NORTHERN BORDER PARTNERS LP - 10-K Annual Report

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

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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, 2001 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.)

1111 SOUTH 103RD STREET, OMAHA, NEBRASKA 68124-1000
(Address of principal executive offices) (zip code)
Registrant's telephone number, including area code: 402-398-7700

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

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.
---

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 March 1, 2002, was approximately
$1,438,920,000.

NORTHERN BORDER PARTNERS, L.P.
TABLE OF CONTENTS

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.
We, through our subsidiary limited partnership, Northern Border Intermediate
Limited Partnership, collectively referred to herein as "Partnership", own a 70%
general partner interest in Northern Border Pipeline Company, a Texas general
partnership ("Northern Border Pipeline"). In 2001, we completed several
acquisitions. We acquired Midwestern Gas Transmission Company ("Midwestern Gas
Transmission"), a 350-mile interstate natural gas pipeline system. We purchased
Bear Paw Energy, LLC ("Bear Paw Energy"), which owns extensive gathering and
processing operations in the Powder River Basin in Wyoming and in the Williston
Basin in Montana and North Dakota. We also acquired an interest in processing
and gathering operations in Alberta, Canada. We are managed under the direction
of a partnership policy committee (similar to a board of directors) appointed by
our general partners. Our general partners and the general partners of the
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 The Williams Companies, Inc.
("Williams").

Our general partners hold an aggregate 2% general partner interest in
the Partnership. Northern Plains also owns common units representing a 1.2%
limited partner interest and Enron, through an indirect subsidiary, holds a 6.5%
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 Williams are 9.4% and 0.3%, respectively. On
December 2, 2001, Enron filed a voluntary petition for Chapter 11 protection in
bankruptcy court. See Item 7. "Management's Discussion and Analysis of Financial
Condition and Results of Operations - Impact of Enron's Chapter 11 Filing on Our
Business" and Item 13. "Certain Relationships and Related Transactions." The
Partnership policy committee consists of three members, each of whom has been
appointed by one of our general partners. See Item 10. "Partnership Management."

Our operations are comprised of the following segments:

o Interstate Natural Gas Pipelines

o Natural Gas Gathering and Processing

o Coal Slurry Pipeline

For information about our operating segments and geographic areas, see
Note 13 to the Consolidated Financial Statements.

INTERSTATE NATURAL GAS PIPELINES

Our interstate pipelines segment provides natural gas transmission
services in the midwestern United States.

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Northern Border Pipeline and Midwestern Gas Transmission transport gas
for shippers under tariffs regulated by the Federal Energy Regulatory Commission
("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 the related
natural gas commodity risk.

The pipeline systems are operated by Northern Plains pursuant to
operating agreements. Northern Plains employs approximately 230 individuals
located at our headquarters in Omaha, Nebraska, and at various locations near
the pipelines. Northern Plains' employees are not represented by any labor union
and are not covered by any collective bargaining agreements.

NORTHERN BORDER PIPELINE SYSTEM

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 with various natural gas
markets. In the year ended December 31, 2001, 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
90% 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 PipeLines Limited
("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

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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
designed to transport 2,374 million cubic feet per day ("mmcfd") from the
Canadian border to Ventura, Iowa; 30-inch diameter pipe and 36-inch diameter
pipe, each approximately 147 miles in length, designed to transport 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 designed to transport 844 mmcfd from
Harper, Iowa to Manhattan, Illinois (Chicago area); and 35 miles of 30-inch
diameter pipe designed to transport 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.

On October 1, 2001, Northern Border Pipeline completed construction and
began operation of its Project 2000 facilities. Project 2000 gives shippers
access to industrial natural gas consumers in northern Indiana through an
interconnect with Northern Indiana Public Service Company, a major midwest local
distribution company, at the terminus near North Hayden, Indiana and provides
545 mmcfd of transportation capacity. Project 2000 also expands Northern Border
Pipeline's delivery capability into the Chicago area by approximately 30%.
Capital expenditures for Project 2000 are approximately $63 million. Project
2000 facilities include approximately 35 miles of 30-inch pipeline, one 13,000
horsepower compressor station in Illinois, additional horsepower at two Iowa
compressor stations and one meter station.

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, as well as the Williston Basin in the United States.
The pipeline system also has access to synthetic gas produced at the Dakota
Gasification plant in North Dakota. At its northern end, the pipeline system's
gas supplies are received through an interconnection with TransCanada's
majority-owned Foothills Pipe Lines (Sask.) Ltd. system in Canada, which is
connected to TransCanada's Alberta system and the pipeline system owned by
Transgas Limited in Saskatchewan. The pipeline system also connects with
facilities of Williston Basin Interstate Pipeline at Glen Ullin and Buford,
North Dakota, facilities of Amerada Hess Corporation at Watford City, North
Dakota and facilities of Dakota Gasification Company at Hebron, North Dakota in
the northern portion of the pipeline system. For the year ended December 31,
2001, of the natural gas transported on the pipeline system, approximately 90%
was produced in Canada, approximately 5% was produced by the Dakota Gasification
plant and approximately 5% was produced in the Williston Basin.

To access markets, the pipeline system interconnects with pipeline
facilities of:

o Northern Natural Gas Company, an Enron subsidiary until
February 1, 2002, and now a subsidiary of Dynegy, Inc., at
Ventura, Iowa as well as multiple smaller interconnections in
South Dakota, Minnesota and Iowa;

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

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

The Ventura, Iowa interconnect with Northern Natural Gas Company
functions as a large market center, where natural gas transported on the
pipeline system is sold, traded and received for transport to significant
consuming markets in the Midwest and to interconnecting pipeline facilities
destined for other markets.

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, 2001, 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, 2001, the termination dates of these contracts ranged from March
31, 2002 to December 21, 2013, and the weighted average contract life, based
upon annual contractual obligations, was approximately five and one-half years
with just under 99% of capacity contracted through mid-September 2003. Contracts
for approximately 42% of the capacity will expire prior to November 1, 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 its 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 for the capacity temporarily released to it. Shippers on
the pipeline system temporarily released capacity during 2001 for varying
periods of time. There were also permanent releases of capacity to other
shippers for the full term of the contracts.

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As of December 31, 2001, the largest shipper, Mirant Americas Energy
Marketing, LP, is obligated for approximately 33.7% of the contracted firm
capacity. Of this amount, 24.4% of Northern Border Pipeline's contracted firm
capacity was obtained under temporary releases from Pan-Alberta Gas (U.S.)
("Pan-Alberta") for a term through October 2002. Pan-Alberta's firm contracts
expire October 31, 2003. Mirant Americas Energy Marketing, LP, manages the
assets of Pan-Alberta Gas, Ltd., which include Pan-Alberta's contracts with
Northern Border Pipeline.

Some of the shippers are affiliated with the general partners of
Northern Border Pipeline. Enron North America Corp. ("ENA"), a subsidiary of
Enron, which also has filed for bankruptcy protection, holds firm contracts
representing 3.5% of capacity, a portion of which (1.1%) has been temporarily
released to a third party until October 31, 2002. The third party that holds the
1.1% of capacity has filed a complaint with the FERC requesting, in effect, that
its contract be deemed terminated as a consequence of ENA's filing for
bankruptcy protection. We believe this shipper's contract will remain in effect
until October 31, 2002. ENA's contractual obligations were supported by a
guaranty from Enron. Transcontinental Gas Pipe Line Corporation, a subsidiary of
Williams, holds a contract representing 0.7% of capacity. See Item 7.
"Management's Discussion and Analysis of Financial Condition and Results of
Operations - Impact of Enron's Chapter 11 Filing On Our Business" and Item 13.
"Certain Relationships and Related Transactions."

MIDWESTERN GAS TRANSMISSION SYSTEM

Effective May 1, 2001, we acquired Midwestern Gas Transmission from El
Paso Corporation for approximately $102 million. The Midwestern Gas Transmission
system extends 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
Tennessee to the north. There are six compressor stations capable of generating
70,170 horsepower.

The Midwestern Gas Transmission system connects with multiple pipeline
systems that provide its shippers access to various markets served by those
pipelines. Because of its position in the U.S. grid, Midwestern Gas Transmission
is configured to receive gas volumes at both ends of its system. In the north
end, Midwestern Gas Transmission can receive gas from ANR Pipeline Company,
Northern Border Pipeline, Natural Gas Pipeline Company of America and Alliance
Pipeline. The southern end of the system has an interconnection with Tennessee
Gas Transmission at Portland. Additionally, Midwestern Gas Transmission has
interconnections with four interstate pipelines in Kentucky, Indiana and
Illinois.

The Midwestern Gas Transmission system serves 30 firm transportation
shippers. Based upon shipper contractual obligations as

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of December 31, 2001, approximately 49% of the firm transportation capacity is
contracted by local distribution companies, 49% by marketers and two percent by
end users.

Based upon the proportionate share of capacity, two shippers account
for approximately 60% of the capacity. They are Northern Illinois Gas Company
(38.4%) and PSI Energy Inc. (20.9%).

As of December 31, 2001, the termination dates of Midwestern Gas
Transmission's firm transportation contracts ranged from March 31, 2002 to
October 31, 2019. The weighted average contract life, based upon annual contract
obligations, was approximately three and one-half years.

One shipper, ENA, which has filed for bankruptcy protection, is
affiliated with our general partners. ENA holds 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 -
Impact of Enron Bankruptcy On Our Business" and Item 13. "Certain Relationships
and Related Transactions."

DEMAND FOR INTERSTATE PIPELINE TRANSPORTATION CAPACITY

The interstate pipelines' long-term financial condition 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 and other facilities that permit natural gas to be produced and
delivered to pipelines that interconnect with the interstate pipelines' systems.
Low prices for natural gas, regulatory limitations or the lack of available
capital for these projects could adversely affect the development of additional
reserves and production, gathering, storage and pipeline transmission of 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 Northern Border Pipeline.

The interstate pipelines' business also depends on the level of demand
for natural gas in the markets the pipeline systems serve. 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 the pipeline systems to meet demand in the markets that the
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;

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o climatic conditions;

o government regulation; and

o technological advances in fuel economy and energy generation devices.

Interstate pipelines' primary exposure to market risk occurs at the
time existing transportation contracts expire and are subject to renegotiation.
A key determinant of the value that customers can realize from firm
transportation on the pipelines 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 level of demand charges customers
are willing to commit to 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 the interstate pipeline systems or how significant
that adverse effect could be.

INTERSTATE PIPELINE COMPETITION

Northern Border Pipeline competes 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. Its competitive
position is affected by the availability of Canadian natural gas for export, the
availability of other sources of natural gas and demand for natural gas in the
United States. Demand for transportation services on Northern Border Pipeline's
system is affected by natural gas prices, the relationship between export
capacity from and production in the western Canadian sedimentary basin, and
natural gas shipped from producing areas in the United States. Shippers of
natural gas produced in the western Canadian sedimentary basin also have other
options to transport Canadian natural gas to the United States, including
transportation on pipelines eastward in Canada or to markets on the West Coast.

The Alliance Pipeline, which was placed in service in December 2000,
competes directly with Northern Border Pipeline in the transportation of natural
gas from the western Canadian sedimentary basin to the Chicago area. Williams
has a minority interest (14.6%) in Alliance Pipeline. 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

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States. Vector Pipeline L.P., which interconnects with the Alliance Pipeline and
transports gas eastward to a terminus in eastern Canada, commenced operations in
December 2000. Guardian Pipeline proposes to be in service in November 2002 and
to interconnect with Northern Border Pipeline. Guardian Pipeline is targeting
markets in northern Illinois and Wisconsin and could provide access to
additional markets for Northern Border Pipeline's shippers.

The Alliance Pipeline has also brought about increased supply access
for Midwestern Gas Transmission customers. The Alliance Pipeline receipt point
into the Midwestern Gas Transmission system near Joliet, Illinois provided
anywhere from ten to thirty percent of the daily needs of Midwestern Gas
Transmission customers during 2001.

TransCanada PipeLines Limited and other unaffiliated companies own and
operate pipeline systems that transport natural gas from the same natural gas
reserves in western Canada that supply Northern Border Pipeline's shippers.

Natural gas is produced in the United States and is also transported by
competing pipeline systems to the same markets as those served by the 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 under
Section 8.

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,

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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
gas tariffs.

