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 ou