UNITED STATES SECURITIES AND EXCHANGE
COMMISSION

WASHINGTON, D.C. 20549

FORM 10-K

ý ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE

SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2002

o 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 of incorporation or organization)		(I.R.S. Employer 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

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 each 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 ý No o

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. ý

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Act)

Yes ý No o

Aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant, as at June 28, 2002, was approximately $303.8 million.

As of March 11, 2003, there were 15,627,129 of the registrant’s common units outstanding.

TC PIPELINES, LP
TABLE OF CONTENTS

Part I

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

Part II

Item 5.	Market for Registrant’s Common Units and Related Security Holder Matters
Item 6.	Selected Financial Data
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations
Item 7A.	Quantitative and Qualitative Disclosures about Market Risk
Item 8.	Financial Statements and Supplementary Data
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

Part III

Item 10.	Directors and Executive Officers of the General Partner
Item 11.	Executive Compensation
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Security Holder Matters
Item 13.	Certain Relationships and Related Transactions

Part IV

Item 14.	Controls and Procedures
Item 15.	Exhibits, Financial Statement Schedules and Reports on Form 8-K

All amounts are stated in United States dollars unless otherwise indicated.

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., a wholly owned subsidiary of TransCanada PipeLines Limited, is the general partner of the Partnership. 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.

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.

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.

At December 31, 2002, the Partnership had 15,627,129 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 936,435 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 936,435 common units and 1,872,871 subordinated units and is entitled to incentive distribution rights 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 is a general partnership formed in 1978. Northern Border Pipeline’s general partners are TC PipeLines and Northern Border Partners, both of which are publicly traded limited 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 partners of Northern Border Partners and its subsidiary limited partnership are Northern Plains Natural Gas Company and Pan Border Gas Company, both subsidiaries of Enron, 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. The Northern Border 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, 2002, Northern Border Pipeline transported approximately 20% of the total amount of natural gas imported from Canada to the United States. Over the same period, approximately 89% 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 natural gas for shippers under a tariff regulated by the Federal Energy

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

Northern Border Pipeline’s management is overseen by a four-member management committee. One representative is designated by TC PipeLines. Three representatives are designated by Northern Border Partners, with each of its general partners selecting one representative. Voting power on the management committee is allocated among the partners in accordance with their proportionate general partner interests. As a result, TC PipeLines holds 30% of the voting power. 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 March 19, 2003, Enron announced its intention to create a new pipeline operating entity which will include Enron’s interests in Northern Plains and Pan Border. See Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Results of Operations of Northern Border Pipeline Company - Update on 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, 2002, Northern Plains employed approximately 203 individuals located at Northern Plains’ headquarters in Omaha, Nebraska, and at various locations along the pipeline route. Northern Plains 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 Northern Border pipeline system 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 natural gas at various points. Other facilities include four field offices and a microwave communication system with 51 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 Northern Border pipeline system is capable of physically receiving natural gas at two locations near Chicago. At its northern end, the Northern Border pipeline system’s natural gas supplies are received through an interconnection with TransCanada’s majority-owned Foothills Pipe Lines (Sask.) Ltd. system in Canada, which is connected to TransCanada’s Alberta System and the pipeline system owned by Transgas Limited in Saskatchewan. Also, at the north end, the Northern Border pipeline system connects to a domestic natural gas gathering system owned by EnCana 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. Other locations in North Dakota where the Northern Border pipeline system 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 Northern Border 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, 2002, of the natural gas transported on the Northern Border pipeline system, approximately 89% was produced in Canada, approximately 5% was produced by the Dakota Gasification plant and approximately 6% was produced in the Williston Basin.

Interconnects

The Northern Border pipeline system connects with multiple pipelines of various interstate, intrastate and local distribution companies that provide its shippers with access to the various natural gas markets served by those pipelines. The Northern Border pipeline system interconnects with pipeline facilities of:

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

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

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

• Alliant Power Company at Prophetstown, Illinois;

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

• Midwestern Gas Transmission Company near Channahon, Illinois;

• ANR Pipeline Company near Manhattan, Illinois;

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

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

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

• Northern Indiana Public Service Company near North Hayden, Indiana at the terminus of the Northern Border 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 Northern Border Pipeline’s 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 Northern Border pipeline system’s 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 50 firm transportation shippers with diverse operating and financial profiles. Based upon shippers’ contractual obligations, as of December 31, 2002, 91% of the firm capacity is contracted by producers and marketers. The remaining firm capacity is contracted to local distribution companies (6%), interstate pipelines (2%) and end-users (1%). As of December 31, 2002, the termination dates of these contracts ranged from March 31, 2003 to December 21, 2013, and the weighted average contract life, based upon annual contractual obligations, was approximately four and one-half years. Contracts for approximately 42% of the capacity will expire during 2003. See Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations of Northern Border Pipeline Company - Outlook.”

Northern Border Pipeline’s mix and number of shippers may change throughout the year as a result of its shippers utilizing Northern Border Pipeline’s capacity release provisions that allow shippers 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. Shippers on the Northern Border pipeline system temporarily released capacity during 2002 for varying periods of time. There were also permanent releases of capacity to other shippers for the full term of the contracts.

As of December 31, 2002, the largest shipper, Pan-Alberta Gas (U.S.) (Pan-Alberta) is obligated for approximately 20% of the contracted firm capacity, of which approximately 3% of the total contracted capacity has been

temporarily released by Pan-Alberta to other shippers through October 31, 2003. Pan-Alberta’s firm contracts expire October 31, 2003. Mirant Americas Energy Marketing, LP, who manages the assets of Pan-Alberta Gas, Ltd., including Pan-Alberta’s contracts with Northern Border Pipeline, is also obligated for approximately 10% of the contracted firm capacity. Mirant’s firm contracts expire in October 2006 and December 2008. Mirant and Pan-Alberta have agreed to maintain credit support in accordance with Northern Border Pipeline's tariff, including letters of credit, that mitigate a portion of Northern Border Pipeline's credit exposure. The only other shipper that held over 10% of the contracted firm capacity at December 31, 2002 is BP Canada Energy Marketing Corp, with approximately 12% of the contracted firm capacity, of which approximately 8% of the total contracted capacity expires on October 31, 2003. See Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations of Northern Border Pipeline Company - Outlook.”

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. Low prices for natural gas, regulatory limitations or the lack of available capital for these projects could adversely affect the development of additional reserves and production, gathering, storage and pipeline transmission of western Canadian natural gas supplies. Additional pipeline export capacity also could accelerate depletion of these reserves. Furthermore, the availability of export capacity could also affect the demand or value of the transportation capacity 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 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:

• economic conditions;

• fuel conservation measures;

• alternative energy requirements and prices;

• gas storage inventory levels;

• climatic conditions;

• government regulation; and

• 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 system 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 natural gas enters and where natural 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 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.

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 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 the liquids extraction facilities, which are located near Chicago. This contrasts with the Northern Border pipeline system, which serves various markets through interconnections with other pipelines along its route.

The competitive impact of the Alliance Pipeline in the Chicago area has been mitigated by the continuing development of additional capacity to ship natural gas from the Chicago area to other markets in the United States. Vector Pipeline L.P. interconnects with the Alliance Pipeline and transports gas eastward to a terminus in eastern Canada. Guardian Pipeline was placed into service in December 2002 and interconnects with Northern Border Pipeline. Guardian Pipeline delivers into markets in Wisconsin and could provide access to additional markets for Northern Border Pipeline’s shippers.

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

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:

• transportation of natural gas;

• rates and charges;

• construction of new facilities;

• extension or abandonment of service and facilities;

• accounts and records;

• depreciation and amortization policies;

• the acquisition and disposition of facilities; and

• the initiation and discontinuation of services.

Where required, Northern Border Pipeline holds certificates of public convenience and necessity issued by the FERC covering 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 under Section 8. Northern Border Pipeline was notified in November that it is one of the companies selected by the FERC to undergo an industry-wide audit of FERC-assessed annual charges. The overall audit objective is to determine compliance with 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 covers the period of January 1, 2001 to December 31, 2001. Based on Northern Border Pipeline's discussion with the FERC, the FERC is intending to issue its final report by the end of the second quarter of 2003. Northern Border Pipeline advises that it does not believe the results of the audit will have a material adverse impact on its results of operations or financial position.

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 Gas 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 Northern Border Pipeline’s 1999 rate case. Northern Border Pipeline may also provide services under negotiated and discounted rates. Approximately 98% of the agreed upon cost of service or revenue level is attributed to demand charges. Firm shippers that contract for the stated transportation rate are obligated to pay a monthly demand charge, regardless of the amount of natural gas they actually transport, for the term of their contracts. The remaining 2% of the agreed upon revenue level is attributed to commodity charges based on the volumes of natural 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 new rate case. Prior to the new 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 natural gas transported and Northern Border Pipeline’s ability to recontract capacity at acceptable rates.

Until new transportation rates are approved by 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 calculated as the sum of the firm transportation maximum reservation charge and commodity rate. Under Northern Border Pipeline’s tariff, Northern Border Pipeline shares net interruptible transportation service revenue and any new services revenue on an equal basis with Northern Border Pipeline’s firm shippers through October 31, 2003. However, Northern Border Pipeline is permitted to retain revenue from interruptible transportation service to offset any decontracted firm capacity.

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. In September 2001, the FERC issued a Notice of Proposed Rulemaking proposing new standards of conduct that would apply uniformly to natural gas pipelines and transmitting public utilities. FERC is proposing one set of standards to govern relationships between regulated transmission providers and all energy affiliates. Should a final rule be issued in this proceeding, Northern Border Pipeline may be subject to standards that could result in additional costs.

On August 1, 2002, FERC issued a Notice of Proposed Rulemaking regarding the Regulation of Cash Management and is proposing to establish limits on the amount of funds that can be transferred from the regulated subsidiary to its non-regulated parent. It is not expected that FERC proposed policy will have an impact on the cash management practices of Northern Border Pipeline.

On July 17, 2002, FERC issued a Notice of Inquiry Concerning Natural Gas Pipeline Negotiated Rate Policies and Practices. In this proceeding the FERC is evaluating its negotiated rate program and has invited all segments of the industry to provide comments. The outcome of this inquiry may change the existing FERC policy concerning the types of negotiated rates that it allows and may have an undetermined impact on the pricing practices for a pipeline’s transportation services.

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 are studying creditworthiness standards and may recommend that the FERC promulgate changes in such standards on an industry-wide basis. The enactment of some of these recommendations may have the effect of easing certain creditworthiness standards and parameters currently reflected in Northern Border Pipeline's tariff. At this stage of the proceedings, however, Northern Border Pipeline advises that it cannot predict the ultimate impact, if any, such changes would have on Northern Border Pipeline.

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 its shippers for its operations, to clarify the language by adding detail to the broad categories that comprise company use gas. Relying upon the currently effective version of the tariff, Northern Border Pipeline included in its collection of company use gas, quantities that were equivalent to the cost of electric power at its electric-driven compressor stations during the period of June 2001 through January 2003. Several parties have filed protests of this change and have requested that the FERC order refunds. At its meeting on March 26, 2003, the FERC voted to reject Northern Border Pipeline's filing and require refunds. In its draft 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 Northern Border Pipeline's company use gas provisions. Other parties and Northern Border Pipeline will have thirty days from the date of order to request rehearing. A reserve in the amount of $10.0 million was established (TC PipeLines' share equates to $3.0 million). Northern Border Pipeline advises that it believes this reserve is sufficient to cover the potential refunds.

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, and the Pipeline Safety Act of 1992.

The Pipeline Safety Improvement Act (Act) was signed into law in December 2002. The Act contains numerous provisions that increase federal inspection and safety requirements for the pipelines. As a result, the Secretary of Transportation and various government agencies are required to develop and implement regulations under the Act in order for the pipelines to carry out the prescribed evaluations and implementation of programs to ensure the safety of its facilities. The Act and subsequent regulations have prescribed timelines and the implementation may have an impact on the costs that Northern Border Pipeline incurs.

Although 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, 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 increasingly strict environmental and safety laws, regulations and enforcement policies thereunder, 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 between the companies.

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 PG&E National Energy Group, Gas Transmission Northwest 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. The Tuscarora pipeline system has firm capacity contracts to transport approximately 182 mmcfd of natural gas.

On December 1, 2002, Tuscarora completed and placed into service an expansion of its pipeline system. The Tuscarora expansion consists 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 capacity from 127 mmcfd to approximately 182 mmcfd. The new capacity is contracted under long-term firm transportation contracts ranging from ten to fifteen years. Sierra Pacific Power Company, a subsidiary of Sierra Pacific Resources, has 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.

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. Sierra Pacific Power holds firm capacity on the lateral for approximately 15 mmcfd through firm transportation contracts that expire in January and October 2016. The project was completed at a capital cost of approximately $8.0 million.

Tuscarora has firm transportation contracts for over 94% of its capacity, including contracts held by Sierra Pacific Power for 68.4% of the total available capacity, the majority of which expires on November 30, 2015. As of December 31, 2002, the weighted average contract life on the Tuscarora pipeline system was approximately 12.5 years.

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.

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.

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 Northern Border 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 Northern Border Pipeline’s 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 Northern Border pipeline system. The right to construct and operate the Northern Border pipeline system across certain property was obtained by Northern Border Pipeline through exercise of the power of eminent domain. Northern Border Pipeline continues to have the power of eminent domain in each of the states in which it operates, 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 are located on fee, allotted and tribal lands within the exterior boundaries of the Fort Peck Indian Reservation in Montana. Tribal lands are lands owned in trust by the United States for the Fort Peck Tribes and allotted lands are lands owned in trust by the United States for an individual Indian or Indians. Northern Border Pipeline does have the right of eminent domain with respect to allotted lands.

In 1980, Northern Border Pipeline entered into a pipeline right-of-way lease with the Fort Peck Tribal Executive Board, for and on behalf of the Assiniboine and Sioux Tribes of the Fort Peck Indian Reservation. This pipeline right-of-way lease, which was approved by the Department of the Interior in 1981, granted to Northern Border Pipeline the right and privilege to construct and operate the Northern Border pipeline system 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 Assiniboine and Sioux Tribes of the Fort Peck Indian Reservation filed a lawsuit in Tribal Court against Northern Border Pipeline to collect more than $3 million in back taxes, together with interest and penalties. The lawsuit relates to a utilities tax on certain of Northern Border Pipeline’s properties within the Fort Peck Indian Reservation. Northern Border Pipeline and the Tribes, through a mediation process, have held

settlement discussions and have reached a settlement in principle on pipeline right-of-way lease and taxation issues, subject to final documentation and necessary governmental approvals. Northern Border Pipeline advises that it believes that it will obtain regulatory recovery of the costs resulting from the settlement, which will result in no material adverse impact to its results of operations or financial position. See Item 7. "Management's Discussion and Analysis of Financial Condition and Results of Operations - Risk Factors and Information Regarding Forward-Looking Statements."

See Item 1. “Business – Business of Northern Border Pipeline Company - FERC Regulation” for a discussion on the proceeding relating to company use gas before the FERC.

Northern Border Pipeline is not currently party to any other legal proceedings that, individually or in aggregate, would reasonably be expected to have a material adverse impact on 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, 2002.

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.

	Price Range				Cash Distributions Declared per Unit
	High		Low		Cash Distributions Declared per Unit
2002
First Quarter	$	27.38	$	23.90	$	0.500
Second Quarter	$	26.00	$	23.31	$	0.525
Third Quarter	$	26.99	$	21.30	$	0.525
Fourth Quarter	$	27.88	$	24.02	$	0.525

2001
First Quarter	$	24.50	$	16.25	$	0.475
Second Quarter	$	24.24	$	20.00	$	0.500
Third Quarter	$	27.00	$	21.85	$	0.500
Fourth Quarter	$	27.60	$	23.00	$	0.500

As of March 11, 2003, there were 96 record holders of common units and approximately 7,300 beneficial owners of common units, including common units held in street name.

The Partnership currently has 15,627,129 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 936,435 are held by the general partner. The Partnership also has 1,872,871 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.

In general, the general partner is entitled to 2% of all cash distributions and the holders of common units and subordinated units (collectively referred to as unitholders) are entitled to the remaining 98% of all cash distributions. 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:

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

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

• 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.

The general partner is entitled to 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 is entitled to 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 2002, the Partnership made cash distributions to unitholders and the general partner that amounted to $37.4 million compared to $35.2 million in 2001. These payments represented $0.50 per unit for the quarters ended December 31, 2001 and March 31, 2002 and $0.525 per unit for the quarters ended June 30, 2002 and September 30, 2002. On February 14, 2003, the Partnership paid a cash distribution of $9.6 million to unitholders and the general partner, representing a cash distribution of $0.525 per unit for the quarter ended December 31, 2002. The distribution was allocated in the following manner: $8.2 million to the holders of common units as of the close of business on January 31, 2003 (including $1.5 million to an affiliate of the general partner as holder of 2,800,000 common units and $0.5 million to the general partner as holder of 936,435 common units), $1.0 million to the general partner as holder of the subordinated units, $0.2 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:

• 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;

• 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

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

Before the end of the subordination period and to the extent the tests for conversion described above are satisfied, a portion of the subordinated units may convert into common units prior to June 30, 2004. On August 1, 2002, 936,435 subordinated units, representing one-third of the then outstanding subordinated units held by the general partner, upon satisfaction of the tests set forth in the partnership agreement, automatically converted into an equal number of common units as provided for in the partnership agreement of TC PipeLines. A second one-third of subordinated units (936,435 subordinated units) may convert into common units on a one-for-one basis on the first day after the record date established for the distribution in respect of any quarter ending on or after June 30, 2003.

Upon expiration of the subordination period, all remaining subordinated units will convert into common units on a one-for-one basis and will thereafter participate, pro rata with the other common units in distributions of Available Cash.

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.”

TC PipeLines, LP

(millions of dollars, except per unit amounts)

	Year Ended December 31									May 28(1) - Dec 31, 1999
	2002			2001			2000
Income Data:
Equity income from investment in Northern Border Pipeline	42.8			42.1			38.1			20.9
Equity income from investment in Tuscarora(2)	4.7			3.6			0.9			—
General and administrative expenses	(1.5		)	(1.2		)	(1.3		)	(0.7		)
Financial charges	(0.5		)	(1.0		)	(0.5		)	—
Net income	45.5			43.5			37.2			20.2

Basic and diluted net income per unit	$	2.50		$	2.40		$	2.08		$	1.13
Units outstanding (millions)	17.5			17.5			17.5			17.5

Cash Flow Data:
Net cash provided by operating activities	52.1			42.9			40.3			11.8
Distributions paid	37.4			35.2			32.6			11.0

Balance Sheet Data (at end of period):
Investment in Northern Border Pipeline	242.9			250.1			248.1			250.5
Investment in Tuscarora(2)	36.7			29.3			27.9			—
Total assets	286.0			288.7			277.5			251.2
Long-term debt	11.5			21.5			21.5			—
Partners’ equity	273.9			266.7			255.4			250.8

(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 for 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, 2002, TC PipeLines’ interest in Northern Border Pipeline represents approximately 85% of TC PipeLines’ total assets and for the year ended December 31, 2002 provided approximately 90% of TC PipeLines’ equity income. All amounts are stated in United States dollars.

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.

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 in 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 potential costs that may arise 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 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.

