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

                          F O R M  10-K

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

For the fiscal year ended December 31, 2000
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.)


          1400 Smith Street, Houston, Texas  77002-7369
       (Address of principal executive offices)(zip code)
Registrant's telephone number, including area code:  713-853-6161
                       ___________________

   Securities registered pursuant to Section 12(b) of the Act:


Title of each class           Name of each exchange on which registered

  Common Units                     New York Stock Exchange

   Securities registered pursuant to Section 12(g) of the Act:
                              None


     Indicate by check mark whether the registrant (1) has filed
all reports required to be filed by Section 13 or 15(d) of the
Securities Exchange Act of 1934 during the preceding 12 months
(or for such shorter period that the registrant was required to
file such reports), and (2) has been subject to such filing
requirements for the past 90 days.   Yes   X    No  _

     Indicate by check mark if disclosure of delinquent filers
pursuant to Item 405 of Regulation S-K is not contained herein,
and will not be contained, to the best of registrant's knowledge,
in definitive proxy or information statements incorporated by
reference in Part III of this Form 10-K or any amendment to this
Form 10-K.  X

     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 2, 2001, was approximately $995,168,848.

<PAGE>
                 NORTHERN BORDER PARTNERS, L.P.
                        TABLE OF CONTENTS


                                                           Page No.


                             Part I

     Item 1.  Business                                           1
     Item 2.  Properties                                        13
     Item 3.  Legal Proceedings                                 14
     Item 4.  Submission of Matters to a Vote of Security
               Holders                                          14

                             Part II

     Item 5.  Market for Registrant's Common Units and Related
               Security Holder Matters                          15
     Item 6.  Selected Financial Data                           16
     Item 7.  Management's Discussion and Analysis of
               Financial Condition and Results of Operations    17
     Item 7a. Quantitative and Qualitative Disclosures
               About Market Risk                                24
     Item 8.  Financial Statements and Supplementary Data       24
     Item 9.  Changes in and Disagreements With Accountants on
               Accounting and Financial Disclosure             24

                            Part III

     Item 10. Partnership Management                           25
     Item 11. Executive Compensation                           28
     Item 12. Security Ownership of Certain Beneficial Owners
               and Management                                  33
     Item 13. Certain Relationships and Related Transactions   33


                        Part IV

     Item 14. Exhibits, Financial Statement Schedules and
               Reports on Form 8-K.                            36


<PAGE>
                           PART I

Item 1.   Business

General

     We are a publicly traded limited partnership 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.  In addition, Crestone Energy Ventures, L.L.C.
and Black Mesa Pipeline Company are wholly-owned subsidiaries
of the Partnership.  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., and Northwest Border Pipeline
Company, a subsidiary of The Williams Companies, Inc.

     Our general partners hold an aggregate 2% general
partner interest in the Partnership.  The general partners
or their affiliates also own common units representing an
aggregate 13.5% limited partner interest.  The combined
general and limited partner interests in the Partnership
held by Enron and Williams are 11.7% and 3.8%, respectively
(See Item 13. "Certain Relationships and Related
Transactions").  The Partnership is managed by or under the
direction of the Partnership Policy Committee consisting of
three members, each of whom has been appointed by one of the
general partners (See Item 10. "Partnership Management").

     Northern Border Pipeline owns an interstate pipeline
system that transports natural gas from the Montana-
Saskatchewan border to natural gas markets in the midwestern
United States.  This pipeline system connects with multiple
pipelines that provide shippers with access to the various
natural gas markets served by those pipelines.  In the year
ended December 31, 2000, we estimate that Northern Border
Pipeline transported approximately 22% 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.

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

     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.  The general
partner of TC PipeLines and its subsidiary limited
partnership is TC PipeLines GP, Inc., which is a subsidiary
of TransCanada PipeLines Limited.

     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 general partner) and one representative
from TC PipeLines.  Voting power on the management committee
is presently 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 the members of the management
committee.  For a discussion of specific relationships with
affiliates, refer to Item 13. "Certain Relationships and
Related Transactions."

     The pipeline system is operated by Northern Plains
pursuant to an operating agreement.  Northern Plains employs
approximately 200 individuals located at the operating
headquarters in Omaha, Nebraska, and at various locations
along the pipeline route.  Northern Plains' employees are
not represented by any labor union and are not covered by
any collective bargaining agreements.

     In September 2000, we purchased interests in gas
gathering businesses in the Powder River and Wind River
Basins in Wyoming for approximately $209 million from Enron
North America.  The transaction included the purchase of
Enron Midstream Services, L.L.C., now known as Crestone
Gathering Services, L.L.C., and ownership interests in
Bighorn Gas Gathering, L.L.C. ("Bighorn"), Fort Union Gas
Gathering, L.L.C. ("Fort Union") and Lost Creek Gathering,
L.L.C. ("Lost Creek").  The transaction added to our
previous ownership in Bighorn.  Through our wholly owned
subsidiary, Crestone Energy Ventures, we own 100% of
Crestone Gathering Services, a 49% interest in Bighorn, a
33% interest in Fort Union and a 35% interest in Lost Creek,
which collectively own over 300 miles of gas gathering
facilities in Wyoming.  Crestone Gathering Services provides
gas gathering services to third parties.  The gathering
facilities interconnect to the interstate gas pipeline grid
serving gas markets in the Rocky Mountains, the Midwest and
California.  The Bighorn and Fort Union systems gather coal
seam 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 reserves to Bighorn, giving Bighorn the right to
gather coal seam methane gas produced in areas of Wyoming
covering 800,000 acres.  Bighorn's system is capable of
gathering more that 250 million cubic feet per day of coal
bed methane gas for delivery to the Fort Union gathering
system.  The Fort Union gathering system is capable of
delivering more than 450 million cubic feet per day of coal
seam methane gas into the interstate pipeline grid.  Fort
Union has announced a planned expansion to increase capacity
to 634 million cubic feet per day that is expected to be in
service in October 2001.  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 million cubic feet per day 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
Barrett Resources hold the remaining interest in Fort Union.
CMS Field Services is the managing member, Western Gas
Resources is the field operator and CIG 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.  The system is
operated by Elkhorn Field Services Company.

     NBP Services Corporation, an Enron subsidiary, provides
administrative services for us and operating services for
Crestone Energy Ventures.  NBP Services Corporation has 22
employees and utilizes employees of its affiliates to
provide these services.

     We also own Black Mesa Pipeline Company.  Black Mesa
owns a 273-mile, 18-inch diameter coal slurry pipeline which
originates at a coal mine in Kayenta, Arizona.  The coal
slurry pipeline transports crushed coal suspended in water.
It traverses westward through northern Arizona to the 1,500
megawatt Mohave Power Station located in Laughlin, Nevada.
The coal slurry pipeline is the sole source of fuel for the
Mohave Power Station, which consumes an average of 4.8
million tons of coal annually.  The capacity of the pipeline
is fully contracted to the coal supplier for the Mohave
Power Station through the year 2005.  The pipeline is
operated by Black Mesa Pipeline Operations, LLC, a
wholly-owned subsidiary of the Partnership.  Approximately
58 people are employed in the operations of Black Mesa, of
which 26 are represented by a labor union, the United Mine
Workers.

Pending Acquisitions

     In March 2001, we signed a definitive agreement for the
acquisition of Midwestern Gas Transmission from El Paso
Corporation for approximately $100 million.  The Midwestern
system is a 350-mile interstate natural gas pipeline
extending from Portland, Tennessee to Joliet, Illinois.
Midwestern connects to Northern Border Pipeline and other
major interstate pipeline systems including Alliance
Pipeline, Tennessee Gas Pipeline, Trunkline and Texas Gas
Transmission to provide bi-directional service to markets in
Kentucky, Indiana, southern Illinois and the Joliet/Chicago
market hub.  The acquisition is expected to close in the
second quarter of this year, subject to the receipt of all
necessary approvals.

     In March 2001, we signed a definitive agreement to
purchase Bear Paw Energy, L.L.C.  The purchase price is
approximately $366 million to be paid with 5.7 million of
our common units and $183 million in cash, of which $98.2
million will be used to retire debt of Bear Paw Energy with
the remainder payable to the sellers.  An additional $6
million will be payable in February 2002, if certain
performance criteria are met.  The purchase is targeted for
completion by the end of the first quarter of this year.
Bear Paw Energy has extensive gathering and processing
operations in the Powder River Basin in Wyoming and the
Williston Basin in Montana, North Dakota and Saskatchewan.
Bear Paw Energy has approximately 226,000 leasehold
production acres under dedication and 600 miles of high and
low pressure gathering pipelines in the Powder River Basin.
In the Williston Basin, Bear Paw Energy has over 2,800 miles
of gathering pipelines and four processing plants with 90
million cubic feet per day of capacity.

     In February 2001, we signed a purchase and sale
agreement to purchase the Mazeppa Plant, Gladys Plant and a
minority interest in the Gregg Lake/Obed Pipeline, all of
which are located in Alberta, Canada, from Dynegy Canada,
Inc.  The purchase price, which is subject to adjustment, is
approximately $46 million.  The Mazeppa Plant is a sour gas
processing plant with 87 million cubic feet per day of
combined capacity and associated gathering pipelines.  The
Gladys Plant is a sour gas processing plant with 7 million
cubic feet per day of capacity.  The Gregg Lake/Obed
Pipeline is comprised of 85 miles of gathering lines with a
capacity of 150 million cubic feet per day.  We are
targeting to close on this transaction by the end of March
2001.

The Northern Border Pipeline System

     Northern Border Pipeline owns a 1,214-mile United
States interstate pipeline system that transports natural
gas from the Montana-Saskatchewan border near Port of
Morgan, Montana, to interconnecting pipelines in the upper
Midwest of the United States.  Construction of the pipeline
was initially completed in 1982.  The pipeline system was
expanded and/or extended in 1991, 1992 and 1998.

     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.
For the year ended December 31, 2000, of the natural gas
transported on the 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.

     The pipeline system consists of 822 miles of 42-inch
diameter pipe designed to transport 2,373 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
1,300 mmcfd in total from Ventura, Iowa to Harper, Iowa; and
226 miles of 36-inch diameter pipe and 19 miles of 30-inch
diameter pipe designed to transport 645 mmcfd from Harper,
Iowa to a terminus near Manhattan, Illinois (Chicago area).
Along the pipeline there are 15 compressor stations with
total rated horsepower of 476,500 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.

     At its northern end, the pipeline system is connected
to 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 Alberta system gathers and
transports approximately 18% of the total North American
natural gas production and approximately 74% of the natural
gas produced in the western Canadian sedimentary basin.  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.

     Interconnects

     The pipeline system connects with multiple pipelines
that provide its shippers with access to the various natural
gas markets served by those pipelines.  The pipeline system
interconnects with pipeline facilities of:

  *  Northern Natural Gas Company, an Enron subsidiary, at
     Ventura, Iowa as well as multiple smaller
     interconnections in South Dakota, Minnesota and Iowa;

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

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

  *  Alliant Power Company at Prophetstown, Illinois;

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

  *  Midwestern Gas Transmission Company near Channahon,
     Illinois;

  *  ANR Pipeline Company near Manhattan, Illinois; and

  *  The Peoples Gas Light and Coke Company near Manhattan,
     Illinois 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.

     Shippers

     The pipeline system serves more than 50 firm
transportation shippers with diverse operating and financial
profiles.  Based upon shippers' contractual obligations, as
of December 31, 2000, 92% of the firm capacity is contracted
by producers and marketers.  The remaining firm capacity is
contracted to local distribution companies (5%), interstate
pipelines (2%) and end-users (1%).  As of December 31, 2000,
the termination dates of these contracts ranged from October
31, 2001 to December 21, 2013 and the weighted average
contract life, based upon annual contractual obligations,
was approximately six years with just under 99% of capacity
contracted through mid-September 2003.

     Based on their proportionate shares of capacity, as of
December 31, 2000, the five largest shippers are: Pan-
Alberta Gas (U.S.) Inc. (25.5%), TransCanada Energy
Marketing USA, Inc. (11.4%), PanCanadian Energy Services Inc
(7.3%), Enron North America Corp. (6.3%) and Engage Energy
US, LP. (5.4%).  The 20 largest shippers, in total, are
responsible for approximately 93% of total revenues.

     As of December 31, 2000, the largest shipper, Pan-
Alberta, holds firm capacity of 690 mmcfd under three
contracts with terms to October 31, 2003.  An affiliate of
Enron provides guaranties for 300 mmcfd of Pan-Alberta's
contractual obligations through October 31, 2001.  In
addition, Pan-Alberta's remaining capacity is supported by
various credit support arrangements, including, among
others, a letter of credit, a guaranty from an interstate
pipeline company through October 31, 2001 for 132 mmcfd, an
escrow account and an upstream capacity transfer agreement.
Mirant Americas Energy Marketing, LP, formerly Southern
Company Energy Marketing L.P., 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.  TransCanada Energy
Marketing USA, Inc., a subsidiary of TransCanada, holds firm
contracts representing 11.4% of capacity.  Enron North
America Corp., a subsidiary of Enron, holds firm contracts
representing 6.3% of capacity.  Transcontinental Gas Pipe
Line Corporation, a subsidiary of Williams, holds a contract
representing 0.8% of capacity.  See Item 13. "Certain
Relationships and Related Transactions."

     Demand For Transportation Capacity

     Northern Border Pipeline's long-term financial
condition is dependent on the continued availability of
economic 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 pipeline system.  Low prices for
natural gas, regulatory limitations or the lack of available
capital for these projects could adversely affect the
development of additional reserves and production,
gathering, storage and pipeline transmission of western
Canadian natural gas supplies.  Additional pipeline export
capacity also could accelerate depletion of these reserves.

     Northern Border Pipeline's business depends in part on
the level of demand for western Canadian natural gas in the
markets the pipeline system serves.  The volumes of natural
gas delivered to these markets from other sources affect the
demand for both western Canadian natural gas and use of the
pipeline system.  Demand for western Canadian natural gas to
serve other markets also influences the ability and
willingness of shippers to use the pipeline system to meet
demand in the markets that the pipeline serves.

     A variety of factors could affect the demand for
natural gas in the markets that the pipeline system serves.
These factors include:

  *  economic conditions;

  *  fuel conservation measures;

  *  alternative energy requirements and prices;

  *  climatic conditions;

  *  government regulation; and

  *  technological advances in fuel economy and energy
     generation devices.

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

Future Demand and Competition

     On March 16, 2000, the FERC issued an order granting
Northern Border Pipeline's application for a certificate to
construct and operate its proposed Project 2000 facilities.
Project 2000 will  expand and extend the pipeline system
into Indiana.  Project 2000 will afford shippers on the
extended pipeline system access to industrial 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.

     The capital expenditures for Project 2000 are estimated
to be approximately $94 million with a planned in-service of
November 2001.  Proposed facilities include approximately
34.4 miles of 30-inch pipeline, new equipment and
modifications at three compressor stations resulting in a
net increase of 22,500 compressor horsepower and one meter
station.

     As a result of the Project 2000 expansion, the pipeline
system will have the ability to transport 1,484 mmcfd from
Ventura to Harper, Iowa, 844 mmcfd from Harper to Manhattan,
Illinois, and 544 mmcfd on the new extension from Manhattan
to North Hayden, Indiana.  Five shippers have contracted for
all the additional capacity under long-term transportation
agreements.

     The Project 2000 shippers are: Bethlehem Steel
Corporation, El Paso Energy Marketing Company, Northern
Indiana Public Service Company, Peoples Energy Services
Corporation and The Peoples Gas Light and Coke Company.

     Northern Border Pipeline competes with other pipeline
companies that transport natural gas from the western
Canadian sedimentary basin or that transport natural gas to
markets in the midwestern United States.  The competitors
for the supply of natural gas include six pipelines and the
Canadian domestic users in the western Canadian sedimentary
basin region.  Northern Border Pipeline's competitive
position is affected by the availability of Canadian natural
gas for export, the prices of natural gas in alternative
markets, the cost of producing natural gas in Canada, and
demand for natural gas in the United States.

     Alliance Pipeline, which commenced transporting natural
gas from the western Canadian sedimentary basin to the
midwestern United States in December 2000, delivers its
volumes into the Chicago market and other interstate
pipelines.  Alliance Pipeline transports  gas containing
high-energy liquid hydrocarbons.  Additional facilities to
extract the natural gas liquids were constructed near
Alliance Pipeline's terminus in Chicago to permit Alliance
to transport natural gas with the liquids-rich element.

     As a consequence of Alliance Pipeline, there has been
an increase in natural gas moving from the western Canadian
sedimentary basin to Chicago.  Vector Pipeline L.P.
interconnects with Alliance and transports gas eastward to a
terminus in eastern Canada.  There are several additional
projects proposed to transport natural gas from the Chicago
area that would provide access to additional markets for the
shippers.  The proposed projects currently being pursued by
third parties are targeting markets in northern Illinois,
Wisconsin and the northeast United States.  These proposed
projects are in various stages of regulatory approval.

     Williams has a minority interest (14.6%) in Alliance
Pipeline.  TransCanada 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 customers.

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

     Crestone Energy Ventures competes with other natural
gas gathering and pipelines companies to carry natural gas
from the production area of the Powder River and Wind River
Basins of Wyoming to the major interstate transmission
pipelines in the Rocky Mountain Region.  Crestone Energy
Ventures' competitive position is affected by the pace of
gas drilling, gas production rates, gas reserves, and the
demand for natural gas in the Rocky Mountains, Midwest, and
California markets served by the interstate pipeline gas
grid.  The pace of drilling may be impacted by the ability
of gas producers to obtain the necessary drilling and
production permits in an economic manner.

     In providing gas gathering services, Crestone Energy
Ventures may require acreage dedication and/or volume
commitments from gas producers.  Development of future gas
gathering systems will be staged to reflect the growth in
number of wells and field production.