Under the tariffs, interstate pipelines are allowed to charge for their
services on the basis of stated transportation rates established in their rate
cases. The tariffs also allow the interstate pipelines to provide services under
negotiated and discounted rates. For our interstate pipelines, approximately 98%
of the agreed upon cost of service or revenue level is attributed to demand
charges. 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. The remaining 2%
of the agreed upon revenue level is attributed to commodity charges based on the
volumes of gas actually transported. Under the terms of settlement in 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
is under no obligation to file a new rate case. Prior to any new 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. 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 FERC, the interstate
pipelines continue to depreciate their transmission plant at FERC approved
depreciation rates. For Northern Border Pipeline, the annual depreciation rate
on transmission plant in service is 2.25% and for Midwestern Gas Transmission,
the annual depreciation rate on transmission plant in service is 1.9%. In order
to avoid a decline in transportation rates set in future rate cases as a result
of accumulated depreciation, the interstate pipelines must maintain or increase
their 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 recent FERC
rulings. In those rulings, the FERC held that an interstate pipeline is not
entitled to a tax allowance for income attributable to limited partnership
interests held by individuals. The settlement of 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 of $31 million
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.

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The 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. In addition, Northern Border Pipeline is permitted to
retain revenue from interruptible transportation service to offset any
decontracted firm capacity. Midwestern Gas Transmission does not share revenue
from its interruptible transportation service with its firm shippers.

After October 31, 2003, all revenues from interruptible and other new
transportation service for Northern Border Pipeline will no longer be subject to
sharing and thus will be retained by Northern Border Pipeline. During 2001,
Northern Border Pipeline and Midwestern Gas Transmission filed and received
approval to implement several new services. The interstate pipelines intend to
continue to develop other new services to meet customer needs and seek the
FERC's authorization to implement such services. Revenues from these sources are
expected to be minimal for the near term.

The 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 Regulation
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.

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 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.

On March 30, 2001, we completed our purchase of Bear Paw Energy for
approximately $381.7 million, paid with 5.7 million of our common units valued
at $183 million and $198.7 million in cash. 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 four processing
plants with 90 mmcfd of capacity.

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Following the acquisition, Bear Paw Energy's Powder River Basin
gathering activities in northeastern Wyoming were integrated with those of our
wholly-owned subsidiary, Crestone Gathering Services, L.L.C. ("Crestone
Gathering"). Bear Paw Energy and Crestone Gathering have approximately 1,100
miles of high and low pressure gathering pipelines, approximately 71 compressor
stations with approximately 114,000 installed horsepower and long-term
volumetric contracts with producers covering approximately 300,000 acres of
dedicated reserves in the Powder River Basin.

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.
("Bighorn"), a 33.33% interest in Fort Union Gas Gathering, L.L.C. ("Fort
Union") and a 35% interest in Lost Creek Gathering, L.L.C. ("Lost Creek"), 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 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. During the fourth quarter of 2001, Fort Union completed an
expansion, increasing its capacity such that it now 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 106 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. 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 interest 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 and Crestone Gathering'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

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pipeline and 28 compressor stations with a total rated horsepower of 28,378, in
addition to plant compression of 19,163 horsepower. Most of the wells connected
to the facilities produce casinghead gas in association with crude oil, which
Bear Paw Energy does not purchase. This gas is generally high in natural gas
liquids ("NGLs") content. The NGLs are separated from the gas at our processing
plants and this mix may then be sold or fractionated into components and then
sold, depending on market conditions. 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 delivery 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
gross proceeds realized.

NBP Services Corporation, an Enron subsidiary, provides administrative
services for us and operating services for Bear Paw Energy and Crestone Energy
Ventures. NBP Services Corporation has approximately 170 employees and utilizes
employees of its affiliates to provide these services.

In April of 2001, we acquired interests in the midstream business in
Canada. Our subsidiary, Border Midstream Services, Ltd. ("Border Midstream")
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 associated gathering pipelines. Sour gas processing involves the
removal of high quantities of sulphur from the gas stream. These associated
pipelines consist of 115 miles of gathering systems. The Gladys Plant is a sour
gas processing plant with 10 mmcfd of capacity. The Gregg Lake/Obed Pipeline is
comprised of 85 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., 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. 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.

The major customers of Border Midstream are Compton, Conoco, and Mobil.
They account for approximately 65%, 12% and 8% of the Mazeppa revenue stream,
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

12

and Wind River Basins of Wyoming are affiliates of Western Gas Resources,
Thunder Creek Gas Gathering, El Paso Field Services and Bighorn. 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 currently two gas plants in the
general vicinity of Border Midstream's plants. The Crestar Vulcan plant is
approximately 30 miles from Mazeppa/Gladys and has processing capabilities of
approximately 56 mmcfd. The Esso Quirk Creek plant is approximately 30 miles
from Mazeppa/Gladys. 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 drilling may be impacted by the ability of gas producers to
obtain and maintain the necessary drilling and production permits in a timely
and economic manner, as well as commodity prices. In the Powder River Basin, 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.

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 Company ("Black Mesa"), 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

13

pipeline is fully contracted to 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
been willing to agree to continued use of water after December 31, 2005. If
efforts by the Mohave Plant 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.

Approximately 58 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. Black Mesa's collective bargaining agreement with the United
Mineworkers of America was renewed for an additional year in February 2002.

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, 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.

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:
Energy Resources Conservation Act, Oil and Gas Conservation Act, Pipeline Act,
and 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 payment of
penalties in the amount of $128,000 for alleged violations of federal and state
law due to discharges of coal slurry on 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. We
believe that three of those incidents give rise to the stipulated penalties
agreed to in the Consent Decree. The estimated amount of the penalties is
$30,000. Black Mesa also has received and responded to a request for information
from the EPA.

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
costs and liabilities to us. If we are unable to recover such resulting costs,
earnings and cash distributions could be adversely affected.

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ITEM 2. PROPERTIES

Northern Border Pipeline and Midwestern Gas Transmission 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 certain of the compressor stations, meter
stations, pipeline field office sites, and microwave tower sites; 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, Crestone Gathering, 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.

Border Midstream's systems are used for gathering, compressing and
processing of natural gas in the Province of Alberta, Canada.

15

Border Midstream holds the right, title and interest in their gathering and
processing facilities, which consist of 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.

Black Mesa holds grant of right of way from private landowners as well
as The Navajo Nation and the Hopi Tribe. These right-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.
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.

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 Reservation. Based on recent
decisions by the federal courts and other defenses, we believe that the Tribes
do not have authority to impose the tax and that the lawsuit will not have a
material adverse impact on the Partnership.

See Item 1. "Business - Environmental and Safety Matters" for the
discussion on the Consent Decree entered against Black Mesa.

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
2001.

16

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 1, 2002, there were approximately 1,600 record holders of
common units and approximately 68,200 beneficial owners of the common units,
including common units held in street name. On March 21, 2002, the last reported
sale price of our common units on the New York Stock Exchange was $39.09 per
common unit.

We currently have 41,623,014 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 16, 2002, we declared a
distribution of $0.80 per unit ($3.20 per unit on an annualized basis), payable
February 14, 2002 to the general partners and unitholders of record at January
31, 2002.

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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.

- ----------

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

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

(3) Includes results of operations for Crestone Energy Ventures and Crestone
Gathering since date of acquisition in September 2000.

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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 generally accepted accounting principles for
nonregulated entities. 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 extraordinary retirements or sales. The original cost of utility
property retired is charged to accumulated depreciation and amortization, net of
salvage and cost of removal. With respect to our acquisitions made in 2000 and
2001, the excess of our purchase price over the fair value of the net assets
acquired or goodwill is being amortized over 30 years. The accounting for
goodwill will change for us in 2002 due to our adoption of SFAS No. 141,
"Business Combinations," and SFAS No. 142, "Goodwill and Other Intangible
Assets." Finally, our accounting for financial instruments follows SFAS No. 133,
"Accounting for Derivative Instruments and Hedging Activities," which we adopted
on January 1, 2001.

19

RESULTS OF OPERATIONS

YEAR ENDED DECEMBER 31, 2001 COMPARED WITH THE YEAR ENDED DECEMBER 31, 2000

Our operating results for 2001 were significantly influenced by the
acquisitions we made in the first half of 2001 and improved performance by
Northern Border Pipeline. Our net income before extraordinary items increased
$12.3 million (16%) for the year ended December 31, 2001, as compared to the
same period in 2000. Net income from our new acquisitions totaled $22.3 million
in 2001. Primarily as a result of borrowings made to fund our acquisitions, the
Partnership's interest expense increased approximately $18.5 million in 2001 as
compared to 2000. Our share of Northern Border Pipeline's net income increased
$9.4 million in 2001 as compared to 2000. Northern Border Pipeline's operating
results benefited from reductions in interest rates, which reduced its interest
expense for 2001 as compared to 2000. Northern Border Pipeline was also able to
control its operating costs resulting in reductions to operations and
maintenance expenses. Although our net income increased between years, our net
income per unit decreased from $2.50 per unit in 2000 to $2.12 per unit for 2001
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.

Operating revenues, net increased $121.7 million (36%) for the year
ended December 31, 2001, as compared to the same period in 2000. Operating
revenues from the gas gathering and processing businesses increased $109.3
million primarily due to the businesses acquired in 2001. Operating revenues
from the interstate pipelines increased $11.6 million due primarily to $9.5
million of revenues from Midwestern Gas Transmission acquired effective May
2001. Operating revenues for Northern Border Pipeline increased $2.1 million for
the year ended December 31, 2001, as compared to the same period in 2000,
primarily due to additional revenues associated with the completion of Project
2000 in October 2001. See Item 1. "Business - Interstate Natural Gas Pipelines -
Northern Border Pipeline System."

Product purchases of $39.7 million recorded in 2001 represent amounts
incurred by Bear Paw Energy. In conjunction with its gathering and processing
activities, Bear Paw Energy receives the natural gas stream from producers. Upon
sale of the natural gas liquids and residue that it processes in its facilities,
Bear Paw Energy pays the producers based upon a percentage of the gross
proceeds.

Operations and maintenance expense increased $34.4 million (55%) for
the year ended December 31, 2001, as compared to the same period in 2000.
Operations and maintenance expense for the gas gathering and processing segment
increased $38.1 million, primarily due to the businesses acquired in 2001.
Operations and maintenance expense from the interstate pipelines decreased $4.7
million due primarily to a decrease in Northern Border Pipeline's expense by
$7.9 million (19%) 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 Northern Border Pipeline's regulatory
commission expense, decreased costs to operate two of its electric-powered
compressor units and decreased employee payroll, benefit and administrative
expenses for the pipeline. Operations and maintenance expense for 2001 includes
approximately $8.8 million of bad debt expense related to ENA. See "Impact of
Enron's Chapter 11 Filing On Our Business" and Item 13. "Certain Relationships
and Related Transactions."

20

Depreciation and amortization expense increased $15.6 million (26%) for
the year ended December 31, 2001, as compared to the same period in 2000.
Depreciation and amortization expense from the gas gathering and processing
segment increased $13.9 million, primarily due to businesses acquired in 2001.
Depreciation and amortization expense from the interstate pipelines increased
$2.5 million due primarily to $2.3 million of expense from Midwestern Gas
Transmission. Depreciation and amortization expense in 2001 and 2000 includes
goodwill amortization of $7.0 million and $0.5 million, respectively. See "New
Accounting Pronouncements" below for discussion of a recently issued accounting
pronouncement that will impact goodwill amortization in 2002.

Taxes other than income decreased $0.6 million (2%) for the year ended
December 31, 2001, as compared to the same period in 2000, due primarily to a
decrease in Northern Border Pipeline's expense by $2.3 million (8%) offset by
$1.4 million of expense from the gas gathering and processing segment. The
decrease in Northern Border Pipeline's taxes other than income is due primarily
to a decrease in use taxes paid to the state of Minnesota. Northern Border
Pipeline had been paying Minnesota a use tax based on the fuel used at its
compressor stations located in the state. A recent ruling by the Minnesota
Supreme Court directed that the compressor fuel used was exempt from this
particular tax. Northern Border Pipeline filed for a refund of amounts
previously paid and received the refund in March 2002.

Consolidated interest expense increased $8.4 million (10%) for the year
ended December 31, 2001, as compared to the same period in 2000. Interest
expense for the Partnership increased approximately $18.5 million (126%) for the
year ended December 31, 2001, as compared to the same period in 2000, due to
additional borrowings. In June 2000 and September 2000, the Partnership issued
$250 million of 8 7/8% Senior Notes, and in March 2001, the Partnership issued
$225 million of 7.10% Senior Notes. The additional borrowings were made
primarily for the acquisition of gas gathering and processing businesses during
2000 and the acquisitions made in March 2001 and April 2001 (see Item 1.
"Business"). Interest expense attributable to Northern Border Pipeline decreased
$9.8 million (15%) for the year ended December 31, 2001, as compared to the same
period in 2000, due primarily to a decrease in Northern Border Pipeline's
average interest rate between 2000 and 2001 as well as a decrease in average
debt outstanding.

