TC PIPELINES LP - 10-K Annual Report

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

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F O R M 10-K

[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2003

OR

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

Commission file number: 000-26091

TC PIPELINES, LP
(Exact name of registrant as specified in its charter)

DELAWARE 52-2135448
(State or other jurisdiction (I.R.S. Employer
of incorporation or organization) Identification No.)

110 TURNPIKE ROAD, SUITE 203
WESTBOROUGH, MASSACHUSETTS 01581
(Address of principal executive offices) (zip code)
Registrant's telephone number, including area code: 508-871-7046

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

TITLE OF EACH CLASS NAME OF EACH EXCHANGE ON WHICH REGISTERED

NONE

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

TITLE OF CLASS

COMMON UNITS REPRESENTING LIMITED PARTNER INTERESTS

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

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

Indicate by check mark whether the registrant is an accelerated filer (as
defined in Rule 12b-2 of the Act) Yes [X] No [ ]

Aggregate market value of the voting and non-voting common equity held by
non-affiliates of the registrant, as at June 30, 2003, was approximately $350.1
million.

As of February 23, 2004, there were 16,563,564 of the registrant's common
units outstanding.

TC PIPELINES, LP
TABLE OF CONTENTS

ALL AMOUNTS ARE STATED IN UNITED STATES DOLLARS UNLESS OTHERWISE INDICATED.

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PART I

ITEM 1. BUSINESS

BUSINESS OF TC PIPELINES, LP

TC PipeLines, LP was formed in 1998 as a Delaware limited partnership to
acquire, own and participate in the management of United States-based
pipeline assets. TC PipeLines, LP and its subsidiary limited partnerships, TC
PipeLines Intermediate Limited Partnership and TC Tuscarora Intermediate
Limited Partnership are collectively referred to herein as "TC PipeLines" or
"the Partnership." TC PipeLines GP, Inc., an indirect wholly owned subsidiary
of TransCanada PipeLines Limited which is a wholly owned subsidiary of
TransCanada Corporation referred to herein collectively as "TransCanada", is
the general partner of the Partnership.

The Partnership owns a 30% general partner interest in Northern Border
Pipeline Company. The remaining 70% general partner interest in Northern
Border Pipeline is held by Northern Border Partners, L.P., a publicly traded
limited partnership that is controlled by affiliates of Enron Corp.
TransCanada holds a minority general partner interest in Northern Border
Partners which entitles it to 12.25% of the voting power of Northern Border
Pipeline.

TC PipeLines also owns a 49% general partner interest in Tuscarora Gas
Transmission Company (Tuscarora). The Partnership acquired this interest from
TCPL Tuscarora Ltd., an indirect subsidiary of TransCanada, in September 2000.

At December 31, 2003, the Partnership had 16,563,564 common units outstanding,
of which 11,890,694 were held by the public, 2,800,000 were held by an affiliate
of the general partner and 1,872,870 were held by the general partner.

TransCanada, by virtue of its ownership of the Partnership's general partner,
holds an aggregate 2% general partner interest in the Partnership. The
general partner also owns 1,872,870 common units and 936,436 subordinated
units and receives incentive distributions if quarterly cash distributions on
the common and subordinated units exceed levels specified in the partnership
agreement (see Item 5. "Market for Registrant's Common Units and Related
Security Holder Matters").

The Partnership's 30% general partner interest in Northern Border Pipeline and
49% general partner interest in Tuscarora represent its only material assets.

BUSINESS OF NORTHERN BORDER PIPELINE COMPANY

GENERAL

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

Northern Border Pipeline owns an interstate pipeline system that transports
natural gas from the Montana-Saskatchewan border to natural gas markets in the
midwestern United States. This pipeline system connects with multiple pipelines
that provide shippers with access to the various natural gas markets served by
those pipelines. TC PipeLines estimates that, in the year ended December 31,
2003, Northern Border Pipeline transported approximately

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22% of the total amount of natural gas imported from Canada to the United
States. Over the same period, approximately 88% of the natural gas transported
was produced in the Western Canadian Sedimentary Basin located in the provinces
of Alberta, British Columbia and Saskatchewan.

Northern Border Pipeline transports gas for shippers under a tariff regulated
by the Federal Energy Regulatory Commission (FERC). The tariff specifies the
maximum and minimum transportation rates and the general terms and conditions
of transportation service on the pipeline system. Northern Border Pipeline's
revenues are derived from agreements for the receipt and delivery of gas at
points along the pipeline system as specified in each shipper's individual
transportation contract. Northern Border Pipeline does not own the gas that
it transports, and therefore it does not assume natural gas commodity price
risk for quantities transported. Any exposure to commodity risk for
imbalances on Northern Border Pipeline's system that may result from under or
over deliveries to customers or interconnecting pipelines is either recovered
through provisions in Northern Border Pipeline's tariff or is immaterial.
Northern Border Pipeline owns the line pack, which is the amount of gas
necessary to maintain efficient operations of the pipeline. Northern Border
Pipeline's shippers are responsible to provide fuel gas necessary for the
operation of gas compressor stations.

Northern Border Pipeline's management is overseen by a four-member management
committee. Three representatives are designated by Northern Border Partners,
with each of its general partners selecting one representative and one
representative is designated by TC PipeLines. Voting power on the management
committee is allocated among Northern Border Partners' three representatives
in proportion to their general partner interests in Northern Border Partners.
As a result, the 70% voting power of Northern Border Partners' three
representatives on the management committee is allocated as follows: 35% to
the representative designated by Northern Plains, 22.75% to the
representative designated by Pan Border and 12.25% to the representative
designated by Northwest Border. Northern Plains and Pan Border are
subsidiaries of Enron. Therefore, Enron controls 57.75% of the voting power
of the management committee and has the right to select two of the members.
On December 2, 2001, Enron filed a voluntary petition for Chapter 11
protection in bankruptcy court. On September 25, 2003, a motion by Enron to
transfer Enron's interests in, among other entities, Northern Plains and Pan
Border to CrossCountry Energy, a new pipeline operating entity, was approved.
See Item 7. "Management's Discussion and Analysis of Financial Condition and
Results of Operations - Results of Operations of Northern Border Pipeline
Company - The Impact Of Enron's Chapter 11 Filing On Northern Border
Pipeline's Business."

The Northern Border pipeline system is operated by Northern Plains pursuant to
an operating agreement. As of December 31, 2003, Northern Plains employed
approximately 216 individuals located at its headquarters in Omaha, Nebraska
and at various locations along the pipeline route and also used employees and
information technology systems of its affiliates to provide its services.
Northern Plains' employees are not represented by any labor union and are not
covered by any collective bargaining agreements.

THE NORTHERN BORDER PIPELINE SYSTEM

Northern Border Pipeline owns a 1,249-mile interstate pipeline system that
transports natural gas from the Montana-Saskatchewan border near Port of Morgan,
Montana to natural gas markets in the midwestern United States. Construction of
the pipeline was initially completed in 1982. The Northern Border pipeline
system was expanded and/or extended in 1991, 1992, 1998 and 2001. The Northern
Border pipeline system connects directly and through multiple pipelines to
various natural gas markets in the United States.

The Northern Border pipeline system consists of 822 miles of 42-inch diameter
pipe from the Canadian border to Ventura, Iowa capable of transporting a total
of 2,374 million cubic feet per day (mmcfd); 30-inch diameter pipe and 36-inch
diameter pipe, each approximately 147 miles in length, capable of transporting
1,484 mmcfd in total from Ventura, Iowa to Harper, Iowa; 226 miles of 36-inch
diameter pipe and 19 miles of 30-inch diameter pipe capable of transporting 844
mmcfd from Harper, Iowa to Manhattan, Illinois (Chicago area); and 35 miles of
30-inch diameter pipe capable of transporting 545 mmcfd from Manhattan, Illinois
to a terminus near North Hayden, Indiana. Along the pipeline there are 16
compressor stations with total rated horsepower of 499,000 and measurement
facilities to support the receipt and delivery of gas at various points. Other
facilities include four field offices and a microwave communication system with
50 tower sites.

The Northern Border pipeline system has pipeline access to natural gas reserves
in the Western Canadian Sedimentary Basin in the provinces of Alberta, British
Columbia and Saskatchewan in Canada, domestic natural gas produced within the
Williston Basin and synthetic gas produced at the Dakota Gasification plant in
North Dakota. In addition, the pipeline is capable of physically receiving
natural gas at two locations near Chicago. At its northern end, the pipeline
system's gas supplies are received through an interconnection with Foothills
Pipe Lines (Sask.)

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Ltd. system in Canada. The Foothills system, owned by TransCanada, is
connected to TransCanada's Alberta system and the pipeline system owned by
Transgas Limited in Saskatchewan. Also at the north end, the pipeline system
connects to a domestic natural gas gathering system owned by Omimex Ltd.
Corporation. In North Dakota, the Northern Border pipeline system connects
with facilities of Northern Natural Gas Company at Buford, which facilities
in turn are connected to Williston Basin Interstate Pipeline and the
gathering system owned by Bear Paw Energy, LLC, a wholly owned subsidiary of
Northern Border Partners. In December 2003, an interconnection with a newly
constructed pipeline owned by Williston Basin Interstate Pipeline near
Manning, North Dakota was placed in service. The initial design capacity of
the interconnect facilities is 200 mmcfd. The pipeline, with an initial
design capacity of 80 mmcfd, was constructed to transport natural gas from
coalbed and conventional natural gas supplies in the Powder River Basin of
northeastern Wyoming and southeastern Montana as well conventional supplies
in the Rocky Mountain area. Other locations in North Dakota where Northern
Border Pipeline can receive gas are interconnections with Williston Basin
Interstate Pipeline at Glen Ullin and Amerada Hess Corporation at Watford
City and facilities of Dakota Gasification Company at Hebron. Near its
terminus, the pipeline system is capable of physically receiving natural gas
from Northern Illinois Gas Company at Troy Grove, Illinois and from
Midwestern Gas Transmission Company, a wholly owned subsidiary of Northern
Border Partners, at Channahon, Illinois. For the year ended December 31,
2003, of the natural gas transported on the Northern Border pipeline system,
approximately 88% was produced in Canada, approximately 5% was produced by
the Dakota Gasification plant and approximately 6% was produced in the
Williston Basin and 1% from other sources.