Year Ended December 31, 2001 Compared with the Year Ended December 31, 2000

Net income increased $6.3 million, or 17%, to $43.5 million for the year ended December 31, 2001, compared to $37.2 million for 2000. 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 $4.0 million, or 10%, to $42.1 million for the year ended December 31, 2001, compared to $38.1 million for 2000. Approximately $1.0 million of this increase is due to Project 2000. An additional $1.9 million of the increase is due to lower operating and maintenance costs as a result of Northern Border Pipeline’s efforts to reduce these costs, offset by the reserve to provide for November and December 2001 revenues due to Northern Border Pipeline under transportation agreements with Enron North America Corp. (ENA), a subsidiary of Enron. ENA, which filed for Chapter 11 bankruptcy protection on December 2, 2001, is in default of its payments to Northern Border Pipeline, starting with payments due for November 2001 (see “Results of Operations of Northern Border Pipeline Company – Update on the Impact of Enron’s Chapter 11 Filing on Northern Border Pipeline’s Business”). Lower average interest rates decreased Northern Border Pipeline’s interest expense in 2001 further increasing 2001 equity income by $2.9 million. These increases to 2001 equity income were partially offset by lower other income for Northern Border Pipeline in 2001, resulting in a $2.5 million decrease in 2001 equity income to TC PipeLines. In 2000, Northern Border Pipeline’s other income was higher due to non-recurring adjustments related to the approval of its rate settlement agreement.

Equity income from the Partnership’s investment in Tuscarora increased $2.7 million, or 300%, to $3.6 million for the year ended December 31, 2001, compared to $0.9 million for 2000. This increase is attributed to the Partnership acquiring its interest in Tuscarora in September 2000 and incremental revenues from Tuscarora’s Hungry Valley lateral, which was placed into service in January 2001.

The Partnership recorded general and administrative expenses of $1.2 million and $1.3 million for the years ended December 31, 2001 and 2000, respectively.

The Partnership recorded financial charges of $1.0 million and $0.5 million for the years ended December 31, 2001 and 2000, respectively. This increase is attributed to the Partnership having a balance of $21.5 million outstanding on its Revolving Credit Facility for the full year in 2001 compared to 2000 when the Partnership only had debt outstanding for four months of the year, partially offset by a decrease in interest rates in 2001. The Partnership drew on the Revolving Credit Facility in September 2000 to fund a portion of the purchase price of a 49% general partner interest in Tuscarora.

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:

• 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;

• 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;

• 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

• 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.

Conversion of Subordinated Units

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

General

On January 21, 2003, the board of directors of the general partner declared the Partnership’s 2002 fourth quarter cash distribution. The fourth quarter cash distribution, which was paid on February 14, 2003 to unitholders of record as of January 31, 2003, totaled $9.6 million and was paid in the following manner: $8.2 million to common unitholders (including $1.5 million to an affiliate of the general partner as holder of 2,800,000 common units and $0.5 million to the general partner as holder of 936,435 common units), $1.0 million to the general partner as holder of the subordinated units, $0.2 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.

On September 30, 2002 the Partnership renewed its unsecured credit facility (Revolving Credit Facility) with Bank One as administrative agent and the other lenders party to the agreement governing the Revolving Credit Facility under which the Partnership may borrow up to an aggregate principal amount of $20.0 million. Loans under the Revolving Credit Facility may bear interest, at the option of the Partnership, at a one-, two-, three-, or six-month London Interbank Offered Rate (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 July 31, 2004. 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 $11.5 million and $21.5 million outstanding under the Revolving Credit Facility at December 31, 2002 and 2001, respectively. The interest rate on the Revolving Credit Facility at December 31, 2002 and 2001 was 2.7% and 3.0%, respectively. As at March 28, 2003, there is $11.5 million 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 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.

On May 28, 2001, the Partnership renewed its $40.0 million unsecured two-year revolving credit facility (TransCanada Credit Facility) with TransCanada PipeLines USA Ltd., an affiliate of the general partner. The TransCanada Credit Facility bears interest at 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, 2002 and 2001, the Partnership had no amount outstanding under the TransCanada Credit Facility. As at March 28, 2003, no amount is outstanding under the TransCanada Credit Facility.

Cash Flows from Operating Activities

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 2002, the Partnership received cash distributions of $49.2 million and $4.6 million from its investments in Northern Border Pipeline and Tuscarora, respectively, compared to $42.9 million and $2.4 million, respectively, in 2001.

Cash flows provided by operating activities increased $2.6 million, or 6%, to $42.9 million for the year ended December 31, 2001, compared to $40.3 million for 2000. In 2000, the Partnership received cash distributions of $40.5 million and $1.5 million from Northern Border Pipeline and Tuscarora, respectively.

Cash Flows from Investing Activities

For the year ended December 31, 2002, the Partnership made equity contributions totalling $7.6 million to Tuscarora related to Tuscarora’s expansion project. This was partially offset by a $0.2 million return of capital received by the Partnership from Tuscarora in 2002. The Partnership did not have any material sources or uses of cash relating to investing activities in 2001.

In 2000, the Partnership paid $28.4 million to purchase a 49% general partner interest in Tuscarora.

Cash Flows from Financing Activities

For the year ended December 31, 2002, the Partnership paid cash distributions of $37.4 million, compared to $35.2 million in 2001. The increase is due to the Partnership increasing its quarterly cash distribution from $0.50 per unit to $0.525 per unit beginning with the 2002 second quarter cash distribution. In 2000, the Partnership paid cash distributions of $32.6 million.

For the year ended December 31, 2002, the Partnership repaid $10.0 million of the balance outstanding on the Revolving Credit Facility. The Partnership did not make any drawings or repayments on the Revolving Credit Facility in 2001. In 2000, the Partnership made its initial borrowing of $24.5 million from the Revolving Credit Facility to fund a portion of the purchase price of the 49% general partner interest in Tuscarora and repaid $3.0 million in the same year. At December 31, 2002, the Partnership had $11.5 million outstanding under the Revolving Credit Facility.

Capital Requirements

To the extent TC PipeLines has any capital requirements with respect to its investments in Northern Border Pipeline and Tuscarora or makes acquisitions in 2003, 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 - Update on the 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 on Northern Border Pipeline to have a material impact on the business or financial condition of 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.

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.

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 give 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, 2002, Northern Border Pipeline has reflected regulatory assets of $10.5 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 follows 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 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 or losses to offset related results on the hedged item in the income statement. At December 31, 2002, Northern Border Pipeline's balance sheet included assets from derivative financial instruments of $21.2 million.

Results of Operations

Northern Border Pipeline’s net income to partners was $142.7 million in 2002, compared to net income of $140.5 million in 2001 and $127.1 million in 2000. Northern Border Pipeline’s 2002 operating results benefited from increased operating revenues from Project 2000, which was Northern Border Pipeline’s expansion and extension that was placed in service in October 2001, 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 2002 as compared to 2001. Northern Border Pipeline’s 2001 results also included a write-off for an uncollectible receivable. Northern Border Pipeline’s increase in net income in 2001 over 2000 resulted from reductions in interest rates, which reduced Northern Border Pipeline’s interest expense for 2001 as compared to 2000. Northern Border Pipeline was also able to control its operating costs in 2001 resulting in reductions to operations and maintenance expenses as compared to 2000.

Operating revenues were $321.1 million in 2002, $313.1 million in 2001 and $311.0 million in 2000. The increase in operating revenues in 2002 over 2001 resulted from additional revenues of approximately $10.3 million related to Project 2000. 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, which filed for Chapter 11 bankruptcy protection in December 2001 (see “Update on the Impact of Enron’s Chapter 11 Filing on Northern Border Pipeline’s Business”). For 2002, the revenues lost on this capacity totaled approximately $1.8 million. The increase in operating revenues in 2001 over 2000 was primarily due to additional revenues associated with the completion of Project 2000 in October 2001.

Operations and maintenance expenses were $41.4 million in 2002, $33.7 million in 2001 and $41.5 million in 2000. The 2002 expense included a $10.0 million reserve for potential costs that may arise from the treatment of previously collected quantities of natural gas used in utility operations to cover electric power costs (see Item 1. "Business—Business of Northern Border Pipeline Company—FERC Regulation"). In 2002, Northern Border Pipeline also had an increase in regulatory commission expense and decreases in employee benefits expenses, administrative expenses and bad debt expense, as compared to 2001. The 2001 expense included $1.3 million of bad debt expense related to ENA. The decrease in operations and maintenance expense in 2001 from 2000 reflects a decrease in regulatory commission expense, decreased employee payroll, employee benefits expenses and administrative expenses, and decreased costs to operate two of Northern Border Pipeline's electric-powered compressor units as a result of collected quantities of natural gas used in utility operations to cover electric power costs.

Depreciation and amortization expenses were $58.7 million in 2002, $57.5 million in 2001 and $57.3 million in 2000. The increase between 2001 and 2002 reflects a $1.2 million increase due to Project 2000.

Taxes other than income were $28.4 million in 2002, $25.6 million in 2001 and $28.0 million in 2000. The increase in 2002 from 2001 is 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. The decrease in taxes other than income in 2001 from 2000 was also due to a decrease in use taxes. 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 $51.5 million in 2002, $55.4 million in 2001 and $65.2 million in 2000. Both 2002 and 2001 interest expense decreased from prior year levels due to a decrease in Northern Border Pipeline’s average interest rates 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 $1.8 million in 2002, ($0.4) million in 2001 and $8.1 million in 2000. In 2002, Northern Border Pipeline recorded income of 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 Project 2000. In 2000, Northern Border Pipeline had recorded approximately $1.7 million of income from the sale of excess capacity on its communication system. Other income for 2000 also included $5.6 million of income due to a reduction in reserves previously established for regulatory issues as the result of the settlement of Northern Border Pipeline’s rate case.

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. Cash distributions are 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

			Payments Due by Period
	Total		Less Than 1 Year		1-3 Years		4-5 Years		After 5 Years
	(millions of dollars)
1992 Series D Senior Notes	$	65.0	$	65.0	$	—	$	—	$	—
Senior Notes due 2007	225.0		—		—		225.0		—
Senior Notes due 2009	200.0		—		—		—		200.0
Senior Notes due 2021	250.0		—		—		—		250.0
Credit Agreement due 2005	89.0		—		89.0		—		—
Operating Leases(1)	6.0		0.9		1.7		1.7		1.7
Total	$	835.0	$	65.9	$	90.7	$	226.7	$	451.7

(1) See Note 7 – Notes to Northern Border Pipeline’s Financial Statements

Debt and Credit Facilities

Northern Border Pipeline entered into a $175 million three-year credit agreement (2002 Pipeline Credit Agreement) with certain financial institutions in May 2002. The 2002 Pipeline Credit Agreement replaced a previous credit agreement. The 2002 Pipeline Credit Agreement is to be used to refinance existing indebtedness and for general business purposes. At December 31, 2002, $89 million was outstanding under the 2002 Pipeline Credit Agreement at an average interest rate of 2.05%. The 2002 Pipeline Credit Agreement requires the maintenance of a ratio of EBITDA (net income plus interest expense, income taxes and depreciation and amortization) to interest expense of greater than 3 to 1. The 2002 Pipeline Credit Agreement also requires the maintenance of a ratio of indebtedness to EBITDA to be no more than 4.5 to 1. At December 31, 2002, Northern Border Pipeline was in compliance with these covenants.

At December 31, 2002, Northern Border Pipeline had outstanding $65 million of Series D Senior Notes issued in a $250 million private placement under a July 1992 note purchase agreement. The Series D Senior Notes mature in August 2003. Northern Border Pipeline anticipates borrowing under the 2002 Pipeline Credit Agreement to repay the Series D Senior Notes.

In April 2002, Northern Border Pipeline completed a private offering of $225 million of 6.25% Senior Notes due

2007 (2002 Pipeline Senior Notes). In September 2001, Northern Border Pipeline completed a private offering of $250 million of 7.50% Senior Notes due 2021 (2001 Pipeline Senior Notes). In August 1999, Northern Border Pipeline completed a private offering of $200 million of 7.75% Senior Notes due 2009 (1999 Pipeline Senior Notes). The 2002 Pipeline Senior Notes, 2001 Pipeline Senior Notes and 1999 Pipeline Senior Notes (collectively Pipeline Senior Notes) were subsequently exchanged in a registered offering for notes with substantially identical terms. The indentures under which the Pipeline Senior Notes were issued do not limit the amount of unsecured debt Northern Border Pipeline incurs, but they do contain material financial covenants, including restrictions on incurrence of secured indebtedness. The proceeds from the Pipeline Senior Notes were used to reduce indebtedness outstanding.

Northern Border Pipeline’s short-term liquidity needs will be met by operating cash flows and through the 2002 Pipeline Credit Agreement. Northern Border Pipeline’s long-term capital needs may be met through the ability to issue long-term indebtedness.

Cash Flows From Operating Activities

Cash flows provided by operating activities were $223.5 million in 2002, $197.3 million in 2001 and $176.0 million in 2000. The $26.2 million increase in 2002 from 2001 was primarily due to increases in operating revenues and the impact of rate case refunds in 2001. In 2001, Northern Border Pipeline realized net cash outflows of approximately $4.7 million related to its rate case refunds. During the first quarter of 2001, Northern Border Pipeline made refunds to its shippers totaling $6.8 million, which included approximately $2.1 million collected in the first quarter of 2001 with the remainder collected previously. The $21.3 million increase in 2001 from 2000 was primarily due to increased earnings and positive changes in working capital.

Cash Flows From Investing Activities

Capital expenditures were $8.4 million for 2002 as compared to $54.7 million for 2001 and $15.5 million for 2000. The 2002, 2001 and 2000 amounts include $0.3 million, $49.0 million and $7.4 million, respectively, for Project 2000. The remaining capital expenditures for 2002, 2001 and 2000 were primarily related to renewals and replacements of existing facilities.

Total capital expenditures for 2003 are estimated to be $11 million primarily related to renewals and replacements of existing facilities. Northern Border Pipeline currently anticipates funding its 2003 capital expenditures primarily by borrowing on debt facilities and using operating cash flows.

Cash Flows From Financing Activities

Cash flows used in financing activities were $200.8 million for the year ended December 31, 2002 as compared to $160.7 million for the same period in 2001 and $148.7 million for the same period in 2000. Distributions to Northern Border Pipeline’s partners were $164.1 million, $143.0 million and $134.9 million for 2002, 2001 and 2000, respectively. The increase in distributions was primarily due to Northern Border Pipeline’s improved operating results.

For 2002, 2001 and 2000, Northern Border Pipeline’s borrowings on long-term debt totaled $431.0 million, $385.4 million and $75.0 million, respectively, which were primarily used to repay previously existing indebtedness. For 2002, Northern Border Pipeline received net proceeds from the 2002 Pipeline Senior Notes of approximately $223.5 million. The net proceeds from the issuance of the 2001 Pipeline Senior Notes totaled approximately $247.2 million in 2001. Northern Border Pipeline’s borrowings under its credit agreements were $207.0 million in 2002, $136.0 million in 2001 and $75.0 million in 2000. Total payments on debt were $468.0 million, $374.0 million and $111.0 million in 2002, 2001 and 2000, respectively.

In April 2002, Northern Border Pipeline received $2.4 million from the termination of forward starting interest rate swaps upon issuance of the 2002 Pipeline Senior Notes (see Note 6 – Notes to Northern Border Pipeline’s Financial Statements). In September 2001, Northern Border Pipeline paid approximately $4.1 million to terminate interest rate swap agreements upon issuance of the 2001 Pipeline Senior Notes. The swaps were entered into to hedge the fluctuations in Treasury rates and spreads between the execution date of the swaps and the issuance of the 2002 and 2001 Pipeline Senior Notes. For 2001, Northern Border Pipeline recognized a decrease in bank overdraft of $22.4 million. At December 31, 2000, Northern Border Pipeline reflected the bank overdraft primarily due to rate refund

checks outstanding.

Update on the Impact of Enron’s Chapter 11 Filing on Northern Border Pipeline’s Business

On December 2, 2001, Enron filed a voluntary petition for bankruptcy protection under Chapter 11 of the United States Bankruptcy Code. Certain wholly owned Enron subsidiaries also filed for Chapter 11 bankruptcy protection on December 2, 2001 and thereafter. Northern Border Pipeline has not filed for bankruptcy protection. Northern Plains, Pan Border and Northwest Border are the general partners of Northern Border Partners, Northern Border Pipeline’s 70% general partner. Each of Northern Plains and Pan Border are wholly owned subsidiaries of Enron, and Northwest Border is a wholly owned subsidiary of TransCanada. Northern Plains and Pan Border were not among the Enron companies that filed for Chapter 11 protection.

The business of Enron and its subsidiaries that have filed for bankruptcy protection are currently being administered under the direction and control of the bankruptcy court. An unsecured creditors' committee has been appointed in the Chapter 11 cases. The creditors' committee is responsible for general oversight of the bankruptcy case, and has the power, among other things, to: investigate the acts, conduct, assets, liabilities, and financial condition of the debtor, the operation of the debtor’s business and the desirability of the continuance of such business; participate in the formulation of a plan of reorganization; and file acceptances or rejections to such a plan. Factors taken into account by Enron in making its business decisions, while in Chapter 11, may include decisions with respect to its investment in Northern Plains, Pan Border and Northern Border Partners, which decisions may affect Northern Border Pipeline.

Current Effects

Enron’s filing for bankruptcy protection has impacted Northern Border Pipeline. At the time of the filing of the bankruptcy petition, Northern Border Pipeline had a number of contractual relationships with Enron and its subsidiaries. Northern Plains provided and continues to provide operating and administrative services for Northern Border Pipeline. Northern Plains has continued to meet its operational and administrative service obligations under the existing agreement, and Northern Border Pipeline believes Northern Plains will continue to do so.

ENA, a wholly owned subsidiary of Enron that is in bankruptcy, was a party to shipper contracts obligating ENA to pay for 3.5% of Northern Border Pipeline’s capacity. Through the bankruptcy proceeding, ENA rejected and terminated all its contracts with Northern Border Pipeline. Northern Border Pipeline contracted portions of that capacity with others for varying terms. For 2002, Northern Border Pipeline experienced lost revenues of approximately $1.8 million for ENA’s capacity (TC PipeLines’ share equates to $0.5 million). Northern Border Pipeline has claims against ENA for damages for breach of contract and other claims.

Northern Border Pipeline filed claims against ENA’s bankruptcy estate related to these agreements. These claims will likely be deemed to be unsecured claims against certain of the Enron related Chapter 11 companies. Northern Border Pipeline is uncertain regarding the ultimate amount of damages for breach of contract or other claims that it will be able to establish in the bankruptcy proceeding, and Northern Border Pipeline cannot predict the amounts that it will collect or the timing of collection. Northern Border Pipeline advises that it believes, however, that any such delay in collecting or failure to collect will not have a material adverse effect on its financial condition, and any amounts collected will not be material to Northern Border Pipeline.

Northern Plains has advised Northern Border Pipeline that under the Operating Agreement with Northern Plains increased costs may be incurred for health care expenses and pension benefits. Such costs are projected to increase as a result of actual medical claims experience, pension investment returns and effects of the Enron bankruptcy filing. While the determination of reimbursement of such costs by Northern Border Pipeline under the agreement will be made at the time of occurrence, Northern Border Pipeline estimates an increase of $3 million over 2002 levels (TC PipeLines’ share would equate to $0.9 million).