FERC Regulation

General

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

  *  transportation of natural gas;

  *  rates and charges;

  *  construction of new facilities;

  *  extension or abandonment of service and facilities;

  *  accounts and records;

  *  depreciation and amortization policies;

  *  the acquisition and disposition of facilities; and

  *  the initiation and discontinuation of services.

     Where required, Northern Border Pipeline holds
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.  Northern Border Pipeline's books and
records are 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.  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.

Northern Border Rate Case Proceeding

     In May 1999, Northern Border Pipeline filed a rate case
wherein it proposed, among other things, to increase the
allowed equity rate of return to 15.25%.  The total annual
cost of service increase due to the proposed changes was
approximately $30 million.  A number of the shippers and
competing pipelines filed interventions and protests.  In
June 1999, the FERC issued an order in which the proposed
changes were suspended until December 1, 1999, after which
they were implemented with subsequent billings subject to
refund.  The order set for hearing not only the proposed
changes but also several issues raised by intervenors
including the appropriateness of the cost of service form of
tariff and the depreciation schedule. Upon a request for
clarification, the FERC issued an order in August 1999 that
provided that the manner in which the costs of the recently
completed expansion and extension project ("The Chicago
Project") could be recovered from  shippers may be examined
in this proceeding and that, while Northern Border Pipeline
had not proposed to change the depreciation rates approved
in the last rate case, it had the burden of proving that the
depreciation rates are just and reasonable.

     On September 26, 2000, Northern Border Pipeline filed a
stipulation and agreement in its 1999 rate case proceeding
that documented a settlement.  On December 13, 2000, the
FERC issued its order approving the terms of the settlement.
One of the important elements of the settlement is the
conversion of Northern Border Pipeline's form of tariff from
cost of service to stated rates based on a straight-fixed
variable rate design.  Under the former cost of service
tariff, the firm transportation shippers contracted to pay
for a proportionate share of the pipeline system's cost of
service.  During any given month, each of these shippers
paid a uniform mileage-based charge for the amount of
capacity contracted, and calculated under a cost of service
tariff.  The shippers were obligated to pay their
proportionate share of the cost of service regardless of the
amount of natural gas they actually transported.  Under the
cost of service form of tariff, Northern Border Pipeline
could not charge or collect more than the cost of service.
Under Northern Border Pipeline's new form of tariff,
shippers pay Northern Border Pipeline on the basis of stated
transportation rates.  Under the terms of the settlement,
and in accordance with straight-fixed variable rate design
principles, approximately 98% of the agreed upon revenue
level is attributed to demand charges.  The firm shippers
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 the commodity charge
based on the volumes of gas actually transported.  From
December 1, 1999, through and including December 31, 2000,
the rates were based upon an annual revenue level of
$307 million.  For periods after December 31, 2000, the
rates are based upon an annual revenue level of $305
million.  On a per unit of transportation basis, the rates
under the new tariff are approximately equal to the cost of
service on a per unit basis charged prior to December 1,
1999.  The settlement also provides that 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.  Prior to the new
rate case, Northern Border Pipeline will not be permitted to
increase rates if its costs increase, nor will it be
required to reduce rates based on cost savings.  Northern
Border Pipeline's earnings and cash flow will depend on its
future costs, contracted capacity, the volumes of gas
transported and its ability to recontract capacity at
acceptable rates.

     Under Northern Border Pipeline's previous cost of
service form of tariff, the amount of revenue that it
collected from customers generally declined as the rate base
was recovered.  Under its new tariff, Northern Border
Pipeline is entitled to collect revenue based on stated
rates established in its 1999 rate case until its next rate
case, which will be filed November 1, 2005.  It will,
however, continue to depreciate its rate base at an annual
depreciation rate on transmission plant in service of 2.25%
and its rate base in 2005 will be a factor in determining
what it can charge when it files a new rate case at that
time.  In order to avoid a decline in revenue it can collect
from its customers, Northern Border Pipeline must maintain
or increase its rate base by acquiring or constructing
assets that replace or add to existing pipeline facilities
or by adding new facilities and maintain its level of
contracted capacity at the stated rates.

     It was agreed in the settlement of the 1999 rate case,
that there would be no project cost containment mechanism
adjustment for The Chicago Project and that all costs as of
November 30, 1999 incurred in the construction and
commissioning of the Chicago Project were included in rate
base.  The project cost containment mechanism was created in
the settlement of the 1995 rate case.  The purpose of the
project cost containment mechanism was to limit Northern
Border Pipeline's ability to include cost overruns for The
Chicago Project in rate base and to provide incentives for
cost underruns.

     The settlement of Northern Border Pipeline's 1995 rate
case provided that for at least seven years from the date
The Chicago Project was completed, 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's 1999 rate
case.

     Northern Border Pipeline also provides interruptible
transportation service.  Interruptible transportation
service is transportation in circumstances when surplus
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 Rate Schedule T-1 maximum reservation charge
and commodity rate.  Under the previous cost of service form
of tariff, all interruptible transportation service revenue
generated was credited to the benefit of the firm shippers.
Under the new 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.

     After October 31, 2003, all revenues from interruptible
transportation service and other new services will no longer
be subject to sharing and thus will be retained by Northern
Border Pipeline.  In addition, the settlement of the 1999
rate case also provided for an equal sharing with its firm
shippers of revenue generated from a certain
telecommunications contract for the term of that contract.
Northern Border Pipeline intends to develop new services and
seek the FERC's authorization to implement such services.
While the receipt of those approvals and the future impact
of the revenue sharing provisions of the settlement on
Northern Border Pipeline's earnings cannot be determined at
this time, revenues from these sources are expected to be
minimal through at least October 31, 2003.

Open access regulation

     Beginning on April 8, 1992, the FERC issued a series of
orders, known as Order 636, which required pipeline
companies to unbundle their services and offer sales,
transportation, storage, gathering and other services
separately, to provide all transportation services on a
basis that is equal in quality for all shippers and to
implement a program to allow firm holders of pipeline
capacity to resell or release their capacity to other
shippers. Capacity release provisions were adopted that
allowed shippers to release all or part of their capacity
either permanently or temporarily. Shippers on the pipeline
system have temporarily released capacity as well as
permanently released capacity to other shippers who have
agreed to comply with the underlying contractual and
regulatory obligations associated with that capacity.

     Beginning in 1996, the FERC issued a series of orders,
referred to together as Order 587, amending its open access
regulations to standardize business practices and procedures
governing transactions between interstate natural gas
pipelines, their customers, and others doing business with
the pipelines.  The intent of Order 587 was to assist
shippers that deal with more than one pipeline by
establishing standardized business practices and procedures.
These business standards, developed by the Gas Industry
Standards Board, govern important business practices
including shipper supplied service nominations, allocation
of available capacity, accounting and invoicing of
transportation service, standardized internet business
transactions and capacity release.  Northern Border Pipeline
has implemented the necessary changes to its tariff and
internal systems.

     In 1998, the FERC initiated a number of proceedings to
further amend its open access regulations. In the resulting
order, Order 637 issued February 9, 2000, the FERC revised
the short-term transportation regulations by 1) waiving the
maximum rate ceiling in its capacity release regulations
until September 30, 2002 for short-term releases of capacity
of less than one year; 2) permitting value-oriented peak/off-
peak rates to better allocate revenue responsibility between
short-term and long-term markets; 3) permitting term-
differentiated rates to better allocate risks between
shippers and the pipelines; 4) revising the regulations
related to scheduling procedures, capacity segmentation,
imbalance management and penalties; 5) retaining the right
of first refusal and the five-year matching cap but limiting
the right to customers with maximum rate contracts for 12 or
more consecutive months of service; and 6) adopting new
reporting requirements to take effect September 1, 2000 that
include reporting daily transactional data on all firm and
interruptible contracts, daily reporting of scheduled
quantities at points or segments, and the posting of
corporate and pipeline organizational charts, names and
functions.  As required by Order No. 637, Northern Border
Pipeline filed pro forma tariff sheets in compliance to
address the issues identified in 4) above.  This filing is
pending at the FERC.  All other related compliance filings
and reporting requirements have been completed and
implemented.

     We do not believe that these regulatory initiatives
will have a material adverse impact to Northern Border
Pipeline's operations.

Environmental and Safety Matters

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

     Black Mesa Pipeline Company, our subsidiary, has
received a Findings of Violation by the United States
Environmental Protection Agency ("EPA"), citing violations
of the Clean Water Act and Notice of Violation from the
Arizona Department of Environmental Quality citing
violations of state laws due to discharges of coal slurry on
Black Mesa's pipeline from December 1997 through July 1999.
Black Mesa Pipeline has paid an amount of $128,000 in
penalties for all alleged violations into an escrow account
and has executed a Consent Decree which sets forth this
payment as well as certain preventative measures, reporting
requirements and associated penalties for failure to comply.
Upon execution by the EPA and the Arizona Department of
Environmental Quality, this Consent Decree will be filed in
the United States District Court, District of Arizona for
public notice, comment and final approval.

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

Item 2.   Properties

     Northern Border Pipeline holds the right, title and
interest in its pipeline system.  With respect to real
property, the pipeline system falls into two basic
categories: (a) parcels which Northern Border Pipeline owns
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 of Northern Border
Pipeline 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 across certain
property was obtained by Northern Border Pipeline through
exercise of the power of eminent domain.  Northern Border
Pipeline continues to have the power of eminent domain in
each of the states in which it operates the pipeline system,
although it may not have the power of eminent domain with
respect to Native American tribal lands.

     Approximately 90 miles of the pipeline is 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 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.  This right-
of-way on allotted lands is either a perpetual easement or
for a term of years.  Most of the allotted lands are subject
to a perpetual easement either granted, by the Bureau of
Indian Affairs ("BIA") 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.

     Crestone Gathering Services holds the right, title and
interest in its gathering system which consists of low
pressure gas gathering lines and compression and measurement
facilities.  Crestone Gathering Services' system is utilized
for the gathering and compression of coal bed methane gas
from low pressure at the wellhead to high pressure gathering
lines of which 30 miles is steel pipe and 99 miles is
polyethylene pipe.  Along these gathering lines, Crestone
Gathering Services has installed 42 gas compression
facilities with a total rated horsepower of 36,000 and
measurement facilities to support the receipt and delivery
of gas at various points.  The real property rights for
Crestone Gathering Service's system are derived through
leases, easements, rights-of-way and permits.

Item 3.   Legal Proceedings

     We are not currently parties to any legal proceedings
that, individually or in the aggregate, would reasonably be
expected to have a material adverse impact on our results of
operations or financial position.  Also, see Item 1.
"Business - Environmental and Safety Matters."

Item 4.   Submission of Matters to a Vote of Security Holders

     There were no matters submitted to a vote of security
holders during 2000.

<PAGE>
                           PART II

Item 5.   Market for the Registrant's Common Units
          and Related Security Holder Matters

     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:

<TABLE>
<CAPTION>
                                       Price Range             Cash
                                      High       Low       Distributions

   <S>                               <C>        <C>            <C>
   2000
   First Quarter..................   $29.25     $23.00         $0.65
   Second Quarter.................    28.125     23.75         $0.65
   Third Quarter..................    31.875     27.25         $0.70
   Fourth Quarter.................    33.625     27.75         $0.70


   1999
   First Quarter..................   $35.50     $30.375        $0.61
   Second Quarter.................    33.5625    30.1875        0.61
   Third Quarter..................    31.875     28.00          0.61
   Fourth Quarter.................    29.50      21.625         0.65
</TABLE>


     As of March 1, 2001, there were approximately 1,480
record holders of common units and approximately 39,700
beneficial owners of the common units, including common
units held in street name.

     We currently have 31,503,563 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 18, 2001, we declared a  distribution of $0.70
per unit ($2.80 per unit on an annualized basis), payable
February 14, 2001 to the general partners and unitholders of
record at January 31, 2001.


Item 6.  Selected Financial Data
(in thousands, except per unit, other financial data and operating data)

<TABLE>
<CAPTION>
                                                 Year Ended December 31,
                                 2000         1999         1998         1997         1996
<S>                          <C>          <C>          <C>          <C>          <C>
INCOME DATA:
Operating revenues, net      $  339,732   $  318,963   $  217,592   $  198,574   $  201,943
Operations and
 maintenance                     62,097       53,451       44,770       37,418       28,366
Depreciation and
 amortization                    60,699       54,842       43,885       40,332       46,979
Taxes other than income          28,634       30,952       22,012       22,836       24,390
Regulatory credit                    --           --       (8,878)          --           --
 Operating income               188,302      179,718      115,803       97,988      102,208
Interest expense, net            81,495       67,709       30,922       30,860       32,670
Other income                      8,032        4,562       13,208        8,149        2,900
Minority interests
 in net income                   38,119       35,568       30,069       22,253       22,153
Net income to partners       $   76,720   $   81,003   $   68,020   $   53,024   $   50,285

Net income per unit          $     2.50   $     2.70   $     2.27   $     1.97   $     1.88

Number of units used
 in computation                  29,665       29,347       29,345       26,392       26,200

CASH FLOW DATA:
Net cash provided by
 operating activities        $  169,615   $  173,368   $  103,849   $  119,621   $  137,534
Capital expenditures             19,721      102,270      652,194      152,658       18,597
Distribution per unit              2.65         2.44         2.30         2.20         2.20

BALANCE SHEET DATA
 (AT END OF PERIOD):
Property, plant
 and equipment, net          $1,732,076   $1,745,356   $1,730,476   $1,118,364   $  937,859
Total assets                  2,082,720    1,863,437    1,825,766    1,266,917    1,016,484
Long-term debt, including
 current maturities           1,171,962    1,031,986      976,832      481,355      377,500
Minority interests in
 partners' capital              248,098      250,450      253,031      174,424      158,089
Partners' capital               572,274      515,269      507,426      500,728      410,586

OTHER FINANCIAL DATA:
Ratio of earnings to
 fixed charges (1)                  2.4          2.7          3.0          3.2          3.2

OPERATING DATA:
Northern Border Pipeline:
Million cubic feet
 of gas delivered               852,674      834,833      608,187      621,262      630,148
 Average daily
 throughput (MMcfd)               2,400        2,353        1,706        1,735        1,755
Transportation units
 (million dekatherm
  miles per day):
    Firm service                  2,276        2,289        1,417        1,393        1,392
    Interruptible                    19            6           28           47           56

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

Item 7. Management's Discussion and Analysis of
         Financial Condition and Results of Operations

Results of Operations

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 - Northern
Border Rate Case Proceeding".  Operating revenues for 1999 were
determined under Northern Border Pipeline's 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 the acquisition of gas
gathering businesses in late September 2000 (see Item 1.
"Business - General").

     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.

     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.

Year Ended December 31, 1999 Compared With the Year Ended
December 31, 1998

     Operating revenues, net increased $101.4 million (47%) for
the year ended December 31, 1999, as compared to the same period
in 1998, due primarily to additional revenue from Northern Border
Pipeline's operation of The Chicago Project facilities.
Additional receipt capacity of 700 mmcfd, a 42% increase, and new
firm transportation agreements with 27 shippers resulted from The
Chicago Project.  Northern Border Pipeline's cost of service
tariff provided an opportunity to recover operations and
maintenance costs of the pipeline, taxes other than income taxes,
interest, depreciation and amortization, an allowance for income
taxes and a regulated return on equity.  Northern Border Pipeline
was generally allowed an opportunity to collect from its shippers
a return on unrecovered rate base as well as recover that rate
base through depreciation and amortization.  The Chicago Project
increased Northern Border Pipeline's rate base, which increased
return for the year ended December 31, 1999.  Also reflected in
the increase in 1999 revenues are recoveries of increased
pipeline operating expenses due to the new facilities.

     Operations and maintenance expense increased $8.7 million
(19%) for the year ended December 31, 1999, from the same period
in 1998, due primarily to operations and maintenance expenses for
The Chicago Project facilities and increased employee payroll and
benefit expenses.

     Depreciation and amortization expense increased $11.0
million (25%) for the year ended December 31, 1999, as compared
to the same period in 1998, due primarily to The Chicago Project
facilities placed into service.  The impact of the additional
facilities on depreciation and amortization expense was partially
offset by a decrease in the depreciation rate applied to
transmission plant from 2.5% to 2.0%.  Northern Border Pipeline
agreed to reduce the depreciation rate at the time The Chicago
Project was placed into service as part of a previous rate case
settlement.

     Taxes other than income increased $8.9 million (41%) for the
year ended December 31, 1999, as compared to the same period in
1998, due primarily to ad valorem taxes attributable to the
facilities placed into service for The Chicago Project.

     For the year ended December 31, 1998, Northern Border
Pipeline recorded a regulatory credit of $8.9 million.  During
the construction of The Chicago Project, Northern Border Pipeline
placed new facilities into service in advance of the December
1998 project in-service date to maintain gas flow at firm
contracted capacity while existing facilities were being
modified.  The regulatory credit deferred the cost of service of
these new facilities, which Northern Border Pipeline began to
recover from its shippers commencing with the in-service date of
The Chicago Project.

     Interest expense, net increased $36.8 million (119%) for the
year ended December 31, 1999, as compared to the same period in
1998, due to an increase in interest expense of $17.9 million and
a decrease in interest expense capitalized of $18.9 million.
Interest expense increased due primarily to an increase in
average debt outstanding, reflecting amounts borrowed to finance
a portion of the capital expenditures for The Chicago Project.
The impact of the increased borrowings on interest expense was
partially offset by a decrease in average interest rates between
1998 and 1999.  The decrease in interest expense capitalized is
due to the completion of construction of The Chicago Project in
December 1998.