INTERCONNECTS

The Northern Border pipeline system connects with multiple pipelines of various
interstate, intrastate and local distribution companies, as well as with
end-users. These interconnects provide its shippers with access to the various
natural gas markets served by those pipelines. The larger interconnections are
with the pipeline facilities of:

o Northern Natural Gas Company at Ventura, Iowa as well as multiple
smaller interconnections in South Dakota, Minnesota and Iowa;

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

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

o Alliant Power Company at Prophetstown, Illinois;

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

o Midwestern Gas Transmission Company near Channahon, Illinois;

o ANR Pipeline Company near Manhattan, Illinois;

o Vector Pipeline L.P. in Will County, Illinois;

o Guardian Pipeline, L.L.C., an affiliate of Northern Border Partners,
in Will County, Illinois;

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

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

Several market centers, where natural gas transported on the Northern Border
pipeline system is sold, traded and received for transport to significant
consuming markets in the Midwest and to interconnecting pipeline facilities,
have developed on the Northern Border pipeline system. The largest of these
market centers is at the Ventura, Iowa connection with Northern Natural Gas
Company. Two other market center locations are the Harper, Iowa connection with
Natural Gas Pipeline Company of America and the multiple interconnects in the
Chicago area that include connections with Northern Illinois Gas Company, The
Peoples Gas Light and Coke Company and Northern Indiana Public Service Company,
as well as four interstate pipelines.

SHIPPERS

The Northern Border pipeline system serves more than 40 firm transportation
shippers with diverse operating and financial profiles. Based upon shippers'
contractual obligations, as of December 31, 2003, 94% of the firm capacity is
contracted by producers and marketers. The remaining firm capacity is contracted
primarily by local distribution companies (5%), and interstate pipelines (1%).
As of December 31, 2003, the termination dates of these contracts ranged from
March 31, 2004 to December 21, 2013, and the weighted average contract life,
based upon contractual obligations, was approximately three and one-third years.
All of Northern Border Pipeline's capacity was under contract through December
31, 2003 and, assuming no extensions of existing contracts or execution of new
contracts, approximately 70% and 59% is under contract through December 31, 2004
and 2005 respectively. See

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Item 7. "Management's Discussion and Analysis of Financial Condition and Results
of Operations - Results of Operations of Northern Border Pipeline Company -
Overview."

Northern Border Pipeline's shippers may change throughout the year as a result
of its shippers utilizing Northern Border Pipeline's capacity release provisions
that allow them to release all or part of their capacity to other shippers,
either permanently for the full term of their contract or temporarily. Under the
terms of Northern Border Pipeline's tariff, a temporary capacity release does
not relieve the original contract shipper from its payment obligations if the
replacement shipper fails to pay.

For the year ended December 31, 2003, BP Canada Energy Marketing Corp. (BP
Canada), EnCana Marketing U.S.A. Inc. (EnCana), and Pan Alberta Gas (U.S.)
Inc. (Pan-Alberta) collectively accounted for approximately 41% of Northern
Border Pipeline's revenues. As of December 31, 2003, Northern Border
Pipeline's three largest shippers were BP Canada, EnCana and Cargill
Incorporated who are obligated for approximately 21%, 19% and 9%,
respectively, of the contracted firm capacity. In July 2003, Cargill
Incorporated completed the assignment of all the firm capacity formerly held
by Mirant Americas Energy Marketing, LP, which extends for terms into 2006
and 2008. Approximately half of the capacity contracted to BP Canada and
EnCana is due to expire by November 1, 2004. During 2003, all of the
contracted capacity due to expire by November 1, 2003, of which Pan-Alberta
held approximately 20% was recontracted with 10 shippers. See Item 7.
"Management's Discussion and Analysis of Financial Condition and Results of
Operations - Results of Operations of Northern Border Pipeline Company -
Overview."

DEMAND FOR TRANSPORTATION CAPACITY

Northern Border Pipeline's long-term financial condition is dependent on the
continued availability of economic western Canadian natural gas supplies for
import into the United States. Natural gas reserves may require significant
capital expenditures by others for exploration and development drilling and
the installation of production, gathering, storage, transportation and other
facilities that permit natural gas to be produced and delivered to pipelines
that interconnect with the interstate pipelines' systems. Prices for natural
gas, the currency exchange rate between Canada and the United States,
regulatory limitations or the lack of available capital for these projects
could adversely affect the development of additional reserves and production,
gathering, storage and pipeline transmission of western Canadian natural gas
supplies. Increased Canadian consumption of natural gas related to the
extraction process for oil sands projects as well as restrictions on gas
production to protect oil sand reserves could also impact supplies of natural
gas for export. Additional pipeline export capacity also could accelerate
depletion of these reserves. Furthermore, the availability of export capacity
could also affect the demand or value of the transport on the Northern Border
pipeline system.

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

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

o economic conditions;

o fuel conservation measures;

o alternative energy requirements and prices;

o gas storage inventory levels;

o climatic conditions;

o government regulation; and

o technological advances in fuel economy and energy generation devices.

Interstate pipelines' primary exposure to market risk occurs at the time
existing transportation contracts expire and are subject to renegotiation. A key
determinant of the value that customers can realize from firm transportation on
a pipeline is the basis differential, or market price spread, between two points
on the pipeline. The difference in natural gas prices between the points along
the pipeline where gas enters and where gas is delivered represents the gross
margin that a customer can expect to achieve from holding transportation
capacity at any point in time. This margin and its variability become important
factors in determining the transportation rate customers are willing to

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pay when they renegotiate their transportation contracts. The basis differential
between markets can be affected by trends in production, available capacity,
storage inventories, weather and general market demand in the respective areas.

Throughput on the Northern Border pipeline system may experience seasonal
fluctuations depending upon the level of winter heating load demand or summer
electric generation usage in the markets it serves. However, since
approximately 98% of Northern Border Pipeline's expected revenue is
attributable to demand charges, Northern Border Pipeline's revenues and cash
flows are not impacted materially by such seasonal throughput variations.

TC PipeLines cannot predict whether these or other factors will have an adverse
effect on demand for use of the Northern Border pipeline system or how
significant such adverse effect could be.

INTERSTATE PIPELINE COMPETITION

Northern Border Pipeline competes with other pipeline companies that
transport natural gas from the Western Canadian Sedimentary Basin or that
transport natural gas to end-use markets in the midwest. Northern Border
Pipeline's competitive position is affected by the availability of Canadian
natural gas for export, the availability of other sources of natural gas and
demand for natural gas in the United States. Demand for transportation
services on the Northern Border pipeline system is affected by natural gas
prices, the relationship between export capacity from and production in the
Western Canadian Sedimentary Basin and natural gas shipped from producing
areas in the United States. Shippers of natural gas produced in the Western
Canadian Sedimentary Basin also have other options to transport Canadian
natural gas to the United States, including transportation on the Alliance
Pipeline, on TransCanada's pipeline system through various interconnects with
U.S. interstate pipelines, including Viking Gas Transmission Company which is
owned by Northern Border Partners, or to markets on the West Coast.

The Alliance Pipeline competes directly with Northern Border Pipeline in the
transportation of natural gas from the Western Canadian Sedimentary Basin to the
Chicago area. Because it transports liquids-rich natural gas, the Alliance
Pipeline has no interconnections with other pipelines upstream of liquids
extraction facilities located near Chicago. This contrasts with the Northern
Border pipeline system, which serves various markets through interconnections
with other pipelines along its route. The Chicago market hub has absorbed the
new supply from Alliance Pipeline as incremental pipeline capacity has been
developed to transport natural gas from the Chicago area to other market
regions.

In addition, Northern Border Pipeline competes in its markets with other
interstate pipelines that provide access to other supply basins. Northern
Border Pipeline's major deliveries into Northern Natural Gas at Ventura, Iowa
compete with gas supplied from the Rockies, and mid-continent regions.
Northern Border Pipeline also competes with these supply basins at its
delivery interconnect with Natural Gas Pipeline at Harper, Iowa. In the
Chicago area, Northern Border Pipeline competes with many interstate
pipelines that transport gas from the Gulf Coast, mid-continent, Rockies and
western Canada.

FERC REGULATION

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

o transportation of natural gas;

o rates and charges;

o construction of new facilities;

o extension or abandonment of service and facilities;

o accounts and records;

o depreciation and amortization policies;

o the acquisition and disposition of facilities; and

o the initiation and discontinuation of services.

Where required, Northern Border Pipeline holds certificates of public
convenience and necessity issued by the

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FERC covering its facilities, activities and services. Under Section 8 of the
Natural Gas Act, the FERC has the power to prescribe the accounting treatment
for items for regulatory purposes. Northern Border Pipeline's books and records
may be periodically audited by the FERC under Section 8. Northern Border
Pipeline was notified in November 2002 that it was one of the companies selected
by the FERC to undergo an industry-wide audit of FERC-assessed annual charges.
The overall audit objective was to determine compliance with the FERC accounting
requirements and regulations as they relate to the calculation and assessment of
annual charges by validating the accuracy of the data filed annually with the
FERC. The audit covered the period of January 1, 2001 to December 31, 2001. On
April 10, 2003, the FERC issued its final report that found Northern Border
Pipeline was in compliance.

The FERC regulates the rates and charges for transportation in interstate
commerce. Natural gas companies may not charge rates exceeding rates judged just
and reasonable by the FERC. Generally, rates are based on the cost of service
including recovery of and a return on the pipeline's actual historical cost
investment. In addition, the FERC prohibits natural gas companies from unduly
preferring or unreasonably discriminating against any person with respect to
pipeline rates or terms and conditions of service. Some types of rates may be
discounted without further FERC authorization and rates may be negotiated
subject to FERC approval. The rates and terms and conditions for Northern Border
Pipeline's service are found in its FERC-approved tariff.

Transportation rates are established periodically in FERC proceedings known as
rate cases. Under Northern Border Pipeline's tariff, Northern Border Pipeline is
allowed to charge for its services on the basis of stated transportation rates
established in its 1999 rate case. Northern Border Pipeline may also provide
services under negotiated and discounted rates. Firm shippers that contract for
the stated transportation rate are obligated to pay a monthly demand charge,
regardless of the amount of natural gas they actually transport, for the term of
their contracts. Approximately 98% of the revenue generated is attributed to
demand charges. The remaining 2% of the agreed upon revenue level is attributed
to commodity charges based on the volumes of gas actually transported.

Under the terms of settlement in Northern Border Pipeline's 1999 rate case,
neither Northern Border Pipeline's existing shippers nor Northern Border
Pipeline can seek rate changes until November 1, 2005, at which time Northern
Border Pipeline must file a rate case. Prior to this rate case, Northern Border
Pipeline will not be permitted to increase rates if costs increase, nor will
Northern Border Pipeline be required to reduce rates based on cost savings. As a
result, Northern Border Pipeline's earnings and cash flow will depend on future
costs, contracted capacity, the volumes of gas transported and its ability to
recontract capacity at acceptable rates.

Until new depreciation rates are approved by the FERC, Northern Border
Pipeline continues to depreciate its transmission plant at the FERC-approved
annual depreciation rate. Northern Border Pipeline's annual depreciation rate
on transmission plant in service is 2.25%. In order to avoid a decline in
transportation rates set in future rate cases as a result of accumulated
depreciation, Northern Border Pipeline must maintain or increase its rate
base by acquiring or constructing assets that replace or add to existing
pipeline facilities or by adding new facilities.

