NORTHERN BORDER PARTNERS LP - 10-K Annual Report

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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, 1996
Commission file number: 1-12202

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

DELAWARE 93-1120873
(State or other jurisdiction (I.R.S. Employer
of incorporation or organization) Identification No.)

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

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

Title of each class Name of each exchange on which registered

Common Units New York Stock Exchange

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

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

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

Aggregate market value of the Common Units held by non-
affiliates of the registrant, based on closing prices in the
daily composite list for transactions on the New York Stock
Exchange on March 4, 1997, was approximately $560,865,925.

NORTHERN BORDER PARTNERS, L.P.
TABLE OF CONTENTS

Page No.

Part I

Item 1. Business 1
Item 2. Properties 12
Item 3. Litigation 13
Item 4. Submission of Matters to a Vote of Security Holders 13

Part II

Item 5. Market for Registrant's Common Units and Related
Security Holder Matters 14
Item 6. Selected Financial Data (Unaudited) 15
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations 16
Item 8. Financial Statements 18
Item 9. Disagreements on Accounting and Financial Disclosure 18

Part III

Item 10. Partnership Management 19
Item 11. Executive Compensation 22
Item 12. Security Ownership of Certain Beneficial Owners
and Management 29
Item 13. Certain Relationships and Related Transactions 29

Part IV

Item 14. Exhibits, Financial Statements and Reports on
Form 8-K. 31

PART I

Item 1. Business

General

Northern Border Partners, L.P. through a subsidiary limited
partnership, Northern Border Intermediate Limited Partnership,
collectively referred to herein as "Partnership", owns a 70%
general partner interest in Northern Border Pipeline Company, a
Texas general partnership ("Northern Border Pipeline"). The
remaining general partner interests in Northern Border Pipeline
are owned by TransCanada Border PipeLine Ltd. (6%) and TransCan
Northern Ltd. (24%), both of which are wholly-owned subsidiaries
of TransCanada PipeLines Limited ("TransCanada"). Northern
Plains Natural Gas Company ("Northern Plains"), Pan Border Gas
Company ("Pan Border") and Northwest Border Pipeline Company
("Northwest Border") serve as the General Partners of the
Partnership. Northern Plains is a wholly-owned subsidiary of
Enron Corp. ("Enron"), Pan Border is a wholly-owned subsidiary of
PanEnergy Corp. ("PanEnergy") and Northwest Border is a wholly-
owned subsidiary of The Williams Companies, Inc. ("Williams").
The General Partners hold an aggregate 2% general partner
interest in the Partnership. The General Partners also own in
the aggregate an effective 24% subordinated limited partner
interest ("Subordinated Units") in the Partnership. The combined
general and limited partner interests in the Partnership of
Northern Plains, Pan Border and Northwest Border are 13%, 8.5%
and 4.5%, respectively (See "Certain Relationships and Related
Transactions").

Northern Border Pipeline owns a 969-mile U.S. interstate
pipeline system (the "Pipeline System") that transports natural
gas from the Montana-Saskatchewan border near Port of Morgan,
Montana, to interconnecting pipelines in the State of Iowa. The
Pipeline System has pipeline access to natural gas reserves in
the provinces of Alberta, British Columbia and Saskatchewan, as
well as the Williston Basin in the United States. The Pipeline
System also has access to production of synthetic gas ("syngas")
from the Great Plains Coal Gasification Project in North Dakota.
Interconnecting pipeline facilities provide Northern Border
Pipeline shippers access to markets in the Midwest, as well as
other markets throughout the U.S. by transportation, displacement
and exchange arrangements.

Management of Northern Border Pipeline is overseen by the
Northern Border Management Committee, which is comprised of three
representatives from the Partnership (one selected by each
General Partner) and one representative from the TransCanada
subsidiaries. The Pipeline System is operated by Northern Plains
pursuant to an operating agreement. Northern Plains employs
approximately 170 individuals to operate the Pipeline System.
These employees are located at the operating headquarters in
Omaha, Nebraska, at locations along the pipeline route and at gas
control operations in Houston, Texas. Northern Plains' employees
are not represented by any labor union and are not covered by any
collective bargaining agreements.

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 transports gas
for shippers under a tariff regulated by the Federal Energy
Regulatory Commission ("FERC") that allows it to recover
operations and maintenance costs of the Pipeline System, taxes
other than income taxes, interest, depreciation and amortization,
an allowance for income taxes and a regulated equity return.
Northern Border Pipeline does not own the gas that it transports
and therefore it does not assume any gas commodity price risk.

As a result of an acquisition during 1996, the Partnership
has a non-controlling ownership position of 60.5% in Black Mesa
Pipeline Holdings, Inc. ("Black Mesa"). Black Mesa, through a
wholly-owned subsidiary, owns a 273-mile, 18-inch diameter coal
slurry pipeline (the "Black Mesa Pipeline") which originates at a
coal mine in Kayenta, Arizona. The pipeline traverses westward
through northern Arizona to the 1,500 megawatt Mohave Power
Station located in Laughlin, Nevada. Black Mesa Pipeline is the
sole source of fuel for the Mohave plant, which consumes an
average of 4.8 million tons of coal annually. The capacity of
Black Mesa Pipeline is fully contracted to the Mohave Power
Station coal supplier through the year 2005. Black Mesa Pipeline
is operated by Williams Technologies, Inc. of Tulsa, Oklahoma,
which is not affiliated with Williams.

The Pipeline System

The 822-mile portion of the Pipeline System from the
Canadian border to Ventura, Iowa, was completed and placed in
service in 1982. It was built to transport large quantities of
natural gas through large diameter, high operating pressure pipe.
Northern Border Pipeline's early operations were, and its current
operations continue to be, supported by significant supplies of
natural gas in Canada. In addition, the Pipeline System gained
access to additional gas supplies from the Williston Basin and
Great Plains Coal Gasification Project in the early 1980s.

At its northern end, the Pipeline System is connected to the
Foothills Pipe Lines (Sask.) Ltd. system in Canada, which in turn
is connected to the gathering systems of NOVA Gas Transmission
Ltd. ("NOVA") in Alberta and of Transgas Limited in Saskatchewan.
The NOVA system gathers and transports a substantial portion of
Canadian natural gas production. The Pipeline System also
connects with the 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 system. In the Pipeline System's
southern portion, it interconnects with the pipeline facilities
of an Enron subsidiary, Northern Natural Gas Company ("Northern
Natural"), near Ventura, Iowa, and of Natural Gas Pipeline
Company of America ("NGPL") near Harper, Iowa. The Ventura, Iowa
interconnect functions as a large market center, where gas
volumes transported on the Pipeline System are sold, traded and
received for transport to significant consuming markets in the
Midwest and to interconnecting pipeline facilities destined for
other markets. The Harper, Iowa interconnect with NGPL also
provides gas transported through the Pipeline System access to
Chicago and other Midwest markets and to interconnecting pipeline
facilities destined for other markets.

There are seven existing compressor stations on the Pipeline
System, and Northern Border Pipeline owns another six sites for
compressor stations that may be constructed in the future (See
"Demand For Transportation Capacity"). Other facilities include
three pipeline field offices and warehouses, five measurement
stations and 39 microwave tower sites. There have been two
expansions of the Pipeline System since it was placed in service
in 1982. An additional compressor station was added in 1991 and
an expansion and extension project was completed and placed in
service on November 1, 1992. This 1992 project entailed the
construction of four compressor stations and the acquisition of
approximately 147 miles of a 30-inch diameter pipeline beginning
at an interconnect with the original system near Ventura, Iowa
and terminating near Harper, Iowa where it interconnects with the
facilities of NGPL. As a result of the two expansions, the
throughput capacity of the Pipeline System increased by 463
million cubic feet per day ("MMCFD") to 1,675 MMCFD.

The 822-mile, 42-inch diameter segment of the Pipeline
System was designed (with maximum compression before looping) to
transport up to 2,400 MMCFD. The 147-mile, 30-inch diameter
segment was designed (with maximum compression before looping) to
transport up to 750 MMCFD. The existing compression on the line
allows the transportation of 1,675 MMCFD through the 42-inch
segment and 386 MMCFD through the 30-inch segment. As a result,
an increase in transportation capacity could be achieved through
the use of additional compression, which is a cost-effective
method of adding capacity to the Pipeline System.

Shippers

Based upon existing contracts and capacity, 100% of the
Pipeline System's firm capacity (at current compression) is
contractually committed through October 2001. The Pipeline
System serves a number of shippers with diverse financial and
market profiles.

At the present time, 6% of the firm capacity (based on
annual cost of service obligations) is contracted by interstate
pipelines. Each of the interstate pipelines is subject to Order
636 (described in greater detail under "FERC Regulation"), and as
a result of each of their restructuring proceedings, capacity on
the Pipeline System has been retained or may be assigned to that
interstate pipeline's suppliers or customers. The remaining firm
capacity is contracted to producers, marketers and local
distribution companies. Four of the firm shippers are affiliated
with general partners of the Partnership or Northern Border
Pipeline: Enron Capital & Trade Resources Corp., a subsidiary of
Enron; Mobil Natural Gas Inc. through its marketing arrangement
with an affiliate of PanEnergy; TransCanada Gas Services Inc., a
subsidiary of, and as agent for, TransCanada; and
Transcontinental Gas Pipe Line Corporation ("Transco"), a
subsidiary of Williams. Together those shippers hold 11% of the
firm capacity.

Northern Border Pipeline's largest shipper, Pan-
Alberta Gas (U.S.) Inc. ("PAGUS"), currently holds 49% of the
firm capacity. Affiliates of PanEnergy and Enron provide
guaranties for 350 MMCFD (150 MMCFD and 200 MMCFD, respectively)
of PAGUS' contractual obligations. The contractual obligation
related to PAGUS' remaining 450 MMCFD of capacity is supported by
various credit support arrangements including, among others, a
letter of credit, an additional guaranty from Northern Natural
for 100 MMCFD, an escrow account and an upstream capacity
transfer agreement. At the request of PAGUS, in February 1997
Northern Border Pipeline filed an application with the FERC to
convert the authority for PAGUS transportation contracts from
individually certificated transactions to Northern Border
Pipeline's blanket certificate under the FERC regulations. PAGUS
requested this conversion for increased operational flexibility
and to more fully utilize capacity release provisions. Panhandle
Eastern Pipe Line Company, the affiliate of PanEnergy that has
provided a guaranty, filed a motion to intervene and protest
requesting the FERC to convene a technical conference to determine
the effect of the conversion on its obligations and the appropriate
credit support for the contract covering 150 MMCFD. This matter is
pending before the FERC.