Other income decreased $7.9 million for the year ended December 31,
2001, as compared to the same period in 2000. Other income for 2001 includes a
net 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. 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. Also
included for 2001 are non-recurring charges of $2.4 million, primarily related
to a loss on a forward purchase of Canadian dollars to fund the acquisition of
gathering and processing assets in Alberta, Canada. Equity earnings (losses) in

21

unconsolidated affiliates increased $2.3 million to $1.7 million for 2001 as
compared to 2000. Goodwill amortization netted against equity earnings (losses)
in unconsolidated affiliates totaled $6.3 million and $2.2 million in 2001 and
2000, respectively. See "New Accounting Pronouncements" below for discussion of
a recently issued accounting pronouncement that will impact goodwill
amortization in 2002.

The extraordinary loss from debt restructuring of $1.2 million recorded
in the year ended December 31, 2001, relates to Black Mesa's 10.7% Secured
Senior Notes. In June 2001, the Partnership repaid Black Mesa's 10.7% Secured
Senior Notes due in 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.

Minority interests in net income increased $4.0 million (11%) for the
year ended December 31, 2001, as compared to the same period in 2000, due to
increased net income for Northern Border Pipeline.

YEAR ENDED DECEMBER 31, 2000 COMPARED WITH THE YEAR ENDED DECEMBER 31, 1999

Operating revenues, net increased $20.8 million (7%) for the year ended
December 31, 2000, as compared to the same period in 1999. Operating revenues
attributable to Northern Border Pipeline were $311.0 million for the year ended
December 31, 2000, as compared to $298.3 million for the same period in 1999, an
increase of $12.7 million (4%). Northern Border Pipeline's operating revenues
for 2000 reflect the significant terms of the rate case settlement discussed in
Item 1. "Business - Interstate Natural Gas Pipelines - Interstate Pipeline
Regulation." Operating revenues for 1999 were determined under Northern Border
Pipeline's former cost of service tariff. Operating revenues from Crestone
Energy Ventures were $7.5 million for 2000, which represented three months of
activity. Crestone Energy Venture's operating results occurred in the fourth
quarter of 2000 after its acquisition by the Partnership in late September 2000.

Operations and maintenance expense increased $8.6 million (16%) for the
year ended December 31, 2000, from the same period in 1999, due primarily to
$5.1 million of expense from Crestone Energy Ventures. Operations and
maintenance expense attributable to Northern Border Pipeline increased $2.8
million (7%) for the year ended December 31, 2000, from the same period in 1999,
due primarily to increased employee payroll and benefit expenses and costs to
operate two electric-powered compressor units.

Depreciation and amortization expense increased $5.9 million (11%) for
the year ended December 31, 2000, as compared to the same period in 1999.
Depreciation and amortization expense attributable to Northern Border Pipeline
increased $5.4 million (10%) for the year ended December 31, 2000, as compared
to the same period in 1999, due primarily to an increase in the depreciation
rate applied to transmission plant. As a result of the rate case settlement,
Northern Border Pipeline used a depreciation rate for transmission plant of
2.25% for 2000. Northern Border Pipeline had used a depreciation rate of 2.0%
for 1999.

22

Taxes other than income decreased $2.3 million (7%) for the year ended
December 31, 2000, as compared to the same period in 1999, due primarily to
adjustments to Northern Border Pipeline's previous estimates of ad valorem
taxes.

Interest expense, net increased $13.8 million (20%) for the year ended
December 31, 2000, as compared to the same period in 1999. Interest expense for
the Partnership increased approximately $9.2 million (167%) for the year ended
December 31, 2000, as compared to the same period in 1999, due to additional
borrowings and an increase in interest rates. The additional borrowings were
made primarily for the acquisition of gas gathering businesses in the Powder
River and Wind River basins in Wyoming in December 1999, June 2000 and September
2000. Interest expense attributable to Northern Border Pipeline increased $4.9
million (8%) for the year ended December 31, 2000, as compared to the same
period in 1999, due primarily to an increase in average interest rates between
1999 and 2000. The impact of the increase in interest rates was partially offset
by a decrease in average debt outstanding.

Other income increased $3.5 million (76%) for the year ended December
31, 2000, as compared to the same period in 1999. Other income attributable to
Northern Border Pipeline increased $6.7 million (491%) for the year ended
December 31, 2000, as compared to the same period in 1999, due primarily to a
reduction in reserves previously established for regulatory issues as a result
of the settlement of Northern Border Pipeline's rate case. The 1999 results
included $3.0 million of other non-recurring income for the Partnership.

Minority interests in net income increased $2.6 million (7%) for the
year ended December 31, 2000, as compared to the same period in 1999, due to
increased net income for Northern Border Pipeline.

LIQUIDITY AND CAPITAL RESOURCES

SUMMARY OF CERTAIN CONTRACTUAL OBLIGATIONS AND COMMERCIAL COMMITMENTS

We have guaranteed the performance of our unconsolidated affiliates in
connection with their credit agreements that expire in

23

March 2009 and September 2009. At December 31, 2001, the combined guarantee was
$4.4 million.

DEBT AND CREDIT FACILITIES AND ISSUANCE OF COMMON UNITS

Northern Border Pipeline had previously entered into a 1997 credit
agreement ("Pipeline Credit Agreement") with certain financial institutions,
which is comprised of a $100 million five-year revolving credit facility and a
$272 million term loan, both maturing in June 2002. At December 31, 2001, no
amounts were outstanding under the five-year revolving credit facility. Northern
Border Pipeline anticipates refinancing the Pipeline Credit Agreement in the
second quarter of 2002. Northern Border Pipeline's refinancing plans are to
issue $225 million of senior notes and to enter into a $175 million revolving
credit facility.

At December 31, 2001, Northern Border Pipeline also had outstanding
$143 million of senior notes issued in a $250 million private placement under a
July 1992 note purchase agreement. The note purchase agreement provides for four
series of notes, Series A through D, maturing between August 2000 and August
2003. The Series A Notes with a principal amount of $66 million and Series B
Notes with a principal amount of $41 million were repaid in August 2000 and
August 2001, respectively. The Series C Notes with a principal amount of $78
million mature in August 2002. Northern Border Pipeline anticipates borrowing on
the refinanced Pipeline Credit Agreement to repay the Series C 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") and in August 1999, Northern Border Pipeline completed a private
offering of $200 million of 7.75% Senior Notes due 2009 ("1999 Pipeline Senior
Notes"). Both the 2001 Pipeline Senior Notes and the 1999 Pipeline Senior Notes
were subsequently exchanged in a registered offering for notes with
substantially identical terms. The indentures under which the 2001 Pipeline
Senior Notes and 1999 Pipeline Senior Notes were issued does 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 2001 Pipeline Senior Notes and 1999 Pipeline
Senior Notes were used to reduce indebtedness outstanding under the Pipeline
Credit Agreement.

In November 2001, Northern Border Pipeline entered into forward
starting interest rate swaps with notional amounts totaling $150 million related
to the planned issuance of senior notes discussed previously. The swaps were
entered into to hedge the fluctuations in Treasury rates and spreads between the
execution date of the swaps and the issuance date of the senior notes.

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

24

subsequently exchanged in registered offerings for notes with substantially
identical terms. The indentures under which the 2001 Partnership Senior Notes
and 2000 Partnership Senior Notes were issued do not limit the amount of
unsecured debt the Partnership may incur, but they do contain material financial
covenants, including restrictions on incurrence of secured indebtedness. The
indentures also contain provisions that would require the Partnership to offer
to repurchase the 2001 and 2000 Partnership Senior Notes, if either Standard &
Poor's Rating Services or Moodys' Investor Services, Inc. ("Moodys") rate the
notes as below investment grade. In February 2002, Moodys placed Northern Border
Pipeline and us on credit review for a possible downgrade in credit rating. At
this time, no action has been taken by Moodys. If Moodys was to issue the
downgrade, we expect our credit rating to remain above investment grade. The
proceeds from the 2001 Partnership Senior Notes were used to fund a portion of
the acquisition of Bear Paw Energy. The proceeds from the 2000 Partnership
Senior Notes were used to fund acquisitions made by the Partnership in June 2000
and September 2000.

The Partnership entered into a $200 million three-year revolving credit
agreement with certain financial institutions ("2001 Partnership Credit
Agreement") in March 2001. The 2001 Partnership Credit Agreement is to be used
for capital expenditures, acquisitions and general business purposes. The 2001
Partnership Credit Agreement replaced revolving credit agreements entered into
in June 2000. At December 31, 2001, $64.0 million was outstanding under the 2001
Partnership Credit Agreement.

In the third quarter of 2001, the Partnership entered into interest
rate swap agreements with notional amounts totaling $225 million that expire in
March 2011. 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 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.

In April and May of 2001, the Partnership sold 407,550 and 4,000,000
common units, respectively. In conjunction with the issuance of the additional
common units, including the units issued for Bear Paw Energy in March 2001, the
Partnership's general partners made capital contributions to the Partnership to
maintain a 2% general partner interest in accordance with the partnership
agreements. The net proceeds of the sale of common units and the general
partners' capital contributions totaled approximately $172.2 million and were
primarily used to repay amounts borrowed under the 2001 Partnership Credit
Agreement.

In November 2000, the Partnership sold 2,156,250 common units. In
conjunction with the issuance of the additional common units, the Partnership's
general partners made capital contributions to the Partnership to maintain a 2%
general partner interest in accordance with the partnership agreements. The net
proceeds of the public offering and the general partners' capital contribution
totaled approximately $60.7 million and were primarily used to repay amounts
borrowed under revolving credit agreements.

25

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

CASH FLOWS FROM OPERATING ACTIVITIES

Cash flows provided by operating activities increased $64.3 million to
$233.9 million for the year ended December 31, 2001, as compared to the same
period in 2000. Net income to partners before depreciation and amortization
increased $26.7 million primarily due to our gas gathering and processing
businesses acquired in 2001 and the fourth quarter of 2000. Other cash flows
from operating activities for 2001 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 provided by operating activities decreased $3.8 million to
$169.6 million for the year ended December 31, 2000, as compared to the same
period in 1999, primarily due to reduced earnings from higher interest costs.
During 2000, we realized net cash inflows of approximately $2.4 million related
to Northern Border Pipeline's rate case, which included $25.1 million of amounts
collected subject to refund less estimated refunds issued in late December 2000
totaling approximately $22.7 million.

CASH FLOWS FROM INVESTING ACTIVITIES

Capital expenditures of $126.4 million for the year ended December 31,
2001 include $69.1 million for gas gathering and processing facilities and $57.0
million for interstate pipeline facilities. The expenditures for interstate
pipeline facilities include $49.0 million for Northern Border Pipeline's Project
2000 (see Item 1. "Business - Interstate Natural Gas Pipelines - Northern Border
Pipeline System"). For the same period in 2000, total capital expenditures were
$19.7 million, which included $7.4 million for Project 2000 and $3.8 million for
gas gathering facilities for Crestone Energy Ventures.

Acquisitions of businesses of $345.1 million for the year ended
December 31, 2001, represents acquisitions of Midwestern Gas Transmission and
midstream assets in Alberta, Canada in April 2001 and the cash portion of the
purchase price of Bear Paw Energy in March 2001. The purchase of Bear Paw Energy
also involved the issuance of 5.7 million common units valued at $183.0 million.
The acquisitions of businesses for the year ended December 31, 2000, included
the acquisition of gas gathering businesses in the Powder River and Wind River
basins in Wyoming for $229.5 million.

The investments in unconsolidated affiliates of $11.2 million for the
year ended December 31, 2001, primarily reflects capital

26

contributions to Bighorn. The investments in unconsolidated affiliates of $8.8
million for the year ended December 31, 2000 primarily 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, ENA agreed to
fund approximately $3.5 million of an equity investment in Lost Creek.

Total capital expenditures and investments in unconsolidated affiliates
for 2002 are estimated to be $86 million. Capital expenditures for the
interstate pipelines are estimated to be $25 million, including approximately
$12 million for Northern Border Pipeline. Northern Border Pipeline currently
anticipates funding its 2002 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 $49 million and
additional investments in unconsolidated affiliates are estimated to be $12
million for 2002. Funds required to meet the capital requirements for 2002 are
anticipated to be provided from debt borrowings, issuance of additional limited
partners interests in the Partnership and operating cash flows. The estimated
capital expenditures and investments do not include any amount for acquisitions
of assets that might become available for purchase during the year. If any such
acquisitions are made, our estimated capital requirements would be increased,
which we would anticipate funding from debt borrowings and the issuance of
additional limited partner interests in the Partnership.

CASH FLOWS FROM FINANCING ACTIVITIES

Cash flows provided by financing activities increased $129.3 million to
$230.1 million for the year ended December 31, 2001, as compared to the same
period in 2000. Cash distributions to the unitholders and the general partners
increased $40.5 million to $120.9 million. The increase is due to both an
increase in the number of common units outstanding and an increase in the
distribution rate. The distributions paid in 2001 were $2.99 per unit ($0.70 per
unit in the first quarter and $0.7625 per unit in the second, third and fourth
quarter) as compared to distributions paid in 2000 of $2.65 per unit ($0.65 per
unit in the first, second and third quarter and $0.70 per unit in the fourth
quarter). In January 2002, we increased our quarterly distribution rate to $0.80
per unit.

