Pipeline, 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 Northern Border Pipeline's FERC tariff, it 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, Northern Border Pipeline 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. Northern Border
Pipeline is now in a position to contract with interested parties on a first
come, first served basis. Based on current conditions, contracts for service on
Northern Border Pipeline may require discounts from maximum transportation rates
established in its tariff and shorter duration than its existing contract
portfolio. Additionally, Northern Border Pipeline may enter into negotiated rate
contracts involving charges established on the basis of Canadian-midwestern U.S.
gas price differentials or other factors. Regarding Midwestern Gas Transmission,
an agreement has been reached with its largest shipper, Northern Illinois Gas
Company, to extend its negotiated rate contract for a three year term subject
to regulatory approval and upstream capacity arrangements.

In February 2003, Northern Border Pipeline 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, 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, resulting in cost savings of approximately $8 million annually.
Pending the final outcome of this FERC proceeding, we may not realize electric
power cost savings to the same extent for 2003.

NATURAL GAS GATHERING AND PROCESSING

We also are developing our gas gathering and processing segment where
we are building on our established business relationships with producers and
marketers in the Canadian and Rocky Mountain supply

40

basins. During 2002, the pricing of gas produced from the Powder River Basin
was depressed due to capacity constraints on pipelines to market hubs. We expect
to see continued build-out of our gathering systems within the areas of acreage
dedications we have secured, particularly in the Powder River Basin. Depending
on the pace of production development, producer response to the basin-wide EIS
and water-discharge permitting, we expect 10 to 15 percent growth in aggregate
gathered volumes on our Powder River systems (Bear Paw Energy, Bighorn and Fort
Union) during 2003. We expect growth in gas volumes for our pipelines and plants
in the Wind River, Williston and western Canadian sedimentary basins to be more
modest, reflecting prospects for drilling activity within these production
areas. In addition, we are pursuing new acreage dedications in each of these
areas. The build-out of our existing, and the addition of new acreage
dedications should mitigate production declines and allow some further
improvement in cost efficiencies. Also, our ownership in Bighorn includes
preferred A units, which effectively provide an incentive mechanism tied to the
number of wells connected to the system. Whether such targets have been met is
under discussion. Resolution of this matter, as expected, would result in income
between $4 and $7 million for 2003.

ACQUISITIONS

Finally, our objective is to continue to acquire complementary
businesses. Our goal is approximately $200 to $250 million of capital
expenditures annually in growth through acquisitions and internal development.
We target businesses that leverage our core competencies of energy
transportation, are conservative in terms of commodity price risk, are located
in the U.S. and Canada, and provide immediate earnings and cash flow
contribution. We anticipate financing our capital expenditures and acquisitions
conservatively through an appropriate mix of additional borrowings and equity
issuances. Although we regularly evaluate various acquisition opportunities, we
cannot provide assurance that we will reach our goal each year and would also
expect that, depending on specific opportunities that develop, acquisitions in
some years could significantly exceed our goal stated above.

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";

41

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 customer'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, Northern Border Pipeline's operator,
and NBP Services, administrator for us, are wholly-owned
subsidiaries of Enron and depend on Enron and certain of its
affiliates for some services they provide to us, potential
further developments in the Enron Chapter 11 proceeding may
cause either or both Northern Plains and NBP Services to be
unable to perform under their agreements 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, Pan Border and NBP Services. See
"Update on The Impact Of Enron's Chapter 11 Filing On Our
Business - Possible Effects" above.

o Contracts on Northern Border Pipeline and Midwestern Gas
Transmission will expire prior to November 1, 2003. On
Northern Border Pipeline, those contracts represent
approximately 42% of its system capacity. The interstate
pipelines' 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"

42

above and Item 1. "Business - Interstate Pipelines - Demand
For Transportation Capacity."

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

o Conflicts of interest may arise between our general partners
and their affiliates on one hand, and us on the other hand. As
a result of these conflicts, the general partners may favor
their own interests and the interests of their affiliates over
the interests of our limited partners.

o We face competition from third parties in our natural gas
transportation, gathering and processing businesses. See Item
1. "Business - Interstate Pipeline Competition" and "Business
- Interstate Pipelines-Future Demand and Competition."

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 Northern Border Pipeline's ability to operate its pipeline on
certain tribal lands will depend on Northern Border Pipeline's
success in renegotiating before 2011 its right-of-way rights
on tribal lands within the Fort Peck Reservation. See Item 2.
"Properties." Northern Border Pipeline 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 Northern Border Pipeline
is unable to recover the costs of the proposed settlement in
its future rates, it could have a material adverse impact on
our results of operation.

o Black Mesa's contract to transport coal slurry terminates in
December 2005. If Black Mesa is unable to extend or enter into
a new arrangement for transportation of coal slurry, Black
Mesa could incur significant costs and expenses for employee
related matters, write off of recorded goodwill and removal of
certain facilities.

o Part of our business strategy is to expand existing assets and
acquire additional assets and businesses that will allow us to
increase our cash flow and distributions to unitholders.

43

Unexpected costs or challenges may arise whenever we acquire
new assets or businesses. Successful acquisitions require
management and other personnel to devote significant amounts
of time to new businesses or integrating the acquired assets
with existing businesses.

o Our ability to expand our midstream gas gathering business
will depend in large part on the pace of drilling and
production activity in the western Canadian sedimentary,
Powder River, Wind River and Williston Basins. Drilling and
production activity will be impacted by a number of factors
beyond our control, including demand for and prices of natural
gas, producer response to the recently issued EIS, the ability
of producers to obtain necessary permits and capacity
constraints on natural gas transmission pipelines that
transport gas from the producing areas. See Item 1. "Business
- Natural Gas Gathering and Processing Segment - Future Demand
and Competition."

o Although our business strategy is to pursue fee-based and
fixed-rate contracts, some of our gas processing facilities
are subject to certain contracts that give us quantities of
natural gas liquids as payment of our processing services. The
income and cash flow from these contracts will be impacted
directly by changes in these commodity prices. See Item 7A.
"Quantitative and Qualitative Disclosures About Market Risk"
below.

o We may need new capital to finance future acquisitions and
expansions. If our access to capital is limited, this will
impair our ability to execute our growth strategy. Enron's
circumstances have caused the credit rating agencies to review
the capital structure and earnings power of energy companies,
including us. As we acquire new businesses and make additional
investments in existing businesses, we may need to increase
borrowings and issue additional equity in order to maintain an
appropriate capital structure. This may impact the market
value of our common units. See "Debt and Credit Facilities and
Issuance of Common Units" above.

o Our indentures contain provisions that would require us to
offer to repurchase our Senior Notes if Moodys or Standard &
Poor's Rating Services rate our notes below investment grade.
See "Debt and Credit Facilities and Issuance of Common Units"
above.

o Under current law, we are treated as a partnership for federal
income tax purposes and do not pay any income tax at the
entity level. In order to qualify for this treatment, we must
derive more than 90% of our annual gross income from specified
investments and activities. While we believe that we currently
do qualify and intend to meet this income requirement, if we
should fail we would be treated as if we were a newly formed
corporation and the income we generate from the date of such
failure would be subject to corporate income tax. Because the
tax would be imposed on us, the cash available for
distribution to our unitholders would be

44

substantially reduced. In addition, the entire amount of cash
received by each unitholder would generally be taxed as a
corporate dividend when received.

o On January 7, 2003, the Bush Administration released a
proposal that would exclude certain corporate dividends from
an individual's federal taxable income. Enactment of
legislation reducing or eliminating the federal income tax on
corporate dividends may cause certain investments to be more
attractive to individual investors than an investment in our
units. We cannot predict whether the proposal will ultimately
be enacted into law or if enacted, the potential impact on the
market for our units.

Additional risks and uncertainties not currently known to us, or risks
that we currently deem immaterial may impair our business operations. Any of the
risk factors described above could significantly and adversely impair our
operational results.

ITEM 7a. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We may be exposed to market risk through changes in commodity prices,
exchange rates and interest rates as discussed below. A control environment has
been established which includes policies and procedures for risk assessment and
the approval, reporting and monitoring of financial instrument activities.

We have utilized and expect to continue to utilize financial
instruments in the management of interest rate risks and our natural gas and
natural gas liquids marketing activities to achieve a more predictable cash flow
by reducing our exposure to interest rate and price fluctuations. Other than
entering into a forward purchase of Canadian dollars in 2001 to fund our
acquisition of the Canadian midstream assets, we have not used financial
instruments in the management of exchange rates.

INTEREST RATE 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 consolidated 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 to variable rate debt to take
advantage of declining interest rates. At December 31, 2002, we had $574.0
million of variable rate debt outstanding, $450.0 million of which was
previously fixed rate 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 7 and Note 8 to our
Consolidated Financial Statements, included elsewhere in this report. As of
December 31, 2002, approximately 57% 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, consolidated annual interest expense would
change by approximately $5.7 million. This amount has been determined by
considering the impact of the hypothetical interest rates on our variable rate
borrowings outstanding as of December 31, 2002.

45

COMMODITY PRICE RISK

Our gas gathering and processing businesses are subject to certain
contracts that give them quantities of natural gas and natural gas liquids as
partial consideration for processing services. The income and cash flows from
these contracts will be impacted by changes in prices for these commodities.
Prior to considering the effects of any hedging, for each $0.10 per million
British thermal unit change in natural gas prices or for each $0.01 per gallon
change in natural gas liquid prices, our annual net income would change by
approximately $0.3 million. This amount has been determined by considering the
impact of the hypothetical commodity prices on our projected gathering and
processing volumes for 2003. We have hedged 70% to 75% of our commodity price
risk in 2003.