Order 636 has created a secondary market in existing
Northern Border Pipeline capacity. There have been temporary
releases of capacity where the releasing party (which is not
relieved of its obligations under its contract) receives credit
against its firm transportation contract for revenues received as
a result of the temporary release. In addition to the temporary
releases, several shippers have permanently released a portion of
their capacity to new shippers who have agreed to comply with the
underlying contractual and regulatory obligations associated with
such capacity. The following table identifies, as of December
31, 1996, Northern Border Pipeline's firm transportation shippers
(other than those under temporary releases), the contracted
volumes and the current termination dates:

FIRM TRANSPORTATION SHIPPERS

SHIPPER MCFD(1) TERMINATION DATE

Producer/Marketer

Amerada Hess Corporation 40,000 10/31/12
AEC West Ltd 15,073 10/31/04
Enron Capital & Trade
Resources Corp. 20,090 10/31/07
Husky Gas Marketing, Inc. 80,000 10/31/10
Mobil Natural Gas, Inc. 30,000 10/31/07
North Canadian Resources Inc. 30,000 10/31/03
Numac Energy (U.S.) Inc. 20,000 10/31/03
9,910 10/31/07
Pan-Alberta Gas (U.S.) Inc. 800,000 10/31/01
Pan Canadian Petroleum Company 13,000 09/19/03
12,000 10/31/03
37,000 10/31/04
Poco Petroleums Ltd. 10,000 10/31/01
5,000 10/31/04
ProGas U.S.A., Inc. 50,000 10/31/01
1,960 09/19/03
Renaissance Energy (U.S.) Inc. 9,942 09/19/03
27,927 10/31/04
12,000 10/31/09
20,000 10/31/10
Salmon Resources Ltd. 30,000 10/31/06
Suncor, Inc. 38,000 10/31/03
15,000 10/31/04
TransCanada Gas Services Inc.,
agent for TransCanada
PipeLines Limited 120,000 10/31/05
Wascana Energy Marketing
(U.S.) Inc. 25,000 10/31/04
Westcoast Gas Services Inc. 27,024 09/19/03
10,000 10/31/01

Total Producers/Marketers 1,508,926

Interstate Pipeline
ANR Pipeline Company 34,375 07/31/09(2)
1,789 09/19/03
Natural Gas Pipeline Company
of America 27,500 12/31/08(2)
5,000 10/31/01
Tennessee Gas Pipeline Company 47,000 12/31/08(2)
Transcontinental Gas Pipe Line
Corporation 34,375 12/31/08(2)

Total Interstate Pipelines 150,039

Local Distribution Company

City of Duluth 1,209 09/19/03
Interstate Power Company 1,072 09/19/03
Metropolitan Utilities District 3,712 09/19/03
MidAmerica Energy Company 6,536 09/19/03
Minnegasco 14,928 09/19/03
Northern States Power (MN) 6,347 09/19/03
Northern States Power (WI) 1,182 09/19/03
UtiliCorp United Inc. 7,926 09/19/03
Wisconsin Gas Company 2,431 09/19/03
Wisconsin Power & Light 942 09/19/03

Total Local Distribution
Companies 46,285

Total 1,705,250(3)
_______________

(1) Based on total maximum receipt quantity committed per shipper
expressed as thousand cubic feet per day ("MCFD").
(2) These contracts may be terminated by shippers if the
production of syngas is abandoned by Dakota Gasification
Company under its gas purchase agreements with these shippers.
(3) Total pipeline maximum receipt quantity, based on a summer
design capacity, is 1,675,250 MCFD. The total of 1,705,250
MCFD includes inline transfers of 30,000 MCFD.

Demand For Transportation Capacity

In 1996, approximately 87% of the natural gas
transported by the Pipeline System was produced in the
Western Canadian Sedimentary Basin located in the provinces
of Alberta, British Columbia and Saskatchewan. The Pipeline
System's share of Canadian gas exported to the United States
was approximately 20% in 1995.

With the existing interconnecting pipeline facilities,
Northern Border Pipeline's transportation of natural gas
produced in Canada primarily reaches gas consuming markets
located in the upper Midwestern portion of the United
States. There are two other interstate pipelines that
transport Canadian gas into the upper Midwest, Great Lakes
Gas Transmission and Viking Gas Transmission, whose combined
share of Canadian gas exported to the United States was
approximately 14% in 1995.

To meet the increasing needs of its shippers, the
Pipeline System was upgraded, expanded and extended in 1991
and 1992 (See "The Pipeline System"). These capital
improvements increased its capacity from 1,212 MMCFD to
1,675 MMCFD. Since these expansions, Northern Border
Pipeline's capacity utilization has increased from an
average of 95% of summer design capacity during 1993 to an
average of 103% in 1996.

Northern Border Pipeline is currently pursuing
opportunities to further increase its capacity. On October
13, 1995, Northern Border Pipeline filed with FERC its
application, which amended the application previously filed
on February 2, 1995, seeking a certificate of public
convenience and necessity to extend and expand its existing
system by installing approximately (a) 224 miles of 36-inch
pipeline from Northern Border Pipeline's current terminus
near Harper, Iowa, to a point near Manhattan, Illinois
(Chicago area); (b) 19 miles of 30-inch pipeline from the
end of the proposed 36-inch pipeline extension to two points
of interconnection with the facilities of the Peoples Gas
Light and Coke Company (Chicago area); (c) 35 miles of 42-
inch and 147 miles of 36-inch pipeline loop; (d) a total of
293,000 horsepower of compression at twelve compressor
stations; and (e) nine meter stations and one meter station
upgrade (collectively referred to as "The Chicago Project").
The estimated cost of the facilities proposed to be
constructed was approximately $800 million in 1995 dollars.
New receipts into the Pipeline System are proposed to be 700
MMCFD with 648 MMCFD proposed to be transported through the
pipeline extension and 516 MMCFD proposed to be delivered at
Harper, Iowa for transport by NGPL on its pipeline. The
application sought FERC authorization for a projected in-
service date of the facilities in the spring of 1998.
Northern Border Pipeline's filing included executed
precedent agreements with twenty-one shippers for the
proposed capacity and support for "rolled-in" ratemaking
treatment which involves the determination that the rates
and charges are based on all the facilities' costs combined
with the existing facilities, and the proposed and
contracted capacity.

NGPL filed on October 18, 1995 a companion application
with the FERC requesting authority to construct and operate
certain facilities needed to increase its pipeline system
capacity to accommodate the new deliveries at Harper, Iowa
from Northern Border Pipeline.

On August 1, 1996, the FERC issued orders which
contained preliminary determinations favorable to Northern
Border Pipeline and NGPL. The preliminary determinations
found that The Chicago Project and NGPL's proposed
facilities are required by the public convenience and
necessity and Northern Border Pipeline's order authorizes
the requested "rolled-in" ratemaking determination. The
preliminary determinations contemplate issuance of a final
order by the FERC, subject to completion of the
environmental review. There are pending rehearing requests
of Northern Border Pipeline's order filed by three
intervenors which claim that the FERC should not have
authorized the construction of the Harper, Iowa to
Manhattan, Illinois extension based upon rolling in those
costs with the other facility costs. On September 4, 1996,
Northern Border Pipeline filed an amendment to its
application to reflect limited facility modifications which
among other things, reduced environmental impacts and
project costs. The Chicago Project facilities proposed to
be constructed are the same facilities previously described
except for the elimination of the 35 miles of 42-inch
pipeline loop and for the change in total compression to
303,500 horsepower. Compression facilities involve the
installation of 228,500 horsepower at eight new stations and
upgrades at five existing stations by the removal from
service of units producing 100,000 horsepower with
replacements of units producing 175,000 horsepower. With
this amendment, The Chicago Project costs are expected to be
approximately $793 million in 1995 dollars ($837 million as
estimated with projected inflation), and subject to timely
regulatory approvals, The Chicago Project is expected to be
ready for service in November 1998.

On December 26, 1996, the FERC issued a Notice of
Availability of the Draft Environmental Impact Statement
("DEIS") for The Chicago Project and related downstream
facilities to be constructed by NGPL to accept and transport
deliveries of gas into its pipeline at Harper, Iowa. The
DEIS found that The Chicago Project and related downstream
facilities of NGPL would have limited adverse environmental
impact and with the adoption of certain mitigative measures,
would be an environmentally acceptable action. The DEIS also
sought additional comments on its analysis of potential
system alternatives. The FERC environmental staff stated
that a single pipeline from the Harper, Iowa to Chicago,
Illinois area would be environmentally preferred but also
recognized that there are a number of other factors to be
considered. Comments on the DEIS were received through
public meetings held in early February, 1997, in Illinois
and Iowa and written comments filed by February 18, 1997.
Northern Border Pipeline filed comments stating that a
single system alternative was not feasible because of the
operational, economic and competitive underpinnings of the
shippers' contractual commitments to The Chicago Project and
any such alternative would cause unacceptable delay.
Several shippers also filed comments supporting The Chicago
Project. NGPL filed comments alleging that, with
modifications it is proposing, the single system alternative
of expanding NGPL's facilities would be environmentally preferred.
NGPL also filed an application for a certificate of public
convenience and necessity on March 19, 1997 proposing to
construct additional facilities to transport 663 MMCFD east
of Harper, Iowa into the Chicago area and proposing that
Northern Border Pipeline enter into a transportation
contract to serve its proposed shippers and also those that
contracted with NGPL. In response to NGPL's filings, Northern
Border Pipeline filed comments opposing NGPL's proposal and
supporting the approval of the previous finding that
construction and operation of The Chicago Project and NGPL's
related downstream facilities as originally proposed is an
environmentally acceptable action with certain mitigation
measures. Based upon the comments received, a final
Environmental Impact Statement will be issued whereupon FERC
will be in a position to issue its final certificate resolving
these issues.

Environmental and Safety Matters

The operations of Northern Border Pipeline 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, Natural Gas Pipeline Safety Act of 1969, as
amended, and the Pipeline Safety Act of 1992. Northern
Border Pipeline has ongoing environmental and safety audit
programs. Northern Border Pipeline believes that its
operations and facilities are in general compliance with
applicable environmental regulations.

FERC Regulation

General

Northern Border Pipeline is subject to extensive
regulation by the FERC as a "natural gas company" under the
Natural Gas Act (the "NGA"). Under the NGA and the Natural
Gas Policy Act ("NGPA"), the FERC has jurisdiction over
Northern Border Pipeline with respect to virtually all
aspects of its business, including transportation of 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, the initiation
and discontinuation of services, and certain other matters.
Northern Border Pipeline, where required, holds certificates
of public convenience and necessity issued by the FERC
covering its facilities, activities and services.

Northern Border Pipeline's rates and charges for
transportation in interstate commerce are subject to
regulation by the FERC. FERC regulations and Northern
Border Pipeline's tariff (approved by the FERC) have allowed
it to recover operations and maintenance costs of the
Pipeline System, taxes other than income taxes, interest,
depreciation and amortization, an allowance for income taxes
and a regulated equity return. Rates charged by natural gas
companies may not exceed the just and reasonable rates
approved by the FERC. In addition, natural gas companies
are prohibited from unduly preferring or unreasonably
discriminating against any person with respect to pipeline
rates or terms and conditions of service. Certain types of
rates may be discounted without further FERC authorization.

Under Section 8 of the NGA, the FERC has the power to
prescribe the accounting treatment for items for regulatory
purposes. The Northern Border Pipeline books and records
are periodically audited pursuant to Section 8. In May
1996, the FERC Staff issued its final audit report on its
examination of Northern Border Pipeline's books and records
for the period from January 1, 1990 to December 31, 1992.
The report required Northern Border Pipeline to record
certain adjustments to its accounts including the
reclassification of $3.9 million of costs from utility plant
in service to a regulatory asset. While this regulatory
asset is includable in rate base, Northern Border Pipeline
must file with the FERC for the future recovery of this
asset through amortization in cost of service. The General
Partners indemnified the Partnership with respect to any
negative impact on distributions received from Northern
Border Pipeline, as a result of this audit, attributable to
periods prior to October 1, 1993. The adjustments made to
Northern Border Pipeline's accounts and the indemnification
received as a result of this audit did not materially affect
the Partnership's financial position or results of
operations.

In December 1991, the FERC staff issued its audit
report on its examination of Northern Border Pipeline's
books and records for the period January 1, 1987 through
December 31, 1989. The report took exception to Northern
Border Pipeline's established method of accounting for
Alternative Minimum Tax ("AMT") for purposes of calculating
rates and charges subject to FERC approval. Northern Border
Pipeline's tariff specifies that Northern Border Pipeline
calculate the income tax component of its cost of service as
if Northern Border Pipeline were a corporation, which
Northern Border Pipeline has done since inception.
Consequently, the particular income tax circumstances of
each Northern Border Pipeline partner have not been utilized
to calculate the cost of service. However, the FERC staff
asserted that the AMT component of Northern Border
Pipeline's rate base should reflect the particular tax
circumstances of each individual partner. Northern Border
Pipeline did not agree with the position taken by the FERC
staff regarding AMT, and a hearing was conducted before an
Administrative Law Judge (the "ALJ") on this issue at which
Northern Border Pipeline argued that such a result would be
contrary to FERC policy and precedent, as well as Northern
Border Pipeline's tariff. A decision from the ALJ was
received on April 15, 1993, which affirmed Northern Border
Pipeline's accounting treatment for AMT. On May 17, 1994,
the FERC issued its order reversing that part of the ALJ's
decision which held that the AMT component of Northern
Border Pipeline's rate base need not reflect the particular
tax circumstances of each Northern Border Pipeline partner.
Northern Border Pipeline filed a request for rehearing of
the May 17, 1994 order. On May 20, 1996, FERC granted
rehearing of this order, accepted the ALJ's conclusions and
vacated the findings in the May 17, 1994 order. As a
result, there were no accounting adjustments or rate refunds
required.

