TC Pipelines, LP

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generating stable cash flows 
and growing distributions 
in a sustainable, disciplined manner

 
 
 
 
BOARD OF DIRECTORS OF THE GENERAL PARTNER 
OF TC PIPELINES, LP

Russell K. Girling
Chairman and Chief Executive Officer, TC PipeLines GP, Inc.
President, Pipelines
TransCanada Corporation
Calgary, Alberta

Steven D. Becker
Vice-President, Pipeline Development, Pipelines Division
TransCanada Corporation
Calgary, Alberta

Kristine L. Delkus
Deputy General Counsel, Pipelines and Regulatory Affairs, 
Pipelines Division
TransCanada Corporation
Calgary, Alberta

Jack F. Jenkins-Stark (1) (2) (3)
Chief Financial Officer
BrightSource Energy, Inc.
Oakland, California

Gregory A. Lohnes
Executive Vice-President and Chief Financial Officer 
TransCanada Corporation
Calgary, Alberta

David L. Marshall (4) (5)
Retired Vice-Chairman and Chief Financial Officer
The Brinks Company
Sparks, Nevada

Walentin (Val) Mirosh (3) (5)
Vice-President, NOVA Chemicals Corporation
President, Olefins and Feedstock
Calgary, Alberta

(1) Lead Director
(2) Chair, Conflicts Committee
(3) Member, Audit Committee
(4) Chair, Audit Committee
(5) Member, Conflicts Committee

TC PipeLines, LP

13710 FNB Parkway 
Omaha, Nebraska, U.S.  68154
Telephone (877) 290-2772
Facsimile (403) 920-2457

450 First Street SW
Calgary, Alberta, Canada  T2P 5H1
Telephone (877) 290-2772
Facsimile (403) 920-2457

Investor Relations

Myles Dougan 
Manager, Investor Relations 

Telephone (877) 290-2772
Facsimile (403) 920-2457
E-mail: investor_relations@tcpipelineslp.com

Website

www.tcpipelineslp.com

K-1 Information 

Telephone (877) 699-1091

Stock Exchange Listing

NASDAQ Global Market: TCLP

EXECUTIVE OFFICERS OF THE GENERAL PARTNER 
OF TC PIPELINES, LP

Auditors 

KPMG LLP, Calgary, Alberta

Transfer Agent

Mellon Investor Services LLC
Ridgefield Park, New Jersey
Telephone (800) 756-3353

Russell K. Girling
Chairman and Chief Executive Officer

Mark Zimmerman
President

Sean Brett 
Vice-President and Treasurer

Terry Ofremchuk
Vice-President, Taxation

Amy Leong 
Controller

Donald J. DeGrandis
Secretary

Please recycle              Printed in Canada March 2008

3

2

1

1. Great Lakes

46.45 per cent ownership; 2,115 miles – connects from the TransCanada Mainline at 
Emerson, Manitoba and delivers to St. Clair, Michigan. 

Receipt capacity: 2.6 billion cubic feet per day

2. Northern Border

50 per cent ownership; 1,249 miles – connects from the Montana-Saskatchewan border 
near Port of Morgan, Montana to Chicago, Illinois and other natural gas markets in the 
midwestern U.S. 

Receipt capacity: 2.4 billion cubic feet per day

3. Tuscarora

100 per cent ownership; 240 miles – originating at an interconnection with the TransCanada-
owned Gas Transmission Northwest system near Malin, Oregon and runs southeast through 
northeastern California and northwestern Nevada, terminating near Wadsworth, Nevada. 

Receipt capacity: 190 million cubic feet per day

Cautionary Statement Regarding Forward-Looking Information  

This annual report includes forward-looking statements regarding future events and our future financial performance. All 

forward-looking statements are based on our beliefs as well as assumptions made by, and information currently available, 

to us. Words such as “believes,” “expects,” “intends,” “forecasts,” “projects,” and similar expressions, identify forward-

looking statements. These statements reflect our current views with respect to future events and are subject to various risks, 

uncertainties and assumptions, which we discuss in detail in our Form 10-K for the year ended December 31, 2007 and 

other filings made with the SEC. If one or more of these risks or uncertainties materialize, or if the underlying assumptions 

prove incorrect, actual results may vary materially from those described in the forward-looking statement. Except as required 

by applicable law. We undertake no obligation to update these forward looking statements to reflect new information, 

subsequent events or otherwise.

l

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92%

Total Assets

99%

Net Income

93%

Partnership
Cash Flows

2007 was a year of growth and diversification for the Partnership. The Partnership’s 

total asset base nearly doubled and net income and Partnership cash flows grew 

significantly as well. In addition, we remained focussed on growing cash distributions to our unitholders 

in a disciplined manner with a firm view on long term sustainability. Our fourth quarter 2007 cash 
distribution was the fifth increase of the quarterly cash distribution in the last six quarters from $2.30 to 

$2.66 per common unit on an annualized basis or a 15.7 per cent increase in the cash distribution over 
that time.

Diversification of our asset base strengthened the Partnership. Great Lakes adds a new source of stable 

income and cash flow for us and its connection with TransCanada’s ANR pipeline system gives us access 

to new supply sources as well. The addition of Great Lakes also expands our customer mix, further 

broadening our revenue sources. As well, by acquiring the remaining 51 per cent of Tuscarora we have 

added to our stable cash flow stream that Tuscarora provides under committed, long term firm contracts.

A number of key events contributed to the Partnership’s success in 2007. First and foremost, we closed 

the $942.4 million acquisition of a 46.45 per cent interest in Great Lakes Gas Transmission on February 

22, adding significant cash flow to the Partnership’s financial results. Great Lakes strong contract 

structure and steady results through the year were the primary reason for a $64.8 million or $0.18 per 

common unit increase in Partnership cash flows when compared to 2006. Great Lakes offers shippers a 

cost effective route to deliver Western Canadian gas and U.S. gas to Eastern Canadian and U.S. markets. 

We anticipate Great Lakes will continue to be an excellent investment for the Partnership.

2007 was the first year under the new FERC approved rates at Northern Border. The rate settlement 

included, among other things, seasonal rates for short term transportation services. We were pleased 

with the operating revenue, net income, and cash flow at Northern Border under this new rate structure. 

The pipeline will continue to face competition as new alternate sources of supply, such as the Rockies, 
compete with supply from the Western Canada Sedimentary Basin in markets that Northern Border 

serves. Demand for Northern Border’s transportation has traditionally been strongest during peak winter 

and summer months. The new seasonal rate structure for short term contracts was well received by 

shippers and was a factor in Northern Border’s strong results.

On April 1, 2007 TransCanada became the operator of Northern Border. This transition was completed 

in connection with our acquisition of an additional 20 per cent interest in Northern Border in April, 

2006. TransCanada now operates all three of the Partnership’s pipeline investments and acts as our 

general partner. As a major North American energy infrastructure company with approximately 

36,500 miles of natural gas pipelines, 365 billion cubic feet of regulated and non-regulated natural gas 

storage facilities and approximately 7,700 megawatts of power generation we continue to benefit from 

TransCanada’s management talent, strong relationships throughout the energy industry and over 50 

years of natural gas pipeline operational experience.

 
48% Growth in Annual 
Cash Distributions Per 
Common Unit Since 
Inception.

*Prorated for full year

**Estimate based on $0.665 first 
quarter, 2008 distribution announced 
January 17, 2008

$1.80

1999*

$2.66

2008**

On December 31, 2007, we purchased an additional two per cent ownership interest in Tuscarora Gas 

Transmission Company, increasing our ownership interest to 100 per cent. This transaction simplifies 
our ownership structure at Tuscarora and marginally increases our ownership of a pipeline with a long 

term contract structure delivering gas to a growing market. 

Looking forward, we expect the Tuscarora expansion project will be in service in March 2008. This 

project is underpinned by a 22.5 year contract to transport 39 million cubic feet per day of natural gas to 

supply Sierra Pacific Power’s Tracy combined cycle power plant. 

In February, 2008, Northern Border filed with the FERC to construct, own and operate interconnect 

facilities, including a 1,600 horsepower compressor facility near Joliet, Illinois. This project is 

estimated to be in service in early 2009 and will be fully subscribed under long term compression and 

transportation contracts. We continue to look for opportunities to expand our pipeline systems to meet 

market demand and further strengthen the Partnership’s financial position.

We also continue to evaluate opportunities to grow through acquisitions. We are focused on investing 

in high quality North American energy infrastructure assets that are underpinned by strong business 

fundamentals and provide stable cash flows. TransCanada continues to view TC PipeLines as an 

important vehicle for realizing its gas transmission growth strategy and is committed to providing the 

expertise that will help the Partnership succeed.

The groundwork has been laid in positioning the Partnership for the future. Our employees deserve 

credit for their energy and dedication in seeking out accretive acquisitions and organic growth 

opportunities, and maximizing our existing portfolio of pipeline systems. I am confident the growth and 

diversification we achieved in 2007 has strengthened the Partnership as we continue with our goal of 

delivering stable cash distributions and growing in a sustained and disciplined manner for the long term 
benefit of our unitholders. 

On behalf of TC PipeLines, LP

Russ Girling

Chairman and Chief Executive Officer
TC PipeLines GP, Inc.

4

TC PIPELINES, LP

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K

(cid:2)

(cid:3)

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

For the fiscal year ended December 31, 2007

or

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

For the Transition period from 

 to 

Commission File Number: 000-26091
TC PipeLines, LP
(Exact name of registrant as specified in its charter)

Delaware
(State or other jurisdiction
of incorporation or organization)

13710 FNB Parkway
Omaha, Nebraska
(Address of principal executive offices)

52-2135448
(I.R.S. Employer
Identification Number)

68154-5200
(Zip code)

877-290-2772
(Registrant’s telephone number, including area code)

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

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

Common units representing limited partner interests

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
Yes (cid:2) No (cid:3)

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.
Yes (cid:3) No (cid:2)

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 (cid:2) No (cid:3)

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. (cid:2)

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a
smaller reporting company. See the definitions of ‘‘large accelerate filer’’, ‘‘accelerated filer’’ and ‘‘small reporting company’’ in
Rule 12b-2 of the Exchange Act.
Large accelerated filer (cid:2)

Smaller reporting company (cid:3)

Accelerated filer (cid:3)

Non-accelerated filer (cid:3)
(Do not check if a smaller
reporting company)

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes (cid:3) No (cid:2)

Aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant as at June 29,
2007 was approximately $953.5 million. Yes (cid:3) No (cid:2)

As of February 28, 2008, there were 34,856,086 of the registrant’s common units outstanding.

2007 ANNUAL REPORT

5

TC PIPELINES, LP

TABLE OF CONTENTS

Page No.

Business

PART I
Item 1.
Item 1A. Risk Factors
Item 1B. Unresolved Staff Comments
Item 2.
Item 3.
Item 4.

Properties
Legal Proceedings
Submission of Matters to a Vote of Security Holders

PART II
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of

Equity Securities
Selected Financial Data

Item 6.
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Financial Statements and Supplementary Data
Item 8.
Item 9.
Changes in and Disagreements With Accountants on Accounting and Financial Disclosure
Item 9A. Controls and Procedures
Item 9B. Other Information

PART III
Item 10. Directors, Executive Officers and Corporate Governance
Item 11.
Item 12.

Executive Compensation
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder

Matters

Item 13. Certain Relationships and Related Transactions, and Director Independence
Item 14.

Principal Accounting Fees and Services

PART IV
Item 15.

Exhibits, Financial Statement Schedules

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

7
22
34
34
35
35

36
37
37
59
60
60
60
61

62
64

66
68
70

71

6

TC PIPELINES, LP

PART I

FORWARD-LOOKING STATEMENTS

The statements in this report that are not historical information, including statements concerning plans and objectives of
management for future operations, economic performance or related assumptions, are forward-looking statements
within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Exchange Act. Forward-looking
statements may include words such as ‘‘anticipate,’’ ‘‘estimate,’’ ‘‘expect,’’ ‘‘project,’’ ‘‘intend,’’ ‘‘plan,’’ ‘‘believe,’’
‘‘forecast’’ and other words and terms of similar meaning. The absence of these words, however, does not mean that
the statements are not forward-looking.

These statements reflect our current views with respect to future events, based on what we believe are reasonable
assumptions. Certain factors that could cause actual results to differ materially from those contemplated in the forward-
looking statements include:

• the ability of Great Lakes and Northern Border to continue to make distributions at their current levels;

• the impact of unsold capacity on Great Lakes and Northern Border being greater or less than expected;

• competitive conditions in our industry and the ability of our pipeline systems to market pipeline capacity on favorable

terms, which is affected by:

• future demand for and prices of natural gas;

• competitive conditions in the overall natural gas and electricity markets;

• availability of supplies of Canadian and U.S. natural gas;

• availability of additional storage capacity;

• weather conditions; and

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

• the Alberta (Canada) government’s decision to implement a new royalty regime effective January 2009 may affect the

amount of exploration and drilling in the Western Canada Sedimentary Basin;

• performance of contractual obligations by customers of our pipeline systems;

• operating hazards, natural disasters, weather-related delays, casualty losses and other matters beyond our control;

• the impact of current and future laws, rulings and governmental regulations, particularly FERC regulations, on us and

our pipeline systems;

• our ability to control operating costs; and

• prevailing economic conditions, including conditions of the capital and equity markets and our ability to access these

markets.

Other factors described elsewhere in this document, or factors that are unknown or unpredictable, could also have
material adverse effects on future results. Please also read Item 1A. ‘‘Risk Factors.’’ All forward-looking statements
attributable to us or persons acting on our behalf are expressly qualified in their entirety by these factors. These
forward-looking statements and information is made only as of the date of the filing of this report, and except as
required by applicable law, we undertake no obligation to update these forward-looking statements and information to
reflect new information, subsequent events or otherwise.

2007 ANNUAL REPORT

7

Item 1. Business

OVERVIEW

We are a publicly traded Delaware limited partnership formed in 1998 by TransCanada PipeLines Limited, a wholly-
owned subsidiary of TransCanada Corporation (collectively referred to as TransCanada), to acquire, own and participate
in the management of United States (U.S.) based pipeline systems. We have broadened our initial scope to energy
infrastructure assets in North America. To date, our primary focus has been in the transportation of natural gas from
the Western Canada Sedimentary Basin (WCSB) to a variety of downstream markets.

TC PipeLines, LP and its subsidiary limited partnerships and subsidiary limited liability company, including, TC PipeLines
Intermediate Limited Partnership (TC PipeLines ILP), TC Tuscarora Intermediate Limited Partnership (TC Tuscarora ILP), TC
GL Intermediate Limited Partnership (TC GL ILP) and TC Pipelines Tuscarora LLC (TC Tuscarora LLC), are collectively
referred to herein as ‘‘TC PipeLines’’ or ‘‘the Partnership.’’ In this report, references to ‘‘we’’, ‘‘us’’ or ‘‘our’’ collectively
refer to TC PipeLines or the Partnership. The general partner of the Partnership is TC PipeLines GP, Inc. (TC
PipeLines GP), a wholly-owned subsidiary of TransCanada.

Our strategic focus is on delivering stable, sustainable cash distributions to our unitholders and finding opportunities to
increase cash distributions while maintaining a low risk profile. Our current portfolio of pipeline investments in the U.S.
consists of:

• A 100 per cent general partner interest in Tuscarora Gas Transmission Company (Tuscarora).

• A 46.45 per cent general partner interest in Great Lakes Gas Transmission Limited Partnership (Great Lakes). The

remaining 53.55 per cent interest in Great Lakes is held by TransCanada.

• A 50 per cent general partner interest in Northern Border Pipeline Company (Northern Border). The other 50 per cent
interest is held by ONEOK Partners, L.P. (ONEOK Partners), a publicly traded limited partnership that is controlled by
ONEOK, Inc.

We account for our interests in both Great Lakes and Northern Border as equity investments; therefore, we do not
consolidate their financial results. TransCanada operates Great Lakes, Northern Border and Tuscarora (collectively, ‘‘our
pipeline systems’’). See Item 13. ‘‘Certain Relationships and Related Transactions, and Director Independence’’.