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.

46

PART III

ITEM 10. PARTNERSHIP MANAGEMENT

We are managed under the direction of the Partnership Policy Committee
consisting of three members, each of which has been appointed by one of our
general partners. The members appointed by Northern Plains, Pan Border and
Northwest Border have 50%, 32.5% and 17.5%, respectively, of the voting power.
We also have an audit committee comprised of individuals who are neither
officers nor employees of any general partner or any affiliate of a general
partner, to serve as a committee of the Partnership (the "Audit Committee"). The
Audit Committee has authority and responsibility for selecting our independent
auditors, reviewing our annual audit and resolving accounting policy questions.
The Audit Committee also has the authority to review, at the request of a
general partner, specific matters as to which a general partner believes there
may be a conflict of interest in order to determine if the resolution of such
conflict proposed by the Partnership Policy Committee is fair and reasonable to
us.

As is commonly the case with publicly-traded partnerships, we do not
directly employ any of the persons responsible for managing or operating the
Partnership or for providing it with services relating to its day-to-day
business affairs. We have entered into an Administrative Services Agreement with
NBP Services Corporation, a wholly-owned subsidiary of Enron that has not filed
for bankruptcy protection, pursuant to which NBP Services provides tax,
accounting, legal, cash management, investor relations, operating and other
services for the Partnership. NBP Services has approximately 135 employees. It
also uses employees of Enron or its affiliates who have duties and
responsibilities other than those relating to the Administrative Services
Agreement. In consideration for its services under the Administrative Services
Agreement, NBP Services is reimbursed for its direct and indirect costs and
expenses, including an allocated portion of employee time and Enron's overhead
costs. See Item 13. "Certain Relationships and Related Transactions."

Set forth below is certain information concerning the members of the
Partnership Policy Committee, our representatives on the Northern Border
Management Committee and the persons designated by the Partnership Policy
Committee as our executive officers and as Audit Committee members. All members
of the Partnership Policy Committee and our representatives on the Northern
Border Management Committee serve at the discretion of the general partner that
appointed them. The persons designated as executive officers serve in that
capacity at the discretion of the Partnership Policy Committee. The members of
the Partnership Policy Committee receive no management fee or other remuneration
for serving on this committee. The Audit Committee members are elected, and may
be removed, by the Partnership Policy Committee. The Chairman of the Audit
Committee receives an annual fee of $50,000 and other Audit Committee members
receive an annual fee of $40,000 and each is paid $1,500 for each meeting
attended. As a result of the purchase by TransCanada of the general partner
interest held by Williams, effective August 2002, Paul MacGregor was designated
by TransCanada as its member on the Partnership Policy Committee and one of our
representatives on the Northern Border Management Committee, replacing James C.
Moore. There are no family relationships between any of our executive officers
or members of the Partnership Policy and Audit Committees.

47

William R. Cordes was named Chief Executive Officer of the Partnership
and Chairman of the Partnership Policy Committee in October 2000. Mr. Cordes is
the President of Northern Plains, an Enron subsidiary, having been appointed to
that position on October 1, 2000, and is a director of Northern Plains. Mr.
Cordes was named Chairman of the Northern Border Management Committee October 1,
2000. In 1970, he started his career with 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 President of
Transwestern Pipeline, a subsidiary of Enron.

Stanley C. Horton was appointed to the Partnership Policy Committee and
to the Northern Border 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)

48

Enron Wind Energy Systems Corp.(n/k/a Enron Wind Energy Systems, LLC)
(Chairman, Director until April 19, 2002)

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)

In August 2002, TransCanada designated Paul MacGregor as its member on
the Partnership Policy Committee. Mr. MacGregor is also TC PipeLines' alternate
representative on the Northern Border 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.

Jerry L. Peters was named Chief Financial and Accounting Officer in
July 1994. Mr. Peters has held several management positions with Northern Plains
since 1985 and was elected Vice President of Finance in July 1994, director in
August 1994 and Treasurer in October 1998. Mr. Peters was also Vice President,
Finance of: Florida Gas Transmission Company from February 2001 to May 2002;
Transportation Trading Services Company from September 2001 to July 2002; Citrus
Corp. from October 2001 to July 2002; and Transwestern Pipeline Company from
November 2001 to May 2002. Prior to joining Northern Plains in 1985, Mr. Peters
was employed as a Certified Public Accountant by KPMG LLP.

Daniel P. Whitty was appointed to the Audit Committee in December 1993.
Mr. Whitty is an independent financial consultant. He has served as a member of
the Board of Directors of Methodist Retirement Communities Inc., and a Trustee
of the Methodist Retirement Trust. Mr. Whitty was a partner at Arthur Andersen
LLP ("Andersen") until his retirement on January 31, 1988. At Andersen, he had
firm wide responsibility for the natural gas transmission industry for many
years. Until his resignation in December 2001, Mr. Whitty served as a director
of EOTT Energy Corp., a subsidiary of Enron and the general partner of EOTT
Energy Partners, L.P.

Gerald B. Smith was appointed to the Audit Committee in April 1994. He
is Chairman and Chief Executive Officer and co-founder of Smith, Graham &
Company Investment Advisors, a global investment management firm, which was
founded in 1990. He has served as a director of Pennzoil-Quaker States since
December 1998 and is a member of the Audit Committee and Executive Committee of
its board. He is a director of: Charles Schwab Family of Funds, Cooper
Industries, and Rorento N.V. (Netherlands). From 1988 to 1990, he served as
Senior Vice President and Director of Fixed Income and Chairman of the Executive
Committee of Underwood Neuhaus & Co.

Gary N. Petersen was appointed to the Audit Committee on March 19,
2002. Since 1998, he has provided consulting services related to strategic and
financial planning. Additionally, he is currently the President of

49

Endres Processing LLC. From 1977 to 1998, Mr. Petersen was employed by Reliant
Energy-Minnegasco. He served as Reliant Energy-Minnegasco's President and Chief
Operating Officer from 1991 to 1998. Prior to his employment at Minnegasco, he
was a senior auditor with Andersen. He currently serves on the boards of the
YMCA of Metropolitan Minneapolis and the Dunwoody Institute.

SECTION 16(a) BENEFICIAL OWNERSHIP REPORTING COMPLIANCE

Section 16(a) of the Securities Exchange Act of 1934 requires executive
officers, members of the Partnership Policy Committee and persons who own more
than ten percent of a registered class of the equity securities issued by us to
file reports of ownership and changes in ownership with the SEC and the New York
Stock Exchange and to furnish the Partnership with copies of all Section 16(a)
forms they file. Based solely on our review of the copies of such reports
received by us, or written representations from certain reporting persons that
no Form 5's were required for those persons, we believe that during 2002 our
reporting persons complied with all applicable filing requirements in a timely
manner.

50

ITEM 11. EXECUTIVE COMPENSATION

The following table summarizes certain information regarding
compensation paid or accrued during each of Northern Plains' last three fiscal
years to the executive officers of the Partnership (the "Named Officers") for
services performed in their capacities as executive officers of 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, an additional 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 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. Its
performance over the 1997-2000 performance period rendered a value of
$2.00 based on a ranking of first.

51

(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 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.

52

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' and NBP Services' Severance Pay Plans provide 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.

53

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

The following table sets forth the beneficial ownership of the voting
securities of the Partnership as of March 3, 2003 by our executive officers,
members of the Partnership Policy Committee and the Audit Committee who own
units and by certain beneficial owners. Other than as set forth below, no person
is known by the general partners to own beneficially more than 5% of the voting
securities.

- --------------
* Less than 1%.

1/ All units involve sole voting and investment power.

2/ Indirect ownership through its subsidiaries. Northern Plains is the
beneficial owner of 500,042 Common Units. Sundance Assets, L.P. is the
beneficial owner of 2,710,000. In a Schedule 13D/A filing in January 2002, it
was disclosed that dispositive power of Sundance Assets, L.P. is shared by Enron
and Citibank, N.A.

For information on equity compensation plans of the Partnership, see
Item 5. "Market for Registrant's Common Units and Related Securities Holder
Matters."

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

On December 2, 2001, Enron and certain of its subsidiaries filed
voluntary petitions for Chapter 11 reorganization under the Bankruptcy Code. We
have a number of relationships with Enron and its subsidiaries. Through

54

Enron's ownership of two of our general partners, Enron is able to elect members
with a majority of the voting power on the Partnership Policy Committee and
Northern Border Pipeline Management Committee. Such other relationships include
the following:

o Northern Plains, a subsidiary of Enron, which has not filed
for bankruptcy protection, provides certain administrative,
operating and management services to the Partnership. For the
year ended December 31, 2002, the aggregate amount charged by
Northern Plains for its services was approximately $29.1
million.

o NBP Services, a subsidiary of Enron that is not in bankruptcy,
provides the Partnership services in connection with the
operation and management of the Partnership and operating
services for Crestone Energy Ventures and Bear Paw Energy
pursuant to the terms of an Administrative Services Agreement
between the Partnership and NBP Services. For the year ended
December 31, 2002, the aggregate amount charged by NBP
Services for its services was approximately $16.2 million.

o ENA holds a contract for firm transportation on Midwestern Gas
Transmission. At present, ENA has not assumed or rejected the
contracts on Midwestern Gas Transmission. ENA's ability to
utilize its capacity has been suspended until ENA provides
adequate assurances of credit support and payment. Midwestern
Gas Transmission's ability to terminate ENA's contract is
stayed as a result of the bankruptcy court proceedings.