In Northern Border Pipeline's 1995 rate case, the FERC addressed the issue of
whether the federal income tax allowance included in Northern Border Pipeline's
proposed cost of service was reasonable in light of previous FERC rulings. In
those rulings, the FERC held that an interstate pipeline is not entitled to a
tax allowance for income attributable to limited partnership interests held by
individuals. The settlement of Northern Border Pipeline's 1995 rate case
provided that until at least December 2005, Northern Border Pipeline could
continue to calculate the allowance for income taxes in the manner it had
historically used. In addition, a settlement adjustment mechanism was
implemented, which effectively reduced the return on rate base. These provisions
of the 1995 rate case were maintained in the settlement of Northern Border
Pipeline's 1999 rate case.

Northern Border Pipeline also provides interruptible transportation service.
Interruptible transportation service is transportation in circumstances when
capacity is available after satisfying firm service requests. The maximum
rate that may be charged to interruptible shippers is the sum of the firm
transportation maximum demand and commodity charges. From the settlement of
its 1999 rate case through October 31, 2003, Northern Border Pipeline shared
net interruptible transportation service revenue and any new services revenue
on an equal basis with its firm shippers, however, Northern Border Pipeline
was permitted to retain revenue from interruptible transportation service to
offset any decontracted firm capacity. Beginning November 1, 2003, Northern
Border Pipeline retains all revenues from these services.

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Northern Border Pipeline is subject to the requirements of FERC Order Nos.
497 and 566, which prohibit preferential treatment by interstate natural gas
pipelines of their marketing affiliates and govern how information may be
provided to those marketing affiliates. On November 25, 2003, the FERC issued
a final rule, Order No. 2004, adopting new standards of conduct for
transmission providers when dealing with their energy affiliates. All
transmission providers must comply with the standards of conduct by June 1,
2004. The standards of conduct are designed to prevent transmission providers
from giving undue preferences to any of their energy affiliates. The final
rule generally requires that transmission function employees operate
independently of the marketing function employees and energy affiliates. As
required of all transmission providers, Northern Border Pipeline posted a
compliance plan to its website on February 9, 2004. By definition, two of
Northern Border Pipeline's energy affiliates are Bear Paw Energy, LLC and
Crestone Energy L.L.C., both of which are gathering companies owned by
Northern Border Partners. Northern Border Pipeline's operator, Northern
Plains, provides after hours and weekend gas control services for Bear Paw
and Crestone that results in some cost savings to Northern Border Pipeline.
Northern Border Pipeline has requested a waiver to permit Northern Plains to
continue to provide after hours and weekend gas control services for Bear Paw
Energy and Crestone. If the waiver is not granted, the cost to maintain gas
control for Northern Border Pipeline will increase slightly. Several parties
have filed for rehearing on a number of issues, including whether gathering
companies should be included in the definition of energy affiliate.

On August 1, 2002, the FERC issued a Notice of Proposed Rulemaking regarding the
regulation of cash management practices of the natural gas and other companies
that it regulates. On June 26, 2003, the FERC issued an interim rule in that
proceeding that amended the FERC's regulations to provide for documentation
requirements for cash management programs and to implement new reporting
requirements. Specifically, under the interim rule, all cash management
agreements between regulated entities and their affiliates must be in writing,
must specify the duties and responsibilities of cash management participants and
administrators, must specify the methods for calculating interest and for
allocating interest income and expense, and must specify any restrictions on
deposits or borrowings by participants. A FERC-regulated entity must file with
the FERC any cash management agreements to which it is a party, as well as any
subsequent changes to such agreements. In addition, a FERC-regulated entity must
notify the FERC when its equity component of proprietary capital ratio falls
below 30%. Northern Border Pipeline does not have a cash management agreement
nor is Northern Border Pipeline required to have one and the FERC was
notified. Northern Border Pipeline advises that it does not expect that the
FERC policy will have an impact on Northern Border Pipeline's cash management
practices.

On July 17, 2002, the FERC issued a Notice of Inquiry Concerning Natural Gas
Pipeline Negotiated Rate Policies and Practices. Subsequently, the FERC
issued an order on July 25, 2003, modifying its prior policy on negotiated
rates. The FERC ruled that it would no longer permit the pricing of
negotiated rates based upon natural gas commodity price indices. Negotiated
rates based upon such indices may continue until the end of the contract
period for which such rates were negotiated, but such rates will not be
prospectively approved by the FERC. The FERC also imposed certain
requirements on other types of negotiated rate transactions to ensure that
the agreements embodying such transactions do not materially differ from the
terms and conditions set forth in the tariff of the pipeline entering into
the transaction. Since Northern Border Pipeline's business does not derive a
significant amount of its revenues from negotiated rate transactions,
Northern Border Pipeline advises that it does not expect this FERC ruling to
have a material effect on its business.

Recent FERC orders in proceedings involving other natural gas pipelines have
addressed certain aspects of the pipelines' creditworthiness provisions set
forth in their tariffs. In addition, industry groups, such as the North
American Energy Standards Board (NAESB), are studying creditworthiness
standards. On February 12, 2004, FERC issued a Notice of Proposed Rulemaking
to require interstate pipelines to follow standardized procedures for
determining the creditworthiness of their shippers. The proposed rule would
incorporate by reference ten consensus standards passed within NAESB and
would adopt additional standards requiring, among other things,
standardization of information shippers provide to establish credit,
collateral requirements for service, procedures for suspension and
termination for non-creditworthy shippers and procedures governing capacity
release transactions. Comments are due on the proposed rule by March 26,
2004. Recent FERC orders, and this proposed rule, support greater collateral
requirements for credit on shippers for the construction of new facilities by
a pipeline. The enactment of some of these standards may have the effect of
easing certain creditworthiness requirements and parameters currently
reflected in Northern Border Pipeline's tariff. Recent FERC orders have
indicated, however, that pipelines are free to negotiate credit terms
relative to the construction of new facilities by a pipeline, which are then
effective for the term of the contract and are not superceded by tariff
provisions once the facilities are

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completed. Northern Border Pipeline advises that, at this time, it cannot
predict the ultimate impact, if any, on Northern Border Pipeline of any
resulting final rule.

In February 2004, the FERC adopted new quarterly financial reporting
requirements and accelerated the filing date for interstate pipeline's annual
financial report. The quarterly reports will include a basic set of financial
statements and other selected data and will be submitted electronically. For
2004, each quarterly report will be due approximately 70 days following the
end of the quarter except for the first quarter report which is due on or
before July 9, 2004. Subsequent reports will be due 60 days after the end of
each quarter. The annual report previously required to be filed each year on
or before April 30, will be required on or before April 25, 2005 for 2004 and
on April 18 thereafter. Northern Border Pipeline advises that it does not
anticipate any impact for complying with these requirements other than the
time and additional expenses for preparation of these reports.

From time to time, Northern Border Pipeline files to make changes to its tariff
to clarify provisions, to reflect current industry practices and to reflect
recent FERC rulings. In February 2003, Northern Border Pipeline filed to amend
the definition of company use gas, which is gas supplied by Northern Border
Pipeline's shippers for the operation of its compressor stations, to clarify
the language by adding detail to the broad categories that comprise company
use gas. However, in its March 2003 order, the FERC directed Northern Border
Pipeline to cease collecting electric costs through its company use gas
provisions and to refund with interest, within 90 days, all electric costs
that had been collected through the company use gas provisions. Refunds of
approximately $10.0 million were made in May 2003.

In August 2003 Northern Border Pipeline filed revised tariff sheets to
clarify its procedures for the awarding of capacity. Several parties
protested the filing. One party requested a show cause proceeding to examine
past tariff practices alleging that Northern Border Pipeline had violated its
tariff by denying a service request that would have involved a short distance
for less than one year. On September 10, 2003, the FERC rejected Northern
Border Pipeline's tariff sheets based upon the conclusion that certain
aspects of the proposal were not in accordance with Commission policy. The
FERC did affirm that, up to ninety days prior to the effective date, Northern
Border Pipeline had the right not to sell capacity requested for short
distances or on a short-term basis. Northern Border Pipeline filed a timely
request for rehearing of the Commission's Order in October 2003 which is
still pending. Northern Border Pipeline also filed responses to requests for
further information on the award of capacity in the summer of 2003. Northern
Border Pipeline filed its compliance tariff sheets in early December 2003 and
is awaiting a Commission decision on these tariff sheets. Northern Border
Pipeline's tariff sheets and the final orders to be entered in this
proceeding will impact how Northern Border Pipeline awards available
capacity. With contracts expiring before November 1, 2004, if timely bids for
one year of service or longer on the entire transportation path available are
not received, Northern Border Pipeline advises that it may potentially be
required to accept bids for shorter distances that may result in creating
segments of capacity of miminal value.

In March 2004, Northern Border Pipeline filed tariff sheets to implement two
balancing services to assist deliveries at variable load points, such as
electrical generation plant. Northern Border Pipeline also filed with the
FERC certain agreements for third party balancing which it believes are
administrative in nature and which will be terminated upon approval of the
new balancing services. Under current orders and rulings in other proceedings
before the FERC, it is unclear whether these agreements would be deemed
non-conforming. However, Northern Border Pipeline advises that it does not
expect that orders on these tariff sheets and agreements will have a material
adverse impact on its business.

ENVIRONMENTAL AND SAFETY MATTERS

Northern Border Pipeline's operations are subject to federal, state and local
laws and regulations relating to safety and the protection of the environment,
which include the Resource Conservation and Recovery Act, the Comprehensive
Environmental Response, Compensation and Liability Act of 1980, as amended,
Clean Air Act, as amended, the Clean Water Act, as amended, the Natural Gas
Pipeline Safety Act of 1969, as amended, the Pipeline Safety Act of 1992 and the
Pipeline Safety Improvement Act of 2002.

The Pipeline Safety Improvement Act (Act) of 2002 was signed into law in
December 2002, providing guidelines for interstate pipelines in the areas of
risk analysis and integrity management, public education programs,
verification of operator qualification programs and filings with the National
Pipeline Mapping System. The Act requires pipeline companies to perform
integrity assessments on pipeline segments that exist in high population
density areas or near specifically identified sites that are designated as
high consequence areas. Pipeline companies are required to perform the
integrity assessments within ten years of the date of enactment and must
perform subsequent integrity assessments on a seven-year cycle. At least 50%
of the highest risk segments must be assessed within five years of the
enactment date. In addition, within one year of enactment, the pipeline's
operator qualification programs, in force since the mandatory compliance date
of October 2002, must also conform to standards provided by the Department of
Transportation. The regulations implementing the Act are not yet final. Rules
on integrity management, direct assessment usage, and the operator
qualification standards have been issued. Northern Border Pipeline has made
the required filings with the National Pipeline Mapping System and has
reviewed and revised its public education program. Compliance with the Act is
expected to increase Northern Border Pipeline's operating costs particularly
related to integrity assessments for its interstate pipeline. As required,
Northern Border Pipeline has developed an overall plan for pipeline integrity
management. The detailed analysis is being performed to determine the
priorities and costs for inspecting and testing its pipeline. However, the
plan will be modified as a result of the findings noted and could result in
additional assessment or remediation costs. Although TC PipeLines expects
Northern Border Pipeline to include these costs in future rate case filings,
total recovery is not assured. Northern Border Pipeline advises that,
presently, it expects its costs for 2004 for integrity assessments to be
approximately $0.5 million.