Recent Developments

Tuscarora 100 per cent Ownership – On December 31, 2007, we purchased the remaining two per cent interest in
Tuscarora, increasing our ownership interest to 100 per cent. One per cent was purchased from a wholly-owned
subsidiary of TransCanada, while the other one per cent was purchased from Tuscarora Gas Pipeline Co., a wholly-
owned subsidiary of Sierra Pacific Resources, for a combined purchase price of $3.9 million.

Northern Border Operatorship – On April 1, 2007, TransCanada Northern Border Inc. (TCNB), a wholly-owned subsidiary
of TransCanada, became the operator of Northern Border, pursuant to an operating agreement entered into with
Northern Border in April 2006.

Great Lakes Acquisition – On February 22, 2007, the Partnership acquired a 46.45 per cent general partner interest in
Great Lakes from El Paso Corporation. The total purchase price was $942.4 million, subject to certain closing
adjustments, and included the indirect assumption of approximately $209.0 million of debt. The acquisition was partially
financed through a private placement of 17,356,086 common units at $34.57 per common unit for gross proceeds of
$600.0 million which closed concurrently with the acquisition. TransCan Northern Ltd. (TransCan Northern), a wholly-
owned subsidiary of TransCanada, purchased 8,678,045 of the 17,356,086 common units issued for gross proceeds of
$300.0 million. In addition, TC PipeLines GP maintained its two per cent general partner interest in the Partnership by
contributing $12.6 million to the Partnership in connection with the private placement.

8

TC PIPELINES, LP

The Partnership funded the balance of the total consideration with a draw on its senior credit facility, which was
amended and restated in connection with this transaction. TransCanada, which previously held a 50 per cent interest in
Great Lakes, acquired the remaining 3.55 per cent interest simultaneously with the Partnership’s acquisition of its
interest. A wholly-owned subsidiary of TransCanada also became the operator of Great Lakes.

Other Developments

Tuscarora Increased Ownership – On December 19, 2006, the Partnership acquired an additional 49 per cent general
partnership interest in Tuscarora for approximately $99.8 million. In connection with this transaction, TCNB became the
operator of Tuscarora.

Implementation of New Rates, Northern Border – In November 2006, the Federal Energy Regulatory Commission (FERC)
approved the uncontested settlement of Northern Border’s rate case. Beginning January 1, 2007, Northern Border’s
overall rates were reduced compared with rates prior to the filing, by approximately 5 per cent. The settlement also
provided for seasonal rates for short-term transportation service.

Tuscarora Cost and Revenue Study – The Public Utilities Commission of Nevada (PUCN) approved Tuscarora’s rate
adjustment, which was subsequently approved by the FERC on July 3, 2006. The settlement resulted in a firm
transportation rate of $0.40/decatherm per day (dth-day) beginning June 1, 2006, or a 17 per cent reduction to the
previous rates of $0.481/dth-day.

Northern Border Increased Ownership – In April 2006, TC PipeLines purchased a 20 per cent partnership interest in
Northern Border from ONEOK Partners. After the transaction, TC PipeLines and ONEOK Partners each own a 50 per
cent interest in Northern Border.

Business Strategies

Our strategic focus is on delivering stable, sustainable cash distributions to our unitholders and finding opportunities to
increase cash distributions while maintaining a low risk profile.

Our business strategies to achieve these objectives are to seek opportunities to undertake accretive acquisitions and
organic growth projects, and maximize the value of our existing portfolio of pipeline systems. Working with our
partners, if any, in our pipeline systems, we seek to pursue policies that:

• Maximize the utilization of our pipeline systems;

• Expand our pipeline systems to meet market demand; and

• Continue to promote safe and efficient operations.

In addition, we intend to support the execution of our business strategies by:

• Maintaining a strong and balanced financial position to:

• maintain a prudent level of available cash for distribution to unitholders;

• fund future growth; and

• broaden our asset base in a disciplined and focused manner;

• Investing in North American energy infrastructure assets that are underpinned by strong business fundamentals and

provide stable cash flows; and

• Maximizing the benefits of our relationship with TransCanada.

2007 ANNUAL REPORT

9

Competitive Strengths

We believe that we are well positioned to execute our business strategies successfully because of the following
competitive strengths:

• Our pipeline systems hold strategic market positions and comprise critical transportation links for the transportation of
natural gas from the Alberta Hub to U.S. markets. The Alberta Hub is one of the largest natural gas hubs in North
America. Additional Canadian natural gas supply sources may be available in the future if new pipeline projects
associated with the Mackenzie Delta in Northern Canada and Alaska are constructed;

• With TransCanada as operator of our pipeline systems, we believe they are well positioned to continue to operate as

trusted and experienced transportation providers to our customers; and

• The senior management team and the board of directors of our general partner have extensive industry experience
and include some of the most senior officers of TransCanada. The management team plays a significant role in
developing the strategic direction of our pipeline systems and their associated operations, and we believe our ability
to execute our business strategies is enhanced by our affiliation with TransCanada.

Our Relationship with TransCanada Corporation

One of our principal strengths is our relationship with TransCanada. TransCanada is a major North American energy
infrastructure company with approximately 36,500 miles of wholly-owned natural gas pipelines, interests in an
additional 4,800 miles of natural gas pipelines, approximately 360 billion cubic feet (Bcf) of storage capacity and,
including facilities that are under construction or in development, also owns, operates, and/or controls approximately
7,700 megawatts of power generation. TransCanada, a Canadian corporation, was founded in 1951 with the objective
of transporting natural gas from Alberta to distant markets. Today, TransCanada is engaged in numerous aspects of the
energy industry but is primarily focused on natural gas transmission and power generation services.

TransCanada provides access to a significant pool of management talent and strong relationships throughout the energy
industry. We expect to pursue strategic acquisitions in a disciplined manner and to have the opportunity to participate
jointly with TransCanada in reviewing potential acquisitions, including transactions that we would be unable to pursue
on our own. Additionally, we may have the opportunity to make acquisitions directly from TransCanada in the future.
TransCanada, however, is under no obligation to allow us to participate in any of its pipeline or energy infrastructure
acquisitions, nor is TransCanada required to offer any of its assets to us.

As of December 31, 2007, we had 34,856,086 common units outstanding, of which 24,142,935 were held by the
public and 10,713,151 were held by wholly-owned subsidiaries of TransCanada. In addition, TransCanada owns the
Partnership’s general partner which holds a two per cent general partner interest in the Partnership. As such,
TransCanada receives distributions as a common unitholder, distributions related to its two per cent general partner
interest, as well as general partner incentive distributions if quarterly cash distributions on the common units exceed
levels specified in the partnership agreement. See Item 5. ‘‘Market for Registrant’s Common Equity, Related Stockholder
Matters and Issuer Purchases of Equity Securities’’.

10

TC PIPELINES, LP

Our Pipeline Systems

3

2

1

1

2

3

Great Lakes

Northern Border

Tuscarora

3MAR200816193112

All of our pipeline systems are rate regulated by the FERC. Operating revenue is derived from the transportation of
natural gas. The maximum transportation rates that our pipeline systems may charge are approved by the FERC, and in
most cases, established in a FERC proceeding known as a rate case. During a rate case, a determination is reached by
the FERC, either through a hearing or a settlement, on the maximum rates permissible for transportation service that
include the recovery of cost-based investment, operating expenses and a reasonable return for its investors. Once
maximum rates are set, the pipeline system is not permitted to adjust the maximum rates to reflect changes in costs or
contract demand until new rates are approved by the FERC, usually after a rate case has been filed. Each pipeline
system’s tariff is approved by the FERC and specifies the maximum rates, as well as the general terms and conditions for
natural gas transportation service on its pipeline. The tariff also allows for services to be provided under negotiated and
discounted rates. As a result, earnings and cash flow of each pipeline system depend on costs incurred; contracted
capacity and transportation path; the volume of gas transported; and the ability of each system to sell capacity at
acceptable rates.

Our pipeline systems’ transportation contracts include specifications regarding the receipt and delivery of natural gas at
points along the pipeline system. The type of transportation contract, either for firm or interruptible service, determines
the basis upon which each customer is charged. Customers with firm service transportation agreements pay a fee
known as a reservation charge to reserve pipeline capacity, regardless of use, for the term of their contracts. On the
Great Lakes and Northern Border systems, firm service transportation customers also pay a variable usage fee known as
a commodity charge or utilization fee that is based on distance and the volume of natural gas they transport.

2007 ANNUAL REPORT

11

Transportation customers on the Northern Border system also pay a compressor usage surcharge, effective with the
settlement of the 2005 rate case, resulting in new rates which were implemented January 1, 2007. Customers with
interruptible service transportation agreements may utilize available capacity on a pipeline system after firm service
transportation requests are satisfied. Interruptible service customers are assessed commodity charges (or utilization fees)
based on distance and the volume of natural gas they transport. The table below provides information with respect to
tariff revenue composition for each of our investments for the year ended December 31, 2007. The weighted average
remaining contract life is determined as at January 31, 2008.

Tariff Revenue Composition

Firm Contracts

Our
Ownership
Interest

46.45%
50%
100%

Capacity
Reservation
Charges

97%
91%
100%

Variable
Usage Fees(1)

3%
7%
n/a

Great Lakes
Northern Border
Tuscarora

Interruptible
Contracts &
Other
Services

0%
2%
0%

Weighted
Average
Remaining
Contract
Life (in years)(2)

2.4
1.3
10.4

(1) Variable usage fees for Northern Border include a compressor usage surcharge which relate to both, firm and interruptible contracts.

Tuscarora does not have any variable usage fees as part of their tariff.

(2) Weighted average remaining contract life is weighted based upon maximum daily quantity (MDQ) in the contracts.

The table below provides information on the average throughput of our pipeline systems:

Average Throughput (MMcf/d)

Great Lakes(1)
Northern Border
Tuscarora

2007

2,270
2,247
77

2006

2,236
2,246
77

2005

2,360
2,277
69

(1) The average throughput for Great Lakes includes periods prior to the February 22, 2007 acquisition by us of a 46.45 per cent general

partner interest in Great Lakes.

BUSINESS OF GREAT LAKES

Great Lakes is a Delaware limited partnership formed in 1990 and holds the assets formerly held by Great Lakes
Transmission Company. The FERC certificate to construct its initial facilities was issued in 1967. Great Lakes is owned
46.45 per cent by us, with the remainder owned by TransCanada. Additionally, Great Lakes is operated by TransCanada.

The major policies of Great Lakes are established by the management committee of Great Lakes (GL Management
Committee), which consists of up to six members, three of whom are designated by us and three of whom are
designated by TransCanada. The GL Management Committee consists of four appointed members, two of whom are
designated by us and two of whom are designated by TransCanada. All decisions by the GL Management Committee
require unanimous consent. For the day to day management of Great Lakes’ business, the GL Management Committee
established an executive committee, which consists of up to three members: one Partnership GL Management
Committee Member, one TransCanada GL Management Committee Member and the president of Great Lakes, who is a
non-voting member (GL Executive Committee). The GL Executive Committee currently consists of two appointed
members: one Partnership GL Management Committee member, and one TransCanada GL Management Committee
member, who also serves as the president of Great Lakes. The GL Executive Committee has all of the powers of the GL
Management Committee in the management of Great Lakes’ business.

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TC PIPELINES, LP

Great Lakes was originally constructed as an operational loop of the TransCanada Mainline Northern Ontario system.
Great Lakes receives natural gas from TransCanada at the Canadian border near Emerson, Manitoba. Great Lakes’
pipeline system extends across Minnesota, Northern Wisconsin and Michigan, and redelivers gas to TransCanada at the
Canadian border at Sault Ste. Marie, Michigan and St. Clair, Michigan.

The Great Lakes mainline transmission pipeline has diameters ranging from 10 inches to 36 inches. The Great Lakes
system consists of approximately 2,115 miles of pipeline with a design capacity of 2.3 Bcf per day at the Emerson Inlet.
Great

Lakes has 14 compressor stations with a total of 438,000 horsepower and measurement facilities to support the 55
receipt and delivery points for gas.

The original construction of Great Lakes’ system occurred in 1967 and 1968. There have been numerous capacity
system expansions since its original construction, the last one completed in 1998.

BUSINESS OF NORTHERN BORDER

Northern Border is a Texas general partnership formed in 1978. TC PipeLines, through its subsidiary TC PipeLines ILP,
and ONEOK Partners, through its subsidiary ONEOK Partners Intermediate Limited Partnership, each own a 50 per cent
interest in Northern Border.

Northern Border is managed by a management committee that consists of four members. Each partner designates two
members, and we designate one of our members as Chairman. Each partner holds a 50 per cent voting interest on the
management committee.

Northern Border extends from the Canadian border near Port of Morgan, Montana to a terminus near North Hayden,
Indiana. Northern Border’s transportation system provides pipeline access to the Midwestern U.S. from natural gas
reserves in the WCSB. Additionally, Northern Border transports natural gas produced in the Williston Basin of Montana
and North Dakota and the Powder River Basin of Wyoming and Montana and synthetic gas produced at the Dakota
Gasification plant in North Dakota.

The pipeline system consists of 1,249 miles of pipeline with diameters ranging from 30 to 42 inches and a design
capacity on the largest segment of the pipeline of 2,374 MMcf/d. Along the pipeline are 17 compressor stations with a
total of 515,000 horsepower, measurement facilities to support the receipt and delivery of gas at ten receipt and 50
delivery points, four field offices and a microwave communication system with 50 tower sites.

Construction of Northern Border’s system was initially completed in 1982, followed by expansions or extensions in
1991, 1992, 1998, 2001 and 2006.

Des Plaines Project – In February 2008, Northern Border filed with the FERC to construct, own and operate interconnect
facilities, including a 1,600 horsepower compressor facility near Joliet, Illinois. It is estimated that this project will cost
approximately $17 million. The targeted in-service date included in Northern Border’s FERC certificate application is
November 1, 2008; however, this schedule is dependent upon the receipt of timely regulatory approvals. The Des
Plaines Project will be fully subscribed under long-term compression and transportation contracts, per the executed
precedent agreement.

BUSINESS OF TUSCARORA

Tuscarora is a Nevada general partnership formed in 1993. We own 100 per cent of Tuscarora through two subsidiaries:
TC Tuscarora ILP owns a 99 per cent general partner interest in Tuscarora, with TC Pipelines Tuscarora LLC owning the
remaining one per cent general partner interest.

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The Tuscarora system originates at an interconnection point with existing facilities of Gas Transmission Northwest
Corporation (GTN), a wholly-owned subsidiary of TransCanada, near Malin, Oregon and runs Southeast through
Northeastern California and Northwestern Nevada. The Tuscarora pipeline system terminates near Wadsworth, Nevada.
Along its route, deliveries are made in Oregon, Northern California and Northwestern Nevada.

Tuscarora owns a 240-mile, 20-inch diameter, pipeline system with a design capacity of approximately 190 MMcf/d.
Tuscarora has two compressor stations with a total of 11,400 horsepower, and measurement facilities at one receipt
point and 16 delivery points.

The Tuscarora pipeline system was initially placed into service in 1995. Expansions or extensions were completed in
2001, 2002 and 2005.

2008 Expansion Project – In July 2007, Tuscarora received FERC approval for the construction of a compressor station
and related facilities (Tuscarora 2008 Expansion Project). This approximately $20 million project is underpinned by a
22.5 year long-term contract to transport a maximum of 39 MMcf/d to Sierra Pacific Power Company (Sierra Pacific
Power), a subsidiary of Sierra Pacific Resources, to supply its Tracy Combined Cycle Power Plant. The project is expected
to be in service in March 2008.

NATURAL GAS INDUSTRY OVERVIEW

North American Demand

Over the last fifteen years, natural gas demand in North America has increased by approximately 15 Bcf/d. Demand for
natural gas is expected to continue to grow across North America in 2008 and beyond. Demand for natural gas
transportation service on a pipeline system is directly related to demand for natural gas in the markets served by that
system. Factors that may impact demand for natural gas include:

• weather conditions;

• economic conditions;

• government regulation;

• the availability and price of alternative energy sources versus natural gas;

• natural gas storage inventories for the markets served;

• fuel conservation measures; and

• technological advances in fuel economy and energy generation devices.