Enron is the grantor of the Enron Gas Pipeline Employee Benefit Trust (the Trust) which, when taken together with the Enron Corp. Medical Plan for Inactive Participants (the Plan), constitutes a "voluntary employees' beneficiary association" or "VEBA" under Section 501(c)(9) of the Internal Revenue Code. In October 2002, Northern Plains was advised that Enron had notified the committee, that has administrative and fiduciary oversight related to the Trust and the Plan, that Enron had made the determination to begin necessary steps to partition the assets of the Trust and the related liabilities of the Plan among all of the participating employers of the Trust. The Trust was established as a regulatory requirement for inclusion of certain costs for post-employment medical benfits in the rates established for the affected pipelines, including Northern Border Pipeline. Enron requested the enrolled actuary to prepare an analysis and recommendation for the allocation of the Trust's assets and associated liabilities among all the participating employers. Enron has advised Northern Border Pipeline's management that it intends to seek bankruptcy court approval for the termination of the Trust and for the participating employers to establish a separate trust adequate to receive the assets.

On May 2, 2002, Enron presented to the creditors' committee a proposal under which specified core energy assets of Enron would be separated from Enron’s bankruptcy estate and operated prospectively as a new integrated power and pipeline company. On August 27, 2002, Enron announced that it had commenced a formal sales process for its interests in certain major assets, including Northern Plains and Pan Border. On March 19, 2003, Enron announced that its Board of Directors had voted to move forward with the creation of a new pipeline operating entity rather than sell its interests in its North American pipelines. This new company, temporarily referred to as “PipeCo”, will include Northern Plains and Pan Border. Enron's announcement also stated that Enron expects PipeCo to be governed by an independent board of directors and to be afforded protection from joint and several Enron group liabilities associated with the Enron bankruptcy case. Further, upon resolution of Enron's Chapter 11 bankruptcy case, it is anticipated that shares of PipeCo will be distributed to creditors in connection with the Plan of Reorganization. PipeCo is expected to include certain service companies that currently support the operations of the North American pipelines, including Northern Border Pipeline. Enron also stated that it is evaluating the potential sale of a minority interest in PipeCo. The formation of PipeCo will require various Enron Board, bankruptcy court and other regulatory approvals, as well as the consent of Enron's Official Unsecured Creditors' Committee.

Enron’s filing for bankruptcy protection and related developments have had other impacts on Northern Border Pipeline’s business and management. Arthur Andersen LLP resigned as Northern Border Pipeline’s auditors in early 2002, and it retained KPMG LLP as its new auditors. Enron has received several requests for information from different agencies and committees of the United States House of Representatives and Senate. Some of the information requested from Enron may include information about Northern Border Pipeline. In addition, Northern Border Pipeline is aware that the Senate Committee on Governmental Affairs has issued a subpoena to Enron requesting documents disclosing Enron’s communications with the SEC and the FERC, as well as information on compensation matters. Northern Border Pipeline has advised that it has been asked to comply with the mandate of the subpoena in such a manner that may be determined by the Committee on Governmental Affairs of the Senate of the United States, which may arise as a result of Enron’s indirect ownership of Northern Border Pipeline.

Possible Effects

While Northern Plains and Pan Border have not filed for Chapter 11 bankruptcy protection, their stock is owned by Enron, which is in bankruptcy. As noted above, Enron could sell its interest in Northern Plains and/or Pan Border, or take other action with respect to its investment in Northern Border Partners. Enron could also cause Northern Plains and Pan Border to file for bankruptcy protection. Northern Border Pipeline has had no indication from Enron that it intends to cause such companies to file for bankruptcy protection.

Northern Border Pipeline is managed by a four-member management committee. One representative is designated by TC PipeLines. Three representatives are designated by Northern Border Partners, with each of its general partners selecting one representative. Voting power on the management committee is allocated among the partners in accordance with their proportionate general partner interests. As a result, TC PipeLines holds 30% of the voting power. The 70% voting interest of Northern Border Partners’ three representatives is allocated 35%, 22.75% and 12.25% among Northern Plains, Pan Border and Northwest Border, respectively. If Enron were to sell the stock of Northern Plains and Pan Border, the purchaser would have the right to appoint a majority of Northern Border Pipeline’s management committee and control its activities, except for those activities requiring a unanimous vote which include changes to Northern Border Pipeline’s cash distribution policy, certain expansions and extensions of the pipeline, some transfers of general partner interests and settlement of rate cases.

Northern Border Pipeline has advised that if Northern Plains and Pan Border were to file for bankruptcy protection, Northern Border Partners’ partnership agreement provides that Northwest Border, as the remaining general partner of Northern Border Partners, would have the right to purchase Northern Plains’ and Pan Border’s general partnership interests. If the remaining general partner does not purchase such general partnership interests, the limited partners of Northern Border Partners would have the right to elect new general partners. In the event that the remaining general partner does not elect to purchase the general partner interests or a successor is not elected by the limited partners, then, the Northern Border Partners partnership would be dissolved. In either event, the

party acquiring the general partner interests currently held by Northern Plains and Pan Border would have the right to appoint a majority of Northern Border Pipeline’s management committee and control its activities, except for those activities requiring a unanimous vote.

Northern Plains also serves as Northern Border Pipeline’s operator. If Northern Plains were to file for bankruptcy protection, it could potentially be removed as operator. Certain of Northern Border Pipeline’s credit agreements provide that it would be an event of default thereunder if Northern Plains is replaced as operator without the consent of the lenders thereunder.

Other than the items identified above, Northern Border Pipeline is not aware of any claims made against it that arise out of the Enron bankruptcy cases. Northern Border Pipeline continues to monitor developments at Enron, to assess the impact on Northern Border Pipeline of its existing agreements and relationships with Enron and its subsidiaries, and to take appropriate action to protect its interests.

Outlook

Northern Border Pipeline will continue to focus on safe, efficient, and reliable operations and the further development of its pipeline system. Northern Border Pipeline intends to maintain its position as a low cost transporter of Canadian gas to the midwestern United States 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. Northern Border Pipeline is currently working with producers and marketers to develop the contractual support for a new 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 is in re-contracting discussions with its customers for contracts that will expire prior to November 1, 2003, which represent approximately 42% of Northern Border Pipeline’s system capacity. Similar to other industries, 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. This relationship, and natural gas markets overall, has been volatile, which is also an important factor in contracting for firm transportation capacity. Under its FERC tariff, Northern Border Pipeline may concurrently solicit bids for available capacity from other parties subject to the existing customer’s rights to match the best offer. During 2002, after completion of this process, Northern Border Pipeline received only bids to extend service from mid-September 2003 to October 31, 2003 and all other existing customers’ rights to match an offer were terminated. Northern Border Pipeline is now in a position to contract with interested parties on a first come, first served basis. Based on current conditions, contracts for service on the Northern Border pipeline system may require discounts from maximum transportation rates established in its tariff and/or shorter duration than its existing contract portfolio. Additionally, Northern Border Pipeline may enter into negotiated rate contracts involving charges established on the basis of Canadian-midwestern U.S. gas price differentials or other factors.

In February 2003, Northern Border Pipeline filed to amend the definition of company use gas, which is gas supplied by its shippers for Northern Border Pipeline's operations, to clarify the language by adding detail to the broad categories that comprise company use gas (see Item 1. "Business - Business of Northern Border Pipeline Company - FERC Regulation"). Relying upon the currently effective version of the tariff, Northern Border Pipeline included in its collection of company use gas quantities that were equivalent to the cost of electric power at its electric driven compressor stations, resulting in cost savings of approximately $8.0 million annually. Pending the final outcome of this FERC proceeding, Northern Border Pipeline may not realize electric power cost savings to the same extent for 2003.

Results of Operations of Tuscarora Gas Transmission Company

In the following discussion of the results of Tuscarora, all amounts represent 100% of the operations of Tuscarora, in which the Partnership has held a 49% interest since September 1, 2000.

Critical Accounting Policy

Tuscarora’s accounting policies conform to SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation.” Accordingly, certain assets that result from the regulated ratemaking process are recorded that would not be recorded under generally accepted accounting principles for nonregulated entities.

Year Ended December 31, 2002 Compared to the Year Ended December 31, 2001

Tuscarora’s net income increased $2.1 million, or 25%, to $10.4 million for the year ended December 31, 2002, compared to $8.3 million in 2001. This increase is primarily due to higher revenues, lower financial charges and higher other income.

Revenues generated by Tuscarora increased $1.8 million, or 8%, to $23.1 million for the year ended December 31, 2002, compared to $21.3 million for 2001. This increase is primarily due to incremental revenues being generated from new transportation contracts, including those related to Tuscarora’s expansion facilities, which were placed into service December 1, 2002.

Costs and expenses incurred by Tuscarora totaled $2.8 million and $2.6 million for the years ended December 31, 2002 and 2001, respectively.

Tuscarora recorded depreciation of $4.9 million and $4.6 million for the years ended December 31, 2002 and 2001, respectively.

Tuscarora recorded financial charges of $5.7 million and $6.1 million for the years ended December 31, 2002 and 2001, respectively. This decrease is due to the capitalization of interest expense in 2002 related to funds being used for the expansion.

Tuscarora recorded other income of $0.7 million and $0.3 million for the years ended December 31, 2002 and 2001, respectively. This increase is primarily due to a higher allowance recorded in 2002 related to equity funds used during construction of the expansion compared to the allowance recorded in 2001 related to the Hungry Valley lateral project.

Year Ended December 31, 2001 Compared with the Year Ended December 31, 2000

Tuscarora’s net income increased $1.5 million, or 22%, to $8.3 million for the year ended December 31, 2001, compared to $6.8 million in 2000. This increase is primarily due to higher revenues, partially offset by higher costs and expenses and higher depreciation expense.

Revenues generated by Tuscarora increased $1.9 million, or 10%, to $21.3 million for the year ended December 31, 2001, compared to $19.4 million in 2000 due to the Hungry Valley lateral which was placed into service in January 2001.

Costs and expenses incurred by Tuscarora totaled $2.6 million and $2.4 million for the years ended December 31, 2001 and 2000, respectively.

Tuscarora recorded depreciation of $4.6 million and $4.4 million for the years ended December 31, 2001 and 2000, respectively.

Tuscarora recorded financial charges of $6.1 million and $6.0 million for the years ended December 31, 2001 and 2000, respectively.

Tuscarora recorded other income of $0.3 million and $0.2 million for the years ended December 31, 2001 and 2000, respectively.

Liquidity and Capital Resources of Tuscarora Gas Transmission Company

Cash Distribution Policy of Tuscarora

In September 2000, Tuscarora adopted a cash distribution policy that became effective January 1, 2001. Under the terms of the cash distribution policy, Tuscarora will make quarterly cash distributions to its general partners in accordance with their respective general partner interests. Cash distributions will generally be computed as the sum of Tuscarora’s net income before taxes and depreciation and amortization, less amounts required for debt repayments, net of refinancings, maintenance capital expenditures, certain non-cash items, and any cash reserves deemed necessary by the Tuscarora management committee. Cash distributions will be computed at the end of each calendar quarter and the distribution will be made on or before the last day of the month following the quarter end.

Summary of Certain Contractual Obligations

			Payments Due by Period
	Total		Less Than 1 Year		1-3 Years		4-5 Years		After 5 Years
	(millions of dollars)
Series A Senior Notes due 2010	$	72.6	$	3.7	$	10.9	$	6.7	$	51.3
Series B Senior Notes due 2010	7.4		0.3		1.2		0.9		5.0
Series C Senior Notes due 2012	10.0		0.6		2.2		1.7		5.5
Credit Facility	4.6		4.6		—		—		—
Operating Leases	0.1		0.1		—		—		—
Total	$	94.7	$	9.3	$	14.3	$	9.3	$	61.8

Debt and Credit Facilities

On March 15, 2002, Tuscarora issued Series C Senior Secured Notes in the amount of $10.0 million. These notes bear interest at 6.89% and are due in 2012. The proceeds from these notes were used to finance the construction of Tuscarora’s expansion facilities.

On January 4, 2002, Tuscarora entered into a credit agreement with Bank One for a $5.0 million, 364-day revolving credit facility (Credit Facility), which bears interest at either LIBOR plus 1% or the prime rate. As at December 31, 2002, the balance outstanding on this facility was $4.6 million. The Credit Facility expired on January 3, 2003, where upon Tuscarora elected not to renew this facility and repaid the outstanding balance.

In November 2001 and January 2002, Tuscarora entered into forward starting interest rate swaps with notional amounts of $10.0 million and $8.0 million, respectively, related to the planned issuance of Series C Senior Secured Notes. The swaps were settled on February 15, 2002 for net proceeds of approximately $0.2 million. The swaps were entered into to hedge the fluctuations in treasury rates and spreads between the execution date of the swaps and the issuance date of the Series C Senior Secured Notes.

Short-term liquidity needs will be met by operating cash flows. Long-term capital needs may be met through the ability to issue long-term indebtedness.

Cash Flows from Operating Activities

Cash flows provided by operating activities increased $1.6 million, or 12%, to $15.0 million for the year ended December 31, 2002, compared to $13.4 million for 2001. This increase is the result of increased earnings during 2002, partially offset by increased working capital during the same period.

Cash flows provided by operating activities increased $2.7 million, or 25%, to $13.4 million for the year ended December 31, 2001 compared to $10.7 million for 2000. This increase is due to increased earnings and a decrease in working capital.

Cash Flows from Investing Activities

Capital expenditures of $31.9 million for the year ended December 31, 2002 included $31.6 million for Tuscarora’s expansion. Capital expenditures of $10.2 million for the year ended December 31, 2001 included $4.7 million for Tuscarora’s expansion and $2.4 million related to the construction of the Hungry Valley lateral.

Capital expenditures for the year ended December 31, 2000 included $3.7 million related to the construction of the Hungry Valley lateral.

Total capital expenditures for 2003 are estimated to be $0.4 million of which approximately $0.3 million relates to the expansion. The remainder relates to renewals and replacements of existing facilities. Tuscarora anticipates funding its 2003 capital expenditures by using a combination of partner contributions and operating cash flows.

Cash Flows from Financing Activities

Cash flows from financing activities were $16.5 million for the year ended December 31, 2002, compared to cash flows used in financing activities of $9.3 million for the year ended December 31, 2001.

In 2002, Tuscarora received net proceeds of $10.0 million from the issuance of its Series C Senior Secured Notes. The proceeds from these notes were used to finance the construction of Tuscarora’s expansion facilities.

Also, in 2002, Tuscarora drew on its Credit Facility. At December 31, 2002, $4.6 million was outstanding on the Credit Facility.

For the years ended December 31, 2002 and 2001 Tuscarora made debt repayments of $4.1 million and $4.2 million, respectively.

In 2002, Tuscarora received contributions from its partners of $15.5 million. These contributions were used to fund the construction of Tuscarora’s expansion facilities. Tuscarora received no contributions from its partners in 2001.

Tuscarora paid cash distributions of $9.3 million and $5.0 million to its general partners for the years ended December 31, 2002 and 2001, respectively. Tuscarora’s 2002 cash distributions represent four quarterly distributions. Tuscarora’s 2001 cash distributions represent three quarterly payments due to the timing of the implementation of Tuscarora’s cash distribution policy.

Cash flows used in financing activities were $1.2 million in 2000. In 2000, Tuscarora received net proceeds of $8.0 million from the issuance of its Series B Senior Secured Notes. The proceeds from these notes were used to finance the construction of the Hungry Valley lateral. Tuscarora made debt repayments of $3.6 million and paid cash distributions of $5.3 million in 2000, which was prior to the implementation of Tuscarora’s cash distribution policy.

New Accounting Pronouncements

During 2002, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards (SFAS) No. 145, “Rescission of SFAS No. 4, 44, and 64, and Amendment of SFAS No. 13,” SFAS No. 146, “Accounting for Costs Associated with Exit or Disposal Activities,” SFAS No. 147, “Acquisitions of Certain Financial Institutions – an amendment to SFAS No. 72 and 144,” and SFAS No. 148, “Accounting for Stock-Based Compensation.”

SFAS No. 145 eliminates SFAS 4, 44, and 64 as these standards have become unnecessary due to the nature of reporting that has evolved over the years since they were issued. This standard also amends SFAS 13, “Accounting for Leases” to correct for some inconsistencies in application. As at December 31, 2002, the Partnership does not hold any leases and is not affected by any of the changes resulting from this standard.

SFAS No. 146 requires that entities record a liability for the cost(s) associated with an exit or disposal activity when the liability has been incurred. Entities are not required to record a liability at the date of an entity’s commitment to a plan as this does not, by itself, create an obligation to others. Initial measurement of the obligation should approximate fair value. SFAS No. 146 is effective for exit or disposal activities that are initiated after December 31, 2002. At December 31, 2002, the Partnership was not involved in any exit or disposal activities.

SFAS No. 143, “Accounting for Asset Retirement Obligations,” was issued during 2001 and will become effective for TC PipeLines in 2003. The requirements of this standard will not have a material impact on the results of TC PipeLines. For a discussion on the effects of this standard on Northern Border Pipeline’s results, see Note 9 to Northern Border Pipeline’s Financial Statements included elsewhere in this document.

Risk Factors and Cautionary Statement Regarding Forward-Looking Information

Cautionary Statement Regarding Forward-Looking Information

A number of statements made by TC PipeLines, LP, in this Form 10-K filing made with the SEC, are forward-looking and relate to, among other things, anticipated financial performance, business prospects, strategies, market forces and commitments. Much of this information appears in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” found herein. All forward-looking statements are based on the Partnership’s beliefs as well as assumptions made by and information currently available to the Partnership. Words such as “anticipate,” “believe,” “estimate,” “expect,” “plan,” “intend,” “forecast,” and similar expressions, identify forward-

looking statements within the meaning of the Private Securities Litigation Reform Act. By its nature, such forward-looking information is subject to various risks and uncertainties, which could cause TC PipeLines’ actual results and experience to differ materially from the anticipated results or other expectations expressed in this Form 10-K. Readers are cautioned not to place undue reliance on this forward-looking information, which is as of the date of this Form 10-K. TC PipeLines undertakes no obligation to update publicly or revise any forward-looking information, whether as a result of new information, future events or otherwise.

Risk Factors

TC PipeLines may not be able to generate sufficient cash from operations to pay the minimum quarterly distribution on the common units every quarter

While TC PipeLines has a significant ownership interest in each of Northern Border Pipeline and Tuscarora, it does not control or operate either of these pipelines. The actual amount of cash TC PipeLines has available to pay the minimum quarterly distribution will depend upon numerous factors relating to each of Northern Border Pipeline’s and Tuscarora’s business, most of which are beyond the control of TC PipeLines or the general partner, including:

• the amount of cash distributed to TC PipeLines by each of Northern Border Pipeline and Tuscarora;

• the ability of Northern Border Pipeline to recontract capacity for maximum transportation rates as existing contracts terminate;

• the tariff and transportation charges collected by Northern Border Pipeline and Tuscarora for transportation services on their pipeline systems;

• increases in Northern Border Pipeline’s and Tuscarora’s operating and maintenance costs;

• payment defaults of shippers on Northern Border’s pipeline system and payment defaults of shippers on Tuscarora’s pipeline system;

• the amount of cash set aside and the adjustment in reserves made by the general partner at its discretion;

• the amount of cash required to be contributed by TC PipeLines to either Northern Border Pipeline or Tuscarora in the future;

• required principal and interest payments on TC PipeLines’ debt;

• the cost of acquisitions, including related debt service payments;

• TC PipeLines’ issuance of debt and equity securities;

• pipelines competing with Northern Border Pipeline and Tuscarora; and

• expansion costs related to these systems.