     Other income decreased $8.6 million (65%) for the year ended
December 31, 1999, as compared to the same period in 1998,
primarily due to a decrease in the allowance for equity funds
used during construction.  The decrease in the allowance for
equity funds used during construction is due to the completion of
construction of The Chicago Project in December 1998.

     Minority interests in net income increased $5.5 million
(18%) for the year ended December 31, 1999, as compared to the
same period in 1998, due to increased net income for Northern
Border Pipeline.

Liquidity and Capital Resources

General

     In August 1999, Northern Border Pipeline completed a private
offering of $200 million of 7.75% Senior Notes due 2009, which
notes were subsequently exchanged in a registered offering for
notes with substantially identical terms ("Pipeline Senior
Notes").  The indenture under which the Pipeline Senior Notes
were issued does not limit the amount of unsecured debt Northern
Border Pipeline may incur, but does contain material financial
covenants, including restrictions on incurrence of secured
indebtedness.  The proceeds from the Pipeline Senior Notes were
used to reduce indebtedness under a June 1997 credit agreement.

     In June 1997, Northern Border Pipeline entered into a credit
agreement ("Pipeline Credit Agreement") with certain financial
institutions to borrow up to an aggregate principal amount of
$750 million.  The Pipeline Credit Agreement is comprised of a
$200 million five-year revolving credit facility to be used for
the retirement of Northern Border Pipeline's prior credit
facilities and for general business purposes, and a $550 million
three-year revolving credit facility to be used for the
construction of The Chicago Project.  Effective March 1999, in
accordance with the provisions of the Pipeline Credit Agreement,
Northern Border Pipeline converted the three-year revolving
credit facility to a term loan maturing in 2002.  At December 31,
2000, $424 million was outstanding under the term loan and $45
million was outstanding under the five-year revolving credit
facility.

     At December 31, 2000, Northern Border Pipeline also had
outstanding $184 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 were repaid
in August 2000.  The Series B Notes with a principal amount of
$41 million mature in August 2001.  Northern Border Pipeline
anticipates borrowing on the Pipeline Credit Agreement to repay
the Series B Notes.

     In June 2000, the Partnership completed a private offering
of $150 million of 8 7/8% Senior Notes due 2010 ("Partnership
Senior Notes").  In September 2000, the Partnership completed an
additional private offering of $100 million of Partnership Senior
Notes.  The Partnership Senior Notes were subsequently exchanged
in a registered offering for notes with substantially identical
terms.  The indenture under which the Partnership Senior Notes
were issued does not limit the amount of unsecured debt the
Partnership may incur, but does contain material financial
covenants, including restrictions on incurrence of secured
indebtedness.  The proceeds from the Partnership Senior Notes
were used in acquisitions made by the Partnership in June 2000
and September 2000 (see Cash Flows from Investing Activities).

     In June 2000, the Partnership entered into two credit
agreements with certain financial institutions, a $75 million 364-
day credit agreement and a $75 million three-year revolving
credit agreement (collectively, "2000 Partnership Credit
Agreements").  At December 31, 2000, $26.3 million was
outstanding under the 2000 Partnership Credit Agreements.

     In November 2000, the Partnership sold, through an
underwritten public offering, 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 the 2000
Partnership Credit Agreements.

     In March 2001, the Partnership completed a private offering
of $225 million of 7.10% Senior Notes due 2011 ("2001 Partnership
Senior Notes").  The Partnership will register an exchange offer
with the Securities and Exchange Commission to exchange the 2001
Partnership Senior Notes for notes with substantially identical
terms.  The indenture under which the 2001 Partnership Senior
Notes were issued does not limit the amount of unsecured debt the
Partnership may incur, but does contain material financial
covenants, including restrictions on incurrence of secured
indebtedness.  The proceeds from the 2001 Partnership Senior
Notes are to be used to fund a portion of the acquisition of Bear
Paw Energy (see Item 1. Business - Pending Acquisitions) and for
capital investments and general corporate purposes.

     In March 2001, the Partnership entered into a $200 million
three-year revolving credit agreement with certain financial
institutions ("2001 Partnership Credit Agreement").  The 2001
Partnership Credit Agreement is to be used for capital
expenditures, working capital and general business purposes.  The
2001 Partnership Credit Agreement replaced the 2000 Partnership
Credit Agreements discussed previously.

     Short-term liquidity needs will be met by internal sources
and through the lines of credit discussed above.  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 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 provided by operating activities increased
$69.5 million to $173.4 million for the year ended December 31,
1999, as compared to the same period in 1998, primarily
attributed to The Chicago Project facilities placed into service
in late December 1998.

Cash Flows From Investing Activities

      Business acquisitions for the year ended December 31, 2000
include gas gathering businesses in the Powder River and Wind
River basins in Wyoming for approximately $229.5 million.  For
the comparable period in 1999, the Partnership acquired a 39%
common member interest in Bighorn for $31.9 million.  See Item 1.
"Business - General" for a discussion of the acquisitions.

      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 Enron North America.  As part of
the terms of the purchase agreement, Enron North America agreed
to fund approximately $3.5 million of an equity investment in
Lost Creek.  Crestone Energy Ventures expects to make the
investment in Lost Creek during 2001.

     Capital expenditures of $19.7 million for the year ended
December 31, 2000 included $7.4 million for Northern Border
Pipeline's Project 2000 (see Item 1. "Business - Future Demand
and Competition") and $3.8 million for gas gathering facilities
for Crestone Energy Ventures.  For the same period in 1999,
capital expenditures were $102.3 million and included $85.5
million for The Chicago Project and $2.5 million for Project
2000.  The remaining capital expenditures for 2000 and 1999 are
primarily related to renewals and replacements of existing
facilities.

     Total capital expenditures and investments in unconsolidated
affiliates for 2001 are estimated to be $198 million.  Capital
expenditures for Northern Border Pipeline are estimated to be $97
million, including approximately $81 million for Project 2000 and
approximately $16 million primarily for renewals and replacements
of existing facilities.  Northern Border Pipeline currently
anticipates funding its 2001 capital expenditures primarily by
using internal sources and borrowing on the Pipeline Credit
Agreement.  Capital expenditures for Crestone Energy Ventures are
estimated to be $79 million and investments in unconsolidated
affiliates are estimated to be $22 million for 2001.  The
Partnership anticipates financing Crestone Energy Venture's
capital requirements primarily by borrowing on the Partnership
Credit Agreements or other debt facilities.

     If the acquisitions discussed in Item 1. "Business - Pending
Acquisitions" are completed, capital expenditures of $30 to $35
million, in addition to those discussed above, are expected in
2001.

Cash Flows From Financing Activities

     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
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 the 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 a cash
overdraft of approximately $22.4 million primarily due to
Northern Border Pipeline's refund checks outstanding.  The goal
of our cash management program is to maximize the amount of our
cash and cash equivalents balance in highly liquid, interest-
bearing investments.  Those investments are converted to cash
when needed to replenish our bank accounts for check clearing
requirements.

     Cash flows used in financing activities were $57.3 million
for the year ended December 31, 1999, as compared to cash flows
provided by financing activities of $482.6 million for the year
ended December 31, 1998.  Cash distributions to the unitholders
and the general partners increased $4.3 million reflecting an
increase in the quarterly distribution from $2.30 per unit for
1998 to $2.44 per unit for 1999.  Distributions paid to minority
interest holders were $38.1 million for the year ended December
31, 1999, as compared to net cash contributions received from
minority interest holders of $48.5 million for the year ended
December 31, 1998, which included amounts needed to finance a
portion of the capital expenditures for The Chicago Project.
Financing activities for the year ended December 31, 1998 reflect
$7.6 million in net proceeds from the issuance of 225,000 common
units and related capital contributions by the Partnership's
general partners in January 1998.  Advances under the Pipeline
Credit Agreement, which were primarily used to finance a portion
of the capital expenditures for The Chicago Project, were $90.0
million for the year ended December 31, 1999.  Advances under a
Partnership credit agreement, which were used for the acquisition
of Bighorn, were $24.5 million for the year ended December 31,
1999.  For the same period in 1998, advances under the Pipeline
Credit Agreement and a Partnership credit agreement totaled
$498.0 million.  During the year ended December 31, 1999, $263.0
million was repaid on the Pipeline Credit Agreement.

New Accounting Pronouncements

     In June 1998, the Financial Accounting Standards Board
("FASB") issued Statement of Financial Accounting Standards
("SFAS") No. 133, "Accounting for Derivative Instruments and
Hedging Activities."  In June 1999, the FASB issued SFAS No. 137,
which deferred the effective date of SFAS No. 133 to fiscal years
beginning after June 15, 2000.  In June 2000, the FASB issued
SFAS No. 138, which amended certain guidance within SFAS No. 133.
See Note 11 to the Consolidated Financial Statements.

Information Regarding Forward Looking Statements

     Statements in this Annual Report that are not historical
information are forward looking statements. Such forward looking
statements include:

  *  the discussions under "Business - Future Demand and
     Competition" and elsewhere regarding Northern Border
     Pipeline's efforts to pursue opportunities to further
     increase the capacity of its pipeline system;

  *  the discussion under "Business - Northern Border Rate Case
     Proceeding" regarding Northern Border Pipeline's rate case
     settlement;

  *  the discussions under "Business - Pending Acquisitions"; and

  *  the discussion 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 can give no assurance that our
goals will be achieved or that our expectations regarding future
developments will be realized.  Important factors that could
cause actual results to differ materially from those in the
forward looking statements include:

  *  future demand for natural gas;

  *  availability of economic western Canadian natural gas;

  *  industry conditions;

  *  natural gas, political and regulatory developments that
     impact FERC proceedings;

  *  Northern Border Pipeline's success in sustaining its
     positions in such proceedings, or the success of intervenors
     in opposing Northern Border Pipeline's positions;

  *  Northern Border Pipeline's ability to replace its rate base
     as it is depreciated and amortized;

  *  competitive developments by Canadian and U.S. natural gas
     transmission companies;

  *  political and regulatory developments in the U.S. and
     Canada;

  *  our ability to successfully negotiate final definitive
     purchase agreements and to receive necessary approvals; and

  *  conditions of the capital markets and equity markets.

Item 7a. Quantitative and Qualitative Disclosures About Market Risk

      Our interest rate exposure results from variable rate
borrowings from commercial banks.  To mitigate potential
fluctuations in interest rates, we attempt to maintain a
significant portion of our consolidated debt portfolio in fixed
rate debt.  We also use interest rate swap agreements to increase
the portion of fixed rate debt.  As of December 31, 2000,
approximately 60% of our debt portfolio, after considering the
effect of interest rate swap agreements, is in fixed rate debt.

      If average interest rates change by one percentage compared
to rates in effect as of December 31, 2000, consolidated annual
interest expense would change by approximately $4.6 million.
This amount has been determined by considering the impact of the
hypothetical interest rates on our variable rate borrowings
outstanding as of December 31, 2000.

Item 8.  Financial Statements and Supplementary Data

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

Item 9.  Changes in and Disagreements With Accountants on Accounting and
         Financial Disclosure

     None.

Item 10. Partnership Management

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

     As is commonly the case with publicly-traded partnerships,
we do not directly employ any of the persons responsible for
managing or operating the Partnership or for providing it with
services relating to its day-to-day business affairs.  We have
entered into an Administrative Services Agreement with NBP
Services Corporation, a wholly-owned subsidiary of Enron,
pursuant to which NBP Services provides tax, accounting, legal,
cash management, investor relations, operating and other services
for the Partnership.  NBP Services has 22 employees and uses the
employees of Enron or its affiliates who have duties and
responsibilities other than those relating to the Administrative
Services Agreement.  Upon completion of the acquisition of the
interests in Bear Paw, NBP Services will increase its employees
by approximately 100.  In consideration for its services under
the Administrative Services Agreement, NBP Services is reimbursed
for its direct and indirect costs and expenses, including an
allocated portion of employee time and Enron's overhead costs.

     Set forth below is certain information concerning the
members of the Partnership Policy Committee, our representatives
on the Northern Border Management Committee and the persons
designated by the Partnership Policy Committee as our executive
officers and as Audit Committee members.  All members of the
Partnership Policy Committee and our representatives on the
Northern Border Management Committee serve at the discretion of
the general partner that appointed them.  The persons designated
as executive officers serve in that capacity at the discretion of
the Partnership Policy Committee.  Effective October 1, 2000,
William R. Cordes replaced Larry L. DeRoin as our Chief Executive
Officer and Chairman of the Partnership Policy Committee and of
the Northern Border Management Committee.  The members of the
Partnership Policy Committee receive no management fee or other
remuneration for serving on this Committee.  The Audit Committee
members are elected, and may be removed, by the Partnership
Policy Committee.  Each Audit Committee member receives an annual
fee of $20,000 and is paid $1,500 for each meeting attended.
Effective February 2001, a third Audit Committee member was
elected.

Name                             Age           Positions

Executive Officers:
    William R. Cordes             52      Chief Executive Officer
    Jerry L. Peters               43      Chief Financial and Accounting
                                           Officer

Members of Partnership Policy
  Committee and Partnership's
  representatives on Northern
  Border Management Committee:

    William R. Cordes             52      Chairman
    Stanley C. Horton             51      Member
    Cuba Wadlington, Jr.          57      Member

Members of Audit Committee:
    Daniel P. Whitty              69      Chairman
    Daniel Dienstbier             60      Member
    Gerald B. Smith               50      Member


     William R. Cordes was named Chief Executive Officer of the
Partnership and Chairman of the Partnership Policy Committee in
October 2000.  Mr. Cordes is the President of Northern Plains, an
Enron subsidiary, having been appointed to that position on
October 1, 2000, and is a director of Northern Plains.  Mr.
Cordes was named Chairman of the Northern Border Management
Committee October 1, 2000.  He started his career with another
Enron company, Northern Natural, in 1970 and has worked in
several management positions at Northern Natural.  In June of
1993, he was named President of Northern Natural and added the
position of President of Transwestern Pipeline in May of 1996.

     Stanley C. Horton was appointed to the Partnership Policy
Committee and to the Northern Border Management Committee in
December 1998.  Mr. Horton is the Chairman and Chief Executive
Officer of Enron Transportation Services Company, formerly the
Enron Gas Pipeline Group, and has held that position since
January 1997.  From February 1996 to January 1997, he was Co-
Chairman and Chief Executive Officer of Enron Operations Corp.
From June 1993 to February 1996, he was President and Chief
Operating Officer of Enron Operations Corp.  He is a Director,
Chairman of the Board and Chief Executive Officer of EOTT Energy
Corp., the general partner of EOTT Energy Partners, L.P.

     Cuba Wadlington, Jr. was named to the Partnership Policy
Committee and to the Northern Border Management Committee on
December 1, 1999.  On January 4, 2000, Mr. Wadlington was named
President and Chief Executive Officer of Williams Gas Pipeline.
Previously, he had served as Executive Vice President and Chief
Operating Officer of Williams Gas Pipeline since July 1999.  Mr.
Wadlington joined Transco in 1995 when Williams acquired Transco
Energy Company.  From 1995 to 1999, he served as senior vice
president and general manager of Williams Gas Pipeline-Transco.
From 1988 to 1995, he served as senior vice president and general
manager of Williams Western Pipeline Company, executive vice
president of Kern River Gas Transmission Company, and director of
Northwest Pipeline Corporation and Williams Western Pipeline, all
affiliates or subsidiaries of Williams.  Mr. Wadlington serves on
the Board of Directors of Williams Communication Group Inc., and
Sterling Bancshares Inc.

     Jerry L. Peters was named Chief Financial and Accounting
Officer in July 1994.  Mr. Peters has held several management
positions with Northern Plains since 1985 and was elected
Treasurer for Northern Plains in October 1998, Vice President of
Finance for Northern Plains in July 1994, and director of
Northern Plains in August 1994.  Mr. Peters was also named Vice
President, Finance of Enron Transportation Services Company in
February 2001.  Prior to joining Northern Plains in 1985, Mr.
Peters was employed as a Certified Public Accountant by KPMG Peat
Marwick, LLP.

     Daniel P. Whitty was appointed to the Audit Committee in
December 1993.  Mr. Whitty is an independent financial
consultant.  He is a director of Enron Funding Corp., Enron
Equity Corp. and of EOTT Energy Corp., all  subsidiaries of
Enron, and the latter of which is the general partner of EOTT
Energy Partners, L.P.  He has served as a member of the Board of
Directors of Methodist Retirement Communities Inc., and a Trustee
of the Methodist Retirement Trust.  Mr. Whitty was a partner at
Arthur Andersen & Co. until his retirement on January 31, 1988.

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

     Daniel Dienstbier was appointed to the Audit Committee
effective February 1, 2001.  Mr. Dienstbier is currently a member
of the Board of Directors of Dynegy Corporation and has served on
that board since 1995.  At the time of his retirement in 1994, he
was the President and Chief Operating Officer of American Oil &
Gas Company.  He serves on arbitration panels involving energy
contract disputes.  From 1965 through mid-1988, Mr. Dienstbier
held various positions with Northern Natural Gas Company.  From
1985 to 1988, he was the President of Enron's Gas Pipeline Group,
which included Enron's interest in Northern Border Pipeline.