Furthermore, factors that may impact demand for natural gas transportation service on any one system include:

• availability of natural gas supply at the pipeline system’s receipt points;

• the ability and willingness of natural gas shippers to utilize the pipeline system over alternative pipelines;

• relative transportation rates; and

• the volume of natural gas delivered to markets from other supply sources and storage facilities.

The primary exposure to business risk for our pipeline systems occurs when our pipeline systems are marketing their
available capacity, such as when existing transportation contracts expire and are subject to renegotiation. Customers
with competitive alternatives analyze the market price spread or basis differential between receipt and delivery points
along the pipeline to determine their expected gross margin. The anticipated margin and its variability are important
determinants of the transportation rate customers are willing to pay. The customers on our pipelines include local
distribution companies (LDCs), industrial companies, electric generation companies, natural gas producers, other natural
gas pipelines and natural gas marketing and trading companies.

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Our Pipeline Systems
Demand for transportation on Great Lakes has remained relatively constant over the last five years from LDCs and
industrial customers, as well as for transportation of volumes back into Canada. Great Lakes’ customer profile is
becoming more heavily weighted towards natural gas marketing and trading companies and less towards producers and
end users, such as industrial customers and LDCs.

Northern Border’s contract life has been declining with a customer profile over the past five years mainly comprised of
producers and natural gas marketing and trading companies. Northern Border delivers gas to highly competitive markets
including interconnections with other major interstate natural gas pipelines and major market centers that serve winter
heating and summer cooling demand, industrial load and storage areas to replenish inventory.

Demand on Tuscarora has steadily increased over the last several years due to increased demand from electric
generation companies and LDCs.

Seasonality

North America
North American demand for natural gas is seasonal. In general, demand tends to be higher in the winter months for
heating requirements and in the summer for power generation demand in support of cooling requirements. This effect
can be somewhat mitigated in the spring and fall by the need for industries to replenish the amount of gas held in
storage for future use.

The amount of uncontracted transportation capacity as well as transportation capacity under short term contracts on a
pipeline system determines the extent that seasonal demand will impact a pipeline system’s revenue. Pipeline systems
that have a higher ratio of long-term contracts (contracts with a duration longer than one year) will be impacted less by
seasonal demand. Conversely, for those pipeline systems with more available capacity, or operating under short term
contracts, fluctuations in demand between seasons can impact revenue. Pipeline systems which have a tariff that
includes seasonal rates for short term service may be able to mitigate the potential negative impact of seasonal
fluctuations in demand.

Great Lakes – As a turbine based pipeline system, Great Lakes’ design day capacity at the Emerson inlet is approximately
2.45 Bcf/day during the winter and 2.3 Bcf/day during the summer (system fuel requirements utilize a portion of this
capacity). Though the winter flow capability is higher than the summer capability, the market demand for Great Lakes’
long haul service can be higher in the summer when Great Lakes’ system has less transportation capacity.

The demand for Great Lakes’ long haul service is at its highest when natural gas is being delivered to natural gas
storage areas. This is due to the approximate 880 Bcf of working gas storage located at the end of the Great Lakes
system in Michigan and Ontario. The high demand period usually begins in the spring and extends through most of the
summer. The transportation value across the Great Lakes pipeline system is at its highest in conjunction with storage fill
requirements and electric power generation demand.

During the winter, there is also strong demand for Great Lakes services to meet the peak winter demand requirements
of Northern Minnesota, Northern Wisconsin, and Michigan. These deliveries are met through Great Lakes short haul,
long haul, and backhauls from storage. In fact, the aggregated peak day of all short haul and long haul flows occurs
during the winter. Approximately ten per cent of Great Lakes’ flows were contracted on a short-term basis in 2007.

Great Lakes experiences significant winter volatility in the utilization of its long haul contracts due to downstream
constraints on the Union Gas Limited and TransCanada systems. As the demand for storage withdrawals from the
Dawn, Ontario storage facility increases to serve points east, so does the level of downstream constraints which may
reduce shippers’ ability to use Great Lakes’ transportation services to serve Eastern markets. This constraint may reduce
demand for Great Lakes’ capacity during certain winter periods.

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Northern Border – Seasonal supply and demand fundamentals are a growing influence on Northern Border’s system
throughput due to increased competition for WCSB supply and growing competition from alternate sources of supply,
such as the Rockies, in the markets served by Northern Border. Demand for Northern Border’s transportation has
traditionally been the strongest during peak winter months to serve heating demand and peak summer months to serve
electric cooling demand and storage injection. Demand conditions in other market regions for Canadian supply can
impact the transportation value of Northern Border’s system. For example, the Western U.S. market is sensitive to
precipitation levels, which impact hydroelectric power generation. During the summer, high temperatures combined
with low hydroelectric power generation levels can increase demand for Canadian natural gas in this region and shift
supply away from Northern Border’s system.

Northern Border’s rate case settlement established seasonal rates for short-term service of less than one year that
provide for higher maximum rates during anticipated peak usage periods and lower maximum rates during anticipated
periods of reduced demand. Approximately 34 per cent of Northern Border’s design capacity was contracted on a
short-term basis in 2007.

Tuscarora – Tuscarora is almost fully contracted under long-term contracts (approximately 97 per cent contracted with a
weighted average remaining contract life of 10.4 years) at December 31, 2007. As a result, fluctuations in revenue due
to seasonality are minimal.

Supply

North American Supply
The primary source of natural gas transported by all of our pipeline systems is the WCSB. For this reason, the
continuous supply of Canadian natural gas is crucial to the long-term financial condition of our pipeline systems.

As of December 2006, the WCSB had remaining discovered natural gas reserves of approximately 57 trillion cubic feet
and a reserves-to-production ratio of approximately nine years at current levels of production. Historically, additional
reserves have continually been discovered to maintain the reserves-to-production ratio at close to nine years. It is
expected that producers will continue to explore and develop new fields, particularly in the Northeastern and West
central foothills regions of Alberta, Canada. There will also be significant activity aimed at unconventional resources
such as coal bed methane.

The amount of WCSB natural gas available for export is the most significant factor affecting the volume of natural gas
transported by our pipeline systems. The amount of WCSB natural gas available for export is determined by:

• WCSB natural gas production levels;

• demand for WCSB natural gas; and

• storage capacity for WCSB natural gas and demand for storage injection.

The extent to which WCSB natural gas available for export will be transported on each pipeline system is affected by:

• demand for WCSB natural gas in different U.S. consumer markets;

• available transportation capacity and related market pricing options on our competitors’ pipelines;

• natural gas from other supply sources that can be transported to our customer markets;

• the natural gas market price spread between Alberta, Canada and the applicable market which reflects the relative

supply and demand for WCSB natural gas in Canada and in the U.S.; and

• storage capacity in the U.S. and Canada and the related demand for storage injection.

Our Pipeline Systems
In 2007, approximately 84 per cent, 82 per cent and 92 per cent of the natural gas transported by Great Lakes,
Northern Border and Tuscarora, respectively, was produced in Canada.

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Great Lakes receives natural gas from interconnections with the TransCanada Mainline, ANR and from storage facilities.
Gas received from the interconnection with the TransCanada Mainline at Emerson, Manitoba is WCSB supply. ANR is
connected with numerous other pipelines, sourcing gas from virtually all North American basins as well as imported
LNG.

Northern Border is also connected directly with other natural gas supplies. Natural gas produced in the Williston Basin
of Montana and North Dakota and the Powder River Basin of Wyoming and Montana accounted for approximately
12 per cent of the natural gas Northern Border transported in 2007. The remaining natural gas transported by Northern
Border was synthetic gas produced at the Dakota Gasification plant in North Dakota.

Tuscarora receives natural gas from its interconnection with GTN. GTN is interconnected with WCSB supply as well as
natural gas from the Rockies and other U.S. basins.

CUSTOMERS, COMPETITION AND CONTRACTING

Customers

Great Lakes – The largest customer for Great Lakes’ capacity is TransCanada, through its mainline pipeline system. This
capacity is used by TransCanada customers to transport Western Canadian gas to Eastern Canadian and U.S. markets.
ANR also holds capacity on Great Lakes to integrate its Michigan storage locations with its Wisconsin pipeline system.
Various local distribution companies in Minnesota, Wisconsin and Michigan contract for transportation on Great Lakes
to add Canadian gas to their supply mix. In addition, natural gas marketing and trading companies and producers hold
transportation capacity on Great Lakes, either directly or through the capacity release program, and use Great Lakes’
flexibility to deliver gas to markets, interconnecting pipelines and storage facilities along its system to maximize the
value of their transportation contracts.

For the year ended December 31, 2007, TransCanada and ANR contracts represented approximately 45 per cent and
three per cent, respectively, of Great Lakes’ revenue. Great Lakes did not have any other customers contributing more
than 10 per cent of their 2007 revenues.

Although Great Lakes has traditionally operated under long-term contracts, in response to changing market conditions,
it markets its capacity on a shorter-term basis to a wide variety of customers, including producers, natural gas
marketing and trading companies and LDCs in the U.S. and Canada.

Northern Border – Northern Border serves Midwestern U.S. markets for customers located throughout North America.
Northern Border’s customers include natural gas producers, marketing and trading companies, industrial facilities, local
distribution companies and electric power generating plants.

For the year ended December 31, 2007, contracts with BP Canada Energy Marketing Corp., Nexen Marketing,
U.S.A., Inc. and Cargill Inc. represented approximately 16 per cent, 14 per cent and 14 per cent, respectively, of
Northern Border’s revenue.

Tuscarora – Tuscarora serves markets in Oregon, Northern California and Northern Nevada. Deliveries are also made
directly to the local gas distribution system of Sierra Pacific Power. Tuscarora’s customers include power generation
companies, local distribution companies, and a variety of industrial, commercial, and other companies.

For the year ended December 31, 2007, contracts with Sierra Pacific Power, Southwest Gas Company and Barrick
Goldstrike Mines represented approximately 72 per cent, 13 per cent and 11 per cent, respectively, of Tuscarora’s
revenue.

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Competition

Competition among natural gas pipelines is based primarily on transportation charges and proximity to natural gas
supply areas and markets. Our pipeline systems face competition at both the supply and market ends of their pipeline
systems where other pipelines access the same supply basins and/or deliver to markets served by our respective
pipelines. Other pipelines access the WCSB supply basin and provide alternative routes for shippers to access markets
served by our systems. Additionally, other pipelines bring supply sourced from other U.S. supply basins into our market
areas.

Great Lakes – Great Lakes’ principal business comes from its position as a link in the chain of pipelines that facilitate the
transportation of natural gas from Western Canada to Eastern Canadian markets. Natural gas is transported by
TransCanada from Western Canada to near Emerson, Manitoba, from Emerson to St. Clair, Michigan by Great Lakes,
and from St. Clair to Dawn, Ontario and points further east by TransCanada. The primary competition for Great Lakes is
the alternate route from Western Canada to Dawn on TransCanada’s Mainline. Other routes from Western Canada to
Ontario, Canada, are the Foothills Pipeline to Northern Border to Vector Pipeline route and the Alliance Pipeline to
Vector Pipeline route. In addition, gas sourced from the U.S. Rockies, U.S. Mid-Continent and U.S. Gulf Coast can be
delivered to Chicago and then to Ontario via the Vector Pipeline.

Northern Border – Northern Border’s system competes for natural gas supply with other pipelines that transport Western
Canadian natural gas to markets in the West, Midwest and East in North America, including TransCanada and Alliance
Pipeline. Northern Border also competes for demand for transportation services with other pipelines that provide the
markets it serves with access to natural gas storage facilities, and with alternate sources of supply, such as the Rockies,
the Mid-Continent, the Permian Basin and the Gulf Coast, and LNG. A new competitor is the REX-West segment of the
1,679 mile Rockies Express Pipeline system from Rio Blanco County, Colorado to Monroe County, Ohio, which is
increasing supply competition in Midwestern markets and could cause Northern Border to discount their rates or
otherwise experience a reduction in their revenues.

Tuscarora – Shippers of natural gas from the WCSB have other options for transporting Canadian natural gas to markets
throughout Canada and the U.S.

Tuscarora’s primary competition in the Northern Nevada natural gas transmission market is with Paiute Pipeline
Company (Paiute), owned by Southwest Gas Co. of Las Vegas, Nevada. Paiute interconnects with Northwest Pipeline
Corp. at the Nevada-Idaho border and transports natural gas from British Columbia and the U.S. Rocky Mountain Basin
to the Northern Nevada market.

Contracting

As existing contracts on our pipeline systems approach their expiration dates, efforts are made to extend and/or renew
the contracts. The ability to extend and/or renew expiring contracts will depend upon competitive alternatives, the
regulatory environment, and market and supply factors. The duration of new or renegotiated contracts will be affected
by current market price spreads, transportation rates, competitive conditions, and judgments concerning future market
trends and volatility. If market conditions are not favorable at the time of renewal, then transportation capacity may be
uncontracted until market conditions become more favorable. Subject to regulatory requirements, our pipeline systems
attempt to recontract or remarket their capacity at the maximum rates allowed under their tariffs. However, a pipeline
system may discount capacity under certain circumstances in order to maximize revenue.

Great Lakes – Existing transportation contracts mature at varying times and in varying amounts of throughput capacity.
Approximately four per cent of Great Lakes’ contracted capacity expired in 2007 and 15 per cent will expire by
December 31, 2008 in the absence of extensions or renewals of this capacity. In addition, ANR holds over 1,100
Mdth/d of capacity on Great Lakes that is expected to be renewed annually. For the year ended December 31, 2007,
Great Lakes’ average contracted capacity compared was 106 per cent.

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Northern Border – Northern Border contracted 97 per cent of its design capacity on a firm basis in 2007, some of
which was sold at a discount to maximize overall revenue on the Port of Morgan, Montana to Harper, Iowa portion of
the pipeline. As of January 31, 2008, Northern Border had 37 per cent of its design capacity uncontracted beginning in
the second quarter of 2008 and 48 per cent uncontracted by the end of 2008. Refer to Item 7. ‘‘Management’s
Discussion and Analysis of Financial Condition and Results of Operations’’ for further discussion.

Tuscarora – Tuscarora’s average contracted capacity for the year ended December 31, 2007 was 96 per cent. Tuscarora
has firm transportation contracts for 97 per cent of its available contracted capacity, as at January 31, 2008. This
includes contracts held by Sierra Pacific Power for 69 per cent of the total available capacity, the majority of which
expire on October 31, 2017.

REGULATORY ENVIRONMENT

Government Regulation

Great Lakes, Northern Border, and Tuscarora are regulated under the Natural Gas Act of 1938, Natural Gas Policy Act of
1978, and Energy Policy Act of 2005, which give the FERC jurisdiction to regulate virtually all aspects of their business,
including:

• transportation of natural gas;

• rates and charges;

• terms of service and service contracts with customers, including creditworthiness requirements;

• certification and construction of new facilities;

• extension or abandonment of service and facilities;

• accounts and records;

• depreciation and amortization policies;

• the acquisition and disposition of facilities;

• initiation and discontinuation of services; and

• standards of conduct for business relations with certain affiliates.

Rate Case, Great Lakes – Great Lakes’ last rate settlement expired on October 31, 2005 with no requirement to file a
new rate proceeding or settlement.

Rate Case, Northern Border – In November 2006, the FERC approved the settlement with Northern Border’s customers
of its 2005 rate case to be effective January 1, 2007. The settlement established maximum long-term mileage-based
rates and charges for transportation on Northern Border’s system. Northern Border’s overall rates were reduced,
compared with rates prior to the filing, by approximately 5 per cent. The settlement also provided for seasonal rates for
short-term transportation services. The settlement included a three-year moratorium on filing rate cases and participants
challenging Northern Border’s rates and requires that Northern Border file a rate case within six years from the date the
new rates went into effect.

Cost and Revenue Study, Tuscarora – As a result of an obligation to file a cost and revenue study with the FERC
pursuant to an agreement with the PUCN, Tuscarora, Sierra Pacific Power and the PUCN entered into settlement
discussions with respect to a potential rate adjustment in 2006. In April 2006, the PUCN and Sierra Pacific Power
agreed to a settlement with Tuscarora, which was subsequently approved by the FERC in July 2006. The settlement
resulted in a firm transportation rate of $0.40/decatherm per day (dth-day) beginning June 1, 2006, or a 17 per cent
reduction to the previous rate of $0.481/dth-day. The settlement also included a moratorium on all rate actions before
the FERC by any party to the settlement until May 31, 2010, including rate actions related to expansion projects where
Tuscarora proposes to price the expansion at the settlement rate.