Cash distributions are dependent primarily on TC PipeLines’ cash flow, financial reserves and working capital borrowings

Cash distributions are not dependent solely on TC PipeLines’ profitability, which is affected by non-cash items. Therefore, TC PipeLines may make cash distributions during periods when losses are reported and may not make cash distributions during periods when profits are reported.

Northern Border Pipeline’s and Tuscarora’s indebtedness may limit their ability to borrow additional funds, make distributions to TC PipeLines or capitalize on business opportunities

Northern Border Pipeline is prohibited from making cash distributions during an event of default under its indebtedness. Provisions in Northern Border Pipeline’s indebtedness limit its ability to incur indebtedness and engage in specific transactions which could reduce its ability to capitalize on business opportunities that arise in the course of its business. Tuscarora is prohibited from making cash distributions during an event of default under its indebtedness. Under Tuscarora’s indebtedness, Tuscarora has granted a security interest in certain of its transportation contracts, which are available to noteholders during an event of default. Any future refinancing of Tuscarora’s existing indebtedness or any new indebtedness could have similar or greater restrictions.

If TC PipeLines is unable to make acquisitions on economically and operationally acceptable terms, either from third parties or TransCanada, TC PipeLines’ future financial performance will be limited to participation in Northern Border Pipeline and Tuscarora

The Partnership may not be able to:

• identify attractive acquisition candidates in the future;

• acquire assets on economically acceptable terms;

• make acquisitions that will not be dilutive to earnings and operating surplus; or

• incur additional debt to finance an acquisition without affecting its ability to make distributions to unitholders.

Future acquisitions may involve the expenditure of significant funds. Depending upon the nature, size and timing of future acquisitions, TC PipeLines may be required to secure additional financing. Additional financing may not be available to TC PipeLines on acceptable terms.

In addition, TC PipeLines may not be able to acquire any more of TransCanada’s United States pipeline assets. Substantially all of TransCanada’s United States pipeline assets are subject to restrictions on sale, such as rights of first refusal. Under a right of first refusal another party, usually a partner, has a right to acquire the particular asset at the price offered. Only if the other party declines to purchase the asset at the price offered could TransCanada sell it to TC PipeLines.

Majority control of the Northern Border Pipeline management committee by affiliates of Enron may limit TC PipeLines’ ability to influence Northern Border Pipeline

TC PipeLines owns a 30% general partner interest in Northern Border Pipeline. The remaining 70% general partner interest in Northern Border Pipeline is owned by Northern Border Partners, a publicly traded limited partnership. The general partners of Northern Border Partners are Northern Plains and Pan Border, both subsidiaries of Enron, and Northwest Border, a subsidiary of TransCanada. Except as to any matters requiring unanimity, such as significant expansions or extensions to the pipeline system, the acceptance of rate cases and changes to, or suspensions of, the cash distribution policy, management committee members designated by subsidiaries of Enron have the voting power to approve a particular matter requiring a majority vote despite the fact that TC PipeLines’ representative may vote against the project or other matter. Conversely, with respect to any matter requiring a majority vote, management committee members designated by subsidiaries of Enron may disapprove of a particular matter despite the fact that TC PipeLines’ representative may vote in favor of that matter.

Northern Plains Natural Gas Company may not be able to continue to efficiently operate or may be forced to cease to operate Northern Border Pipeline

Since Northern Plains is a wholly owned subsidiary of Enron it depends on Enron and some of its affiliates for some of the administrative services Northern Plains provides to Northern Border Pipeline. Potential further developments in the Enron bankruptcy situation may cause Northern Plains to be unable to provide a sufficient level of services or any services as operator. Such removal would cause an event of default under Northern Border Pipeline’s 1997 credit agreement and its 1992 note purchase agreement unless the lenders consent to the removal. Any interruption of services may have a significant impact on the operations of Northern Border Pipeline and Northern Border Pipeline may not be able to transition to a new operator in a timely and efficient manner.

Northern Border Pipeline and Tuscarora are extensively regulated by the FERC

If the FERC requires that Northern Border Pipeline’s or Tuscarora’s tariff be changed, Northern Border Pipeline’s or Tuscarora’s respective cash flows may be adversely affected.

Northern Border Pipeline and Tuscarora are subject to extensive regulation by the FERC. The FERC’s regulatory authority extends to matters including:

• transportation of natural gas;

• rates and charges;

• construction of new facilities;

• acquisitions, extension or abandonment of services and facilities;

• accounts and records;

• depreciation and amortization policies; and

• operating terms and conditions of service.

Given the extent of regulation by the FERC and potential changes to regulations, the Partnership cannot give assurance regarding:

• the likely federal regulations under which Northern Border Pipeline or Tuscarora will operate in the future;

• the effect that regulation will have on Northern Border Pipeline’s, Tuscarora’s or the Partnership’s financial positions, results of operations and cash flows; or

• whether the Partnership’s cash flow will be adequate to make distributions to unitholders.

Northern Border Pipeline’s ability to file for an increase of its rates before November 2005 to recover increases in most types of costs has been substantially eliminated by the settlement of its last rate case.

If Northern Border Pipeline or Tuscarora do not maintain or increase their respective rate bases by successfully completing FERC-approved projects, the amount of revenue attributable to the return on the rate base they collect from their shippers will decrease over time

The Northern Border and Tuscarora pipeline systems are generally allowed to collect from their customers a return on their assets or “rate base” as reflected in their financial records as well as recover that rate base through depreciation. The amount they may collect from customers decreases as the rate base declines as a result of, among other things, depreciation and amortization. In order to avoid a reduction in the level of cash available for distributions to its partners based on its current FERC-approved tariff, each of these pipelines must maintain or increase its rate base through projects that maintain or add to existing pipeline facilities. These projects will depend upon many factors including:

• sufficient demand for natural gas;

• an adequate supply of proved natural gas reserves;

• available capacity on pipelines that connect with these pipelines;

• the execution of natural gas transportation contracts;

• the approval of any expansion or extension of the pipeline systems by their respective management committees, or in some cases, a ruling from an arbitrator;

• obtaining financing for these projects; and

• receipt and acceptance of necessary regulatory approvals.

Northern Border Pipeline’s and Tuscarora’s ability to complete these projects is also dependent on numerous business, economic, regulatory, competitive and political uncertainties beyond its control, and neither Northern Border Pipeline nor Tuscarora may be able to complete these projects.

If any shipper fails to perform its contractual obligations, Northern Border Pipeline’s or Tuscarora’s respective cash flows and financial condition could be adversely impacted

If any shipper fails to perform its contractual obligations, Northern Border Pipeline’s or Tuscarora’s cash flows and financial condition could be adversely impacted. As a result, the cash available for distribution by TC PipeLines to unitholders could be reduced.

As of December 31, 2002, the three largest shippers on the Northern Border pipeline system accounted for approximately 42% of contracted capacity, with one shipper, Pan-Alberta, being obligated for approximately 20%.

Sierra Pacific Power, a wholly owned subsidiary of Sierra Pacific Resources, is Tuscarora’s largest shipper with firm contracts for 68.4% of its capacity. Sierra Pacific Resources and Sierra Pacific Power have below-investment grade credit ratings. While TC PipeLines has no current indication that Sierra Pacific Power is unable to meet its ongoing contractual obligations, TC PipeLines is unable to predict the future financial condition of Sierra Pacific Power and its long-term ability to meet its obligations under existing agreements.

Northern Border Pipeline's ability to operate its pipeline on certain tribal lands will depend on its success in renegotiating its right-of-way rights on tribal lands within the Fort Peck Reservation

Northern Border Pipeline's ability to operate its pipeline on certain tribal lands will depend on its success in renegotiating before 2011 its right-of-way rights on tribal lands within the Fort Peck Reservation. See Item 2. "Properties - Properties of Northern Border Pipeline Company." Northern Border Pipeline and the Tribes, through a mediation process, have held settlement discussions and have reached a settlement in principle on the pipeline right-of-way lease and taxation issues, subject to final documentation and necessary governmental approvals. If Northern Border Pipeline is unable to recover the additional costs of the proposed settlement in its future rates, it could have a material adverse impact on Northern Border Pipeline's results of operations.

The long-term financial conditions of Northern Border Pipeline and Tuscarora and as a result, of TC PipeLines, are dependent on the continued availability of western Canadian natural gas for import into the United States

The development of additional natural gas reserves requires 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 Northern Border’s and Tuscarora’s pipeline systems. Low prices for natural gas, regulatory limitations, or the lack of available capital for these projects could adversely affect the development of additional reserves and production, gathering, storage and pipeline transmission and import and export of natural gas supplies. Long-term contracts covering approximately 42% of Northern Border Pipeline’s capacity expire prior to November 2003. Northern Border Pipeline may not be able to replace these contracts with new long-term contracts providing similarly attractive economic terms. Substantially all of Tuscarora’s capacity is contractually committed through 2015. If the availability of western Canadian natural gas were to decline over these periods, existing shippers on the Northern Border and Tuscarora pipeline systems may be unlikely to extend their contracts and Northern Border Pipeline and Tuscarora may be unable to find replacement shippers for lost capacity. Furthermore, additional natural gas reserves may not be developed in commercial quantities and in sufficient amounts to fill the capacities of each of the Northern Border or Tuscarora pipeline systems.

Northern Border Pipeline’s and Tuscarora’s business depends in part on the level of demand for western Canadian natural gas in the markets the pipeline systems serve

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

Natural gas is also produced in the United States and transported by competing unaffiliated pipeline systems to the same destinations as natural gas transported by the Northern Border and Tuscarora pipeline systems. Other pipeline projects may be constructed in the future that may also compete with Northern Border Pipeline and Tuscarora.

A variety of factors could cause the demand for natural gas to fall in the markets that these pipeline systems serve. These factors include:

• economic conditions;

• fuel conservation measures;

• alternative energy requirements and prices;

• climatic conditions;

• government regulation; and

• technological advances in fuel economy and energy generation devices.

The Partnership cannot predict whether or how these or other factors will affect the demand for use of the Northern Border or Tuscarora pipeline systems. If either of these pipeline systems are used less over the long term, the Partnership may have lower revenues and less cash to distribute to its unitholders.

Because of the highly competitive nature of the natural gas transmission business, Northern Border Pipeline and Tuscarora may not be able to maintain existing customers or acquire new customers when the current shipper contracts expire.

Other pipeline systems that transport natural gas serve the same markets served by the Northern Border and Tuscarora pipeline systems. As a result, Northern Border Pipeline and Tuscarora face competition from other pipeline systems.

Northern Border Pipeline may not be able to renew or replace expiring contracts. The renewal or replacement of the existing long-term contracts with customers of Northern Border Pipeline depends on a number of factors beyond Northern Border Pipeline’s control, including:

• the supply of natural gas in Canada and the United States;

• competition from alternative sources of supply in the United States;

• competition from other pipelines; and

• the price of, and demand for, natural gas in markets served by the Northern Border pipeline system.

Long-term contracts covering approximately 42% of Northern Border Pipeline’s capacity expire prior to November 2003. Northern Border Pipeline may not be able to replace these contracts with new long-term contracts providing similarly attractive terms.

Tuscarora competes in the northern Nevada natural gas transmission market with Paiute Pipeline Co., owned by Southwest Gas Co. of Las Vegas, Nevada. The Paiute pipeline interconnects with Northwest Pipeline Corp. at the Nevada-Idaho border and transports gas from British Columbia and the U.S. Rocky Mountain Basin to the northern Nevada market.

TransCanada owns and operates a pipeline system which transports natural gas from the same natural gas reserves in western Canada that are used by Northern Border Pipeline’s and Tuscarora’s customers. TransCanada is not prohibited from actively competing with Northern Border Pipeline for the transport of western Canadian natural gas.

Northern Border Pipeline’s and Tuscarora’s operations are regulated by federal and state agencies responsible for environmental protection and operational safety

TC PipeLines believes that these operations comply in all material respects with applicable environmental and safety regulations. However, risks of substantial costs and liabilities are inherent in pipeline operations and each of Northern Border Pipeline and Tuscarora may incur substantial costs and liabilities in the future as a result of stricter environmental and safety laws, regulations and enforcement policies and claims for personal or property damages resulting from Northern Border Pipeline’s or Tuscarora’s operations. If either Northern Border Pipeline or Tuscarora, as applicable, was not able to recover these costs, cash distributions to TC PipeLines’ unitholders could be adversely affected.

Northern Border Pipeline’s and Tuscarora’s operations are subject to operational hazards and unforeseen interruptions, including natural disasters, adverse weather, accidents or other events beyond its control. A casualty occurrence might result in a loss of equipment or life, as well as injury and extensive property or environmental damage.

War, terrorist attacks or threats of war or terrorist attacks could have a material adverse effect on the business of Northern Border Pipeline or Tuscarora

The war with Iraq, increasing military tension with regard to North Korea, as well as the terrorist attacks of September 11, 2001 and subsequent unrest, have caused instability in the world’s financial and commercial markets and have contributed to volatility in prices for natural gas. In addition, since the September 11, 2001 attacks, the United States government has issued warnings that energy assets, including the U.S. pipeline infrastructure, may be a target of future terrorist attacks.

TC PipeLines does not have stand-alone management resources to operate without services provided by TransCanada

TransCanada provides all of TC PipeLines’ management resources. Further, TC PipeLines would not be able to evaluate potential acquisitions and successfully complete acquisitions without TransCanada’s resources.

The IRS could treat TC PipeLines as a corporation, which would substantially reduce the cash available for distribution to unitholders

Current law may change so as to cause TC PipeLines to be taxable as a corporation for federal income tax purposes or otherwise to be subject to entity-level taxation. The partnership agreement provides that, if a law is enacted or existing law is modified or interpreted in a manner that subjects TC PipeLines to taxation as a corporation or otherwise subjects TC PipeLines to entity-level taxation for federal, state or local income tax purposes, then specified provisions of the partnership agreement relating to distributions will be subject to change, including a decrease in distributions to reflect the impact of that law on TC PipeLines.

Item 7A. Quantitative and Qualitative Disclosures about Market Risk

TC PipeLines’ interest rate exposure results from its Revolving Credit Facility, which is subject to variability in LIBOR interest rates. At December 31, 2002, TC PipeLines had $11.5 million outstanding on its Revolving Credit Facility. If LIBOR interest rates change by one percent compared to the rates in effect as of December 31, 2002, annual interest expense would change by approximately $0.1 million. This amount has been determined by considering the impact of the hypothetical interest rates on variable rate borrowings outstanding as of December 31, 2002.

The Partnership’s market risk sensitivity is also influenced by and reflects the same factors that influence Northern Border Pipeline.

Northern Border Pipeline’s interest rate exposure results from variable rate borrowings from commercial banks. To mitigate potential fluctuations in interest rates, Northern Border Pipeline attempts to maintain a significant portion of its debt portfolio in fixed rate debt. Northern Border Pipeline also uses interest rate swaps as a means to manage interest expense by converting a portion of fixed rate debt into variable rate debt to take advantage of declining interest rates. At December 31, 2002, Northern Border Pipeline had $314.0 million of variable rate debt outstanding, $225.0 million of which was previously fixed rate debt but had been converted to variable rate debt through the use of interest rate swaps. For additional information on Northern Border Pipeline’s debt obligations and derivative instruments, see Note 5 and Note 6 to Northern Border Pipeline’s Financial Statements, included elsewhere in this report. As of December 31, 2002, approximately 62% of Northern Border Pipeline’s debt portfolio was in fixed rate debt.

If average interest rates change by one percent compared to rates in effect as of December 31, 2002, annual interest expense would change by approximately $3.1 million. This amount has been determined by considering the impact of the hypothetical interest rates on variable rate borrowings outstanding as of December 31, 2002.

Item 8. Financial Statements and Supplementary Data

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

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

None.

Part III

Item 10. Directors and Executive Officers of the General Partner

TC PipeLines is a limited partnership and has no officers, directors or employees. Set forth below is certain information concerning the directors and officers of the general partner. Each director holds office for a one-year term or until his or her successor is earlier appointed. All officers of the general partner serve at the discretion of the Board of Directors of the general partner.

Name	Age as of December 31, 2002	Position with General Partner as of December 31, 2002
Ronald J. Turner	49	President, Chief Executive Officer and Director
Russell K. Girling	40	Chief Financial Officer and Director
Paul F. MacGregor	45	Vice-President, Business Development
Donald R. Marchand	40	Vice-President and Treasurer
Ronald L. Cook	45	Vice-President, Taxation
Theresa Jang	38	Controller
Rhondda E.S. Grant	45	Secretary
Robert A. Helman	68	Independent Director
Jack F. Jenkins-Stark	51	Independent Director
David L. Marshall	63	Independent Director
Albrecht W.A. Bellstedt	53	Director
Dennis J. McConaghy	50	Director

Mr. Turner has been a director of the general partner since April 1999 and was appointed President and Chief Executive Officer in December 2000. Mr. Turner’s principal occupation is Executive Vice-President, Operations and Engineering of TransCanada, a position he has held since December 2000. From June 2000 until December 2000, Mr. Turner was Executive Vice-President, International of TransCanada. From April 2000 until June 2000, Mr. Turner was Senior Vice-President, International of TransCanada. From July 1999 until April 2000, Mr. Turner was Senior Vice-President and President, International of TransCanada. From July 1998 until July 1999, Mr. Turner was Senior Vice-President of TransCanada. From April 1998 until July 1998, Mr. Turner was Executive Vice-President, NOVA Gas Transmission Ltd. (natural gas transmission). From December 1997 until April 1998, Mr. Turner was Vice-President, Value Process West, NOVA Chemicals Ltd. (commodity chemicals). Mr. Turner is also a director of NOVA Gas Transmission Ltd.

Mr. Girling was appointed Chief Financial Officer and a director of the general partner in April 1999. Mr. Girling’s principal occupation is Executive Vice-President and Chief Financial Officer of TransCanada, a position he has held since June 2000. From July 1999 until June 2000, Mr. Girling was Senior Vice-President and Chief Financial Officer of TransCanada. From January 1999 until July 1999, Mr. Girling was Vice-President, Finance of TransCanada. From July 1998 until January 1999, Mr. Girling was Executive Vice-President, Power (TransCanada Energy Ltd.). From October 1995 until July 1998, Mr. Girling was Senior Vice-President, North American Power (TransCanada Energy Ltd.). Mr. Girling is a director and chairman of the board of directors of the general partner of TransCanada Power, L.P., a Canadian limited partnership. Mr. Girling is also a director of NOVA Gas Transmission Ltd.

Mr. MacGregor was appointed Vice-President, Business Development of the general partner in April 1999. Mr. MacGregor’s principal occupation is Vice-President, Eastern Business Development of TransCanada, a position he has held since September 1999. From July 1998 until September 1999, Mr. MacGregor was Vice-President, North American Pipeline Investments for TransCanada’s Transmission division. From 1997 until July 1998, Mr. MacGregor was a Vice-President of Alberta Natural Gas Company Ltd. (energy services), a former subsidiary of TransCanada which has since amalgamated into TransCanada.

Mr. Marchand was appointed Vice-President and Treasurer of the general partner in October 1999. Mr. Marchand’s principal occupation is Vice-President, Finance and Treasurer of TransCanada, a position he has held since September 1999. From January 1998 until September 1999, Mr. Marchand was Director, Finance of TransCanada. From August 1996 until January 1998, Mr. Marchand was Manager, Finance of TransCanada.

Mr. Cook was appointed Vice-President, Taxation of the general partner in April 2002. Mr. Cook’s principal occupation is Vice-President, Taxation of TransCanada, a position he has held since April 2002. From June 1997 to April 2002, Mr. Cook served as Director, Taxation of TransCanada.

