NORTHERN BORDER PIPELINE CO - 10-K Annual Report

Back to GetFilings.com

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: 333-88577

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

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

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

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

Title of each class Name of each exchange on which registered

None

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

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

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

Aggregate market value of the voting and non-voting common
equity held by non-affiliates of the registrant on March 1, 2001,
was $0.

NORTHERN BORDER PIPELINE COMPANY
TABLE OF CONTENTS

Page No.

Part I

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

Part II

Item 5. Market for Registrant's Common Equity and
Related Stockholder Matters 12
Item 6. Selected Financial Data 13
Item 7. Management's Discussion and Analysis of
Financial Condition and Results of Operations 14
Item 7a. Quantitative and Qualitative Disclosures About
Market Risk 18
Item 8. Financial Statements and Supplementary Data 19
Item 9. Changes in and Disagreements With Accountants
on Accounting and Financial Disclosure 19

Part III

Item 10. Partnership Management 19
Item 11. Executive Compensation 21
Item 12. Security Ownership of Certain Beneficial Owners
and Management 26
Item 13. Certain Relationships and Related Transactions 26

Part IV

Item 14. Exhibits, Financial Statement Schedules and
Reports on Form 8-K. 28

PART I

Item 1. Business

General

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

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

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

Our management is overseen by a four-member management
committee. Three representatives are designated by Northern
Border Partners, with each of its general partners selecting
one representative; one representative is designated by 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 Northern Border Partners' three
representatives on the management committee is allocated as
follows: 35% to the representative designated by Northern
Plains, 22.75% to the representative designated by Pan
Border and 12.25% to the representative designated by
Northwest Border. Northern Plains and Pan Border are
subsidiaries of Enron Corp. 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."

Our pipeline system is operated by Northern Plains
pursuant to an operating agreement. As of December 31,
2000, Northern Plains employed 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.

The Pipeline System

We own 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.

Our pipeline system has pipeline access to natural gas
reserves in the western Canadian sedimentary basin in the
provinces of Alberta, British Columbia and Saskatchewan in
Canada, as well as the Williston Basin in the United States.
Our 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.

Our 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, our 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

Our pipeline system connects with multiple pipelines
that provide our 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

Our 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, our 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 us.

Some of our shippers are affiliated with the general
partners of Northern Border Partners and TC PipeLines.
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

Our 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.

Our 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 our pipeline system.
Demand for western Canadian natural gas to serve other
markets also influences the ability and willingness of
shippers to use our pipeline system to meet demand in the
markets that our pipeline serves.

A variety of factors could affect the demand for
natural gas in the markets that our 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 our pipeline
system or how significant that adverse effect could be.

Future Demand and Competition

On March 16, 2000, the FERC issued an order granting
our application for a certificate to construct and operate
our proposed Project 2000 facilities. Project 2000 will
expand and extend the pipeline system into Indiana. Project
2000 will afford shippers on our 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, our 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.

We compete 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. Our
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 for its shippers 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
our customers.

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

FERC Regulation

General

We are subject to extensive regulation by the FERC as a
"natural gas company" under the Natural Gas Act. Under the
Natural Gas Act and the Natural Gas Policy Act, the FERC has
jurisdiction with respect to virtually all aspects of 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, we hold certificates of public
convenience and necessity issued by the FERC covering the
facilities, activities and services. Under Section 8 of the
Natural Gas Act, the FERC has the power to prescribe the
accounting treatment for items for regulatory purposes. Our
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.

Rate Case Proceeding

In May 1999, we filed a rate case wherein we 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 we had not proposed to change the depreciation rates
approved in the last rate case, we had the burden of proving
that the depreciation rates are just and reasonable.

On September 26, 2000, we filed a stipulation and
agreement in our 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 our 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 our 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, we could not charge or
collect more than the cost of service. Under our new form
of tariff, shippers pay us 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 we nor our
existing shippers can seek rate changes until November 1,
2005, at which time we must file a new rate case. Prior to
the new rate case, we will not be permitted to increase
rates if our costs increase, nor will we be required to
reduce rates based on cost savings. Our earnings and cash
flow will depend on our future costs, contracted capacity,
the volumes of gas transported and our ability to recontract
capacity at acceptable rates.

Under our previous cost of service form of tariff, the
amount of revenue that we collected from customers generally
declined as the rate base was recovered. Under our new
tariff, we are entitled to collect revenue based on
stated rates established in our 1999 rate case until our
next rate case, which will be filed November 1, 2005. We
will, however, continue to depreciate our rate base at an
annual depreciation rate on transmission plant in service of
2.25% and our rate base in 2005 will be a factor in
determining what we can charge when we file a new rate case
at that time. In order to avoid a decline in revenue we can
collect from our customers, we must maintain or increase our
rate base by acquiring or constructing assets that replace
or add to existing pipeline facilities or by adding new
facilities and maintain our 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 be 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 our ability
to include cost overruns for The Chicago Project in rate
base and to provide incentives for cost underruns.

The settlement of our 1995 rate case provided that for
at least seven years from the date The Chicago Project was
completed, we could continue to calculate the allowance for
income taxes in the manner we 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 our 1999 rate case.