During the year ended December 31, 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 the
Pipeline 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 $47.3
million of indebtedness outstanding. Repayments of amounts borrowed under the
Pipeline Credit Agreement totaled $333.0 million during the year ended December
31, 2001, as compared to repayments of $45.0 million for the comparable period
in 2000. A significant portion of the 2001 payments on the Pipeline Credit
Agreements was made using proceeds from the 2001 Pipeline Senior Notes. In
August 2001 and

27

August 2000, Northern Border Pipeline repaid its Series B and A Notes of $41
million and $66 million, respectively, primarily by borrowing under the Pipeline
Credit Agreement.

For the year ended December 31, 2001, we recognized a decrease in bank
overdrafts of $22.4 million. At December 31, 2000, Northern Border Pipeline
reflected the bank overdrafts primarily due to rate case refund checks
outstanding. In March 2001, the Partnership paid approximately $4.3 million to
terminate 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 the 2001 Partnership Senior Notes and 2001 Pipeline
Senior Notes (see Note 7 - Notes to Consolidated Financial Statements).
Financing activities for 2001 reflect the issuance of partnership interests of
$172.2 million, which was primarily used to repay amounts borrowed on the 2001
Partnership Credit Agreement of $168.0 million.

Cash flows provided by financing activities were $100.8 million for the
year ended December 31, 2000 compared to cash flows used of $57.3 million for
the same period in 1999. Cash distributions to the unitholders and the general
partners increased $7.3 million to $80.4 million reflecting an increase in the
distribution from $2.44 per unit for 1999 to $2.65 per unit for 2000. The
proceeds from the private offering of the 2000 Partnership Senior Notes,
including premiums but net of associated debt discounts and issuance costs,
totaled approximately $252.0 million. The proceeds were used to repay the
Partnership's existing indebtedness of $119.5 million and to partially fund the
acquisition of gas gathering businesses discussed previously. The funding for
the remainder of the acquisition of gas gathering businesses came from
borrowings under Partnership credit agreements of $97.5 million. Financing
activities for 2000 reflect $60.7 million in net proceeds from the issuance of
2,156,250 common units and a related capital contribution by the Partnership's
general partners in November 2000. In December 2000, the Partnership received
approximately $15.0 million from the termination of interest rate swap
agreements. Repayments on the 2000 Partnership credit agreements of
approximately $71.2 million were primarily made using the proceeds from the
issuance of common units and the termination of the interest rate swap
agreements. For the year ended December 31, 2000, advances under the Pipeline
Credit Agreement, which were primarily used to repay $66 million of Series A
Notes, were $75 million as compared to advances of $90 million for the same
period in 1999, which were primarily used to finance a portion of the capital
expenditures for The Chicago Project. Financing activities for the year ended
December 31, 1999 included $197.4 million from the issuance of the Pipeline
Senior Notes, net of associated debt discounts and issuance costs, and $12.9
million from the termination of Northern Border Pipeline's interest rate forward
agreements. Payments on the Pipeline Credit Agreement were $45 million for the
year ended December 31, 2000, as compared to $263 million for the same period
1999. At December 31, 2000, we reflected bank overdrafts of approximately $22.4
million primarily due to Northern Border Pipeline's refund checks outstanding.

28

NEW ACCOUNTING PRONOUNCEMENTS

In the third quarter of 2001, the Financial Accounting Standards Board
issued SFAS No. 141, "Business Combinations," SFAS No. 142, "Goodwill and Other
Intangible Assets," SFAS No. 143, "Accounting for Asset Retirement Obligations"
and SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived
Assets." See Note 12 - Notes to Consolidated Financial Statements.

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 Williams. Northern Plains and
Pan Border were not among the Enron companies filing for Chapter 11 protection.

The business of Enron and its subsidiaries that have filed for
bankruptcy protection are currently being administered under the direction and
control of the bankruptcy court. An unsecured creditors committee has been
appointed in the Chapter 11 cases. The creditors committee is responsible for
general oversight of the bankruptcy case, and has the power, among other things,
to: investigate the acts, conduct, assets, liabilities, and financial condition
of the debtor, the operation of the debtor's business and the desirability of
the continuance of such business; participate in the formulation of a plan of
reorganization; and file acceptances or rejections to such a plan. Factors taken
into account by Enron in making its business decisions while in Chapter 11, may
include decisions with respect to its investment in Northern Plains 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, is a
party to shipper contracts obligating ENA to pay for 3.5% of Northern Border
Pipeline's capacity. Through October 31, 2002, ENA has temporarily released 1.1%
of this capacity to a third party. Although this third party has filed a
complaint with the FERC requesting, in effect, that its contract be deemed
terminated as a consequence of ENA's filing for bankruptcy protection, we
believe this shipper's contract will remain in effect until October 31, 2002.
ENA has not assumed or rejected these contracts, but its ability to use the
capacity has been suspended until it provides adequate assurance of credit
support. We estimate that Northern Border Pipeline has aggregate financial
exposure over the next 12 months of approximately $9 million of revenues under
its firm transportation contracts with ENA. We believe that failure by ENA to
perform its obligations under the firm transportation contracts will not have a
material adverse impact on our financial condition.

29

In addition, Bear Paw Energy entered into certain swap arrangements
with ENA to hedge risks of changes in commodity prices. These swaps were
terminated prior to December 31, 2001, and Bear Paw Energy recorded bad debt
expense of approximately $5.4 million. 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 2001, Bear
Paw Energy recorded approximately $1.4 million into earnings and expects to
record approximately $4.6 million into earnings in 2002.

Also, Crestone Energy Ventures provided gas and administrative services
to ENA under a Master Services Agreement. This agreement was terminated in
November 2001 for ENA's failure to pay approximately $2.1 million in fees.

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

Enron's filing for bankruptcy protection and related developments have
had other impacts on our business and management. Arthur Andersen LLP resigned
as our auditors, 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. Because of
Enron's indirect ownership interest in us, we are willing to comply with the
mandate of the subpoena in such a manner that may be determined by the Committee
on Governmental Affairs of the Senate of the United States.

POSSIBLE EFFECTS

While Northern Plains and Pan Border have not filed for Chapter 11
bankruptcy protection, their stock is owned by Enron, which is in bankruptcy. It
is possible that in the course of Enron's bankruptcy proceedings, Enron could
attempt to 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 current indication from Enron that they intend to sell the stock in
Northern Plains or Pan Border or cause such companies to file for bankruptcy
protection.

30

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. 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
Williams do not control, free of any liens, greater than 50% of general partner
percentages. 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
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. We
believe these administrative services could be readily obtained through other
sources.

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.

31

Other than the complaint against Northern Border Pipeline filed with
the FERC by the shipper with temporarily released capacity, we are not are not
aware of any claims made against us that arise out of the Enron bankruptcy
cases. We plan to continue to monitor developments at Enron, to continue 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. Growth in
our interstate pipelines is expected to occur primarily in market areas we serve
through incremental projects supported by long-term contracts. Project 2000, our
recently completed extension into Indiana, is a good example. This project,
completed on time and well under budget, connects Northern Border Pipeline
directly to a large Chicago-area gas distribution company (Northern Indiana
Public Service Company) and to industrial gas consumers in northern Indiana. We
also intend to continue to expand the marketing of new services to meet our
customers' needs. Depending on natural gas prices and gas development
activities, selected opportunities to connect new sources of supply to our
interstate pipelines may arise. We are currently working with producers and
marketers to develop the contractual support for a new 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 Joliet Compression Project will provide the opportunity 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.

In 2002, Northern Border Pipeline will begin contract extension
discussions with customers for contracts that will expire prior to November 1,
2003, which represents approximately 42% of its system capacity. 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 of late,
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. We can begin this process during a
period that extends from 6 to 18 months before the termination date of the
contract. The

32

commencement of any bidding negotiations and the market conditions affecting the
value of transportation on the pipeline. 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
negotiated rate contracts involving charges established on the basis of
Canadian-midwestern U.S. gas price differentials or other factors.

NATURAL GAS GATHERING AND PROCESSING

We also are aggressively 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 basins. 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 and water-discharge permitting,
we expect 50 to 70 percent growth in aggregate gathered volumes on our Powder
River systems (Bear Paw Energy, Bighorn and Fort Union) during 2002. 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 the nature
of and 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 decline and provide solid growth in revenues and further improve cost
efficiencies due to the increased scale and scope of our gathering and
processing operations.

ACQUISITIONS

Finally, our objective is to continue to acquire complementary
businesses. Our goal is approximately $200 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

33

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 - Impact of Enron's Chapter 11
Filing On Our Business";

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

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

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

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

o Any customer's failure to perform its contractual obligations
could adversely impact our cash flows and financial condition.
ENA has 3.5% of Northern Border Pipeline's firm capacity and
less than 1% of Midwestern Gas Transmission's firm capacity and
has failed to pay its demand and any applicable commodity
charges due for November 2001 transport and thereafter. ENA has
neither assumed nor rejected its contracts and its ability to
use the capacity has been suspended. Until ENA assumes or
rejects its contracts, Northern Border Pipeline and Midwestern
Gas Transmission are unable to recontract all or a portion of
this capacity on a longer-term basis. See "Impact of Enron's
Chapter 11 Filing On Our Business" above.

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 it provides 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. See "Impact of
Enron's Chapter 11 Filing On Our Business" above.

o Contracts representing approximately 42% of Northern Border
Pipeline's system capacity will expire prior to November 1,
2003. 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

34

gas in our market areas and the basis differential between the
receipt and delivery points on our system. See "Outlook" above
and Item 1. "Business - 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 We face competition from third parties in our natural gas
transportation, gathering and processing businesses. See Item 1.
"Business - Interstate Pipeline Competition" and "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."

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.
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, 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."

35

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

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 to fund our acquisition of
Canadian midstream assets, we have not used financial instruments in the
management of exchange rates.

36

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. As of December 31, 2001, approximately 60% of our debt
portfolio is in fixed rate debt.

If average interest rates change by one percent compared to rates in
effect as of December 31, 2001, consolidated annual interest expense would
change by approximately $5.6 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, 2001.

COMMODITY PRICE RISK

Our gas gathering and processing businesses are subject to certain
contracts that give it 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. For
each $0.10 per mcf 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 $0.4 million. This amount has been determined by considering the
impact of the hypothetical commodity prices on our projected gathering and
processing volumes for 2002. We have hedged a portion of our commodity price
risk in 2002.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

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

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

(a) Effective February 5, 2002, Arthur Andersen LLP ("Andersen")
resigned as auditors of the Partnership.

(b) The reports of Andersen on the Partnership's financial
statements for the past two fiscal years did not contain an
adverse opinion or disclaimer of opinion and were not
qualified or modified as to audit scope, uncertainty or
accounting principles. Andersen has advised us that it has not
withdrawn any of its opinions expressed in their auditor's
report for any periods for which they conducted audits of the
Partnership.

(c) The resignation by Andersen was not approved by the
Partnership Policy Committee or the Audit Committee of the
Partnership.

(d) During the preceding two years and in the subsequent interim
periods, there were no disagreements with Andersen

37

on any matters of accounting principles or practices,
financial statement disclosures, or auditing scope or
procedures, which if not resolved to the satisfaction of
Andersen would have caused Andersen to make reference to the
matter in their report.

(e) During the preceding two years and in the subsequent interim
periods, there were no "reportable events" within the meaning
of Item 304(a)(1)(v) of Regulation S-K.

(f) The Partnership has retained the services of KPMG LLP as its
independent auditor.

38

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 public
accountants, 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 170 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. Effective March 18, 2002, Gary N. Petersen was appointed to the Audit
Committee, replacing Daniel Dienstbier who resigned on January 12, 2002. There
are no family relationships between any of our executive officers or members of
the Partnership Policy and Audit Committees.

39

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. He started his career with another Enron company, Northern Natural, in
1970 and has worked in several management positions at Northern Natural. 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 President of Transwestern
Pipeline.

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 is a Director and Chairman of the Board of EOTT Energy
Corp., the general partner of EOTT Energy Partners, L.P. Mr. Horton also holds
the elected position of officer and/or director of the following companies that
have filed for Chapter 11 bankruptcy protection:

Calypso Pipeline, L.L.C. (Director)
Enron Transportation Services Company (Chairman, President and Chief
Executive Officer and Director)
Enron Wind Corp. (Chairman, Director)
Enron Wind Systems, Inc. (Director)
Enron Wind Energy Systems Corp. (Chairman, Director)
Enron Wind Maintenance Corp. (Chairman, Director)
Enron Wind Constructors Corp. (Chairman, Director)

James C. Moore was named to the Partnership Policy Committee and to the
Northern Border Management Committee on December 21, 2001. Mr. Moore has served
as Senior Vice President of Group Planning and Development for

40

Williams Gas Pipeline since August 2001. He joined Williams in 1990 as Director
of MIS and in 1992 he became Director of Business Development for Williams
Natural Gas. In August 2000, he was named Vice President of Group Planning and
Development for Williams Gas Pipeline. Mr. Moore serves as one of Williams'
representatives on the Canadian and U.S. boards of Alliance Pipeline.