Firm transportation shippers, ANR Pipeline, NGPL,
Tennessee Gas Pipeline Company and Transco, purchase the
production of syngas from the plant now owned by Dakota
Gasification Company. These shippers may terminate their
firm transportation contracts covering contracted volumes of
143,250 MCFD if the production of syngas is abandoned by
Dakota Gasification Company under its gas purchase
agreements with these shippers. Settlements of disputes
between the plant owner and the pipelines were reached in
1993 which modified, inter alia, pricing, volume and term
provisions of the pre-existing syngas purchase agreements.
In a FERC proceeding, approval of these settlements was
sought. NGPL reached an uncontested agreement with its
customers regarding its settlement which was approved by the
FERC on January 23, 1995. On December 29, 1995, an ALJ
issued an initial decision on the three remaining
settlements which found, among other things, that the
pricing formula proposed under the settlements should be
modified and that the customers should only be responsible
for costs associated with 137,500 MCFD. In its brief on
exceptions to the initial decision, Dakota Gasification
Company argued that the price and volume changes ordered by
the ALJ could threaten the survival of the plant. The three
affected pipelines and the Department of Energy also filed
briefs excepting to the initial decision. The FERC issued
on December 18, 1996, its order which reversed the ALJ's
initial decision. The FERC found the settlements to be just
and reasonable and did not limit the volume to 137,500 MCFD.
Therefore, the resolution of the disputes are final with no
adverse impact to Northern Border Pipeline.

Cost of Service Tariff

Northern Border Pipeline's firm transportation shippers
contract to pay for an allocable share of the Pipeline
System's capacity. During any given month, all such
shippers pay a uniform charge per dekatherm-mile of capacity
contracted, calculated under a cost of service tariff. The
shippers' obligations to pay their allocable share of the
cost of service is not dependent upon the volumes actually
shipped. That is, the cost of service payment obligation is
a function of the shippers' contracted capacity. This
tariff is regulated by the FERC and provides an opportunity
to recover all operations and maintenance costs of the
Pipeline System, taxes other than income taxes, interest,
depreciation and amortization, an allowance for income taxes
and a regulated equity return. Northern Border Pipeline may
not charge or collect more than its cost of service pursuant
to its tariff on file with the FERC.

Northern Border Pipeline bills the cost of service on
an estimated basis for a six month cycle. Any net excess or
deficiency resulting from the comparison of the cost of
service determined for that period in accordance with the
FERC tariff to the estimated billing is accumulated,
including carrying charges thereon, and is either billed to
or credited back to the shippers.

Northern Border Pipeline also provides interruptible
transportation service. The maximum rate charged to
interruptible shippers is calculated from the cost of
service estimate on the basis of contracted capacity.
Except for any period when the risk conditions described in
the next paragraph are applicable, all revenue from the
interruptible transportation service is credited back to the
firm shippers' accounts.

Northern Border Pipeline is at risk for the recovery of
the annual cost of service associated with the capacity from
both the 1991 and the 1992 expansion projects (See "The
Pipeline System"). In the event that a portion of that
capacity were to become uncontracted, or the government
authorizations to export or import natural gas from Canada
were to lapse, FERC has stated that Northern Border Pipeline
would not be allowed to recover from the remaining firm
shippers on the system that portion of its cost of service
related to those facilities and the uncontracted capacity
associated with these projects.

The cost of service has been levelized due primarily to
annual depreciation changes. This means that the annual
cost of service, since the effective date of Northern Border
Pipeline's 1992 rate case, is designed to be generally level
until January 1, 1997 when a higher levelized cost of
service was to be effective through 2001. In the 1992 rate
case, Northern Border Pipeline committed to make a filing no
later than January 1, 1997 to adjust the depreciation rate
to reflect the circumstances existing on the Pipeline System
at that time. An integral component of The Chicago Project
is a proposed change in the depreciation schedule which, if
implemented, would extend the Pipeline System's depreciable
life for ratemaking purposes. FERC authority to implement a
new depreciation schedule, both prior to and after the
targeted in-service date of The Chicago Project, has been
requested in Northern Border Pipeline's November 1995 rate
case proceeding discussed below.

In November 1995, Northern Border Pipeline filed a rate
case in compliance with its FERC tariff for the
determination of its allowed equity rate of return. In this
proceeding, Northern Border Pipeline proposed, among other
items, to increase its allowed equity rate of return from
12.75% to 14.25%. Pursuant to a December 1995 FERC order,
Northern Border Pipeline began collecting the proposed
increase in rate of return on equity effective June 1, 1996,
subject to refund. After reaching a settlement accord with
a majority of its shippers, on October 15, 1996, Northern
Border Pipeline filed for FERC approval of a Stipulation and
Agreement ("Stipulation") to settle its rate case. The
Stipulation would allow Northern Border Pipeline a 12.75%
equity rate of return from June 1, 1996 to September 30,
1996, and a 12% rate beginning October 1, 1996. In
addition, the depreciation rates applied to Northern Border
Pipeline's gross transmission plant would be reduced
effective June 1, 1996, from 3.6% to 2.7% thereby fulfilling
the requirement in Northern Border Pipeline's 1992 rate
case.

Another issue addressed in the Stipulation was the
allowance for income taxes. The FERC had previously ruled
in a case involving Lakehead Pipe Line Company L.P. that an
income tax allowance would not be allowed with respect to
income attributable to the limited partnership interests
held by individuals. During the rate case proceeding,
Northern Border Pipeline filed testimony regarding what it
believed to be the proper application of this FERC ruling to
its circumstances. The Partnership believes the
Stipulation, if approved, effectively resolves the income
tax issue for the Shippers at least through 2005 and
Northern Border Pipeline can continue to include an
allowance for income taxes at the current level in its cost
of service. Under the Stipulation, in connection with the
completion of The Chicago Project, Northern Border Pipeline
would implement a new depreciation schedule with an extended
depreciable life, a capital project cost containment
mechanism and a $31 million settlement adjustment mechanism.
The capital project cost containment mechanism would
allocate variances in actual construction costs between
Northern Border Pipeline and its Shippers through
adjustments to rate base. The settlement adjustment
mechanism would effectively reduce the allowed return on
rate base. One participant, NGPL, who as a firm shipper is
responsible for 1.6% of the annual cost of service cost has
filed comments alleging that the Stipulation is contrary to
FERC policy. On November 19, 1996, the Stipulation was
certified by an ALJ to the FERC for review and approval.
Northern Border Pipeline must receive FERC approval of the
Stipulation before it can implement all of the filed for
terms and any associated refunds. The Partnership is unable
to predict if or when the Stipulation will be approved as
filed and thus the effect of this rate proceeding on future
operating results of Northern Border Pipeline cannot be
determined at this time.

Open Access Regulation

The FERC issued Order No. 636 on April 8, 1992, Order
No. 636-A, an order on rehearing of Order 636, on August 3,
1992, and a further order on rehearing, Order No. 636-B, on
November 27, 1992 (together, "Order 636"). Among other
things, Order 636 required companies to unbundle their
services and offer sales, transportation, storage, gathering
and other services separately; to permanently assign their
firm capacity on upstream pipelines to firm shippers wanting
such capacity; and to provide all transportation services on
a basis that is equal in quality for all shippers. Order
636 was substantially affirmed by the United States Court of
Appeals for the District of Columbia.

With respect to the limited aspects of Order 636 that
the court remanded to the FERC, only one issue, the "right
of first refusal" ("ROFR") procedures (imposed by FERC as a
condition to the pipeline's right to abandon long-term
transportation service), is relevant to Northern Border
Pipeline operations. The ROFR procedures required existing
shippers to match any bid of up to twenty years in order to
retain their capacity. The court upheld the basic structure
of FERC's rules, but remanded the ROFR mechanism for further
explanation of why a twenty-year term-matching cap was
adopted. The FERC, on remand, adopted a five-year matching
cap. The effect of this ruling on Northern Border
Pipeline's ability to renew or recontract firm capacity
under long-term service agreements once existing agreements
expire cannot be quantified at this time.

On July 17, 1996, the FERC issued Order No. 587
amending its open access regulations to standardize certain
business practices and procedures governing transactions
between interstate natural gas pipelines, their customers,
and others doing business with the pipelines. These initial
business standards, developed by the Gas Industry Standards
Board, govern important business practices such as shipper
supplied service nominations, allocation of available
capacity, accounting and invoicing of transportation
service, and capacity release. Northern Border Pipeline is
in the process of implementing changes to its tariff and
internal systems so it can fully comply with the initial
business standards by April 1, 1997, as required by Order
No. 587.

Item 2. Properties

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

Approximately 90 miles of the pipeline is located on
fee, allotted and tribal lands within the exterior
boundaries of the Fort Peck Indian Reservation in Montana.
Tribal lands are lands owned in trust by the United States
for the tribes and allotted lands are lands owned in trust
by the United States for an individual Indian or Indians.
In 1980, Northern Border Pipeline entered into a pipeline
right-of-way lease with the Fort Peck Tribal Executive
Board, for and on behalf of the Assiniboine and Sioux Tribes
of the Fort Peck Indian Reservation. This pipeline right-of-
way lease, which was approved by the Department of the
Interior in 1981, granted to Northern Border Pipeline the
right and privilege to construct and operate its pipeline on
certain tribal lands, for a term of 15 years, renewable for
an additional 15 year term at the option of Northern Border
Pipeline without additional rental. Northern Border
Pipeline notified the Bureau of Indian Affairs ("BIA") in
March 1996 that it was exercising its option to renew the
pipeline right-of-way lease for an additional 15 year term.
Northern Border Pipeline continues to operate on this
portion of the pipeline located on tribal lands in
accordance with its renewal rights. Northern Border
Pipeline has been preliminarily advised by the attorneys
retained by the Fort Peck Tribes that Northern Border
Pipeline may not have valid pipeline rights on tribal lands.
Northern Border Pipeline has been supplied with a letter
explaining this conclusion, but Northern Border Pipeline's
initial analysis of the explanation does not appear to
support this conclusion. However, the Partnership is unable
to predict at this time the outcome of this issue.

In conjunction with obtaining a pipeline right-of-way
lease across tribal lands located within the exterior
boundaries of the Fort Peck Indian Reservation, Northern
Border Pipeline also obtained a right-of-way across allotted
lands located within the reservation boundaries. This right-
of-way, granted by the BIA on March 25, 1981, for and on
behalf of individual Indian owners, expired on March 31,
1996. Before the termination date, Northern Border Pipeline
undertook efforts to obtain voluntary consents from
individual Indian owners for a new right-of-way, and
Northern Border Pipeline filed applications with the BIA for
new rights-of-way across those tracts of allotted lands
where a sufficient number of consents from the owners had
been obtained. Also, a condemnation action was filed in
Federal Court concerning those remaining tracts of allotted
land for which a majority of consents were not received. An
order in this proceeding was issued by the Federal Court
granting Northern Border Pipeline continued access and
possession during the pendency of the condemnation action of
the right-of-way on the tracts in question.

Item 3. Litigation

In addition to the condemnation action (See "Item 2.
Properties") and matters related to the FERC regulation, various
legal actions which have arisen in the ordinary course of
business are pending with respect to Northern Border Pipeline.

The Partnership is not currently a party to any legal
proceedings, of which, individually or in the aggregate, would
reasonably be expected to have a material adverse impact on the
Partnership's 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 1996.