Item 11.  Executive Compensation

     The following table summarizes certain information regarding
compensation paid or accrued during each of Northern Plains' last
three fiscal years to the executive officers of the Partnership
(the "Named Officers") for services performed in their capacities
as executive officers of Northern Plains:

<TABLE>

                   Summary Compensation Table
                                                                                                                   All Other
<CAPTION>
                                 Annual Compensation                          Long-Term Compensation             Compensation
                                                                                      Securities
                                                                       Restricted     Underlying
                                                     Other Annual     Stock Awards   Options/SARs   LTIP Payouts
Name & Position       Year   Salary(1)   Bonus(2)   Compensation(3)      ($)(4)          (#)           ($)(5)       ($)(6)

<S>                   <C>    <C>         <C>            <C>             <C>             <C>           <C>          <C>
Larry L. DeRoin       2000   $209,167    $     --       $16,844         $164,754        11,335        $403,125     $513,534
Chief Executive       1999   $266,367    $225,000       $ 7,773         $     --            --        $     --     $ 10,413
Officer               1998   $256,067    $250,000       $ 7,200         $125,024        19,020        $     --     $  6,380

William R. Cordes     2000   $311,000    $250,000       $15,000         $205,984        17,405        $131,250     $ 13,110
Chief Executive
Officer

Jerry L. Peters       2000   $145,293    $110,000       $ 3,708         $112,385        15,040        $     --     $ 10,091
Chief Financial and   1999   $132,933    $100,000       $ 3,983         $     --         9,070        $     --     $  5,260
Accounting Officer    1998   $123,225    $110,000       $ 1,214         $ 60,030        20,000        $     --     $  1,956

<FN>
(1)  Mr. DeRoin retired effective September 30, 2000.  Mr. Cordes
     was appointed President of Northern Plains and Chief Executive
     Officer of the Partnership on October 1, 2000.
(2)  Employees may elect to receive Northern Border phantom
     units, Enron Corp. phantom stock, and/or Enron Corp. stock
     options in lieu of all or a portion of an annual bonus payment.
     Mr. Peters elected to receive Northern Border phantom units in
     lieu of a portion of the cash bonus payment under the Northern
     Border Phantom Unit Plan.  He received 1,532 units in 1999 and
     1,450 units in 2000.  In each case, units will be released to him
     five years following the grant date.
(3)  Other Annual Compensation includes cash perquisite
     allowances, service awards, and vacation payouts.  Also, Enron
     maintains three deferral plans for key employees under which
     payment of base salary, annual bonus, and long-term incentive
     awards may be deferred to a later specified date. Under the 1985
     Deferral Plan, interest is credited on amounts deferred based on
     150% of Moody's seasoned corporate bond yield index with a
     minimum rate of 12%, which for 1998, 1999 and 2000 was the
     minimum rate of 12%.  No interest has been reported as Other
     Annual Compensation under the 1985 Deferral Plan for
     participating Named Officers because the crediting rates during
     1998, 1999, and 2000, did not exceed 120% of the long-term
     Applicable Federal Rate of 14.38% in effect at the time the 1985
     Deferral Plan was implemented.  Beginning January 1, 1996, the
     1994 Deferral Plan credits interest based on fund elections
     chosen by participants.  Since earnings on deferred compensation
     invested in third-party investment vehicles, comparable to mutual
     funds, need not be reported, no interest has been reported as
     Other Annual Compensation under the 1994 Deferral Plan during
     1998, 1999 and 2000.
(4)  The aggregate total of shares in unreleased Enron restricted
     stock holdings and their values as of December 31, 2000, for each
     of the Named Officers is: Mr. Cordes, 7,737 shares valued at
     $643,138, and Mr. Peters, 2,755 shares valued at $229,009.
     Dividend equivalents for all restricted stock awards accrue from
     date of grant and are paid upon vesting.
(5)  Reflects cash payments under the Enron Corp. Performance
     Unit Plan for the 1996-1999 period.  Payments made under the
     Performance Unit Plan are based on Enron's total shareholder
     return relative to its peers.  Enron's performance over the 1996-
     1999 performance period rendered a value of $1.50 based on a
     ranking of second as compared to 11 industry peers.  Mr. DeRoin's
     payment includes amounts relating to 1997-2000 and 1998-2001
     performance periods ($187,250 and $103,125 respectively) which
     were paid early due to his retirement.
(6)  The amounts shown include the value of Enron Common Stock
     allocated to employees' special subaccounts under Enron's
     Employee Stock Ownership Plan, matching contributions to
     employees' Enron Corp. Savings Plan, and imputed income on life
     insurance benefits.  Mr. DeRoin received a $500,000 payment
     following his retirement.  Such payment was in lieu of any
     severance pay or severance benefits that otherwise would be
     payable under Enron's Severance Pay Plan. In addition, Mr. DeRoin
     has entered into an agreement under which he has agreed to
     provide consulting services to Northern Plains and its businesses
     until September 30, 2002 for which he receives a payment of
     $20,833 per month.
</TABLE>

Stock Option Grants During 2000

     The following table sets forth information with respect to grants of
stock options pursuant to Enron's stock plans to the Named Officers
reflected in the Summary Compensation Table.  No stock appreciation rights
were granted during 2000.

<TABLE>
<CAPTION>
                                                                                Potential Realizable Value at
                  Individual Grants                                             Assumed Annual Rates of Stock
                     Number of         % of Total                               Price Appreciation for Option Term (1)
                     Securities       Options/SARs
                     Underlying        Granted to    Exercise or
                    Options/SARs      Employees in   Base Price    Expiration
    Name             Granted(#)       Fiscal Year      ($/Sh)         Date           0%(2)      5%        10%

<S>                    <C>       <C>     <C>          <C>          <C>               <C>     <C>        <C>
Larry L. DeRoin        11,285    (3)     0.03%        $55.5000     01/18/2007        $  --   $254,974   $594,198
                           50    (4)     0.00%        $55.5000     01/18/2007        $  --   $  1,130   $  2,633

William R. Cordes      14,105    (3)     0.04%        $55.5000     01/18/2007        $  --   $318,689   $742,682
                           50    (4)     0.00%        $55.5000     01/18/2007        $  --   $  1,130   $  2,633
                        3,250    (6)     0.01%        $83.1250     12/29/2007        $  --   $ 73,431   $171,125

Jerry L. Peters         7,695    (3)     0.02%        $55.5000     01/18/2007        $  --   $173,861   $405,171
                           50    (4)     0.00%        $55.5000     01/18/2007        $  --   $  1,130   $  2,633
                        5,770    (5)     0.01%        $65.0000     01/24/2007        $  --   $152,683   $355,816
                        1,525    (6)     0.00%        $83.1250     12/29/2007        $  --   $ 34,456   $ 80,297

<FN>
(1) The dollar amounts under these columns represent the potential
    realizable value of each grant of options assuming that the market price on
    Enron Common Stock appreciates in value from the date of grant at the 5%
    and 10% annual rates prescribed by the SEC and therefore are not intended
    to forecast possible future appreciation, if any, of the price of Enron
    Common Stock.
(2) An appreciation in stock price, which will benefit all shareholders,
    is required for optionees to receive any gain.  A stock price appreciation
    of 0% would render the option without value to the optionees.
(3) Represents stock options awarded under the Enron Corp. Long-Term
    Incentive Program.  Awards vest 25% on the grant date and 25% on each
    anniversary thereafter.
(4) A grant of 50 stock options was provided to each eligible Enron
    employee in recognition of Enron stock reaching a fair market value of $50
    after the August, 1999, 2-for-1 stock split.
(5) Mr. Peters elected to receive stock options in lieu of a portion of
    his 1999 annual cash bonus payment in the form of stock options which were
    granted in January, 2000 and were 100% vested on date of grant.
(6) All eligible employees received an option grant under the EnronOptions
    Program.   The EnronOptions Program provides a grant of options equal to 5%
    of base annual salary for each year of participation in the program, not to
    exceed five years of participation.  Stock options vest 20% each year
    beginning June 30, 2001.
</TABLE>

Aggregated Stock Option/SAR Exercises During 2000 and Stock
Option/SAR Values as of December 31, 2000

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

<TABLE>
<CAPTION>
                                                  Number of Securities
                                                 Underlying Unexercised          Value of Unexercised
                      Shares                         Options/SARs at          In-the-Money Options/SARs
                    Acquired on      Value          December 31, 2000           December 31, 2000 (1)
  Name              Exercise (#)    Realized   Exercisable   Unexercisable   Exercisable   Unexercisable

<S>                    <C>         <C>           <C>            <C>          <C>             <C>
Larry L. DeRoin        102,990     $5,458,031     50,875            --       $ 2,630,794     $       --
William R. Cordes       47,130     $2,922,001    213,788        41,327       $13,454,935     $1,945,463
Jerry L. Peters          9,090     $  432,676     54,084         9,891       $ 2,915,839     $  393,525

<FN>
(1) The dollar value in this column for Enron Corp. stock
    options was calculated by determining the difference between the
    fair market value underlying the options as of December 31, 2000
    ($83.1250) and the grant price.
</TABLE>

Retirement and Supplemental Benefit Plans

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

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

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

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

<TABLE>
<CAPTION>
                        Estimated
             Current    Credited      Current        Estimated
             Credited   Years of    Compensation   Annual Benefit
             Years of    Service      Covered       Payable Upon
             Service    at Age 65     By Plans       Retirement

<S>            <C>         <C>        <C>             <C>
Mr. Cordes     30.4        43.1       $311,000        $142,234
Mr. Peters     15.9        37.8       $145,293        $ 78,957
________
<FN>
NOTE:  The estimated annual benefits payable are based on the
       straight life annuity form without adjustment for any offset
       applicable to a participant's retirement subaccount in
       Enron's ESOP.
</TABLE>

     Mr. DeRoin participates in the Executive Supplemental
Survivor Benefit Plan.  In the event of death after retirement,
the Plan provides an annual benefit to the participant's
beneficiary equal to 50 percent of the participant's annual base
salary at retirement, paid for 10 years.  The Plan also provides
that in the event of death before retirement, the participant's
beneficiary receives an annual benefit equal to 30% of the
participant's annual base salary at death, paid for the life of
the participant's spouse (but for no more than 20 years in some
cases).

Severance Plans

     Enron's Severance Pay Plan, as amended, provides for the
payment of benefits to employees who are terminated for failing
to meet performance objectives or standards or who are terminated
due to reorganization or economic factors.  The amount of
benefits payable for performance related terminations is based on
length of service and may not exceed six weeks' pay.  For those
terminated as the result of reorganization or economic
circumstances, the benefit is based on length of service and
amount of pay up to a maximum payment of 26 weeks of base pay.
If the employee signs a Waiver and Release of Claims Agreement,
the severance pay benefits are doubled.  Under no circumstances
will the total severance pay benefit exceed 52 weeks of pay.
Under the Enron Corp. Change of Control Severance Plan, in the
event of an unapproved change of control of Enron, any employee
who is involuntarily terminated within two years following the
change of control will be eligible for severance benefits equal
to two weeks of base pay multiplied by the number of full or
partial years of service, plus one month of base pay for each
$10,000 (or portion of $10,000) included in the employee's annual
base pay, plus one month of base pay for each five percent of
annual incentive award opportunity under any approved plan.  The
maximum an employee can receive is 2.99 times the employee's
average W-2 earnings over the past five years.


Item 12.   Security Ownership of Certain Beneficial
           Owners and Management

     The following table sets forth the beneficial ownership of
the voting securities of the Partnership as of February 15, 2001
by our executive officers, members of the Partnership Policy
Committee and the Audit Committee who own units and by certain
beneficial owners.  Other than as set forth below, no person is
known by the general partners to own beneficially more than 5% of
the voting securities.

                           Amount and Nature of Beneficial Ownership
                                         Common Units
                                      Number     Percent
                                    of Units1/   of Class

Jerry L. Peters                         1,000         *
  1111 South 103rd Street
  Omaha, NE 68124-1000
Stanley C. Horton
  1400 Smith Street
  Houston, TX 77002-7369               10,000         *
The Williams Companies, Inc.2/      1,123,500       3.6
  One Williams Center
  Tulsa, OK  74101-3288
Enron Corp.2/
  1400 Smith Street
  Houston, TX   77002               3,215,452      10.2
Duke Energy Corp.2/
  422 So. Church St.
  Charlotte, NC  88242-0001         2,086,500       6.6
______________
*  Less than 1%.
1/ All units involve sole voting and investment power.

2/ Indirect ownership through their subsidiaries.


Item 13.   Certain Relationships and Related Transactions

     We have extensive ongoing relationships with the general
partners.  Such relationships include the following: (i) Northern
Plains provides, in its capacity as the operator of the Northern
Border pipeline system, certain tax, accounting and other
information to the Partnership, (ii) NBP Services, an affiliate
of Enron, assists the Partnership in connection with the
operation and management of the Partnership and operating
services for Crestone Energy Ventures pursuant to the terms of an
Administrative Services Agreement between the Partnership and NBP
Services, (iii) NBP Energy Pipelines, L.L.C. (now known as
Crestone Energy Ventures, L.L.C) purchased from Enron North
America Corp., an affiliate of Enron, interests in gas gathering
businesses in the Powder River and Wind River Basins in Wyoming
for approximately $209 million, and (iv) Crestone Energy Ventures
provides to Enron North America Corp., under a Master Services
Agreement effective September 21, 2000, gas and administrative
services for fixed and variable fees.  The amount of fixed fees
for 2000 was $45,000 per day and for 2001 is $21,600 per day.

     In addition, Northern Border Pipeline has extensive ongoing
relationships with the general partners and certain of their
affiliates and with affiliates of TC PipeLines.  For example,
Northern Plains has acted (since 1980), and will continue to act,
as the operator of the pipeline system pursuant to the terms of
an operating agreement between Northern Plains and Northern
Border Pipeline.

     In addition, as of February 1, 2001:

  *  Enron North America Corp., an affiliate of Enron, is one of
     Northern Border Pipeline's firm shippers, and is obligated
     to pay for 6.3% of the capacity.  It also has contracted
     with Crestone Energy Venture and Crestone Gas Services for
     certain gas and administrative services for which it pays
     both a fixed and variable fee.

  *  TransCanada Energy Marketing USA, Inc., an affiliate of
     TransCanada PipeLines Limited, is one of Northern Border
     Pipeline's firm shippers and is currently obligated to pay
     for 11.4% of the capacity;

  *  Transcontinental Gas Pipe Line Corporation, an affiliate of
     Williams, is one of Northern Border Pipeline's firm shippers
     and is currently obligated to pay for 0.8% of the capacity;
     and

  *  Northern Natural Gas Company, an affiliate of Enron,
     provides a financial guaranty for a portion of the
     transportation capacity held by Pan-Alberta Gas, which
     currently represents 10.5% of the capacity.

     The Partnership Policy Committee, whose members are
designated by our three general partners, establishes the
business policies of the Partnership. We have three
representatives on the Northern Border Management Committee, each
of whom votes a portion of the Partnership's 70% interest on the
Northern Border Management Committee.  These representatives are
also designated by our general partners.

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

     Unless otherwise provided for in a partnership agreement,
the laws of Delaware and Texas generally require a general
partner of a partnership to adhere to fiduciary duty standards
under which it owes its partners the highest duties of good
faith, fairness and loyalty.  Similar rules apply to persons
serving on the Partnership Policy Committee or the Northern
Border Management Committee.  Because of the competing interests
identified above, our Partnership Agreement and the partnership
agreement for Northern Border Pipeline contain provisions that
modify certain of these fiduciary duties.  For example:

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

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

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

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

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

  *  We entered into an amendment to the partnership agreement
     for Northern Border Pipeline that relieves us and TC PipeLines,
     their affiliates and their transferees from any duty to offer
     business opportunities to Northern Border Pipeline, with certain
     exceptions.