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 named Vice
President, Finance of: Florida Gas Transmission Company in February 2001;
Transportation Trading Services Company in September 2001; Citrus Corp. in
October 2001; and Transwestern Pipeline Company in November 2001. 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 fixed income 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 provides consulting services related to strategic and
financial planning. Additionally, he is currently the President of 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 board 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 2001 our
reporting persons complied with all applicable filing requirements in a timely
manner except Cub Investment, LLC,

41

Haddington/Chase Energy Partners (Bear Paw) LP, and James C. Moore did not
timely file one report each on Form 3. Mr. Moore's filed report on Form 3
disclosed no ownership in our common units.

42

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 1,532 units in
1999; 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 1999, 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 1999, 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 1999, 2000 and 2001.

(4) The aggregate total of shares in unreleased Enron restricted stock
holdings and their values as of December 31, 2001, for each of the Named
Officers is: Mr. Cordes, 4,295 shares valued at $2,577, and Mr. Peters,
1,701 shares valued at $1,021. Dividend equivalents for all restricted
stock awards accrue from date of grant and are paid upon vesting. Any
dividends on Enron Corp. stock accrued an unreleased as of the date of
Enron Corp's filing for bankruptcy protection will only be released in
accordance with applicable bankruptcy law.

43

(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. 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. It's performance over the
1997-2000 performance period rendered a value of $2.00 based on a ranking
of first.

(7) The amounts shown include the value of Enron Common Stock allocated to
employees' special subaccounts under Enron's Employee Stock Ownership
Plan, matching contributions to employees' Enron Corp. Savings Plan, and
imputed income on life insurance benefits.

44

STOCK OPTION GRANTS DURING 2001

The following table sets forth information with respect to 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
2001.

(1) The dollar amounts under these columns represent the potential
realizable value of each grant of options assuming that the market price
on Enron Common Stock appreciates in value from the date of grant at the
5% and 10% annual rates prescribed by the SEC and therefore are not
intended to forecast possible future appreciation, if any, of the price
of Enron Common Stock. This section is not applicable under the current
circumstances.

(2) An appreciation in stock price, which will benefit all shareholders, is
required for optionees to receive any gain. A stock price appreciation
of 0% would render the option without value to the optionees.

(3) Represents stock options awarded under the Enron Corp. Long-Term
Incentive Program. Awards vest 15% on the grant date and 15% every 6
months thereafter with the final vesting of 10% on January 31, 2004.

(4) All eligible Enron employees received an option grant under the 2001
Special Stock Option Grant. A grant of options equal to 5% of base
annual salary as of August 13, 2001 was awarded on August 21, 2001.
Options granted through the 2001 Special Stock Option Grant were 100%
vested on the date of grant.

(5) Mr. Peters elected to receive stock options in lieu of a portion of his
2000 annual cash bonus payment in the form of stock options, which were
granted in January, 2001 and were 100% vested on date of grant.

45

AGGREGATED STOCK OPTION/SAR EXERCISES DURING 2001 AND STOCK OPTION/SAR VALUES AS
OF DECEMBER 31, 2001

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, 2001 ($0.60) 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 annual base pay beginning January 1, 1996. Under the Cash
Balance Plan, each employee's accrued benefit will be credited with interest
based on ten-year Treasury Bond yields.

Enron also maintains a noncontributory employee stock ownership plan
("ESOP"), which covers all eligible employees. Allocations to individual
employees' retirement accounts within the ESOP offset a portion of benefits
earned under the Cash Balance Plan prior to December 31, 1994. December 31, 1993
was the final date on which ESOP allocations were made to employees' retirement
accounts.

In addition, Enron has a Supplemental Retirement Plan that is designed
to assure payments to certain employees of that retirement income that would be
provided under the Cash Balance Plan except for the dollar limitation on accrued
benefits imposed by the Internal Revenue Code of 1986, as amended, and a Pension
Program for Deferral Plan Participants that provides supplemental retirement
benefits equal to any reduction in benefits due to deferral of salary into
Enron's Deferral Plan.

46

The following table sets forth the estimated annual benefits payable
under normal retirement at age 65, assuming current remuneration levels without
any salary or bonus projections and participation until normal retirement at age
65, with respect to the Named Officers under the provisions of the foregoing
retirement plans.

- ----------

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

SEVERANCE PLANS

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

47

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 21, 2002 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 504,338 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 shown as shared
by Enron and Citibank, N.A.

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 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:

48

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,
2001, the aggregate amount charged by Northern Plains for it services
was approximately $31.5 million.

o NBP Services, a subsidiary of Enron which 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, 2001, the aggregate amount
charged by NBP Services for its services was approximately $15.3
million.

o Crestone Energy Ventures provided gas gathering and administrative
services for fixed and variable fees to Enron North America Corp.
("ENA"), an Enron subsidiary that has filed for bankruptcy protection,
under a Master Services Agreement effective September 21, 2000. The
amount of fixed fees for 2001 was $21,600 per day. The Master Services
Agreement was terminated for ENA's failure to pay and was replaced by
individual gathering and various service agreements with individual
producers. The approximate amount of the unpaid fees is $2,150,000.

o Bear Paw Energy entered into certain swap arrangements with ENA to
hedge risks of changes in commodity prices. ENA's obligations were
supported by a guaranty by Enron. These arrangements were terminated by
Bear Paw Energy on November 28, 2001, at which time the market value of
the swaps was approximately $5 million in our favor.

o ENA is one of Northern Border Pipeline's firm shippers, and is
obligated to pay for 3.5% of the capacity. A guaranty from Enron
supported ENA's obligations. ENA is also a shipper on Midwestern Gas
Transmission. At present, ENA has not assumed or rejected the contracts
on Northern Border Pipeline or Midwestern Gas Transmission. ENA's
ability to utilize their capacity has been suspended until ENA provides
adequate assurances of credit support and payment. Northern Border
Pipeline and Midwestern Gas Transmission's ability to terminate ENA's
contracts are stayed as a result of the bankruptcy court proceedings.

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

In addition, Northern Border Pipeline has other ongoing relationships
with the general partners and certain of their affiliates. Transcontinental Gas
Pipe Line Corporation, an affiliate of Williams, is one of Northern Border
Pipeline's firm shippers and is currently obligated to pay for 0.7% of the
capacity.

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. These representatives are also designated by our general partners.

Our interests could conflict with the interests of our general partners
or their affiliates, and in such case the members of the Partnership Policy

49

Committee will generally have a fiduciary duty to resolve such conflicts in a
manner that is in our best interest. Northern Border Pipeline's interests could
conflict with our interest or the interest of TC PipeLines and its affiliates,
and in such case our representatives on the Northern Border 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. Our fiduciary duty as a
general partner of Northern Border Pipeline may prevent us from taking actions
that might be in our best interest but in conflict with the fiduciary duty that
our representatives or we owe to Northern Border Pipeline or TC PipeLines.

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 duty to offer business opportunities to
Northern Border Pipeline, with certain exceptions.

50

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.

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PART IV

ITEM 14. 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.

* 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").

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

*10.3 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).

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

52

*10.5 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")).

*10.6 Northern Border Pipeline Company U.S. Shippers Service
Agreement between Northern Border Pipeline Company and Enron
Gas Marketing, Inc., dated June 22, 1990 (Exhibit 10.10 to
Form S-1).

*10.7 Amended Exhibit A to Northern Border Pipeline Company U.S.
Shippers Service Agreement between Northern Border Pipeline
Company and Enron Gas Marketing, Inc. (Exhibit 10.10.1 to the
Partnership's Annual Report on Form 10-K for the year ended
December 31, 1993 ("1993 10-K")).

*10.8 Amended Exhibit A to Northern Border Pipeline U.S. Shippers
Service Agreement between Northern Border Pipeline Company and
Enron Gas Marketing, Inc., effective November 1, 1994 (Exhibit
10.10.2 to the Partnership's Annual Report on Form 10-K for
the year ended December 31, 1994).

*10.9 Amended Exhibit A's to Northern Border Pipeline Company U.S.
Shipper Service Agreement effective, August 1, 1995 and
November 1, 1995 (Exhibit 10.10.3 to 1995 10-K).

*10.10 Amended Exhibit A to Northern Border Pipeline Company U.S.
Shipper Service Agreement effective April l, 1998 (Exhibit
10.10.4 to the Partnership's Annual Report on Form 10-K for
the year ended December 31, 1997 ("1997 10-K")).

*10.11 Guaranty made by Enron Corp. dated August 8, 1989 (Exhibit
10.9 to Northern Border Pipeline Company's Form 10-K for the
year ended December 31, 2001("NB Pipeline 2001 10-K")).

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

*10.13 Northern Border Pipeline Company U.S. Shippers Service
Agreement between Northern Border Pipeline Company and
Transcontinental Gas Pipe Line Corporation, dated July 14,
1983, with Amended Exhibit A effective February 11, 1994
(Exhibit 10.17 to 1995 10-K).

*10.14 Form of Credit Agreement among Northern Border Pipeline
Company, The First National Bank of Chicago, as Administrative
Agent, The First National Bank of Chicago, Royal Bank of
Canada, and Bank of America National Trust and Savings
Association, as Syndication Agents, First Chicago Capital
Markets, Inc., Royal Bank of Canada, and BancAmerica
Securities, Inc, as Joint Arrangers and Lenders (as defined
therein) dated as of June 16, 1997 (Exhibit 10(c) to Amendment
No. 1 to Form S-3, Registration Statement No. 333-40601 ("Form
S-3")).

*10.15 Northern Border Pipeline Company U.S. Shippers Service
Agreement between Northern Border Pipeline Company and Enron
Capital & Trade Resources Corp. dated October 15, 1997
(Exhibit 10.21 to 1997 10-K).

*10.16 Guaranty made by Enron Corp., dated October 20, 1997 (Exhibit
10.16 to NB Pipeline 2001 10-K).

*10.17 Northern Border Pipeline Company U.S. Shippers Service
Agreement between Northern Border Pipeline Company and Enron
Capital & Trade Resources Corp. dated October 15, 1997
(Exhibit 10.22 to 1997 10-K).

53

*10.18 Guaranty made by Enron Corp., dated October 20, 1997 (Exhibit
10.18 to NB Pipeline 2001 10-K).

*10.19 Northern Border Pipeline Company U.S. Shippers Service
Agreement between Northern Border Pipeline Company and Enron
Capital & Trade Resources Corp. dated August 5, 1997 with
Amendment dated September 25, 1997 (Exhibit 10.25 to 1997
10-K).

*10.20 Guaranty made by Enron Corp., dated April 29, 1997 (Exhibit
10.20 to NB Pipeline 2001 10-K).

*10.21 Northern Border Pipeline Company U.S. Shippers Service
Agreement between Northern Border Pipeline Company and Enron
Capital & Trade Resources Corp. dated August 5, 1997 (Exhibit
10.26 to 1997 10-K).

*10.22 Guaranty made by Enron Corp., dated April 29, 1997 (Exhibit
10.22 to NB Pipeline 2001 10-K).

*10.23 Project Management Agreement by and between Northern Plains
Natural Gas Company and Enron Engineering & Construction
Company, dated March 1, 1996 (Exhibit No. 10.39 to NB Form
S-4).

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

*10.25 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")).

*10.26 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")).

*10.27 Northern 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).

*10.28 Northern Border Pipeline Company U.S. Shippers Service
Agreement between Northern Border Pipeline Company and
Pan-Alberta Gas (U.S.) Inc., dated October 1, 1992, with
Amended Exhibit A effective June 22, 1998 (Exhibit 10.38 to NB
Pipeline 1999 10-K).

*10.29 Purchase and Sale Agreement, dated as of September 21, 2000 by
and between Enron North America Corp. and NBP Energy Pipeline,
L.L.C. (now known as Crestone Energy Ventures, L.L.C.)
(Exhibit 10.24 to 2000 10-K).

*10.30 Master Services Agreement, dated as of September 21, 2000
between NBP Energy Pipelines, L.L.C., (now known as Crestone
Energy Ventures, L.L.C.) and Enron North America Corp.
(Exhibit 10.25 to 2000 10-K).

*10.31 Acquisition Agreement, dated as of March 14, 2001, among
Northern Border Partners, L.P., Northern Border Intermediate
Limited Partnership, Bear Paw Investments, LLC, Bear Paw
Energy, LLC and Sellers (defined therein) (Exhibit 10.26 to
2000 10-K).

54

*10.32 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).

*10.33 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).