PART II

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

The following table sets forth, for the periods indicated,
the high and low sale prices per Common Unit, as reported on the
New York Stock Exchange Composite Tape, and the amount of cash
distributions paid per Common Unit:

Price Range Cash
High Low Distributions

1996
First Quarter $25.875 $23.500 $0.55
Second Quarter 24.875 22.875 0.55
Third Quarter 26.125 23.875 0.55
Fourth Quarter 27.375 25.500 0.55

1995
First Quarter $24.125 $20.875 $0.55
Second Quarter 25.625 21.875 0.55
Third Quarter 25.500 24.000 0.55
Fourth Quarter 25.250 23.250 0.55

As of January 31, 1997, there were approximately 1,900
record holders of the Partnership's Common Units. There is no
established public trading market for the Partnership's
Subordinated Units held by the General Partners. Cash
distributions of $0.55 per Unit have been paid on all Common and
Subordinated Units for all quarters since inception of the
Partnership. The Partnership distributes 100% of its Available
Cash (defined below) within 45 days after the end of each quarter
to Unitholders of record and the General Partners. During a
specified period that will not end earlier than December 31, 1998
(the "Subordination Period"), distributions of Available Cash on
Subordinated Units are subordinated to the rights of the holders
of the Common Units to receive $0.55 per Common Unit per quarter.
"Available Cash" consists generally of all of the cash receipts
of the Partnership adjusted for its cash disbursements and net
changes to reserves. A full definition of Available Cash and the
Subordination Period is set forth in the Partnership Agreement, a
form of which is filed as an Exhibit hereto.

Item 6. Selected Financial Data (Unaudited)
(in thousands, except per Unit and operating data)

On October 1, 1993, the Partnership acquired a 70% general partner
interest in Northern Border Pipeline. Prior to October 1, 1993, the
Partnership had no financial statements. The following selected
financial data labeled "Historical (Predecessor)" represent the income
data, cash flow data, balance sheet data and operating data of Northern
Border Pipeline, the Partnership's predecessor company as defined under
the regulations of the Securities and Exchange Commission ("SEC").

Partnership Historical (Predecessor)
Pro Forma Three Nine
Year Months Months Year
Ended Ended Ended Ended
Year Ended December 31, December 31, December 31, September 30, December 31,
1996 1995 1994 1993 1993 1993 1992

INCOME DATA:
Operating revenue $ 201,943 $ 206,497 $ 211,580 $205,241 $ 53,148 $ 152,093 $ 166,928
Operations and
maintenance 28,366 26,730 28,919 27,210 7,424 18,661 22,052
Depreciation and
amortization 46,979 47,081 41,959 39,539 10,489 29,050 27,287
Taxes other than
income 24,390 23,886 24,438 21,393 5,582 15,811 20,788
Operating income 102,208 108,800 116,264 117,099 29,653 88,571 96,801
Interest expense 33,117 35,205 38,424 40,671 10,054 30,617 33,187
Other income (expense) 3,347 568 (1,340) (784) (1,209) 425 5,835
Minority interests in
net income 22,153 22,360 23,147 22,622 5,108 -- --
Net income to partners $ 50,285 $ 51,803 $ 53,353 $ 53,022 $ 13,282 $ 58,379 $ 69,449

Net income per Unit $ 1.88 $ 1.94 $ 2.00 $ 1.98 $ .50 -- --

CASH FLOW DATA:
Net cash provided by
operating activities $ 137,534 $ 127,078 $ 121,088 $116,530 $ 35,184 $ 82,471 $ 86,132
Capital expenditures 18,597 8,411 2,985 1,268 528 739 135,990

BALANCE SHEET DATA
(AT END OF PERIOD):
Net property, plant
and equipment $ 937,859 $ 957,587 $ 983,842 $ -- $1,015,567 $1,023,725 $1,049,023
Total assets 1,016,484 1,041,339 1,083,468 -- 1,115,768 1,096,099 1,129,200
Long-term debt,
including current
maturities 377,500 410,000 445,000 -- 470,000 470,000 492,500
Minority interests in
partners' capital 158,089 166,789 173,984 -- 177,089 -- --
Partners' capital 410,586 419,117 426,130 -- 431,593 597,587 604,927

OPERATING DATA:
MMCF of gas delivered 633,908 615,133 597,898 570,469 142,040 428,429 515,215
Average throughput (MMCFD) 1,764 1,720 1,663 1,592 1,581 1,596 1,418

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

Results of Operations

Year Ended December 31, 1996 Compared With the Year Ended
December 31, 1995

Operating revenue decreased $4.6 million (2%) for the year
ended December 31, 1996, as compared to the results for the
comparable period in 1995, due primarily to equity returns on a
lower rate base and lower interest expense. These lower
recoveries were partially offset by higher operations and
maintenance expense recoveries. Northern Border Pipeline is
generally allowed to collect from its shippers a return on
unrecovered rate base as well as recover that rate base through
depreciation and amortization. The return amount Northern Border
Pipeline may collect from its shippers declines as the rate base
is recovered. Operating revenue for 1996 reflect the terms of
the Stipulation filed by Northern Border Pipeline for FERC
approval to settle its rate case (See "Business-FERC
Regulation").

Operations and maintenance expense increased $1.6 million (6%)
for the year ended December 31, 1996, from the comparable period
in 1995 due primarily to expenses incurred in conjunction with
Northern Border Pipeline's rate case proceeding as well as higher
administrative expenses.

Depreciation and amortization expense remained constant for
the year ended December 31, 1996, as compared to the results for
the same period in 1995. Depreciation and amortization expense
for 1996 is reduced approximately $7.4 million from the level
authorized in Northern Border Pipeline's FERC tariff to reflect
the Stipulation discussed above, which results in an average
depreciation rate for transmission plant of 3.1% for the year
ended December 31, 1996 and matches the rate used in 1995. In
accordance with the terms of the Stipulation, the depreciation
rate applied to Northern Border Pipeline's gross transmission
plant is reduced to 2.7% effective June 1996 from the 3.6% rate
in its FERC tariff.

Interest expense decreased $2.1 million (6%) for the year
ended December 31, 1996, as compared to the results for the same
period in 1995 due to a decrease in the average debt outstanding.
Average debt outstanding has decreased between the two periods
reflecting principal payments of $32.5 million made under the
Northern Border Pipeline bank loan agreement.

Other income (expense) increased $2.8 million for the year
ended December 31, 1996, from results for the year ended December
31, 1995, primarily due to the reversal of previously established
reserves for regulatory issues (See "Business-FERC Regulation").

Year Ended December 31, 1995 Compared With the Year Ended
December 31, 1994

Operating revenue decreased $5.1 million (2%) for the year
ended December 31, 1995, as compared to the results for the
comparable period in 1994, due primarily to equity returns on a
lower rate base, lower operations and maintenance expense and
lower interest expense. These lower recoveries were partially
offset by higher depreciation and amortization expense
recoveries.

Operations and maintenance expense decreased $2.2 million (8%)
for the year ended December 31, 1995, from the comparable period
in 1994 due to lower administrative expenses for Northern Border
Pipeline.

Depreciation and amortization expense increased $5.1 million
(12%) for the year ended December 31, 1995, as compared to the
results for the same period in 1994. The increase is due to an
increase in the depreciation rate applied to Northern Border
Pipeline's gross transmission plant from 2.8% for the year ended
December 31, 1994 to 3.1% in 1995 as authorized in its FERC
tariff.

Interest expense decreased $3.2 million (8%) for the year
ended December 31, 1995, as compared to the results for the same
period in 1994 due to a decrease in the average debt outstanding
and a decrease in the average interest rate from 8.5% to 8.3%.
Average debt outstanding decreased approximately $31 million
between the two periods reflecting principal payments made under
the Northern Border Pipeline bank loan agreement.

Other income (expense) increased $1.9 million for the year
ended December 31, 1995, from results for the year ended
December 31, 1994, primarily due to a $1.5 million increase in
other income and a $0.7 million increase in interest income
offset by a $0.3 million increase in other expenses. The
increase in other income between 1994 and 1995 primarily reflects
miscellaneous plant acquisition adjustments.

Liquidity and Capital Resources

General

Short-term liquidity needs of the Partnership will be met by
internal sources. In addition, the Partnership has the ability
to establish lines of credit with one or more financial
institutions. Long-term capital needs can be met by the
Partnership's ability to issue additional limited partner
interests in the Partnership.

On October 4, 1996, Northern Border Pipeline entered into a
one-year $50 million revolving credit agreement with a financial
institution. Borrowings under the credit agreement are expected
to be used by Northern Border Pipeline to fund working capital,
construction and other general business purposes.

Cash Flows From Operating Activities

Cash flow from operations increased $10.5 million to $137.5
million for the year ended December 31, 1996 as compared to the
same period in 1995, due primarily to amounts collected subject
to refund by Northern Border Pipeline as a result of its current
rate case (See "Business-FERC Regulation"). Cash flow from
operations increased $6.0 million to $127.1 million for the year
ended December 31, 1995 as compared to the same period in 1994
due primarily to an increase in Northern Border Pipeline's
depreciation and amortization expense which is collected from its
shippers.

Cash Flows From Investing Activities

Net plant additions of $18.6 million for the year ended
December 31, 1996, include $11.8 million for The Chicago Project
(See "Business-Demand for Transportation Capacity"). The
remaining $6.8 million of net plant additions for 1996 are
primarily related to renewals and replacements of the existing
facilities. For the comparable period in 1995, net plant
additions were $8.4 million which included $4.5 million for The
Chicago Project and $3.9 million primarily related to renewals
and replacements of the existing facilities.

Total capital expenditures for 1997 are estimated to be $210
million for The Chicago Project. The Chicago Project is
expected to be ready for service in November 1998, subject to
timely regulatory approvals, and is estimated to cost $837
million, using certain construction cost escalation assumptions.
An additional $14 million of 1997 capital expenditures is
planned for renewals and replacements for the existing
facilities. Funds required to meet the 1997 capital
expenditures are anticipated to be provided from debt
borrowings, internal sources and equity contributions from
minority interest holders.

Cash Flows From Financing Activities

Cash used in financing activities of $112.2 million for the
year ended December 31, 1996, reflects distributions made to
partners and minority interests of $58.8 million and $30.9
million, respectively, and $22.5 million in net principal
reductions under the Northern Border Pipeline bank loan and
credit agreements. For the comparable period in 1995, cash used
in financing activities totaled $123.4 million and reflected
distributions made to partners and minority interests of $58.8
million and $29.6 million, respectively, and $35.0 million in
principal payments under the Northern Border Pipeline bank loan
agreement.

Information Regarding Forward Looking Statements

Within the Partnership's interpretation of the Private
Securities Litigation Reform Act of 1995, statements in this
Annual Report that are not historical information are forward
looking statements within the meaning of Section 27A of the
Securities Act of 1933 and Section 21E of the Securities Exchange
Act of 1934. Such forward looking statements include the
discussions under "Business-Demand for Transportation Capacity"
and elsewhere regarding Northern Border Pipeline's efforts to
pursue opportunities to further increase its capacity, the
discussion under "Business-FERC Regulation" regarding pending and
future proceedings before FERC and related matters and the
discussion in "Management's Discussion and Analysis of Financial
Condition and Results of Operations-Liquidity and Capital
Resources." Although the Partnership believes that its
expectations regarding future events are based on reasonable
assumptions within the bounds of its knowledge of its business,
it can give no assurance that its goals will be achieved or that
its expectations regarding future developments will be realized.
Important factors that could cause actual results to differ
materially from those in the forward looking statements herein
include political and regulatory developments that impact FERC
and state utility commission proceedings, Northern Border
Pipeline's success in sustaining its positions in such
proceedings or the success of intervenors in opposing Northern
Border Pipeline's positions, developments relating to the renewal
of the pipeline right-of-way lease with the Fort Peck Indian
Reservation and the condemnation proceedings involving allotted
lands of the reservation, competitive developments by Canadian
and U.S. natural gas transmission peers, political and regulatory
developments in Canada and conditions of the capital markets and
equity markets during the periods covered by the forward looking
statements.

Item 8. Financial Statements

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

Item 9. Disagreements on Accounting and Financial Disclosure

None.

PART III

Item 10. Partnership Management

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

As is commonly the case with publicly-traded partnerships,
the Partnership does not directly employ any of the persons
responsible for managing or operating the Partnership or for
providing it with services relating to its day-to-day business
affairs. The Partnership has entered into an agreement (the
"Administrative Services Agreement") with NBP Services
Corporation ("NBP Services"), a wholly-owned subsidiary of Enron,
pursuant to which NBP Services provides tax, accounting, legal,
cash management, investor relations and other services for the
Partnership. NBP Services utilizes the employees of Enron or its
affiliates who have duties and responsibilities other than those
relating to the Administrative Services Agreement. In
consideration for its services under the Administrative Services
Agreement, NBP Services is reimbursed for its direct and indirect
costs and expenses, including an allocated portion of employee
time and Enron's overhead costs.