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."

The Partnership Policy Committee, whose members are designated by our
three general partners, establishes the business policies of the Partnership. We
have three representatives on the Northern Border Management Committee, each of
whom votes a portion of our 70% interest on the Northern Border Management
Committee, with the other 30% interest being voted by a representative of TC
PipeLines, which is an affiliate of one of our general partners.

Our general partners (subsidiaries of Enron and a subsidiary of
TransCanada) and their respective affiliates, currently actively engage or may
engage in the businesses in which we engage or in which we may engage in the
future. As a result, conflicts of interest may arise between our general
partners and their affiliates on the one hand, and the Partnership on the other
hand. In such case the members of the Partnership Policy Committee will
generally have a fiduciary duty to resolve such conflicts in a manner that is in
our best interest.

Enron (the parent of two of our general partners) and its affiliates
and TC PipeLines (a 30% owner of Northern Border Pipeline Company whose general
partner is an affiliate of one of our general partners) and its affiliates also
actively engage in interstate pipeline transportation of

55

natural gas in the United States separate from their interests in Northern
Border Pipeline. As a result, conflicts also may arise between Enron and its
affiliates, TransCanada and its affiliates or TC PipeLines and its affiliates,
on the one hand, and the Northern Border Pipeline Company on the other hand. If
such conflicts arise, the representatives on the Northern Border Pipeline
Management Committee will generally have a fiduciary duty to resolve such
conflicts in a manner that is in the best interest of Northern Border Pipeline.

Unless otherwise provided for in a partnership agreement, the laws of
Delaware and 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. Similar rules apply to persons
serving on the Partnership Policy Committee or the Northern Border Management
Committee. Because of the competing interests identified above, our Partnership
Agreement and the partnership agreement for Northern Border Pipeline contain
provisions that modify certain of these fiduciary duties. For example:

o Our Partnership Agreement states that our general partners,
their affiliates and their officers and directors will not be
liable for damages to us, our limited partners or their
assignees for errors of judgment or for any acts or omissions
if the general partners and such other persons acted in good
faith.

o Our Partnership Agreement allows our general partners and our
Partnership Policy Committee to take into account the
interests of parties in addition to our interest in resolving
conflicts of interest.

o Our Partnership Agreement provides that the general partners
will not be in breach of their obligations under our
Partnership Agreement or their duties to us or our unitholders
if the resolution of a conflict is fair and reasonable to us.
The latitude given in our Partnership Agreement in connection
with resolving conflicts of interest may significantly limit
the ability of a unitholder to challenge what might otherwise
be a breach of fiduciary duty.

o Our Partnership Agreement provides that a purchaser of Common
Units is deemed to have consented to certain conflicts of
interest and actions of the general partners and their
affiliates that might otherwise be prohibited and to have
agreed that such conflicts of interest and actions do not
constitute a breach by the general partners of any duty stated
or implied by law or equity.

o Our Audit Committee will, at the request of a general partner
or a member of the Partnership Policy Committee, review
conflicts of interest that may arise between a general partner
and its affiliates (or the member of the Partnership Policy
Committee designated by it), on the one hand, and the
unitholders or us, on the other. Any resolution of a conflict
approved by the Audit Committee is conclusively deemed fair
and reasonable to us.

o We entered into an amendment to the partnership agreement of
Northern Border Pipeline that relieves us and TC PipeLines,
their affiliates and their transferees from any

56

duty to offer business opportunities to Northern Border
Pipeline, subject to specified exceptions.

We are required to indemnify the members of the Partnership Policy
Committee and general partners, their affiliates and their respective officers,
directors, employees, agents and trustees to the fullest extent permitted by law
against liabilities, costs and expenses incurred by any such person who acted in
good faith and in a manner reasonably believed to be in, or (in the case of a
person other than one of the general partners) not opposed to, our best
interests and with respect to any criminal proceedings, had no reasonable cause
to believe the conduct was unlawful.

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.

57

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 Form of Amended and Restated Agreement of Limited
Partnership of Northern Border Partners, L.P.
(Exhibit 3.1 No. 2 to the Partnership's Form S-1
Registration Statement, Registration No. 33-66158
("Form S-1")).

*3.2 Form of Amended and Restated Agreement of Limited
Partnership For Northern Border Intermediate Limited
Partnership (Exhibit 10.1 to Form S-1).

*4.1 Indenture, dated as of June 2, 2000, between the
registrants and Bank One Trust Company, N.A. (Exhibit
4.1 to the Partnership's Quarterly Report on Form
10-Q for the quarterly period ended June 30, 2000
("June 2000 10-Q")).

*4.2 First Supplemental Indenture, dated as of September
14, 2000, between the registrants and Bank One Trust
Company, N.A. (Exhibit 4.2 to Form S-4 Registration
Statement, Registration No. 333-46212 ("NBP Form
S-4")).

*4.3 Indenture, dated as of March 21, 2001, between
Northern Border Partners, L.P. and Northern Border
Intermediate Limited Partnership and Bank One Trust
Company, N.A., Trustee (Exhibit 4.3 to Northern
Border Partners, L.P. Form 10-K for the year ended
December 31, 2001).

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

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

*4.6 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 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 Form S-1).

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

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

58

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

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

*10.6 Administrative Services Agreement between NBP
Services Corporation, Northern Border Partners, L.P.
and Northern Border Intermediate Limited Partnership
(Exhibit 10.4 to Form S-1).

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

*10.8 Supplemental Agreement to the Note Purchase Agreement
dated as of June 1, 1995 (Exhibit 10.6.1 to the
Partnership's Annual Report on Form 10-K for the year
ended December 31, 1995 ("1995 10-K")).

*10.9 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).

*10.10 Revolving Credit Agreement, dated as of March 21,
2001, between Northern Border Partners, L.P.,
SunTrust Bank, Administrative Agent, Bank of Montreal
and Bank of America, N.A., Co-Syndication Agents and
Bank One, NA, Documentation Agent and Lenders (as
defined therein)(Exhibit 10.20 to Northern Border
Partners, L.P. Form 10-K for the year ended December
31, 2000 ("2000 10-K")).

*10.11 Northern Border Pipeline Company U.S. Shippers
Service Agreement between Northern Border Pipeline
Company and Pan-Alberta Gas (US) Inc., dated October
1, 1993, with Amended Exhibit A effective June 22,
1998 (Exhibit 10.36 to Northern Border Pipeline
Company Annual Report on Form 10-K for the year ended
December 31, 1999 ("NB Pipeline 1999 10-K")).

*10.12 Northern Border Pipeline Company U.S. Shippers
Service Agreement between Northern Border Pipeline
Company and Pan-Alberta Gas (US) Inc.,(successor to
Natgas U.S. Inc.) dated October 6, 1989, with Amended
Exhibit A effective April 2, 1999 (Exhibit 10.37 to
NB Pipeline 1999 10-K).

*10.13 Northern Border Pipeline Company U.S. Shippers
Service Agreement between Northern Border Pipeline
Company and Pan-Alberta Gas (U.S.) Inc., dated
October l, 1992, with Amended Exhibit A effective
June 22, 1998 (Exhibit 10.38 to NB Pipeline 1999
10-K).

*10.14 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).

*10.15 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).

*10.16 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).

59

*10.17 Operating Agreement between Midwestern Gas
Transmission Company and Northern Plains Natural Gas
Company dated as of April 1, 2001. (Exhibit 10.38 to
Northern Border Partner, L.P.'s Form 10-K for year
ended December 31, 2001).

10.18 Operating Agreement between Viking Gas Transmission
Company and Northern Plains Natural Gas Company dated
as of January 17, 2003.

*10.19 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")).

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

21 The subsidiaries of Northern Border Partners, L.P.
are Northern Border Intermediate Limited Partnership;
Northern Border Pipeline Company; Crestone Energy
Ventures, L.L.C.; Bear Paw Investments, LLC; Bear Paw
Energy, LLC; Border Midwestern Company; Midwestern
Gas Transmission Company; Border Viking Company; and
Viking Gas Transmission Company.

23.01 Consent of KPMG LLP.

*99.1 Northern Border Phantom Unit Plan (Exhibit 99.1 to
Amendment No. 1 to Form S-8, 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.

(b)REPORTS

The Partnership 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 Items 10 and 13 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.

The Partnership filed a Current Report on Form 8-K, dated November 8,
2002 reporting a press release dated November 8, 2002 announcing the
execution of a definitive agreement to purchase Viking Gas Transmission
Company, including a one-third interest in Guardian Pipeline.

The Partnership filed a Current Report on Form 8-K, dated December 9,
2002, pursuant to Item 9 of that form, including a press release
announcing a presentation to be made by the Chairman and Chief
Executive Officer at the Wachovia Pipeline Conference on December 10,
2002.

The Partnership filed a Current Report on Form 8-K, dated December 11,
2002, reporting receipt of a letter from the United States
Environmental Protection Agency demanding payment of $176,000 in
stipulated penalties.

60

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 PARTNERS, L.P.
(A Delaware Limited Partnership)

By: WILLIAM R. CORDES
--------------------------------------------
William R. Cordes
Chief Executive Officer

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.