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

*10.35 Northern Border Pipeline Company U.S. Shipper Service
Agreement between Northern Border Pipeline Company and Enron
North America Corp., dated October 29, 2001 (Exhibit 10.38 to
2001 Form S-4).

*10.36 Northern Border Pipeline Company U.S. Shipper Service
Agreement between Northern Border Pipeline Company and Enron
North America Corp., dated October 29, 2001 (Exhibit 10.35 to
NB Pipeline 2001 10-K).

*10.37 Guaranty made by Enron Corp., dated October 31, 2001 (Exhibit
10.36 to NB Pipeline 2001 10-K).

10.38 Operating Agreement between Midwestern Gas Transmission
Company and Northern Plains Natural Gas Company dated as of
April 1, 2001.

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; and Midwestern Gas Transmission Company.

23.01 Consent of Arthur Andersen 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).

*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 November 29,
2001, which included a press release issued by Northern Border Partners
to reassure investors regarding its exposure to Enron.

55

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 29th day of
March, 2002.

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

By: /s/ 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.

56

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

F-1

INDEPENDENT AUDITORS' REPORT

To Northern Border Partners, L.P.:

We have audited the accompanying consolidated balance sheet of Northern Border
Partners, L.P. (a Delaware limited partnership) and Subsidiaries as of December
31, 2001, and the related consolidated statements of income, comprehensive
income, cash flows and changes in partners' equity for the year then ended.
These financial statements are the responsibility of the Company's management.
Our responsibility is to express an opinion on these financial statements based
on our audit. The accompanying consolidated financial statements of Northern
Border Partners, L.P. as of December 31, 2000 and for the years ended December
31, 2000 and 1999 were audited by other auditors whose report thereon dated
January 22, 2001 expressed an unqualified opinion on those statements.

We conducted our audit 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 audit provides a
reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in
all material respects, the financial position of Northern Border Partners, L.P.
and Subsidiaries as of December 31, 2001, and the results of their operations
and their cash flows for the year then ended, in conformity with accounting
principles generally accepted in the United States of America.

As discussed in note 7 to the consolidated financial statements, Northern Border
Partners, L.P. and Subsidiaries adopted the provisions of Statement of Financial
Accounting Standards (SFAS) No. 133, "Accounting for Derivative Instruments and
Hedging Activities," which was subsequently amended by SFAS No. 137 and SFAS No.
138.

KPMG LLP

Omaha, Nebraska,
March 8, 2002

F-2

REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS

To Northern Border Partners, L.P.:

We have audited the accompanying consolidated balance sheet of Northern Border
Partners, L.P. (a Delaware limited partnership) and Subsidiaries as of December
31, 2000, and the related consolidated statements of income, comprehensive
income, cash flows and changes in partners' equity for each of the two years in
the period ended December 31, 2000. These financial statements are the
responsibility of the Company's management. Our responsibility is to express an
opinion on these financial statements based on our audits.

We conducted our audits in accordance with auditing standards generally accepted
in the United States. Those standards require that we plan and perform the audit
to obtain reasonable assurance about whether the financial statements are free
of material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements. An audit
also includes assessing the accounting principles used and significant estimates
made by management, as well as evaluating the overall financial statement
presentation. We believe that our audits provide a reasonable basis for our
opinion.

In our opinion, the financial statements referred to above present fairly, in
all material respects, the financial position of Northern Border Partners, L.P.
and Subsidiaries as of December 31, 2000, and the results of their operations
and their cash flows for each of the two years in the period ended December 31,
2000, in conformity with accounting principles generally accepted in the United
States.

ARTHUR ANDERSEN LLP

Omaha, Nebraska,
January 22, 2001

F-3

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-4

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-5

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-6

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-7

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); Crestone Gathering
Services, L.L.C. (Crestone Gathering Services); 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.

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 The
Williams Companies, Inc. (Williams) 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 1.2%
limited partner interest and Enron, through an indirect subsidiary, owns
common units representing a 6.5% limited partner interest in the
Partnership at December 31, 2001 (see Note 9).

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, pursuant to which NBP
Services provides certain administrative, operating and management
services for the Partnership and its subsidiaries and is reimbursed for
its direct and indirect costs and expenses. For the years ended December
31, 2001, 2000 and 1999, the Partnership's charges from NBP Services and
its affiliates totaled approximately $15.3 million, $3.5 million and
$1.4 million, respectively. See Note 15 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. The day-to-day management
of Northern Border Pipeline's affairs is the responsibility of Northern
Plains (the Operator),

F-8

NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. ORGANIZATION AND MANAGEMENT (continued)

as defined by the operating agreement between Northern Border Pipeline
and Northern Plains. Northern Border Pipeline is charged for the
salaries, benefits and expenses of the Operator. For the years ended
December 31, 2001, 2000 and 1999, Northern Border Pipeline's charges
from the Operator totaled approximately $29.5 million, $31.7 million and
$29.7 million, respectively. Additionally, Northern Border Pipeline has
utilized Enron affiliates for management on pipeline expansion and
extension projects.

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 with a capacity of 650 million cubic feet per day.
Midwestern Gas Transmission's pipeline system connects with multiple
pipeline systems, including Northern Border Pipeline. The day-to-day
management of Midwestern Gas Transmission is the responsibility of
Northern Plains, as defined by the operating agreement between
Midwestern Gas Transmission and Northern Plains. Midwestern Gas
Transmission is charged for the salaries, benefits and expenses of
Northern Plains. For the year ended December 31, 2001, Midwestern Gas
Transmission's charges from Northern Plains totaled approximately $2.0
million.

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 four processing plants with 90 million
cubic feet per day of capacity. Following the acquisition, Bear Paw
Energy's Powder River Basin gathering activities in northeastern Wyoming
were integrated with those of Crestone Gathering Services. Bear Paw
Energy and Crestone Gathering Services have approximately 1,100 miles of
high and low pressure gathering pipelines and approximately 300,000
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 with a capacity of
approximately 150 million cubic feet per day.

The Partnership owns a 49% common membership interest and a 100% class A
share interest in Bighorn Gas Gathering, L.L.C. (Bighorn); a 33%
interest

F-9

NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. ORGANIZATION AND MANAGEMENT (continued)

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, Crestone Gathering Services 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.

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. At December 31, 2001 and 2000,
Northern Border Pipeline has reflected regulatory assets of
approximately $11.5 million and $12.4 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.

F-10

NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)

(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 (Pipeline Agreement). Under the terms of
the Pipeline Agreement, Black Mesa receives a monthly demand
payment, a per ton commodity payment and a reimbursement for
certain other expenses.

(E) Income Taxes

Income taxes are the responsibility of the partners and are not
reflected in these financial statements. However, the Northern
Border Pipeline 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 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 $336
million and $326 million at December 31, 2001 and 2000,
respectively, and are primarily related to accelerated
depreciation and other plant-related differences.

(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

F-11

NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)

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

the case of extraordinary retirements or sales. 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 rates applied to
Northern Border Pipeline's transmission plant in 2001, 2000 and
1999 were 2.25%, 2.25% and 2.0%, respectively. Midwestern Gas
Transmission applied a 1.9% depreciation rate to its transmission
plant in 2001. 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 3.2% 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) Investments in Unconsolidated Affiliates

The investments in unconsolidated affiliates are accounted for by
the equity method. The excess of the Partnership's investments in
unconsolidated affiliates over the underlying equity in the fair
value of the net assets acquired is being amortized on a
straight-line basis 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 8 for details on the
Partnership's investments in unconsolidated affiliates and
related equity earnings (losses). See Note 12 for discussion of
an accounting pronouncement that will impact goodwill
amortization in 2002.

(I) Goodwill

Goodwill consists of the excess of cost over fair value of the
net assets acquired in business acquisitions and is being
amortized using a straight-line method over 30 years. During
2001, 2000 and 1999, the Partnership recorded amortization
expense of $7.0 million, $0.5 million and $0.3 million,
respectively. This amortization expense is reflected as a
component of depreciation and amortization in the consolidated
statement of income. See Note 12 for discussion of an accounting
pronouncement that will impact goodwill amortization in 2002.

F-12

NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)

(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. See Note 7
for a discussion of the Partnership's accounting for derivatives
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.

3. BUSINESS ACQUISITIONS

In December 1999, the Partnership purchased a 39% common membership
interest in Bighorn for approximately $31.9 million and in June 2000,
the Partnership purchased 80% of class A shares in 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 a
100% interest in Enron Midstream Services, L.L.C., now known as Crestone
Gathering Services, 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 class A shares.

The Partnership completed three acquisitions during 2001. On March 30,
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.
Effective May 1, 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

F-13

NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

3. BUSINESS ACQUISITIONS (continued)

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 8
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, 2000 and 1999 on the Partnership's consolidated financial position
(amounts in thousands):

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 class A and class 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 class 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 2000 or 1999.
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.

F-14

NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

4. RATES AND REGULATORY ISSUES

Northern Border Pipeline Rate Case

Northern Border Pipeline's revenue is derived from agreements with
various shippers for the transportation of natural gas. It transports
gas under a FERC regulated tariff. Northern Border Pipeline had used a
cost of service form of tariff since its inception but agreed to convert
to a stated rate form of tariff as part of the settlement of its 1999
rate case discussed below.

Under the cost of service tariff, Northern Border Pipeline was provided
an opportunity to recover all of the operations and maintenance costs of
the pipeline, taxes other than income taxes, interest, depreciation and
amortization, an allowance for income taxes and a regulated return on
equity. Northern Border Pipeline was generally allowed to collect from
its shippers a return on regulated rate base as well as recover that
rate base through depreciation and amortization. Billings for the firm
transportation agreements were based on contracted volumes to determine
the allocable share of the cost of service and were not dependent upon
the percentage of available capacity actually used.

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. The total annual cost of service increase due to
Northern Border Pipeline's proposed changes was approximately $30
million. In June 1999, the FERC issued an order in which the proposed
changes were suspended until December 1, 1999, after which the proposed
changes were implemented with subsequent billings subject to refund.

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 approved settlement, effective December 1, 1999,
shippers began paying stated transportation rates based on a straight
fixed variable rate design. Under the straight fixed variable rate
design, approximately 98% of the agreed upon revenue level is attributed
to demand charges, based upon contracted firm capacity, and the
remaining 2% is attributed to commodity charges, based on the volumes of
gas actually transported on the system. 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.

F-15

NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

4. RATES AND REGULATORY ISSUES (continued)

Northern Border Pipeline Certificate application

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. The capital expenditures for the project are expected
to be approximately $63 million, of which $60.5 million had been
incurred through December 31, 2001.

5. 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 2002 to December 2013. The termination dates for
Midwestern Gas Transmission's firm service agreements range from March
2002 to October 2019.

Northern Border Pipeline also has interruptible service agreements with
numerous other shippers. Under the approved settlement of Northern
Border Pipeline's rate case discussed in Note 4, Northern Border
Pipeline will reduce the billings for the firm service agreements by one
half of the revenues received from the interruptible service agreements
through October 31, 2003. Northern Border Pipeline is permitted to
retain revenue from interruptible transportation service to offset any
decontracted capacity. After October 31, 2003, all revenues from
interruptible transportation service will be retained by Northern Border
Pipeline.

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

At December 31, 2001, Northern Border Pipeline's largest shipper, Mirant
Americas Energy Marketing, LP (Mirant) is obligated for approximately
33.7% of the contracted firm capacity, which consists of the following:
24.4% from temporary releases of firm capacity from Pan-Alberta Gas
(U.S.) Inc. (PAGUS) and 9.3% from permanent releases of firm capacity
from TransCanada Energy Marketing USA, Inc. (TransCanada Energy), an
affiliate of TC PipeLines. The PAGUS firm service agreements expire in
October 2003. The permanent release to Mirant commenced in December 2001
and the firm service agreements expire in October 2006 and December
2008. The obligations of Mirant and PAGUS 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 the Mirant and PAGUS firm service agreements and
interruptible service agreements for the years ended December 31, 2001,
2000 and 1999 were $80.7 million, $78.2 million and $76.6 million,
respectively.

F-16

NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

5. TRANSPORTATION AGREEMENTS (continued)

Some of Northern Border Pipeline's shippers are affiliated with its
general partners. ENA has firm service agreements representing 3.5% of
capacity, a portion of which (1.1%) has been temporarily released to a
third party until October 31, 2002 (see Note 15). Transcontinental Gas
Pipe Line Corporation, a subsidiary of Williams, holds a firm service
agreement representing 0.7% of capacity. The firm service agreements
with affiliates extend for various terms with termination dates that
range from October 2002 to May 2009. Operating revenues from the
affiliated firm service agreements and interruptible service agreements,
including revenues from TransCanada Energy when it held capacity on
Northern Border Pipeline, were $52.1 million, $58.5 million and $52.5
million for the years ended December 31, 2001, 2000, and 1999,
respectively.