Set forth below is certain information concerning the
members of the Partnership Policy Committee, the Partnership's
representatives on the Northern Border Management Committee and
the persons designated by the Partnership Policy Committee as
executive officers of the Partnership and as Audit Committee
members. All members of the Partnership Policy Committee and the
Partnership's representatives on the Northern Border Management
Committee serve at the discretion of the General Partner that
appointed them, and the persons designated as executive officers
serve in that capacity at the discretion of the Partnership
Policy Committee. The members of the Partnership Policy
Committee receive no management fee or other remuneration for
serving on this Committee. The Audit Committee members are
elected, and may be removed, by the Partnership Policy Committee.
Each Audit Committee member receives an annual fee of $15,000 and
is paid $1,000 for each meeting attended.

Name Age Positions

Executive Officers:
Larry L. DeRoin 55 Chief Executive Officer
Jerry L. Peters 39 Chief Financial and Accounting Officer

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

Larry L. DeRoin 55 Chairman of Partnership
(Northern Plains) Policy Committee and
Northern Border Management Committee
George L. Mazanec 61 Member of Partnership Policy
(Pan Border) Committee and Northern
Border Management Committee
Brian E. O'Neill 61 Member of Partnership Policy
(Northwest Border) Committee and Northern
Border Management Committee

Members of Audit
Committee:
Daniel P. Whitty 65 Chairman of Audit Committee
Gerald B. Smith 46 Member of Audit Committee

Larry L. DeRoin was named Chief Executive Officer of the
Partnership and Chairman of the Partnership Policy Committee in
July, 1993. Mr. DeRoin is the President of Northern Plains, an
Enron subsidiary, having held that position since January, 1985,
and is a director of Northern Plains. He started his career with
another Enron company, Northern Natural, in 1967 and has worked
in several management positions, including President of Peoples
Natural Gas Company, a former retail natural gas subsidiary of
Enron. Mr. DeRoin has been a member of the Northern Border
Management Committee since 1985 and has been Chairman since late
1988.

George L. Mazanec was appointed to the Partnership Policy
Committee in July, 1993. Mr. Mazanec is an Advisor to the Chief
Executive Officer of PanEnergy. From December, 1993 to December,
1996 he was the Vice Chairman of the Board of Directors of
PanEnergy and had been a director since December, 1992. He was a
director of Texas Eastern Products Pipeline Company, the general
partner of TEPPCO Partners, L.P. From March, 1991 to December,
1993, he was Executive Vice President of PanEnergy. From 1989 to
1991, he was Group Vice President of PanEnergy and from 1987 to
1989, he was Senior Vice President of Texas Eastern Corporation
and Texas Eastern Transmission Company. He is a director of
National Fuel Gas Company and Northern Trust Bank of Texas. He
has served on the Northern Border Management Committee since
1991.

Brian E. O'Neill was appointed to the Partnership Policy
Committee in July, 1993. Mr. O'Neill is President and Chief
Executive Officer of Northwest Pipeline Corporation, Williams
Western Pipeline Company, Williams Natural Gas Company, Transco
and Texas Gas Transmission Corporation. He was elected to his
position at Transco and Texas Gas Transmission Corporation in
1995. He was elected to his positions at Northwest Pipeline
Corporation and Williams Western Pipeline Company effective
January 1, 1994. He was elected President of Williams Natural
Gas Company in 1988. He is a director of Daniel Industries, Inc.
He has served on the Northern Border Management Committee since
April 1993.

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

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

Gerald B. Smith was appointed to the Audit Committee in
April, 1994. He is Chief Executive Officer and co-founder of
Smith, Graham & Co., a fixed income investment management firm,
which was founded in 1990. He is a director of Alliance Capital,
Community Partners and First Interstate Bank of Texas, N.A. From
1988 to 1990, he served as Senior Vice President and Director of
Fixed Income and Chairman of the Executive Committee of Underwood
Neuhaus & Co.

Item 11. Executive Compensation

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

Summary Compensation Table
All Other
Annual Compensation Long-Term Compensation Compensation
Other Securities
Annual Restricted Underlying LTIP
Compensation Stock Options/ Payouts
Year Salary Bonus (1) Awards (2) SARs (#) (3) (4)

Larry L. DeRoin 1996 $239,667 $144,000 $25,665 $ - 18,220 $ - $ 1,102
Chief Executive 1995 $235,000 $128,500 $19,208 $ - 14,550 $150,000 $ 793
Officer 1994 $235,000 $112,000 $29,039 $7,035 30,445 $150,000 $31,572

Jerry L. Peters 1996 $114,525 $ 20,000 $ - $ - 5,045 $ - $ 767
Chief Financial and 1995 $104,900 $ 15,000 $ - $ - 2,655 $ - $ 552
Accounting Officer 1994 $ 92,270 $ 12,500 $ - $ - 5,475 $ - $18,609

(1) No Named Officer had "Perquisites and Other Personal
Benefits" with a value greater than the lesser of $50,000 or
10% of reported salary and bonus. 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 1994 was the minimum rate of 12.0%,
for 1995 was 12.39%, and for 1996 was the minimum rate of
12.0%. Interest in excess of 120% of the December, 1995 long-
term Applicable Federal Rate ("AFR") (7.65%) has been
reported as Other Annual Compensation for 1996, interest in
excess of 120% of the December, 1994 long-term AFR (9.91%)
has been reported as Other Annual Compensation for 1995, and
interest in excess of 120% of the December, 1993 long-term
AFR (7.29%) has been reported as Other Annual Compensation
for 1994. No interest has been reported as Other Annual
Compensation under the 1992 Deferral Plan, which credits
interest at Enron's mid-term borrowing rate, since the
crediting rates for 1994, 1995 and 1996 of 6.0%, 8.5%, and
6.5% respectively, did not exceed 120% of the AFR. Under the
1994 Deferral Plan interest was credited on amounts deferred
at a fixed rate of 9% for 1994 and 1995. Interest in excess
of 120% of the December, 1993 long-term AFR (7.29%) has been
reported as Other Annual Compensation for 1994. 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 1996. Other
Annual Compensation also includes cash perquisite allowances.

(2) Restricted stock awarded to Mr. DeRoin on February 7, 1994
became 50% vested on August 7, 1994, and 50% vested on
February 7, 1995. Dividend equivalents accrued from date of
grant and were paid upon vesting. The Named Officers had no
unreleased restricted stock holdings as of December 31, 1996.

(3) The amounts shown for 1994 and 1995, for Mr. DeRoin
represent payouts made under Enron's Performance Unit Plan.

(4) The amounts shown include the value, as of year-end 1994,
1995, and 1996 of Enron Common Stock allocated during those
years to employees' savings and special subaccounts under
Enron's Employee Stock Ownership Plan ("ESOP"). Included in
1994 is a special allocation made in February, 1994 to
employees' savings subaccounts under the ESOP in lieu of a
merit increase in 1994 and a special allocation made in
December, 1994 to a special allocation subaccount. Included
in 1995 and 1996, is a special allocation made in December of
1995 and 1996, to a special allocation subaccount under the
ESOP.

Stock Option Grants During 1996

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 1996.

Individual Grants
% of Total Potential Realizable Value at
Options/ Options/SARs Exercise Assumed Annual Rates of
SARs Granted to or Base Stock Price Appreciation
Granted Employees in Price Expiration For Option Term (5)
Name (#) (1) Fiscal Year ($/Sh) Date 0% (4) 5% 10%

Larry L. DeRoin 6,590 (2) 0.09% $36.7500 01/23/01 $- $ 66,911 $ 147,855
11,630 (3) 0.16% $43.1250 12/31/01 $- $ 138,567 $ 306,197

Jerry L. Peters 3,545 (2) 0.05% $36.7500 01/23/01 $- $ 35,994 $ 79,536
1,500 (3) 0.02% $43.1250 12/31/01 $- $ 17,872 $ 39,492

All Employee and
Director Optionees 7,371,026 (6) 100% $39.7113 (7) N/A $- $ 184,085,478 (8) $ 466,509,287 (8)

All Stockholders N/A N/A N/A N/A $- $6,160,902,605 (8) $15,612,955,030 (8)

Optionee Gain as %
of All Stockholders
Gain N/A N/A N/A N/A N/A 2.99% 2.99%

1. If a "change of control" (as defined in the Enron Stock
Plans) were to occur before the options become exercisable and
are exercised, the vesting described below will be accelerated
and all such outstanding options shall be surrendered and the
optionee shall receive a cash payment by Enron in an amount equal
to the value of the surrendered options (as defined in the Enron
Stock Plans).

2. Stock options awarded on January 23, 1996 became 100% vested
on the date of grant.

3. Stock options awarded on December 31, 1996 became 25% vested
on the date of grant with an additional 25% vested on the
anniversary of the date of grant until December 31, 1999.

4. An appreciation in stock price, which will benefit all
stockholders, is required for optionees to receive any gain. A
stock price appreciation of zero percent would render the option
without value to the optionees.

5. The dollar amounts under these columns represent the
potential realizable value of each grant of options assuming that
the market price of 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.

6. Includes shares issued on December 31, 1996 under the All-
Employee Stock Option Program to employees hired during 1996.

7. Weighted average exercise price of all Enron stock options
granted to employees in 1996.

8. Appreciation for All Employee and Director Optionees is
calculated using the maximum allowable option term of 10 years,
even though in some cases the actual option term is less than 10
years. Appreciation for all stockholders is calculated using an
assumed ten-year term, the weighted average exercise price for
All Employee and Director Optionees ($39.7113) and the number of
shares of Common Stock issued and outstanding on December 31,
1996 excluding shares held by the Enron Flexible Equity Trust.

Aggregated Stock Option/SAR Exercises During 1996 and Stock
Option/SAR Values as of December 31, 1996

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/
Acquired on Value December 31, 1996 SARs at December 31, 1996
Name Exercise (#) Realized Exercisable Unexercisable Exercisable Unexercisable

Larry L. DeRoin - $ - 111,925 31,290 $2,222,215 $248,562
Jerry L. Peters 600 $21,113 13,362 3,413 $ 185,012 $ 29,286

Long-Term Incentive Plan - Awards in 1996

The following table provides information concerning awards of
performance units under Enron's Performance Unit Plan during 1996
for the 1996 - 1999 performance period. Mr. Peters is not a
participant in this plan. Grants are made at the beginning of
each fiscal year and each unit is assigned a value of $1.00. The
units are subject to a four-year performance period, at the end
of which Enron's total stockholder return is compared to that of
the 11 peer companies included in the Peer Group. At that time,
the units are assigned a value ranging from $0 to $2.00 based on
the rank of Enron's stockholder return within the Peer Group. To
be valued at the maximum of $2.00, Enron must rank first, and to
be valued at the target of $1.00, Enron must rank third.
Regardless of Enron's rank, Enron's stockholder return must be
above the return on 90-day U.S. Treasury Bills over the same
performance period in order for any value to be assigned.

Performance or Estimated Future Payouts
Number of Shares, Other Period Until Under Non-Stock Price Based
Units or Other Maturation or Plans
Name Rights (#) Payout Threshold Target Maximum

Larry L. DeRoin 75,000 4 years $- $75,000 $150,000

Retirement and Supplemental Benefit Plans

Enron maintains the Enron Corp. Retirement Plan (the
"Retirement Plan") which is a noncontributory defined benefit
plan to provide retirement income for employees of Enron and its
subsidiaries. Through December 31, 1994, participants in the
Retirement 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 Retirement Plan changing the
Plan's name to the Enron Corp. Cash Balance Plan (the "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 10-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.

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 Plans.