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


                             PART IV

Item 14.  Exhibits, Financial Statement Schedules, and Reports on Form 8-K

     (a)(1) and (2) Financial Statements and Financial Statement Schedules

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

     (a)(3) Exhibits

      * 3.1   Form of Amended and Restated Agreement of
              Limited Partnership of Northern Border
              Partners, L.P. (Exhibit 3.1 No. 2 to the
              Partnership's Form S-1 Registration
              Statement, Registration No. 33-66158
              ("Form S-1")).
      * 3.2   Form of Amended and Restated Agreement of
              Limited Partnership For Northern Border
              Intermediate Limited Partnership (Exhibit
              10.1 to Form S-1).
      * 4.1   Indenture, dated as of June 2, 2000,
              between the registrants and Bank One
              Trust Company, N.A. (Exhibit 4.1 to the
              Partnership's Quarterly Report on Form 10-Q
              for the quarterly period ended June 30,
              2000 ("June 2000 10-Q")).
      * 4.2   First Supplemental Indenture, dated as of
              September 14, 2000, between the
              registrants and Bank One Trust Company,
              N.A.(Exhibit 4.2 to Form S-4 Registration
              Statement, Registration No. 333-46212
              ("NBP Form S-4")).
        4.3   Indenture, dated as of March 21, 2001,
              between Northern Border Partners, L.P.
              and Northern Border Intermediate Limited
              Partnership and Bank One Trust Company,
              N.A., Trustee.
        4.4   Registration Rights Agreement dated March
              21, 2001 by and among Northern Border
              Partners, L.P., Northern Border
              Intermediate Limited Partnership, Banc of
              America Securities LLC, SunTrust
              Equitable Securities Corporation, Banc
              One Capital Markets, Inc. and BMO Nesbitt
              Burns Corp.
      * 4.5   Indenture, dated as of August 17, 1999,
              between Northern Border Pipeline Company
              and Bank One Trust Company, NA, successor
              to The First National Bank of Chicago, as
              trustee. (Exhibit No. 4.1 to Northern
              Border Pipeline Company's Form S-4
              Registration Statement, Registration No.
              333-88577 ("NB Form S-4").
      *10.1   Northern Border Pipeline Company General
              Partnership Agreement between Northern
              Plains Natural Gas Company, Northwest
              Border Pipeline Company, Pan Border Gas
              Company, TransCanada Border Pipeline Ltd.
              and TransCan Northern Ltd., effective
              March 9, 1978, as amended (Exhibit 10.2
              to Form S-1).
      *10.2   Operating Agreement between Northern
              Border Pipeline Company and Northern
              Plains Natural Gas Company, dated
              February 28, 1980 (Exhibit 10.3 to Form S-1).
      *10.3   Administrative Services Agreement between
              NBP Services Corporation, Northern Border
              Partners, L.P. and Northern Border
              Intermediate Limited Partnership (Exhibit
              10.4 to Form S-1).
      *10.4   Note Purchase Agreement between Northern
              Border Pipeline Company and the parties
              listed therein, dated July 15, 1992
              (Exhibit 10.6 to Form S-1).
      *10.4.1 Supplemental Agreement to the Note
              Purchase Agreement dated as of June 1,
              1995 (Exhibit 10.6.1 to the Partnership's
              Annual Report on Form 10-K for the year
              ended December 31, 1995 ("1995 10-K")).
      *10.5   Guaranty made by Panhandle Eastern
              Pipeline Company, dated October 31, 1992
              (Exhibit 10.9 to Form S-1).
      *10.6   Northern Border Pipeline Company U.S.
              Shippers Service Agreement between
              Northern Border Pipeline Company and
              Enron Gas Marketing, Inc., dated June 22,
              1990 (Exhibit 10.10 to Form S-1).
      *10.6.1 Amended Exhibit A to Northern Border
              Pipeline Company U.S. Shippers Service
              Agreement between Northern Border
              Pipeline Company and Enron Gas Marketing,
              Inc. (Exhibit 10.10.1 to the
              Partnership's Annual Report on Form 10-K
              for the year ended December 31, 1993
              ("1993 10-K")).
      *10.6.2 Amended Exhibit A to Northern Border
              Pipeline U.S. Shippers Service Agreement
              between Northern Border Pipeline Company
              and Enron Gas Marketing, Inc., effective
              November 1, 1994 (Exhibit 10.10.2 to the
              Partnership's Annual Report on Form 10-K
              for the year ended December 31, 1994).
      *10.6.3 Amended Exhibit A's to Northern Border
              Pipeline Company U.S. Shipper Service
              Agreement effective, August 1, 1995 and
              November 1, 1995 (Exhibit 10.10.3 to 1995
              10-K).
      *10.6.4 Amended Exhibit A to Northern Border
              Pipeline Company U.S. Shipper Service
              Agreement effective April l, 1998
              (Exhibit 10.10.4 to the Partnership's
              Annual Report on Form 10-K for the year
              ended December 31, 1997 ("1997 10-K")).
      *10.7   Guaranty made by Northern Natural Gas
              Company, dated October 7, 1993 (Exhibit
              10.11.1 to 1993 10-K).
      *10.8   Guaranty made by Northern Natural Gas
              Company, dated October 7, 1993 (Exhibit
              10.11.2 to 1993 10-K).
      *10.9   Northern Border Pipeline Company U.S.
              Shippers Service Agreement between
              Northern Border Pipeline Company and
              Western Gas Marketing Limited, as agent
              for TransCanada PipeLines Limited, dated
              December 15, 1980 (Exhibit 10.13 to Form
              S-1).
      *10.9.1 Amendment to Northern Border Pipeline
              Company Service Agreement extending the
              term effective November 1, 1995 (Exhibit
              10.13.1 to 1995 10-K).
      *10.10  Form of Seventh Supplement Amending
              Northern Border Pipeline Company General
              Partnership Agreement (Exhibit 10.15 to
              Form S-1).
      *10.11  Northern Border Pipeline Company U.S.
              Shippers Service Agreement between
              Northern Border Pipeline Company and
              Transcontinental Gas Pipe Line
              Corporation, dated July 14, 1983, with
              Amended Exhibit A effective February 11,
              1994 (Exhibit 10.17 to 1995 10-K).
      *10.12  Form of Credit Agreement among Northern
              Border Pipeline Company, The First
              National Bank of Chicago, as
              Administrative Agent, The First National
              Bank of Chicago, Royal Bank of Canada,
              and Bank of America National Trust and
              Savings Association, as Syndication
              Agents, First Chicago Capital Markets,
              Inc., Royal Bank of Canada, and
              BancAmerica Securities, Inc, as Joint
              Arrangers and Lenders (as defined
              therein) dated as of June 16, 1997
              (Exhibit 10(c) to Amendment No. 1 to Form
              S-3, Registration Statement No. 333-40601
              ("Form S-3")).
      *10.13  Northern Border Pipeline Company U.S.
              Shippers Service Agreement between
              Northern Border Pipeline Company and
              Enron Capital & Trade Resources Corp.
              dated October 15, 1997 (Exhibit 10.21 to
              1997 10-K).
      *10.14  Northern Border Pipeline Company U.S.
              Shippers Service Agreement between
              Northern Border Pipeline Company and
              Enron Capital & Trade Resources Corp.
              dated October 15, 1997 (Exhibit 10.22 to
              1997 10-K).
      *10.15  Northern Border Pipeline Company U.S.
              Shippers Service Agreement between
              Northern Border Pipeline Company and
              Enron Capital & Trade Resources Corp.
              dated August 5, 1997 with Amendment dated
              September 25, 1997 (Exhibit 10.25 to 1997
              10-K).
      *10.16  Northern Border Pipeline Company U.S.
              Shippers Service Agreement between
              Northern Border Pipeline Company and
              Enron Capital & Trade Resources Corp.
              dated August 5, 1997 (Exhibit 10.26 to
              1997 10-K).
      *10.17  Northern Border Pipeline Company U.S.
              Shippers Service Agreement between
              Northern Border Pipeline Company and
              TransCanada Gas Services Inc., as agent
              for TransCanada PipeLines Limited dated
              August 5, 1997 (Exhibit 10.27 to 1997
              10-K).
      *10.18  Project Management Agreement by and
              between Northern Plains Natural Gas
              Company and Enron Engineering &
              Construction Company, dated March 1, 1996
              (Exhibit No. 10.39 to NB Form S-4).
      *10.19  Eighth Supplement Amending Northern
              Border Pipeline Company General
              Partnership Agreement (Exhibit 10.15 to
              NB Form S-4).
       10.20  Revolving Credit Agreement, dated as of
              March 21, 2001, between Northern Border
              Partners, L.P., SunTrust Bank,
              Administrative Agent, Bank of Montreal
              and Bank of America, N.A., Co-Syndication
              Agents and Bank One, NA, Documentation
              Agent and Lenders (as defined therein).
      *10.21  Northern Border Pipeline Company U.S.
              Shippers Service Agreement between
              Northern Border Pipeline Company and Pan-
              Alberta Gas (US) Inc., dated October 1,
              1993, with Amended Exhibit A effective
              June 22, 1998 (Exhibit 10.36 to Northern
              Border Pipeline Company Annual Report on
              Form 10-K for the year ended December 31,
              1999 ("NB Pipeline 1999 10-K")).
      *10.22  Northern Pipeline Company U.S. Shippers
              Service Agreement between Northern Border
              Pipeline Company and Pan-Alberta Gas (US)
              Inc.,(successor to Natgas U.S. Inc.)
              dated October 6, 1989, with Amended
              Exhibit A effective April 2, 1999
              (Exhibit 10.37 to NB Pipeline 1999 10-K).
      *10.23  Northern Border Pipeline Company U.S.
              Shippers Service Agreement between
              Northern Border Pipeline Company and Pan-
              Alberta Gas (U.S.) Inc., dated October l,
              1992, with Amended Exhibit A effective
              June 22, 1998 (Exhibit 10.38 to NB
              Pipeline 1999 10-K).
       10.24  Purchase and Sale Agreement, dated as of
              September 21, 2000 by and between Enron
              North America Corp. and NBP Energy
              Pipeline, L.L.C.(now known as Crestone
              Energy Ventures, L.L.C.).
       10.25  Master Services Agreement, dated as of
              September 21, 2000 between NBP Energy
              Pipelines, L.L.C.,(now known as Crestone
              Energy Ventures, L.L.C.) and Enron North
              America Corp.
       10.26  Acquisition Agreement, dated as of March
              14, 2001, among Northern Border Partners,
              L.P., Northern Border Intermediate
              Limited Partnership, Bear Paw
              Investments, LLC, Bear Paw Energy, LLC
              and Sellers (defined therein).
       21     The subsidiaries of Northern Border
              Partners, L.P. are Northern Border
              Intermediate Limited Partnership;
              Northern Border Pipeline Company; and
              Crestone Energy Ventures, L.L.C.
       23.01  Consent of Arthur Andersen LLP.
      *99.1   Northern Border Phantom Unit Plan
              (Exhibit 99.1 to Amendment No. 1 to Form
              S-8, Registration No. 333-66949).
     *Indicates exhibits incorporated by reference as
      indicated; all other exhibits are filed herewith.

     (b)Reports
      The Partnership filed a Current Report on Form 8-K,
      dated November 2, 2000, reporting the public
      offering of up to 2,156,250 common units
      representing limited partner interests and
      including exhibits.


                           SIGNATURES


   Pursuant to the requirements of Section 13 or 15(d) of the
Securities Exchange Act of 1934, the registrant has duly caused
this report to be signed on its behalf by the undersigned,
thereunto duly authorized on this 29th day of March, 2001.


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




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



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

      Signature                  Title                      Date



   WILLIAM R. CORDES      Chief Executive Officer and     March 29, 2001
   William R. Cordes      Chairman of the Partnership
                          Policy Committee
                          (Principal Executive Officer)



   STANLEY C. HORTON      Member of Partnership Policy    March 29, 2001
   Stanley C. Horton      Committee



   CUBA WADLINGTON, JR.   Member of Partnership Policy    March 29, 2001
   Cuba Wadlington, Jr.   Committee



   JERRY L. PETERS        Chief Financial and             March 29, 2001
   Jerry L. Peters        Accounting Officer



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

                                                                  Page No.

Consolidated Financial Statements

       Report of Independent Public Accountants                     F-2
       Consolidated Balance Sheet - December 31, 2000 and 1999      F-3
       Consolidated Statement of Income - Years Ended               F-4
        December 31, 2000, 1999 and 1998
      Consolidated Statement of Cash Flows - Years Ended            F-5
        December 31, 2000, 1999 and 1998
      Consolidated Statement of Changes in Partners' Capital -
        Years Ended December 31, 2000, 1999 and 1998                F-6
      Notes  to Consolidated Financial Statements                   F-7 through
                                                                    F-26

Financial Statements Schedule

       Report of Independent Public Accountants on Schedule         S-1
       Schedule II - Valuation and Qualifying Accounts              S-2


            Report of Independent Public Accountants


To Northern Border Partners, L.P.:

We have audited the accompanying consolidated balance sheet of
Northern Border Partners, L.P. (a Delaware limited partnership)
and Subsidiaries as of December 31, 2000 and 1999, and the
related consolidated statements of income, cash flows and changes
in partners' capital for each of the three years in the period
ended December 31, 2000.  These financial statements are the
responsibility of the Company's management.  Our responsibility
is to express an opinion on these financial statements based on
our audits.

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

In our opinion, the financial statements referred to above
present fairly, in all material respects, the financial position
of Northern Border Partners, L.P. and Subsidiaries as of December
31, 2000 and 1999, and the results of their operations and their
cash flows for each of the three years in the period ended
December 31, 2000, in conformity with accounting principles
generally accepted in the United States.


                                        ARTHUR ANDERSEN LLP

Omaha, Nebraska,
  January 22, 2001

<PAGE>
<TABLE>
         NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES

                   CONSOLIDATED BALANCE SHEET

                         (In Thousands)
<CAPTION>
                                              December 31,
ASSETS                                      2000        1999

<S>                                          <C>          <C>
CURRENT ASSETS
 Cash and cash equivalents                   $   35,363   $   22,927
 Accounts receivable                             31,538       24,946
 Related party receivables                        9,079        5,292
 Materials and supplies, at cost                  5,736        4,410
 Under recovered cost of service                     --        3,068

   Total current assets                          81,716       60,643

TRANSMISSION PLANT
 Property, plant and equipment                2,454,918    2,410,133
 Less: Accumulated provision for
   depreciation and amortization                722,842      664,777

   Property, plant and equipment, net         1,732,076    1,745,356

INVESTMENTS AND OTHER ASSETS
 Investments in unconsolidated affiliates       221,625       31,895
 Goodwill                                        28,405        9,076
 Other                                           18,898       16,467

   Total investments and other assets           268,928       57,438

   Total assets                              $2,082,720   $1,863,437

LIABILITIES AND PARTNERS' CAPITAL

CURRENT LIABILITIES
 Current maturities of long-term debt        $   44,464   $  183,617
 Accounts payable                                35,413        8,279
 Accrued taxes other than income                 28,493       26,608
 Accrued interest                                15,635       17,608
 Accumulated provision for rate refunds           4,726        2,317

   Total current liabilities                    128,731      238,429

LONG-TERM DEBT, net of current maturities     1,127,498      848,369

MINORITY INTERESTS IN PARTNERS' CAPITAL         248,098      250,450

RESERVES AND DEFERRED CREDITS                     6,119       10,920

COMMITMENTS AND CONTINGENCIES (NOTE 9)

PARTNERS' CAPITAL
 General Partners                                11,445       10,305
 Common Units                                   560,829      504,964

   Total partners' capital                      572,274      515,269

   Total liabilities and partners' capital   $2,082,720   $1,863,437


<FN>
The accompanying notes are an integral part of these consolidated
                      financial statements.
</TABLE>


<PAGE>
<TABLE>

         NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES

                CONSOLIDATED STATEMENT OF INCOME

             (In Thousands, Except Per Unit Amounts)

<CAPTION>
                                     Year Ended December 31,
                                  2000       1999      1998

<S>                                   <C>        <C>        <C>
OPERATING REVENUES
 Operating revenues                   $363,688   $321,280   $217,592
 Provision for rate refunds            (23,956)    (2,317)        --

   Operating revenues, net             339,732    318,963    217,592

OPERATING EXPENSES
 Operations and maintenance             62,097     53,451     44,770
 Depreciation and amortization          60,699     54,842     43,885
 Taxes other than income                28,634     30,952     22,012
 Regulatory credit                          --         --     (8,878)

   Operating expenses                  151,430    139,245    101,789

OPERATING INCOME                       188,302    179,718    115,803

INTEREST EXPENSE
 Interest expense                       81,881     67,807     49,923
 Interest expense capitalized             (386)       (98)   (19,001)

   Interest expense, net                81,495     67,709     30,922

OTHER INCOME
 Allowance for equity funds used
   during construction                     305        101     10,237
 Equity earnings (losses) of
   unconsolidated affiliates              (647)        --         --
 Other income, net                       8,374      4,461      2,971

    Other income                         8,032      4,562     13,208

MINORITY INTERESTS IN NET INCOME        38,119     35,568     30,069

NET INCOME TO PARTNERS                $ 76,720   $ 81,003   $ 68,020

NET INCOME PER UNIT                   $   2.50   $   2.70   $   2.27

NUMBER OF UNITS USED IN COMPUTATION     29,665     29,347     29,345

<FN>
The accompanying notes are an integral part of these consolidated
                      financial statements.
</TABLE>


<PAGE>
<TABLE>
         NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES

              CONSOLIDATED STATEMENT OF CASH FLOWS

                         (In Thousands)
<CAPTION>
                                                         Year Ended December 31,
                                                      2000        1999        1998

<S>                                                <C>         <C>         <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
 Net income to partners                            $  76,720   $  81,003   $  68,020

 Adjustments to reconcile net income to partners
 to net cash provided by operating activities:
   Depreciation and amortization                      61,054      54,895      43,899
   Minority interests in net income                   38,119      35,568      30,069
   Provision for rate refunds                         25,082       2,317          --
   Rate refunds paid                                 (22,673)         --          --
   Allowance for equity funds used
    during construction                                 (305)       (101)    (10,237)
   Reserves and deferred credits                      (4,801)      1,077         (24)
   Regulatory credit                                      --          --      (9,105)
   Changes in components of working capital           (2,279)     (1,482)    (19,243)
   Other                                              (1,302)         91         470

      Total adjustments                               92,895      92,365      35,829

   Net cash provided by operating activities         169,615     173,368     103,849

CASH FLOWS FROM INVESTING ACTIVITIES:
 Capital expenditures for property, plant
   and equipment, net                                (19,721)   (102,270)   (652,194)
 Acquisition of businesses                          (229,505)    (31,895)         --
 Investments in unconsolidated affiliates             (8,766)         --          --

   Net cash used in investing activities            (257,992)   (134,165)   (652,194)

CASH FLOWS FROM FINANCING ACTIVITIES:
 Cash distributions
   General and limited partners                      (80,411)    (73,160)    (68,876)
   Minority Interests                                (40,471)    (38,149)    (18,362)
 Contributions received from Minority Interests           --          --      66,900
 Issuance of partnership interests, net               60,696          --       7,554
 Issuance of long-term debt, net                     431,148     313,526     498,000
 Retirement of long-term debt                       (304,817)   (270,805)     (2,523)
 Increase in cash overdraft                           22,437          --          --
 Proceeds received upon termination of derivatives    15,005      12,896          --
 Long-term debt financing costs                       (2,774)     (1,626)        (63)

   Net cash provided by (used in)
    financing activities                             100,813     (57,318)    482,630

NET CHANGE IN CASH AND CASH EQUIVALENTS               12,436     (18,115)    (65,715)

Cash and cash equivalents-beginning of year           22,927      41,042     106,757

Cash and cash equivalents-end of year              $  35,363   $  22,927   $  41,042


Changes in components of working capital:
 Accounts receivable                               $  (8,502)  $  (8,691)  $  (1,628)
 Materials and supplies                               (1,313)       (221)        269
 Accounts payable                                      4,755      (3,897)    (11,830)
 Accrued taxes other than income                       1,686       6,468        (368)
 Accrued interest                                     (1,973)      5,146       1,696
 Over/under recovered cost of service                  3,068        (287)     (7,382)

 Total                                             $  (2,279)  $  (1,482)  $ (19,243)

<FN>
The accompanying notes are an integral part of these consolidated
                      financial statements.
</TABLE>

<PAGE>
<TABLE>
         NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES

     CONSOLIDATED STATEMENT OF CHANGES IN PARTNERS' CAPITAL

                         (In Thousands)


<CAPTION>
                                                                                Total
                                         General     Common    Subordinated   Partners'
                                         Partners    Units         Units       Capital

<S>                                      <C>        <C>          <C>          <C>
Partners' Capital at December 31, 1997   $10,015    $394,587     $ 96,126     $500,728

Net income to partners                     1,359      52,077       14,584       68,020

Issuance of partnership interests, net       151       7,457          (54)       7,554

Distributions paid                        (1,377)    (52,733)     (14,766)     (68,876)

Partners' Capital at December 31, 1998    10,148     401,388       95,890      507,426

Subordinated Units converted to
 Common Units                                 --      95,890      (95,890)          --

Net income to partners                     1,710      79,293           --       81,003

Distributions paid                        (1,553)    (71,607)          --      (73,160)

Partners' Capital at December 31, 1999    10,305     504,964           --      515,269

Net income to partners                     2,566      74,154           --       76,720

Issuance of partnership interests, net     1,214      59,482           --       60,696

Distributions paid                        (2,640)    (77,771)          --      (80,411)

Partners' Capital at December 31, 2000   $11,445    $560,829     $     --     $572,274

<FN>
The accompanying notes are an integral part of these consolidated
                      financial statements.
</TABLE>

<PAGE>
         NORTHERN BORDER PARTNERS, L. P. AND SUBSIDIARIES

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


1.  ORGANIZATION AND MANAGEMENT

    Northern Border Partners, L.P., a Delaware limited partnership,
    through a subsidiary limited partnership, Northern Border
    Intermediate Limited Partnership, a Delaware limited partnership,
    collectively referred to herein as the Partnership, owns a 70%
    general partner interest in Northern Border Pipeline Company
    (Northern Border Pipeline).  The remaining 30% general partner
    interest in Northern Border Pipeline is owned by TC PipeLines
    Intermediate Limited Partnership (TC PipeLines).  Black Mesa
    Holdings, Inc. (Black Mesa) and Crestone Energy Ventures, L.L.C.
    (Crestone Energy Ventures)(formerly NBP Energy Pipelines, L.L.C.)
    are wholly-owned subsidiaries of the Partnership.