Ms. Jang was appointed Controller of the general partner in June 1999. From May 1997 until June 1999, Ms. Jang was a Specialist in TransCanada’s Financial Reporting department. From February 1996 until May 1997, Ms. Jang was Supervisor, Corporate Accounting of TransCanada.

Ms. Grant was appointed Secretary of the general partner in April 1999. Ms. Grant’s principal occupation is Vice-President and Corporate Secretary of TransCanada, a position she has held since September 1999. From July 1998 until September 1999, Ms. Grant was Corporate Secretary and Associate General Counsel, Corporate of TransCanada. From October 1994 until July 1998, Ms. Grant was Corporate Secretary and Associate General Counsel, Corporate of NOVA Corporation (energy services and commodity chemicals).

Mr. Helman was appointed a director of the general partner in July 1999. Mr. Helman has been a partner of Mayer, Brown, Rowe & Maw (law firm) since 1967. Mayer, Brown, Rowe & Maw provides legal services on U.S. related matters to TransCanada, the parent of the general partner. In the first half of 2002, Mayer, Brown, Rowe & Maw provided limited legal services to the general partner on behalf of the Partnership solely relating to matters arising from Enron’s voluntary petition for bankruptcy protection. Mr. Helman did not participate, nor was he consulted in the provision of such services. Further, Mayer, Brown, Rowe & Maw no longer provides such services to the Partnership. Mr. Helman serves as a director of Dreyers Grand Ice Cream, Inc., Northern Trust Corporation and The Northern Trust Company.

Mr. Jenkins-Stark was appointed a director of the general partner in July 1999. Mr. Jenkins-Stark is currently Senior Vice-President and Chief Financial Officer of Silicon Energy Corp. (a developer and seller of internet-based energy technology software), a position he has held since April 2000. From December 1998 until April 2000, Mr. Jenkins-Stark was Senior Vice-President and Chief Financial Officer of GATX Capital (commercial finance). From September 1998 until December 1998, Mr. Jenkins-Stark was Senior Vice-President, Finance of GATX Capital. From June 1987 until May 1998, Mr. Jenkins-Stark was Senior Vice-President of PG&E Corp. and President and Chief Executive Officer of PG&E Gas Transmission Company. Mr. Jenkins-Stark also serves as a director of Hall-Kinion Corporation.

Mr. Marshall was appointed a director of the general partner in July 1999. Mr. Marshall was Vice-Chairman of The Pittston Company (diversified energy, security and transportation services firm) from 1994 until 1998 and was the Chief Financial Officer and a director of The Pittston Company from 1983 until 1994.

Mr. Bellstedt was appointed a director of the general partner in December 2001. Mr. Bellstedt’s principal occupation is Executive Vice-President, Law and General Counsel of TransCanada, a position he has held since June 2000. From April 2000 until June 2000, Mr. Bellstedt was Senior Vice-President, Law and General Counsel of TransCanada. From August 1999 until April 2000, Mr. Bellstedt was Senior Vice-President, Law and Administration of TransCanada. From February 1999 until August 1999, Mr. Bellstedt was Senior Vice-President, Law and Chief Compliance Officer of TransCanada. Prior to February 1999, Mr. Bellstedt was a senior partner of Fraser Milner, a Canadian law firm.

Mr. McConaghy was appointed a director of the general partner in December 2000. Mr. McConaghy’s principal occupation is Executive Vice-President, Gas Development of TransCanada, a position he has held since May 2001. From October 2000 until May 2001, Mr. McConaghy was Senior Vice-President, Business Development of TransCanada. From June 2000 until October 2000, Mr. McConaghy was Senior Vice-President, Midstream/Divestments of TransCanada. From July 1998 until June 2000, Mr. McConaghy was Vice-President, Corporate Strategy and Planning of TransCanada. From May 1996 until July 1998, Mr. McConaghy was Vice-President, Strategy and Corporate Development, NOVA Corporation.

The general partner’s corporate governance practices comply with the current Nasdaq Stock Market guidelines respecting corporate governance. The general partner is cognizant of the various corporate governance changes being proposed both by the Nasdaq and the SEC. The relevant charters and corporate governance guidelines of the general partner will be updated over the course of 2003 as the new governance requirements are finalized.

The Audit Committee of the Board of Directors of the general partner is comprised of its three independent members: Mr. Helman, Mr. Jenkins-Stark, and Mr. Marshall.

Section 16(a) Beneficial Ownership Reporting Compliance

Section 16(a) of the Exchange Act requires the Partnership’s directors and executive officers, and persons who own more than 10% of the common units, to file initial reports of ownership and reports of changes in ownership (Forms 3, 4, and 5) of the common units with the SEC and the Nasdaq Stock Market. Executive officers, directors and greater than 10% unitholders are required by SEC regulation to furnish the Partnership with copies of all such forms that they file.

Based solely upon a review of reports on Forms 3 and 4 and amendments thereto furnished to the Partnership during its most recent fiscal year and reports on Form 5 and amendments thereto furnished to the Partnership with respect to its most recent fiscal year, and written representations from officers and directors of the general partner that no Form 5 was required, the Partnership believes that all filing requirements applicable to its officers, directors and beneficial owners under Section 16(a) were complied with during the year ended December 31, 2002.

Item 11. Executive Compensation

The following table summarizes certain information regarding the annual salary of Ronald J. Turner, President and Chief Executive Officer of the general partner of the Partnership, for the years ended December 31, 2002, 2001 and 2000 paid by TransCanada, parent company of the general partner. Mr. Turner is an employee of TransCanada. TC PipeLines reimburses TransCanada for the services contributed to its operations by Mr. Turner.

		Annual TransCanada Base Salary(1)
Name and Principal Position	Year	Canadian Dollars	United States Dollar Equivalent(2)
Ronald J. Turner	2002	436,254	276,000
President and Chief Executive Officer	2001	412,503	259,000
	2000	309,660	206,500

(1) Annualized base salary paid by TransCanada. Based on services provided, approximately 10% of this base salary is allocated to the Partnership.

(2) The compensation of the Chief Executive Officer of the general partner is paid by TransCanada in Canadian dollars. The United States dollar equivalents have been calculated using the applicable December 31, 2002, 2001 and 2000 noon buying rates of 0.6331, 0.6279 and 0.6669, respectively, as reported by the Bank of Canada.

Each director who is not an employee of TransCanada, the general partner or its affiliates (independent director) is entitled to a directors’ retainer fee of $10,000 per annum and an additional fee of $2,000 per annum for each committee of the board of which he is Chair. These fees are paid by the Partnership on a semi-annual basis. Each independent director is also paid a fee of $1,500 for attendance at each meeting of the Board of Directors and a fee of $750 for attendance at each meeting of a committee of the Board. The independent directors are reimbursed for out-of-pocket expenses incurred in the course of attending such meetings. Under a directors’ compensation plan adopted effective July 19, 1999, each independent director receives 50% of his annual board retainer that is payable on the applicable date in the form of common units of the Partnership. The common units are purchased by the general partner on the open market and the number of common units purchased under the directors’ compensation plan is based on the trading price of common units on the day preceding the applicable payment date.

As the Partnership does not have any employees, the Audit and Compensation Committee of the Board of Directors, to April 25, 2001, and subsequently the Board of Directors of the general partner of TC PipeLines have not been called upon to make any determination with respect to compensation. The executive officers’ salaries are determined on a competitive and market basis by TransCanada.

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Matters

The following table sets forth the beneficial ownership of the voting securities of the Partnership as of March 11, 2003 by the general partner’s directors, officers and certain beneficial owners. Executive Officers of the general partner own shares of TransCanada, which in the aggregate amount to less than 1% of TransCanada’s issued and outstanding shares. Other than as set forth below, no person is known by the general partner to own beneficially more than 5% of the voting securities of the Partnership.

	Amount and Nature of Beneficial Ownership					Percentage of Interest for all Units(1)
	Common Units			Subordinated Units
Name and Business Address	Number of Units	Percent of Class		Number of Units	Percent of Class
TC PipeLines GP, Inc.(2)(3) 450 1^st Street SW Calgary, Alberta T2P 5H1	936,435	6.0		1,872,871	100	16.1
TransCan Northern Ltd.(2) 450 1^st Street SW Calgary, Alberta T2P 5H1	2,800,000	17.9		—	—	16.0
Goldman, Sachs Group Inc.(4) 85 Broad Street New York, New York 10004	1,639,717	10.5		—	—	9.4
Robert A. Helman(5) 190 S. LaSalle Street Chicago, Illinois 60603	10,852		*	—	—		*
Jack F. Jenkins-Stark(6) 1010 Atlantic Avenue Alameda, California 94501	2,852		*	—	—		*
David L. Marshall(7) 450 1^st Street SW Calgary, Alberta T2P 5H1	2,452		*	—	—		*
Ronald J. Turner 450 1^st Street SW Calgary, Alberta T2P 5H1	—	—		—	—	—
Directors and Executive Officers as a Group(8)(9) (12 persons)	16,156		*	—	—		*

(1) A total of 17,500,000 common and subordinated units are issued and outstanding.

(2) TC PipeLines GP, Inc. and TransCan Northern Ltd. are wholly owned subsidiaries of TransCanada.

(3) TC PipeLines GP, Inc. owns an aggregate 2% general partner interest of TC PipeLines.

(4) As reported on a schedule 13G/A filed on February 11, 2003, the Goldman Sachs Group, Inc. (GS Group) and Goldman, Sachs & Co. (Goldman Sachs) each disclaim beneficial ownership of the securities beneficially owned by (i) any client accounts with respect to which Goldman Sachs or employees of Goldman Sachs have voting or investment discretion, or both and (ii) certain investment entities, of which a subsidiary of GS Group or Goldman Sachs is the general partner, managing general partner or other manager, to the extent interests in such entities are held by persons other than GS Group, Goldman Sachs or their affiliates.

(5) 10,852 units are held directly by Mr. Helman.

(6) 2,852 units are held by the Jenkins-Stark Family Trust dated June 16, 1995.

(7) 2,452 units are held directly by Mr. Marshall.

(8) With the exception of the three named directors above, none of the other directors and executive officers hold any units of TC PipeLines.

(9) Ronald J. Turner holds 212,225 options and 18,169 shares of TransCanada; Russell K. Girling holds 256,412 options and 8,477 shares of TransCanada and 8,900 units of TransCanada Power, L.P.; Albrecht W.A. Bellstedt holds 209,375 options and 11,226 shares of TransCanada; and Dennis J. McConaghy holds 153,624 options and

9,114 shares of TransCanada. The directors and executive officers as a group hold 1,052,699 options and 63,729 shares of TransCanada.

* Less than 1%.

Item 13. Certain Relationships and Related Transactions

An indirect subsidiary of TransCanada owns 2,800,000 common units and the general partner owns 936,435 common units and 1,872,871 subordinated units, representing an aggregate 31.4% limited partner interest in the Partnership. In addition, the general partner owns an aggregate 2% general partner interest in the Partnership through which it manages and operates the Partnership. As a result, TransCanada’s aggregate ownership interest in the Partnership is 33.4% by virtue of its indirect ownership of the Partnership and a 31.4% aggregate limited partner interest.

The general partner is accountable to TC PipeLines and the unitholders as a fiduciary. Neither the Delaware Revised Uniform Limited Partnership Act (Delaware Act) nor case law defines with particularity the fiduciary duties owed by general partners to limited partners of a limited partnership. The Delaware Act does provide that Delaware limited partnerships may, in their partnership agreements, restrict or expand the fiduciary duties owed by a general partner to limited partners and the partnership.

In order to induce the general partner to manage the business of TC PipeLines, the partnership agreement contains various provisions restricting the fiduciary duties that might otherwise be owed by the general partner. The following is a summary of the material restrictions of the fiduciary duties owed by the general partner to the limited partners.

• The partnership agreement permits the general partner to make a number of decisions in its “sole discretion.” This entitles the general partner to consider only the interests and factors that it desires and it shall have no duty or obligation to give any consideration to any interest of, or factors affecting, TC PipeLines, its affiliates or any limited partner. Other provisions of the partnership agreement provide that the general partner’s actions must be made in its reasonable discretion.

• The partnership agreement generally provides that affiliated transactions and resolutions of conflicts of interest not involving a required vote of unitholders must be “fair and reasonable” to TC PipeLines. In determining whether a transaction or resolution is “fair and reasonable” the general partner may consider interests of all parties involved, including its own. Unless the general partner has acted in bad faith, the action taken by the general partner shall not constitute a breach of its fiduciary duty.

• The partnership agreement specifically provides that it shall not be a breach of the general partner’s fiduciary duty if its affiliates engage in business interests and activities in competition with, or in preference or to the exclusion of, TC PipeLines. Further, the general partner and its affiliates have no obligation to present business opportunities to TC PipeLines.

• The partnership agreement provides that the general partner and its officers and directors will not be liable for monetary damages to TC PipeLines, the limited partners or assignees for errors of judgment or for any acts or omissions if the general partner and those other persons acted in good faith.

TC PipeLines is required to indemnify the general partner and its officers, directors, employees, affiliates, partners, members, agents and trustees (collectively referred to hereafter as the General Partner and others), to the fullest extent permitted by law, against liabilities, costs and expenses incurred by the General Partner and others. This indemnification is required if the General Partner and others acted in good faith and in a manner they reasonably believed to be in, or (in the case of a person other than the general partner) not opposed to, the best interests of TC PipeLines. Indemnification is required for criminal proceedings if the General Partner and others had no reasonable cause to believe their conduct was unlawful.

The Partnership does not have any employees. The management and operating functions are provided by the general partner. The general partner does not receive a management fee or other compensation in connection with its management of the Partnership. The Partnership reimburses the general partner for all costs of services provided,

including the costs of employee, officer and director compensation and benefits, and all other expenses necessary or appropriate to the conduct of the business of, and allocable to the Partnership. The partnership agreement provides that the general partner will, in its sole discretion, determine the expenses that are allocable to the Partnership in any reasonable manner determined by it. Total costs reimbursed to the general partner by the Partnership were approximately $0.5 million for the year ended December 31, 2002. Such costs include personnel costs (such as salaries and employee benefits), overhead costs (such as office space and equipment) and out-of-pocket expenses related to the provision of services to the Partnership.

On May 28, 2001, 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 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, 2002, the Partnership had no amount outstanding under the TransCanada Credit Facility.

Mr. Helman, a director of the general partner of the Partnership, is a partner of the law firm of Mayer, Brown, Rowe & Maw, which provides legal services on U.S. related matters to TransCanada, the parent of the general partner. In the first half of 2002, Mayer, Brown, Rowe & Maw provided limited legal services to the general partner on behalf of the Partnership solely relating to matters arising from Enron’s voluntary petition for bankruptcy protection. Mr. Helman did not participate, nor was he consulted in the provision of such services. Further, Mayer, Brown, Rowe & Maw no longer provide such services to the Partnership.

PART IV

Item 14. Controls and Procedures

a) Evaluation of disclosure controls and procedures. Based on their evaluation of the Partnership’s disclosure controls and procedures as of a date within 90 days of the filing of this annual report, the President and Chief Executive Officer and Chief Financial Officer of the general partner of the Partnership have concluded that the disclosure controls and procedures are effective.

b) Changes in internal controls. There were no significant changes in the Partnership’s internal controls or in other factors that could significantly affect these controls subsequent to the date of their evaluation.

Item 15. Exhibits, Financial Statement Schedules and Reports on Form 8-K

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

The financial statements filed as part of this report are listed in the “Index to Financial Statements” on Page F-1.

(3)

Exhibit No.		Description

*3.1		Amended and Restated Agreement of Limited Partnership of TC PipeLines, LP dated May 28, 1999 (Exhibit 3.1 to TC PipeLines, LP’s Form 10-K, March 28, 2000).
*3.2		Certificate of Limited Partnership of TC PipeLines, LP (Exhibit 3.2 to TC PipeLines, LP’s Form S-1 Registration Statement, Registration No. 333-69947, December 30, 1998).
*3.3		Certificate of Limited Partnership of TC PipeLines Intermediate Limited Partnership (Exhibit 3.3 to TC PipeLines, LP’s Form S-1, December 30, 1998).
*3.4		Certificate of Limited Partnership of TC Tuscarora Intermediate Limited Partnership (Exhibit 99.1 to TC PipeLines, LP’s Form 8-K, September 1, 2000).
*3.5		Agreement of Limited Partnership of TC Tuscarora Intermediate Limited Partnership dated July 19, 2000 (Exhibit 99.2 to TC PipeLines, LP’s Form 8-K, September 1, 2000).
*3.6		Amended and Restated Agreement of Limited Partnership of TC PipeLines Intermediate Limited Partnership dated May 28, 1999 (Exhibit 10.1 to TC PipeLines, LP’s Form 10-K, March 28, 2000).
*4.1		Indenture, dated as of August 17, 1999 between Northern Border Pipeline Company and Bank One Trust Company, NA, successor to The First National Bank of Chicago, as trustee (Exhibit 4.1 to Northern Border Pipeline Company, Form S-4 Registration Statement, Registration No. 333-88577, October 7, 1999).
*4.2		Indenture, Assignment and Security Agreement dated December 21, 1995 between Tuscarora Gas Transmission Company and Wilmington Trust Company, as trustee (Exhibit 99.1 to TC PipeLines, LP’s Form 10-Q, September 30, 2000).
*4.3		Indenture dated September 17, 2001, between Northern Border Pipeline Company and Bank One Trust Company, N.A. (Exhibit 4.2 to Northern Border Pipeline Company, Form S-4 Registration Statement, Registration No. 333-73282, November 13, 2001).
*4.4		Indenture dated April 29, 2002, between Northern Border Pipeline Company and Bank One Trust Company, NA, as trustee (Exhibit 4.1 to Northern Border Pipeline Company’s Form 10-Q, March 31, 2002).
*10.1		Contribution, Conveyance and Assumption Agreement among TC PipeLines, LP and certain other parties dated May 28, 1999 (Exhibit 10.2 to TC PipeLines, LP’s Form 10-K, March 28, 2000).