We also provide 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 our previous
cost of service form of tariff, all interruptible
transportation service revenue generated was credited to the
benefit of the firm shippers. Under our new tariff, we
share net interruptible transportation service revenue and
any new services revenue on an equal basis with our firm
shippers through October 31, 2003. In addition, we are
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 us. In
addition, the settlement of the 1999 rate case also provided
for an equal sharing with our firm shippers of revenue
generated from a certain telecommunications contract for the
term of that contract. We intend 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 our 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 our 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. We have implemented the
necessary changes to our 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, we 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 our 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.

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

Item 2. Properties

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

Approximately 90 miles of our 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. We do have the right of eminent domain with
respect to allotted lands.

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

In conjunction with obtaining a pipeline right-of-way
lease across tribal lands located within the exterior
boundaries of the Fort Peck Indian Reservation, we also
obtained a right-of-way across allotted lands located within
the reservation boundaries. 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 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.

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.

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

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

PART II

Item 5. Market for the Registrant's Common Equity and Related
Stockholder Matters

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

The payment of distributions to our general partners is
restricted under the terms of the 1997 Pipeline Credit
Agreement and the 1992 Senior Notes. See Note 5, "Credit
Facilities and Long-Term Debt", in the Notes to Financial
Statements referred to in Item 8. "Financial Statements and
Supplementary Data". Under the most restrictive covenants,
approximately $136 million of partners' capital could be
distributed as of December 31, 2000.

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

Year Ended December 31,
2000 1999 1998 1997 1996

INCOME DATA:
Operating revenues, net $ 311,022 $ 298,347 $ 196,600 $ 186,050 $ 201,943
Operations and
maintenance 41,548 38,708 29,447 28,522 26,974
Depreciation and
amortization 57,328 51,908 40,989 38,708 46,979
Taxes other than income 27,979 30,320 21,381 22,393 24,390
Regulatory credit -- -- (8,878) -- --
Operating income 184,167 177,411 113,661 96,427 103,600
Interest expense, net 65,161 60,214 25,541 29,360 32,670
Other income 8,058 1,363 12,111 5,705 2,913
Net income to partners $ 127,064 $ 118,560 $ 100,231 $ 72,772 $ 73,843

CASH FLOW DATA:
Net cash provided by
operating activities $ 175,967 $ 171,466 $ 103,777 $ 115,328 $ 136,808
Capital expenditures 15,523 101,678 651,169 152,070 18,597
Distributions to
partners 134,904 127,163 61,205 99,322 102,845

BALANCE SHEET DATA
(AT END OF PERIOD):
Property, plant
and equipment, net $1,686,992 $1,731,394 $1,714,523 $1,100,890 $ 937,859
Total assets 1,768,505 1,796,691 1,790,889 1,147,120 974,137
Long-term debt,
including current
maturities 863,267 900,459 862,000 459,000 377,500
Partners' capital 826,995 834,835 843,438 581,412 526,962

OTHER FINANCIAL DATA:
Ratio of earnings to
fixed charges (1) 2.9 3.0 3.2 3.2 3.2

OPERATING DATA:
Natural gas delivered
(millions of cubic
feet) 852,674 834,833 608,187 621,262 630,148
Average throughput
(millions of cubic
feet per day) 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

(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.

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 for the year ended December 31, 2000
were $311.0 million as compared to $298.3 million for the same
period in 1999, an increase of $12.7 million (4%). Our net
operating revenues for 2000 reflect the significant terms of the
rate case settlement discussed in Item 1. "Business - Rate Case
Proceeding". Operating revenues for 1999 were determined under
Northern Border Pipeline's cost of service tariff.

Operations and maintenance expense 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 our two electric-powered compressor
units.

Depreciation and amortization expense 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, we used a depreciation rate for
transmission plant of 2.25% for 2000. We had used a depreciation
rate of 2.0% for 1999.

Taxes other than income decreased $2.3 million (8%) for the
year ended December 31, 2000, as compared to the same period in
1999, due primarily to adjustments to previous estimates of ad
valorem taxes.

Interest expense, net 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 $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 the result of the settlement of our rate
case.

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

Operating revenues, net increased $101.7 million (52%) for
the year ended December 31, 1999, as compared to the same period
in 1998, due primarily to additional revenue from the 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.
Our 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. We
were generally allowed an opportunity to collect from our
shippers a return on unrecovered rate base as well as recover
that rate base through depreciation and amortization. The
Chicago Project increased our 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 $9.3 million
(31%) 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 $10.9
million (27%) 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%. We 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 (42%) 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, we recorded a
regulatory credit of $8.9 million. During the construction of
The Chicago Project, we 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 we began to recover from
our shippers commencing with the in-service date of The Chicago
Project.

Interest expense, net increased $34.7 million (136%) for the
year ended December 31, 1999, as compared to the same period in
1998, due to an increase in interest expense of $15.8 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 $10.7 million (89%) 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.

Liquidity and Capital Resources

General

In August 1999, we 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 ("Senior Notes"). The indenture
under which the Senior Notes were issued does not limit the
amount of unsecured debt we may incur, but does contain material
financial covenants, including restrictions on incurrence of
secured indebtedness. The proceeds from the Senior Notes were
used to reduce indebtedness under a June 1997 credit agreement.