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TC PipeLines believes that Northern Border Pipeline's operations and
facilities are in general compliance in all material respects with applicable
environmental and safety regulations, however, risks of substantial costs and
liabilities are inherent in pipeline operations, and TC PipeLines cannot
provide any assurances that Northern Border Pipeline will not incur such
costs and liabilities. Moreover, it is possible that other developments, such
as the enactment of increasingly strict environmental and safety laws,
regulations and enforcement policies by Congress, the FERC, the Department of
Transportation and other federal agencies, state regulatory bodies and the
courts, and claims for damages to property or persons resulting from Northern
Border Pipeline's operations, could result in substantial costs and
liabilities to Northern Border Pipeline. If Northern Border Pipeline is
unable to recover such resulting costs, earnings and cash distributions could
be adversely affected.

BUSINESS OF TUSCARORA GAS TRANSMISSION COMPANY

Tuscarora is a Nevada general partnership formed in 1993. Its general
partners are TC Tuscarora Intermediate Limited Partnership, a direct
subsidiary of TC PipeLines, which holds a 49% general partner interest,
Tuscarora Gas Pipeline Co., a wholly owned subsidiary of Sierra Pacific
Resources, which holds a 50% general partner interest and TCPL Tuscarora
Ltd., an indirect wholly owned subsidiary of TransCanada, which holds a 1%
general partner interest.

The management of Tuscarora is overseen by a management committee that
determines the policies of, has authority over the affairs of, and approves
the actions of Tuscarora. The management committee participates in the
management of the construction, maintenance and operation of the Tuscarora
pipeline system.

Under the Tuscarora partnership agreement, voting control is allocated among
Tuscarora's three general partners in proportion to their general partner
interests in Tuscarora. As a result, TC PipeLines has a 49% voting interest,
Sierra Pacific Resources has a 50% voting interest, and TransCanada has a 1%
voting interest on the Tuscarora management committee. Tuscarora Gas Operating
Company, a subsidiary of Sierra Pacific Resources, operates the Tuscarora
pipeline system pursuant to an operating agreement. Effective December 1, 2002,
TransCanada is under contract to provide gas control services for the Tuscarora
pipeline system, including monitoring and control of the compressor units, as
well as emergency call out functions and other operational co-ordination.

THE TUSCARORA PIPELINE SYSTEM

Tuscarora owns a 240-mile, 20-inch diameter, United States interstate pipeline
system that originates at an interconnection point with facilities of Gas
Transmission Northwest Corporation (GTN) near Malin, Oregon and runs southeast
through northeastern California and northwestern Nevada. The Tuscarora pipeline
system terminates near Wadsworth, Nevada. Deliveries are also made directly to
the local gas distribution system of Sierra Pacific Power Company, a
subsidiary of Sierra Pacific Resources. Along its route, deliveries are made
in Oregon, northern California and northwestern Nevada.

The Tuscarora pipeline system was constructed in 1995 and was placed into
service in December 1995. The Tuscarora pipeline system has firm capacity
contracts to transport approximately 180 mmcfd of natural gas.

On December 1, 2002, Tuscarora completed and placed into service an expansion
of its pipeline system. This expansion consisted of two compressor stations
and an 11-mile pipeline extension from the previous terminus of the Tuscarora
pipeline system near Reno, Nevada to Wadsworth, Nevada. The expansion
increased Tuscarora's contracted capacity from 127 mmcfd to approximately 180
mmcfd. The new capacity was contracted under long-term firm transportation
contracts ranging from ten to fifteen years from the in-service date. Sierra
Pacific Power had contracted for approximately 11 mmcfd of the expansion
capacity. The project had a capital budget of approximately $43.0 million and
was completed at a capital cost of approximately $39.0 million. At the
request of the Public Utilities Commission of Nevada, Tuscarora will submit a
cost and revenue study to the FERC within 3 years of the in-service date of
the expansion.

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Tuscarora has firm transportation contracts for over 94% of its capacity,
including contracts held by Sierra Pacific Power for 68.1% of the total
available capacity, the majority of which expires on November 30, 2015. As of
December 31, 2003, the weighted average contract life on the Tuscarora pipeline
system was approximately 11.5 years.

In June 2003, Tuscarora held an open season to determine the demand for
incremental firm capacity by winter 2005. The open season resulted in the
execution of firm transportation service agreements for a net increase of
approximately 50 mmcfd. Tuscarora has begun preliminary planning activities
for construction of additional facilities to meet the additional capacity
requirements. Tuscarora has advised that it anticipates that an application
for a Certificate of Public Convenience and Necessity for authorization to
construct and operate the new pipeline facilities, will be filed with the
FERC by the second quarter 2004. Construction of the project is anticipated
to commence in late spring of 2005, with newly commissioned facilities on
line by November 1, 2005. Total capital cost is estimated to be approximately
$16.6 million. This expansion project will increase Tuscarora's contracted
capacity by approximately 28%.

Tuscarora's competitive position is dependent on the continued availability of
commercially attractive western Canadian natural gas for import into the United
States and on the level of demand for western Canadian natural gas in the
markets the Tuscarora pipeline system serves. Shippers of natural gas from the
Western Canadian Sedimentary Basin have other options for transporting Canadian
natural gas to the United States, including transportation on pipelines eastward
in Canada or to markets on the west coast of the United States and Canada.
Similarly, natural gas produced in the United States serves the same markets as
Tuscarora in northern Nevada. Tuscarora is able to transport both Canadian and
United States natural gas, providing Tuscarora with a well-diversified supply of
natural gas to serve its markets.

FERC REGULATION

Tuscarora is subject to regulation by the FERC as a "natural gas company" under
the Natural Gas Act, and is subject to the FERC's rules, regulations and
accounting procedures.

Tuscarora generates revenues from individual transportation contracts with
shippers that provide for the receipt and delivery of natural gas at points
along the Tuscarora pipeline system. Tuscarora's transportation rates are based
on its cost of service as approved by the FERC. Tuscarora's cost of service
includes administrative and operating costs, depreciation and amortization,
taxes other than income taxes, an allowance for income taxes and a regulated
return on capital employed.

On November 25, 2003, the FERC issued a final rule, Order No. 2004, adopting
new standards of conduct for transmission providers when dealing with their
energy affiliates. All transmission providers must comply with the standards
of conduct by June 1, 2004. The standards of conduct are designed to prevent
transmission providers from giving undue preferences to any of their energy
affiliates. The final rule generally requires that transmission function
employees operate independently of the marketing function employees and
energy affiliates. Tuscarora advises that it will be in compliance with these
new standards by June 1, 2004.

In February 2004, the FERC amended its financial reporting regulations to
establish new quarterly financial reporting requirements. The reports will
include a basic set of financial statements and other selected data and will
be submitted electronically. The first report for Tuscarora will be due on or
before July 23, 2004. Tuscarora advises that it does not anticipate any
impact from complying with these requirements other than the time and
additional expenses for preparation of these reports.

ENVIRONMENTAL AND SAFETY MATTERS

Tuscarora's operations are subject to federal, state and local laws and
regulations relating to safety and protection of the environment. TC PipeLines
believes that Tuscarora's operations and facilities comply in all material
respects with applicable United States environmental and safety regulations.

AVAILABLE INFORMATION

The Partnership's annual report on Form 10-K, quarterly reports on Form 10-Q,
current reports on Form 8-K and any amendments to these reports filed or
furnished pursuant to Section 13(a) or 15(d) of the Exchange Act are made
available free of charge on the Partnership's website at
www.tcpipelineslp.com/investor/reports.htm as soon as reasonably practicable
after the Partnership electronically files these materials with, or furnishes
them to, the Securities and Exchange Commission (SEC).

ITEM 2. PROPERTIES

TC PipeLines does not hold the right, title or interest in any properties.

PROPERTIES OF NORTHERN BORDER PIPELINE COMPANY

Northern Border Pipeline holds the right, title and interest in its pipeline
system. With respect to real property, the pipeline system falls into two basic
categories: (a) parcels which are owned in fee, such as sites for compressor
stations, meter stations, pipeline field offices, and microwave towers; and (b)
parcels where the interest derives from leases, easements, rights-of-way,
permits or licenses from landowners or governmental authorities permitting the
use of such land for the construction and operation of the pipeline system. The
right to construct and operate the pipeline system across certain property was
obtained 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, although Northern Border Pipeline may not have the power of
eminent domain with respect to Native American tribal lands.

Approximately 90 miles of the Northern Border pipeline system 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

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United States for the Fort Peck Tribes and allotted lands are lands owned in
trust by the United States for an individual Indian or Indians. Northern Border
Pipeline does have the right of eminent domain with respect to allotted lands.

In 1980, Northern Border Pipeline entered into a pipeline right-of-way lease
with the Fort Peck Tribal Executive Board, for and on behalf of the
Assiniboine and Sioux Tribes of the Fort Peck Indian Reservation (Tribes).
This pipeline right-of-way lease, which was approved by the Department of the
Interior in 1981, granted to Northern Border Pipeline the right and privilege
to construct and operate its pipeline on certain tribal lands. This pipeline
right-of-way lease expires in 2011. See Item 3. "Legal Proceedings."

In conjunction with obtaining a pipeline right-of-way lease across tribal lands
located within the exterior boundaries of the Fort Peck Indian Reservation,
Northern Border Pipeline also obtained a right-of-way across allotted lands
located within the reservation boundaries. Most of the allotted lands are
subject to a perpetual easement either granted by the Bureau of Indian Affairs
for and on behalf of individual Indian owners or obtained through condemnation.
Several tracts are subject to a right-of-way grant that has a term of 15 years,
expiring in 2015.

PROPERTIES OF TUSCARORA GAS TRANSMISSION COMPANY

Tuscarora holds the right, title and interest in its pipeline system. Tuscarora
owns all of its material equipment and personal property and leases office space
in Reno, Nevada. With respect to real property, Tuscarora's ownership falls into
two basic categories: (a) parcels which it owns in fee; and (b) parcels where
its interest derives from leases, easements, grants, permits or licenses from
landowners or governmental authorities permitting the use of the land for the
construction and operation of its pipeline system.