Based upon the proportionate share of capacity, two of Midwestern Gas
Transmission's shippers account for approximately 60% of its capacity.
Northern Illinois Gas Company (Northern Illinois) and PSI Energy Inc.
(PSI) have capacity on Midwestern Gas Transmission of 38.4% and 20.9%,
respectively. Operating revenues from Northern Illinois and PSI for the
period from May 2001 to December 2001 totaled $3.8 million and $0.9
million, respectively.

The gas gathering and processing businesses provide services for
gathering, treating, processing and compression of natural gas and the
fractionation of natural gas liquids. Bear Paw Energy's two largest
customers, Lodgepole Energy Marketing and Tenaska Marketing Venture,
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 7) 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 15). Crestone's revenues from other affiliates totaled $0.3
million and $0.1 million in 2001 and 2000, respectively. Border
Midstream's two largest customers, 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 Pipeline Agreement with
the coal supplier for the Mohave Power Station that expires in December
2005. The pipeline is the sole source of fuel for the Mohave plant.
Operating revenues under the Pipeline Agreement totaled $22.0 million,
$21.1 million and $20.6 million for the years ended December 31, 2001,
2000 and 1999, respectively.

F-17

NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

Detailed information on long-term debt is as follows:

In September 2001, Northern Border Pipeline completed a private offering
of $250 million of 7.50% Senior Notes due 2021, which notes were
subsequently exchanged in a registered offering for notes with
substantially identical terms (2001 Pipeline Senior Notes). The proceeds
from the 2001 Pipeline Senior Notes were used to reduce indebtedness
outstanding under the Pipeline Credit Agreement.

In March 2001, the Partnership completed a private offering of $225
million of 7.10% Senior Notes due 2011 (2001 Partnership Senior Notes).
The 2001 Partnership Senior Notes were subsequently exchanged in a
registered offering for notes with substantially identical terms. The
proceeds from the 2001 Partnership Senior Notes were used to fund a
portion of the acquisition of Bear Paw Energy (see Note 3).

F-18

NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

The Partnership entered into a $200 million three-year revolving credit
agreement with certain financial institutions (2001 Partnership Credit
Agreement) in March 2001. The 2001 Partnership Credit Agreement is to be
used for capital expenditures, acquisitions and general business
purposes. The 2001 Partnership Credit Agreement permits the Partnership
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. The Partnership is required to pay a
fee on the principal commitment amount of $200 million. The 2001
Partnership Credit Agreement replaced revolving credit agreements
entered into in June 2000. In June 2000, the Partnership had entered
into two credit agreements with certain financial institutions, a $75
million 364-day credit agreement and a $75 million three-year revolving
credit agreement (collectively, 2000 Partnership Credit Agreements). The
2000 Partnership Credit Agreements were to be used for capital
expenditures, working capital and general business purposes.

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.

In June 2000, the Partnership completed a private offering of $150
million of 8 7/8% Senior Notes due 2010 (2000 Partnership Senior Notes).
The proceeds from the private offering, net of debt discounts and
issuance costs, were primarily used to reduce existing indebtedness
under a November 1997 credit agreement and to acquire the class A shares
in Bighorn (see Note 3). In September 2000, the Partnership completed a
private offering of an additional $100 million of 2000 Partnership
Senior Notes. The proceeds from this offering, along with the proceeds
from the credit agreements described above, were used for the
acquisition of the interests in gas gathering businesses from ENA (see
Note 3). The 2000 Partnership Senior Notes were subsequently exchanged
in a registered offering for notes with substantially identical terms.

The Partnership entered into 10-year interest rate swap agreements with
an aggregate notional principal amount of $150 million in June 2000. The
interest rate swap agreements were terminated in December 2000 and
resulted in proceeds to the Partnership of approximately $15.0 million.
The proceeds are being amortized against interest expense over the
10-year life of the terminated interest rate swap agreements.

In August 1999, Northern Border Pipeline completed a private offering of
$200 million of 7.75% Senior Notes due 2009, which notes were
subsequently exchanged in a registered offering for notes with
substantially identical terms (1999 Pipeline Senior Notes). Also in
August 1999, Northern Border Pipeline received approximately $12.9
million from the termination of interest rate forward agreements, which
is being amortized against interest expense over the life of the 1999
Pipeline Senior Notes. The interest rate forward agreements, which had
an aggregate notional amount of $150 million, had been executed in
September 1998 to hedge the interest rate on a planned

F-19

NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

issuance of fixed rate debt in 1999. The proceeds from the private
offering, net of debt discounts and issuance costs, and the termination
of the interest rate forward agreements were used to reduce existing
indebtedness under the Pipeline Credit Agreement.

In June 1997, Northern Border Pipeline entered into a credit agreement
(Pipeline Credit Agreement) with certain financial institutions, which
is comprised of a $100 million five-year revolving credit facility and a
$272 million term loan, both maturing in June 2002. The Pipeline Credit
Agreement permits Northern Border Pipeline to choose among various
interest rate options, to specify the portion of the borrowings to be
covered by specific interest rate options and to specify the interest
rate period, subject to certain parameters. Northern Border Pipeline is
required to pay a facility fee on the aggregate principal commitment
amount of $372 million.

Interest paid, net of amounts capitalized, during the years ended
December 31, 2001, 2000 and 1999 was $86.5 million, $84.2 million and
$62.5 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: $350 million, $65 million and $64 million for 2002, 2003,
and 2004, respectively. There are no scheduled debt maturities for 2005
or 2006.

Future minimum payments under Bear Paw Energy's non-cancelable capital
leases on compressors are as follows (in thousands):

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.

Certain of Northern Border Pipeline's long-term debt and credit
arrangements contain requirements as to the maintenance of minimum
partners' capital and debt to capitalization ratios which 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

F-20

NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

most restrictive of the covenants, as of December 31, 2001 and 2000,
respectively, $110 million and $136 million of partners' capital of
Northern Border Pipeline could be distributed. 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. (Moodys) rate the notes as below investment grade. In February
2002, Moodys placed Northern Border Pipeline and the Partnership on
credit review for a possible downgrade in credit rating. At this time,
no action has been taken by Moodys. If Moodys was to issue the
downgrade, the Partnership expects Northern Border Pipeline and its
credit ratings to remain above investment grade. 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 to be 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, 2001, 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 and 2001 Pipeline Senior Notes was approximately $1,125 million
and $675 million at December 31, 2001 and 2000, 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 and
2001 Pipeline Senior Notes, which will result in no gains or losses on
their respective repayment. The fair value of the Pipeline Credit
Agreement and 2001 Partnership Credit Agreement approximates the
carrying value since the interest rates are periodically adjusted to
reflect current market conditions. The estimated fair value of the Black
Mesa note agreement was approximately $15 million at December 31, 2000.

7. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

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. In 1998, the Financial Accounting Standards Board
issued SFAS No. 133, "Accounting for Derivative Instruments and Hedging
Activities," which was subsequently amended by SFAS No. 137 and SFAS No.
138. SFAS No. 133 requires that every derivative instrument (including
certain derivative instruments embedded in other contracts) be recorded
on the balance sheet

F-21

NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

7. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES (continued)

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.

At December 31, 2000, the Partnership had classified in long-term debt
$26.0 million of unamortized proceeds from the termination of
derivatives. This included unamortized proceeds of $14.9 million from
the termination of interest rate swap agreements by the Partnership in
December 2000 and $11.1 million from the termination of interest rate
forward agreements by Northern Border Pipeline in August 1999. 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. The Partnership is reflecting 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.

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.

In February 2001, the Partnership entered into forward starting interest
rate swaps with notional amounts totaling $150 million related to the
anticipated issuance of fixed rate debt. Upon issuance of the 2001
Partnership Senior Notes in March 2001, the Partnership paid
approximately $4.3 million to terminate the swaps, which was recorded in
accumulated other comprehensive income. The swaps were 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 2001 Partnership Senior Notes.

In March 2001, Northern Border Pipeline entered into forward starting
interest rate swaps with notional amounts totaling $200 million related
to the planned issuance of 10-year and 30-year fixed rate debt. Upon
issuance of the 2001 Pipeline Senior Notes in September 2001, Northern
Border Pipeline paid approximately $4.1 million to terminate the swaps,
of which $2.9 million was recorded in accumulated other comprehensive
income and $1.2 million was recorded as an adjustment to minority
interests in partners' equity. The swaps were 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 2001 Pipeline Senior Notes.

F-22

NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

7. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES (continued)

During the year ended December 31, 2001, the Partnership amortized
approximately $2.1 million related to the terminated derivatives, as a
reduction to interest expense from accumulated other comprehensive
income. The Partnership expects to amortize a comparable amount in 2002.

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 receives payments based on a 7.10% fixed rate. At
December 31, 2001, the average effective interest rate on the interest
rate swaps was 4.21%. The swaps have been designated as fair value
hedges as they were entered into to hedge the fluctuations in the market
value of the 2001 Partnership Senior Notes. A non-cash gain of
approximately $6.3 million is reflected in assets from price risk
management activities and long-term debt on the accompanying
consolidated balance sheet.

In November 2001, Northern Border Pipeline entered into forward starting
interest rate swaps with notional amounts totaling $150 million related
to the planned issuance of senior notes. The 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 date of the senior notes, which is expected to occur in
the second quarter of 2002. At December 31, 2001, the Partnership
reflected approximately $3.4 million in assets from price risk
management activities on the accompanying consolidated balance sheet
with corresponding offsets of $2.4 million in accumulated other
comprehensive income and $1.0 million in minority interests in partners'
equity.

Bear Paw Energy, which was acquired by the Partnership in March 2001
(see Note 3), 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 Bear Paw Energy's exposure to gas and natural gas liquid price
volatility. The price swaps and collars that Bear Paw Energy had in
place when it was acquired by the Partnership were redesignated as
hedges upon acquisition. 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. At December 31, 2001, Bear Paw
Energy did not have any outstanding derivative contracts.

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 and terminated the swap arrangements (see Note
15). 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 being recorded into earnings
in the same periods during which the hedged forecasted transactions will
affect earnings. In 2001, the Partnership recorded approximately $1.4
million into earnings and expects to record approximately $4.6 million
into earnings in 2002.

F-23

NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

8. 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 at December 31, 2001 and 2000. The
Partnership also held 100% of the non-voting class A shares of
Bighorn at December 31, 2001 and 2000.

(b) At December 31, 2001 and 2000, the unamortized excess of the
Partnership's investments in unconsolidated affiliates was $180.1
million and $189.5 million, respectively.

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

(a) Initial investments in unconsolidated affiliates began in late
December 1999.

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

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

(a) Includes $434 thousand receivable from the Partnership at
December 31, 2000.

F-24

NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

8. UNCONSOLIDATED AFFILIATES (continued)

(a) Includes entire year results for Bighorn, which was acquired in
late December 1999, and results for Fort Union and Lost Creek after
they were acquired in September 2000.

(b) Includes results for Gregg Lake after it was acquired in April 2001.

9. PARTNERS' CAPITAL

At December 31, 2001, partners' capital consisted of 41,623,014 common
units representing an effective 98% limited partner interest in the
Partnership (including 7.7% held by Northern Plains and Enron, through
an indirect subsidiary) and a 2% general partner interest. At December
31, 2000, partners' capital consisted of 31,503,563 common units
representing an effective 98% limited partner interest in the
Partnership (including 13.8% held collectively by the General Partners
or their affiliates) and a 2% general partner interest. 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 April and May of 2001, the Partnership sold 407,550 and 4,000,000
common units, respectively. The net proceeds from the sale of common
units and the general partners' capital contributions totaled
approximately $172.2 million and were primarily used to repay amounts
borrowed under the 2001 Partnership Credit Agreement.

In connection with the Partnership's sale of common units in May 2001,
Northwest Border sold its 1,123,500 common units. These common units had
previously been outstanding and did not affect the number of the
Partnership's total common units outstanding. The Partnership did not
receive any of the proceeds from the common units sold by Northwest
Border.

In November 2000, the Partnership sold 2,156,250 common units. The net
proceeds of the public offering and the general partners' capital
contribution totaled approximately $60.7 million and were primarily used
to repay amounts borrowed under the 2000 Partnership Credit Agreements.

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
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 11). Under the
incentive distribution provisions, the General Partners receive 15% of
amounts

F-25

NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

9. PARTNERS' CAPITAL (continued)

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.

10. 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 $8.6 million and $2.2 million for the
years ended December 31, 2001 and 2000, respectively, related to these
agreements. At December 31, 2001, the estimated aggregate amounts of
such required future payments were $8.2 million annually for 2002
through 2006 and $28.2 million for later years.

At December 31, 2001, the Partnership has guaranteed the performance of
its unconsolidated affiliates in connection with credit agreements that
expire in March 2009 and September 2009. At December 31, 2001, the
combined guarantee was $4.4 million.