61

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 Partners,
L.P.;

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. Cores
---------------------------------
William R. Cordes
Chief Executive Officer

62

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 Partners,
L.P.;

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
Chief Financial and Accounting Officer

63

NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES
INDEX TO FINANCIAL STATEMENTS

F-1

INDEPENDENT AUDITORS' REPORT

Northern Border Partners, L.P.:

We have audited the accompanying consolidated balance sheets of Northern Border
Partners, L.P. (a Delaware limited partnership) and Subsidiaries as of December
31, 2002 and 2001, and the related consolidated 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 consolidated
financial statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these consolidated 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 consolidated financial statements referred to above present
fairly, in all material respects, the financial position of Northern Border
Partners, L.P. and Subsidiaries as of December 31, 2002 and 2001, and the
results of their operations and their 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.

As discussed in note 4 to the consolidated financial statements, Northern Border
Partners, L.P. and Subsidiaries adopted the provisions of Statement of Financial
Accounting Standards (SFAS) No. 142, Goodwill and Other Intangibles.

KPMG LLP

January 23, 2003
Omaha, Nebraska

F-2

NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEET

(IN THOUSANDS)

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

F-3

NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF INCOME

(IN THOUSANDS, EXCEPT PER UNIT AMOUNTS)

NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME

(IN THOUSANDS)

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

F-4

NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF CASH FLOWS

(IN THOUSANDS)

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

F-5

NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF CHANGES IN PARTNERS' EQUITY

(IN THOUSANDS)

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

F-6

NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. ORGANIZATION AND MANAGEMENT

Northern Border Partners, L.P., through a subsidiary limited
partnership, Northern Border Intermediate Limited Partnership, both
Delaware limited partnerships, collectively referred to herein as the
Partnership, owns a 70% general partner interest in Northern Border
Pipeline Company (Northern Border Pipeline). The remaining 30% general
partner interest in Northern Border Pipeline is owned by TC PipeLines
Intermediate Limited Partnership (TC PipeLines). Crestone Energy
Ventures, L.L.C. (Crestone Energy Ventures); Bear Paw Energy, L.L.C.
(Bear Paw Energy); Border Midstream Services, Ltd. (Border Midstream);
Midwestern Gas Transmission Company (Midwestern Gas Transmission) and
Black Mesa Pipeline, Inc. (Black Mesa) are wholly-owned subsidiaries of
the Partnership. As discussed in Note 17, the Partnership acquired all
of the common stock of Viking Gas Transmission Company (Viking Gas
Transmission) on January 17, 2003.

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 (Northwest Border), a wholly-owned subsidiary of
TransCanada PipeLines Limited (TransCanada) and affiliate of TC
PipeLines, serve as the General Partners of the Partnership and
collectively own a 2% general partner interest in the Partnership.
Northern Plains also owns common units representing a 1.1% limited
partner interest and Enron, through an indirect subsidiary, owns common
units representing a 6.2% limited partner interest in the Partnership at
December 31, 2002 (see Note 10).

The Partnership is managed under the direction of the Partnership Policy
Committee consisting of one person appointed by each General Partner.
The members appointed by Northern Plains, Pan Border and Northwest
Border have 50%, 32.5% and 17.5%, respectively, of the voting interest
on the Partnership Policy Committee. The Partnership has entered into an
administrative services agreement with NBP Services Corporation (NBP
Services), a wholly-owned subsidiary of Enron. NBP Services provides
certain administrative, operating and management services for the
Partnership and its gas gathering and processing and coal slurry
businesses and is reimbursed for its direct and indirect costs and
expenses. NBP Services also utilizes Enron affiliates to provide these
services. For the years ended December 31, 2002, 2001 and 2000, charges
from NBP Services and its affiliates totaled approximately $16.2
million, $15.3 million and $3.5 million, respectively. See Note 16 for a
discussion of the Partnership's relationships with Enron and
developments involving Enron.

Northern Border Pipeline is a Texas general partnership formed in 1978.
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 the Partnership (one representative
appointed by each of the General Partners of the Partnership) and one
representative from TC PipeLines. The Partnership's representatives
selected by Northern Plains, Pan Border and Northwest Border have 35%,
22.75% and 12.25%, respectively, of the voting interest on the Northern
Border Pipeline Management Committee. The representative designated by
TC PipeLines votes the remaining 30% interest.

F-7

NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. ORGANIZATION AND MANAGEMENT (continued)

The Northern Border Pipeline partnership agreement provides that
distributions to Northern Border Pipeline's partners are to be made on a
pro rata basis according to each partner's capital account balance. The
Northern Border Pipeline Management Committee determines the amount and
timing of such distributions. Any changes to, or suspension of, the cash
distribution policy of Northern Border Pipeline requires the unanimous
approval of the Northern Border Pipeline Management Committee.

The Partnership acquired Midwestern Gas Transmission effective May 1,
2001 (see Note 3). The Midwestern Gas Transmission system is a 350-mile
interstate natural gas pipeline extending from Portland, Tennessee to
Joliet, Illinois. Midwestern Gas Transmission's pipeline system connects
with multiple pipeline systems, including Northern Border Pipeline.

The day-to-day management of Northern Border Pipeline's and Midwestern
Gas Transmission's affairs is the responsibility of Northern Plains, as
defined by their respective operating agreements with Northern Plains.
Northern Border Pipeline and Midwestern Gas Transmission are charged for
the salaries, benefits and expenses of Northern Plains. Northern Plains
also utilizes Enron affiliates for management services related to
Northern Border Pipeline and Midwestern Gas Transmission. For the years
ended December 31, 2002, 2001 and 2000, Northern Plains' and its
affiliates' charges to Northern Border Pipeline and Midwestern Gas
Transmission totaled approximately $29.1 million, $31.5 million and
$31.7 million, respectively.

On March 30, 2001, the Partnership acquired Bear Paw Energy (see Note
3). Bear Paw Energy has extensive natural gas gathering, processing and
fractionation operations in the Williston Basin in Montana, North Dakota
and Saskatchewan as well as gas gathering operations in the Powder River
Basin in Wyoming. In the Williston Basin, Bear Paw Energy has over 3,000
miles of gathering pipelines and five processing plants with 90 million
cubic feet per day of capacity. Bear Paw Energy has approximately 1,100
miles of high and low pressure gathering pipelines and approximately
430,000 acres of dedicated reserves in the Powder River Basin.

On April 4, 2001, Border Midstream completed the acquisition of the
Mazeppa and Gladys gas processing plants, gas gathering systems and a
minority interest in the Gregg Lake/Obed Pipeline (see Note 3). The
Mazeppa and Gladys plants, which are located near Calgary, Alberta, have
a combined capacity of 87 million cubic feet per day. The Gregg
Lake/Obed Pipeline system, which is located near Edmonton, Alberta, is
comprised of 85 miles of gathering lines.

The Partnership owns a 49% common membership interest and a 100%
preferred A share interest in Bighorn Gas Gathering, L.L.C. (Bighorn); a
33% interest in Fort Union Gas Gathering, L.L.C. (Fort Union); and a 35%
interest in Lost Creek Gathering, L.L.C. (Lost Creek). The Partnership
acquired its interests in Fort Union, Lost Creek and a portion of
Bighorn in September 2000 (see Note 3).

Collectively, Bighorn, Fort Union and Lost Creek own over 300 miles of
gas gathering facilities in Wyoming. The gathering facilities
interconnect to the interstate gas pipeline grid serving gas markets in
the Rocky Mountains, the Midwest and California.

F-8

NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. ORGANIZATION AND MANAGEMENT (continued)

Black Mesa owns a 273-mile, 18-inch diameter coal slurry pipeline that
originates at a coal mine in Kayenta, Arizona and ends at the 1,500
megawatt Mohave Power Station located in Laughlin, Nevada.

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

(A) Principles of Consolidation and Use of Estimates

The consolidated financial statements include the assets,
liabilities and results of operations of the Partnership and its
majority-owned subsidiaries. The Partnership operates through a
subsidiary limited partnership of which the Partnership is the
sole limited partner and the General Partners are the sole
general partners. The 30% ownership of Northern Border Pipeline
by TC PipeLines is accounted for as a minority interest. All
significant intercompany items have been eliminated in
consolidation.

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 and Midwestern Gas Transmission are
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."
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 consolidated balance sheet. Northern Border Pipeline is
recovering the regulatory assets from its shippers over varying
time periods, which range from five to 44 years.

Although Northern Border Pipeline is a general partnership,
Northern Border Pipeline's tariff establishes the method of
accounting for and calculating income taxes and requires Northern
Border Pipeline to reflect in its financial records 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

F-9

NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)

(B) Government Regulation (continued)

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.

(C) 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.

(D) Revenue Recognition

Northern Border Pipeline and Midwestern Gas Transmission
transport gas for shippers under tariffs regulated by the FERC.
The tariffs specify the calculation of amounts to be paid by
shippers and the general terms and conditions of transportation
service on the respective pipeline systems. Operating 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 and Midwestern Gas Transmission do not own the gas that
they transport, and therefore do not assume the related natural
gas commodity risk.

For the gas gathering and processing businesses, operating
revenue is recorded when gas is processed in or transported
through company facilities.

Black Mesa's operating revenue is derived from a pipeline
transportation agreement. Under the terms of the agreement, Black
Mesa receives a monthly demand payment, a per ton commodity
payment and a reimbursement for certain other expenses.