In June 1997, we 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 maturing in June 2002 to be used
for the retirement of our 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 31, 1999, the three-year revolving credit
facility converted to a term loan maturing in June 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, we 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. We anticipate borrowing on the Pipeline Credit
Agreement to repay the Series B Notes.

Short-term liquidity needs will be met by internal sources
and through the Pipeline Credit Agreement discussed above. Long-
term capital needs may be met through the ability to issue long-
term indebtedness.

Cash Flows From Operating Activities

Cash flows provided by operating activities increased $4.5
million to $176.0 million for the year ended December 31, 2000,
as compared to the same period in 1999, primarily due to
increased earnings. During 2000, we realized net cash inflows of
approximately $2.4 million related to our rate case, which
included approximately $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 $67.7 million to $171.5 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

Capital expenditures of $15.5 million for the year ended
December 31, 2000 included $7.4 million for Project 2000 (see
Item 1. "Business - Future Demand and Competition"). For the
same period in 1999, capital expenditures were $101.7 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 for 2001 are estimated to be $97
million, including $81 million for Project 2000. The remaining
capital expenditures planned for 2001 are for renewals and
replacements of existing facilities. We currently anticipate
funding our 2001 capital expenditures primarily by borrowing on
our Pipeline Credit Agreement and using internal sources.

Cash Flows From Financing Activities

Cash flows used in financing activities increased $58.8
million to $148.7 million for the year ended December 31, 2000,
as compared to same period in 1999. Distributions paid to the
general partners increased $7.7 million to $134.9 million for the
year ended December 31, 2000 as compared to the same period of
1999 primarily due to an increase in our net income. 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 Senior
Notes, net of associated debt discounts and issuance costs, and
$12.9 million from the termination of 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 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 $89.9 million
for the year ended December 31, 1999, as compared to cash flows
provided by financing activities of $564.8 million for the same
period in 1998. During the year ended December 31, 1998, our
general partners contributed $223.0 million to finance a portion
of the capital expenditures for The Chicago Project.
Distributions paid to the general partners increased $66.0
million to $127.2 million for the year ended December 31, 1999 as
compared to the same period of 1998. The distributions for 1999
were impacted by increased earnings and included distributions
for 13 months activity, rather than 12 months, resulting from a
change in the timing of distribution payments. The distributions
for 1998 were impacted by a rate case refund during the fourth
quarter of 1997 and by the change in the timing of distribution
payments. Advances under the Pipeline Credit Agreement, which
were primarily used to finance a portion of the capital
expenditures for The Chicago Project, were $90 million for the
year ended December 31, 1999 as compared to advances of $403
million for the same period in 1998.

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 8 to the 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 Item 1. "Business - Future Demand and
Competition" and elsewhere regarding our efforts to pursue
opportunities to further increase the capacity of our
pipeline system;

* the discussion under Item 1. "Business - Rate Case
Proceeding" regarding the settlement of our rate case;

* the discussion in Item 1. "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;

* our success in sustaining our positions in such proceedings,
or the success of intervenors in opposing our positions;

* our ability to replace our 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; 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 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 50% 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 point
compared to rates in effect as of December 31, 2000, annual
interest expense would change by approximately $4.3 million.
This amount has been determined by considering the impact of the
hypothetical interest rates on 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.

PART III

Item 10. Partnership Management

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

William R. Cordes, Chairman(1)

Stanley C. Horton(1)

Dennis J. McConaghy(2)

Cuba Wadlington, Jr.(1)

__________

(1) Designated by Northern Border Partners.

(2) Designated by TC PipeLines.

William R. Cordes (52) has been a member and Chairman of our
management committee since October 1, 2000. Mr. Cordes was named
Chief Executive Officer of Northern Border Partners in October
2000. Since October 2000, Mr. Cordes has been the President and
a director of Northern Plains, an Enron subsidiary and our
operator.

Stanley C. Horton (50) has been a member of our management
committee since 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. Prior to that, Mr. Horton served as Co-
Chairman and Chief Executive Officer of Enron Operations Corp.
(1996-1997) and President and Chief Operating Officer of Enron
Operations Corp. (1993-1996). 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.

Dennis J. McConaghy (49) has been a member of our management
committee since December 2000. He was appointed a director of TC
PipeLines GP, Inc. (the general partner of TC PipeLines LP) in
December 2000. His principal occupation is Senior Vice-President
Business Development for TransCanada, a position he has held
since October 2000. Prior to that time and since June 2000, Mr.
McConaghy was Senior Vice-President, Midstream/Divestments,
TransCanada. Prior to that time and since July 1998, Mr.
McConaghy was Vice-President, Strategy and Planning, TransCanada.
Prior to that time and since May 1996, Mr. McConaghy was Vice-
President, Corporate Development, NOVA Corporation. Prior to
that time and since November 1995, Mr. McConaghy was Senior Vice-
President and Chief Financial Officer, NOVA Chemicals Ltd.

Cuba Wadlington, Jr. (57) has been a member of our
management committee since 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., public companies subject to the reporting
requirements of the Securities Exchange Act of 1934.