    Northern Plains Natural Gas Company (Northern Plains), a wholly-
    owned subsidiary of Enron Corp. (Enron), Pan Border Gas Company (Pan
    Border), a wholly-owned subsidiary of Northern Plains, and Northwest
    Border Pipeline Company (Northwest Border), a wholly-owned
    subsidiary of The Williams Companies, Inc. serve as the General
    Partners of the Partnership and collectively own a 2% general
    partner interest in the Partnership.  In December 1998, Northern
    Plains acquired Pan Border from a subsidiary of Duke Energy
    Corporation.  At the closing of the acquisition, Pan Border's sole
    asset consisted of its general partner interest in the Partnership.
    The General Partners or their affiliates also own common units
    representing, in the aggregate, an effective 13.5% limited partner
    interest in the Partnership at December 31, 2000 (see Note 8).

    The Partnership is managed by or is under the direction of a
    committee (Partnership Policy Committee) consisting of one person
    appointed by each General Partner.  The members appointed by
    Northern Plains, Pan Border and Northwest Border have 50%, 32.5% and
    17.5%, respectively, of the voting interest on the Partnership
    Policy Committee.  The Partnership has entered into an
    administrative services agreement with NBP Services Corporation (NBP
    Services), a wholly-owned subsidiary of Enron, pursuant to which NBP
    Services provides certain administrative, operating and management
    services for the Partnership and is reimbursed for its direct and
    indirect costs and expenses.

    Northern Border Pipeline is a general partnership, formed in 1978,
    pursuant to the Texas Uniform Partnership Act.  Northern Border
    Pipeline owns a 1,214-mile natural gas transmission pipeline system
    extending from the United States-Canadian border near Port of
    Morgan, Montana, to a terminus near Manhattan, Illinois.

    Northern Border Pipeline is managed by a Management Committee that
    includes three representatives from the Partnership (one
    representative appointed by each of the General Partners of the
    Partnership) and one representative from TC PipeLines.  The
    Partnership's representatives selected by Northern Plains, Pan
    Border and Northwest Border have 35%, 22.75% and 12.25%,
    respectively, of the voting interest on the Northern Border Pipeline
    Management Committee.  The representative designated by TC PipeLines
    votes the remaining 30% interest.  The day-to-day management of
    Northern Border Pipeline's affairs is the responsibility of Northern
    Plains (the Operator), as defined by the operating agreement between
    Northern Border Pipeline and Northern Plains.  Northern Border
    Pipeline is charged for the salaries, benefits and expenses of the
    Operator.  For the years ended December 31, 2000, 1999 and 1998,
    Northern Border Pipeline reimbursed the Operator approximately $31.7
    million, $29.7 million and $30.0 million, respectively.
    Additionally, Northern Border Pipeline utilizes Enron affiliates for
    management on pipeline expansion and extension projects.

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

    Crestone Energy Ventures owns a 49% common membership interest and a
    100% class A share interest in Bighorn Gas Gathering, L.L.C.
    (Bighorn); a 33% interest in Fort Union Gas Gathering, L.L.C. (Fort
    Union); and a 35% interest in Lost Creek Gathering, L.L.C. (Lost
    Creek).  Crestone Gathering Services, L.L.C. (Crestone Gathering
    Services) is a wholly-owned subsidiary of Crestone Energy Ventures.
    Crestone Energy Ventures acquired its interests in Fort Union, Lost
    Creek, Crestone Gathering Services and a portion of Bighorn in
    September 2000 (see Note 3).  Collectively, Crestone Gathering
    Services, Bighorn, Fort Union and Lost Creek own over 300 miles of
    gas gathering facilities in Wyoming.  The gathering facilities
    interconnect to the interstate gas pipeline grid serving gas markets
    in the Rocky Mountains, the Midwest and California.  NBP Services
    provides certain administrative and management services for Crestone
    Energy Ventures.

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

2.  SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

    (A) Principles of Consolidation and Use of Estimates

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

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

    (B) Government Regulation

        Northern Border Pipeline is subject to regulation by the
        Federal Energy Regulatory Commission (FERC).  Northern Border
        Pipeline's accounting policies conform to Statement of Financial
        Accounting Standards (SFAS) No. 71, "Accounting for the Effects
        of Certain Types of Regulation."  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.  At December 31, 2000 and
        1999, Northern Border Pipeline has reflected regulatory assets
        of approximately $12.4 million and $12.1 million, respectively,
        in Other Assets on the consolidated balance sheet.  Northern
        Border Pipeline is recovering the regulatory assets from its
        shippers over varying time periods, which range from four to 43
        years.

    (C) Revenue Recognition

        Northern Border Pipeline transports gas for shippers under a tariff
        regulated by the FERC.  The tariff specifies the calculation of
        amounts to be paid by shippers and the general terms and conditions
        of transportation service on the pipeline system.  Northern Border
        Pipeline's revenues are derived from agreements for the receipt and
        delivery of gas at points along the pipeline system as specified in
        each shipper's individual transportation contract.  Northern Border
        Pipeline does not own the gas that it transports, and therefore it
        does not assume the related natural gas commodity risk.  See Notes 4
        and 5 for a further discussion of Northern Border Pipeline's tariff
        and transportation agreements.

    (D) Cash and Cash Equivalents

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

    (E) Income Taxes

        Income taxes are the responsibility of the partners and are
        not reflected in these financial statements.  However, the
        Northern Border Pipeline tariff establishes the method of
        accounting for and calculating income taxes and requires
        Northern Border Pipeline to reflect in its financial records the
        income taxes which would have been paid or accrued if Northern
        Border Pipeline were organized during the period as a
        corporation.  As a result, for purposes of determining
        transportation rates in calculating the return allowed by the
        FERC, partners' capital and rate base are reduced by the amount
        equivalent to the net accumulated deferred income taxes.  Such
        amounts were approximately $326 million and $316 million at
        December 31, 2000 and 1999, respectively, and are primarily
        related to accelerated depreciation and other plant-related
        differences.

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

        Property, plant and equipment is stated at original cost.  The
        original cost of utility property retired is charged to
        accumulated depreciation and amortization, net of salvage and
        cost of removal.  No retirement gain or loss is included in
        income except in the case of extraordinary retirements or sales.

        Maintenance and repairs are charged to operations in the
        period incurred.  The provision for depreciation and
        amortization of the transmission line is an integral part of
        Northern Border Pipeline's FERC tariff.  The effective
        depreciation rates applied to Northern Border Pipeline's
        transmission plant in 2000, 1999 and 1998 were 2.25%, 2.0% and
        2.5%, respectively.  Based upon the rate case settlement
        discussed in Note 4, Northern Border Pipeline will continue to
        use a 2.25% depreciation rate.  The effective depreciation rate
        applied to Crestone Energy Venture's gathering facilities was
        3.33%.  Composite rates are applied to all other functional
        groups of property having similar economic characteristics.

    (G) Allowance for Funds Used During Construction

        The allowance for funds used during construction (AFUDC)
        represents the estimated costs, during the period of
        construction, of funds used for construction purposes.  For
        regulated activities, Northern Border Pipeline is permitted to
        earn a return on and recover AFUDC through its inclusion in rate
        base and the provision for depreciation.

    (H) Investments in Unconsolidated Affiliates

        The investments in unconsolidated affiliates are accounted for
        by the equity method.  The excess of the Partnership's
        investments in unconsolidated affiliates over the underlying
        equity in the fair value of the net assets acquired is being
        amortized on a straight-line basis over 30 years.  During 2000,
        the Partnership recorded amortization expense of $2.2 million
        related to its investments in unconsolidated affiliates, which
        is reflected as a component of equity earnings (losses) of
        unconsolidated affiliates in the Partnership's consolidated
        statement of income.  See Note 7 for details on the
        Partnership's investments in unconsolidated affiliates and
        related equity earnings (losses).

    (I) Goodwill

        Goodwill consists of the excess of cost over fair value of the
        net assets acquired in business acquisitions and is being
        amortized using a straight-line method over 30 years.  During
        2000, 1999 and 1998, the Partnership recorded amortization
        expense of $0.5 million, $0.3 million and $0.3 million,
        respectively.  This amortization expense is reflected as a
        component of depreciation and amortization in the Partnership's
        consolidated statement of income.

    (J) Risk Management

        Financial instruments are used in the management of the
        Partnership's interest rate exposure.  A control environment has
        been established which includes policies and procedures for risk
        assessment and the approval, reporting and monitoring of
        financial instrument activities.  As a result, Northern Border
        Pipeline has entered into various interest rate swap agreements
        with major financial institutions which hedge interest rate risk
        by effectively converting certain of its floating rate debt to
        fixed rate debt.  Northern Border Pipeline does not use these
        instruments for trading purposes.  The cost or benefit of the
        interest rate swap agreements is recognized currently as a
        component of interest expense.

    (K) Reclassifications

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

3.  BUSINESS ACQUISITIONS

    In December 1999, Crestone Energy Ventures purchased a 39%
    common membership interest in Bighorn for approximately $31.9
    million and in June 2000, Crestone Energy Ventures purchased 80% of
    class A shares in Bighorn for approximately $20.8 million.

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

    The Partnership has accounted for these acquisitions using the
    purchase method of accounting.  The purchase price has been
    allocated based upon the estimated fair value of the assets and
    liabilities acquired as of the acquisition date.  The excess of the
    purchase price over the fair value of the Crestone Gathering
    Services net assets acquired is reflected as goodwill on the
    consolidated balance sheet.  The investments in Bighorn, Fort Union
    and Lost Creek are being reflected in investments in unconsolidated
    affiliates on the consolidated balance sheet.  See Note 7 for
    additional discussion of the Partnership's investments in
    unconsolidated affiliates.

    The following is a summary of the effects of the acquisitions
    made in  2000 and 1999 on the Partnership's consolidated financial
    position (amounts in thousands):

<TABLE>
<CAPTION>

                                             2000             1999

          <S>                             <C>               <C>
          Current assets                  $  1,949          $    --
          Property, plant and equipment     29,789               --
          Investments in unconsolidated
            affiliates                     179,079           31,895
          Goodwill                          18,887               --
          Current liabilities                 (199)              --
                                          $229,505          $31,895
</TABLE>


    If the acquisitions made in 2000 had occurred at the beginning
    of 2000, the Partnership's 2000 consolidated operating revenues
    would have been $343 million, net income to partners would have
    been $65 million and net income per unit would have been $2.00.
    These unaudited pro forma results are for illustrative purposes
    only and are not necessarily indicative of the operating results
    that would have occurred had the business acquisitions been
    consummated at that date, nor are they necessarily indicative of
    future operating results.

    Bighorn's ownership structure consists of common membership
    interests, which represents approximately 93.8% of its
    capitalization, and non-voting class A and class B shares, each of
    which represents approximately 3.1% of the total capitalization.
    Both of the non-voting classes of shares are subject to certain
    distribution preferences as well as limitations based on the
    cumulative number of wells connected to the Bighorn system at the
    end of each calendar year.  These shares will receive an income
    allocation equal to the cash distributions received and are not
    entitled to any other allocations of income or distributions of
    cash.  During 1999 and 2000, no income allocation or cash
    distribution was made to the non-voting shares.  Ownership of these
    shares does not affect the amount of capital contributions that are
    required to be made to the operations of Bighorn by the owners of
    the common membership interests.

4.  RATES AND REGULATORY ISSUES

    Rate Case

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

    Under the cost of service tariff, Northern Border Pipeline was
    provided an opportunity to recover all of the operations and
    maintenance costs of the pipeline, taxes other than income taxes,
    interest, depreciation and amortization, an allowance for income
    taxes and a regulated return on equity.  Northern Border Pipeline
    was generally allowed to collect from its shippers a return on
    regulated rate base as well as recover that rate base through
    depreciation and amortization.  Billings for the firm transportation
    agreements were based on contracted volumes to determine the
    allocable share of the cost of service and were not dependent upon
    the percentage of available capacity actually used.  Under the cost
    of service tariff, Northern Border Pipeline billed on an estimated
    basis for a six-month cycle.  Any net excess or deficiency resulting
    from the comparison of the actual cost of service determined for the
    period in accordance with the FERC tariff to the estimated billing
    was accumulated, including carrying charges thereon, and was either
    billed to or credited back to the shippers.  Revenues reflected
    actual cost of service.  An amount equal to differences between
    billing estimates and the actual cost of service, including carrying
    charges, was reflected in current assets or current liabilities.

    Northern Border Pipeline filed a rate proceeding with the FERC in
    May 1999 for, among other things, a redetermination of its allowed
    equity rate of return.  The total annual cost of service increase
    due to Northern Border Pipeline's proposed changes was approximately
    $30 million.  In June 1999, the FERC issued an order in which the
    proposed changes were suspended until December 1, 1999, after which
    the proposed changes were implemented with subsequent billings
    subject to refund.

    In September 2000, Northern Border Pipeline filed a stipulation and
    agreement with the FERC that documented the proposed settlement of
    its pending rate case.  The settlement was approved by the FERC in
    December 2000.  Under the approved settlement, effective December 1,
    1999, shippers will pay stated transportation rates based on a
    straight fixed variable rate design.  Under the straight fixed
    variable rate design, approximately 98% of the agreed upon revenue
    level is attributed to demand charges, based upon contracted firm
    capacity, and the remaining 2% is attributed to commodity charges,
    based on the volumes of gas actually transported on the system.
    From December 1, 1999, through and including December 31, 2000, the
    rates were based upon an annual revenue level of $307 million.  For
    periods after December 31, 2000, the rates are based upon an annual
    revenue level of $305 million.  The settlement further provides for
    the incorporation into Northern Border Pipeline's rate base all of
    the construction costs of The Chicago Project, which was Northern
    Border Pipeline's expansion and extension of its pipeline from near
    Harper, Iowa to a point near Manhattan, Illinois.  Northern Border
    Pipeline had placed into service the facilities for The Chicago
    Project in December 1998.  Under the settlement, both Northern
    Border Pipeline and its existing shippers will not be able to seek
    rate changes until November 1, 2005, at which time Northern Border
    Pipeline must file a new rate case.

    After the FERC approved the rate case settlement and prior to the
    end of 2000, Northern Border Pipeline made estimated refund payments
    to its shippers totaling approximately $22.7 million, primarily
    related to the period from December 1999 to November 2000.  At
    December 31, 2000, Northern Border Pipeline had estimated its
    remaining refund obligation through the end of 2000 to be
    approximately $4.7 million, which is expected to be paid in the
    first quarter of 2001.  Northern Border Pipeline's operating
    revenues for 2000 reflect the significant terms of the approved
    settlement.

    Certificate application

    In October 1998, Northern Border Pipeline filed a certificate
    application with the FERC to seek approval to expand and extend its
    pipeline system into Indiana (Project 2000).  When completed,
    Project 2000 will afford shippers on the expanded and extended
    pipeline system access to industrial gas consumers in northern
    Indiana.  The certificate application was subsequently amended by
    Northern Border Pipeline in March and December 1999.  On March 16,
    2000, the FERC issued an order granting Northern Border Pipeline's
    application for a certificate to construct and operate the proposed
    facilities.  The FERC approved Northern Border Pipeline's request
    for rolled-in rate treatment based upon the proposed project costs.
    The project has a targeted in-service date of November 2001.  The
    capital expenditures for the project are estimated to be
    approximately $94 million, of which $10.8 million had been incurred
    through December 31, 2000.