(E) Income Taxes

The Partnership is not a taxable entity for federal income tax
purposes. As such, the Partnership does not directly pay federal
income tax. The Partnership's taxable income or loss, which may
vary substantially from the net income or loss reported in the
consolidated statement of income, is includable in the federal
income tax returns of each partner. The aggregate difference in
the basis of the Partnership's net assets for financial and
income tax purposes cannot be readily determined as the
Partnership does not have access to information about each
partner's tax attributes related to the Partnership.

F-10

NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)

(E) Income Taxes (continued)

The Partnership's corporate subsidiaries are required to pay
federal and state income taxes. Deferred income tax assets and
liabilities are recognized by these entities for temporary
differences between the assets and liabilities for financial
reporting and tax purposes. The amount of income taxes recorded
for these entities is presently not material to the Partnership's
financial position or results of operations.

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

Property, plant and equipment is stated at original cost. During
periods of construction, utilities are permitted to capitalize an
allowance for funds used during construction, which represents
the estimated costs of funds used for construction purposes. The
original cost of utility property retired is charged to
accumulated depreciation and amortization, net of salvage and
cost of removal. For utility property, no retirement gain or loss
is included in income except in the case of retirements or sales
of entire operating units. Maintenance and repairs are charged to
operations in the period incurred.

For utility property, the provision for depreciation and
amortization is an integral part of the interstate pipelines'
FERC tariffs. The effective depreciation rate applied to Northern
Border Pipeline's transmission plant was 2.25%. Midwestern Gas
Transmission applied a 1.9% depreciation rate to its transmission
plant. Composite rates are applied to all other functional groups
of utility property having similar economic characteristics. The
effective depreciation rate applied to gas gathering and
processing assets ranges from 3.33% to 20%. The effective
depreciation rate applied to coal slurry assets ranges from 3.1%
to 14.3%.

(G) Foreign Currency Translation

For the Partnership's Canadian subsidiary, Border Midstream,
asset and liability accounts are translated from its functional
currency (the Canadian dollar) at year-end rates of exchange and
revenue and expenses are translated at average exchange rates
prevailing during the year. Translation adjustments are included
as a separate component of other comprehensive income and
partners' equity. Currency transaction gains and losses are
recorded in income.

(H) Goodwill

Beginning January 1, 2002, the excess of cost over fair value of
the net assets acquired in business acquisitions or goodwill is
no longer being amortized and instead is tested for impairment
(see Note 4). Prior to January 1, 2002, the excess was being
amortized using a

F-11

NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)

(H) Goodwill (continued)

straight-line method over 30 years. During 2001 and 2000,
respectively, the Partnership recorded amortization expense of
$6.3 million and $2.2 million related to its investments in
unconsolidated affiliates, which is reflected as a component of
equity earnings (losses) of unconsolidated affiliates in the
consolidated statement of income. See Note 9 for details on the
Partnership's investments in unconsolidated affiliates and
related equity earnings (losses). For the Partnership's
consolidated affiliates, during 2001 and 2000, the Partnership
recorded amortization expense of $7.0 million and $0.5 million,
respectively. This amortization expense is reflected as a
component of depreciation and amortization in the consolidated
statement of income.

(I) Equity Method of Accounting

The Partnership accounts for its investments, which it does not
control, by the equity method of accounting. Under this method,
an investment is carried at its acquisition cost, plus the equity
in undistributed earnings or losses since acquisition.

(J) Risk Management

The Partnership uses financial instruments in the management of
its interest rate and commodity price 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. The Partnership
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. The Partnership adopted SFAS No. 133
beginning January 1, 2001. See Note 8 for a discussion of the
Partnership's derivative instruments and hedging activities.

(K) Reclassifications

Certain reclassifications have been made to the consolidated
financial statements for prior years to conform with the current
year presentation.

F-12

NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

3. BUSINESS ACQUISITIONS

Pursuant to a 1999 purchase agreement, in June 2000, the Partnership
purchased 80% of the preferred A shares outstanding of Bighorn for
approximately $20.8 million.

In September 2000, the Partnership purchased interests in gas gathering
businesses in the Powder River and Wind River basins in Wyoming from
Enron North America Corp. (ENA), a subsidiary of Enron, for
approximately $208.7 million. The acquisition included the purchase of
Crestone Gathering Services, L.L.C., a 33% interest in Fort Union and a
35% interest in Lost Creek. The purchase of Crestone Gathering Services
increased the Partnership's ownership in Bighorn to a 49% common
membership interest and a 100% interest in the preferred A shares.

The Partnership completed three acquisitions during 2001. On March 30,
2001, the Partnership acquired Bear Paw Energy for $381.7 million. The
purchase price consisted of $198.7 million in cash and the issuance of
5.7 million common units valued at $183.0 million. Border Midstream
acquired the Mazeppa and Gladys gas processing plants, gas gathering
systems and a minority interest in the Gregg Lake/Obed Pipeline (Gregg
Lake/Obed) for $70 million (Canadian) or $45 million (U.S.) on April 4,
2001. Effective May 1, 2001, the Partnership acquired Midwestern Gas
Transmission for $102 million.

The Partnership has accounted for these acquisitions using the purchase
method of accounting. The purchase price has been allocated based upon
the estimated fair value of the assets and liabilities acquired as of
the acquisition date. The excess of the purchase price over the fair
value of the Bear Paw Energy, Midwestern Gas Transmission and Crestone
Gathering Services net assets acquired is reflected as goodwill on the
consolidated balance sheet. The investments in Bighorn, Fort Union, Lost
Creek and Gregg Lake/Obed are being reflected in investments in
unconsolidated affiliates on the consolidated balance sheet. See Note 9
for additional discussion of the Partnership's investments in
unconsolidated affiliates.

The following is a summary of the effects of the acquisitions made in
2001 and 2000 on the Partnership's consolidated financial position
(amounts in thousands):

F-13

NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

3. BUSINESS ACQUISITIONS (continued)

If the acquisitions made in 2001 had occurred at the beginning of 2001,
the Partnership's 2001 consolidated operating revenues, net income to
partners and net income per unit would have been $506 million, $88
million and $2.12 per unit, respectively. These unaudited pro forma
results are for illustrative purposes only and are not necessarily
indicative of the operating results that would have occurred had the
business acquisitions been consummated at that date, nor are they
necessarily indicative of future operating results.

Bighorn's ownership structure consists of common membership interests
and non-voting preferred A and B shares. Both of the non-voting classes
of shares are subject to certain distribution preferences and
limitations based on the cumulative number of wells connected to the
Bighorn system at the end of each calendar year. These shares will
receive an income allocation equal to the cash distributions received
and are not entitled to any other allocations of income or distributions
of cash. During 2001, the non-voting preferred A shares received a $0.1
million income allocation and cash distribution. No income allocation or
cash distribution was made to the non-voting shares in 2002 or 2000.
Ownership of these shares does not affect the amount of capital
contributions that are required to be made to the operations of Bighorn
by the owners of the common membership interests.

4. GOODWILL

In the third quarter of 2001, the Financial Accounting Standards Board
(FASB) issued SFAS No. 142, "Goodwill and Other Intangible Assets." SFAS
No. 142 modifies the accounting and reporting of goodwill and intangible
assets. It requires entities to discontinue the amortization of
goodwill, reallocate goodwill among its reporting segments and perform
impairment tests by applying a fair-value-based analysis on the goodwill
in each reporting segment. The Partnership adopted SFAS No. 142
effective January 1, 2002. At December 31, 2002 and 2001, the
Partnership's balance sheet included goodwill of approximately $476
million and $475 million, respectively, with approximately $180 million
recorded in the Partnership's investment in unconsolidated affiliates.

During 2002, the Partnership completed its initial and annual
evaluations of approximately $296 million recorded goodwill. The
Partnership determined that it did not have an impairment loss for 2002.

Changes in the carrying amount of goodwill for the year ended December
31, 2002, are summarized as follows:

F-14

NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

4. GOODWILL (continued)

The following information discloses the effect of goodwill amortization
on the Partnership's net income to partners and net income per unit.

5. 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 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

F-15

NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

5. RATES AND REGULATORY ISSUES (continued)

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 the
Partnership cannot predict the outcome of this proceeding at this time,
the accompanying consolidated financial statements reflect a reserve of
$10 million.

6. TRANSPORTATION AGREEMENTS

Northern Border Pipeline's and Midwestern Gas Transmission's operating
revenues are collected pursuant to their FERC tariffs through firm
transportation service agreements. Northern Border Pipeline's firm
service agreements extend for various terms with termination dates that
range from March 2003 to December 2013. The termination dates for
Midwestern Gas Transmission's firm service agreements range from March
2003 to October 2019. Northern Border Pipeline and Midwestern Gas
Transmission also have interruptible transportation service agreements
and other transportation service agreements with numerous shippers.

Under the capacity release provisions of Northern Border Pipeline's and
Midwestern Gas Transmission's FERC tariffs, 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 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.

F-16

NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

6. TRANSPORTATION AGREEMENTS (continued)

For the year ended December 31, 2002, Midwestern Gas Transmission's two
largest shippers were Northern Illinois Gas Company (Northern Illinois)
and Northern Indiana Public Service Company (NIPSCO). The transportation
agreements with Northern Illinois expire in October 2003 and the
agreements with NIPSCO expire in October 2004 and December 2006.
For 2002, Northern Illinois and NIPSCO accounted for $5.2 million (28%)
and $2.9 million (16%), respectively, of Midwestern Gas Transmission's
operating revenues. For the period from May 2001 to December 2001,
Midwestern Gas Transmission's two largest customers, Northern Illinois
and PSI Energy LLC had total operating revenues of $4.7 million.