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

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

Item 11. Executive Compensation

Executive Disclosure

Jerry L. Peters (43) has served as Treasurer of Northern
Plains since October 1998, Vice President of Finance for Northern
Plains since July 1994 and director of Northern Plains since
August 1994. He has also been named Vice President, Finance for
Enron Transportation Services Company. He has been associated
with Northern Plains since 1985.

The following table summarizes information regarding
compensation paid or accrued during each of the last three fiscal
years to Larry L. DeRoin, Jerry L. Peters and the last fiscal
year to William R. Cordes (the "Named Officers") by Northern
Plains, our operator. Messrs. Cordes and Peters are both
employees of Northern Plains, but contribute services to our
operations, for which we reimburse Northern Plains. Mr. DeRoin
was an employee of Northern Plains until his retirement on
September 30, 2000. Northern Plains is an affiliate of Enron.

Summary Compensation Table
All Other

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)

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

(1) Mr. DeRoin retired effective September 30, 2000. Mr. Cordes
was appointed President of Northern Plains 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.

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.

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%

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

(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.

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:

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

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

(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.

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.

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

Mr. Cordes 30.4 43.1 $311,000 $142,234
Mr. Peters 15.9 37.8 $145,293 $ 78,957
________

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.

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. Beneficial Ownership Of Partnership Interests

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

General
Partnership
Name of Beneficial Owner Interest

Northern Border Partners, L.P.(1) 70%
TC PipeLines, LP(2) 30%
__________

(1) The address of Northern Border Partners, L.P. is 1400
Smith Street, Houston, Texas 77002. Northern Border Partners
holds its 70% general partnership interest through Northern
Border Intermediate Limited Partnership, a subsidiary limited
partnership. Northern Border Partners has three general
partners: Northern Plains Natural Gas Company, Pan Border Gas
Company and Northwest Border Pipeline Company. Northern
Plains and Pan Border are wholly-owned subsidiaries of Enron
Corp. and Northwest Border is a wholly-owned subsidiary of The
Williams Companies, Inc.

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

Item 13. Certain Relationships And Related Transactions

We have extensive ongoing relationships with our general
partners and certain of their affiliates. Since 1980, Northern
Plains, an affiliate of Enron, has acted and will continue to act
as the operator of our pipeline system pursuant to the terms of
the operating agreement with Northern Plains. The initial term
of the operating agreement expires in 2007. The operating
agreement will continue in effect thereafter on a year-to-year
basis unless terminated by us or Northern Plains upon six months
written notice by either party. The operator is entitled to
reimbursement for all reasonable costs, including overhead and
administrative expenses, incurred by it and its affiliates in
connection with the performance of its responsibilities as
operator. In addition, we have agreed to indemnify the operator
against any claims and liabilities arising out of the good faith
performance by the operator of its responsibilities under our
partnership agreement, to the extent the operator is acting
within the scope of its authority and in the course of our
business. For the year ended December 31, 2000, the aggregate
amount paid and reimbursed to Northern Plains, for its services
as operator, was approximately $31.7 million.

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;

* 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 terms of all such related transactions are no less
favorable to us than those we would expect to negotiate with
unrelated third parties on an arm's length basis.

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

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

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

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

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

* The partnership agreement relieves Northern Border
Partners and TC PipeLines, their affiliates and their
transferees from any duty to offer business opportunities
to us, except that neither our general partners or their
affiliates may pursue Project 2000 or any other
opportunity relating to expansion or improvements of our
pipeline system as it existed on January 15, 1999.