Exhibit No.		Description
*10.2		Northern Border Pipeline Company General Partnership Agreement between Northern Border Intermediate Limited Partnership, TransCanada Border PipeLine Ltd., and TransCan Northern Ltd., effective March 9, 1978 as amended (Exhibit 3.2 to Northern Border Partners, L.P. Form S-1 Registration Statement No. 33-66158).
*10.2.1		Seventh Supplement Amending Northern Border Pipeline Company General Partnership Agreement dated as of September 23, 1993 (Exhibit 10.3.1 to TC PipeLines, LP's Form S-1, December 30, 1998).
*10.2.2		Eighth Supplement Amending Northern Border Pipeline Company General Partnership Agreement dated May 21, 1999 by and among TransCan Border PipeLine Ltd., TransCanada Northern Ltd., Northern Border Intermediate Limited Partnership and TC PipeLines Intermediate Limited Partnership (Exhibit 10.3.2 to TC PipeLines, LP’s Form 10-K, March 28, 2000).
*10.2.3		Ninth Supplement Amending Northern Border Pipeline Company General Partnership Agreement dated July 16, 2001 by and among Northern Border Intermediate Limited Partnership and TC PipeLines Intermediate Limited Partnership (Exhibit 10.37 to Northern Border Pipeline Company, Form S-4 Registration Statement, Registration No. 333-73282, November 13, 2001).
*10.3		Note Purchase Agreement between Northern Border Pipeline Company and the parties listed therein, dated July 15, 1992 (Exhibit 10.6 to Northern Border Partners, L.P.’s Form S-1 Registration Statement No. 33-66158).
*10.3.1		Supplemental Agreement to the Note Purchase Agreement dated as of June 1, 1995 (Exhibit 10.6.1 to Northern Border Partners, L.P.’s Form S-1 Registration Statement No. 33-66158).
*10.4		Renewal of U.S. $40,000,000 Two Year Revolving Credit Facility between TC PipeLines, LP, as borrower, and TransCanada PipeLines USA Ltd., as lender dated May 28, 2001 (Exhibit 1 to TC PipeLines, LP’s Form 10-Q, June 30, 2001).
*10.5		Operating Agreement between Northern Border Pipeline Company and Northern Plains Natural Gas Company, dated February 28, 1980 (Exhibit 10.3 to Northern Border Partners, L.P.’s Form S-1 Registration Statement No. 33-66158).
*10.6		Agreement among Northern Plains Natural Gas Company, Pan Border Gas Company, Northwest Border Pipeline Company, TransCanada Border PipeLine Ltd., TransCan Northern Ltd., Northern Border Intermediate Limited Partnership, Northern Border Partners, L.P., and the Management Committee of Northern Border Pipeline, dated as of March 17, 1999 (Exhibit 10.21 to Northern Border Partners, L.P.’s 1998 Form 10-K/A, March 24, 1999).
*10.7		Northern Border Pipeline Company U.S. Shippers Service Agreement between Northern Border Pipeline Company and Pan-Alberta Gas (U.S.) Inc. dated October 1, 1993, with Amended Exhibit A effective June 22, 1998 (Exhibit 10.25 to TC PipeLines, LP's Form S-1, December 30, 1998).
*10.8		Northern Border Pipeline Company U.S. Shippers Service Agreement between Northern Border Pipeline Company and Pan-Alberta Gas (U.S.) Inc. (successor to Natgas U.S. Inc.), dated October 6, 1989, with Amended Exhibit A effective April 2, 1999 (Exhibit 10.26 to TC PipeLines, LP's Form S-1, December 30, 1998).
*10.9		Northern Border Pipeline Company U.S. Shippers Service Agreement between Northern Border Pipeline Company and Pan-Alberta Gas (U.S.) Inc., dated October 1, 1992, with Amended Exhibit A effective June 22, 1998 (Exhibit 10.27 to TC PipeLines, LP's Form S-1, December 30, 1998).
*10.10		Directors’ Compensation Plan of TC PipeLines, GP, Inc. dated effective July 19, 1999 (Exhibit 10.36 to TC PipeLines, LP’s Form 10-K, March 28, 2000).
*10.11		Purchase and Sale Agreement dated July 19, 2000 among TCPL Tuscarora Ltd., TC Tuscarora Intermediate Limited Partnership, TC PipeLines GP, Inc., TransCanada PipeLines Limited and TransCanada PipeLine USA Ltd. (Exhibit 99.3 to TC PipeLines, LP’s Form 8-K, September 1, 2000).

Exhibit No.		Description
*10.12		Credit Agreement dated as of August 22, 2000 among TC PipeLines, LP, the Lenders Party thereto and Bank One N.A., as agent (Exhibit 99.2 to TC PipeLines, LP’s Form 10-Q, September 30, 2000).
*10.12.1		First Amendment and Waiver to Credit Agreement among TC PipeLines, LP, the Lenders Party thereto and Bank One N.A., as agent, April 15, 2002 (Exhibit 10.1 to TC PipeLines, LP’s Form 10-Q, September 30, 2002).
*10.12.2		Second Amendment to Credit Agreement among TC PipeLines, LP, the Lenders Party thereto and Bank One N.A., as agent, September 30, 2002 (Exhibit 10.2 to TC PipeLines, LP’s Form 10-Q, September 30, 2002).
*10.13		Employment Agreement between Northern Plains Natural Gas Company and William R. Cordes effective June 1, 2002 (Exhibit 10.27 to Northern Border Partners, L.P.’s Form 10-Q, June 30, 2001).
*10.13.1		Amendment to Employment Agreement between Northern Plains Natural Gas Company and William R. Cordes, effective September 25, 2001 (Exhibit 10.36 to Northern Border Pipeline Company’s Form S-4, November 13, 2001).
*10.14		Employment Agreement between Northern Plains Natural Gas Company and Jerry L. Peters effective April 1, 2002 (Exhibit 10.1 to Northern Border Pipeline Company’s Form 10-Q, March 31, 2002).
21.1		Subsidiaries of the Registrant.
23.1		Consent of KPMG LLP with respect to the financial statements of TC PipeLines, LP.
23.2		Consent of KPMG LLP with respect to the financial statements of Northern Border Pipeline Company.
99.1		Certification of principal executive officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
99.2		Certification of principal financial officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

* Indicates exhibits incorporated by reference.

(b) Reports on Form 8-K

None.

(d) None.

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized on this 28^th day of March 2003.

	TC PIPELINES, LP
	(A Delaware Limited Partnership)
	by its general partner, TC PipeLines GP, Inc.

	By:	/s/ Ronald J. Turner
		Ronald J. Turner
		President and Chief Executive Officer
		TC PipeLines GP, Inc.

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

Signature	Title	Date

/s/ Ronald J. Turner
Ronald J. Turner	President and Chief Executive Officer
	and Director (Principal Executive Officer)	March 28, 2003

/s/ Russell K. Girling
Russell K. Girling	Chief Financial Officer
	and Director (Principal Financial Officer)	March 28, 2003

/s/ Theresa Jang
Theresa Jang	Controller (Principal Accounting Officer)	March 28, 2003

/s/ Albrecht W.A. Bellstedt
Albrecht W. A. Bellstedt	Director	March 28, 2003

/s/ Dennis J. McConaghy
Dennis J. McConaghy	Director	March 28, 2003

/s/ Robert A. Helman
Robert A. Helman	Director	March 28, 2003

/s/ Jack F. Jenkins-Stark
Jack F. Jenkins-Stark	Director	March 28, 2003

/s/ David L. Marshall
David L. Marshall	Director	March 28, 2003

CERTIFICATIONS

I, Ronald J. Turner, certify that:

1. I have reviewed this annual report on Form 10-K of TC PipeLines, LP;

2. Based on my knowledge, this annual report does not contain any untrue statements of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;

3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;

4. The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:

a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;

b) evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the “Evaluation Date”); and

c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

5. The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent function):

a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant’s ability to record, process, summarize and report financial data and have identified for the registrant’s auditors any material weaknesses in internal controls; and

b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and

6. The registrant’s other certifying officers and I have indicated in this annual report whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

Dated: March 28, 2003


	/s/ Ronald J. Turner
	Ronald J. Turner
	President and Chief Executive Officer
	TC PipeLines GP, Inc., as general partner

I, Russell K. Girling, certify that:

1. I have reviewed this annual report on Form 10-K of TC PipeLines, LP;

b) evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the “Evaluation Date”); and

c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and

Dated: March 28, 2003


	/s/ Russell K. Girling
	Russell K. Girling
	Chief Financial Officer
	TC PipeLines GP, Inc., as general partner

TC PIPELINES, LP

INDEX TO FINANCIAL STATEMENTS

Financial Statements of TC PipeLines, LP

Independent Auditors’ Report

Balance Sheet – December 31, 2002 and 2001

Statement of Income – Years Ended December 31, 2002, 2001 and 2000

Statement of Comprehensive Income – Years Ended December 31, 2002, 2001 and 2000

Statement of Cash Flows – Years Ended December 31, 2002, 2001 and 2000

Statement of Changes in Partners’ Equity – Years Ended December 31, 2002, 2001 and 2000

Notes to Financial Statements

Financial Statements of Northern Border Pipeline Company

Independent Auditors’ Report

Balance Sheet – December 31, 2002 and 2001

Statement of Income – Years Ended December 31, 2002, 2001 and 2000

Statement of Comprehensive Income – Years Ended December 31, 2002, 2001 and 2000

Statement of Cash Flows – Years Ended December 31, 2002, 2001 and 2000

Statement of Changes in Partners’ Equity – Years Ended December 31, 2002, 2001 and 2000

Notes to Financial Statements

Financial Statements Schedule of Northern Border Pipeline Company

Independent Auditors’ Report on Schedule

Schedule II – Valuation and Qualifying Accounts

F-1

Independent Auditors’ Report

To the Board of Directors of TC PipeLines GP, Inc., General Partner of TC PipeLines, LP:

We have audited the accompanying balance sheets of TC PipeLines, LP (a Delaware limited partnership) as of December 31, 2002 and 2001 and the related statements of income, comprehensive income, cash flows and changes in partners’ equity for each of the years in the three year period ended December 31, 2002. These financial statements are the responsibility of the General Partner. Our responsibility is to express an opinion on these financial statements based on our audits.

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

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of TC PipeLines, LP as of December 31, 2002 and 2001 and the results of its operations and its cash flows for each of the years in the three year period ended December 31, 2002 in conformity with accounting principles generally accepted in the United States of America.

/s/ KPMG LLP

Calgary, Canada
March 7, 2003

F-2

TC PipeLines, LP
Balance Sheet

December 31 (millions of dollars)	2002	2001

Assets
Current Assets
Cash	6.4	9.2

Investment in Northern Border Pipeline	242.9	250.1
Investment in Tuscarora	36.7	29.3
Deferred Amounts	—	0.1
	286.0	288.7

Liabilities and Partners’ Equity
Current Liabilities
Accounts payable	0.6	0.4
Accrued interest	—	0.1
	0.6	0.5

Long-Term Debt	11.5	21.5

Partners’ Equity
Common units	238.9	219.0
Subordinated units	27.0	39.2
General partner	5.9	5.5
Other comprehensive income	2.1	3.0
	273.9	266.7
	286.0	288.7

Statement of Income

	Year ended December 31,
(millions of dollars, except per unit amounts)	2002			2001			2000
Equity Income from Investment in Northern Border Pipeline	42.8			42.1			38.1
Equity Income from Investment in Tuscarora	4.7			3.6			0.9
General and Administrative Expenses	(1.5		)	(1.2		)	(1.3		)
Financial Charges	(0.5		)	(1.0		)	(0.5		)
Net Income	45.5			43.5			37.2

Net Income per Unit	$	2.50		$	2.40		$	2.08

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

F-3

TC PipeLines, LP

Statement of Comprehensive Income

	Year ended December 31,
(millions of dollars)	2002		2001		2000
Net Income	45.5		43.5		37.2
Other Comprehensive Income
Transition adjustment from adoption of SFAS No. 133	—		3.1		—
Change associated with current period hedging transactions	(0.9	)	(0.1	)	—
Total Comprehensive Income	44.6		46.5		37.2

Statement of Cash Flows

	Year ended December 31,
(millions of dollars)	2002		2001		2000
Cash Generated from Operations
Net Income	45.5		43.5		37.2
Add/(deduct):
Equity income less than/(in excess of) distributions received	6.3		(0.4	)	2.9
Increase/(decrease) in accounts payable	0.2		(0.1	)	0.1
(Decrease)/increase in accrued interest	(0.1	)	(0.1	)	0.1
Other	0.2		—		—
	52.1		42.9		40.3
Investing Activities
Investment in Tuscarora	(7.4	)	—		(28.4	)
Deferred amounts	—		(0.1	)	—
	(7.4	)	(0.1	)	(28.4	)
Financing Activities
Distributions paid	(37.4	)	(35.2	)	(32.6	)
Long-term debt issued	—		—		24.5
Reduction of long-term debt	(10.0	)	—		(3.0	)
Other	(0.1	)	—		—
	(47.5	)	(35.2	)	(11.1	)
(Decrease)/Increase in Cash	(2.8	)	7.6		0.8
Cash, Beginning of Period	9.2		1.6		0.8
Cash, End of Period	6.4		9.2		1.6

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

F-4

TC PipeLines, LP

Statement of Changes in Partners’ Equity

Common Units

Subordinated
Units

General
Partner

Other
Comprehensive
Income

Partners’
Equity

(millions
of
units)

(millions
of
dollars)

(millions
of
units)

(millions
of
dollars)

(millions
of
units)

(millions
of
dollars)

Partners’ Equity at December 31, 1999

14.7

208.6

2.8

37.2

5.0

—

17.5

250.8

Net Income

—

30.5

—

5.8

0.9

—

37.2

Distributions Paid

—

(26.8

)

—

(5.1

)

(0.7

)

—

(32.6

)

Partners’ Equity at December 31, 2000

14.7

212.3

2.8

37.9

5.2

—

17.5

255.4

Net Income

—

35.3

—

6.8

1.4

—

43.5

Distributions Paid

—

(28.6

)

—

(5.5

)

(1.1

)

—

(35.2

)

Other Comprehensive Income

—

3.0

—

3.0

Partners’ Equity at December 31, 2001

14.7

219.0

2.8

39.2

5.5

3.0

17.5

266.7

Net Income

—

37.5

—

6.2

1.8

—

45.5

Distributions Paid

—

(30.7

)

—

(5.3

)

(1.4

)

—

(37.4

)

Subordinated Unit Conversion

0.9

13.1

(0.9

)

(13.1

)

—

Other Comprehensive Income

—

(0.9

)

—

(0.9

)

Partners’ Equity at December 31, 2002

15.6

238.9

1.9

27.0

5.9

2.1

17.5

273.9

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

F-5

TC PipeLines, LP

Notes to Financial Statements

Note 1 Organization

TC PipeLines, LP, and its subsidiary limited partnerships, TC PipeLines Intermediate Limited Partnership and TC Tuscarora Intermediate Limited Partnership, all Delaware limited partnerships, are collectively referred to herein as TC PipeLines or the Partnership. TC PipeLines was formed by TransCanada PipeLines Limited (TransCanada) to acquire, own and participate in the management of United States-based pipeline assets.

TC PipeLines owns a 30% general partner interest in Northern Border Pipeline Company (Northern Border Pipeline), a Texas general partnership. Northern Border Pipeline owns a 1,249-mile United States interstate pipeline system that transports natural gas from the Montana-Saskatchewan border to markets in the midwestern United States.

TC PipeLines also owns a 49% general partner interest in Tuscarora Gas Transmission Company (Tuscarora), a Nevada general partnership. Tuscarora owns a 240-mile United States interstate pipeline system that transports natural gas from Oregon, where it interconnects with facilities of PG&E National Energy Group, Gas Transmission Northwest, to northern Nevada.

TC PipeLines is managed by its general partner, TC PipeLines GP, Inc. (General Partner), a wholly-owned subsidiary of TransCanada. The General Partner provides certain administrative services for the Partnership and is reimbursed for its costs and expenses. In addition to its 2% general partner interest, the General Partner owns 936,435 common units and 1,872,871 subordinated units, representing an effective 15.7% limited partner interest in the Partnership at December 31, 2002. TransCanada indirectly holds 2,800,000 common units representing an effective 15.7% limited partner interest in the Partnership at December 31, 2002.

Note 2 Significant Accounting Policies

(a) Basis of Presentation

The accompanying financial statements and related notes present the financial position of the Partnership as of December 31, 2002 and 2001 and the results of its operations, cash flows and changes in partners’ equity for the years ended December 31, 2002, 2001 and 2000. The Partnership uses the equity method of accounting for its investments in Northern Border Pipeline and Tuscarora, over which it is able to exercise significant influence. Other comprehensive income recorded by TC PipeLines arises through its equity investments in Northern Border Pipeline and Tuscarora and relates to cash flow hedges transacted by Northern Border Pipeline and Tuscarora. Amounts are stated in United States dollars.

(b) Use of Estimates

The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities as at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Although management believes these estimates are reasonable, actual results could differ from these estimates.

F-6

(c) Cash and Cash Equivalents

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

(d) Partners’ Equity

Costs incurred in connection with the issuance of units are deducted from the proceeds received. Costs incurred to convert subordinated units to common units were deducted from Partners’ Equity.

(e) Income Taxes

No provision for income taxes related to the operations of the Partnership is included in the accompanying financial statements because, as a partnership, it is not subject to Federal or state income tax. The tax effect of the Partnership’s activities accrues to its partners.

F-7

Note 3 Investment in Northern Border Pipeline Company

The Partnership owns a 30% general partner interest in Northern Border Pipeline. The remaining 70% partnership interest in Northern Border Pipeline is held by Northern Border Partners, L.P. (NBP), a publicly traded limited partnership. The Northern Border pipeline system is operated by Northern Plains Natural Gas Company, a wholly-owned subsidiary of Enron. Northern Border Pipeline is regulated by the Federal Energy Regulatory Commission (FERC).

TC PipeLines’ equity income amounted to $42.8 million, $42.1 million and $38.1 million for the years ended December 31, 2002, 2001 and 2000, respectively, representing 30% of the net income of Northern Border Pipeline for the same periods. Undistributed earnings of Northern Border Pipeline amounted to $1.3 million, $8.4 million and $6.4 million for the years ended December 31, 2002, 2001 and 2000, respectively.

The following sets out summarized financial information for Northern Border Pipeline as at December 31, 2002 and 2001 and for the years ended December 31, 2002, 2001 and 2000.

December 31 (millions of dollars)	2002	2001
Northern Border Pipeline Balance Sheet
Assets
Cash and cash equivalents	25.4	11.0
Other current assets	40.8	36.3
Plant, property and equipment, net	1,636.0	1,685.7
Other assets	37.8	18.9
	1,740.0	1,751.9
Liabilities and Partners’ Equity
Current liabilities	130.9	399.0
Reserves and deferred credits	15.4	5.6
Long-term debt	783.9	513.7
Partners’ Equity
Partners’ capital	803.0	824.4
Accumulated other comprehensive income	6.8	9.2
	1,740.0	1,751.9

Year ended December 31 (millions of dollars)	2002		2001		2000
Northern Border Pipeline Income Statement
Revenues	321.0		313.1		311.0
Costs and expenses	(69.9	)	(59.3	)	(69.5	)
Depreciation	(58.7	)	(57.5	)	(57.3	)
Financial charges	(51.5	)	(55.4	)	(65.2	)
Other income/(expense)	1.8		(0.4	)	8.1
Net income	142.7		140.5		127.1

Note 4 Investment in Tuscarora Gas Transmission Company

The Partnership owns a 49% general partner interest in Tuscarora. The remaining general partner interests in Tuscarora are held 50% by Sierra Pacific Resources and 1% by TransCanada. Tuscarora is regulated by the FERC.

F-8

TC PipeLines’ equity income from Tuscarora amounted to $4.7 million, $3.6 million and $0.9 million for the years ended December 31, 2002 and 2001 and the period September 1 to December 31, 2000, respectively, representing 49% of the net income of Tuscarora for the same periods. Undistributed earnings of Tuscarora amounted to $0.8 million, $0.9 million and nil for the years ended December 31, 2002 and 2001 and the period September 1 to December 31, 2000, respectively.

The following sets out summarized financial information for Tuscarora as at December 31, 2002 and 2001 and for the years ended December 31, 2002 and 2001 and the period September 1 to December 31, 2000. TC PipeLines has held its general partner interest since September 1, 2000.