The gas gathering and processing businesses provide services for
gathering, treating, processing and compression of natural gas and the
fractionation of natural gas liquids. For the year ended December 31,
2002, Bear Paw Energy's two largest customers, Lodgepole Energy
Marketing (Lodgepole) and Tenaska Marketing Ventures (Tenaska) accounted
for $44.2 million (35%) and $20.2 million (16%), respectively, of Bear
Paw Energy's operating revenue. Lodgepole and Tenaska accounted for
$34.8 million (40%) and $8.7 million (10%), respectively, of Bear Paw
Energy's operating revenue for the period from March 31, 2001 to
December 2001. Bear Paw Energy's operating revenue for 2001 also
included $1.7 million from ENA related to swap arrangements to hedge
risks of changes in commodity prices (see Note 8) and $0.5 million from
TransCanada Energy. In 2001 and 2000, Crestone Energy Ventures and
Crestone Gathering Services (collectively Crestone) provided gas
gathering and administrative services to ENA under a master services
agreement. Crestone's revenues from ENA totaled $20.6 million and $7.2
million for the years ended December 31, 2001 and 2000, respectively
(see Note 16). Crestone's revenues from other affiliates totaled $0.2
million, $0.3 million and $0.1 million in 2002, 2001 and 2000,
respectively. For the year ended December 31, 2002, Border Midstream's
two largest customers, Compton Petroleum (Compton) and ConocoPhillips
(Conoco), accounted for $5.6 million (70%) and $0.9 million (11%) of
Border Midstream's operating revenues. Compton and Conoco, accounted for
$3.1 million (65%) and $0.6 million (13%) of Border Midstream's revenues
for the period from April 2001 to December 2001.

Black Mesa's operating revenue is derived from a transportation
agreement with the coal supplier for the Mohave Power Station that
expires in December 2005. The coal slurry pipeline is the sole source of
fuel for the Mohave plant. Operating revenues under the agreement
totaled $21.5 million, $22.0 million and $21.1 million for the years
ended December 31, 2002, 2001 and 2000, respectively.

F-17

NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

7. CREDIT FACILITIES, LONG-TERM DEBT AND CAPITAL LEASES

Detailed information on long-term debt is as follows:

The Partnership and Northern Border Pipeline have entered into revolving credit
facilities, which are used for capital expenditures, acquisitions and general
business purposes and for refinancing existing indebtedness. Northern Border
Pipeline entered into a $175 million three-year credit agreement (2002 Pipeline
Credit Agreement) with certain financial institutions in May 2002. The
Partnership entered into a $200 million three-year revolving credit agreement
with certain financial institutions (2001 Partnership Credit Agreement) in March
2001. Both of the revolving credit facilities permit the Partnership and
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. Both the Partnership and
Northern Border Pipeline are required to pay a fee on the principal commitment
amounts.

F-18

NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

7. CREDIT FACILITIES, LONG-TERM DEBT AND CAPITAL LEASES (continued)

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.

In March 2001, the Partnership completed a private offering of $225
million of 7.10% Senior Notes due 2011 (2001 Partnership Senior Notes).
In June 2000, the Partnership completed a private offering of $150
million of 8 -7/8% Senior Notes due 2010 (2000 Partnership Senior Notes)
and in September 2000, the Partnership completed an additional private
offering of $100 million of 2000 Partnership Senior Notes. The 2001
Partnership Senior Notes and 2000 Partnership Senior Notes were
subsequently exchanged in registered offerings for notes with
substantially identical terms. The proceeds from the Partnership's
senior notes were used to fund its acquisitions in 2001 and 2000.

In June 2001, the Partnership repaid Black Mesa's 10.7% Secured Senior
Notes due May 2004. The total repayment of approximately $13.6 million
consisted of remaining principal and interest of $12.4 million and an
early payment premium of $1.2 million. The early payment premium is
reflected as an extraordinary loss on the consolidated statement of
income.

Interest paid, net of amounts capitalized, during the years ended
December 31, 2002, 2001 and 2000 was $88.2 million, $86.5 million and
$84.2 million, respectively.

Aggregate repayments of long-term debt required for the next five years,
excluding payments required under Bear Paw Energy's capital leases, are
as follows: $65 million, $35 million, $89 million and $225 million for
2003, 2004, 2005 and 2007, respectively. There are no scheduled debt
maturities for 2006.

Bear Paw Energy has entered into non-cancelable capital leases on
compressors. The capital leases incorporate annual interest rates
ranging from 7.10% to 8.85% and are for a term of five years, after
which Bear Paw Energy receives ownership of the equipment. Future
minimum payments under Bear Paw Energy's capital leases are as follows
(in thousands):

Years ending December 31,
2003 $ 3,355
2004 3,355
2005 3,074
2006 169
-------
$ 9,953
Less amount representing interest 1,099
-------
Present value of lease payments 8,854
Less: current portion 2,765
-------
Long-term portion $ 6,089
=======

F-19

NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

7. CREDIT FACILITIES, LONG-TERM DEBT AND CAPITAL LEASES (continued)

Certain of Northern Border Pipeline's long-term debt and credit
arrangements contain requirements as to the maintenance of minimum
partners' capital, 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 to be 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 its financial
covenants.

The indentures under which the 2001 and 2000 Partnership Senior Notes
were issued do not limit the amount of indebtedness or other obligations
that the Partnership may incur, but do contain material financial
covenants, including restrictions on the incurrence of secured
indebtedness. The indentures also contain a provision that would require
the Partnership to offer to repurchase the 2001 and 2000 Partnership
Senior Notes if either Standard & Poor's Rating Services or Moody's
Investor Service, Inc. rate the notes below investment grade and the
investment grade rating is not reinstated for a period of 40 days. The
2001 Partnership Credit Agreement requires the maintenance of a ratio of
consolidated EBITDA (consolidated net income plus minority interests in
net income, consolidated interest expense, income taxes and depreciation
and amortization) to consolidated interest expense of greater than 3 to
1. The 2001 Partnership Credit Agreement also requires the maintenance
of the ratio of consolidated funded debt to adjusted consolidated EBITDA
(EBITDA adjusted for pro forma operating results of acquisitions made
during the year) of no more than 4.5 to 1. At December 31, 2002, the
Partnership 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, 2000 Partnership Senior Notes, 2001 Partnership Senior
Notes, 2001 Pipeline Senior Notes and 2002 Pipeline Senior Notes was
approximately $1,367 million and $1,125 million at December 31, 2002 and
2001, respectively. The Partnership presently intends to maintain the
current schedule of maturities for the 1992 Pipeline Senior Notes, 1999
Pipeline Senior Notes, 2000 Partnership Senior Notes, 2001 Partnership
Senior Notes, 2001 Pipeline Senior Notes and 2002 Pipeline Senior Notes,
which will result in no gains or losses on their respective repayment.
The fair value of the 2002 Pipeline Credit Agreement and 2001
Partnership Credit Agreement approximates the carrying value since the
interest rates are periodically adjusted to reflect current market
conditions.

F-20

NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

8. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

The Partnership reflects in consolidated accumulated other comprehensive
income its 70% share of Northern Border Pipeline's accumulated other
comprehensive income. The remaining 30% is reflected as an adjustment to
minority interests in partners' equity. The Partnership also reflects in
consolidated accumulated other comprehensive income its ownership share
of accumulated other comprehensive income of its unconsolidated
affiliates (see Note 9).

As a result of the adoption of SFAS No. 133, the Partnership
reclassified $22.7 million from long-term debt to accumulated other
comprehensive income and $3.3 million from long-term debt to minority
interests in partners' equity related to unamortized proceeds from
interest rate swap agreements terminated prior to 2001. Also upon
adoption of SFAS No. 133, Northern Border Pipeline designated an
outstanding interest rate swap agreement with a notional amount of $40
million as a cash flow hedge. As a result, the Partnership recorded a
non-cash loss of $0.5 million in accumulated other comprehensive income
and $0.3 million as an adjustment to minority interests in partners'
equity. The $40 million interest rate swap agreement terminated in
November 2001.

Prior to the anticipated issuance of fixed rate debt, both the
Partnership and Northern Border Pipeline have 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 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. The Partnership also recorded an adjustment to minority
interests in partners' equity for Northern Border Pipeline's terminated
swaps.

For the year ended December 31, 2002, Northern Border Pipeline received
$2.4 million from terminated interest rate swaps, of which $1.6 million
was recorded in accumulated other comprehensive income and $0.8 million
was recorded as an adjustment to minority interests in partners' equity.
For the year ended December 31, 2001, the Partnership and Northern
Border Pipeline paid $4.3 million and $4.1 million, respectively, to
terminate interest rate swaps, of which $7.2 million was recorded in
accumulated other comprehensive income and $1.2 million was recorded as
an adjustment to minority interests in partners' equity.

During each of the years ended December 31, 2002 and 2001, the
Partnership and Northern Border Pipeline amortized approximately $2.1
million related to the terminated derivatives, as a reduction to
interest expense from accumulated other comprehensive income. A
comparable amount is expected to be amortized in 2003.