The following table sets forth the estimated annual benefits
payable under normal retirement at age 65, assuming current
remuneration levels without any salary projection 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
Name Service at Age 65 By Plans Retirement

Larry L. DeRoin 29.3 39.0 $242,000 $135,525
Jerry L. Peters 11.9 37.8 $114,900 $ 67,922

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. Security Ownership of Certain Beneficial
Owners and Management

The following table sets forth the beneficial ownership of
the voting securities of the Partnership as of January 31, 1997
by the Partnership's executive officers, members of the
Partnership Policy Committee and the Audit Committee and certain
beneficial owners. Other than as set forth below, no person is
known by the General Partners to own beneficially more than 5% of
the voting securities.

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

Larry L. DeRoin 10,000 *
Jerry L. Peters 1,300 *
George L. Mazanec 2,500 *
Brian E. O'Neill -
Daniel P. Whitty -
Gerald B. Smith -
The Williams Companies, Inc.2/ 1,123,500 17.5
One Williams Center
Tulsa, OK 74101-3288
Enron Corp.3/ 3,210,000 50.0
1400 Smith Street
Houston, TX 77002
PanEnergy Corp.4/ 2,086,500 32.5
5400 Westheimer Court
Houston, TX 77056-5310

* Less than 1%.
1/ All units involve sole voting and investment power.
2/ Indirect ownership through its subsidiary, Northwest Border.
3/ Indirect ownership through its subsidiary, Northern Plains.
4/ Indirect ownership through its subsidiary, Pan Border.

Item 13. Certain Relationships and Related Transactions

The Partnership has extensive ongoing relationships with the
General Partners. Such relationships include the following: (i)
Northern Plains provides, in its capacity as the operator of the
Pipeline System, certain tax, accounting and other information to
the Partnership, and (ii) NBP Services, an affiliate of Enron,
assists the Partnership in connection with the operation and
management of the Partnership pursuant to the terms of an
Administrative Services Agreement between the Partnership and NBP
Services.

In addition, Northern Border Pipeline, in which the
Partnership owns a 70% general partner interest, has extensive
ongoing relationships with the General Partners and certain of
their affiliates and with an affiliate of TransCanada. For
example, Northern Plains, a General Partner and affiliate of
Enron, has acted (since 1980), and will continue to act, as the
operator of the Pipeline System pursuant to the terms of an
Operating Agreement between Northern Plains and Northern Border
Pipeline. In addition, as of March 1, 1997, (i) Enron Capital &
Trade Resources Corp., an affiliate of Enron, is a transportation
customer of Northern Border Pipeline, which is obligated to pay
0.2% of Northern Border Pipeline's annual cost of service; (ii)
Northern Natural, an affiliate of Enron, provides a financial
guaranty for a portion (300 MMCFD) of the transportation capacity
held by PAGUS, which represents 17.2% of Northern Border
Pipeline's annual cost of service; (iii) PanEnergy Trading and
Market Services LLC, a joint venture affiliate of PanEnergy is
the agent for the transportation contract with Mobil Natural Gas
Inc. which is obligated to pay 1.8% of Northern Border Pipeline's
annual cost of service; (iv) Panhandle Eastern Pipe Line Company,
an affiliate of PanEnergy, provides a financial guaranty for a
portion (150 MMCFD) of the transportation capacity held by PAGUS,
which in turn represents 10.7% of Northern Border Pipeline's
annual cost of service; (v) TransCanada Gas Services Inc.
("TransCanada Gas Services"), an affiliate of TransCanada, is a
transportation customer of Northern Border Pipeline which is
obligated to pay 7.2% of Northern Border Pipeline's annual cost
of service pursuant to a transportation contract with Northern
Border Pipeline wherein TransCanada Gas Services acts as the
agent of its parent, TransCanada and (vi) Transco, an affiliate
of Williams, is a transportation customer of Northern Border
Pipeline which is obligated to pay 1.2% of Northern Border
Pipeline's annual cost of service. In addition, PanEnergy
Trading and Market Services LLC and Cibola Energy Services
Corporation, an affiliate of TransCanada are transportation
customers under temporary releases from firm transportation
shippers.

The Partnership Policy Committee, whose members are
appointed by the three General Partners, establishes the business
policies of the Partnership, and each General Partner has a right
to appoint a representative to the Northern Border Management
Committee, each of which will vote a portion of the Partnership's
voting interest on the Northern Border Management Committee.
Certain conflicts of interest could arise as a result of the
relationships among the General Partners, their respective
parents and other affiliates, TransCanada, its affiliates, the
Unitholders and Northern Border Pipeline. The directors and
officers of Enron, PanEnergy, Williams and TransCanada have
fiduciary duties to manage their respective companies, including
their investments in their respective affiliates and
subsidiaries, in a manner beneficial to their respective
shareholders. In addition, (i) the members of the Partnership
Policy Committee have a fiduciary duty to manage the Partnership
in a manner beneficial to the Unitholders, (ii) the Partnership's
representatives on the Northern Border Management Committee have
a fiduciary duty to manage Northern Border Pipeline in a manner
beneficial to the Partnership, and (iii) the Partnership has a
fiduciary duty to the subsidiaries of TransCanada, as partners in
Northern Border Pipeline, which duty is also owed by TransCanada
to the Partnership. The Partnership Agreement contains
provisions that allow the General Partners and the Partnership
Policy Committee to take into account the interests of parties in
addition to the Partnership in resolving conflicts of interest,
thereby limiting their duties to the Partnership and the
Unitholders, as well as provisions that may restrict the remedies
available to Unitholders for actions taken that might, without
such limitations, constitute breaches of duty. The Audit
Committee will, at the request of a General Partner or a member
of the Partnership Policy Committee, review conflicts of interest
that may arise between such General Partner and its affiliates
(or the member of the Partnership Policy Committee designated by
it), on the one hand, and the Partnership or the Unitholders, on
the other. In addition, with respect to the fiduciary duties
owed by the Partnership and the subsidiaries of TransCanada to
each other as partners in Northern Border Pipeline, (i) the
fiduciary duty owed by the Partnership to such subsidiaries of
TransCanada may restrict the ability of the Partnership Policy
Committee to cause the Partnership to take certain actions that
might be in the best interests of the Partnership, but in
conflict with the fiduciary duty owed by the Partnership to such
subsidiaries of TransCanada and (ii) the duty of the directors
and officers of each of the parent companies of such subsidiaries
of TransCanada to its shareholders may conflict with the duty
owed by such subsidiaries of TransCanada to the Partnership as a
partner in Northern Border Pipeline.

PART IV

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

(a)(1) and (2) Financial Statements
See "Index to Financial Statements" set forth on page F-1.

(a)(3) Exhibits

* 3.1 Form of Amended and Restated Agreement of
Limited Partnership of Northern Border
Partners, L.P. (Exhibit 3.1 No. 2 to the
Partnership's Form S-1 Registration
Statement, Registration No. 33-66158
("Form S-1")).
*10.1 Form of Amended and Restated Agreement of
Limited Partnership For Northern Border
Intermediate Limited Partnership (Exhibit
10.1 to Form S-1).
*10.2 Northern Border Pipeline Company General
Partnership Agreement between Northern
Plains Natural Gas Company, Northwest
Border Pipeline Company, Pan Border Gas
Company, TransCanada Border Pipeline Ltd.
and TransCan Northern Ltd., effective
March 9, 1978, as amended (Exhibit 10.2
to Form S-1).
*10.3 Operating Agreement between Northern
Border Pipeline Company and Northern
Plains Natural Gas Company, dated
February 28, 1980 (Exhibit 10.3 to Form S-
1).
*10.4 Administrative Services Agreement between
NBP Services Corporation, Northern Border
Partners, L.P. and Northern Border
Intermediate Limited Partnership (Exhibit
10.4 to Form S-1).
*10.5 Amended and Restated Loan Agreement among
Northern Border Pipeline Company, the
Banks (as defined therein), Canadian
Imperial Bank of Commerce, New York
Agency and Bank of America National Trust
& Savings Association, dated July 15,
1992 (Exhibit 10.5 to Form S-1).
*10.5.1Letter Amendment to Amended and Restated
Loan Agreement effective as of September
21, 1993 (Exhibit 10.5.1 to the
Partnership's Annual Report on Form 10-K
for the year ended December 31, 1993
("1993 10-K")).
*10.5.2Letter Amendment to Amended and Restated
Loan Agreement effective as of September
9, 1994 (Exhibit 10.5.2 to the
Partnership's Annual Report on Form 10-K
for the year ended December 31, 1994
("1994 10-K")).
*10.5.3Letter Amendment to Amended and Restated
Loan Agreement dated May 18, 1995
(Exhibit 10.5.3 to the Partnership's
Annual Report on Form 10-K for the year
ended December 31, 1995 ("1995 10-K)).
*10.6 Note Purchase Agreement between Northern
Border Pipeline Company and the parties
listed therein, dated July 15, 1992
(Exhibit 10.6 to Form S-1).
*10.6.1Supplemental Agreement to the Note
Purchase Agreement dated as of June 1,
1995 (Exhibit 10.6.1 to 1995 10-K).
*10.7 Consent and Agreement of the Partners
among Northern Plains Natural Gas
Company, Northwest Border Pipeline
Company, Pan Border Gas Company,
TransCanada Border PipeLine Ltd. and
Canadian Imperial Bank of Commerce, New
York Agency, dated February 28, 1990
(Exhibit 10.7 to Form S-1).
*10.8 Consent and Agreement of the Partners
among TransCanada Border PipeLine Ltd.,
TransCan Northern Ltd. and Canadian
Imperial Bank of Commerce, New York
Agency, dated April 19, 1991 (Exhibit
10.8 to Form S-1).
*10.9 Guaranty made by Panhandle Eastern
Pipeline Company, dated October 31, 1992
(Exhibit 10.9 to Form S-1).
*10.10 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).
*10.10.1Amended 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 1993 10-K).
*10.10.2Amended 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 1994
10-K).
*10.10.3Amended 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).
*10.11.1Guaranty made by Northern Natural Gas
Company, dated October 7, 1993 (Exhibit
10.11.1 to 1993 10-K).
*10.11.2Guaranty 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
Northern Natural Gas Company, dated
August 25, 1988 (Exhibit 10.12 to Form S-
1).
*10.12.1Amendment to Northern Border Pipeline
Company U.S. Shippers Service Agreement
effective October 1, 1993. (Exhibit
10.12.1 to 1993 10-K).
*10.12.2Amendment to Northern Border Pipeline
Company U.S. Shippers Service Agreement
terminating the Agreement as of November
1, 1994 (Exhibit 10.12.2 to 1994 10-K).
*10.13 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).
*10.13.1Amendment to Northern Border Pipeline
Company Service Agreement extending the
term effective November 1, 1995 (Exhibit
10.13.1 to 1995 10-K).
*10.14 Form of Credit Agreement between Northern
Border Partners, L.P., as borrower, and
Northern Plains Natural Gas Company,
Northwest Border Pipeline Company and Pan
Border Gas Company, as lenders (Exhibit
10.14 to Form S-1).
*10.15 Form of Seventh Supplement Amending
Northern Border Pipeline Company General
Partnership Agreement (Exhibit 10.15 to
Form S-1).
*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 Northern Border Pipeline Company U.S.
Shippers Service Agreement dated August
30, 1991 between Northern Border Pipeline
Company and Mobil Natural Gas, Inc., with
Amended Exhibit A effective April 29,
1994 and designation of agent effective
August 1, 1996.
21. The subsidiaries of Northern Border
Partners, L.P. are Northern Border
Intermediate Limited Partnership and
Northern Border Pipeline Company.
__________
*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 1996.

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the
Securities Exchange Act of 1934, the registrant has duly caused
this report to be signed on its behalf by the undersigned,
thereunto duly authorized on this 28th day of March, 1997.

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

By LARRY L. DEROIN
Larry L. DeRoin
Chief Executive Officer

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

Signature Title Date

LARRY L. DEROIN Chief Executive Officer and March 28, 1997
Larry L. DeRoin Chairman of the Partnership
Policy Committee
(Principal Executive Officer)

GEORGE L. MAZANEC Member of Partnership Policy March 28, 1997
George L. Mazanec Committee

BRIAN E. O'NEILL Member of Partnership Policy March 28, 1997
Brian E. O'Neill Committee

JERRY L. PETERS Chief Financial and March 28, 1997
Jerry L. Peters Accounting Officer

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

Page No.