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Income Tax Allowance – In May 2005, the FERC issued a policy statement permitting the inclusion of an income tax
allowance in the rates for partnership interests held by partners with an actual or potential income tax liability. On
December 16, 2005, the FERC issued an order (the ‘‘December 16 Order’’) in its first case-specific review of the income
tax allowance issue, reaffirming its tax allowance policy and directing the pipeline to provide certain evidence necessary
to determine the income tax allowance. The FERC’s new policy and the December 16 Order were appealed; however,
the United States Court of Appeals for the D.C. Circuit subsequently denied the petitions for review and upheld the
FERC’s income tax allowance policy.

On December 26, 2007, the FERC issued an order (the ‘‘December 26 Order’’) which upheld and clarified its
methodology for determining a partnership’s income tax allowance in a rate case. In the future, partnerships will be
required to prove (1) that its partners have an actual or potential income tax liability, which is determined by the
partner’s obligation to file a return that recognizes either a taxable gain or loss; (2) its partners’ marginal Federal income
tax rates, if higher than the commission’s default rates of 28 per cent for individuals and 34 per cent for corporations,
and (3) the partners’ marginal state income tax rates. If the FERC were to disallow a portion of the income tax
allowance for one of our pipeline systems in a rate case, it may cause its recourse rate to be set at a level that is
different, or lower, than the level otherwise in effect.

Composition of Proxy Groups for Rates of Return Determinations – On July 19, 2007, the FERC issued a policy
statement proposing to update its standards regarding the composition of proxy groups for determining the appropriate
returns on equity for natural gas and oil pipelines. The proposed policy statement would permit the inclusion of master
limited partnerships (MLPs) in the proxy group for purposes of calculating returns on equity under the Discounted Cash
Flow (DCF) analysis. This is a change from its prior view that MLPs should not be included in the proxy group.
Specifically, the FERC proposes that MLPs may be included in the proxy group provided that the distributions used in
the DCF analysis are capped at the pipeline’s reported earnings level. According to the proposed policy statement, the
return on equity under the DCF analysis is calculated by adding the dividend or distribution yield (dividends divided by
share/unit price) to the projected future growth rate of dividends or distributions. The future growth rate is weighted
based on the long-term growth of the economy and the short-term growth for the pipeline. Additionally, the decision
as to whether an MLP is included in the proxy group will be made on a case by case basis and will be based on stability
of the MLP’s earnings over a number of years. The FERC is currently evaluating the merit of the new policy statement
through comments, reply comments and technical conferences. The FERC’s proposed policy statement is subject to
change based on comments filed and the outcome of the technical conference and therefore we cannot predict the
impact or timing of the final policy statement.

Energy Affiliates – In November 2003, the FERC adopted revised standards of conduct which govern the relationships
between regulated interstate natural gas pipelines and their energy affiliates. The new standards of conduct were
designed to prevent interstate natural gas pipelines from giving any undue preference to their energy affiliates and
ensure that transmission service is provided on a nondiscriminatory basis. In November 2006, the United States Court of
Appeals for the District of Columbia vacated the FERC’s order regarding standards of conduct for energy affiliates of
natural gas pipelines and remanded the matter back to the FERC. On January 9, 2007, the FERC issued Order No. 690,
Standards of Conduct for Transmission Providers (the Interim Rule) as the Commission’s interim response to the Appeals
Court decision. The Interim Rule reduced the application of the standards of conduct for interstate natural gas pipelines
to the relationship between the pipelines and their marketing affiliates as defined in the FERC’s rules that were in effect
prior to the current regulations and made certain other revisions that were subject to the appeal. Requests for
clarifications and in the alternative rehearing of the Interim Rule have been filed. On January 18, 2007, the FERC issued
a Notice of Proposed Rulemaking, which if accepted as the final rule, will make permanent the Interim Rule’s
applicability of the standards of conduct to govern the relationship between interstate natural gas pipelines and their
marketing affiliates.

Market Manipulation – In January 2006, the FERC issued a final rule making it unlawful for any entity subject to its
jurisdiction that directly or indirectly purchases or sells natural gas, transportation services or electric energy to defraud,
using any device, scheme or artifice; make untrue statements of a material fact or omit a material fact; or engage in

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any act, practice or course of business that operates as a fraud. The maximum civil penalty under these statutes is
$1 million per day, per violation.

Environmental and Safety Matters

All of our pipeline systems’ operations are subject to stringent and complex federal, state, and local laws and
regulations governing environmental protection, including air emissions, water quality, wastewater discharges, and solid
waste management. Such laws and regulations generally require natural gas pipelines to obtain and comply with a wide
variety of environmental registrations, licenses, permits, and other approvals. These laws and regulations also can restrict
or impact business activities in many ways, such as restricting the way wastes are handled or disposed of; requiring
remedial action to mitigate pollution conditions that may be caused by its operations or that are attributable to former
operators; and enjoining some or all of the operations of facilities deemed in non-compliance with permits issued
pursuant to such environmental laws and regulations. Failure to comply with these laws and regulations may result in
the assessment of administrative, civil and/or criminal penalties, the imposition of remedial requirements, and the
issuance of orders enjoining future operations.

Pipeline Safety – Our pipeline systems are subject to U.S. Department of Transportation pipeline integrity management
regulations. The Pipeline Safety Improvement Act requires pipeline companies to perform integrity assessments on
pipeline segments that exist in densely populated areas or near specifically identified sites that are designated as high
consequence areas. Pipeline companies are required to perform the integrity assessments within ten years of the date of
enactment and perform subsequent integrity assessments on a seven-year cycle. All of our pipeline systems had
performed the required assessments of 50 per cent of the highest priority high consequence areas by the end of 2007.

Waste Management – The operations of our pipeline systems generate hazardous and non-hazardous solid wastes that
are subject to the federal Resource Conservation and Recovery Act (RCRA) and comparable state laws, which impose
detailed requirements for the handling, storage, treatment and disposal of hazardous and non-hazardous solid wastes.
For instance, RCRA prohibits the disposal of certain hazardous wastes on land without prior treatment, and requires
generators of wastes subject to land disposal restrictions to provide notification of pre-treatment requirements to
disposal facilities that are in receipt of these wastes. Generators of hazardous wastes also must comply with certain
standards for the accumulation and storage of hazardous wastes, as well as with recordkeeping and reporting
requirements applicable to hazardous waste storage and disposal activities.

Site Remediation – The Comprehensive Environmental Response, Compensation and Liability Act (CERCLA), also known
as ‘‘Superfund,’’ and comparable state laws and regulations impose liability, without regard to fault or the legality of the
original conduct, on certain classes of persons considered to be responsible for the release of hazardous substances into
the environment. These persons include the current and past owner or operator of the site where the release occurred,
and anyone who disposed or arranged for the disposal of a hazardous substance released at the site. Under CERCLA,
such persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that
have been released into the environment, for damages to natural resources and for the costs of certain health studies.

Our pipeline systems currently own or lease properties that for many years have been used for the transportation and
compression of natural gas. These properties and the substances released on them may be subject to CERCLA, RCRA
and analogous state laws. Under such laws, our pipeline systems could be required to remove any previously disposed
wastes, including waste disposed of by prior owners or operators; remediate contaminated property, including
groundwater contamination, whether from prior owners or operators or other historic activities or spills; or perform
remedial closure operations to prevent future contamination.

Air Emissions – The Clean Air Act (CAA) and comparable state laws regulate emissions of air pollutants from various
industrial sources, including compressor stations, and also impose various monitoring and reporting requirements. Such
laws and regulations may require pre-approval for the construction or modification of certain projects or facilities
expected to produce air emissions or result in an increase of existing air emissions; application for, and strict compliance

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with, air permits containing various emissions and operational limitations; or the utilization of specific emission control
technologies to limit emissions.

Water Discharges – The Clean Water Act (CWA) and analogous state laws impose strict controls with respect to the
discharge of pollutants, including spills and leaks of oil and other substances, into waters of the United States. The
discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by
the Environmental Protection Agency (EPA) or an analogous state agency. The CWA and regulations implemented
thereunder also prohibit the discharge of dredge and fill material into regulated waters, including wetlands, unless
authorized by an appropriately issued permit. Federal and state regulatory agencies may impose administrative, civil and
criminal penalties for non-compliance with discharge permits or other requirements of the CWA and analogous state
laws and regulations.

Activities on Federal Lands – Natural gas transportation activities are subject to the National Environmental Policy Act
(NEPA). NEPA requires federal agencies, including the Department of the Interior, to evaluate major agency actions
having the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare
an Environmental Assessment that assesses the potential direct, indirect and cumulative impacts of a proposed project
and, if necessary, will prepare a more detailed Environmental Impact Statement that may be made available for public
review and comment. The current activities of our pipeline systems, as well as any proposed plans for future activities,
on federal lands are subject to the requirements of NEPA.

Other Laws and Regulations – Recent scientific studies have suggested that emissions of certain gases, commonly
referred to as ‘‘greenhouse gases’’ and including carbon dioxide and methane, may be contributing to warming of the
Earth’s atmosphere. In response to such studies, the U.S. Congress is actively considering legislation to reduce emissions
of greenhouse gases. In addition, several states have declined to wait on Congress to develop and implement climate
control legislation and have already taken legal measures to reduce emissions of greenhouse gases.

The Department of Homeland Security Appropriations Act of 2007 requires the Department of Homeland Security (DHS)
to issue regulations establishing risk-based performance standards for the security of chemical and industrial facilities,
including oil and gas facilities that are deemed to present ‘‘high levels of security risk.’’ The DHS is currently in the
process of adopting regulations that will determine whether some of our pipeline facilities or operations will be subject
to additional DHS-mandated security requirements.

Title to Properties

Our pipeline systems hold all rights, titles and interests in their pipeline system. With respect to real property, our
pipeline systems own sites for compressor stations, meter stations, pipeline field offices, microwave towers and a
corporate office. Our pipeline systems also derive interests from leases, easements, rights-of-way, permits and licenses
from landowners or governmental authorities permitting land use for construction and operation of their pipelines.

Great Lakes – Approximately 74 miles of Great Lakes’ pipeline system are located within the boundaries of three Indian
reservations: the Leech Lake Chippewa Indian Reservation and the Fond du Lac Chippewa Indian Reservation in
Minnesota, and Bad River Chippewa Indian Reservation in Wisconsin. In 1968, Great Lakes obtained right-of-way across
allotted lands located within each of the reservations boundaries. All of the allotted lands are subject to a 50 year
easement granted by the Bureau of Indian Affairs (BIA) for and on behalf of the individual Indian owners or the
reservations. These tracts are subject to right-of-way permits issued by the BIA that expire in 2018. Also, the Great
Lakes pipeline crosses approximately 1000 ft. in two tracts in Lower Michigan, which are located within the Chippewa
Indian Reservation, under perpetual easements.

Northern Border – Approximately 90 miles of Northern Border’s pipeline system are located within the boundaries of the
Fort Peck Indian Reservation in Montana. In 1980, Northern Border entered into a pipeline right-of-way lease with the
Fort Peck Tribal Executive Board on behalf of the Assiniboine and Sioux Tribes of the Fort Peck Indian Reservation. This
pipeline right-of-way lease granted Northern Border the right to construct and operate its pipeline on certain tribal

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TC PIPELINES, LP

lands. The pipeline right-of-way lease expires in 2011, although Northern Border has an option to renew the pipeline
right-of-way lease through 2061. In conjunction with obtaining a right-of-way across tribal lands located within the
exterior boundaries of the Fort Peck Indian Reservation, Northern Border also obtained right-of-way across allotted lands
located within the reservation boundaries. Most of the allotted lands are subject to a perpetual easement granted by
the BIA for and on behalf of the individual Indian owners or obtained through condemnation. Several tracts are subject
to a right-of-way grant that expires in 2015.

Insurance

The Partnership’s operations and activities are insured under TransCanada insurance programs, including property
insurance, liability, automobile liability and workers compensation, in amounts which management believes are
reasonable and appropriate.

Employees

The Partnership does not have any employees. In addition, none of our pipeline systems directly employ any of the
persons responsible for managing or operating the pipeline systems or for providing them with services related to their
day-to-day business affairs. Subsidiaries of TransCanada are the operators of all of our systems.

AVAILABLE INFORMATION

Our website is www.tcpipelineslp.com. We make available free of charge, on or through our website, our annual,
quarterly and current reports, and any amendments to those reports, as soon as reasonably practicable after
electronically filing or furnishing such reports with the SEC. Information contained on our web site is not part of this
report.

Item 1A. Risk Factors

Cautionary Statement Regarding Forward-Looking Information

A number of statements made by TC PipeLines, LP in this Form 10-K filing 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 current beliefs as well as assumptions made
by and information currently available to the Partnership. These statements reflect the Partnership’s current views with
respect to future events. The Partnership assumes no obligation to update any such forward looking statements to
reflect events or circumstances occurring after the date hereof. Words such as ‘‘anticipate,’’ ‘‘believe,’’ ‘‘estimate,’’
‘‘expect,’’ ‘‘plan,’’ ‘‘intend,’’ ‘‘forecast,’’ and similar expressions, identify forward-looking statements. By its nature, such
forward-looking information is subject to various risks and uncertainties, including the risk factors discussed under
Item 1A. ‘‘Risk Factors’’, 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.

Each of the risks and uncertainties described below could lead to events or circumstances that may have a material
adverse effect on our business, financial condition, results of operations and cash flows, including our ability to make
distributions to our unitholders.

All of the information included in this report and any subsequent reports we may file with the SEC or make available to
the public should be carefully considered and evaluated before investing in any securities issued by us.

The risks referred to herein refer to risks inherent in the Partnership and our pipeline systems.

2007 ANNUAL REPORT

23

Risks Inherent in Our Business

Cash distributions are dependent primarily on our cash flow, financial reserves and working capital
borrowings.
Cash distributions are not dependent solely on our profitability, which is affected by non-cash items. Therefore, we may
make cash distributions during periods when losses are reported and may not make cash distributions during periods
when we report profits.

Factors that affect the actual amount of cash that we will have available for distribution to our unitholders include the
following:

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

• the level of capital expenditures made by our pipeline systems;

• the required principal and interest payments on our debt, retirement of debt and other liabilities including cost of

acquisitions;

• the amount of cash distributed to us by the entities in which we own a non-controlling interest;

• our ability to borrow funds and access capital markets including the issuance of debt and equity securities; and

• restrictions on distributions contained in debt agreements.

We are dependent on our pipeline systems to generate sufficient cash to enable us to pay distributions.
The amount of cash we have quarterly to distribute to our common unitholders depends upon numerous factors, most
of which are beyond our control and the control of our general partner, including:

• the rates charged and the volumes under contract for the transportation services of our pipeline systems;

• the quantities of natural gas available for transport and the demand for natural gas;

• legislative or regulatory action affecting demand for and supply of natural gas, and the rates our pipeline systems are

allowed to charge in relation to their operating costs;

• the level of our pipeline systems’ operating costs; and

• the creditworthiness of our pipeline systems’ shippers.

If we do not identify opportunities for accretive growth through organic projects or acquisitions, or our
pipeline systems do not successfully complete expansion projects or make and integrate acquisitions that are
accretive, our future growth may be limited.
A principal focus of our strategy is to continue to grow the cash distributions on our units by expanding our business.
Our ability to grow depends on our ability to undertake acquisitions and organic growth projects, and the ability of our
pipelines systems to complete expansion projects and make acquisitions that result in an increase in cash per unit
generated from operations.

The long-term financial conditions of our pipeline systems are dependent on the continued availability of
Western Canadian natural gas for import into the U.S. and the market demand for these volumes.
Competition from pipelines that deliver natural gas from other supply sources to our pipeline systems’ market
areas could cause our pipeline systems to discount their rates or otherwise experience a reduction in their
revenues.
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 our pipeline systems. High
exploration and production costs, low prices for natural gas, regulatory limitations such as royalty frameworks, or the
lack of available capital for these projects could adversely affect the development of additional reserves in Western
Canada and the production in the WCSB.