During the third quarter of 2001, the Partnership entered into interest
rate swaps with notional amounts totaling $225 million. Under the
interest rate swap agreements, the Partnership makes payments to
counterparties at variable rates based on the London Interbank Offered
Rate and in return

F-21

NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

8. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES (continued)

receives payments based on a 7.10% fixed rate. In October 2002, the
Partnership agreed to an increase in the variable interest rate on two
of its interest rate swap agreements with notional amounts totaling $150
million. As consideration for the change to the variable interest rate,
the Partnership received approximately $18.2 million, which represented
the fair value of the financial instruments at the date of the
adjustment. The Partnership used the proceeds to repay amounts borrowed
under its credit facility. The proceeds are recorded in long-term debt
and will be recognized as a reduction in interest expense over the
remaining life of the interest rate swap agreements. The Partnership
amortized approximately $0.5 million in the fourth quarter of 2002 and
expects to amortize approximately $2.2 million in 2003 for these
agreements. At December 31, 2002 and 2001, the average effective
interest rate on the Partnership's interest rate swap agreements was
3.97% and 4.21%, respectively.

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%.

Both the Partnership's and 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 senior
notes issued by the Partnership in 2001 and by Northern Border Pipeline
in 2002. The accompanying consolidated balance sheet at December 31,
2002, reflects a non-cash gain of approximately $36.9 million in
derivative financial instruments with a corresponding increase in
long-term debt.

Bear Paw Energy periodically enters into commodity derivatives contracts
and fixed-price physical contracts. Bear Paw Energy primarily utilizes
price swaps and collars, which have been designated as cash flow hedges,
to hedge its exposure to gas and natural gas liquid price volatility.
During the year ended December 31, 2002, Bear Paw Energy recognized
losses of $2.8 million from the settlement of derivative contracts.
During the period from late March 2001 to December 2001, Bear Paw Energy
recognized gains of $4.7 million from the settlement of derivative
contracts. Bear Paw Energy recognized a loss of $0.1 million for
ineffective hedges for 2002, which is included in operating revenues. At
December 31, 2002, Bear Paw Energy reflected a non-cash loss of
approximately $4.1 million in derivative financial instruments with a
corresponding reduction of $4.0 million in accumulated other
comprehensive income. In 2003, Bear Paw Energy expects to reclassify
approximately $3.4 million from accumulated other comprehensive income
as a reduction to operating revenues.

At September 30, 2001, Bear Paw Energy had outstanding commodity price
swap arrangements with ENA, which had been accounted for as cash flow
hedges, and resulted in Bear Paw Energy recording a non-cash gain of
approximately $6.7 million in accumulated other comprehensive income.
During the fourth quarter of 2001, the Partnership determined that ENA
was no longer likely to honor the obligations it had to Bear Paw Energy
for these derivatives

F-22

NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

8. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES (continued)

and terminated the swap arrangements (see Note 16). In accordance with
SFAS No. 133, Bear Paw Energy ceased to account for these derivatives as
hedges. The gain previously recorded in accumulated other comprehensive
income is reflected in earnings in the same periods during which the
hedged forecasted transactions will affect earnings. In 2002 and 2001,
the Partnership recorded approximately $4.6 million and $1.4 million,
respectively, in earnings and expects to record approximately $0.3
million in earnings in 2003.

9. UNCONSOLIDATED AFFILIATES

The Partnership's investments in unconsolidated affiliates which are
accounted for by the equity method is as follows:

(a) As discussed in Note 3, the Partnership held a 49% common
membership interest in Bighorn and 100% of the non-voting
preferred A shares of Bighorn at December 31, 2002 and 2001.

(b) At December 31, 2002 and 2001, the unamortized excess of the
Partnership's investments in unconsolidated affiliates was $180.1
million.

The Partnership's equity earnings (losses) of unconsolidated affiliates
is as follows:

(a) As discussed in Note 4, the Partnership has adopted SFAS No. 142 and
beginning January 1, 2002, the Partnership is no longer recording
amortization expense related to goodwill. The equity earnings (losses)
of unconsolidated affiliates included goodwill amortization of $6.3
million and $2.2 million in 2001 and 2000, respectively.

(b) Investments in Gregg Lake/Obed began in April 2001 (See Note 3).

F-23

NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

9. UNCONSOLIDATED AFFILIATES (continued)

Summarized combined financial information of the Partnership's
unconsolidated affiliates is presented below:

(a) Includes results for Fort Union and Lost Creek after they were
acquired in September 2000.

10. PARTNERS' CAPITAL

At December 31, 2002, partners' capital consisted of 43,809,714 common
units representing an effective 98% limited partner interest in the
Partnership (including 1.1% held by Northern Plains and 6.2% held by
Sundance Assets, L.P., an indirect subsidiary of Enron) and a 2% general
partner interest. At December 31, 2001, partners' capital consisted of
41,623,014 common units representing an effective 98% limited partner
interest in the Partnership (including 1.2% held by Northern Plains and
6.5% held by Sundance Assets) and a 2% general partner interest. The
dispositive power of Sundance Assets is shared by Enron and Citibank,
N.A. In conjunction with the issuance of additional common units, the
Partnership's general partners are required to make capital
contributions to the Partnership to maintain a 2% general partner
interest in accordance with the partnership agreements.

In July 2002, the Partnership sold 2,186,700 common units. In April and
May of 2001, the Partnership sold 407,550 and 4,000,000 common units,
respectively. In November 2000, the Partnership sold 2,156,250 common
units. The net proceeds from the sale of common units and the general
partners' capital contributions totaled approximately $75.4 million in
2002, $172.2 million in 2001 and $60.7 million in 2000 and were
primarily used to repay indebtedness outstanding.

The Partnership will make distributions to its partners with respect to
each calendar quarter in an amount equal to 100% of its Available Cash.
"Available Cash" generally consists of all of the cash receipts of the
Partnership adjusted for its cash disbursements and net changes to cash

F-24

NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

10. PARTNERS' CAPITAL (continued)

reserves. Available Cash will generally be distributed 98% to the
Unitholders and 2% to the General Partners. As an incentive, the General
Partners' percentage interest in quarterly distributions is increased
after certain specified target levels are met (see Note 12). Under the
incentive distribution provisions, the General Partners receive 15% of
amounts distributed in excess of $0.605 per common unit, 25% of amounts
distributed in excess of $0.715 per unit and 50% of amounts distributed
in excess of $0.935 per unit. Partnership income is allocated to the
General Partners and the limited partners in accordance with their
respective partnership percentages, after giving effect to any priority
income allocations for incentive distributions that are allocated 100%
to the General Partners.

11. COMMITMENTS AND CONTINGENCIES

Firm Transportation Obligations and Other Commitments

Crestone Energy Ventures has firm transportation agreements with Fort
Union and Lost Creek. Under these agreements, Crestone Energy Ventures
must make specified minimum payments each month. Crestone Energy
Ventures recorded expenses of $11.4 million, $8.6 million and $2.2
million for the years ended December 31, 2002, 2001 and 2000,
respectively, related to these agreements. At December 31, 2002, the
estimated aggregate amounts of such required future payments were $11.6
million annually for 2003 through 2007 and $26.4 million for later
years.

At December 31, 2002, the Partnership has guaranteed the performance of
certain of its unconsolidated affiliates in connection with credit
agreements that expire in March 2009 and September 2009. Collectively,
at December 31, 2002, the amount of both guarantees was $4.4 million.

Operating Leases

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

Year ending December 31,
2003 $ 3,112
2004 3,082
2005 2,901
2006 2,439
2007 1,597
Thereafter 2,285
-------
$15,416
=======

Expenses incurred related to these lease obligations for the years ended
December 31, 2002 and 2001, were $2.0 million and $1.1 million,
respectively.

Capital expenditures

Total capital expenditures for 2003 are estimated to be $51 million.
This includes approximately $32 million for gas gathering and processing
facilities and $17 million for interstate natural gas pipeline
facilities.

F-25

NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

11. COMMITMENTS AND CONTINGENCIES (continued)

Capital expenditures (continued)

Funds required to meet the capital requirements for 2003 are anticipated
to be provided from debt borrowings, issuance of additional limited
partnership interests in the Partnership and operating cash flows.

Environmental Matters

The Partnership is not aware of any material contingent liabilities with
respect to compliance with applicable environmental laws and
regulations.

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. The Partnership believes that the resolution of this lawsuit
will not have a material adverse impact on the Partnership's results of
operations or financial position.

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

12. NET INCOME PER UNIT

Net income per unit is computed by dividing net income, after deduction
of the General Partners' allocation, by the weighted average number of
units outstanding. The General Partners' allocation is equal to an
amount based upon their combined 2% general partner interest, adjusted
to reflect an amount equal to incentive distributions. Net income per
unit was determined as follows:

F-26

NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

13. ACCOUNTING PRONOUNCEMENTS

In 2001, the 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 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, the Partnership's
subsidiaries are obligated by contractual terms or regulatory
requirements to remove facilities or perform other remediation upon
retirement. The Partnership has, where possible, developed its estimate
of the retirement obligations and the effect of adopting SFAS No. 143
is not expected to be material to the consolidated financial
statements.

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. The
Partnership 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.

14. GEOGRAPHIC AND BUSINESS SEGMENT INFORMATION

The Partnership's business is divided into three reportable segments,
defined as components of the enterprise about which financial
information is available and evaluated regularly by the Partnership's
executive management and the Partnership Policy Committee in deciding
how to allocate resources to an individual segment and in assessing
performance of the segment.