Report of Independent Public Accountants F-2
Consolidated Balance Sheet - December 31, 1996 and 1995 F-3
Consolidated Statement of Income - Years Ended F-4
December 31, 1996, 1995 and 1994
Consolidated Statement of Cash Flows - Years Ended F-5
December 31, 1996, 1995 and 1994
Consolidated Statement of Changes in Partners' Capital - F-6
Years Ended December 31, 1996, 1995 and 1994
Notes to Consolidated Financial Statements F-7 through
F-16

REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS

To Northern Border Partners, L.P.:

We have audited the accompanying consolidated balance sheets of
Northern Border Partners, L.P., a Delaware limited partnership,
and Subsidiaries as of December 31, 1996 and 1995, and the
related consolidated statements of income, cash flows and changes
in partners' capital for each of the three years in the period
ended December 31, 1996. 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 generally accepted
auditing standards. Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether
the financial statements are free of material misstatement. An
audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An
audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating
the overall financial statement presentation. We believe that
our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above
present fairly, in all material respects, the financial position
of Northern Border Partners, L.P. and Subsidiaries as of December
31, 1996 and 1995, and the results of their operations and their
cash flows for each of the three years in the period ended
December 31, 1996, in conformity with generally accepted
accounting principles.

ARTHUR ANDERSEN LLP

Omaha, Nebraska,
January 22, 1997

NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEET

(In Thousands)

December 31,
ASSETS 1996 1995

CURRENT ASSETS
Cash and cash equivalents $ 41,390 $ 39,418
Accounts receivable 16,907 18,928
Related party receivables 2,364 2,883
Materials and supplies, at cost 4,128 4,437

Total current assets 64,789 65,666

NATURAL GAS TRANSMISSION PLANT
Property, plant and equipment 1,513,116 1,499,893
Less: Accumulated provision for
depreciation and amortization 575,257 542,306

Net property, plant and equipment 937,859 957,587

OTHER ASSETS 13,836 18,086

Total assets $1,016,484 $1,041,339

LIABILITIES AND PARTNERS' CAPITAL

CURRENT LIABILITIES
Current maturities of long-term debt $ 17,500 $ 15,000
Note payable 10,000 --
Accounts payable 3,463 1,193
Accrued taxes other than income 20,968 19,903
Accrued interest 10,353 10,516
Over recovered cost of service 4,236 2,508
Accumulated provision for billings
subject to refund 12,227 --

Total current liabilities 78,747 49,120

LONG-TERM DEBT, net of current maturities 360,000 395,000

MINORITY INTERESTS IN PARTNERS' CAPITAL 158,089 166,789

RESERVES AND DEFERRED CREDITS 9,062 11,313

COMMITMENTS AND CONTINGENCIES (NOTE 6)

PARTNERS' CAPITAL
General Partners 8,212 8,382
Common Units 303,777 310,089
Subordinated Units 98,597 100,646

Total partners' capital 410,586 419,117

Total liabilities and partners' capital $1,016,484 $1,041,339

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

NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF INCOME

(In Thousands, Except Per Unit Amounts)

Year Ended December 31,
1996 1995 1994

OPERATING REVENUE $201,943 $206,497 $211,580

OPERATING EXPENSES
Operations and maintenance 28,366 26,730 28,919
Depreciation and amortization 46,979 47,081 41,959
Taxes other than income 24,390 23,886 24,438

Operating expenses 99,735 97,697 95,316

OPERATING INCOME 102,208 108,800 116,264

INTEREST EXPENSE 33,117 35,205 38,424

OTHER INCOME (EXPENSE)
Other income (expense), net 2,951 478 (1,382)
Allowance for equity funds used
during construction 396 90 42

Other income (expense) 3,347 568 (1,340)

MINORITY INTERESTS IN NET INCOME 22,153 22,360 23,147

NET INCOME TO PARTNERS $ 50,285 $ 51,803 $ 53,353

NET INCOME PER UNIT $ 1.88 $ 1.94 $ 2.00

NUMBER OF UNITS USED IN COMPUTATION 26,200 26,200 26,200

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

NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF CASH FLOWS

(In Thousands)

Year Ended December 31,
1996 1995 1994

CASH FLOWS FROM OPERATING ACTIVITIES:
Net income to partners $ 50,285 $ 51,803 $ 53,353

Adjustments to reconcile net income to
partners to net cash provided by
operating activities:
Depreciation and amortization 47,010 47,083 41,959
Minority interests in net income 22,153 22,360 23,147
Provision for billings subject to refund 12,227 -- --
Changes in other current assets
and liabilities 7,749 (975) (925)
Other (1,890) 6,807 3,554

Total adjustments 87,249 75,275 67,735

Net cash provided by operating activities 137,534 127,078 121,088

CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to property, plant, and
equipment, net (18,597) (8,411) (2,985)
Other (4,796) -- --

Net cash used in investing activities (23,393) (8,411) (2,985)

CASH FLOWS FROM FINANCING ACTIVITIES:
Cash distributions
Common units (43,516) (43,516) (43,516)
Subordinated units (14,124) (14,124) (14,124)
General partners (1,176) (1,176) (1,176)
Minority Interests (30,853) (29,555) (26,252)
Retirement of long-term debt (32,500) (35,000) (25,000)
Borrowings on note payable 10,000 -- --

Net cash used in financing activities (112,169) (123,371) (110,068)

NET CHANGE IN CASH AND CASH EQUIVALENTS 1,972 (4,704) 8,035

Cash and cash equivalents-beginning of period 39,418 44,122 36,087

Cash and cash equivalents-end of period $ 41,390 $ 39,418 $ 44,122

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

NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF CHANGES IN PARTNERS' CAPITAL

(In Thousands)

General Common Subordinated Partners'
Partners Units Units Capital

Partners' Capital at December 31, 1993 $ 8,632 $319,320 $103,641 $431,593

Net income to partners 1,066 39,474 12,813 53,353

Distributions paid (1,176) (43,516) (14,124) (58,816)

Partners' Capital at December 31, 1994 8,522 315,278 102,330 426,130

Net income to partners 1,036 38,327 12,440 51,803

Distributions paid (1,176) (43,516) (14,124) (58,816)

Partners' Capital at December 31, 1995 8,382 310,089 100,646 419,117

Net income to partners 1,006 37,204 12,075 50,285

Distributions paid (1,176) (43,516) (14,124) (58,816)

Partners' Capital at December 31, 1996 $ 8,212 $303,777 $ 98,597 $410,586

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

NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. ORGANIZATION AND MANAGEMENT

Northern Border Partners, L.P., through a subsidiary limited
partnership, Northern Border Intermediate Limited Partnership,
collectively referred to herein as the Partnership, a Delaware
limited partnership, owns a 70% general partner interest in Northern
Border Pipeline Company (Northern Border Pipeline). The remaining
30% general partner interests in Northern Border Pipeline are owned
by TransCanada Border PipeLine Ltd. (6%) and TransCan Northern Ltd.
(24%) (collectively TransCanada), both of which are wholly-owned
subsidiaries of TransCanada PipeLines Limited. 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 PanEnergy Corp. (PanEnergy), and Northwest Border
Pipeline Company (Northwest Border), a wholly-owned subsidiary of The
Williams Companies, Inc. serve as the General Partners of the
Partnership and collectively own a 2% general partner interest in the
Partnership. The General Partners also own Subordinated Units
representing, in the aggregate, an effective 24% limited partner
interest in the Partnership.

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

Northern Border Pipeline is a general partnership, formed March 9,
1978, pursuant to the Texas Uniform Partnership Act. The pipeline
system owned by Northern Border Pipeline is a 969-mile natural gas
transmission line extending from the United States-Canadian border
near Port of Morgan, Montana, to a terminus near Harper, Iowa, where
it interconnects with the system of Natural Gas Pipeline Company of
America.

Northern Border Pipeline is managed by a Management Committee that
includes three representatives from the Partnership (one
representative from each of the General Partners of the Partnership)
and one representative from TransCanada. The Partnership's
representatives selected by Northern Plains, Pan Border and Northwest
Border have 35%, 22.75% and 12.25%, respectively, of the voting
interest on the Northern Border Pipeline Management Committee. The
representative designated by TransCanada votes the remaining 30%
interest. The day-to-day management of Northern Border Pipeline's
affairs is the responsibility of Northern Plains (the Operator), as
defined by the operating agreement between Northern Border Pipeline
and Northern Plains. Northern Border Pipeline is charged for the
salaries, benefits and expenses of the Operator. Substantially all
of the operations and maintenance expenses are paid to the Operator
and other Enron affiliates.

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

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

(A) Principles of Consolidation and Use of Estimates

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

The preparation of financial statements in conformity with
generally accepted accounting principles 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 Regulations

Northern Border Pipeline is subject to regulation by the
Federal Energy Regulatory Commission (FERC). Northern Border
Pipeline's accounting policies conform to generally accepted
accounting principles, as applied in the case of regulated
entities.

(C) Income Taxes

Income taxes are the responsibility of the partners and are
not reflected in these financial statements. However, the
Northern Border Pipeline tariff establishes the method of
accounting for and calculating income taxes and requires
Northern Border Pipeline to reflect in its cost of service 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 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 $306.7 million and
$322.7 million as of December 31, 1996 and 1995, respectively,
and are primarily related to accelerated depreciation and other
plant-related differences.

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

Property, plant and equipment is stated at original cost.
Balances at December 31, 1996 and 1995 include construction
work in progress of approximately $19.6 million and $5.1
million, respectively. Approximately $16.8 million and $4.6
million of the construction work in progress balances at
December 31, 1996 and 1995, respectively, represent project-to-
date expenditures on Northern Border Pipeline's proposed
expansion and extension of its pipeline from its current
terminus near Harper, Iowa to a point near Manhattan, Illinois
(The Chicago Project) (see Note 6).

Expenditures for 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 and its
levelized cost of service. The effective depreciation rate
applied to Northern Border Pipeline's gross transmission plant
in 1996, 1995 and 1994 was 3.1%, 3.1% and 2.8%, respectively
(see Note 6).

Composite rates are applied to all other functional groups of
property having similar economic characteristics. 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.

(F) Revenue Recognition

Northern Border Pipeline bills the cost of service on an
estimated basis for a six month cycle. Any net excess or
deficiency resulting from the comparison of the cost of service
determined for that period in accordance with the FERC tariff
(incurred cost of service) to the estimated billing is
accumulated, including carrying charges thereon, and is either
billed to or credited back to the shippers. Revenues reflect
incurred cost of service. An amount equal to differences
between billing estimates and the incurred cost of service,
including carrying charges, is reflected in current assets or
current liabilities.

(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.
Recognition of this allowance is appropriate because it
constitutes an actual cost of construction. 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. The rate employed for the
equity component of AFUDC is the equity rate of return stated
in Northern Border Pipeline's FERC tariff.

(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 agreements for trading purposes.
The cost or benefit of the interest rate swap agreements is
recognized currently as a component of interest expense.

3. SHIPPER SERVICE AGREEMENTS

Operating revenues are collected pursuant to the FERC tariff which
directs that Northern Border Pipeline collect its cost of service
through firm transportation service agreements (firm service
agreements). Northern Border Pipeline's FERC tariff provides an
opportunity to recover all operations and maintenance costs of the
pipeline, taxes other than income taxes, interest, depreciation and
amortization, an allowance for income taxes and a regulated equity
return. Billings for the firm service agreements are based on
contracted volumes to determine the allocable share of the cost of
service and are not dependent on the volumes actually transported.

Northern Border Pipeline has firm service agreements for various
terms extending as long as October 2012. Based on existing
contracts and capacity, Northern Border Pipeline has contracts for
its entire firm capacity through October 2001. Northern Border
Pipeline also has interruptible service contracts with numerous
other shippers as a result of its self-implementing blanket
transportation authority. Revenues received from the interruptible
service contracts are credited to the cost of service reducing the
billings for the firm service agreements.