5.  TRANSPORTATION AGREEMENTS

    Northern Border Pipeline's operating revenues are collected pursuant
    to the FERC tariff through firm transportation service agreements
    (firm service agreements).  The firm service agreements extend for
    various terms with termination dates that range from October 2001 to
    December 2013.  Northern Border Pipeline also has interruptible
    service agreements with numerous other shippers as a result of its
    self-implementing blanket transportation authority.  Under the
    approved settlement of Northern Border Pipeline's rate case
    discussed in Note 4, in certain situations, Northern Border Pipeline
    will reduce the billings for the firm service agreements by one half
    of the revenues received from the interruptible service agreements
    through October 31, 2003.  After October 31, 2003, all revenues from
    interruptible transportation service will be retained by Northern
    Border Pipeline.

    Northern Border Pipeline's largest shipper, Pan-Alberta Gas (U.S.)
    Inc. (PAGUS), is presently obligated for approximately 25.5% of the
    contracted firm capacity through three firm service agreements which
    expire in October 2003.  Financial guarantees exist through October
    2001 for approximately 16.3% of the contracted firm capacity of
    PAGUS, including 10.5% guaranteed by Northern Natural Gas Company, a
    wholly-owned subsidiary of Enron.  The remaining obligation of PAGUS
    is supported by various credit support arrangements, including among
    others, a letter of credit, an escrow account and an upstream
    capacity transfer agreement.  Operating revenues from the PAGUS firm
    service agreements and interruptible service agreements for the
    years ended December 31, 2000, 1999 and 1998 were $65.0 million,
    $76.6 million and $87.3 million, respectively.

    TransCanada Energy Marketing USA, Inc. (TransCanada Energy), an
    affiliate of TC PipeLines, has firm service agreements representing
    approximately 11.4% of contracted capacity.  The firm service
    agreements for TransCanada Energy extend for various terms with
    termination dates that range from October 2003 to December 2008.
    Other shippers affiliated with the partners of Northern Border
    Pipeline have firm service agreements representing approximately
    7.1% of contracted capacity.  These firm service agreements extend
    for various terms with termination dates that range from January
    2002 to May 2009.  Operating revenues from the affiliated firm
    service agreements and interruptible service agreements for the
    years ended December 31, 2000, 1999, and 1998 were $58.5 million,
    $52.5 million and $22.4 million, respectively.

    Crestone Energy Ventures and Crestone Gathering Services
    (collectively Crestone) provide gas gathering and administrative
    services to third parties, ENA, and the Partnership's unconsolidated
    affiliates.  Crestone's total revenues from affiliates for the year
    ended December 31, 2000, were $7.3 million.

    Black Mesa's operating revenue is derived from a pipeline
    transportation agreement (Pipeline Agreement) with the coal supplier
    for the Mohave Power Station that expires in December 2005.  The
    pipeline is the sole source of fuel for the Mohave plant.  Under the
    terms of the Pipeline Agreement, Black Mesa receives a monthly
    demand payment, a per ton commodity payment and a reimbursement for
    certain other expenses.

6.  CREDIT FACILITIES AND LONG-TERM DEBT

    Detailed information on long-term debt is as follows:

<TABLE>
<CAPTION>
                                                          December 31,
    (In thousands)                                     2000         1999

    <S>                                            <C>          <C>
    Northern Border Pipeline
      1992 Pipeline Senior Notes - average 8.49%
        and 8.43% at December 31, 2000 and 1999,
        respectively, due from 2000 to 2003        $  184,000   $  250,000
      Pipeline Credit Agreement
        Term loan, due 2002                           424,000      439,000
        Five-year revolving credit facility            45,000           --
      1999 Pipeline Senior Notes - 7.75%,
        due 2009                                      200,000      200,000
    Northern Border Partners, L.P.
      Partnership Senior Notes - 8 7/8%,
        due 2010                                      250,000           --
      Partnership Credit Agreements -
        Three-year revolving credit facility           26,300           --
      Credit agreements - average 6.78%,
        due 2000                                           --      114,500
    Black Mesa
      10.7% Note agreement,
        due quarterly to 2004                          13,910       17,027
    Unamortized proceeds from termination
      of derivatives                                   26,046       12,397
    Unamortized debt premium (discount)                 2,706         (938)
    Total                                           1,171,962    1,031,986
    Less: Current maturities of long-term debt         44,464      183,617
    Long-term debt                                 $1,127,498   $  848,369
</TABLE>

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

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

    In June 2000, the Partnership entered into two credit agreements
    with certain financial institutions, a $75 million 364-day credit
    agreement and a $75 million three-year revolving credit agreement
    (collectively, Partnership Credit Agreements).  The Partnership
    Credit Agreements are to be used for capital expenditures, working
    capital and general business purposes.  The Partnership Credit
    Agreements permit the Partnership to choose among various interest
    rate options, to specify the portion of the borrowings to be covered
    by specific interest rate options and to specify the interest rate
    period.  The Partnership is required to pay a fee on the principal
    commitment amount of $150 million.  At December 31, 2000, the
    average effective interest rate on the Partnership Credit Agreements
    was 8.92%

    In August 1999, Northern Border Pipeline completed a private
    offering of $200 million of 7.75% Senior Notes due 2009, which notes
    were subsequently exchanged in a registered offering for notes with
    substantially identical terms (1999 Pipeline Senior Notes).  Also in
    August 1999, Northern Border Pipeline received approximately $12.9
    million from the termination of interest rate forward agreements,
    which is being amortized against interest expense over the life of
    the 1999 Pipeline Senior Notes.  The interest rate forward
    agreements, which had an aggregate notional amount of $150 million,
    had been executed in September 1998 to hedge the interest rate on a
    planned issuance of fixed rate debt in 1999.  The proceeds from the
    private offering, net of debt discounts and issuance costs, and the
    termination of the interest rate forward agreements were used to
    reduce existing indebtedness under a June 1997 credit agreement.

    In June 1997, Northern Border Pipeline entered into a credit
    agreement (Pipeline Credit Agreement) with certain financial
    institutions to borrow             up to an aggregate principal
    amount of $750 million.  The Pipeline Credit Agreement is comprised
    of a $200 million five-year revolving credit facility to be used for
    the retirement of a previously existing bank loan agreement and for
    general business purposes, and a $550 million three-year revolving
    credit facility to be used for the construction of The Chicago
    Project.  Effective March 1999, in accordance with the provisions of
    the Pipeline Credit Agreement, Northern Border Pipeline converted
    the three-year revolving credit facility to a term loan maturing in
    June 2002.  The Pipeline Credit Agreement permits Northern Border
    Pipeline to choose among various interest rate options, to specify
    the portion of the borrowings to be covered by specific interest
    rate options and to specify the interest rate period, subject to
    certain parameters.  Northern Border Pipeline is required to pay a
    facility fee on the remaining aggregate principal commitment amount
    of $624 million.

    At December 31, 2000 and 1999, Northern Border Pipeline had an
    outstanding interest rate swap agreement with a notional amount of
    $40 million, which will terminate in November 2001.  Under the
    agreement, Northern Border Pipeline makes payments to counterparties
    at fixed rates and in return receives payments at variable rates
    based on the London Interbank Offered Rate.  At December 31, 2000
    and 1999, Northern Border Pipeline was in a payable position
    relative to its counterparties.  The average effective interest rate
    of Northern Border Pipeline's variable rate debt, taking into
    consideration the interest rate swap agreement, was 7.06% and 6.73%
    at December 31, 2000 and 1999, respectively.

    Interest paid, net of amounts capitalized, during the years ended
    December 31, 2000, 1999 and 1998 was $84.2 million, $62.5 million
    and $28.7 million, respectively.

    Aggregate repayments of long-term debt required for the next five
    years are as follows:  $44 million, $551 million, $96 million, and
    $2 million for 2001, 2002, 2003, and 2004, respectively.  There are
    no scheduled debt maturities for 2005.

    Certain of Northern Border Pipeline's long-term debt and credit
    arrangements contain requirements as to the maintenance of minimum
    partners' capital and debt to capitalization ratios which restrict
    the incurrence of other indebtedness by Northern Border Pipeline and
    also place certain restrictions on distributions to the partners of
    Northern Border Pipeline.  Under the most restrictive of the
    covenants, as of December 31, 2000 and 1999, respectively, $136
    million and $132 million of partners' capital of Northern Border
    Pipeline could be distributed.  The indenture under which the
    Partnership Senior Notes were issued does not limit the amount of
    indebtedness or other obligations that the Partnership may incur,
    but does contain material financial covenants, including
    restrictions on the incurrence of secured indebtedness.  The
    Partnership Credit Agreements, as amended, require the maintenance
    of a ratio of debt to total capital, excluding the nonrecourse debt
    of subsidiaries, of no more than 45% currently and gradually
    decreasing to 35% by September 30, 2001.

    The following estimated fair values of financial instruments
    represent the amount at which each instrument could be exchanged in
    a current transaction between willing parties.  Based on quoted
    market prices for similar issues with similar terms and remaining
    maturities, the estimated fair value of the 1992 Pipeline Senior
    Notes was approximately $191 million and $273 million at December
    31, 2000 and 1999, respectively.  The estimated fair value of the
    1999 Pipeline Senior Notes was approximately $213 million and $201
    million at December 31, 2000 and 1999, respectively.  The estimated
    fair value of the Partnership Senior Notes was approximately $271
    million at December 31, 2000.  The estimated fair value of the Black
    Mesa note agreement was approximately $15 million and $18 million at
    December 31, 2000 and 1999, respectively.  At December 31, 2000 and
    1999, the estimated fair value which would be payable to terminate
    the interest rate swap agreement, taking into account current
    interest rates, was approximately $1 million.  The Partnership
    presently intends to maintain the current schedule of maturities for
    the 1992 Pipeline Senior Notes, 1999 Pipeline Senior Notes,
    Partnership Senior Notes, the Black Mesa note agreement and the
    interest rate swap agreement that will result in no gains or losses
    on their respective repayment.  The fair value of the Pipeline
    Credit Agreement and Partnership Credit Agreements approximates the
    carrying value since the interest rates are periodically adjusted to
    reflect current market conditions.

7. UNCONSOLIDATED AFFILIATES

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

<TABLE>
<CAPTION>
                      Net
                    Ownership             December 31,
    (In thousands)  Interest           2000         1999

    <S>                <C>           <C>           <C>
    Bighorn            (a)           $ 83,562      $31,895
    Fort Union         33%             69,872           --
    Lost Creek         35%             68,191           --
                                     $221,625(b)   $31,895

<FN>
    (a) As discussed in Note 3, the Partnership's common membership
        interest in Bighorn increased from 39% at December 31, 1999 to 49% at
        December 31, 2000.  The Partnership also held 100% of the non-voting
        class A shares of Bighorn at December 31, 2000.
    (b) At December 31, 2000 and 1999, the unamortized excess of the
        Partnership's investments in unconsolidated affiliates was $189.5
        million and $20.0 million, respectively.
</TABLE>

    The Partnership's equity earnings (losses) of unconsolidated
    affiliates is as follows:
<TABLE>
<CAPTION>
    (In thousands)                               2000(a)

    <S>                                         <C>
    Bighorn                                     $(1,394)
    Fort Union                                      285
    Lost Creek                                      462
                                                $  (647)
<FN>
    (a) Initial investments in unconsolidated affiliates began in late
        December 1999.
</TABLE>

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

<TABLE>
<CAPTION>
                                                    December 31,
    (In thousands)                                2000      1999(b)
    <S>                                         <C>        <C>
    Balance sheet
      Current assets (a)                        $ 15,202   $ 1,770
      Property, plant and equipment, net         160,558    32,619
      Other noncurrent assets                      1,329        --
      Current liabilities                          4,509     1,912
      Long-term debt                              99,364        --
      Other noncurrent liabilities                 4,008        --
      Owners' equity                              69,208    32,477

<FN>
    (a) Includes $434 thousand receivable from the Partnership at
        December 31, 2000.
    (b) Includes only balances from Bighorn.
</TABLE>

<TABLE>

<CAPTION>
    (In thousands)                             2000 (a)
    <S>                                          <C>
    Income statement
      Operating revenues                         $8,598
      Operating expenses                          3,871
      Net income                                  4,116

    Distributions paid to
      the Partnership                            $  933

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

8.  PARTNERS' CAPITAL

    At December 31, 2000, partners' capital consisted of 31,503,563
    common units representing an effective 98% limited partner interest
    in the Partnership (including 13.5% held collectively by the General
    Partners or their affiliates) and a 2% general partner interest.  At
    December 31, 1999, partners' capital consisted of 29,347,313 common
    units representing an effective 98% limited partner interest in the
    Partnership (including 14.5% held collectively by the General
    Partners or their affiliates) and a 2% general partner interest.
    Effective January 19, 1999, the Partnership converted its 6,420,000
    outstanding subordinated units into an equal number of common units
    since the Partnership Policy Committee determined the subordination
    period ended as a result of satisfying the criteria set forth in the
    partnership agreement.

    In November 2000, the Partnership sold, through an underwritten
    public offering, 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 the
    Partnership Credit Agreements.

    In January 1998, the Partnership sold, through an underwritten
    public offering, 225,000 common units.  The units sold in 1998
    resulted from the underwriters exercise of an over-allotment option
    to purchase a limited number of additional common units after an
    offering of common units in December 1997.  The net proceeds, of the
    public offering and the associated general partners' capital
    contributions, was approximately $7.6 million.

    The Partnership will make distributions to its partners with respect
    to each calendar quarter in an amount equal to 100% of its Available
    Cash.  "Available Cash" generally consists of all of the cash
    receipts of the Partnership adjusted for its cash disbursements and
    net changes to cash reserves.  Available Cash will generally be
    distributed 98% to the Unitholders and 2% to the General Partners.

    Partnership income is allocated to the General Partners and the
    limited partners in accordance with their respective partnership
    percentages, after giving effect to any priority income allocations
    for incentive distributions that are allocated 100% to the General
    Partners.  As an incentive, the General Partners' percentage
    interest in quarterly distributions is increased after certain
    specified target levels are met (see Note 10).  At the time the
    quarterly distributions exceed $0.605 per unit, the General Partners
    receive 15% of the excess.  As the quarterly distributions are
    increased above $0.715 per unit, the General Partners receive
    increasing percentages in excess of the targets reaching a maximum
    of 50% of the excess of the highest target level.

9.  COMMITMENTS AND CONTINGENCIES

    Firm Transportation Obligations and Other Commitments

    Crestone Energy Ventures has firm transportation agreements with
    Fort Union and Lost Creek.  Under these agreements, Crestone Energy
    Ventures must make specified minimum payments each month.  At
    December 31, 2000, the estimated aggregate amounts of such required
    future payments were $8.2 million annually for 2001 through 2005 and
    $35.7 million for later years.

    At December 31, 2000, the Partnership is a guarantor on a
    construction loan outstanding of an unconsolidated affiliate of
    approximately $23.1 million.  The Partnership has also guaranteed
    the performance of an unconsolidated affiliate in connection with a
    credit agreement that expires in September 2009.  At December 31,
    2000, the guarantee was $2.9 million.

    Capital expenditure and investment program

    Total capital expenditures for 2001 are estimated to be $176
    million.  This includes approximately $81 million for Northern
    Border Pipeline's Project 2000 (see Note 4), $79 million for
    Crestone Energy Ventures gathering facilities and approximately $16
    million for renewals and replacements of the existing facilities.
    Crestone Energy Ventures also estimates that it will be required to
    make additional investments in its unconsolidated affiliates of
    approximately $22 million in 2001 to support their capital
    expenditure projects.  Funds required to meet the capital
    requirements for 2001 are anticipated to be provided primarily from
    debt borrowings and internal sources.

    Environmental Matters

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

    Other

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

10. NET INCOME PER UNIT

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

<TABLE>
<CAPTION>
    (In thousands, except                             Year ended December 31,
       per unit amounts)                              2000      1999     1998

    <S>                                             <C>       <C>       <C>
    Net income to partners                          $76,720   $81,003   $68,020

    Net income allocated to General Partners         (1,534)   (1,620)   (1,359)
    Adjustment to reflect incentive distributions    (1,032)      (90)       --

                                                     (2,566)   (1,710)   (1,359)

    Net income allocable to units                   $74,154   $79,293   $66,661
    Weighted average units outstanding               29,665    29,347    29,345

    Net income per unit                             $  2.50   $  2.70   $  2.27
</TABLE>

11. ACCOUNTING PRONOUNCEMENTS

    In 1998, the Financial Accounting Standards Board (FASB) issued SFAS
    No. 133, "Accounting for Derivative Instruments and Hedging
    Activities."  SFAS No. 133 establishes accounting and reporting
    standards requiring that every derivative instrument (including
    certain derivative instruments embedded in other contracts) be
    recorded on the balance sheet as either an asset or liability
    measured at its fair value.  The statement requires that changes in
    the derivative's fair value be recognized currently in earnings
    unless specific hedge accounting criteria are met.  Special
    accounting for qualifying hedges allows a derivative's gains and
    losses to offset related results on the hedged item in the income
    statement, and requires that a company formally document, designate
    and assess the effectiveness of transactions that receive hedge
    accounting.

    In June 1999, the FASB issued SFAS No. 137, which deferred the
    effective date of SFAS No. 133 to fiscal years beginning after June
    15, 2000.  In June 2000, the FASB issued SFAS No. 138, which amended
    certain guidance within SFAS No. 133.  The Partnership and its
    subsidiaries will adopt SFAS No. 133 beginning January 1, 2001.  The
    adoption of SFAS No. 133, as amended, will not have a material
    impact on the Partnership's financial position or results of
    operations.