Operating Leases

Future minimum lease payments under non-cancelable operating leases on
office space and vehicles of Bear Paw Energy are as follows (in
thousands):

Expenses incurred related to these lease obligations for the period from
April to December 2001, which were the months the Partnership's
operating results included those of Bear Paw Energy, were $1.1 million.

Capital expenditure and investment program

Total capital expenditures and investments in unconsolidated affiliates
for 2002 are estimated to be $86 million. This includes approximately
$49 million for gas gathering and processing facilities and $25 million
for interstate pipeline facilities. The Partnership also estimates that
it will

F-26

NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

10. COMMITMENTS AND CONTINGENCIES (continued)

Capital expenditure and investment program (continued)

be required to make additional investments in its unconsolidated
affiliates of approximately $12 million in 2002 to support their capital
expenditure projects. Funds required to meet the capital requirements
for 2002 are anticipated to be provided from debt borrowings, issuance
of additional limited partners 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 Reservation. Based on recent decisions by the federal courts and
other defenses, Northern Border Pipeline believes that the Tribes do not
have the authority to impose the tax and that the lawsuit will not have
a material adverse impact on the Partnership.

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.

11. 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-27

NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

12. ACCOUNTING PRONOUNCEMENTS

In the third quarter of 2001, the Financial Accounting Standards Board
issued SFAS No. 141, "Business Combinations," SFAS No. 142, "Goodwill
and Other Intangible Assets," SFAS No. 143, "Accounting for Asset
Retirement Obligations" and SFAS No. 144, "Accounting for the Impairment
or Disposal of Long-Lived Assets."

SFAS No. 141 requires all business combinations initiated after June 30,
2001, to be accounted for using the purchase method. 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 initial
impairment tests by applying a fair-value-based analysis on the goodwill
in each reporting segment. Subsequent to the initial adoption, goodwill
shall be tested for impairment annually or more frequently if
circumstances indicate a possible impairment. For goodwill and
intangible assets on the balance sheet at June 30, 2001, the provisions
of SFAS No. 142 must be applied to fiscal years beginning after December
15, 2001. At December 31, 2001, the Partnership's balance sheet included
goodwill of approximately $475 million. The Partnership adopted SFAS No.
142 effective January 1, 2002. At the date of this report, the
Partnership is evaluating the impact of adopting SFAS No. 142, including
whether any transitional impairment losses will be required to be
recognized as the cumulative effect of a change in accounting principle.
Beginning January 1, 2002, effective with the adoption of SFAS No. 142,
the Partnership will no longer record amortization expense related to
goodwill.

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. When the liability is initially recorded, the entity
capitalizes a cost by increasing the carrying amount of the related
long-lived asset. Over time, the liability is accreted to its present
value and the capitalized cost is depreciated over the useful life of
the related asset. 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. The Partnership is in the
process of evaluating the application of this pronouncement.

SFAS No. 144 establishes one accounting model to be used for long-lived
assets to be disposed of by sale and broadens the presentation of
discontinued operations to include more disposal transactions. SFAS No.
144 supersedes both SFAS No. 121, "Accounting for the Impairment of
Long-Lived Assets and for Long-Lived Assets to be Disposed of," and the
accounting and reporting provisions of APB Opinion No. 30. This standard
is effective for fiscal years beginning after December 15, 2001. The
Partnership adopted SFAS No. 144 effective January 1, 2002. The
Partnership doe not expect the adoption of SFAS No. 144 will have a
material impact on the Partnership's financial position or results of
operations.

F-28

NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

13. GEOGRAPHIC AND BUSINESS SEGMENT INFORMATION

The Partnership's business is divided into operating 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. They 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 (net income before minority interests;
interest expense; income taxes; and depreciation and amortization,
including goodwill amortization, which is netted against equity earnings
(losses) of unconsolidated affiliates) 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.

Business Segments
Interstate Gas
Natural Gathering
Gas and
Pipelines Coal Processing
(In thousands) (a) Slurry (b) Other(d) Total
- --------------------------------------------------------------------------------------------------------
2001

Revenues from
external customers $ 322,584 $ 22,041 $ 116,844 $ -- $ 461,469

Depreciation and
amortization 59,854 2,144 14,312 -- 76,310

Operating income (loss) 199,822 5,953 18,239 (3,055) 220,959

Interest expense, net 55,351 717 706 33,134 89,908

F-29

NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

13. GEOGRAPHIC AND BUSINESS SEGMENT INFORMATION (continued)

Business Segments (continued)

F-30

NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

13. 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.

14. QUARTERLY FINANCIAL DATA (Unaudited)

F-31

NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

15. 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.

As indicated in Note 5, ENA has firm service agreements with Northern
Border Pipeline representing approximately 3.5% of contracted capacity,
a portion of which (1.1%) has 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. ENA has not
assumed or rejected these contracts, but its ability to use the capacity
has been suspended until ENA provides adequate assurance of credit
support and payment. The third party that holds the 1.1% of capacity
through October 31, 2002, has filed a complaint with the FERC
requesting, in effect, that its contract be deemed terminated as a
consequence of ENA's filing for bankruptcy protection. Management
believes this shipper's contract will remain in effect until October 31,
2002. For 2002, Northern Border Pipeline's estimated financial
exposure for ENA's firm service agreements is approximately $9 million.
Management believes that even if ENA continues to fail to perform its
obligations under Northern Border Pipeline's firm service agreements, it
will not have a material adverse impact on the Partnership's financial
condition and results of operations.

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 7). Bear Paw Energy terminated the swap arrangements with ENA prior
to December 31, 2001, and recorded bad debt expense of approximately
$5.4 million.

Management plans to continue to monitor developments at Enron, to
continue 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.

16. SUBSEQUENT EVENTS

On January 16, 2002, 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, 2001. The distribution was paid February 14, 2002, to
unitholders of record at January 31, 2002.

F-32

INDEPENDENT AUDITORS' REPORT ON SCHEDULE

To 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 included in this Form 10-K and have
issued our report thereon dated March 8, 2002. Our audit was 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

Omaha, Nebraska,
March 8, 2002

S-1

REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS ON SCHEDULE

To Northern Border Partners, L.P.:

We have audited in accordance with auditing standards generally accepted in the
United States, the consolidated financial statements as of December 31, 2000,
and for each of the two years in the period ended December 31, 2000, of Northern
Border Partners, L.P. and Subsidiaries included in this Form 10-K and have
issued our report thereon dated January 22, 2001. 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.

ARTHUR ANDERSEN LLP

Omaha, Nebraska,
January 22, 2001

S-2

SCHEDULE II

NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 2001, 2000 AND 1999
(IN THOUSANDS)

S-3

INDEX TO EXHIBITS

*10.5 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")).

*10.6 Northern Border Pipeline Company U.S. Shippers Service
Agreement between Northern Border Pipeline Company and Enron
Gas Marketing, Inc., dated June 22, 1990 (Exhibit 10.10 to
Form S-1).

*10.7 Amended Exhibit A to Northern Border Pipeline Company U.S.
Shippers Service Agreement between Northern Border Pipeline
Company and Enron Gas Marketing, Inc. (Exhibit 10.10.1 to the
Partnership's Annual Report on Form 10-K for the year ended
December 31, 1993 ("1993 10-K")).

*10.8 Amended Exhibit A to Northern Border Pipeline U.S. Shippers
Service Agreement between Northern Border Pipeline Company and
Enron Gas Marketing, Inc., effective November 1, 1994 (Exhibit
10.10.2 to the Partnership's Annual Report on Form 10-K for
the year ended December 31, 1994).

*10.9 Amended Exhibit A's to Northern Border Pipeline Company U.S.
Shipper Service Agreement effective, August 1, 1995 and
November 1, 1995 (Exhibit 10.10.3 to 1995 10-K).

*10.10 Amended Exhibit A to Northern Border Pipeline Company U.S.
Shipper Service Agreement effective April l, 1998 (Exhibit
10.10.4 to the Partnership's Annual Report on Form 10-K for
the year ended December 31, 1997 ("1997 10-K")).

*10.11 Guaranty made by Enron Corp. dated August 8, 1989 (Exhibit
10.9 to Northern Border Pipeline Company's Form 10-K for the
year ended December 31, 2001("NB Pipeline 2001 10-K")).

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

*10.13 Northern Border Pipeline Company U.S. Shippers Service
Agreement between Northern Border Pipeline Company and
Transcontinental Gas Pipe Line Corporation, dated July 14,
1983, with Amended Exhibit A effective February 11, 1994
(Exhibit 10.17 to 1995 10-K).

*10.14 Form of Credit Agreement among Northern Border Pipeline
Company, The First National Bank of Chicago, as Administrative
Agent, The First National Bank of Chicago, Royal Bank of
Canada, and Bank of America National Trust and Savings
Association, as Syndication Agents, First Chicago Capital
Markets, Inc., Royal Bank of Canada, and BancAmerica
Securities, Inc, as Joint Arrangers and Lenders (as defined
therein) dated as of June 16, 1997 (Exhibit 10(c) to Amendment
No. 1 to Form S-3, Registration Statement No. 333-40601 ("Form
S-3")).

*10.15 Northern Border Pipeline Company U.S. Shippers Service
Agreement between Northern Border Pipeline Company and Enron
Capital & Trade Resources Corp. dated October 15, 1997
(Exhibit 10.21 to 1997 10-K).

*10.16 Guaranty made by Enron Corp., dated October 20, 1997 (Exhibit
10.16 to NB Pipeline 2001 10-K).

*10.17 Northern Border Pipeline Company U.S. Shippers Service
Agreement between Northern Border Pipeline Company and Enron
Capital & Trade Resources Corp. dated October 15, 1997
(Exhibit 10.22 to 1997 10-K).

*10.18 Guaranty made by Enron Corp., dated October 20, 1997 (Exhibit
10.18 to NB Pipeline 2001 10-K).

*10.19 Northern Border Pipeline Company U.S. Shippers Service
Agreement between Northern Border Pipeline Company and Enron
Capital & Trade Resources Corp. dated August 5, 1997 with
Amendment dated September 25, 1997 (Exhibit 10.25 to 1997
10-K).

*10.20 Guaranty made by Enron Corp., dated April 29, 1997 (Exhibit
10.20 to NB Pipeline 2001 10-K).

*10.21 Northern Border Pipeline Company U.S. Shippers Service
Agreement between Northern Border Pipeline Company and Enron
Capital & Trade Resources Corp. dated August 5, 1997 (Exhibit
10.26 to 1997 10-K).

*10.22 Guaranty made by Enron Corp., dated April 29, 1997 (Exhibit
10.22 to NB Pipeline 2001 10-K).

*10.23 Project Management Agreement by and between Northern Plains
Natural Gas Company and Enron Engineering & Construction
Company, dated March 1, 1996 (Exhibit No. 10.39 to NB Form
S-4).

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

*10.25 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")).

*10.26 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")).

*10.27 Northern 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).

*10.28 Northern Border Pipeline Company U.S. Shippers Service
Agreement between Northern Border Pipeline Company and
Pan-Alberta Gas (U.S.) Inc., dated October 1, 1992, with
Amended Exhibit A effective June 22, 1998 (Exhibit 10.38 to NB
Pipeline 1999 10-K).

*10.29 Purchase and Sale Agreement, dated as of September 21, 2000 by
and between Enron North America Corp. and NBP Energy Pipeline,
L.L.C. (now known as Crestone Energy Ventures, L.L.C.)
(Exhibit 10.24 to 2000 10-K).

*10.30 Master Services Agreement, dated as of September 21, 2000
between NBP Energy Pipelines, L.L.C., (now known as Crestone
Energy Ventures, L.L.C.) and Enron North America Corp.
(Exhibit 10.25 to 2000 10-K).

*10.31 Acquisition Agreement, dated as of March 14, 2001, among
Northern Border Partners, L.P., Northern Border Intermediate
Limited Partnership, Bear Paw Investments, LLC, Bear Paw
Energy, LLC and Sellers (defined therein) (Exhibit 10.26 to
2000 10-K).

*10.32 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).

*10.33 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).

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

*10.35 Northern Border Pipeline Company U.S. Shipper Service
Agreement between Northern Border Pipeline Company and Enron
North America Corp., dated October 29, 2001 (Exhibit 10.38
to 2001 Form S-4).

*10.36 Northern Border Pipeline Company U.S. Shipper Service
Agreement between Northern Border Pipeline Company and Enron
North America Corp., dated October 29, 2001 (Exhibit 10.35 to
NB Pipeline 2001 10-K).

*10.37 Guaranty made by Enron Corp., dated October 31, 2001 (Exhibit
10.36 to NB Pipeline 2001 10-K).

10.38 Operating Agreement between Midwestern Gas Transmission
Company and Northern Plains Natural Gas Company dated as of
April 1, 2001.

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; and Midwestern Gas Transmission Company.

23.01 Consent of Arthur Andersen 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).

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