ITEM 3. LEGAL PROCEEDINGS

TC PipeLines is not currently a party to any material legal proceedings.

On July 31, 2001, the Tribes of the Fort Peck Indian Reservation filed a
lawsuit in Tribal Court against Northern Border Pipeline to collect more than
$3.0 million in back taxes, together with interest and penalties. The lawsuit
relates to a utilities tax on certain of Northern Border Pipeline's
properties within the Fort Peck Indian Reservation. Northern Border Pipeline
and the Tribes, through a mediation process, reached a settlement in
principle on pipeline right-of-way lease and taxation issues. Final
documentation has been completed and is subject to the approval of the Bureau
of Indian Affairs, which the parties believe will be obtained in the very
near term. This settlement grants to Northern Border Pipeline, among other
things, (i) an option to renew the pipeline right-of-way lease upon agreed
terms and conditions on or before April 1, 2011 for a term of 25 years with a
renewal right for an additional 25 years; (ii) a present right to use
additional tribal lands for expanded facilities; and (iii) release and
satisfaction of all tribal taxes against Northern Border Pipeline. In
consideration of this option and other benefits, Northern Border Pipeline
will pay a lump sum amount of $5.9 million and an annual amount of
approximately $1.5 million beginning April 2004. Northern Border Pipeline
advises that it intends to seek regulatory recovery of the costs resulting
from the settlement. See Item 7. "Management's Discussion and Analysis of
Financial Condition and Results of Operations - Risk Factors and Cautionary
Statement Regarding Forward-Looking Statements."

See Item 1. "Business - Business of Northern Border Pipeline Company - FERC
Regulation" for a discussion on the proceeding before the FERC.

Northern Border Pipeline advises that it is not currently party to any other
legal proceedings that, individually or in the aggregate, would reasonably be
expected to have a material adverse impact on it or TC PipeLines' results of
operations or financial position.

Tuscarora is not currently a party to any material legal proceedings.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

There were no matters submitted to a vote of security holders, through
solicitation of proxies or otherwise, during the year ended December 31, 2003.

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PART II

ITEM 5. MARKET FOR REGISTRANT'S COMMON UNITS AND RELATED SECURITY HOLDER MATTERS

The common units representing limited partner interests in the Partnership were
issued pursuant to an initial public offering on May 28, 1999 at a price of
$20.50 per common unit. The common units are quoted on the Nasdaq Stock Market
and trade under the symbol "TCLP."

The following table sets forth, for the periods indicated, the high and low sale
prices per common unit, as reported by the Nasdaq Stock Market, and the amount
of cash distributions per common unit declared with respect to the corresponding
periods. Cash distributions are paid within 45 days after the end of each
quarter to unitholders of record as of the record date.

As of February 23, 2004, there were 97 record holders of common units and
approximately 7,500 beneficial owners of common units, including common units
held in street name.

The Partnership currently has 16,563,564 common units outstanding, of which
11,890,694 are held by the public, 2,800,000 are held by an affiliate of the
general partner, and 1,872,870 are held by the general partner. The Partnership
also has 936,436 subordinated units outstanding, all of which are held by the
general partner, for which there is no established public trading market. The
common units and the subordinated units represent an aggregate 98% limited
partner interest and the general partner interest represents an aggregate 2%
general partner interest in the Partnership.

The general partner receives 2% of all cash distributions and the holders of
common units and subordinated units (collectively referred to as unitholders)
receive the remaining 98% of all cash distributions. The general partner is
also entitled to incentive distributions as described below. The
Partnership's quarterly cash distributions to its unitholders are comprised
of all of its Available Cash. Available Cash is defined in the partnership
agreement and generally means, with respect to any quarter of the
Partnership, all cash on hand at the end of a quarter less the amount of cash
reserves that are necessary or appropriate, in the reasonable discretion of
the general partner, to:

o provide for the proper conduct of the business of the Partnership
(including reserves for future capital expenditures and for
anticipated credit needs);

o comply with applicable laws or any Partnership debt instrument or
agreement; or

o provide funds for cash distributions to unitholders and the general
partner in respect of any one or more of the next four quarters.

Distributions of Available Cash to the holder of subordinated units are subject
to the prior rights of the holders of common units to receive the minimum
quarterly distribution for each quarter while the subordinated units are
outstanding (subordination period), and to receive any arrearages in the cash
distribution of minimum quarterly distributions on the common units for prior
quarters during the subordination period. The partnership agreement defines the
minimum quarterly distribution as $0.45 for each full fiscal quarter.

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The general partner receives incentive distributions if the amount distributed
with respect to any quarter exceeds the minimum quarterly distribution of $0.45
per unit. Under the incentive distribution provisions, the general partner
receives 15% of amounts distributed in excess of $0.45 per unit, 25% of amounts
distributed in excess of $0.5275 per unit, and 50% of amounts distributed in
excess of $0.69 per unit provided the balance has been first distributed to
unitholders on a pro rata basis. The amounts that trigger incentive
distributions at various levels are subject to adjustment in certain events, as
described in the partnership agreement.

In 2003, the Partnership made cash distributions to unitholders and the general
partner that amounted to $39.4 million compared to $37.4 million in 2002. These
payments represented $0.525 per unit for the quarters ended December 31, 2002
and March 31, 2003 and $0.55 per unit for the quarters ended June 30, 2003 and
September 30, 2003. On February 13, 2004, the Partnership paid a cash
distribution of $10.1 million to unitholders and the general partner,
representing a cash distribution of $0.55 per unit for the quarter ended
December 31, 2003. The distribution was allocated in the following manner: $9.1
million to the holders of common units as of the close of business on January
30, 2004 (including $1.5 million to an affiliate of the general partner as
holder of 2,800,000 common units and $1.0 million to the general partner as
holder of 1,872,870 common units), $0.5 million to the general partner as holder
of the subordinated units, $0.3 million to the general partner as holder of
incentive distribution rights, and $0.2 million to the general partner in
respect of its 2% general partner interest.

SUBORDINATION PERIOD

The subordination period extends until the first day of any quarter beginning
after June 30, 2004 in respect of which:

o distributions of Available Cash from operating surplus on the common
units and the subordinated units for each of the three non-overlapping
four-quarter periods immediately preceding that date equaled or
exceeded the sum of the minimum quarterly distribution on all of the
outstanding common units and subordinated units during those periods;

o the adjusted operating surplus generated during each of the three
non-overlapping four-quarter periods immediately preceding that date
equaled or exceeded the sum of the minimum quarterly distribution on
all of the common units and the subordinated units that were
outstanding on a fully diluted basis and the related distributions on
the general partner interest during those periods; and

o there are no arrearages in payment of the minimum quarterly
distribution on the common units.

On August 1, 2002, 936,435 subordinated units, representing one-third of the
outstanding subordinated units held by the general partner, upon satisfaction of
the financial tests set forth in the partnership agreement of TC PipeLines,
automatically converted into an equal number of common units.

On August 1, 2003, an additional 936,435 subordinated units held by the general
partner, upon satisfaction of the financial tests set forth in the partnership
agreement, automatically converted into an equal number of common units.

The remaining 936,436 outstanding subordinated units will, upon satisfaction
of the financial tests, automatically convert into common units on the first
day after the record date for distributions for the quarter ending June 30,
2004, and will thereafter participate, pro rata, with the other common units
in distributions of Available Cash.

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ITEM 6. SELECTED FINANCIAL DATA

The selected financial data should be read in conjunction with the financial
statements, including the notes thereto, and Item 7. "Management's Discussion
and Analysis of Financial Condition and Results of Operations."

(1) The Partnership commenced operations on May 28, 1999.

(2) The Partnership acquired a 49% interest in Tuscarora on September 1, 2000.

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS

AS A RESULT OF THE PARTNERSHIP'S OWNERSHIP OF INVESTMENTS IN BOTH NORTHERN
BORDER PIPELINE AND TUSCARORA, THE FOLLOWING DISCUSSES FIRST THE RESULTS OF
OPERATIONS AND LIQUIDITY AND CAPITAL RESOURCES OF TC PIPELINES, THEN THOSE OF
EACH OF NORTHERN BORDER PIPELINE AND TUSCARORA IN THEIR ENTIRETY.

The following discussions of the financial condition and results of operations
of the Partnership, Northern Border Pipeline and Tuscarora should be read in
conjunction with the financial statements and notes thereto of the Partnership
and Northern Border Pipeline included elsewhere in this report (see Item 8.
"Financial Statements and Supplementary Data"). For more detailed information
regarding the basis of presentation for the following financial information, see
the notes to the financial statements of the Partnership and Northern Border
Pipeline. As of December 31, 2003, TC PipeLines' interest in Northern Border
Pipeline represents approximately 84% of TC PipeLines' total assets and for the
year ended December 31, 2003 provided approximately 89% of TC PipeLines' equity
income. All amounts are stated in United States dollars.

OVERVIEW

TC PipeLines, LP owns a 30% general partner interest in Northern Border
Pipeline Company. The remaining 70% general partner interest in Northern
Border Pipeline is held by Northern Border Partners, L.P., a publicly traded
limited partnership that is controlled by affiliates of Enron Corp.
TransCanada

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holds a minority general partner interest in Northern Border Partners which
entitles it to 12.25% of the voting power of Northern Border Pipeline.
Northern Border Pipeline owns a 1,249-mile interstate pipeline system that
transports natural gas from the Montana-Saskatchewan border near Port of
Morgan, Montana to natural gas markets in the midwestern United States.
Construction of the pipeline was initially completed in 1982. The Northern
Border pipeline system was expanded and/or extended in 1991, 1992, 1998 and
2001. The Northern Border pipeline system connects directly and through
multiple pipelines to various natural gas markets in the United States.

TC PipeLines also owns a 49% general partner interest in Tuscarora Gas
Transmission Company. The Partnership acquired this interest from TCPL
Tuscarora Ltd., an indirect subsidiary of TransCanada, in September 2000.
Tuscarora owns a 240-mile, 20-inch diameter, United States interstate
pipeline system that originates at an interconnection point with facilities
of Gas Transmission Northwest Corporation (GTN) near Malin, Oregon and runs
southeast through northeastern California and northwestern Nevada. The
Tuscarora pipeline system terminates near Wadsworth, Nevada. Deliveries are
also made directly to the local gas distribution system of Sierra Pacific
Resources. Along its route, deliveries are made in Oregon, northern
California and northwestern Nevada.

The Tuscarora pipeline system was constructed in 1995 and was placed into
service in December 1995. In January 2001, Tuscarora completed construction
of the Hungry Valley lateral, a 14-mile, 16-inch pipeline extension that
serves as Tuscarora's second connection into Reno, Nevada. On December 1,
2002, Tuscarora completed and placed into service another expansion of its
pipeline system. The 2002 expansion consisted of two compressor stations and
an 11-mile pipeline extension from the previous terminus of the Tuscarora
pipeline system near Reno, Nevada to Wadsworth, Nevada. The expansion
increased Tuscarora's contracted capacity from 127 mmcfd to approximately 180
mmcfd. The new capacity is contracted under long-term firm transportation
contracts.