The Partnership's reportable segments are strategic business units that
offer different services. Each are managed separately because each
business requires different marketing strategies. The accounting
policies of the segments are the same as those described in the summary
of significant accounting policies in Note 2. The Partnership evaluates
performance based on EBITDA and operating income. Interest expense on
the Partnership's debt is not allocated to the segments. Therefore,
management believes that EBITDA is the dominant measurement of segment
performance.

F-27

NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

14. GEOGRAPHIC AND BUSINESS SEGMENT INFORMATION (continued)

Geographic Segments

Business Segments

F-28

NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

14. GEOGRAPHIC AND BUSINESS SEGMENT INFORMATION (continued)
Business Segments (continued)

F-29

NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

14. GEOGRAPHIC AND BUSINESS SEGMENT INFORMATION (continued)

Business Segments (continued)

(a) Includes interstate natural gas pipeline results of Midwestern Gas
Transmission commencing from the effective date of acquisition in May
2001 (see Note 3).

(b) Includes gas gathering and processing results of Bear Paw Energy and
Border Midstream commencing from the date of acquisition in March and
April of 2001, respectively (see Note 3).

(c) Gas gathering and processing operating results commence from the date
of acquisition in September 2000 (see Note 3) except for equity
earnings (losses) of Bighorn, which commenced in January 2000.

(d) Includes other items not allocable to segments.

15. QUARTERLY FINANCIAL DATA (Unaudited)

F-30

NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

16. 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 and NBP Services were not included in the bankruptcy filing
and management believes that Northern Plains and NBP Services will continue
to be able to meet their operational and administrative service obligations
under the existing operating agreements. ENA, a subsidiary of Enron, was
included in the bankruptcy filing.

At the time of the bankruptcy filing, ENA had firm service agreements with
Northern Border Pipeline 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 consolidated 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.

Crestone had provided gas gathering and administrative services to ENA under
a master services agreement. This agreement was terminated for ENA's failure
to pay approximately $2.1 million, which was recorded as bad debt expense in
2001. Subsequent to the termination of the agreement, the services are being
provided through contracts directly with the producers.

Bear Paw Energy had also periodically entered into certain swap arrangements
with ENA to hedge risks of changes in commodity prices (see Note 8). Bear
Paw Energy terminated the swap arrangements with ENA prior to December 31,
2001, and recorded bad debt expense of approximately $5.4 million.

The Partnership and its subsidiaries have filed proofs of claims regarding
the amount of damages for breach of contract and other claims in the
bankruptcy proceeding. However, the Partnership cannot predict the amounts,
if any, that it will collect or the timing of collection. The Partnership
believes, however, that any amounts collected will not be material.

Management continues to monitor developments at Enron, to assess the impact
on the Partnership of its existing agreements and relationships with Enron
and to take appropriate action to protect the interests of the Partnership.

17. SUBSEQUENT EVENTS

On January 17, 2003, the Partnership acquired all of the common stock of
Viking Gas Transmission including a one-third interest in Guardian Pipeline
L.L.C. (Guardian Pipeline) for approximately $162 million, which included
the assumption of $40 million of debt. The Partnership financed the
acquisition initially the 2001 Partnership Credit Agreement. Effective with
the closing of the Viking Gas Transmission acquisition, the Partnership
amended the 2001 Partnership Credit Agreement to increase the ratio of

F-31

NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

17. SUBSEQUENT EVENTS (continued)

consolidated funded debt to adjusted consolidated EBITDA to no more than
4.75 to 1 through June 30, 2003, at which time the ratio reverts back to 4.5
to 1. As part of the acquisition, the Partnership agreed to guarantee its
ownership share of Guardian Pipeline's indebtedness. The amount of the
guarantee is $60 million. Pursuant to the terms of Guardian Pipeline's debt
agreements, the guarantee is removed upon Guardian Pipeline meeting certain
conditions, which the Partnership expects to occur in the second quarter of
2003.

The Viking Gas Transmission system is a 578-mile interstate natural gas
pipeline extending from the U.S.-Canadian border near Emerson, Manitoba to
Marshfield, Wisconsin. Viking Gas Transmission connects to other major
pipeline systems including TransCanada, Northern Natural Gas Company, Great
Lakes Gas Transmission and ANR Pipeline Company to provide service to
markets in Minnesota, Wisconsin and North Dakota.

Guardian Pipeline is a 141-mile interstate natural gas pipeline system that
went into service on December 7, 2002. This system transports natural gas
from Joliet, Illinois to a point west of Milwaukee, Wisconsin.

On January 22, 2003, the Partnership declared a cash distribution of $0.80
per unit ($3.20 per unit on an annualized basis) for the quarter ended
December 31, 2002. The distribution was payable February 14, 2003, to
unitholders of record at January 31, 2003.

F-32

INDEPENDENT AUDITORS' REPORT ON SCHEDULE

Northern Border Partners, L.P.:

We have audited in accordance with auditing standards generally accepted in the
United States of America, the consolidated financial statements of Northern
Border Partners, L.P. and Subsidiaries 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 Partners,
L.P. and Subsidiaries 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 PARTNERS, L.P. AND SUBSIDIARIES
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 2002, 2001 AND 2000
(IN THOUSANDS)

S-2

EXHIBIT INDEX

*3.1 Form of Amended and Restated Agreement of Limited
Partnership of Northern Border Partners, L.P.
(Exhibit 3.1 No. 2 to the Partnership's Form S-1
Registration Statement, Registration No. 33-66158
("Form S-1")).

*3.2 Form of Amended and Restated Agreement of Limited
Partnership For Northern Border Intermediate Limited
Partnership (Exhibit 10.1 to Form S-1).

*4.1 Indenture, dated as of June 2, 2000, between the
registrants and Bank One Trust Company, N.A. (Exhibit
4.1 to the Partnership's Quarterly Report on Form
10-Q for the quarterly period ended June 30, 2000
("June 2000 10-Q")).

*4.2 First Supplemental Indenture, dated as of September
14, 2000, between the registrants and Bank One Trust
Company, N.A. (Exhibit 4.2 to Form S-4 Registration
Statement, Registration No. 333-46212 ("NBP Form
S-4")).

*4.3 Indenture, dated as of March 21, 2001, between
Northern Border Partners, L.P. and Northern Border
Intermediate Limited Partnership and Bank One Trust
Company, N.A., Trustee (Exhibit 4.3 to Northern
Border Partners, L.P. Form 10-K for the year ended
December 31, 2001).

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

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

*4.6 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 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 Form S-1).

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

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

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

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

*10.6 Administrative Services Agreement between NBP
Services Corporation, Northern Border Partners, L.P.
and Northern Border Intermediate Limited Partnership
(Exhibit 10.4 to Form S-1).

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

*10.8 Supplemental Agreement to the Note Purchase Agreement
dated as of June 1, 1995 (Exhibit 10.6.1 to the
Partnership's Annual Report on Form 10-K for the year
ended December 31, 1995 ("1995 10-K")).

*10.9 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).

*10.10 Revolving Credit Agreement, dated as of March 21,
2001, between Northern Border Partners, L.P.,
SunTrust Bank, Administrative Agent, Bank of Montreal
and Bank of America, N.A., Co-Syndication Agents and
Bank One, NA, Documentation Agent and Lenders (as
defined therein)(Exhibit 10.20 to Northern Border
Partners, L.P. Form 10-K for the year ended December
31, 2000 ("2000 10-K")).

*10.11 Northern Border Pipeline Company U.S. Shippers
Service Agreement between Northern Border Pipeline
Company and Pan-Alberta Gas (US) Inc., dated October
1, 1993, with Amended Exhibit A effective June 22,
1998 (Exhibit 10.36 to Northern Border Pipeline
Company Annual Report on Form 10-K for the year ended
December 31, 1999 ("NB Pipeline 1999 10-K")).

*10.12 Northern Border Pipeline Company U.S. Shippers
Service Agreement between Northern Border Pipeline
Company and Pan-Alberta Gas (US) Inc.,(successor to
Natgas U.S. Inc.) dated October 6, 1989, with Amended
Exhibit A effective April 2, 1999 (Exhibit 10.37 to
NB Pipeline 1999 10-K).

*10.13 Northern Border Pipeline Company U.S. Shippers
Service Agreement between Northern Border Pipeline
Company and Pan-Alberta Gas (U.S.) Inc., dated
October l, 1992, with Amended Exhibit A effective
June 22, 1998 (Exhibit 10.38 to NB Pipeline 1999
10-K).

*10.14 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).

*10.15 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).

*10.16 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).

*10.17 Operating Agreement between Midwestern Gas
Transmission Company and Northern Plains Natural Gas
Company dated as of April 1, 2001. (Exhibit 10.38 to
Northern Border Partner, L.P.'s Form 10-K for year
ended December 31, 2001).

10.18 Operating Agreement between Viking Gas Transmission
Company and Northern Plains Natural Gas Company dated
as of January 17, 2003.

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

21 The subsidiaries of Northern Border Partners, L.P.
are Northern Border Intermediate Limited Partnership;
Northern Border Pipeline Company; Crestone Energy
Ventures, L.L.C.; Bear Paw Investments, LLC; Bear Paw
Energy, LLC; Border Midwestern Company; Midwestern
Gas Transmission Company; Border Viking Company; and
Viking Gas Transmission Company.

23.01 Consent of KPMG LLP.

*99.1 Northern Border Phantom Unit Plan (Exhibit 99.1 to
Amendment No. 1 to Form S-8, 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.