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TC PIPELINES, LP

Volumes available for export out of the WCSB depend in part on the internal demand for Canadian natural gas which
may increase as a result of increased demand for electricity generation and other industrial requirements, including the
development of oil sands projects, which may require substantial amounts of natural gas. This higher internal demand
may reduce the amount of gas available for import into the U.S. In the longer term, a portion of the Alberta hub gas
supply may come from proposed gas pipelines from the North Slope of Alaska and the Mackenzie Delta of Canada and
from the continued growth of coal bed methane projects. Cancellation or delays in the construction of such pipelines or
such projects could adversely affect the volumes available for export in the long term.

If the availability of Alberta hub natural gas was to decline, existing shippers on our pipeline systems may be unlikely to
extend their contracts and our pipeline systems 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 our pipeline systems.

In addition, existing customers may not extend their contracts if the cost of delivered natural gas from other producing
regions into the markets served by our pipeline systems is lower than the cost of natural gas delivered by our pipeline
systems. Our pipeline systems face increased competition from other pipelines that provide access for our shippers to
capacity from the U.S. Rocky Mountain Region. The Rockies Express Pipeline owned by Rockies Express Pipeline LLC is
being constructed in three phases and the planned terminus is in Clarington, Ohio. The first phase of The Rockies
Express Pipeline is completed and currently delivering gas to interconnects in the Midwestern region. The Rockies
Express Pipeline could result in significant downward pressure on natural gas prices in the Mid-continent Region, which
could have an impact on Northern Border or Great Lakes.

An increase in competition in the key markets served by our pipeline systems could arise from new ventures or
expanded operations from existing competitors. Our financial performance depends to a large extent on the capacity
contracted on our pipeline systems. Decreases in the volumes transported by our pipeline systems, whether caused by
supply or demand factors in the markets these pipeline systems serve, competition or otherwise, can directly and
adversely affect our revenues and results of operations.

Our pipeline systems may not be able to maintain existing customers or acquire new customers when the
current shipper contracts expire or customers may choose to recontract for shorter periods or at less than
maximum rates.
The ability to extend and replace contracts on terms comparable to prior contracts or on any terms at all, could be
adversely affected by factors, including:

• the supply of natural gas in Canada and the U.S.;

• competition from alternative sources of supply in the U.S.;

• competition from other pipelines, including their transportation rates or through their access to upstream supplies, as

well as the proposed construction by other companies of additional pipeline capacity;

• the price of, and demand for, natural gas in markets served by our pipeline systems; and

• regulatory actions.

Ongoing changes in these factors and customers’ ability to adjust to changing market conditions may cause Great Lakes
and Northern Border to sell a significant portion of available capacity on a short-term basis. The weighted average life
of Great Lakes’ and Northern Border’s contracts has generally declined over time. As of January 31, 2008, the weighted
average remaining lives of Great Lakes’ and Northern Border’s contracts were 2.4 years and 1.3 years, respectively.
Additionally, if the forward natural gas basis differentials do not support maximum rates, they may sell portions of their
capacity at discounted rates. Any inability by Great Lakes and Northern Border to renew existing contracts at maximum
rates or at all may have an adverse impact on their revenues and, as a result, cash distributions made to us.

2007 ANNUAL REPORT

25

If any significant shipper fails to perform its contractual obligations, our pipeline systems’ respective cash
flows and financial condition could be adversely impacted.
As of December 31, 2007, each of our pipeline systems has customers that account for more than ten per cent of their
revenue. The loss of all or even a portion of the revenues associated with these customers, as a result of competition,
creditworthiness or otherwise, could have a material adverse effect on the financial condition, results of operations and
cash flows of our pipeline systems, unless they were able to contract for comparable volumes from other customers at
favorable rates.

Sierra Pacific Power is Tuscarora’s largest shipper, with firm contracts for approximately 69 per cent of its capacity. Sierra
Pacific Resources and Sierra Pacific Power have non-investment grade credit ratings.

Our pipeline systems’ transportation rates are subject to review and possible adjustment by federal
regulators. If the FERC requires that our pipeline systems’ tariff be changed, their respective cash flows may
be adversely affected.
Under the Natural Gas Act (NGA), interstate transportation rates must be just and reasonable and not unduly
discriminatory. Our pipeline systems are subject to extensive regulation by the FERC. The FERC’s regulatory authority is
not limited to but extends to matters including:

• transportation of natural gas;

• rates and charges;

• operating terms and conditions of service including creditworthiness requirements;

• types of services our pipeline systems may offer to their customers;

• construction of new facilities;

• extension or abandonment of service and facilities;

• accounts and records;

• depreciation and amortization policies;

• the acquisition and disposition of facilities;

• initiation and discontinuation of services; and

• standards of conduct business relations with certain affiliates.

Given the extent of regulation by the FERC and potential changes to regulations, we cannot predict:

• the likely federal regulations under which our pipeline systems will operate in the future;

• the effect that regulation will have on financial position, results of operations and cash flows of our pipeline systems

and ourselves; or

• whether our cash flow will be adequate to make distributions to unitholders.

Great Lakes’ last rate settlement expired on October 31, 2005 with no requirement to file a new rate proceeding or
settlement. Northern Border and Tuscarora are currently operating under rate settlements which precludes a party to the
rate settlements from bringing any rate actions prior to December 31, 2009 and May 31, 2010, respectively.

Action by the FERC on currently pending matters as well as matters arising in the future could adversely affect our
pipeline systems’ ability to establish or charge rates that would cover future increase in their costs, or even to continue
to collect rates that cover current costs, including a reasonable return. We cannot assure unitholders that our pipeline
systems will be able to recover all of their costs through existing or future rates.

Should our pipeline systems fail to comply with all applicable FERC administered statutes, rules, regulations and orders,
our pipeline systems could be subject to substantial penalties and fines. Under the Energy Policy Act of 2005, the FERC

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TC PIPELINES, LP

has civil penalty authority under the NGA to impose penalties for current violations of up to $1 million per day for each
violation.

Finally, we cannot give any assurance regarding the future regulations under which our pipeline systems will operate
their natural gas transportation businesses, or the effect such regulations could ultimately have on our financial
condition, results of operations and cash flows.

If our pipeline systems do not maintain their respective rate bases, the amount of revenue attributable to the
return on the rate base they collect from their shippers will decrease over time.
Our 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. In the absence of additions to
the rate base through capital expenditures, the amount they may collect from customers decreases as the rate base
declines as a result of, among other things, depreciation and amortization.

Our pipeline systems’ pipeline integrity programs may impose significant costs and liabilities.
The U.S. Department of Transportation rules require pipeline operators to develop integrity management programs to
comprehensively evaluate their pipelines, and take measures to protect pipeline segments located in what the rules refer
to as ‘‘high consequence areas.’’ The final rule resulted from the enactment of the Pipeline Safety Improvement Act of
2002. At this time, we cannot predict the total costs of compliance with this rule because those costs will depend on
the extent of the pipeline testing and any subsequent repairs found to be necessary. Our pipeline systems completed
the required 50 per cent inspection of their respective pipelines highest priority highest consequence segments of lines
by the end of 2007. The remaining 50 per cent of each pipeline’s highest priority highest consequence segments of
pipeline is required to be inspected, and repaired if necessary, by 2012. After that point, the inspection is required to
reoccur every seven years. Once 100 per cent of our pipeline systems have been inspected, we will have a better
understanding of the total ongoing costs. Our pipeline systems will continue their pipeline integrity testing programs to
assess and maintain the integrity of the pipelines. The results of this work could cause our pipeline systems to incur
significant and unanticipated capital and operating expenditures for repairs or upgrades deemed necessary to ensure the
continued safe and reliable operation of their pipelines.

Our pipeline systems’ operations are regulated by federal, state and local agencies responsible for
environmental protection and operational safety.
Risks of substantial costs and liabilities are inherent in pipeline operations and each of our pipeline systems 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 our pipeline systems’ operations.
Moreover, new, stricter environmental laws, regulations or enforcement policies could be implemented that significantly
increase our pipeline systems’ compliance costs or the cost of any remediation of environmental contamination that
may become necessary, and these costs could be material. For instance, the U.S. Congress is actively considering federal
legislation to reduce emissions of ‘‘greenhouse gases’’ (including carbon dioxide and methane). Several states of the U.S.
have already taken legal measures to reduce emissions of greenhouse gases, and many other nations, not including the
U.S., have also already agreed to regulate emissions of greenhouse gases. As a result of the regulation of greenhouse
gases in the U.S., we may incur increased compliance costs to (i) operate and maintain our facilities; (ii) install new
emission controls on our facilities; and (iii) administer and manage any greenhouse gas emissions reduction program
that may be applicable to our operations. In addition, laws and regulations to reduce emissions of greenhouse gases
could affect the consumption of natural gas and consequently, adversely affect the demand for our pipeline services
and the rates we are able to collect for those services. If our pipeline systems are not able to recover these costs, cash
distributions to unitholders could be adversely affected.

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27

Our pipeline systems’ indebtedness may limit their ability to borrow additional funds, make distributions to
us or capitalize on business opportunities.
As of December 31, 2007, Great Lakes, Northern Border and Tuscarora had $440 million, $616 million and $66 million
of debt outstanding, respectively. Their respective levels of debt could have important consequences to Great Lakes,
Northern Border and Tuscarora, including the following:

• their ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other

purposes may be impaired or such financing may not be available on favorable terms;

• they will need a portion of their cash flow to make interest payments on the debt, reducing the funds that would
otherwise be available for operations, future business opportunities and distributions to us, which will reduce our
ability to make distributions to our unitholders;

• their debt level may make them more vulnerable to competitive pressures or a downturn in our business or the

economy generally; and

• their debt level may limit their flexibility in responding to changing business and economic conditions.

Our pipeline systems’ ability to service their debt will depend upon, among other things, future financial and operating
performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other
factors, some of which are beyond their control.

In addition, under the terms of these financing arrangements, our pipeline systems are prohibited from making cash
distributions during an event of default under their debt instruments. Under Great Lakes’ debt instruments, Great Lakes
has limitations on the level of indebtedness and has other restrictions, including a general prohibition against liens on
pipeline facilities. Provisions in Northern Border’s debt instruments limit its ability to incur indebtedness and engage in
specific transactions. This could reduce its ability to capitalize on business opportunities that arise in the course of its
business. Under Tuscarora’s debt instruments, Tuscarora has granted a security interest in certain of its transportation
contracts, which is available to noteholders upon an event of default. In addition, the Partnership’s third party credit
facility requires us to maintain certain financial ratios and contains restrictions on incurring additional debt and making
distributions to partners.

We do not own a controlling interest in Great Lakes or Northern Border and we may be unable to cause
certain actions to take place unless the other partner agrees. As a result, we will be unable to control the
amount of cash we will receive from those operations and we could be required to contribute significant cash
to fund our share of their operations. If we fail to make these contributions our ownership interest would be
diluted.
The major policies of Great Lakes and Northern Border are established by each of their Management Committees.

Great Lakes’ Management Committee consists of up to six members, three of whom are designated by us and three of
whom are designated by TransCanada. Currently the committee consists of four appointed members, two of whom are
designated by us and two of whom are designated by TransCanada. All decisions by the Management Committee
require unanimous consent. An Executive Committee which consists of up to three members: one Partnership
Committee Member, one TransCanada Committee Member and the Great Lakes’ President, a non-voting member.
Currently this committee consists of two appointed members: one Partnership Committee Member and one
TransCanada Committee Member, who also serves as the Great Lakes president. The Executive Committee has all of the
powers of the Management Committee in the management of Great Lakes’ business. Because of these provisions,
without the concurrence of TransCanada, we may be unable to cause Great Lakes to take or not to take certain
actions, even though those actions may be in the best interest of us or Great Lakes.

Northern Border’s Management Committee consists of four members, two of whom are designated by us and two of
whom are designated by an affiliate of ONEOK. The Management Committee requires the affirmative vote of a majority
of the partners’ ownership interests to act on most activities. Certain activities require the unanimous consent of the
committee, such as the filing of the application for regulatory authority to construct and operate new facilities and any

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TC PIPELINES, LP

changes to the cash distribution policy. Because of these provisions, without the concurrence of ONEOK, we may be
unable to cause Northern Border to take or not to take certain actions, even though those actions may be in the best
interest of us or Northern Border.

Great Lakes and Northern Border may require us to make additional capital contributions. Our funding of these capital
contributions would reduce the amount of cash otherwise available for distribution to our unitholders. Additionally, in
the event we elect not to, or are unable to, make a required capital contribution to Great Lakes or Northern Border, our
ownership interest would be diluted.

Our pipeline systems’ operations are subject to operational hazards and unforeseen interruptions, which
could adversely affect their businesses and for which they may not be adequately insured.
Our pipeline systems’ operations are subject to all of the risks and hazards typically associated with the operation of
natural gas transportation pipeline systems. Operating risks include, but are not limited to, leaks, pipeline ruptures, the
breakdown or failure of equipment or processes, and the performance of pipeline facilities below expected levels of
capacity and efficiency. Other operational hazards and unforeseen interruptions include adverse weather conditions,
accidents, the collision of equipment with our pipeline systems’ pipeline facilities (which may occur if a third party were
to perform excavation or construction work near these facilities), and catastrophic events such as explosions, fires,
earthquakes, floods or other similar events beyond our pipeline systems’ control. It is also possible that our pipeline
systems’ infrastructure facilities could be direct targets or indirect casualties of an act of terrorism. A casualty occurrence
might result in injury or loss of life, extensive property damage or environmental damage. Liabilities incurred, and
interruptions to the operation of our pipeline systems’ facilities, for short or extended durations, caused by such an
event, could reduce revenues generated by our pipeline systems and increase expenses, thereby impairing their ability to
meet their obligations. Insurance proceeds may not be adequate to cover all liabilities or expenses incurred or revenues
lost. Should one of our pipeline systems experience such an event, it may have an adverse impact on our results of
operations and cash flow.

Our pipeline systems do not own all of the land on which their pipelines and facilities are located, which
could disrupt their operations.
Our pipeline systems do not own all of the land on which their pipelines and facilities are located, and they are,
therefore, subject to the risk of increased costs to maintain necessary land use. They obtain the rights to construct and
operate certain of our pipelines and related facilities on land owned by third parties and governmental agencies for a
specific period of time. Their loss of these rights, through their inability to renew right-of-way contracts or otherwise, or
increased costs to renew such rights, could have a material adverse effect on their financial condition, results of
operations and cash flows.

If we were to lose TransCanada’s management expertise, we would not have sufficient stand-alone resources
to operate.
TransCanada, through wholly-owned subsidiaries, is the operator of all our pipeline systems. We do not presently have
sufficient stand-alone management resources to operate without services provided by TransCanada. Further, we would
not be able to evaluate potential growth opportunities and successfully complete acquisitions without TransCanada’s
resources.

Risks Inherent in an Investment in the Partnership

The Partnership’s indebtedness may limit its ability to borrow additional funds, make distributions or
capitalize on business opportunities.
As of December 31, 2007, the Partnership had $573 million of debt outstanding. This substantial level of debt could
have important consequences to the Partnership including the following:

• our ability to obtain additional financing, if necessary, for working capital, acquisitions or other purposes may be

impaired or such financing may not be available on favorable terms;

2007 ANNUAL REPORT

29

• we will need a portion of our cash flow to make interest payments on the debt, reducing the funds that would
otherwise be available for operations, future business opportunities and distributions to our unitholders; and

• our debt level may limit our flexibility in responding to changing business and economic conditions.

Our ability to service our debt will depend upon, among other things, the future financial and operating performance
of our pipeline systems, which will be affected by prevailing economic conditions and financial, business, regulatory and
other factors, some of which are beyond our control.

In addition, our credit facilities contain restrictive covenants that may prevent us from engaging in certain transactions
that we deem beneficial. These agreements require us to comply with various affirmative and negative covenants and
maintaining certain financial ratios. There are restrictions and covenants with respect to:

• entering into mergers, consolidations and sales of assets;

• granting liens;

• material amendments to TC PipeLines’ partnership agreement;

• incurring additional debt; and

• distributions to partners.

Any future debt may contain similar restrictions.