December 31 (millions of dollars)	2002	2001
Tuscarora Balance Sheet
Assets
Cash and cash equivalents	0.6	1.1
Other current assets	4.3	2.1
Plant, property and equipment, net	148.4	121.3
Other assets	1.2	1.6
	154.5	126.1

Liabilities and Partners’ Equity
Current liabilities	14.6	7.7
Long-term debt	85.3	80.0
Partners’ Equity
Partners’ capital	54.2	37.9
Accumulated other comprehensive income	0.4	0.5
	154.5	126.1

Year ended December 31 (millions of dollars)	2002		2001		2000
Tuscarora Income Statement
Revenues	23.1		21.3		19.4
Costs and expenses	(2.8	)	(2.6	)	(2.4	)
Depreciation	(4.9	)	(4.6	)	(4.4	)
Financial charges	(5.7	)	(6.1	)	(6.0	)
Other (expense)/income	0.7		0.3		0.2
Net income	10.4		8.3		6.8

Note 5 Credit Facilities and Long-Term Debt

On September 30, 2002, the Partnership renewed its credit facility (Revolving Credit Facility) with Bank One, NA, as administrative agent of the credit facility under which the Partnership may borrow up to an aggregate principal amount of $20.0 million. Loans under the Revolving Credit Facility bear interest at a floating rate. The Revolving Credit Facility matures on July 31, 2004. 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. At December 31, 2002, the Partnership had borrowings of $11.5 million outstanding under the Revolving Credit Facility (2001 – $21.5 million). The fair value of the Revolving Credit Facility approximates its carrying value because the interest rate is a floating rate. The interest rate on the Revolving Credit Facility averaged 3.57% for the year (2001 – 5.19%; 2000 – 7.57%) and

F-9

was 2.70% at the end of the year (2001 – 3.02%). Interest paid during the years ended December 31, 2002, 2001 and 2000 was $0.4 million, $1.2 million and $0.5 million, respectively.

On May 28, 2001, the Partnership renewed its $40.0 million unsecured two-year revolving credit facility (TransCanada Credit Facility), with TransCanada PipeLines USA Ltd., an affiliate of the General Partner. The TransCanada Credit Facility bears interest at London Interbank Offered Rate 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, 2002 and 2001, the Partnership had no amount outstanding under the TransCanada Credit Facility.

Note 6 Partners’ Capital and Cash Distributions

Partners’ capital consists of 15,627,129 common units representing an 87.5% limited partner interest (936,435 common units are held by the General Partner and 2,800,000 common units are owned by an affiliate of the General Partner), 1,872,871 subordinated units owned by the General Partner representing a 10.5% limited partner interest and a 2% general partner interest. In aggregate the General Partner’s and its affiliate’s interests represent an effective 33.4% ownership of the Partnership’s equity.

The Partnership makes cash distributions to its partners with respect to each calendar quarter within 45 days after the end of each quarter. Distributions are based on Available Cash, which includes all cash and cash equivalents of the Partnership and working capital borrowings less reserves established by the General Partner. The Unitholders are entitled to receive the minimum quarterly distribution (MQD) of $0.45 per unit if and to the extent there is sufficient Available Cash. Distributions to holders of the subordinated units are subject, while subordinated units remain outstanding (Subordination Period), to the prior rights of holders of the common units to receive the MQD. Common units will not accrue arrearages with respect to distributions for any quarter after the Subordination Period and subordinated units will not accrue any arrearages with respect to distributions for any quarter.

The Subordination Period generally cannot end before June 30, 2004. Upon expiration of the Subordination Period, all subordinated units will be converted on a one-for-one basis into common units and will participate pro rata with all other common units in future distributions. On August 1, 2002, 936,435 subordinated units, representing one-third of the then outstanding subordinated units held by the General Partner, upon satisfaction of the tests set forth in the partnership agreement, automatically converted into an equal number of common units as provided for in the partnership agreement of TC PipeLines. A second one-third of subordinated units (936,435 subordinated units) may convert into common units on a one-for-one basis on the first day after the record date established for the distribution in respect of any quarter ending on or after June 30, 2003.

As an incentive, the General Partner’s percentage interest in quarterly distributions is increased after certain specified target levels are met. The incremental incentive distributions payable to the General Partner are 15%, 25% and 50% of all quarterly distributions of

F-10

Available Cash that exceed target levels of $0.45, $0.5275 and $0.69, respectively, per unit. For the years ended December 31, 2002, 2001 and 2000, the Partnership distributed $2.075, $1.975 and $1.85, respectively, per unit. The distributions for the year ended December 31, 2002, 2001 and 2000 included incentive distributions to the General Partner in the amount of $0.8 million, $0.5 million and $0.2 million, respectively.

Partnership income is allocated to the General Partner and the limited partners in accordance with their respective partnership percentages, after giving effect to any priority income allocations for incentive distributions that are allocated 100% to the General Partner.

Note 7 Net Income per Unit

Net income per unit is computed by dividing net income, after deduction of the General Partner’s allocation, by the weighted average number of common and subordinated units outstanding. The General Partner’s allocation is equal to an amount based upon the General Partner’s 2% interest, adjusted to reflect an amount equal to incentive distributions. Net income per unit was determined as follows:

	Year ended December 31,
(millions of dollars, except per unit amounts)	2002			2001			2000
Net Income	45.5			43.5			37.2
Net income allocated to General Partner	(0.9		)	(0.8		)	(0.7		)
Adjustment to reflect incentive distribution income allocation	(0.9		)	(0.6		)	(0.2		)
	(1.8		)	(1.4		)	(0.9		)
Net income allocable to units	43.7			42.1			36.3
Weighted average units outstanding (millions)	17.5			17.5			17.5
Net income per unit	$	2.50		$	2.40		$	2.08

Note 8 Related Party Transactions

The Partnership does not have any employees. The management and operating functions are provided by the General Partner. The General Partner does not receive a management fee or other compensation in connection with its management of the Partnership. The Partnership reimburses the General Partner for all costs of services provided, including the costs of employee, officer and director compensation and benefits, and all other expenses necessary or appropriate to the conduct of the business of, and allocable to the Partnership. The Partnership Agreement provides that the General Partner will determine the expenses that are allocable to the Partnership in any reasonable manner determined by the General Partner in its sole discretion. Total costs reimbursed to the General Partner by the Partnership were approximately $0.5 million, $0.5 million and $0.7 million for the years ended December 31, 2002, 2001 and 2000, respectively. Such costs include (i) personnel costs (such as salaries and employee benefits), (ii) overhead costs (such as office space and equipment) and (iii) out-of-pocket expenses related to the provision of such services.

F-11

Note 9 Quarterly Financial Data (unaudited)

The following sets forth selected financial data for the four quarters of 2002 and 2001.

Quarter ended (millions of dollars, except per unit amounts)

March 31

June 30

September 30

December 31

2002

Equity Income

12.4

12.6

12.9

9.6

Net Income

11.9

12.2

12.5

8.9

Net Income per Unit

0.66

0.67

0.68

0.49

Cash Distributions Paid

9.0

9.6

2001

Equity Income

11.7

10.3

11.5

12.2

Net Income

10.9

9.8

11.0

11.8

Net Income per Unit

0.61

0.54

0.60

0.65

Cash Distributions Paid

8.5

9.0

9.1

Note 10 Accounting Pronouncements

SFAS No. 145 eliminates SFAS 4, 44, and 64 as these standards have become unnecessary due to the nature of reporting that has evolved over the years since they were issued. This standard also amends SFAS 13, “Accounting for Leases” to correct for some inconsistencies in application. As at December 31, 2002, TC PipeLines does not hold any leases and is not affected by any of the changes resulting from this standard.

SFAS No. 146 requires that entities record a liability for the cost(s) associated with an exit or disposal activity when the liability has been incurred. Entities are not required to record a liability at the date of an entity’s commitment to a plan as this does not, by itself, create an obligation to others. Initial measurement of the obligation should approximate fair value. This Statement is effective for exit or disposal activities that are initiated after December 31, 2002. At December 31, 2002, the Partnership was not involved in any exit or disposal activities.

SFAS No. 143, "Accounting for Asset Retirement Obligations," was issued during 2001 and will become effective for the Partnership in 2003. The requirements of this standard will not have a material impact on the results of TC PipeLines.

Note 11 Subsequent Events

On January 21, 2003, the Board of Directors of the General Partner declared a cash distribution of $0.525 per unit related to the three months ended December 31, 2002. The $9.6 million distribution is payable on February 14, 2003 in the following manner: $8.2 million to the holders of common units as of the close of business on January 31, 2003, $1.0 million to the General Partner as holder of the subordinated units, $0.2 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.

F-12

Independent Auditors’ Report

Northern Border Pipeline Company:

We have audited the accompanying balance sheets of Northern Border Pipeline Company (a Texas partnership) as of December 31, 2002 and 2001, and the related statements of income, comprehensive income, cash flows, and changes in partners’ equity for each of the years in the three-year period ended December 31, 2002. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

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

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Northern Border Pipeline Company as of December 31, 2002 and 2001, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2002, in conformity with accounting principles generally accepted in the United States of America.

KPMG LLP

January 23, 2003
Omaha, Nebraska

F-13

NORTHERN BORDER PIPELINE COMPANY

BALANCE SHEET

(In Thousands)

	December 31,
	2002		2001
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	25,358	$	11,003
Accounts receivable (net of allowance for doubtful accounts of $1,925 in 2001)	32,774		29,249
Related party receivables (net of allowance for doubtful accounts of $4,805 and $1,251 in 2002 and 2001, respectively)	1,552		455
Materials and supplies, at cost	4,721		4,873
Prepaid expenses and other	1,844		1,731

Total current assets	66,249		47,311

NATURAL GAS TRANSMISSION PLANT
In service	2,427,459		2,429,662
Construction work in progress	4,027		2,891

Total property, plant and equipment	2,431,486		2,432,553
Less: Accumulated provision for depreciation and amortization	795,525		746,888

Property, plant and equipment, net	1,635,961		1,685,665

OTHER ASSETS
Derivative financial instruments	21,204		3,366
Other	16,623		15,527

Total other assets	37,827		18,893

Total assets	$	1,740,037	$	1,751,869

LIABILITIES AND PARTNERS’ EQUITY
CURRENT LIABILITIES
Current maturities of long-term debt	$	65,000	$	350,000
Accounts payable	17,103		3,089
Related party payables	7,323		2,204
Accrued taxes other than income	28,374		27,167
Accrued interest	13,173		16,526

Total current liabilities	130,973		398,986

LONG-TERM DEBT, NET OF CURRENT MATURITIES	783,906		513,666

RESERVES AND DEFERRED CREDITS	15,386		5,623

COMMITMENTS AND CONTINGENCIES (Note 7)

PARTNERS’ EQUITY
Partners’ capital	803,014		824,421
Accumulated other comprehensive income	6,758		9,173

Total partners’ equity	809,772		833,594

Total liabilities and partners’ equity	$	1,740,037	$	1,751,869

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

F-14

NORTHERN BORDER PIPELINE COMPANY

STATEMENT OF INCOME

(In Thousands)

	Year Ended December 31,
	2002			2001			2000
OPERATING REVENUES
Operating revenues	$	321,050		$	315,145		$	334,978
Provision for rate refunds	—			(2,057		)	(23,956		)

Operating revenues, net	321,050			313,088			311,022

OPERATING EXPENSES
Operations and maintenance	41,442			33,695			41,548
Depreciation and amortization	58,714			57,516			57,328
Taxes other than income	28,436			25,636			27,979

Operating expenses	128,592			116,847			126,855

OPERATING INCOME	192,458			196,241			184,167

INTEREST EXPENSE
Interest expense	51,550			56,262			65,489
Interest expense capitalized	(25		)	(911		)	(328		)

Interest expense, net	51,525			55,351			65,161

OTHER INCOME (EXPENSE)
Allowance for equity funds used during construction	26			925			305
Other income (expense), net	1,760			(1,357		)	7,753

Other income (expense)	1,786			(432		)	8,058

NET INCOME TO PARTNERS	$	142,719		$	140,458		$	127,064

NORTHERN BORDER PIPELINE COMPANY

STATEMENT OF COMPREHENSIVE INCOME

(In Thousands)

	Year Ended December 31,
	2002			2001			2000
Net income to partners	$	142,719		$	140,458		$	127,064
Other comprehensive income:
Transition adjustment from adoption of SFAS No. 133	—			10,347			—
Change associated with current period hedging transactions	(2,415		)	(1,174		)	—

Total comprehensive income	$	140,304		$	149,631		$	127,064

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

F-15

NORTHERN BORDER PIPELINE COMPANY

STATEMENT OF CASH FLOWS

(In Thousands)

	Year Ended December 31,
	2002			2001			2000
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income to partners	$	142,719		$	140,458		$	127,064

Adjustments to reconcile net income to partners to net cash provided by operating activities:
Depreciation and amortization	59,079			57,881			57,682
Provision for rate refunds	—			2,036			25,082
Rate refunds paid	—			(6,762		)	(22,673		)
Allowance for equity funds used during construction	(26		)	(925		)	(305		)
Reserves and deferred credits	9,763			736			(5,806		)
Changes in components of working capital	12,404			4,583			(3,002		)
Other	(447		)	(685		)	(2,075		)

Total adjustments	80,773			56,864			48,903

Net cash provided by operating activities	223,492			197,322			175,967

CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures for property, plant and equipment, net	(8,379		)	(54,659		)	(15,523		)

CASH FLOWS FROM FINANCING ACTIVITIES:
Distributions to partners	(164,126		)	(143,032		)	(134,904		)
Issuance of long-term debt, net	431,894			385,400			75,000
Retirement of long-term debt	(468,000		)	(374,000		)	(111,000		)
Increase (decrease) in bank overdrafts	—			(22,437		)	22,437
Proceeds received (paid) upon termination of derivatives	2,351			(4,070		)	—
Long-term debt financing costs	(2,877		)	(2,567		)	(241		)

Net cash used in financing activities	(200,758		)	(160,706		)	(148,708		)

NET CHANGE IN CASH AND CASH EQUIVALENTS	14,355			(18,043		)	11,736

Cash and cash equivalents-beginning of year	11,003			29,046			17,310

Cash and cash equivalents-end of year	$	25,358		$	11,003		$	29,046

Changes in components of working capital:
Accounts receivable	$	(4,622	)	$	3,432		$	(6,087	)
Materials and supplies	152			(163		)	(1,767		)
Prepaid expenses and other	(113		)	(1,484		)	455
Accounts payable	19,133			1,643			1,585
Accrued taxes other than income	1,207			(970		)	1,847
Accrued interest	(3,353		)	2,125			(2,103		)
Over/under recovered cost of service	—			—			3,068

Total	$	12,404		$	4,583		$	(3,002	)

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

F-16

NORTHERN BORDER PIPELINE COMPANY

STATEMENT OF CHANGES IN PARTNERS’ EQUITY

(In Thousands)

	TC PipeLines Intermediate Limited Partnership			Northern Border Intermediate Limited Partnership			Accumulated Other Comprehensive Income			Total Partners’ Equity
Partners’ Equity at December 31, 1999	$	250,450		$	584,385		$	—		$	834,835
Net income to partners	38,119			88,945			—			127,064
Distributions paid	(40,471		)	(94,433		)	—			(134,904		)
Partners’ Equity at December 31, 2000	248,098			578,897			—			826,995
Net income to partners	42,138			98,320			—			140,458
Transition adjustment from adoption of SFAS No. 133	—			—			10,347			10,347
Change associated with current period hedging transactions	—			—			(1,174		)	(1,174		)
Distributions paid	(42,910		)	(100,122		)	—			(143,032		)
Partners’ Equity at December 31, 2001	247,326			577,095			9,173			833,594
Net income to partners	42,816			99,903			—			142,719
Change associated with current period hedging transactions	—			—			(2,415		)	(2,415		)
Distributions paid	(49,238		)	(114,888		)	—			(164,126		)
Partners’ Equity at December 31, 2002	$	240,904		$	562,110		$	6,758		$	809,772

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

F-17

NORTHERN BORDER PIPELINE COMPANY

NOTES TO FINANCIAL STATEMENTS

1. ORGANIZATION AND MANAGEMENT

Northern Border Pipeline Company (Northern Border Pipeline) is a Texas general partnership formed in 1978. The ownership percentages of the partners in Northern Border Pipeline (Partners) at December 31, 2002 and 2001, are as follows:

Partner		Ownership Percentage
Northern Border Intermediate Limited Partnership		70
TC PipeLines Intermediate Limited Partnership		30

Northern Border Pipeline owns a 1,249-mile natural gas transmission pipeline system extending from the United States-Canadian border near Port of Morgan, Montana, to a terminus near North Hayden, Indiana.

Northern Border Pipeline is managed by a Management Committee that includes three representatives from Northern Border Intermediate Limited Partnership (Partnership) and one representative from TC PipeLines Intermediate Limited Partnership (TC PipeLines). The Partnership’s representatives selected by its general partners, Northern Plains Natural Gas Company (Northern Plains), a wholly-owned subsidiary of Enron Corp. (Enron), Pan Border Gas Company (Pan Border), a wholly-owned subsidiary of Northern Plains, and Northwest Border Pipeline Company, a wholly-owned subsidiary of TransCanada PipeLines Limited and affiliate of TC PipeLines, have 35%, 22.75% and 12.25%, respectively, of the voting interest on the Management Committee. The representative designated by TC PipeLines votes the remaining 30% interest. The day-to-day management of Northern Border Pipeline’s affairs is the responsibility of Northern Plains, as defined by an operating agreement between Northern Border Pipeline and Northern Plains. Northern Border Pipeline is charged for the salaries, benefits and expenses of Northern Plains. Northern Plains also utilizes Enron affiliates for management services related to Northern Border Pipeline. For the years ended December 31, 2002, 2001, and 2000, Northern Border Pipeline’s charges from Northern Plains and its affiliates totaled approximately $22.8 million, $29.5 million and $31.7 million, respectively. See Note 10 for a discussion of Northern Border Pipeline’s relationships with Enron and developments involving Enron.

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

(A) Use of Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States 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.

(B) Government Regulation

Northern Border Pipeline is subject to regulation by the Federal Energy Regulatory Commission (FERC). Northern Border Pipeline’s accounting policies conform to Statement of Financial Accounting Standards (SFAS) No. 71, “Accounting for the Effects of Certain Types of Regulation.”

F-18

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 recovery of the regulatory assets is probable by considering such factors as regulatory changes and the impact of competition. Northern Border Pipeline believes the recovery of the existing regulatory assets is probable. 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, 2002 and 2001, Northern Border Pipeline has reflected regulatory assets of approximately $10.5 million and $11.5 million, respectively, in other assets on the balance sheet. Northern Border Pipeline is recovering the regulatory assets from its shippers over varying time periods, which range from five to 44 years.

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

(D) Income Taxes

Income taxes are the responsibility of the Partners and are not reflected in these financial statements. However, the Northern Border Pipeline FERC tariff establishes the method of accounting for and calculating income taxes and requires Northern Border Pipeline to reflect in its rates the income taxes, which would have been paid or accrued if Northern Border Pipeline were organized during the period as a corporation. As a result, for purposes of determining transportation rates in calculating the return allowed by the FERC, Partners’ capital and rate base are reduced by the amount equivalent to the net accumulated deferred income taxes. Such amounts were approximately $343 million and $336 million at December 31, 2002 and 2001, respectively, and are primarily related to accelerated depreciation and other plant-related differences.

(E) Cash and Cash Equivalents

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

Property, plant and equipment is stated at original cost. During periods of construction, Northern Border Pipeline is permitted to

F-19

capitalize an allowance for funds used during construction, which represents the estimated costs of funds used for construction purposes. The original cost of property retired is charged to accumulated depreciation and amortization, net of salvage and cost of removal. No retirement gain or loss is included in income except in the case of retirements or sales of entire regulated operating units.