12. GEOGRAPHIC AND BUSINESS SEGMENT INFORMATION

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

    The Partnership's reportable segments are strategic business units
    that offer different services.  They are managed separately because
    each business requires different marketing strategies.  The
    accounting policies of the segments are the same as those described
    in the summary of significant accounting policies in Note 2.  The
    Partnership evaluates performance based on EBITDA (net income before
    minority interests; interest expense; and depreciation and
    amortization, including goodwill amortization, which is netted
    against equity earnings of unconsolidated affiliates) and operating
    income.  Interest expense on the Partnership's debt is not allocated
    to the segments.  Therefore, management believes that EBITDA is the
    dominant measurement of segment performance.

<TABLE>
<CAPTION>
                                                          Gas
                                Interstate    Coal     Gathering
    (In thousands)               Pipeline    Slurry       (a)     Other(b)    Total
    2000

    <S>                        <C>          <C>        <C>        <C>       <C>
    Revenues from
      external customers       $  311,022   $ 21,170   $  7,540   $    --   $  339,732

    Depreciation and
      amortization                 57,328      2,977        394        --       60,699

    Operating income (loss)       184,167      4,355      2,019    (2,239)     188,302

    Interest expense, net          65,161      1,677         --    14,657       81,495

    Equity earnings
      (losses) of
      unconsolidated
      affiliates                       --         --       (647)       --         (647)

    Other income, net               8,058         32         --       589        8,679

    EBITDA                        249,553      7,364      4,007    (1,650)     259,274

    Capital expenditures           15,523        386      3,812        --       19,721

    Identifiable assets         1,768,505     29,605     58,230     4,755    1,861,095

    Investments in
      unconsolidated
      affiliates                       --         --    221,625        --      221,625

    Total assets               $1,768,505   $ 29,605   $279,855   $ 4,755   $2,082,720

    1999

    Revenues from
      external customers       $  298,347   $ 20,616   $     --   $    --   $  318,963

    Depreciation and
      amortization                 51,908      2,934         --        --       54,842


    Operating income (loss)       177,411      3,670         --    (1,363)     179,718

    Interest expense, net          60,214      1,997         --     5,498       67,709

    Other income, net               1,363        (39)        --     3,238        4,562

    EBITDA                        230,682      6,565         --     1,875      239,122

    Capital expenditures          101,678        592         --        --      102,270

    Identifiable assets         1,796,691     32,075         --     2,776    1,831,542

    Investments in
      unconsolidated
      affiliates                       --         --     31,895        --       31,895

    Total assets               $1,796,691   $ 32,075   $ 31,895   $ 2,776   $1,863,437

    1998

    Revenues from
      external customers       $  196,600   $ 20,992   $     --   $    --   $   217,592

    Depreciation and
      amortization                 40,989      2,896         --        --        43,885

    Operating income (loss)       113,661      3,631         --    (1,489)      115,803

    Interest expense, net          25,541      2,281         --     3,100        30,922

    Other income, net              12,111        640         --       457        13,208

    EBITDA                        166,761      7,167         --    (1,032)      172,896

    Capital expenditures          651,169      1,025         --         --      652,194

    Identifiable assets         1,790,889     34,421         --         456   1,825,766

    Total assets               $1,790,889   $ 34,421   $     --   $     456  $1,825,766

<FN>
(a)  Gas gathering operating results commence from the date of
     acquisition in September 2000 (see Note 4) except for equity earnings of
     Bighorn, which commenced in January 2000.
(b)  Includes other items not allocable to segments.
</TABLE>

13. QUARTERLY FINANCIAL DATA (Unaudited)
<TABLE>
<CAPTION>
    (In thousands, except     Operating     Operating   Net Income    Net Income
        per unit amounts)   Revenues, net    Income     to Partners    per Unit

    <S>                        <C>           <C>          <C>            <C>
    2000
      First Quarter            $81,517       $45,171      $17,966        $0.59
      Second Quarter            82,536        44,747       18,042         0.60
      Third Quarter             83,550        48,216       20,338         0.66
      Fourth Quarter            92,129        50,168       20,374         0.65
    1999
      First Quarter            $78,895       $44,961      $21,631        $0.72
      Second Quarter            78,012        44,255       20,561         0.69
      Third Quarter             79,046        44,728       19,357         0.65
      Fourth Quarter            83,010        45,774       19,454         0.65
</TABLE>

14. SUBSEQUENT EVENTS

    On January 18, 2001, the Partnership declared a cash distribution of
    $0.70 per unit ($2.80 per unit on an annualized basis) for the
    quarter ended December 31, 2000.  The distribution is payable
    February 14, 2001, to unitholders of record at January 31, 2001.


Report of Independent Public Accountants on Schedule


To Northern Border Partners, L.P.:

We have audited in accordance with auditing standards generally accepted
in the United States, the consolidated financial statements of Northern
Border Partners, L.P. and Subsidiaries included in this Form 10-K and
have issued our report thereon dated January 22, 2001.  Our audits were
made for the purpose of forming an opinion on the basic financial
statements taken as a whole.  The schedule of Northern Border Partners,
L.P. and Subsidiaries listed in Item 14 of Part IV of this Form 10-K is
the responsibility of the Company's management and is presented for
purposes of complying with the Securities and Exchange Commission's
rules and is not part of the basic financial statements.  This schedule
has been subjected to the auditing procedures applied in the audits of
the basic financial statements and, in our opinion, fairly states in all
material respects the financial data required to be set forth therein in
relation to the basic financial statements taken as a whole.


                                        ARTHUR ANDERSEN LLP

Omaha, Nebraska,
  January 22, 2001

<TABLE>

                                                             SCHEDULE II

             NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES
             SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
          FOR THE YEARS ENDED DECEMBER 31, 2000, 1999 AND 1998
                             (In Thousands)


<CAPTION>
Column A               Column B         Column C              Column D        Column E
                                        Additions            Deductions
                      Balance at   Charged to   Charged    For Purpose For
                      Beginning    Costs and    to Other   Which Reserves    Balance at
Description            of Year      Expenses    Accounts    Were Created     End of Year

<S>                    <C>          <C>           <C>         <C>             <C>
Reserve for
  regulatory issues
   2000                $7,376       $1,800        $--         $7,376          $1,800
   1999                $6,726       $  650        $--         $   --          $7,376
   1998                $6,726       $   --        $--         $   --          $6,726
</TABLE>

<PAGE>
            UNITED STATES SECURITIES AND EXCHANGE
                         COMMISSION
                   WASHINGTON, D.C.  20549
                   _______________________


                         EXHIBITS TO
                        F O R M  10-K



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


For the fiscal year ended December 31, 2000
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             Identification No.)
           or organization)




        1400 Smith Street, Houston, Texas  77002-7369
     (Address of principal executive offices)(zip code)
Registrant's telephone number, including area code:  713-853-6161
                     ___________________



                        EXHIBIT INDEX


      * 3.1   Form of Amended and Restated
              Agreement of Limited Partnership of
              Northern Border Partners, L.P.
              (Exhibit 3.1 No. 2 to the
              Partnership's Form S-1 Registration
              Statement, Registration No. 33-66158
              ("Form S-1")).
      * 3.2   Form of Amended and Restated
              Agreement of  Limited Partnership
              For Northern Border Intermediate
              Limited Partnership (Exhibit 10.1 to
              Form S-1).
      * 4.1   Indenture, dated as of June 2, 2000,
              between the registrants and Bank One
              Trust Company, N.A. (Exhibit 4.1 to
              the Partnership's Quarterly Report
              on Form 10-Q for the quarterly
              period ended June 30, 2000 ("June
              2000 10-Q")).
      * 4.2   First Supplemental Indenture, dated
              as of September 14, 2000, between
              the registrants and Bank One Trust
              Company, N.A.(Exhibit 4.2 to Form S-4
              Registration Statement, Registration No.
              333-46212 ("NBP Form S-4")).
        4.3   Indenture, dated as of March 21,
              2001, between Northern Border
              Partners, L.P. and Northern Border
              Intermediate Limited Partnership and
              Bank One Trust Company, N.A.,
              Trustee.
        4.4   Registration Rights Agreement dated
              March 21, 2001 by and among Northern
              Border Partners, L.P., Northern
              Border Intermediate Limited
              Partnership, Banc of America
              Securities LLC, SunTrust Equitable
              Securities Corporation, Banc One
              Capital Markets, Inc. and BMO
              Nesbitt Burns Corp.
      * 4.5   Indenture, dated as of August 17,
              1999, between Northern Border
              Pipeline Company and Bank One Trust
              Company, NA, successor to The First
              National Bank of Chicago, as
              trustee. (Exhibit No. 4.1 to
              Northern Border Pipeline Company's
              Form S-4 Registration Statement,
              Registration No. 333-88577 ("NB Form
              S-4").
      *10.1   Northern Border Pipeline Company
              General Partnership Agreement
              between Northern Plains Natural Gas
              Company, Northwest Border Pipeline
              Company, Pan Border Gas Company,
              TransCanada Border Pipeline Ltd. and
              TransCan Northern Ltd., effective
              March 9, 1978, as amended (Exhibit
              10.2 to Form S-1).
      *10.2   Operating Agreement between Northern
              Border Pipeline Company and Northern
              Plains Natural Gas Company, dated
              February 28, 1980 (Exhibit 10.3 to
              Form S-1).
      *10.3   Administrative Services Agreement
              between NBP Services Corporation,
              Northern Border Partners, L.P. and
              Northern Border Intermediate Limited
              Partnership (Exhibit 10.4 to Form S-1).
      *10.4   Note Purchase Agreement between
              Northern Border Pipeline Company and
              the parties listed therein, dated
              July 15, 1992 (Exhibit 10.6 to Form
              S-1).
      *10.4.1 Supplemental Agreement to the Note
              Purchase Agreement dated as of June 1,
              1995 (Exhibit 10.6.1 to the
              Partnership's Annual Report on Form
              10-K for the year ended December 31,
              1995 ("1995 10-K")).
      *10.5   Guaranty made by Panhandle Eastern
              Pipeline Company, dated October 31,
              1992 (Exhibit 10.9 to Form S-1).
      *10.6   Northern Border Pipeline Company
              U.S. Shippers Service Agreement
              between Northern Border Pipeline
              Company and Enron Gas Marketing,
              Inc., dated June 22, 1990 (Exhibit
              10.10 to Form S-1).
      *10.6.1 Amended Exhibit A to Northern Border
              Pipeline Company U.S. Shippers
              Service Agreement between Northern
              Border Pipeline Company and Enron
              Gas Marketing, Inc. (Exhibit 10.10.1
              to the Partnership's Annual Report
              on Form 10-K for the year ended
              December 31, 1993 ("1993 10-K")).
      *10.6.2 Amended Exhibit A to Northern Border
              Pipeline U.S. Shippers Service
              Agreement between Northern Border
              Pipeline Company and Enron Gas
              Marketing, Inc., effective November 1,
              1994 (Exhibit 10.10.2 to the
              Partnership's Annual Report on Form
              10-K for the year ended December 31,
              1994).
      *10.6.3 Amended Exhibit A's to Northern
              Border Pipeline Company U.S. Shipper
              Service Agreement effective, August 1,
              1995 and November 1, 1995
              (Exhibit 10.10.3 to 1995 10-K).
      *10.6.4 Amended Exhibit A to Northern Border
              Pipeline Company U.S. Shipper
              Service Agreement effective April l,
              1998 (Exhibit 10.10.4 to the
              Partnership's Annual Report on Form
              10-K for the year ended December 31,
              1997 ("1997 10-K")).
      *10.7   Guaranty made by Northern Natural
              Gas Company, dated October 7, 1993
              (Exhibit 10.11.1 to 1993 10-K).
      *10.8   Guaranty made by Northern Natural
              Gas Company, dated October 7, 1993
              (Exhibit 10.11.2 to 1993 10-K).
      *10.9   Northern Border Pipeline Company
              U.S. Shippers Service Agreement
              between Northern Border Pipeline
              Company and Western Gas Marketing
              Limited, as agent for TransCanada
              PipeLines Limited, dated December
              15, 1980 (Exhibit 10.13 to Form S-1).
      *10.9.1 Amendment to Northern Border
              Pipeline Company Service Agreement
              extending the term effective
              November 1, 1995 (Exhibit 10.13.1 to
              1995 10-K).
      *10.10  Form of Seventh Supplement Amending
              Northern Border Pipeline Company
              General Partnership Agreement
              (Exhibit 10.15 to Form S-1).
      *10.11  Northern Border Pipeline Company
              U.S. Shippers Service Agreement
              between Northern Border Pipeline
              Company and Transcontinental Gas
              Pipe Line Corporation, dated July
              14, 1983, with Amended Exhibit A
              effective February 11, 1994 (Exhibit
              10.17 to 1995 10-K).
      *10.12  Form of Credit Agreement among
              Northern Border Pipeline Company,
              The First National Bank of Chicago,
              as Administrative Agent, The First
              National Bank of Chicago, Royal Bank
              of Canada, and Bank of America
              National Trust and Savings
              Association, as Syndication Agents,
              First Chicago Capital Markets, Inc.,
              Royal Bank of Canada, and
              BancAmerica Securities, Inc, as
              Joint Arrangers and Lenders (as
              defined therein) dated as of
              June 16, 1997 (Exhibit 10(c) to
              Amendment No. 1 to Form S-3,
              Registration Statement No. 333-40601
              ("Form S-3")).
      *10.13  Northern Border Pipeline Company
              U.S. Shippers Service Agreement
              between Northern Border Pipeline
              Company and Enron Capital & Trade
              Resources Corp. dated October 15,
              1997 (Exhibit 10.21 to 1997 10-K).
      *10.14  Northern Border Pipeline Company
              U.S. Shippers Service Agreement
              between Northern Border Pipeline
              Company and Enron Capital & Trade
              Resources Corp. dated October 15,
              1997 (Exhibit 10.22 to 1997 10-K).
      *10.15  Northern Border Pipeline Company
              U.S. Shippers Service Agreement
              between Northern Border Pipeline
              Company and Enron Capital & Trade
              Resources Corp. dated August 5, 1997
              with Amendment dated September 25,
              1997 (Exhibit 10.25 to 1997 10-K).
      *10.16  Northern Border Pipeline Company
              U.S. Shippers Service Agreement
              between Northern Border Pipeline
              Company and Enron Capital & Trade
              Resources Corp. dated August 5, 1997
              (Exhibit 10.26 to 1997 10-K).
      *10.17  Northern Border Pipeline Company
              U.S. Shippers Service Agreement
              between Northern Border Pipeline
              Company and TransCanada Gas Services
              Inc., as agent for TransCanada
              PipeLines Limited dated August 5,
              1997 (Exhibit 10.27 to 1997 10-K).
      *10.18  Project Management Agreement by and
              between Northern Plains Natural Gas
              Company and Enron Engineering &
              Construction Company, dated March 1,
              1996 (Exhibit No. 10.39 to NB Form S-4).
      *10.19  Eighth Supplement Amending Northern
              Border Pipeline Company General
              Partnership Agreement (Exhibit 10.15
              to NB Form S-4).
       10.20  Revolving Credit Agreement, dated as
              of March 21, 2001, between Northern
              Border Partners, L.P., SunTrust
              Bank, Administrative Agent, Bank of
              Montreal and Bank of America, N.A.,
              Co-Syndication Agents and Bank One,
              NA, Documentation Agent and Lenders
              (as defined therein).
      *10.21  Northern Border Pipeline Company
              U.S. Shippers Service Agreement
              between Northern Border Pipeline
              Company and Pan-Alberta Gas (US)
              Inc., dated October 1, 1993, with
              Amended Exhibit A effective June 22,
              1998 (Exhibit 10.36 to Northern
              Border Pipeline Company Annual
              Report on Form 10-K for the year
              ended December 31, 1999 ("NB
              Pipeline 1999 10-K")).
      *10.22  Northern Pipeline Company U.S.
              Shippers Service Agreement between
              Northern Border Pipeline Company and
              Pan-Alberta Gas (US) Inc.,(successor
              to Natgas U.S. Inc.) dated October 6,
              1989, with Amended Exhibit A
              effective April 2, 1999 (Exhibit
              10.37 to NB Pipeline 1999 10-K).
      *10.23  Northern Border Pipeline Company
              U.S. Shippers Service Agreement
              between Northern Border Pipeline
              Company and Pan-Alberta Gas (U.S.)
              Inc., dated October l, 1992, with
              Amended Exhibit A effective June 22,
              1998 (Exhibit 10.38 to NB Pipeline
              1999 10-K).
       10.24  Purchase and Sale Agreement, dated
              as of September 21, 2000 by and
              between Enron North America Corp.
              and NBP Energy Pipeline, L.L.C.(now
              known as Crestone Energy Ventures,
              L.L.C.).
       10.25  Master Services Agreement, dated as
              of September 21, 2000 between NBP
              Energy Pipelines, L.L.C.,(now known
              as Crestone Energy Ventures, L.L.C.)
              and Enron North America Corp.
       10.26  Acquisition Agreement, dated as of
              March 14, 2001, among Northern
              Border Partners, L.P., Northern
              Border Intermediate Limited
              Partnership, Bear Paw Investments,
              LLC, Bear Paw Energy, LLC and
              Sellers (defined therein).
       21     The subsidiaries of Northern Border
              Partners, L.P. are Northern Border
              Intermediate Limited Partnership;
              Northern Border Pipeline Company;
              and Crestone Energy Ventures, L.L.C.
       23.01  Consent of Arthur Andersen LLP.
      *99.1   Northern Border Phantom Unit Plan
              (Exhibit 99.1 to Amendment No. 1 to
              Form S-8, Registration No. 333-
              66949).
     *Indicates exhibits incorporated by
      reference as indicated; all other exhibits are
      filed herewith.