Increases in interest rates could materially adversely affect our business, results of operations, cash flows and
financial condition.
As of December 31, 2007, TC PipeLines had approximately $507 million outstanding under the Senior Credit Facility, all
of which was at variable interest rates. As a result, our results of operations, cash flows and financial condition could be
materially adversely affected by significant increases in interest rates. From time to time, we may enter into interest rate
swap arrangements, which decrease our exposure to variable interest rates. At December 31, 2007, approximately
80 per cent of the variable interest rate exposure related to the Partnership’s $507 million of debt outstanding under
the Senior Credit Facility was mitigated by fixed interest rate swap arrangements.

An increase in interest rates may also cause a corresponding decline in demand for equity investments, in general, and
in particular for yield-based equity investments such as our common units. Any such reduction in demand for our
common units resulting from other more attractive investment opportunities may cause the trading price of our
common units to decline.

We do not have the same flexibility as other types of organizations to accumulate cash and equity to protect
against illiquidity in the future.
Unlike a corporation, our partnership agreement requires us to make quarterly distributions to our unitholders of all
available cash reduced by any amounts of reserves for commitments and contingencies, including capital and operating
costs and debt service requirements. The value of our units and other limited partner interests may decrease in direct
correlation with decreases in the amount we distribute per unit. Accordingly, if we experience a liquidity problem in the
future, we may not be able to recapitalize by issuing more equity.

Unitholders have limited voting rights and do not control our general partner.
The general partner is our manager and operator. Unlike the holders of common stock in a corporation, holders of
common units have only limited voting rights on matters affecting our business. Unitholders have no right to elect our
general partner on an annual or other continuing basis. Our general partner may not be removed except by the vote of
the holders of at least 662⁄3 per cent of the outstanding units and upon the election of a successor general partner by
the vote of the holders of a majority of the outstanding common units. These required votes would include the votes of
units owned by our general partner and its affiliates. The ownership of an aggregate of approximately 32 per cent of
the outstanding units by our general partner and its affiliates has the practical effect of making removal of our general
partner difficult.

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TC PIPELINES, LP

In addition, the partnership agreement contains some provisions that may have the effect of discouraging a person or
group from attempting to remove our general partner or otherwise change our management. If our general partner is
removed as our general partner under circumstances where cause does not exist and units held by our general partner
and its affiliates are not voted in favor of that removal:

• any existing arrearages in the payment of the minimum quarterly distributions on the common units will be

extinguished; and

• our general partner will have the right to convert its general partner interests and its incentive distribution rights into

common units or to receive cash in exchange for those interests.

These provisions may diminish the price at which the common units will trade under some circumstances.The
partnership agreement also contains provisions limiting the ability of unitholders to call meetings of unitholders or to
acquire information about our operations, as well as other provisions limiting the unitholders’ ability to influence the
manner or direction of management. Further, if any person or group other than our general partner or its affiliates or a
direct transferee of our general partner or its affiliates acquires beneficial ownership of 20 per cent or more of any class
of units then outstanding, that person or group will lose voting rights with respect to all of its units. As a result,
unitholders will have limited influence on matters affecting our operations, and third parties may find it difficult to
attempt to gain control of us, or influence our activities.

We may issue additional common units without unitholder approval, which would dilute existing unitholders’
interest. In addition, issuance of additional common units may increase the risk that we will be unable to pay
the full minimum quarterly distribution on all common units.

Our general partner can cause us to issue additional common units, without the approval of unitholders, in the
following circumstances:

• under employee benefit plans, if any;

• upon conversion of the general partner interests and incentive distribution rights into common units as a result of the

withdrawal of our general partner; or

• in connection with acquisitions or capital improvements that are accretive to our cash flow on a per unit basis.

In addition, we may issue an unlimited number of limited partner interests of any type without the approval of the
unitholders. Based on the circumstances of each case, the issuance of additional common units or securities ranking
senior to or on a parity with the common units may dilute the value of the interests of the then-existing holders of
common units in the net assets of TC PipeLines and dilute the interests of unitholders in distributions by TC PipeLines.
Our partnership agreement does not give the unitholders the right to approve the issuance by us of equity securities
ranking junior to the common units at any time.

Any increase in the number of outstanding common units will increase the percentage of the aggregate minimum
quarterly distribution payable to the common unitholders, which will in turn have the effect of increasing the risk that
we will be unable to pay the minimum quarterly distribution in full on all the common units.

Unitholders may not have limited liability in some circumstances.
The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not
been clearly established in some states. If it were to be determined that:

• TC PipeLines had been conducting business in any state without compliance with the applicable limited partnership

statute, or

• the right or the exercise of the right by the unitholders as a group to remove or replace our general partner, to

approve some amendments to the partnership agreement or to take other action under the partnership agreement
constituted participation in the ‘‘control’’ of TC PipeLines’ business,

2007 ANNUAL REPORT

31

then unitholders could be held liable in some circumstances for TC PipeLines’ obligations to the same extent as a
general partner. In addition, under some circumstances a unitholder may be liable to TC PipeLines for the amount of a
distribution for a period of three years from the date of the distribution.

Our general partner has a limited call right that may require unitholders to sell their common units at an
undesirable time or price.
If our general partner and its affiliates, who currently own an aggregate of approximately 30.7 per cent of our common
units, come to own 80 per cent or more of the common units, the general partner will have the right, which it may
assign to any of its affiliates or us, to acquire all of the remaining common units held by unaffiliated persons at a price
generally equal to the then current market price of the common units. As a consequence, unitholders may be required
to sell their common units at a time when they may not desire to sell them or at a price that is less than the price they
would desire to receive upon sale. Unitholders may also incur a tax liability upon a sale of their units.

Without the consent of each unitholder, Great Lakes, Northern Border or Tuscarora might be converted into a
corporation, which would result in Great Lakes, Northern Border or Tuscarora, as the case may be, being
subject to corporate income taxes.
If it becomes unlawful to conduct the business of Great Lakes, Northern Border or Tuscarora as a partnership and some
other conditions are satisfied, the business and assets of Great Lakes, Northern Border or Tuscarora, as the case may be,
will automatically be transferred to a corporation without the vote or consent of unitholders. Therefore, unitholders
would not receive a proxy or consent solicitation statement in connection with that transaction. However, we believe
that it is unlikely that circumstances requiring an automatic transfer will occur. A transfer to corporate form would result
in Great Lakes, Northern Border or Tuscarora being subject to corporate income taxes and would likely be materially
adverse to their, and therefore, our results of operations and financial condition.

TransCanada controls our general partner, which has sole responsibility for conducting our business and
managing our operations. TC PipeLines GP, our general partner, and its affiliates have limited fiduciary
responsibilities and may have conflicts of interest with respect to our partnership, and they may favor their
own interests to the detriment of our unitholders.
The directors and officers of TC PipeLines GP and its affiliates have duties to manage TC PipeLines GP in a manner that
is beneficial to its stockholders. At the same time, TC PipeLines GP has duties to manage our partnership in a manner
that is beneficial to us. Therefore, TC PipeLines GP’s duties to us may conflict with the duties of its officers and directors
to its stockholders. Such conflicts may include, among others, the following:

• decisions of TC PipeLines GP regarding the amount and timing of asset purchases and sales, cash expenditures,

borrowings, issuances of additional common units and reserves in any quarter may affect the level of cash available
to pay quarterly distributions to unitholders and TC PipeLines GP;

• under our partnership agreement, TC PipeLines GP determines which costs incurred by it and its affiliates are

reimbursable by us;

• affiliates of TC PipeLines GP may compete with us in certain circumstances;

• TC PipeLines GP may limit our liability and reduce our fiduciary duties, while also restricting the remedies available to
our unitholders for actions that might, without the limitations, constitute breaches of fiduciary duty. As a result of
purchasing our units, unitholders are deemed to consent to some actions and conflicts of interest that might
otherwise constitute a breach of fiduciary or other duties under applicable law;

• we do not have any employees and we rely solely on TC PipeLines GP and its affiliates to conduct our business, and

• TransCanada, through wholly-owned subsidiaries, is the operator of all of our pipeline systems. This operator role

along with their ownership interest in Great Lakes may put TransCanada in a position to have to make decisions that
may conflict as operator and/or owner of these systems.

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TC PIPELINES, LP

Cost reimbursements due to our general partner may be substantial and could reduce our cash available for
distribution.
Prior to making any distribution on the common units, we will reimburse our general partner and its affiliates, including
officers and directors of the general partner, for all expenses incurred by our general partner and its affiliates on our
behalf. During the year ended December 31, 2007, we paid fees and reimbursements to our general partner in the
amount of $1.9 million. Our general partner in its sole discretion will determine the amount of these expenses. In
addition, our general partner and its affiliates may provide us services for which we will be charged reasonable fees as
determined by the general partner. The reimbursement of expenses and the payment of fees could adversely affect our
ability to make distributions.

If we were found to be an ‘‘investment company’’ under the Investment Company Act of 1940, our contracts
may be voidable and our offers of securities may be subject to rescission.
If we were deemed to be an unregistered ‘‘investment company’’ under the Investment Company Act, our contracts
may be voidable and our offers of securities may be subject to rescission, and we may also be subject to other
materially adverse consequences.

Our assets include a 46.45 per cent general partner interest in Great Lakes and a 50 per cent general partner interest in
Northern Border. We could be deemed to be an ‘‘investment company’’ under the Investment Company Act if these
general partner interests constituted an ‘‘investment security’’, as defined in the Investment Company Act. If we were
deemed to be an ‘‘investment company’’, then we would be required to be registered as an investment company under
the Investment Company Act. In that case, there would be a substantial risk that we would be in violation of the
Investment Company Act because of the practical inability to register under the Investment Company Act.

Tax Risks

The Internal Revenue Service (‘‘IRS’’) could treat us as a corporation, which would substantially reduce the
cash available for distribution to unitholders.
The anticipated after-tax benefit of an investment in us depends largely on our classification as a partnership for federal
income tax purposes. We have not requested, and do not plan to request, a ruling from the IRS on this or any other
matter affecting us.

If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our income
at the corporate tax rate, which is currently a maximum of 35 per cent. Distributions would generally be taxed again to
unitholders as corporate distributions, and no income, gains, losses, deductions or credits would flow through to
unitholders. Because a tax would be imposed upon us as an entity, the cash available for distribution to unitholders
would be substantially reduced. Our treatment as a corporation would result in a material reduction in the anticipated
cash flow and after-tax return to unitholders and thus would likely result in a substantial reduction in the value of the
common units.

Current law may change so as to cause us to be taxable as a corporation for federal income tax purposes or otherwise
to be subject to entity level taxation. Our partnership agreement provides that, if a law is enacted or existing law is
modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us 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. These changes would include a decrease in distributions to reflect the impact
of that law on us.

If our pipeline systems were to become subject to a material amount of entity level taxation for state tax
purposes, then our pipeline systems’ operating cash flow and cash available for distribution to us and for
other business needs would be reduced.
Our pipeline systems are partnerships or tax flow through entities, and as such they generally are not subject to income
tax at the entity level. Several states are evaluating a variety of ways to subject partnerships to entity level taxation. One
prevalent form of such taxation is a tax on gross receipts apportioned to a state. Imposition of such a tax on our

2007 ANNUAL REPORT

33

pipeline systems by any state will reduce the cash available for distribution to us and for other business needs by our
pipeline systems.

We have not requested an IRS ruling with respect to our tax treatment.
We have not requested a ruling from the IRS with respect to any matter affecting us. The IRS may adopt positions that
differ from the positions we take. It may be necessary to resort to administrative or court proceedings in an effort to
sustain some or all of our counsel’s conclusions or the positions we take. Any contest with the IRS may materially and
adversely impact the market for our common units and the price at which the common units trade. In addition, the
costs of any contest with the IRS will be borne directly or indirectly by some or all of the unitholders and the general
partner.

Unitholders may be required to pay taxes on income from us even if they receive no cash distributions.
Unitholders may be required to pay federal income taxes and, in some cases, state and local income taxes on their
allocable share of our income, whether or not they receive cash distributions from us. Unitholders may not receive cash
distributions equal to their allocable share of our taxable income or even the tax liability that results from that income.

Tax gains or losess on the disposition of common units could be different than expected.
If unitholders sell their common units, they will recognize a gain or loss equal to the difference between the amount
realized and their tax basis in those common units. Prior distributions in excess of the total net taxable income that
unitholders were allocated for a common unit which decreased their tax basis in that common unit will, in effect,
become taxable income if the common unit is sold at a price greater than their tax basis in that common unit, even if
the price is less than the original cost. A substantial portion of the amount realized, whether or not representing a gain,
may be ordinary income to unitholders. If the IRS successfully contests some conventions we use, unitholders could
recognize more gain on the sale of common units than would be the case under those conventions without the benefit
of decreased income in prior years.

Investors other than individuals who are U.S. residents may have adverse tax consequences from owning
common units.
An investment in common units by tax-exempt entities, regulated investment companies and foreign persons raises
issues unique to these persons. For example, virtually all of our income allocated to organizations exempt from federal
income tax, including individual retirement accounts and other retirement plans, will be unrelated business taxable
income and will be taxable to them. Net income derived from the ownership of certain publicly traded partnerships is
treated as qualifying income to a regulated investment company. Distributions to foreign persons will be reduced by
withholding taxes. Foreign persons will be required to file federal income tax returns and pay tax on their share of our
taxable income.

We have registered as a ‘‘tax shelter.’’ This may increase the risk of an IRS audit of TC PipeLines or a
unitholder.
We have registered as a ‘‘tax shelter’’ with the Secretary of the Treasury. As a result, we may be audited by the IRS and
tax adjustments could be made. Any unitholder owning less than a one per cent interest in us has a very limited right
to participate in the income tax audit process. Further, any adjustments in our tax returns will lead to adjustments in
unitholders’ tax returns and may lead to audits of their tax returns and adjustments of items unrelated to us.
Unitholders would bear the cost of any expenses incurred in connection with an examination of their personal tax
return.

We treat a purchaser of common units as having the same tax benefits as the seller. A successful IRS
challenge could adversely affect the value of the common units.
Because we cannot match transferors and transferees of common units, we have adopted depreciation and
amortization conventions that do not conform to all aspects of specified Treasury regulations. A successful challenge to
those conventions by the IRS could adversely affect the amount of tax benefits available to unitholders or could affect
the timing of tax benefits or the amount of gain from the sale of common units and could have a negative impact on
the value of the common units or result in audit adjustments to unitholders’ tax returns.

34

TC PIPELINES, LP

We have adopted certain valuation methodologies that may result in a shift of income, gain, loss and
deduction between the general partner and the unitholders. The IRS may challenge this treatment, which
could adversely affect the value of the common units.
For income tax purposes and pursuant to the Partnership Agreement, when we issue additional units or engage in
certain other transactions, we determine the fair market value of our assets and allocate any unrealized gain or loss
attributable to our assets to the capital accounts of our unitholders and our general partner. If our valuation
methodology were not sustained upon an IRS challenge, there may be a shift of income, gain, loss and deduction
between certain unitholders and the general partner, which may be unfavorable to such unitholders. Our valuation
methodology is also used in certain computations and allocations relating to Section 743(b) adjustments and
Section 751 deemed sale tax effects.

A successful IRS challenge to these methods, calculations or allocations could adversely affect the amount of taxable
income or loss being allocated to our unitholders. It also could affect the amount of gain from our unitholders’ sale of
common units and could have a negative impact on the value of the common units or result in audit adjustments to
our unitholders’ tax returns without the benefit of additional deductions.

The sale or exchange of 50 per cent or more of the total interest in our capital and profits will result in the
termination of our partnership for federal income tax purposes.
We will be considered to have terminated for federal income tax purposes if there is a sale or exchange of 50 per cent
or more of the total interests in our capital and profits within a 12-month period. Our termination would, among other
things, result in the closing of our taxable year for all unitholders and could result in a deferral of depreciation
deductions allowable in computing our taxable income.

Unitholders will likely be subject to state and local taxes as a result of an investment in units.
In addition to federal income taxes, unitholders will likely be subject to other taxes, including state and local taxes,
unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in
which we do business or own property. Unitholders may be required to file state and local income tax returns and pay
state and local income taxes in some or all of the jurisdictions in which we do business or own property and may be
subject to penalties for failure to comply with those requirements. It is the unitholders’ responsibility to file all required
United States federal, state and local tax returns. Counsel has not rendered an opinion on the state or local tax
consequences of an investment in us.