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 Northern Border Pipeline Company General
Partnership Agreement between Northern
Plains Natural Gas Company, Northwest
Border Pipeline Company, Pan Border Gas
Company, TransCanada Border Pipeline Ltd.
and TransCan Northern Ltd., effective
March 9, 1978, as amended (Exhibit 10.2
to Northern Border Partners, L.P.'s Form
S-1, SEC File No. 33-66158 ("Form S-1")).
* 4.1 Indenture, dated as of August 17, 1999,
between the registrant and Bank One Trust
Company, NA, successor to The First
National Bank of Chicago, as trustee.
(Exhibit 4.1 to Northern Border Pipeline
Company's Form S-4 Registration
Statement, Registration No. 333-88577
("Form S-4")).
*10.1 Operating Agreement between Northern
Border Pipeline Company and Northern
Plains Natural Gas Company, dated
February 28, 1980 (Exhibit 10.3 to Form S-1).
*10.2 Note Purchase Agreement between Northern
Border Pipeline Company and the parties
listed therein, dated July 15, 1992
(Exhibit 10.6 to Form S-1).
*10.3 Supplemental Agreement to the Note
Purchase Agreement dated as of June 1,
1995 (Exhibit 10.6.1 to Northern Border
Partners L.P.'s Form 10-K for the year
ended December 31, 1995, SEC File No.
1-12202 ("1995 10-K")).
*10.4 Guaranty made by Panhandle Eastern
Pipeline Company, dated October 31, 1992
(Exhibit 10.9 to Form S-1).
*10.5 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 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 Northern Border
Partners L.P.'s Form 10-K for the year
ended December 31, 1993, SEC File No.
1-12202 ("1993 10-K")).
*10.7 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
Northern Border Partners, L.P.'s Form 10-K
for the year ended December 31, 1994,
SEC File No. 1-12202 ("1994 10-K")).
*10.8 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).
*10.9 Amended Exhibit A to Northern Border
Pipeline Company U.S. Shipper Service
Agreement effective April l, 1998
(Exhibit 10.10.4 to Northern Border
Partners, L.P.'s Form 10-K for the year
ended December 31, 1997, SEC File No.
1-12202 ("1997 10-K")).
*10.10 Guaranty made by Northern Natural Gas
Company, dated October 7, 1993 (Exhibit
10.11.1 to 1993 10-K).
*10.11 Guaranty made by Northern Natural Gas
Company, dated October 7, 1993 (Exhibit
10.11.2 to 1993 10-K)
*10.12 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).
*10.13 Amendment to Northern Border Pipeline
Company Service Agreement extending the
term effective November 1, 1995 (Exhibit
10.13.1 to 1995 10-K).
*10.14 Seventh Supplement Amending Northern
Border Pipeline Company General
Partnership Agreement (Exhibit 10.15 to
Form S-1).
*10.15 Eighth Supplement Amending Northern
Border Pipeline Company General
Partnership Agreement. (Exhibit 10.15 of
Form S-4).
*10.16 Form of Conveyance, Contribution and
Assumption Agreement among Northern
Plains Natural Gas Company, Northwest
Border Pipeline Company, Pan Border Gas
Company, Northern Border Partners, L.P.,
and Northern Border Intermediate Limited
Partnership (Exhibit 10.16 to Form S-1).
*10.17 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).
*10.18 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
Northern Border Partners, L.P. Form S-3,
SEC File No 333-40601 ("Form S-3")).
*10.19 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).
*10.20 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).
*10.21 Northern Border Pipeline Company U.S.
Shippers Service Agreement between
Northern Border Pipeline Company and
Enron Capital & Trade Resources Corp.
dated August 5, 1997 with Amendment dated
September 25, 1997 (Exhibit 10.25 to 1997
10-K).
*10.22 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).
*10.23 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).
*10.24 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 10.28 to 1997
10-K).
*10.25 Northern Border Pipeline Company
Agreement among Northern Plains Natural
Gas Company, Pan Border Gas Company,
Northwest Border Pipeline Company,
TransCanada Border PipeLine Ltd.,
TransCan Northern Ltd., Northern Border
Intermediate Limited Partnership,
Northern Border Partners, L.P., and the
Management Committee of Northern Border
Pipeline, dated as of March 17, 1999.
(Exhibit No. 10.21 to Northern Border
Partners, L.P.'s Form 10-K for the year
ended December 31, 1998, SEC File No.
1-12202 ("1998 10-K")).
*10.26 Form of Contribution, Conveyance and
Assumption Agreement among TC PipeLines,
LP and certain other parties. (Exhibit
10.2 to TC PipeLines, LP's Form S-1, SEC
File No. 333-69947 ("TC Form S-1")).
*10.27 Amended Exhibit A to Northern Border
Pipeline Company U.S. Shippers Service
Agreement between Northern Border
Pipeline Company and Western Gas
Marketing extending the term effective
April 2, 1999 (Exhibit 10.11.1 to TC Form
S-1).
*10.28 Amended Exhibit A to Northern Border
Pipeline Company U.S. Shippers Service
Agreement between Northern Border
Pipeline Company and Enron Capital &
Trade Resources Corp. effective November
1, 1998 (Exhibit 10.15.1 to TC Form S-1).
*10.29 Amended Exhibit A to Northern Border
Pipeline Company U.S. Shippers Service
Agreement between Northern Border
Pipeline Company and Enron Capital &
Trade Resources Corp. effective April 2,
1999 (Exhibit 10.16.1 to TC Form S-1).
*10.30 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
October 10, 1996, with Amended Exhibit A
effective April 2, 1999 (Exhibit 10.19 to
TC Form S-1).
*10.31 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
October 5, 1998, with Amended Exhibit A
effective April 2, 1999 (Exhibit 10.20 to
TC Form S-1).
*10.32 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
October 5, 1998, with Amended Exhibit A
effective April 2, 1999 (Exhibit 10.21 to
TC Form S-1).
*10.33 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
October 5, 1998, with Amended Exhibit A
effective April 2, 1999 (Exhibit 10.22 to
TC Form S-1).
*10.34 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
October 5, 1998, with Amended Exhibit A
effective April 2, 1999 (Exhibit 10.23 to
TC Form S-1).
*10.35 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
December 18, 1998 (Exhibit 10.24 to TC
Form S-1).
*10.36 Northern Border Pipeline Company U.S.
Shippers Service Agreement between
Northern Border Pipeline Company and Pan-
Alberta Gas (U.S.) Inc., dated October 1,
1993, with Amended exhibit A effective
June 22, 1998 (Exhibit 10.25 to TC Form S-1).
*10.37 Northern Border Pipeline Company U.S.
Shippers Service Agreement between
Northern Border Pipeline Company and Pan-
Alberta Gas (U.S.) Inc. (successor to
Natgas U.S. Inc.), dated October 6, 1989,
with Amended Exhibit A effective April 2,
1999 (Exhibit 10.26 to TC Form S-1).
*10.38 Northern Border Pipeline Company U.S.
Shippers Service Agreement between
Northern Border Pipeline Company and Pan-
Alberta Gas (U.S.) Inc., dated October 1,
1992, with Amended Exhibit A effective
June 22, 1998 (Exhibit 10.27 to TC Form S-1).
*10.39 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 Form S-4).
*99.1 Northern Border Phantom Unit Plan
(Exhibit 99.1 to Northern Border
Partners, L.P.'s 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
No reports on Form 8-K were filed by the Partnership
during the last quarter of 2000.