The Partnership's 30% general partner interest in Northern Border Pipeline and
49% general partner interest in Tuscarora represent its only material assets.
As a result, the Partnership is dependent upon Northern Border Pipeline and
Tuscarora for all of its available cash. Northern Border Pipeline represents
approximately 90% of TC Pipelines' equity income. For an overview discussing
the important factors impacting Northern Border Pipeline's business, such as
the continued availability of western Canadian natural gas and demand
therefore in the U.S., see "Results of Operations of Northern Border Pipeline
Company - Overview" below.

RESULTS OF OPERATIONS OF TC PIPELINES, LP

CRITICAL ACCOUNTING POLICY

TC PipeLines accounts for its investments in both Northern Border Pipeline and
Tuscarora using the equity method of accounting as detailed in Note 3 and Note 4
to the Partnership's Financial Statements, included elsewhere in this report.
The equity method of accounting is appropriate where the investor does not
control an investee, but rather is able to exercise significant influence over
the operating and financial policies of an investee. TC PipeLines is able to
exercise significant influence over its investments in Northern Border Pipeline
and Tuscarora as evidenced by its representation on their respective management
committees.

Since the 30% general partner interest in Northern Border Pipeline and the 49%
general partner interest in Tuscarora are currently the Partnership's only
material sources of income, the Partnership's results of operations are
influenced by and reflect the same factors that influence the financial results
of Northern Border Pipeline and Tuscarora (see Item 1. "Business - Business of
Northern Border Pipeline Company" and "Business - Business of Tuscarora Gas
Transmission Company").

YEAR ENDED DECEMBER 31, 2003 COMPARED WITH THE YEAR ENDED DECEMBER 31, 2002

Net income increased $2.5 million, or 5%, to $48.0 million for the year ended
December 31, 2003, compared to $45.5 million for 2002. The increase is primarily
due to higher equity income from the Partnership's investments in Northern
Border Pipeline and Tuscarora.

Equity income from the Partnership's investment in Northern Border Pipeline
increased $1.7 million, or 4%, to $44.5 million for the year ended December 31,
2003 compared to $42.8 million for 2002. Northern Border Pipeline's revenues for
2003 were higher than the same period last year due to the uncollected revenues
associated with the transportation capacity previously held by Enron North
America which reduced 2002 revenues, as well as additional incremental
revenues received in 2003. These factors increased the Partnership's 2003
equity income by $0.9 million. Also, Northern Border Pipeline's interest
expense was lower during 2003 compared to the same period last year due
primarily to lower average interest rates and lower average debt balances
outstanding, resulting in an increase of $2.0 million to the Partnership's
equity income. These increases were partially offset by higher operations and
maintenance expenses and taxes other than income as well as a decrease in
other income. The increase in 2003 operations and maintenance expense is
primarily due to a provision recorded by Northern Border

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Pipeline in 2003 related to its share of Enron's cash balance plan
underfunding (see "Results of Operations of Northern Border Pipeline Company -
Impact of Enron's Chapter 11 Filing on Northern Border Pipeline's Business"),
partially offset by lower electric power costs in 2003 as compared to 2002,
resulting in a net decrease to the Partnership's equity income of $0.3
million. The increase in 2003 taxes other than income is primarily due to a
refund of use taxes received by Northern Border Pipeline during 2002 as well
as higher property taxes in 2003 as compared to 2002. These increases resulted
in a decrease in equity income to the Partnership of $0.4 million. Other
income (expense) was lower during 2003 as compared to the prior year. The 2003
amount includes interest expense for refunds required by the order issued by
the FERC on March 27, 2003 (see Item 1. "Business - Business of Northern
Border Pipeline Company - FERC Regulation") whereas the 2002 amount includes
income mostly related to interest received on the refund of use taxes
previously discussed and income for previously vacated frequency bands. The
impact on the Partnership of this decrease in other income was a $0.5 million
reduction in equity income from Northern Border Pipeline.

Equity income from the Partnership's investment in Tuscarora increased $0.6
million, or 13%, to $5.3 million for the year ended December 31, 2003, compared
to $4.7 million for the prior year. Tuscarora's revenues increased primarily due
to new transportation contracts from the expansion, increasing the Partnership's
equity income from Tuscarora by $3.2 million. This increase was partially offset
by increased operations and maintenance expense and increased depreciation
expense, both resulting from Tuscarora's expansion. The combined effect of these
increased expenses reduced the Partnership's equity income from Tuscarora by
$1.8 million. In addition, higher interest expense due to Tuscarora's expansion,
partially offset by a decrease in Tuscarora's other income, resulted in a $0.8
million reduction in the Partnership's equity income for the year ended December
31, 2003.

The Partnership recorded general and administrative expenses of $1.7 million and
$1.5 million for the years ended December 31, 2003 and 2002, respectively.

The Partnership recorded financial charges of $0.1 million and $0.5 million for
the years ended December 31, 2003 and 2002, respectively. This decrease is
primarily attributed to the Partnership repaying $6.0 million of the balance
outstanding on its Revolving Credit Facility during 2003, which reduced the
balance outstanding from $11.5 million to $5.5 million.

YEAR ENDED DECEMBER 31, 2002 COMPARED WITH THE YEAR ENDED DECEMBER 31, 2001

Net income increased $2.0 million, or 5%, to $45.5 million for the year ended
December 31, 2002, compared to $43.5 million for 2001. The increase is primarily
due to higher equity income from the Partnership's investments in Northern
Border Pipeline and Tuscarora.

Equity income from the Partnership's investment in Northern Border Pipeline
increased $0.7 million, or 2%, to $42.8 million for the year ended December 31,
2002 compared to $42.1 million for 2001. Northern Border Pipeline's revenues
increased in 2002 due to Project 2000, Northern Border Pipeline's expansion and
extension that was placed into service in October 2001. This had the impact of
increasing the Partnership's 2002 equity income by approximately $2.4 million.
Also, favorable interest rates decreased Northern Border Pipeline's interest
expense in 2002 further increasing 2002 equity income to the Partnership by $1.1
million. These increases were largely offset by a reserve recorded by Northern
Border Pipeline in 2002 for costs that arose from the treatment of previously
collected quantities of natural gas used in utility operations to cover
electric power costs, resulting in a $3.0 million decrease in 2002 equity
income to the Partnership (see Item 1. "Business - Business of Northern Border
Pipeline Company - FERC Regulation").

Equity income from the Partnership's investment in Tuscarora increased $1.1
million, or 31%, to $4.7 million for the year ended December 31, 2002, compared
to $3.6 million for 2001. This increase is attributed to incremental revenue
from new transportation contracts, the completion of Tuscarora's expansion
facilities, which were placed into service on December 1, 2002, as well as lower
interest expense, resulting from the capitalization of interest expense related
to funds being used for the expansion.

The Partnership recorded general and administrative expenses of $1.5 million and
$1.2 million for the years ended December 31, 2002 and 2001, respectively.

The Partnership recorded financial charges of $0.5 million and $1.0 million for
the years ended December 31, 2002 and 2001, respectively. This decrease is
primarily attributed to the Partnership repaying $10.0 million of the balance

- 18 -

outstanding on its Revolving Credit Facility during 2002, which reduced the
balance outstanding from $21.5 million to $11.5 million, and to lower average
interest rates during 2002.

LIQUIDITY AND CAPITAL RESOURCES OF TC PIPELINES, LP

CASH DISTRIBUTION POLICY OF TC PIPELINES

During the subordination period, which generally cannot end before June 30,
2004, the Partnership makes distributions of Available Cash in the following
manner:

o First, 98% to the common units, pro rata, and 2% to the general
partner, until there is distributed for each outstanding common unit
an amount equal to the minimum quarterly distribution for that
quarter;

o Second, 98% to the common units, pro rata, and 2% to the general
partner, until there is distributed for each outstanding common unit
an amount equal to any arrearages in payment of the minimum quarterly
distribution on the common units for that quarter and for any prior
quarters during the subordination period;

o Third, 98% to the subordinated units, pro rata, and 2% to the general
partner, until there is distributed for each outstanding subordinated
unit an amount equal to the minimum quarterly distribution for that
quarter; and

o Thereafter, in a manner whereby the general partner has rights
(referred to as incentive distribution rights) to receive increasing
percentages of excess quarterly cash distributions over specified cash
distribution thresholds.

The general partner receives incentive distributions if the amount distributed
with respect to any quarter exceeds the minimum quarterly distribution of $0.45
per unit. Under the incentive distribution provisions, the general partner
receives 15% of amounts distributed in excess of $0.45 per unit, 25% of amounts
distributed in excess of $0.5275 per unit, and 50% of amounts distributed in
excess of $0.69 per unit provided the balance has been first distributed to
unitholders on a pro rata basis. The amounts that trigger incentive
distributions at various levels are subject to adjustment in certain events, as
described in the partnership agreement.

CONVERSION OF SUBORDINATED UNITS

On August 1, 2002, 936,435 subordinated units, representing one-third of the
outstanding subordinated units held by the general partner, upon satisfaction of
the financial tests set forth in the partnership agreement of TC PipeLines,
automatically converted into an equal number of common units.

On August 1, 2003, an additional 936,435 subordinated units held by the general
partner, upon satisfaction of the financial tests set forth in the partnership
agreement, automatically converted into an equal number of common units.

The remaining 936,436 outstanding subordinated units will, upon satisfaction
of the financial tests, automatically convert into common units on the first
day after the record date for distributions for the quarter ending June 30,
2004, and will thereafter participate, pro rata, with the other common units
in distributions of Available Cash.

GENERAL

On January 30, 2004, the Partnership paid $19.5 million related to its 30%
share of a capital contribution to Northern Border Pipeline in response to a
$65.0 million cash call issued by Northern Border Pipeline to its partners on
January 27, 2004. Northern Border Pipeline advises that the funds will be
used to repay a portion of its existing indebtedness under the 2002 Pipeline
Credit Agreement. This payment was funded through the use of cash from
operations and existing credit facilities.

On January 16, 2004, the board of directors of the general partner declared the
Partnership's 2003 fourth quarter cash distribution. The fourth quarter cash
distribution, which was paid on February 13, 2004 to unitholders of record as of
January 30, 2004, totaled $10.1 million and was paid in the following manner:
$9.1 million to common unitholders (including $1.5 million to an affiliate of
the general partner as holder of 2,800,000 common units and $1.0 million to the
general partner as holder of 1,871,870 common units), $0.5 million to the
general partner as holder of the subordinated units, $0.3 million to the general
partner as the holder of incentive distribution rights, and $0.2 million to the
general partner in respect of its 2% general partner interest.