Northern Border Pipeline's largest shipper, Pan-Alberta Gas (U.S.)
Inc. (PAGUS), is obligated for approximately 49.0% of the cost of
service through its firm service agreements which expire in October
2001. Operating revenues from the PAGUS firm service agreements and
interruptible service contracts for the years ended December 31,
1996, 1995 and 1994 were $101.7 million, $99.9 million and $103.1
million, respectively. Northern Natural Gas Company, a wholly-owned
subsidiary of Enron, and Panhandle Eastern Pipe Line Company, a
wholly-owned subsidiary of PanEnergy, have executed financial
guarantees representing 17.2% and 10.7%, respectively, of the total
cost of service related to the contracted capacity of PAGUS. The
remaining 21.1% of the cost of service 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.

Shippers affiliated with the partners of Northern Border Pipeline
have firm service agreements representing approximately 10.4% of the
cost of service through October 2001. These firm service agreements
extend for various terms which range from October 2005 to December
2008. Operating revenues from the affiliated firm service agreements
and interruptible service contracts for the years ended December 31,
1996, 1995 and 1994 were $22.7 million, $18.8 million and $25.2
million, respectively.

4. CREDIT FACILITIES, SHORT-TERM BORROWINGS AND LONG-TERM DEBT

In October 1996, Northern Border Pipeline entered into a one-year
$50 million revolving credit agreement with a financial institution.
The 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.
The interest rate options available under the credit agreement are
based upon the London Interbank Offered Rate (LIBOR), certificate of
deposit rates or other short-term interest rates. Compensating
balances are not required, but Northern Border Pipeline is required
to pay a commitment fee on unborrowed funds. In late December 1996,
$10 million was borrowed under the credit agreement at an interest
rate of 5.94% and is shown as a note payable in the accompanying
consolidated balance sheet.

Northern Border Pipeline has senior notes in the aggregate principal
amount of $250 million at both December 31, 1996 and 1995, pursuant
to note purchase agreements, which combined have an average fixed
interest rate of 8.43%. Annual principal payments on the senior
notes begin August 2000, with the final principal payment due August
2003.

As of December 31, 1996 and 1995, Northern Border Pipeline had
outstanding $127.5 million and $160 million, respectively, under an
amended bank loan agreement. The amended bank loan agreement
provides for fixed, semi-annual repayments and has a final maturity
of December 31, 1999. The amended bank loan 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. The interest rate options
available to Northern Border Pipeline under the amended bank loan
agreement were based upon LIBOR, CD Advances rate or U.S. prime rate.

At December 31, 1996 and 1995, Northern Border Pipeline had
outstanding interest rate swap agreements with notional amounts of
$90 million and $115 million, respectively. Under the agreements,
which have a remaining average maturity of approximately three years
as of December 31, 1996, Northern Border Pipeline makes payments to
counterparties at fixed rates and in return receives payments at
variable rates based on LIBOR. At both December 31, 1996 and 1995,
Northern Border Pipeline was in a payable position relative to its
counterparties. The average effective interest rate of Northern
Border Pipeline's amended bank loan agreement, taking into
consideration the interest rate swap agreements, was 7.32% and 7.39%
at December 31, 1996 and 1995, respectively.

The average interest rates and interest paid, net of amounts
capitalized, on the total outstanding debt, including the interest
rate swap agreements, were as follows:

1996 1995 1994

Average interest rate during the
year ended December 31 8.37% 8.34% 8.50%
Average interest rate
at December 31 8.21% 8.38% 8.24%
Interest paid, net of
amounts capitalized, during
the year ended December 31 (in
millions of dollars) $31.9 $34.3 $37.8

Aggregate repayments of long-term debt required for the next five
years are as follows: $17.5 million, $50 million, $60 million, $66
million and $41 million for 1997, 1998, 1999, 2000 and 2001,
respectively.

The credit agreement, senior notes and amended bank loan agreement
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, 1996 and 1995, respectively, $27
million and $29 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 senior notes was
approximately $271 million and $282 million at December 31, 1996 and
1995, respectively. At December 31, 1996 and 1995, the estimated
fair value which would be payable to terminate the interest rate
swap agreements, taking into account current interest rates, was
approximately $4 million and $7 million, respectively. Northern
Border Pipeline presently intends to maintain the current schedule
of maturities for the senior notes and the interest rate swap
agreements which will result in no gains or losses on their
respective repayment. The carrying value of the credit agreement
and the amended bank loan agreement approximate the fair value since
the interest rates are periodically adjusted to current market
conditions.

5. PARTNERS' CAPITAL

Partners' capital consists of 19,780,000 Common Units representing
an effective 74% limited partner interest in the Partnership;
6,420,000 Subordinated Units representing an effective 24% limited
partner interest in the Partnership owned by the General Partners;
and a 2% general partner interest.

The Partnership Policy Committee may cause the Partnership to issue
additional Common Units or other partner interests. However, the
Partnership may not issue more than an additional 17,200,000 Common
Units or equivalent other partner interests while the Subordinated
Units have not been converted or are still outstanding without the
approval of the holders of at least a majority of the outstanding
Common Units (excluding Common Units held by the General Partners
and their affiliates). Subordinated Units may not be converted to
Common Units until after December 31, 1998 and after certain
financial tests have been met.

The Partnership will make distributions to its partners with respect
to each calendar quarter in an amount equal to 100% of its Available
Cash. "Available Cash" generally consists of all of the cash
receipts of the Partnership adjusted for its cash disbursements and
net changes to reserves. Available Cash will generally be
distributed 98% to the Unitholders and 2% to the General Partners.
The holders of Units are entitled to receive the minimum quarterly
distribution of $0.55 per Unit per quarter if and to the extent
there is sufficient Available Cash. Distributions of Available Cash
to the holders of Subordinated Units are subject to the rights of
the holders of the Common Units to receive the minimum quarterly
distribution.

6. COMMITMENTS AND CONTINGENCIES

Regulatory Proceedings

In November 1995, Northern Border Pipeline filed a rate case in
compliance with its FERC tariff for the determination of its allowed
equity rate of return. In December 1995, the FERC issued an order
that permitted Northern Border Pipeline to begin collecting the
requested increase in the equity rate of return effective June 1,
1996, subject to refund. Northern Border Pipeline filed for FERC
approval of a Stipulation and Agreement (Stipulation) on October 15,
1996, to settle its rate case. On November 19, 1996, the
Stipulation was certified by an Administrative Law Judge (ALJ) to
the FERC for review and approval. In accordance with the terms of
the Stipulation, Northern Border Pipeline's allowed equity rate of
return would be reduced from a requested 14.25% to 12.75% for the
period June 1, 1996 to October 1, 1996 and to 12% thereafter.
Additionally, the Stipulation would reduce the depreciation rate
applied to Northern Border Pipeline's gross transmission plant from
3.6% to 2.7% for the period June 1, 1996 to December 31, 1996,
resulting in an average effective depreciation rate of 3.1% for the
year ended December 31, 1996. Beginning January 1, 1997, the
depreciation rate would be reduced to 2.5%. Northern Border
Pipeline has reduced its operating revenue by approximately $12.2
million for the year ended December 31, 1996, which includes $7.4
million attributable to the reduction in depreciation and
amortization expense for 1996, to reflect the terms of the
Stipulation. Northern Border Pipeline must receive FERC approval of
the Stipulation before it can implement all of the filed for terms
and any associated refunds. The Partnership is unable to predict if
or when the Stipulation will be approved as filed and thus actual
results could differ from amounts recorded.

In August 1996, the FERC issued an order which contained a
preliminary determination favorable to Northern Border Pipeline's
October 1995 amended application with the FERC for The Chicago
Project. The preliminary determination found that The Chicago
Project is required by the public convenience and necessity and
authorizes the project facility costs to be included with existing
facility costs in the determination of rates. The preliminary
determination contemplates issuance of a final order by the FERC,
subject to completion of the environmental review. In September
1996, Northern Border Pipeline filed an amendment to its October
1995 application to reflect limited facility modifications which
among other things, reduced environmental impacts and project costs.
In December 1996, the FERC issued a draft Environmental Impact
Statement (EIS) which concluded The Chicago Project would have a
limited adverse environmental impact and would be environmentally
acceptable after adoption of certain recommended mitigation
measures. Northern Border Pipeline's September 1996 application
with the FERC for The Chicago Project facilities proposes
construction and operation of 243 miles of pipeline, 147 miles of
pipeline loop and a total of 228,500 compressor horsepower at eight
compressor stations. The application also requests approval to
remove from service 100,000 compressor horsepower at five existing
compressor stations to be replaced with 175,000 compressor
horsepower. The project is expected to cost, using certain
construction cost escalation assumptions, approximately $837 million
and, subject to timely regulatory approvals, be ready for service in
November 1998. A final EIS and FERC order approving construction
and operation of The Chicago Project is anticipated in 1997.

In May 1996, the FERC granted rehearing of its May 1994 order on
Northern Border Pipeline's methodology for recording in its books
and reflecting in its rates amounts related to alternative minimum
tax (AMT). The FERC Audit Staff (Staff), in December 1991 after an
examination of Northern Border Pipeline's records for the period
January 1, 1987 through December 31, 1989, took exception to
Northern Border Pipeline's established method of accounting for AMT
for ratemaking purposes. Northern Border Pipeline did not agree
with the exception noted by the Staff and proceeded with a hearing
before an ALJ who concluded Northern Border Pipeline had properly
accounted for AMT. Ultimately, in the May 1996 order, the FERC
accepted the ALJ's conclusions and vacated its May 1994 order which
had held that the AMT component of Northern Border Pipeline's rate
base should reflect the particular tax circumstances of each
Northern Border Pipeline partner. There were no accounting
adjustments or rate refunds required in resolution of this issue.

In May 1996, the Staff issued its audit report on its examination of
Northern Border Pipeline's records for the three year period
subsequent to January 1, 1990. The audit report required Northern
Border Pipeline to record certain adjustments to its accounts
including the reclassification of $3.9 million of costs from utility
plant in service to a regulatory asset. In accordance with Northern
Border Pipeline's FERC tariff, the regulatory asset is includable in
rate base, however Northern Border Pipeline must file with the FERC
for the future recovery of this asset through amortization in cost
of service. The General Partners indemnified the Partnership for
any negative impact on distributions the Partnership received from
Northern Border Pipeline as a result of this audit attributable to
periods prior to October 1, 1993. The adjustments made and the
indemnification received as a result of the audit report did not
materially affect the consolidated financial position or results of
operations.

Environmental Matters

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

Other

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

7. CAPITAL EXPENDITURE PROGRAM

Total capital expenditures for 1997 are estimated to be $210 million
for The Chicago Project and $14 million for renewals and
replacements for the existing facilities. Funds required to meet
the 1997 capital expenditures are anticipated to be provided from
debt borrowings, internal sources and equity contributions from
minority interest holders.

8. NET INCOME PER UNIT

The General Partners' allocation of net income is based on their
combined 2% interest in the Partnership which has been deducted
before calculating net income per Unit. The computation of net
income per Unit is based on the number of outstanding Common Units
of 19,780,000 and outstanding Subordinated Units of 6,420,000.

9. QUARTERLY FINANCIAL DATA (Unaudited)

(In thousands, except Operating Operating Net Income Net Income
per unit amounts) Revenue Income to Partners per Unit

1996
First Quarter $52,953 $26,325 $12,847 $0.48
Second Quarter 52,918 25,943 12,737 0.48
Third Quarter 52,863 25,991 12,942 0.48
Fourth Quarter 43,209 23,949 11,759 0.44
1995
First Quarter $52,188 $27,736 $12,960 $0.48
Second Quarter 52,587 27,608 12,969 0.49
Third Quarter 51,886 27,301 12,786 0.48
Fourth Quarter 49,836 26,155 13,088 0.49

10. SUBSEQUENT EVENTS

On January 16, 1997, the Partnership declared a cash distribution of
$0.55 per Unit and a cash distribution to the General Partners at a
rate equivalent to their combined 2% General Partner interest for
the period October 1, 1996 through December 31, 1996. The
distribution is payable February 14, 1997, to the General Partners
and to the Unitholders of record at January 31, 1997.