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 PIPELINE COMPANY
(A Texas General partnership)

BY: Northern Plains Natural Gas
Company, As Operator

By: JERRY L. PETERS
Jerry L. Peters
Vice President, Finance and
Treasurer

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

Signature Title Date

WILLIAM R. CORDES President, Northern Plains Natural March 29, 2001
William R. Cordes Company
(functional equivalent to the
registrant's principal executive
officer)
and Management Committee Member

JERRY L. PETERS Vice President, Finance and Treausrer, March 29, 2001
Northern Plains Natural Gas Company
(functional equivalent to the
registrant's principal financial and
accounting officer)

STANLEY C. HORTON Management Committee Member March 29, 2001
Stanley C. Horton

DENNIS J. MCCONAGHY Management Committee Member March 29, 2001
Dennis J. McConaghy

CUBA WADLINGTON, JR. Management Committee Member March 29, 2001
Cuba Wadlington, Jr.

NORTHERN BORDER PIPELINE COMPANY
INDEX TO FINANCIAL STATEMENTS

Page No.

Financial Statements

Report of Independent Public Accountants F-2
Balance Sheet - December 31, 2000 and 1999 F-3
Statement of Income - Years Ended F-4
December 31, 2000, 1999 and 1998
Statement of Cash Flows - Years Ended F-5
December 31, 2000, 1999 and 1998
Statement of Changes in Partners' Capital - F-6
Years Ended December 31, 2000, 1999 and 1998
Notes to Financial Statements F-7 through
F-16

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 Pipeline Company:

We have audited the accompanying balance sheet of Northern Border
Pipeline Company (a Texas partnership) as of December 31, 2000
and 1999, and the related 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 Pipeline Company as of December 31, 2000 and
1999, and the results of its operations and its 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

NORTHERN BORDER PIPELINE COMPANY

BALANCE SHEET

(In Thousands)

December 31,
ASSETS 2000 1999

CURRENT ASSETS
Cash and cash equivalents $ 29,046 $ 17,310
Accounts receivable 27,128 21,929
Related party receivables 6,008 5,120
Materials and supplies, at cost 4,957 3,645
Under recovered cost of service -- 3,068

Total current assets 67,139 51,072

NATURAL GAS TRANSMISSION PLANT
In service 2,364,487 2,363,291
Construction work in progress 14,405 4,730

Total property, plant and equipment 2,378,892 2,368,021
Less: Accumulated provision for
depreciation and amortization 691,900 636,627

Property, plant and equipment, net 1,686,992 1,731,394

OTHER ASSETS 14,374 14,225

Total assets $1,768,505 $1,796,691

LIABILITIES AND PARTNERS' CAPITAL

CURRENT LIABILITIES
Current maturities of long-term debt $ 41,000 $ 66,000
Accounts payable 26,087 5,588
Accrued taxes other than income 28,137 26,290
Accrued interest 14,401 16,504
Accumulated provision for rate refunds 4,726 2,317

Total current liabilities 114,351 116,699

LONG-TERM DEBT, NET OF CURRENT MATURITIES 22,267 834,459

RESERVES AND DEFERRED CREDITS 4,892 10,698

COMMITMENTS AND CONTINGENCIES (Note 6)

PARTNERS' CAPITAL 826,995 834,835

Total liabilities and partners' capital $1,768,505 $1,796,691

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

NORTHERN BORDER PIPELINE COMPANY

STATEMENT OF INCOME

(In Thousands)

Year Ended December 31,
2000 1999 1998

OPERATING REVENUES
Operating revenues $334,978 $300,664 $196,600
Provision for rate refunds (23,956) (2,317) --

Operating revenues, net 311,022 298,347 196,600

OPERATING EXPENSES
Operations and maintenance 41,548 38,708 29,447
Depreciation and amortization 57,328 51,908 40,989
Taxes other than income 27,979 30,320 21,381
Regulatory credit -- -- (8,878)

Operating expenses 126,855 120,936 82,939

OPERATING INCOME 184,167 177,411 113,661

INTEREST EXPENSE
Interest expense 65,489 60,312 44,542
Interest expense capitalized (328) (98) (19,001)

Interest expense, net 65,161 60,214 25,541

OTHER INCOME
Allowance for equity funds used
during construction 305 101 10,237
Other income, net 7,753 1,262 1,874