Item 1B. Unresolved Staff Comments

None.

Item 2 Properties

Excluding properties held directly by Tuscarora, TC PipeLines does not hold the right, title or interest in any properties.

Properties of Great Lakes Gas Transmission Limited Partnership, Northern Border Pipeline Company and
Tuscarora Gas Transmission Company

See Item 1. ‘‘Business ‘‘for a description of our pipeline systems’ properties, their utilization, and how each property is
held.

2007 ANNUAL REPORT

35

Item 3.

Legal Proceedings

Our pipeline systems are parties to various legal actions arising in the normal course of business. Management believes
the disposition of all known outstanding legal actions will not have a material adverse impact on the Partnership’s
financial condition, results of operations or cash flows.

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, 2007.

PART II

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity

Securities

The common units representing limited partner interests in the Partnership were issued pursuant to an initial public
offering on May 28, 1999 and a private placement on February 22, 2007. The common units are quoted on the
NASDAQ Global Select Market and trade under the symbol ‘‘TCLP.’’

On February 22, 2007, the Partnership completed a private placement of 17,356,086 common units at $34.57 per
common unit for gross proceeds of $600.0 million. Net of issuing costs, the proceeds from the private placement were
$594.4 million, which were used to fund a portion of the cash consideration for the Partnership’s acquisition of a
46.45 per cent general partner interest in Great Lakes that closed concurrently with the private placement. TransCanada
Northern purchased 8,678,045 of the 17,356,086 common units issued for gross proceeds of $300.0 million. In
addition, TC PipeLines GP maintained its two per cent general partner interest in the Partnership by contributing
$12.6 million to the Partnership in connection with the private placement.

The following table sets forth, for the periods indicated, the high and low sale prices per common unit, as reported by
the NASDAQ Global Select 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.

2007
First Quarter
Second Quarter
Third Quarter
Fourth Quarter

2006
First Quarter
Second Quarter
Third Quarter
Fourth Quarter

Price Range

High

Low

Cash Distributions
Declared per
Common Unit

$37.54
$42.83
$40.69
$37.35

$35.14
$34.65
$33.50
$36.00

$35.29
$36.34
$32.98
$35.50

$32.60
$31.54
$30.41
$30.00

$0.600
$0.650
$0.655
$0.660

$0.575
$0.575
$0.575
$0.600

As of February 28, 2008, there were 96 registered holders of common units and approximately 13,800 beneficial
owners of common units, including common units held in street name.

36

TC PIPELINES, LP

The Partnership currently has 34,856,086 common units outstanding, of which 24,142,935 are held by the public,
8,678,045 are held by TransCan Northern, and 2,035,106 are held by TC PipeLines GP. The common units represent an
aggregate 98 per cent limited partner interest and the general partner interest represents an aggregate two per cent
general partner interest in the Partnership.

The general partner receives two per cent of all cash distributions in regards to its general partner interest and is also
entitled to incentive distributions as described below. The holders of common units (collectively referred to as
unitholders) receive the remaining portion of the cash distribution. The Partnership’s quarterly cash distributions to its
unitholders comprise 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.

The general partner receives incentive distributions if the amount distributed with respect to any quarter exceeds the
minimum quarterly distribution of $0.45 per common unit. Under the incentive distribution provisions, the general
partner receives 15 per cent of amounts distributed in excess of $0.45 per common unit, 25 per cent of amounts
distributed in excess of $0.5275 per common unit, and 50 per cent of amounts distributed in excess of $0.69 per
common 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 2007, the Partnership made cash distributions to unitholders and the general partner that amounted to $86.7 million
compared to $43.5 million in 2006. These payments represented $0.60 per common unit for the quarter ended
December 31, 2006, $0.65 per common unit for the quarter ended March 31, 2007, $0.655 for the quarter ended
June 30, 2007 and $0.66 per common unit for the quarter ended September 30, 2007. On February 14, 2008, the
Partnership paid a cash distribution of $25.6 million to unitholders and the general partner, representing a cash
distribution of $0.665 per common unit for the quarter ended December 31, 2007. The distribution was allocated in
the following manner: $23.2 million to the holders of common units as of the close of business on January 31, 2008
(including $1.4 million to the general partner as holder of 2,035,106 common units and $5.8 million to TransCan
Northern as holder of 8,678,045 common units), $1.9 million to the general partner as holder of incentive distribution
rights, and $0.5 million to the general partner in respect of its two per cent general partner interest.

2007 ANNUAL REPORT

37

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.’’

(millions of dollars, except per unit amounts)

2007(1)

2006(2)

2005

2004

2003

Year Ended December 31

Income Data
Equity income from investment in Great

Lakes

Equity income from investment in Northern

Border

Equity income from investment in Tuscarora
Transmission revenues
Financial charges, net and other
Net income
Basic and diluted net income per unit

Cash Flow Data
Cash distribution paid per unit

Balance Sheet Data (at December 31)
Total assets
Long-term debt (including current maturities)
Partners’ equity

49.0

61.2
–
27.2
(33.8)
89.0
$2.51

–

–

–

–

56.6
5.9
0.9
(15.8)
44.7
$2.39

45.7
7.5
–
(1.0)
50.2
$2.70

50.0
7.5
–
(0.5)
55.1
$2.99

44.5
5.3
–
(0.1)
48.0
$2.63

$2.565

$2.325

$2.300

$2.275

$2.175

1,492.6
573.4
900.1

777.8
468.1
303.9

315.7
13.5
301.6

332.1
36.5
294.9

288.1
5.5
282.0

(1) TC PipeLines acquired a 46.45 per cent interest in Great Lakes on February 22, 2007. The equity method is used to account for the

Partnership’s investment in Great Lakes.

(2) TC PipeLines accounted for its investment in Tuscarora using the equity method until December 19, 2006 and began consolidating

Tuscarora’s operations upon acquisition of the additional 49 per cent general partner interest.

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

The following discusses the results of operations and liquidity and capital resources of TC PipeLines, along with those of
Great Lakes, Northern Border and Tuscarora (together ‘‘our pipeline systems’’) as a result of the Partnership’s ownership
interests.

The following discussions of the financial condition and results of operations of the Partnership and its pipeline systems
should be read in conjunction with the financial statements and notes thereto of the Partnership, Great Lakes and
Northern Border 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, Great Lakes and Northern Border. All amounts are stated in U.S. dollars.

PARTNERSHIP OVERVIEW

TC PipeLines was formed in 1998 as a Delaware limited partnership. TC PipeLines was formed by TransCanada PipeLines
Limited, a wholly-owned subsidiary of TransCanada Corporation (collectively referred to herein as TransCanada), to
acquire, own and participate in the management of energy infrastructure assets in North America. Our strategic focus is
on delivering stable, sustainable cash distributions to our unitholders and finding opportunities to increase cash
distributions while maintaining a low risk profile.

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TC PIPELINES, LP

TC PipeLines, LP and its subsidiaries are collectively referred to herein as ‘‘TC PipeLines’’ or ‘‘the Partnership.’’ In this
report, references to ‘‘we’’, ‘‘us’’ or ‘‘our’’ collectively refer to TC PipeLines or the Partnership. The general partner of the
Partnership is TC PipeLines GP, Inc., a wholly-owned subsidiary of TransCanada.

We own a 46.45 per cent general partner interest in Great Lakes, which we acquired on February 22, 2007 from El
Paso Corporation. The remaining 53.55 per cent general partner interest in Great Lakes is held by TransCanada.

We own a 50 per cent general partner interest in Northern Border, including a 20 per cent interest acquired on April 6,
2006. The remaining 50 per cent general partner interest in Northern Border is held by ONEOK Partners, a publicly
traded limited partnership that is controlled by ONEOK, Inc.

We also own 100 per cent of Tuscarora. The Partnership acquired a 49 per cent interest from a wholly-owned subsidiary
of TransCanada in September 2000. An additional 49 per cent was acquired from Tuscarora Gas Pipeline Co., a wholly-
owned subsidiary of Sierra Pacific Resources, on December 19, 2006. On December 31, 2007, the Partnership acquired
the remaining two per cent general partner interest in Tuscarora, with one per cent purchased from a wholly-owned
subsidiary of TransCanada and the other one per cent purchased from Tuscarora Gas Pipeline Co.

The Partnership’s general partner interests in Great Lakes, Northern Border and Tuscarora represent its only material
assets at December 31, 2007. As a result, the Partnership is dependent upon Great Lakes, Northern Border and
Tuscarora for all of its available cash.

Great Lakes Overview

Great Lakes is a Delaware limited partnership formed in 1990. Great Lakes’ operating revenue is derived from
transportation of natural gas. Great Lakes was originally constructed as an operational loop of the TransCanada
Mainline Northern Ontario system. Great Lakes receives natural gas from TransCanada at the Canadian border near
Emerson, Manitoba and extends across Minnesota, Northern Wisconsin and Michigan, and redelivers gas to
TransCanada at the Canadian border at Sault Ste. Marie, Michigan and St. Clair, Michigan.

Northern Border Overview

Northern Border is a Texas general partnership formed in 1978. Northern Border’s operating revenue is derived from
transportation of natural gas. Northern Border transports natural gas from the Montana-Saskatchewan border near Port
of Morgan, Montana to a terminus near North Hayden, Indiana. Additionally, Northern Border transports natural gas
produced in the Williston Basin of Montana and North Dakota and the Powder River Basin of Wyoming and Montana
and synthetic gas produced at the Dakota Gasification plant in North Dakota.

Tuscarora Overview

Tuscarora is a Nevada general partnership formed in 1993. Tuscarora’s operating revenue is derived from transportation
of natural gas. Tuscarora’s U.S. interstate pipeline system originates at an interconnection point with existing facilities of
Gas Transmission Northwest Corporation (GTN), a wholly-owned subsidiary of TransCanada, near Malin, Oregon and
runs Southeast through Northeastern California and Northwestern Nevada. The Tuscarora pipeline system terminates
near Wadsworth, Nevada. Along its route, deliveries are made in Oregon, Northern California and Northwestern
Nevada. Deliveries are also made directly to the local gas distribution system of Sierra Pacific Power Company (Sierra
Pacific Power), a subsidiary of Sierra Pacific Resources.

2007 ANNUAL REPORT

39

FACTORS THAT IMPACT OUR BUSINESS

Key factors that impact our business are the ability of Great Lakes and Northern Border to make distributions to us and
of Tuscarora to generate positive operating cash flows and our ability to maintain a strong and balanced financial
position. Partnership cash flows from our investments are necessary to generate sufficient cash to make distributions to
our unitholders. A strong and balanced financial position will ensure that we are able to maintain a prudent level of
available cash to make distributions to our unitholders.

FACTORS THAT IMPACT THE BUSINESS OF OUR PIPELINE SYSTEMS

Key factors that impact the business of our pipeline systems are the supply of and demand for natural gas in the
markets in which our pipeline systems operate; the customers of our pipeline systems and the mix of services they
require; competition; and government regulation of natural gas pipelines. These factors are discussed in more detail
below.

Supply and Demand of Natural Gas

Our pipeline systems depend upon the continued availability of natural gas production and reserves in the regions we
access, primarily the WCSB. Our pipeline systems provide their customers with natural gas transportation services to
market demand areas. The amount of WCSB natural gas available for export is dependent upon natural gas production
levels, demand for natural gas in Canada, and storage capacity for Canadian natural gas and demand for storage
injection. Additional Canadian natural gas supply sources may be available in the future if new pipeline projects
associated with the Mackenzie Delta in Northern Canada and the North Slope of Alaska are constructed.

Demand for natural gas transportation service on our pipeline systems is directly related to demand for natural gas in
the markets served by these systems. Factors which may impact the overall demand for natural gas include weather
conditions, economic conditions, government regulation, availability and price of alternative energy sources, fuel
conservation measures, and technological advances in fuel economy and energy generation devices. Additionally, factors
that may impact demand for transportation service on any one system include the ability and willingness of natural gas
shippers to utilize one system over alternative pipelines, transportation rates, and the volume of natural gas delivered to
markets from other supply sources and storage facilities.

Our pipeline systems depend upon the WCSB for the majority of the natural gas that they transport. There has been a
decline in the flows out of WCSB over the last year. However, as discussed above, the impact of this decline on any
given pipeline is dependent upon market conditions in the markets those pipelines serve. The decline in WCSB gas
available for export did not negatively impact throughput on our pipeline systems in 2007. We cannot predict the
impact of any export declines on 2008 throughput which will depend on WCSB natural gas available for export in the
future and market conditions in the markets our pipeline systems serve.

The 2006-2007 winter was unusually warm in the markets served by Great Lakes. The low winter demand drove gas
prices in the WCSB down and made it attractive to source gas in the supply area and move it to market instead of
drawing storage gas. This increased utilization on the Great Lakes pipeline system. It also left Midwest storage levels at
record highs, but in the post-Katrina environment when markets were disrupted by the hurricane, Great Lakes had sold
its 2007 summer (and some winter 2006-2007) capacity on a firm basis so revenues were not adversely affected by
lower than normal storage injection. Finally, with storage inventories at or near maximum, system demand was
maintained late in the year by aggressively discounting to move available supply to markets.

Increased drilling and production activity in the Powder River Basin of Wyoming and Montana and the Williston Basin of
Montana and North Dakota may present opportunities for Northern Border to pursue additional connections with this
supply area. Future opportunities for potential additional supply include the construction of proposed coal gasification

40

TC PIPELINES, LP

plants. A proposed coal gasification plant in North Dakota by Great Northern Power Development LP and Allied Syngas
Corporation may also be a potential future supply source for Northern Border.

The GTN system is one of the U.S. transporters of Canadian natural gas from the WCSB, effectively the sole source of
gas on Tuscarora. Tuscarora serves a number of markets along its route through Southern Oregon, Northern California
and Northern Nevada. However, Tuscarora’s largest customers are in the Reno-Sparks area of Washoe County, Storey
County and downstream of the Paiute system, where gas consumption related to industrial use, population growth and
increased gas-fired power generation has grown significantly and is expected to continue.

Customers

Our pipeline systems transport natural gas for a variety of customers including other natural gas pipelines, natural gas
distribution companies, electric generation companies, natural gas producers, and natural gas marketing and trading
companies. Each type of customer has a different reason for using certain natural gas transportation services and
routes. Natural gas distribution companies and electric generation companies typically require a secure and reliable
supply of natural gas over a sustained period of time to meet the needs of their customers. These types of customers
typically enter into long-term firm transportation contracts to ensure a ready supply of natural gas and sufficient
transportation capacity over the life of their contracts. Natural gas producers typically enter into firm transportation
contracts to ensure that they will have sufficient capacity to deliver their product to market centers. Natural gas
marketing and trading companies typically use transportation services to capitalize on natural gas price volatility.

Competition

Our pipeline systems compete primarily with other interstate and intrastate pipelines in the transportation of natural
gas. Additionally, supply competition from other natural gas sources can impact demand for transportation on our
pipeline systems. Growth in supplies available from other natural gas producing regions can impact prices for natural
gas delivered to some of the markets our pipeline systems serve relative to other market regions. An increase in the
number of new pipeline projects in the U.S. has led to rising costs, both labor and materials, associated with new
pipeline projects. These rising costs may impact our pipeline systems’ ability to pursue expansion projects.

Great Lakes competes directly with Northern Border, Alliance/Vector, Viking and the TransCanada Mainline. In addition,
supply competition from other natural gas sources can impact demand for transportation on Great Lakes. Great Lakes
anticipates that further growth in supplies from the Rocky Mountain region will create additional supply in the markets
Great Lakes serves. Anticipated additional supplies from the Eastern segment of the Rockies Express Pipeline, discussed
below, may provide opportunities for Great Lakes to market its Eastern zone capacity for storage injection and
withdrawal, which has historically gone underutilized.