- 19 -

SUMMARY OF CERTAIN CONTRACTUAL OBLIGATIONS

DEBT AND CREDIT FACILITIES

On May 28, 2003, the Partnership renewed its $40.0 million unsecured two-year
revolving credit facility (TransCanada Credit Facility) with TransCanada
PipeLine USA Ltd., an affiliate of the general partner. The TransCanada Credit
Facility bears interest at the London Interbank Offered Rate (LIBOR) plus
1.25%. The purpose of the TransCanada Credit Facility is to provide
borrowings to fund capital expenditures, to fund capital contributions to
Northern Border Pipeline, Tuscarora and any other entity in which the
Partnership directly or indirectly acquires an interest, to fund working
capital and for other general business purposes, including temporary funding
of cash distributions to unitholders and the general partner, if necessary.
At December 31, 2003 and 2002, the Partnership had no borrowings outstanding
under the TransCanada Credit Facility. As at March 12, 2004, $9.0 million is
outstanding under the TransCanada Credit Facility.

On March 8, 2004, the Partnership renewed its unsecured credit facility
(Revolving Credit Facility) with Bank One, NA, as administrative agent. Under
the Revolving Credit Facility, the Partnership may borrow up to an aggregate
principal amount of $30.0 million. Loans under the Revolving Credit Facility
may bear interest, at the option of the Partnership, at a one-, two-, three-,
or six-month LIBOR plus 1.25%, or at a floating rate based on the higher of
the federal funds effective rate plus 0.5% and the prime rate. The Revolving
Credit Facility matures on February 28, 2006. Amounts borrowed may be repaid
in part or in full prior to that time without penalty. The Revolving Credit
Facility may be used to finance capital expenditures and for other general
purposes. The Partnership had $5.5 million and $11.5 million outstanding
under the Revolving Credit Facility at December 31, 2003 and 2002,
respectively. The interest rate on the Revolving Credit Facility at December
31, 2003 and 2002 was 2.4% and 2.7%, respectively. As at March 12, 2004, $5.5
million is outstanding under the Revolving Credit Facility.

On April 23, 2002, the Partnership filed a shelf registration statement with the
SEC to sell, from time to time, up to $200.0 million of common units
representing limited partner interests and/or debt securities. The Partnership
intends to use the net proceeds for general purposes, repayment of debt, future
acquisitions, capital expenditures and working capital. As at March 12, 2004, no
additional units of the Partnership had been issued.

CASH FLOWS FROM OPERATING ACTIVITIES

Cash flows provided by operating activities decreased $2.5 million, or 5%, to
$49.6 million for the year ended December 31, 2003, compared to $52.1 million
for 2002. The decrease is primarily due to lower distributions received from
Northern Border Pipeline in 2003 as compared to 2002. In 2003, Northern Border
Pipeline was ordered by the FERC to refund $10.0 million (TC PipeLines' share is
$3.0 million) to its shippers related to company use gas (see Item 1.
"Business - Business of Northern Border Pipeline Company - FERC Regulation").
In 2003, the Partnership's cash from operations included cash distributions
of $45.2 million and $6.2 million from its investments in Northern Border
Pipeline and Tuscarora, respectively, compared to $49.2 million and $4.6
million, respectively, in 2002.

Cash flows provided by operating activities increased $9.2 million, or 21%, to
$52.1 million for the year ended December 31, 2002, compared to $42.9 million
for 2001. In 2001, the Partnership received cash distributions of $42.9 million
and $2.4 million from Northern Border Pipeline and Tuscarora, respectively.

- 20 -

CASH FLOWS FROM INVESTING ACTIVITIES

For the year ended December 31, 2003, the Partnership made equity contributions
totaling $4.9 million to Tuscarora related to Tuscarora's expansion project,
which was partially offset by a $0.8 million return of capital from Tuscarora.
As well, a $1.0 million return of capital was received by the Partnership from
Northern Border Pipeline in 2003. During 2002, the Partnership made equity
contributions totaling $7.6 million to Tuscarora related to Tuscarora's
expansion project, partially offset by a $0.2 million return of capital received
from Tuscarora in 2002.

The Partnership did not have any material sources or uses of cash relating to
investing activities in 2001.

CASH FLOWS FROM FINANCING ACTIVITIES

For the year ended December 31, 2003, the Partnership paid cash distributions of
$39.4 million, compared to $37.4 million in 2002. The increase is due to the
Partnership increasing its quarterly cash distribution from $0.525 per unit to
$0.55 per unit beginning with the 2003 second quarter cash distribution. In
2001, the Partnership paid cash distributions of $35.2 million.

For the year ended December 31, 2003, the Partnership repaid $6.0 million of the
balance outstanding on the Revolving Credit Facility, compared to repayments of
$10.0 million during 2002. The Partnership did not make any drawings or
repayments on the Revolving Credit Facility in 2001. At December 31, 2003, the
Partnership had $5.5 million outstanding under the Revolving Credit Facility.

CAPITAL REQUIREMENTS

On January 30, 2004, TC PipeLines paid $19.5 million related to its 30% share of
a capital contribution to Northern Border Pipeline in response to a $65.0
million cash call issued by Northern Border Pipeline to its partners on January
27, 2004.

To the extent TC PipeLines has any additional capital requirements with respect
to its investments in Northern Border Pipeline and Tuscarora or makes
acquisitions in 2004, TC PipeLines expects to finance these requirements with
operating cash flows, debt and/or equity.

IMPACT OF ENRON'S CHAPTER 11 FILING ON TC PIPELINES' BUSINESS

In 2001, Enron filed a voluntary petition for bankruptcy protection under
Chapter 11 of the United States Bankruptcy Code. For more details see
"Results of Operations of Northern Border Pipeline Company - Impact of
Enron's Chapter 11 Filing on Northern Border Pipeline's Business."

Based on currently available information, TC PipeLines does not expect the
impact of Enron's bankruptcy protection filing to have a material impact on the
business or financial condition of Northern Border Pipeline or TC PipeLines.

TC PipeLines continues to monitor developments at Enron and to assess any impact
of Enron's Chapter 11 proceedings on Northern Border Pipeline in light of
Northern Border Pipeline's existing agreements and relationships with Enron and
its subsidiaries, and to take all appropriate action to protect the interests of
TC PipeLines and its unitholders.

OUTLOOK

On December 19, 2003, Northern Border Pipeline advised that its Management
Committee had unanimously agreed to issue equity cash calls to its partners in
the total amount of $130.0 million (TC PipeLines' share is $39.0 million) in
early 2004, the first of which was issued on January 27, 2004, and $90.0 million
(TC PipeLines' share is $27.0 million) in 2007 and to change the cash
distribution policy of Northern Border Pipeline as of January 1, 2004.
Effective January 1, 2008, Northern Border Pipeline's cash distribution
policy will be adjusted to maintain a consistent capital structure. TC
PipeLines expects to fund a portion of the 2004 equity cash calls with
borrowings under its existing credit facilities. As at March 12, 2004, the
Partnership has paid Northern Border Pipeline $19.5 million related to the
equity cash calls previously discussed.

- 21 -

RESULTS OF OPERATIONS OF NORTHERN BORDER PIPELINE COMPANY

IN THE FOLLOWING DISCUSSION OF THE RESULTS OF NORTHERN BORDER PIPELINE, ALL
AMOUNTS REPRESENT 100% OF THE OPERATIONS OF NORTHERN BORDER PIPELINE, IN WHICH
THE PARTNERSHIP HAS HELD A 30% INTEREST SINCE MAY 28, 1999.

The discussion and analysis of Northern Border Pipeline's financial condition
and operations are based on Northern Border Pipeline's financial statements,
which were prepared in accordance with accounting principles generally accepted
in the United States of America. The following discussion and analysis should be
read in conjunction with Northern Border Pipeline's financial statements
included elsewhere in this report.

OVERVIEW

For Northern Border Pipeline, there are several major business drivers.
First, a healthy long-term supply outlook is critical. Because the primary
source of gas supply that is transported on its system is in the Western
Canadian Sedimentary Basin, western Canadian supply trends are particularly
important to Northern Border Pipeline. The current outlook for western
Canadian supply looks stable for the foreseeable future however production
has exceeded new reserve additions in recent years. Increased Canadian
consumption related to the extraction process for oil sands projects as well
as restrictions on gas production to protect oil sand reserves could also
impact supplies of natural gas for export. The supply outlook may be
significantly enhanced over time by new Alaskan and Mackenzie Delta supplies
reaching the western Canadian pipeline grid potentially beginning by the end
of this decade.

Natural gas markets are also critical to Northern Border Pipeline's financial
performance. The Northern Border pipeline system serves natural gas markets
in the upper midwestern area of the United States and accesses a major
trading hub in the Chicago area. Market growth has been steady with both
heating load growth and direct end-user growth such as power plants and
ethanol plants. However, competitive pipeline projects may have a negative
impact on Northern Border Pipeline's profitability.

Northern Border Pipeline charges fees for transportation which are primarily
fixed and are based on the amount of capacity reserved by each shipper.
Contracting with shippers to reserve the available pipeline capacity as
existing contracts expire is a critical factor in Northern Border Pipeline's
success. The weighted average life of Northern Border Pipeline's contracts as
of December 31, 2003 was approximately three and one third years. During
2003, Northern Border Pipeline was successful in recontracting, at maximum
rates, all the capacity under contracts that expired on or before November
2003.

The composition of natural gas affects the volume of natural gas that is
transported through a pipeline system. Beginning in 2000, the energy content
of natural gas that Northern Border Pipeline receives at the Canadian border
has declined modestly from 1,023 British Thermal Units (Btus) per cubic foot
(cf) to 1,005 Btus/cf. Northern Border Pipeline's transportation contracts in
conjunction with its tariff define both the volume and equivalent Btu value
of the gas to be transported. A reduction in the Btu level results in a
higher volume of natural gas to be transported to meet an overall equivalent
Btu value of the gas. The Btu level decline that is being experienced is
primarily the result of greater processing capacity in Alberta, Canada. The
change has caused Northern Border Pipeline to reduce its capacity by almost 2
percent to be able to maintain its high standard of system reliability for
its customers. Although Btu levels could theoretically go lower, Northern
Border Pipeline advises that it believes the Btu level will stabilize near
the current level of 1,005 Btus/cf.