Other income 8,058 1,363 12,111

NET INCOME TO PARTNERS $127,064 $118,560 $100,231

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

NORTHERN BORDER PIPELINE COMPANY

STATEMENT OF CASH FLOWS

(In Thousands)

Year Ended December 31,
2000 1999 1998

CASH FLOWS FROM OPERATING ACTIVITIES:
Net income to partners $ 127,064 $ 118,560 $ 100,231

Adjustments to reconcile net income to
partners to net cash provided by
operating activities:
Depreciation and amortization 57,682 51,962 41,005
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 (5,806) 880 (10)
Regulatory credit -- -- (9,105)
Changes in components of working capital (3,002) (2,112) (18,471)
Other (2,075) (40) 364

Total adjustments 48,903 52,906 3,546

Net cash provided by operating activities 175,967 171,466 103,777

CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures for property, plant
and equipment, net (15,523) (101,678) (651,169)

CASH FLOWS FROM FINANCING ACTIVITIES:
Contributions from partners -- -- 223,000
Distributions to partners (134,904) (127,163) (61,205)
Issuance of long-term debt, net 75,000 289,026 403,000
Retirement of long-term debt (111,000) (263,000) --
Increase in bank overdraft 22,437 -- --
Proceeds received upon termination of
interest rate forward agreements -- 12,896 --
Long-term debt financing costs (241) (1,626) --

Net cash provided by (used in)
financing activities (148,708) (89,867) 564,795

NET CHANGE IN CASH AND CASH EQUIVALENTS 11,736 (20,079) 17,403

Cash and cash equivalents-beginning of year 17,310 37,389 19,986

Cash and cash equivalents-end of year $ 29,046 $ 17,310 $ 37,389

Changes in components of working capital:
Accounts receivable $ (6,087) $ (8,145) $ (1,567)
Materials and supplies (1,312) (285) 317
Accounts payable 1,585 (4,598) (10,769)
Accrued taxes other than income 1,847 6,462 (466)
Accrued interest (2,103) 4,741 1,396
Over/under recovered cost of service 3,068 (287) (7,382)

Total $ (3,002) $ (2,112) $ (18,471)

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

NORTHERN BORDER PIPELINE COMPANY

STATEMENT OF CHANGES IN PARTNERS' CAPITAL

(In Thousands)

TC Northern
TransCanada PipeLines Border
Border TransCan Intermediate Intermediate Total
PipeLine Northern Limited Limited Partners'
Ltd. Ltd. Partnership Partnership Capital

Partners' Capital at
December 31, 1997 $ 34,885 $ 139,539 $ -- $406,988 $ 581,412

Net income to partners 6,014 24,055 -- 70,162 100,231

Contributions received 13,380 53,520 -- 156,100 223,000

Distributions paid (3,673) (14,689) -- (42,843) (61,205)

Partners' Capital at
December 31, 1998 50,606 202,425 -- 590,407 843,438

Net income to partners 2,930 11,715 20,923 82,992 118,560

Distributions paid (5,206) (20,819) (12,124) (89,014) (127,163)

Ownership transfer (48,330) (193,321) 241,651 -- --

Partners' Capital at
December 31, 1999 -- -- 250,450 584,385 834,835

Net income to partners -- -- 38,119 88,945 127,064

Distributions paid -- -- (40,471) (94,433) (134,904)

Partners' Capital at
December 31, 2000 $ -- $ -- $248,098 $578,897 $ 826,995

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

NORTHERN BORDER PIPELINE COMPANY

NOTES TO FINANCIAL STATEMENTS

1. ORGANIZATION AND MANAGEMENT

Northern Border Pipeline Company (Northern Border Pipeline) is a
general partnership, formed in 1978, pursuant to the Texas Uniform
Partnership Act. The ownership percentages of the partners in
Northern Border Pipeline (Partners) at December 31, 2000 and 1999,
are as follows:

Ownership
Partner Percentage

Northern Border Intermediate Limited Partnership 70
TC PipeLines Intermediate Limited Partnership 30

Net income and distributions are allocated to the Partners based on
ownership percentage. Effective May 28, 1999, TransCanada Border
PipeLine Ltd. and TransCan Northern Ltd. transferred their combined
30% ownership interest in Northern Border Pipeline to TC PipeLines
Intermediate Limited Partnership (TC PipeLines) in connection with
an initial public offering of limited partner interests in TC
PipeLines, LP. In accordance with the partnership agreement, net
income and distributions were prorated at the effective date of the
ownership transfer.

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 Northern Border Intermediate
Limited Partnership (Partnership) and one representative from TC
PipeLines. The Partnership's representatives selected by its
general partners, Northern Plains Natural Gas Company (Northern
Plains), a wholly-owned subsidiary of Enron Corp. (Enron), Pan
Border Gas Company (Pan Border), a wholly-owned subsidiary of
Northern Plains, and Northwest Border Pipeline Company, a wholly-
owned subsidiary of The Williams Companies, Inc., have 35%, 22.75%
and 12.25%, respectively, of the voting interest on the Management
Committee. The representative designated by TC PipeLines votes the
remaining 30% interest. 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 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.