Maintenance and repairs are charged to operations in the period incurred. The provision for depreciation and amortization of the transmission line is an integral part of Northern Border Pipeline’s FERC tariff. The effective depreciation rate applied to Northern Border Pipeline’s transmission plant is 2.25%. Composite rates are applied to all other functional groups of property having similar economic characteristics.

(G) Risk Management

Financial instruments are used by Northern Border Pipeline in the management of its interest rate exposure. A control environment has been established which includes policies and procedures for risk assessment and the approval, reporting and monitoring of financial instrument activities. Northern Border Pipeline does not use these instruments for trading purposes. SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended by SFAS No. 137 and SFAS No. 138, requires that every derivative instrument (including certain derivative instruments embedded in other contracts) be recorded on the balance sheet as either an asset or liability measured at its fair value. The statement requires that changes in the derivative’s fair value be recognized currently in earnings unless specific hedge accounting criteria are met. Special accounting for qualifying hedges allows a derivative’s gains and losses to offset related results on the hedged item in the income statement, and requires that a company formally document, designate and assess the effectiveness of transactions that receive hedge accounting. Northern Border Pipeline adopted SFAS No. 133 beginning January 1, 2001. See Note 6 for a discussion of Northern Border Pipeline’s derivative instruments and hedging activities.

3. RATES AND REGULATORY ISSUES

Northern Border Pipeline filed a rate proceeding with the FERC in May 1999 for, among other things, a redetermination of its allowed equity rate of return. In September 2000, Northern Border Pipeline filed a stipulation and agreement with the FERC that documented the proposed settlement of its 1999 rate case. The settlement was approved by the FERC in December 2000. Under the settlement, both Northern Border Pipeline and its existing shippers will not be able to seek rate changes until November 1, 2005, at which time Northern Border Pipeline must file a new rate case.

After the FERC approved the rate case settlement and prior to the end of 2000, Northern Border Pipeline made estimated refund payments to its shippers totaling approximately $22.7 million, primarily related to the period from December 1999 to November 2000. During the first quarter of 2001, Northern Border Pipeline paid the remaining refund obligation to its

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shippers totaling approximately $6.8 million, which related to periods through January 2001.

On March 16, 2000, the FERC issued an order granting Northern Border Pipeline’s application for a certificate to construct and operate an expansion and extension of its pipeline system into Indiana (Project 2000). The facilities for Project 2000 were placed into service on October 1, 2001.

In 2003, Northern Border Pipeline filed to amend its tariff for the definition of company use gas, which is gas supplied by its shippers for its operations, to clarify the language by adding detail to the broad categories that comprise company use gas. Relying upon the currently effective version of the tariff, Northern Border Pipeline included in its collection of company use gas quantities that were equivalent to the cost of electric power at its electric-driven compressor stations during the period of June 2001 through January 2003. The proposed language provides additional detail concerning the practice of recognizing electric costs at electric powered compressor stations in the determination of company use gas. Northern Border Pipeline requested that the tariff change be effective April 1, 2003. Several parties have filed protests of this change and have requested that the FERC order refunds. While Northern Border Pipeline cannot predict the outcome of this proceeding at this time, the accompanying financial statements reflect a reserve of $10 million.

4. TRANSPORTATION SERVICE AGREEMENTS

Operating revenues are collected pursuant to the FERC tariff through firm transportation service agreements. The firm service agreements extend for various terms with termination dates that range from March 2003 to December 2013. Northern Border Pipeline also has interruptible transportation service agreements and other transportation service agreements with numerous shippers.

Under the capacity release provisions of Northern Border Pipeline’s FERC tariff, shippers are allowed to release all or part of their capacity either permanently for the full term of the contract or temporarily. A temporary capacity release does not relieve the original contract shipper from its payment obligations if the replacement shipper fails to pay for the capacity temporarily released to it.

At December 31, 2002, Northern Border Pipeline’s largest shipper is Pan-Alberta Gas (U.S.) Inc. (Pan-Alberta) with approximately 20% of the contracted firm capacity, of which approximately 3% has been temporarily released to other shippers through October 31, 2003. Mirant Americas Energy Marketing, LP (Mirant), who manages the assets of Pan-Alberta Gas, Ltd., including the Pan-Alberta contracts with Northern Border Pipeline, also is obligated for approximately 10% of the contracted firm capacity. The Pan-Alberta firm service agreements expire in October 2003. The Mirant firm service agreements expire in October 2006 and December 2008. The obligations of Pan-Alberta and Mirant are supported by various credit support arrangements, including among others, letters of credit and escrow accounts and an upstream capacity transfer agreement. Operating revenues

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from Mirant and Pan-Alberta for the years ended December 31, 2002, 2001 and 2000 were $105.5 million, $80.7 million and $78.2 million, respectively.

At December 31, 2002, there is no contracted firm capacity held by shippers affiliated with Northern Border Pipeline. Previously, some of Northern Border Pipeline’s shippers have been affiliated with its general partners. Operating revenues from affiliates were $1.4 million, $52.1 million and $58.5 million for the years ended December 31, 2002, 2001, and 2000, respectively.

5. CREDIT FACILITIES AND LONG-TERM DEBT

Detailed information on long-term debt is as follows:

	December 31,
(Thousands of dollars)	2002			2001
1992 Pipeline Senior Notes — average 8.57% and 8.53% at December 31, 2002 and 2001, respectively, due from 2002 to 2003	$	65,000		$	143,000
Pipeline Credit Agreement -
Term loan — average 2.46% at December 31, 2001, due 2002	—			272,000
2002 Pipeline Credit Agreement — average 2.05% at December 31, 2002, due 2005	89,000			—
1999 Pipeline Senior Notes — 7.75%, due 2009	200,000			200,000
2001 Pipeline Senior Notes — 7.50%, due 2021	250,000			250,000
2002 Pipeline Senior Notes — 6.25%, due 2007	225,000			—
Fair value adjustment for interest rate swaps (Note 6)	21,204			—
Unamortized debt discount	(1,298		)	(1,334		)

Total	848,906			863,666
Less: Current maturities of long-term debt	65,000			350,000

Long-term debt	$	783,906		$	513,666

Northern Border Pipeline entered into a $175 million three-year credit agreement (2002 Pipeline Credit Agreement) with certain financial institutions in May 2002, which is to be used to refinance existing indebtedness and for general business purposes. The 2002 Pipeline Credit Agreement permits Northern Border Pipeline to choose among various interest rate options, to specify the portion of the borrowings to be covered by specific interest rate options and to specify the interest rate period. Northern Border Pipeline is required to pay a fee on the principal commitment amount of $175 million.

In April 2002, Northern Border Pipeline completed a private offering of $225 million of 6.25% Senior Notes due 2007 (2002 Pipeline Senior Notes) and in September 2001, Northern Border Pipeline completed a private offering of $250 million of 7.50% Senior Notes due 2021 (2001 Pipeline Senior Notes). The 2002 Pipeline Senior Notes and 2001 Pipeline Senior Notes were subsequently exchanged in registered offerings for notes with substantially identical terms. The proceeds from the senior notes were used to reduce indebtedness outstanding.

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Interest paid, net of amounts capitalized, during the years ended December 31, 2002, 2001 and 2000 was $55.3 million, $53.9 million and $68.0 million, respectively.

Aggregate required repayments of long-term debt are as follows: $65 million, $89 million and $225 million for 2003, 2005 and 2007, respectively. There are no required repayment obligations for either 2004 or 2006.

Certain of Northern Border Pipeline’s long-term debt and credit arrangements contain requirements as to the maintenance of minimum partners’ capital and debt to capitalization ratios, leverage ratios and interest coverage ratios that restrict the incurrence of other indebtedness by Northern Border Pipeline and also place certain restrictions on distributions to the partners of Northern Border Pipeline. Under the most restrictive of the covenants, as of December 31, 2002 and 2001, respectively, $99 million and $110 million of partners’ capital of Northern Border Pipeline could be distributed. The 2002 Pipeline Credit Agreement requires the maintenance of a ratio of EBITDA (net income plus interest expense, income taxes and depreciation and amortization) to interest expense of greater than 3 to 1. The 2002 Pipeline Credit Agreement also requires the maintenance of the ratio of indebtedness to EBITDA of no more than 4.5 to 1. At December 31, 2002, Northern Border Pipeline was in compliance with these covenants.

The following estimated fair values of financial instruments represent the amount at which each instrument could be exchanged in a current transaction between willing parties. Based on quoted market prices for similar issues with similar terms and remaining maturities, the estimated fair value of the 1992 Pipeline Senior Notes, 1999 Pipeline Senior Notes, 2001 Pipeline Senior Notes and 2002 Pipeline Senior Notes was approximately $827 million and $623 million at December 31, 2002 and 2001, respectively. Northern Border Pipeline presently intends to maintain the current schedule of maturities for the 1992 Pipeline Senior Notes, 1999 Pipeline Senior Notes, 2001 Pipeline Senior Notes and the 2002 Pipeline Senior Notes, which will result in no gains or losses on their respective repayment. The fair value of Northern Border Pipeline’s variable rate debt approximates the carrying value since the interest rates are periodically adjusted to reflect current market conditions.

6. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

As a result of the adoption of SFAS No. 133, Northern Border Pipeline reclassified approximately $11.1 million from long-term debt to accumulated other comprehensive income related to unamortized proceeds from the termination of interest rate swap agreements. Also upon adoption of SFAS No. 133, Northern Border Pipeline recorded a non-cash loss in accumulated other comprehensive income of approximately $0.8 million, related to its outstanding interest rate swap agreement with a notional amount of $40 million, which terminated in November 2001.

Prior to the anticipated issuance of fixed rate debt, Northern Border Pipeline has entered into forward starting interest rate swap agreements. The interest rate swaps have been designated as cash flow hedges as they were entered into to hedge the fluctuations in Treasury rates and spreads between the execution date of the swaps and the issuance of the fixed rate debt. The notional amount of the interest rate swaps does not exceed the expected principal amount of fixed rate debt to be issued. Upon issuance of the fixed rate debt, the swaps were terminated and the proceeds received or

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amounts paid to terminate the swaps were recorded in accumulated other comprehensive income and amortized to interest expense over the term of the hedged debt.

For the year ended December 31, 2002, Northern Border Pipeline received $2.4 million from terminated interest rate swaps. For the year ended December 31, 2001, Northern Border Pipeline paid approximately $4.1 million to terminate interest rate swaps.

During the years ended December 31, 2002 and 2001, respectively, Northern Border Pipeline amortized approximately $1.4 million and $1.2 million related to the terminated interest rate swap agreements as a reduction to interest expense from accumulated other comprehensive income. Northern Border Pipeline expects to amortize approximately $1.6 million in 2003.

Northern Border Pipeline entered into interest rate swap agreements with notional amounts totaling $225 million in May 2002. Under the interest rate swap agreements, Northern Border Pipeline makes payments to counterparties at variable rates based on the London Interbank Offered Rate and in return receives payments based on a 6.25% fixed rate. At December 31, 2002, the average effective interest rate on Northern Border Pipeline’s interest rate swap agreements was 2.70%. Northern Border Pipeline’s interest rate swap agreements have been designated as fair value hedges as they were entered into to hedge the fluctuations in the market value of the 2002 Pipeline Senior Notes. The accompanying balance sheet at December 31, 2002, reflects a non-cash gain of approximately $21.2 million in derivative financial instruments with a corresponding increase in long-term debt.

7. COMMITMENTS AND CONTINGENCIES

Operating Leases

Future minimum lease payments under non-cancelable operating leases on office space are as follows (in thousands):

Year ending December 31,
	2003	$	862
	2004	857
	2005	857
	2006	857
	2007	857
	Thereafter	1,713

		$	6,003

Capital expenditures

Total capital expenditures for 2003 are estimated to be $11 million. Funds required to meet the capital expenditures for 2003 are anticipated to be provided primarily from debt borrowings and operating cash flows.

Environmental Matters

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

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Other

On July 31, 2001, the Assiniboine and Sioux Tribes of the Fort Peck Indian Reservation (Tribes) filed a lawsuit in Tribal Court against Northern Border Pipeline to collect more than $3 million in back taxes, together with interest and penalties. The lawsuit relates to a utilities tax on certain of Northern Border Pipeline’s properties within the Fort Peck Indian Reservation. The Tribes and Northern Border Pipeline, through a mediation process, have held settlement discussions and have reached a settlement in principle on pipeline right-of-way lease and taxation issues, subject to final documentation and necessary government approvals. Northern Border Pipeline believes that the resolution of this lawsuit will not have a material adverse impact on Northern Border Pipeline’s results of operations or financial position.

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

8. QUARTERLY FINANCIAL DATA (Unaudited)

(In thousands)	Operating Revenues, net		Operating Income		Net Income to Partners
2002
First Quarter	$	78,155	$	49,895	$	37,670
Second Quarter	80,173		52,014		38,506
Third Quarter	81,553		51,843		39,197
Fourth Quarter	81,169		38,706		27,346
2001
First Quarter	$	77,040	$	50,318	$	35,889
Second Quarter	76,950		46,706		31,632
Third Quarter	77,932		48,083		35,537
Fourth Quarter	81,166		51,134		37,400

9. ACCOUNTING PRONOUNCEMENTS

In 2001, the Financial Accounting Standards Board (FASB) issued SFAS No. 143, “Accounting for Asset Retirement Obligations.” SFAS No. 143 requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred, if the liability can be reasonably estimated. When the liability is initially recorded, the carrying amount of the related asset is increased by the same amount. Over time, the liability is accreted to its future value and the accretion is recorded to expense. The initial adjustment to the asset is depreciated over its useful life. Upon settlement of the liability, an entity either settles the obligation for its recorded amount or incurs a gain or loss. SFAS No. 143 is effective for fiscal years beginning after June 15, 2002, with earlier application encouraged. In some instances, Northern Border Pipeline is obligated by contractual terms or regulatory requirements to remove facilities or perform other remediation upon retirement. Northern Border Pipeline expects that it will be unable to reasonably estimate and record liabilities for its obligations that fall under the provisions of this statement because it cannot reasonably estimate when such obligations would be settled. The effect of adopting SFAS No. 143 is not expected to be material to the financial statements.

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In April 2002, the FASB issued SFAS No. 145, “Rescission of FASB Statements No. 4, No. 44 and No. 64, Amendments to FASB Statements No. 13 and Technical Corrections.” SFAS No. 146, “Accounting for Costs Associated with Exit or Disposal Activities” was issued in June 2002. SFAS No. 145 streamlines the reporting of debt extinguishments and requires that only gains and losses from extinguishments meeting the criteria in Accounting Principles Board Opinion 30 would be classified as extraordinary. SFAS No. 146 requires that a liability for a cost associated with an exit or disposal activity be recognized when the liability is incurred. SFAS No. 145 is effective for fiscal years beginning after May 15, 2002. SFAS No. 146 is effective for exit or disposal activities that are initiated after December 31, 2002. Northern Border Pipeline does not expect the adoption of SFAS No. 145 and SFAS No. 146 to have a material impact on its financial position, results of operations or cash flows.

10. RELATIONSHIPS WITH ENRON

In December 2001, Enron and certain of its subsidiaries filed voluntary petitions for Chapter 11 reorganization with the U.S. Bankruptcy Court. Northern Plains was not included in the bankruptcy filing and management believes that Northern Plains will continue to be able to meet its operational and administrative service obligations under the existing operating agreement. Enron North America Corp. (ENA), a subsidiary of Enron, was included in the bankruptcy filing. At the time of the bankruptcy filing, ENA had firm service agreements representing approximately 3.5% of contracted capacity, a portion of which (1.1%) had been temporarily released to a third party until October 31, 2002. Northern Border Pipeline recorded a bad debt expense of approximately $1.3 million representing ENA’s unpaid November and December 2001 transportation, which is included in operations and maintenance expense on the statement of income. On June 13, 2002, the Bankruptcy Court approved a Stipulation and Order entered into on May 15, 2002, by ENA and Northern Border Pipeline pursuant to which ENA agreed that all but one of the shipper contracts, representing 1.7% of pipeline capacity, will be deemed rejected and terminated. The remaining contract was terminated in the third quarter of 2002. For the year ended December 31, 2002, Northern Border Pipeline has experienced lost revenues of approximately $1.8 million related to ENA’s capacity. Northern Border Pipeline has filed proofs of claims regarding the amount of damages for breach of contract and other claims in the bankruptcy proceeding. However, Northern Border Pipeline cannot predict the amounts, if any, that it will collect or the timing of collection. Northern Border Pipeline believes, however, that any amounts collected will not be material.

Northern Border Pipeline continues to monitor developments at Enron, to assess the impact on Northern Border Pipeline of its existing agreements and relationships with Enron, and to take appropriate action to protect Northern Border Pipeline’s interests.

11. SUBSEQUENT EVENTS

Northern Border Pipeline makes distributions to it general partners approximately one month following the end of the quarter. The distribution for the fourth quarter of 2002 of approximately $41.8 million was declared in January 2003 to be paid in February 2003.

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Independent Auditors’ Report on Schedule

Northern Border Pipeline Company:

We have audited in accordance with auditing standards generally accepted in the United States of America, the financial statements of Northern Border Pipeline Company as of December 31, 2002 and 2001 and for each of the years in the three-year period ended December 31, 2002 included in this Form 10-K, and have issued our report thereon dated January 23, 2003.

Our audits were made for the purpose of forming an opinion on the basic financial statements taken as a whole. The schedule of Northern Border Pipeline Company listed in Item 14 of Part IV of this Form 10-K is the responsibility of the Company’s management and is presented for purposes of complying with the Securities and Exchange Commission’s rules and is not part of the basic financial statements. This schedule has been subjected to the auditing procedures applied in the audits of the basic financial statements and, in our opinion, fairly states in all material respects, the financial data required to be set forth therein in relation to the basic financial statements taken as a whole.

KPMG LLP

January 23, 2003
Omaha, Nebraska

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SCHEDULE II

NORTHERN BORDER PIPELINE COMPANY

SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS

FOR THE YEARS ENDED DECEMBER 31, 2002, 2001 AND 2000

(In Thousands)

Column A	Column B		Column C				Column D		Column E
			Additions				Deductions
	Balance at		Charged to		Charged		For Purpose For
	Beginning		Costs and		to Other		Which Reserves		Balance at
Description	of Year		Expenses		Accounts		Were Created		End of Year
Reserve for regulatory issues
2002	$	2,531	$	9,763	$	—	$	—	$	12,294
2001	$	1,800	$	731	$	—	$	—	$	2,531
2000	$	7,376	$	1,800	$	—	$	7,376	$	1,800

Allowance for doubtful accounts
2002	$	3,176	$	3,452	$	—	$	1,823	$	4,805
2001	$	—	$	3,176	$	—	$	—	$	3,176
2000	$	—	$	—	$	—	$	—	$	—

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NONE

(1) A total of 17,500,000 common and subordinated units are issued and outstanding.

Financial Statements of TC PipeLines, LP

Financial Statements of Northern Border Pipeline Company

Financial Statements Schedule of Northern Border Pipeline Company

Note 1 Organization

Note 2 Significant Accounting Policies

Note 3 Investment in Northern Border Pipeline Company

Note 4 Investment in Tuscarora Gas Transmission Company

Note 5 Credit Facilities and Long-Term Debt

Note 6 Partners’ Capital and Cash Distributions

Note 7 Net Income per Unit

Note 8 Related Party Transactions

Note 9 Quarterly Financial Data (unaudited)

Note 10 Accounting Pronouncements

Note 11 Subsequent Events