As was the case last year, Northern Border Pipeline is in re-contracting
discussions with its customers for contracts that will expire prior to
November 1, 2004, which represents approximately 30% of its system capacity.
The value of capacity on interstate pipelines is driven by supply and demand
conditions. In particular, the relationship between gas prices in Canada and
prices in the midwestern U.S. markets will determine the underlying value of
transportation. The current gas balance in western Canada is such that
Northern Border Pipeline's transportation has been commercially attractive
for available supply that is not consumed within western Canada or committed
to transportation capacity on other pipelines reaching downstream markets. To
maintain an adequate gas balance in western Canada, production will need to
grow moderately in the future to meet anticipated demand primarily driven by
gas consumption in the extraction and processing associated with Canadian oil
sands development. Canada holds an estimated 1.6 trillion barrels of bitumen
reserves. Bitumen, after it is extracted from sand, can be upgraded to
synthesized crude oil through several processes. The extraction and
processing of bitumen require significant quantities of natural gas. Northern
Border Pipeline advises that it does not know how many of the announced oil
sands development projects will be approved and constructed but the demand
for transportation on its pipeline system could be affected adversely by the
additional competition for Canadian gas supply that would result.

Northern Border Pipeline advises that it continues to work with producers and
marketers to develop the contractual support for a new proposed 300-mile
pipeline project, the Bison Pipeline, to connect the coal bed methane
reserves in the Powder River Basin to markets served by Northern Border
Pipeline. Northern Border Pipeline advises that it intends to hold a new open
season for the Bison Pipeline when production increases to levels that
Northern Border Pipeline believes will support the project. If sufficient
interest commitments are received, Northern Border Pipeline advises that it
will pursue regulatory approvals.

Northern Border Pipeline advises that it will continue to focus on safe,
efficient, and reliable operations and the further development of its
pipeline. Northern Border Pipeline further advises that it is working to
maintain its position as a low cost transporter of Canadian gas to the
midwestern U.S. and provide highly valued services to its customers. Growth
may occur through incremental projects intended to access new markets or
supply areas and supported by long-term contracts.

- 22 -

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

Certain amounts included in or affecting Northern Border Pipeline's financial
statements and related disclosures must be estimated, requiring Northern
Border Pipeline to make certain assumptions with respect to values or
conditions that cannot be known with certainty at the time the financial
statements are prepared. The preparation of financial statements in
conformity with accounting principles generally accepted in the United States
of America requires management to make estimates and assumptions that affect
the reported amounts of assets and liabilities and disclosure of contingent
assets and liabilities at the date of the financial statements and the
reported amounts of revenues and expenses during the reporting period. Actual
results could differ from those estimates. Any effects on Northern Border
Pipeline's business, financial position or results of operations resulting
from revisions to these estimates are recorded in the period in which the
facts that gave rise to the revision become known.

Northern Border Pipeline's significant accounting policies are summarized in
Note 2 - Notes to Northern Border Pipeline's Financial Statements included
elsewhere in this report. Certain of Northern Border Pipeline's accounting
policies are of more significance in its financial statement preparation process
than others. Northern Border Pipeline's accounting policies conform to Statement
of Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects of
Certain Types of Regulation." Accordingly, certain assets that result from the
regulated ratemaking process are recorded that would not be recorded under
accounting principles generally accepted in the United States of America for
nonregulated entities. Northern Border Pipeline continually assesses whether the
regulatory assets are probable of future recovery by considering such factors as
regulatory changes and the impact of competition. If future recovery ceases to
be probable, Northern Border Pipeline would be required to write-off the
regulatory assets at that time. At December 31, 2003, Northern Border Pipeline
has reflected regulatory assets of $8.2 million, which are being recovered from
its shippers over varying periods of time.

Northern Border Pipeline's long-lived assets are stated at original cost.
Northern Border Pipeline must use estimates in determining the economic useful
lives of those assets. For utility property, no retirement gain or loss is
included in income except in the case of retirements or sales of entire
regulated operating units. The original cost of utility property retired is
charged to accumulated depreciation and amortization, net of salvage and cost of
removal.

Northern Border Pipeline's accounting for financial instruments is in
accordance with SFAS No. 133, "Accounting for Derivative Instruments and
Hedging Activities." SFAS No. 133 requires that every derivative instrument
be recorded on the balance sheet as either an asset or liability measured at
its fair value. The statement requires that changes in the derivative's fair
value be recognized currently in earnings unless specific hedge accounting
criteria are met. Special accounting for qualifying hedges allows a
derivative's gains and losses to offset related results on the hedged item in
the income statement. At December 31, 2003, Northern Border Pipeline's
balance sheet included assets from derivative financial instruments of
$16.6 million.

RESULTS OF OPERATIONS

Northern Border Pipeline's net income to partners was $148.2 million in 2003,
compared to net income of $142.7 million in 2002 and $140.5 million in 2001.
Northern Border Pipeline's 2003 operating results benefited from increased
operating revenues from Northern Border Pipeline's Order 637 Compliance
filing which went into effect October 1, 2003 and the ability to enter into
short-term contracts effective November 1, 2003, the re-contracting of
capacity previously held by Enron North America Corp. (ENA) and reductions in
interest expense due to lower interest rates. Partially offsetting these
increases to Northern Border Pipeline's operating results were higher
operations and maintenance expenses for 2003 as compared to 2002. Northern
Border Pipeline's increase in net income in 2002 over 2001 resulted from
reductions in interest rates, which reduced its interest expense for 2002 as
compared to 2001. In addition, Northern Border Pipeline realized increased
operating revenues in 2002 resulting from Project 2000, Northern Border
Pipeline's expansion and extension placed in service in October 2001.
Northern Border Pipeline's 2001 results were reduced by reserves for
uncollectible receivables.

Operating revenues were $324.2 million in 2003, $321.1 million in 2002 and
$313.1 million in 2001. The $3.1 million increase in operating revenues in
2003 over 2002 resulted primarily from additional revenues of approximately
$1.8 million related to the re-contracted capacity of ENA contracts. ENA
filed for Chapter 11 bankruptcy protection in December 2001 (see "Impact of
Enron's Chapter 11 Filing on Northern Border Pipeline's Business"). In
addition, Northern Border Pipeline recognized revenues from its ability to
now offer short-term firm contracts and also transportation service beyond a
shipper's contracted transportation path. The increase in operating revenues
in 2002 over 2001 was primarily due to additional revenues of approximately
$10.3 million associated with the completion of Project 2000 in October 2001.
The impact of the additional revenues associated with Project 2000 was
partially offset by uncollected revenues associated with the transportation
capacity formerly held by ENA. For 2002, the revenues lost on this capacity
totaled approximately $1.8 million.

- 23 -

Operations and maintenance expenses were $43.8 million in 2003, $41.4 million
in 2002 and $33.7 million in 2001. The 2003 expense included a $3.1 million
charge for Northern Border Pipeline's allocation from Northern Plains related
to the Enron cash balance plan under funding (see "Impact of Enron's Chapter
11 Filing on Northern Border Pipeline's Business"). In 2003, Northern Border
Pipeline also had increases in salaries and benefits, right-of-way damages,
and telecommunication expenses offset by decreases in electric power costs,
as compared to 2002. The 2002 expense included $10.0 million reserve for
costs associated with the treatment of previously collected quantities of
natural gas used in utility operations to cover electric power costs. The
FERC ordered refunds for these costs in 2003 (see Item 1. "Business -
Business of Northern Border Pipeline - FERC Regulation"). The 2002 expense
also included an increase in regulatory commission expense, and decreases in
employee benefit expense, administrative expense, and bad debt expense as
compared to 2001.

Depreciation and amortization expense was $57.8 million in 2003, $58.7
million in 2002 and $57.5 million in 2001. The decrease from 2002 to 2003
primarily reflects asset retirements. The increase between 2001 and 2002
reflects additional expense for assets related to Project 2000, placed in
service in October 2001.

Taxes other than income were $29.6 million in 2003, $28.4 million in 2002 and
$25.6 million in 2001. The increase in 2003 from 2002 is due primarily to a
refund from Minnesota for previously paid use taxes. The decrease in taxes other
than income in 2002 from 2001 was due primarily to adjustments to ad valorem
taxes. Northern Border Pipeline periodically reviews and adjusts its estimates
of ad valorem taxes. Reductions to previous estimates in 2001 exceeded
reductions to previous estimates in 2002 by approximately $2.1 million. As a
result of a ruling by the Minnesota Supreme Court, Northern Border Pipeline
filed for a refund of use taxes previously paid on exempt purchases. Northern
Border Pipeline received the refund in March 2002.

Interest expense was $44.9 million in 2003, $51.5 million in 2002 and $55.4
million in 2001. Interest expense for both 2003 and 2002 decreased from prior
year levels due to a decrease in Northern Border Pipeline's average interest
rate as well as a decrease in its average debt outstanding. The 2001 results
included $0.9 million of interest expense capitalized primarily related to
construction of Project 2000 facilities.

Other income (expense) was $0.1 million in 2003, $1.8 million in 2002 and
($0.4 million) in 2001. In 2003, Northern Border Pipeline recorded expense of
approximately $0.6 million for a repayment of amounts previously received for
vacated microwave frequency bands, interest expense of $0.3 million due to
the FERC-ordered refunds of electric power costs and $0.2 million of interest
income received related to a sales tax refund on exempt purchases. The amount
for 2002 includes approximately $0.6 million for amounts received for
previously vacated microwave frequency bands and income of $0.2 million due
to a reduction in reserves previously established. The amount for 2001
includes a charge of approximately $1.5 million for an uncollectible
receivable from a telecommunications company that had purchased excess
capacity on Northern Border Pipeline's communication system and a $0.7
million charge for reserves established. Northern Border Pipeline recorded an
allowance for equity funds used during construction of $0.9 million in 2001
primarily due to the construction of Project 2000 facilities.

LIQUIDITY AND CAPITAL RESOURCES OF NORTHERN BORDER PIPELINE COMPANY

CASH DISTRIBUTION POLICY OF NORTHERN BORDER PIPELINE

Under the terms of the cash distribution policy of Northern Border Pipeline,
distributions to the general partners of Northern Border Pipeline are to be
made on a proportionate basis according to each general partner's capital
account balance. The Northern Border Pipeline management committee determines
the amount and timing of distributions. In December 2003, Northern Border
Pipeline's management committee voted to, among other things, change its cash
distribution policy effective January 1, 2004. Under this new policy, cash
distributions are based upon 100% of distributable cash flow which is
earnings before interest, taxes, depreciation and amortization less interest
expense and maintenance capital expenditures. Effective January 1, 2008, the
cash distribution policy will be adjusted to maintain a consistent capital
structure at a level to be determined. Prior to January 1, 2004, cash
distributions were computed as the sum of 100% of net income, excluding
specific non-cash items, 100% of the current portion of any allowance for
income taxes and 35% of the sum of deferred tax expense, depreciation expense
and amortization of regulatory assets, minus 35% of maintenance capital
expenditures. Cash distributions are currently made by Northern Border
Pipeline on a quarterly basis approximately one month after the end of the
quarter.

SUMMARY OF CERTAIN CONTRACTUAL OBLIGATIONS

(a) See Note 7 - Notes to Northern Border Pipeline's Financial Statements