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

(A) Use of Estimates

The preparation of financial statements in conformity with
accounting principles generally accepted in the United States
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 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 3 and 4 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 FERC tariff establishes the method of
accounting for and calculating income taxes and requires
Northern Border Pipeline to reflect in its rates the income
taxes which would have been paid or accrued if Northern Border
Pipeline were organized during the period as a corporation. As
a result, for purposes of determining transportation rates in
calculating the return allowed by the FERC, Partners' capital
and rate base are reduced by the amount equivalent to the net
accumulated deferred income taxes. Such amounts were
approximately $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 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 3, Northern Border
Pipeline will continue to use a 2.25% depreciation rate.
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) Risk Management

Financial instruments are used by Northern Border Pipeline
in the management of its interest rate exposure. A control
environment has been established which includes policies and
procedures for risk assessment and the approval, reporting and
monitoring of financial instrument activities. 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.

3. 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.

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
the rate case discussed in Note 3, 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.

5. CREDIT FACILITIES AND LONG-TERM DEBT

Detailed information on long-term debt is as follows:

December 31,
(Thousands of dollars) 2000 1999

1992 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 Senior Notes - 7.75%, due 2009 200,000 200,000
Unamortized proceeds from termination
of interest rate forward agreements 11,107 12,397
Unamortized debt discount (840) (938)

Total 863,267 900,459
Less: Current maturities of long-term debt 41,000 66,000

Long-term debt $822,267 $834,459

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 Senior Notes). Also in August
1999, Northern Border Pipeline received approximately $12.9 million
from the termination of interest rate forward agreements, which is
included in long-term debt on the balance sheet and is being
amortized against interest expense over the life of the 1999 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 $68.0 million, $55.5 million
and $23.8 million, respectively.

Aggregate required repayments of long-term debt are as follows: $41
million, $547 million and $65 million for 2001, 2002 and 2003,
respectively. There are no required repayment obligations for
either 2004 or 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 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 Senior Notes was
approximately $191 million and $273 million at December 31, 2000 and
1999, respectively. The estimated fair value of the 1999 Senior
Notes was approximately $213 million and $201 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. Northern Border Pipeline
presently intends to maintain the current schedule of maturities for
the 1992 Senior Notes, 1999 Senior Notes and the interest rate swap
agreement which will result in no gains or losses on their
respective repayment. The fair value of Northern Border Pipeline's
variable rate debt approximates the carrying value since the
interest rates are periodically adjusted to reflect current market
conditions.

6. COMMITMENTS AND CONTINGENCIES

Capital expenditures

Total capital expenditures for 2001 are estimated to be $97 million.
This includes approximately $81 million for Project 2000 (see Note
3) and approximately $16 million for renewals and replacements of
the existing facilities. Funds required to meet the capital
expenditures for 2001 are anticipated to be provided primarily from
debt borrowings and internal sources.

Environmental Matters

Northern Border Pipeline 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. Northern Border Pipeline believes that the
resolution of these issues will not have a material adverse impact
on Northern Border Pipeline's results of operations or financial
position.

7. QUARTERLY FINANCIAL DATA (Unaudited)

Operating Operating Net Income
(In thousands) Revenues, net Income to Partners

2000
First Quarter $76,241 $44,628 $28,744
Second Quarter 77,346 44,305 29,413
Third Quarter 78,241 47,584 34,293
Fourth Quarter 79,194 47,650 34,614
1999
First Quarter $73,635 $44,271 $30,315
Second Quarter 73,022 43,788 28,933
Third Quarter 73,925 44,017 29,127
Fourth Quarter 77,765 45,335 30,185

8. ACCOUNTING PRONOUNCEMENTS

In 1998, the Financial Accounting Standards Board 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. Northern Border Pipeline will
adopt SFAS No. 133 beginning January 1, 2001. The adoption of SFAS
No. 133, as amended, will not have a material impact on Northern
Border Pipeline's financial position or results of operations.

9. SUBSEQUENT EVENTS

Northern Border Pipeline makes distributions to it general partners
approximately one month following the end of the quarter. The
distribution for the fourth quarter of 2000 of approximately $31.4
million is payable February 2, 2001.

Report of Independent Public Accountants on Schedule

To Northern Border Pipeline Company:

We have audited in accordance with auditing standards generally accepted
in the United States, the financial statements of Northern Border
Pipeline Company 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 Pipeline Company listed in Item 14 of
Part IV of this Form 10-K is the responsibility of the Company's
management and is presented for purposes of complying with the
Securities and Exchange Commission's rules and is not part of the basic
financial statements. This schedule has been subjected to the auditing
procedures applied in the audits of the basic financial statements and,
in our opinion, fairly states in all material respects the financial
data required to be set forth therein in relation to the basic financial
statements taken as a whole.

ARTHUR ANDERSEN LLP

Omaha, Nebraska,
January 22, 2001

SCHEDULE II

NORTHERN BORDER PIPELINE COMPANY
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 2000, 1999 AND 1998
(In Thousands)

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

Reserve for
regulatory issues
2000 $7,376 $1,800 $-- $7,376 $1,800
1999 $6,726 $ 650 $-- $ -- $7,376
1998 $6,726 $ -- $-- $ -- $6,726