Northern Border serves natural gas markets in the Midwestern U.S. through major interconnects with other interstate
natural gas pipelines. Northern Border also delivers natural gas directly to LDCs in Iowa, Illinois and Indiana. Two of
Northern Border’s major interconnections are with Northern Natural Gas at Ventura, Iowa and Natural Gas Pipeline at
Harper, Iowa. Northern Border provides its customers with access to the Chicago market area, which is the third largest
market area hub in North America. Supply competition from other natural gas sources in these markets can adversely
impact demand for transportation on Northern Border’s system. Northern Border has seen growth in supplies from the
Rocky Mountain region creating additional supply in the markets Northern Border serves, including Ventura, Harper and
Chicago. Additional supply competition deliveries from other supply sources may impact Northern Border’s ability to
contract available capacity at Ventura and Harper beginning in April 2008 when approximately 37 per cent of its design
capacity becomes uncontracted. Additional supply in the Chicago market may impact Northern Border’s ability to
contract available capacity in 2009 as long-term transportation contracts expire.

2007 ANNUAL REPORT

41

The Western segment of the Rockies Express Pipeline is increasing supply competition in Midwestern markets and could
cause Northern Border to discount their rates or otherwise experience a reduction in their revenues. The Eastern
segment of the Rockies Express Pipeline, from Missouri to Ohio, is expected to be placed in service by June 2009
(pending regulatory approvals), and is anticipated to transport natural gas further east, potentially mitigating excess
supply in Northern Border’s market region.

There are several other pipeline projects that have been announced, mostly moving gas from the U.S. Rocky Mountain
Region to various regions of the U.S. Should any of these projects be built, they will have an impact on the U.S. natural
gas markets, including the markets served by Northern Border and Great Lakes.

Tuscarora maintains a very strong competitive position relative to other sources of gas in the markets it serves. Tuscarora
is one of only two pipelines that serves the Northern Nevada market, the other being Paiute Pipeline. Tuscarora can
economically expand to meet the future gas transportation needs of the region by adding additional compression,
which offers the greatest volume and pressure flexibility. Tuscarora also has access to supply regions as its upstream
pipelines have excess capacity.

Government Regulation

Natural gas transportation is regulated by the FERC and other federal and state regulatory agencies, including the
Department of Transportation. FERC regulatory policies govern the rates that pipelines are permitted to charge
customers for interstate transportation of natural gas. The operation and maintenance of our pipeline systems are also
impacted by the federal and state regulatory agencies.

The FERC-approved rate designs used by our pipeline systems are based upon firm service and interruptible services.
Customers with firm service transportation agreements pay a fee known as a reservation charge to reserve pipeline
capacity, regardless of use, for the term of their contracts. Firm service transportation customers may also pay a variable
fee that is based on the distance and volume of natural gas they transport. Customers with interruptible service
transportation agreements may utilize available capacity on a pipeline system after firm service transportation requests
are satisfied. Interruptible service customers are assessed a variable fee based on distance and the volume of natural gas
they transport. The majority of our pipeline systems’ revenue is generated by firm service transportation agreements.

HOW WE EVALUATE OUR OPERATIONS

We evaluate our business primarily on the basis of the underlying operating results for each of our pipeline systems,
along with a measure of Partnership cash flows. Partnership cash flows, a non-generally accepted accounting principle
(GAAP) financial measure, is the sum of cash distributions received from Northern Border and Great Lakes, and cash
flows from Tuscarora’s operating activities less Partnership costs.

RESULTS OF OPERATIONS OF TC PIPELINES, LP

The general partner interests in Great Lakes, Northern Border and Tuscarora were our only material sources of income in
2007; therefore, our results of operations were influenced by and reflect the same factors that influenced the financial
results of Great Lakes, Northern Border and Tuscarora. See Item 1. ‘‘Business’’.

Critical Accounting Policies and Estimates

The preparation of financial statements in accordance with U.S. GAAP requires us to make estimates and assumptions,
with respect to values or conditions which cannot be known with certainty, that affect the reported amount of assets
and liabilities and the disclosure of contingent assets and liabilities at the date of the financial statements. Such

42

TC PIPELINES, LP

estimates and assumptions also affect the reported amounts of revenue and expenses during the reporting period.
Although we believe these estimates and assumptions are reasonable, actual results could differ from our estimates. The
following summarizes the Partnership’s and our pipeline systems’ accounting policies and estimates, which should be
read in conjunction with Note 2 of the Partnership’s Financial Statements included elsewhere in this report.

We account for our investments in Great Lakes and Northern Border using the equity method of accounting. 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. We are able to exercise significant influence
over our investments in Great Lakes and Northern Border because of our ownership interests and our representation on
the Great Lakes and Northern Border management committees.

We used the equity method to account for our investment in Tuscarora until December 19, 2006. On this date, we
acquired an additional 49 per cent general partner interest in Tuscarora and, as a result of acquiring a controlling
interest in Tuscarora, began to consolidate its operations. The consolidation method of accounting is appropriate where
the investor controls the investee.

Regulatory Assets
Our pipeline systems’ accounting policies conform to Statement of Financial Accounting Standards (SFAS) No. 71,
Accounting for the Effects of Certain Types of Regulation. Our pipeline systems consider several factors to evaluate their
continued application of the provisions of SFAS No. 71 such as potential deregulation of their pipelines; anticipated
changes from cost-based ratemaking to another form of regulation; increasing competition that limits their ability to
recover costs; and regulatory actions that limit rate relief to a level insufficient to recover costs.

Certain assets that result from the ratemaking process are reflected on Northern Border’s balance sheet as regulatory
assets. If Northern Border determines future recovery of these assets is no longer probable as a result of discontinuing
application of SFAS No. 71 or other regulatory actions, Northern Border would be required to write off the regulatory
assets at that time. As of December 31, 2007, Northern Border reflected regulatory assets of $20.6 million on its
balance sheet. These assets are being amortized as directed by the FERC in Northern Border’s previous regulatory
proceedings over varying time periods up to 43 years.

As at December 31, 2007, Great Lakes and Tuscarora did not have any regulatory assets or liabilities recorded on their
respective balance sheets.

Contingencies
Our pipeline systems’ accounting for contingencies covers a variety of business activities, including contingencies for
legal and environmental liabilities. Our pipeline systems accrue for these contingencies when their assessments indicate
that it is probable that a liability has been incurred or an asset will not be recovered and an amount can be reasonably
estimated in accordance with SFAS No. 5, ‘‘Accounting for Contingencies.’’ Our pipeline systems base their estimates on
currently available facts and their estimates of the ultimate outcome or resolution. Actual results may differ from our
pipeline systems’ estimates resulting in an impact, positive or negative, on earnings.

Impairment of Long-Lived Assets and Goodwill
We assess our long-lived assets for impairment based on SFAS No. 144, Accounting for the Impairment or Disposal of
Long-Lived Assets. A long-lived asset is tested for impairment whenever events or changes in circumstances indicate
that its carrying amount may exceed its fair value. Fair values are based on the sum of the undiscounted future cash
flows expected to result from the use and eventual disposition of the assets.

We assess our goodwill for impairment at least annually, based on SFAS No. 142, Goodwill and Other Intangible Assets.
An initial assessment is made by comparing the fair value of the operations with goodwill, as determined in accordance
with SFAS No. 142, to the book value of each reporting unit. If the fair value is less than the book value, an
impairment is indicated, and we must perform a second test to measure the amount of the impairment. In the second
test, we calculate the implied fair value of the goodwill by deducting the fair value of all tangible and intangible net
assets of the operations with goodwill from the fair value determined in step one of the assessment. If the carrying

2007 ANNUAL REPORT

43

value of the goodwill exceeds this calculated implied fair value of the goodwill, we will record an impairment charge. At
December 31, 2007, we had $81.7 million of goodwill recorded on our balance sheet related to the Tuscarora
acquisitions.

Impact of New Accounting Standards

In 2006, the Financial Accounting Standards Board issued SFAS No. 157, Fair Value Measurements, and during 2007,
issued SFAS No. 141(R), Business Combinations – revised, SFAS No. 159, The Fair Value Option for Financial Assets and
Financial Liabilities – including an amendment of FASB Statement No. 115, and SFAS No. 160, Noncontrolling Interests
in Consolidated financial Statements.

SFAS No. 157 establishes a framework for measuring fair value and requires additional disclosures about fair value
measurements. The effect of adopting SFAS No. 157 is not expected to be material to our results of operations or
financial position.

SFAS No. 141(R) replaces SFAS No. 141, Business Combinations. SFAS No. 141 (R) retains the fundamental requirements
of SFAS No. 141 that the acquisition method of accounting be used for all business combinations and for an acquirer
to be identified for each business combination, with the objective of improving the relevance and comparability of the
information that a reporting entity provides in its financial reports about a business combination and its effects. The
requirements of this standard will not have a material impact on the results of the Partnership.

SFAS No. 159 permits entities to choose to measure selected financial assets and financial liabilities at fair value. The fair
value option established by SFAS No. 159 permits all entities to choose to measure eligible items at fair value at
specified election dates. The effect of adopting SFAS No. 159 is not expected to be material to our results of operations
or financial position.

SFAS No. 160 clarifies the classification of noncontrolling interests in consolidated statements of financial position and
the accounting for and reporting of transactions between the reporting entity and holders of such noncontrolling
interests. The Partnership does not have noncontrolling interests and therefore, is not affected by the changes resulting
from this standard.

In June 2007 the Emerging Issues Task Force of the FASB issued EITF 07-4, ‘‘Application of the Two-Class Method under
FASB Statement No. 128, Earnings per Share, to Master Limited Partnerships’’. EITF 07-4 addresses how current period
earnings of a Master Limited Partnership (MLP) should be allocated to the general partner, limited partners and when
applicable, incentive distribution rights when applying the two-class method under Statement 128. A tentative
conclusion was ratified by the FASB in December 2007. We are currently reviewing the applicability of EIFT 07-4 to our
results of operations and financial position.

YEAR IN REVIEW

TC PipeLines

Acquisition of Interest in Great Lakes
On February 22, 2007, the Partnership acquired a 46.45 per cent general partner interest in Great Lakes from El Paso
Corporation (El Paso). TransCanada, which previously held a 50 per cent interest in Great Lakes, acquired the other
3.55 per cent general partner interest simultaneously with the Partnership’s acquisition of its interest. In connection with
these transactions, a wholly-owned subsidiary of TransCanada became the operator of Great Lakes.

Equity Issuance
On February 22, 2007, the Partnership completed a private placement of 17,356,086 common units at $34.57 per
common unit for gross proceeds of $600.0 million which closed concurrently with the Great Lakes acquisition. TransCan

44

TC PIPELINES, LP

Northern purchased 8,678,045 of the 17,356,086 common units issued for gross proceeds of $300.0 million. In
addition, TC PipeLines GP maintained its two per cent general partner interest in the Partnership by contributing
$12.6 million to the Partnership in connection with the private placement.

Acquisition of Remaining Interest in Tuscarora
On December 31, 2007, TC PipeLines acquired the remaining two per cent general partner interest in Tuscarora, with
one per cent purchased from a wholly-owned subsidiary of TransCanada and the other one per cent purchased from
Tuscarora Gas Pipeline Co. TC PipeLines now owns 100 per cent of Tuscarora.

Great Lakes

Operating Revenues
For the period of March 1, 2007 to December 31, 2007, Great Lakes’ average contracted capacity was 104 per cent. As
of January 31, 2008, the weighted average remaining life of Great Lakes’ contracts was 2.4 years.

Operating Data

MMcf delivered
MMcf/d average throughput

For the period February 23
to December 31, 2007

693,017
2,221

Regulatory Deferred Income Taxes
Income taxes are the responsibility of the partners and are not reflected in Great Lakes’ financial statements prepared in
accordance with GAAP. On the balance sheet prepared for regulatory accounting purposes, partners’ capital is reduced
by the amount equivalent to accumulated deferred income taxes.

The sale of El Paso’s partnership interest, and a corresponding Internal Revenue Code Section 754 election, resulted in
Great Lakes’ pre-acquisition amounts equivalent to net deferred income tax liability balances being reduced by
46.45 per cent. In addition, Great Lakes’ amounts equivalent to net deferred tax liabilities for pre-acquisition retirement
plans were eliminated. Great Lakes’ regulated partners’ capital and amounts equivalent to net deferred tax liabilities
were adjusted on February 22, 2007, by approximately $135 million as approved by the FERC.

Michigan Business Tax
In the third quarter of 2007, the state of Michigan enacted the Michigan Business Tax (MBT), which replaced the
Michigan Single Business Tax (SBT), effective January 1, 2008. The MBT is an income tax levied at the partnership level.
The MBT is expected to result in an annual income tax expense of approximately $4 to $5 million and to provide a
property tax credit of approximately $1 million, for a net annual impact of $3 to $4 million to Great Lakes beginning in
2008. In September 2007, Great Lakes eliminated its deferred SBT amounts consistent with the elimination of the SBT
tax. This resulted in an increase of $1.6 million to Great Lakes’ net income.

Northern Border

Operating Revenues
Long-term rates were reduced and short-term seasonal rates were implemented effective January 1, 2007 as a result of
Northern Border’s rate case settlement, discussed later in this section. 2007 revenues were comparable to 2006 primarily
due to the implementation of seasonal rates and a favorable contracting experience for 2007. Northern Border’s
average throughput and contracted capacity remained consistent from 2007 to 2006 as shown in the table below. The
trend toward shorter term contracts and discounted transportation rates continued on Northern Border’s system. The

2007 ANNUAL REPORT

45

weighted average life of Northern Border’s contracts declined from 1.8 years at December 31, 2006 to 1.3 years at
January 31, 2008.

Operating Data

MMcf delivered
MMcf/d average throughput
Average contracted capacity

2007

799,637
2,247
97%

2006

799,301
2,246
97%

Settlement of Rate Case
The settlement of Northern Border’s 2005 rate case was approved by the FERC in November 2006. The settlement
established maximum long-term mileage-based rates and charges for transportation on Northern Border’s system.
Beginning January 1, 2007, overall rates were reduced, compared with rates prior to the filing, by approximately five
per cent. For the full transportation route from Port of Morgan, Montana to the Chicago area, the previous charge of
approximately $0.46 per Dth is now approximately $0.44 per Dth, which is comprised of a reservation rate, commodity
rate and a compressor usage surcharge rate. The factors used in calculating depreciation expense for transmission plant
were increased from 2.25 per cent to 2.40 per cent. The settlement also provided for seasonal rates for short-term
transportation services. Seasonal maximum rates vary on a monthly basis from approximately $0.54 per Dth to
approximately $0.29 per Dth for the full transportation route from Port of Morgan, Montana to the Chicago area.

Change in Operator
TransCanada Northern Border Inc. (TCNB), a wholly-owned subsidiary of TransCanada, became Northern Border’s
operator effective April 1, 2007 under a new operating agreement.

Tuscarora

Operating Revenues
Long-term rates were reduced effective June 1, 2006 as a result of Tuscarora’s rate settlement, discussed later in this
section. 2007 revenues were lower when compared to 2006 primarily due to the reduction of rates effective June 1,
2006. Tuscarora’s average throughput and contracted capacity remained consistent from 2007 to 2006 as shown in the
table below. The weighted average remaining life of Tuscarora’s contracts declined from 11.4 years at December 31,
2006 to 10.4 years at December 31, 2007.

Operating Data

MMcf delivered
MMcf/d average throughput
Average contracted capacity

2007

28,257
77
96%

2006

28,067
77
96%

Cost and Revenue Study
On August 7, 2006, the FERC approved a settlement reached by Tuscarora, the PUCN and Sierra Pacific Power that
resulted in a firm transportation rate of $0.40/decatherm per day (dth-day) effective June 1, 2006. This was a 17 per
cent reduction to the previous rate of $0.4811/dth-day, or an approximate $5 million reduction in Tuscarora’s annual
revenues. In addition, the settlement resulted in a moratorium on all rate actions before the FERC by any party to the
settlement for a period of 48 months to May 31, 2010, including rate actions related to expansion projects where
Tuscarora proposes to price the expansion at the settlement rate.

2008 Expansion Project
Tuscarora filed an application with the FERC on November 20, 2006 for approval to construct the compressor station
and related facilities (Tuscarora 2008 Expansion Project). This project is to transport a maximum of 39 MMcf/d to Sierra
Pacific Power to supply its Tracy combined cycle power plant. The project is expected to cost approximately $20 million

46

TC PIPELINES, LP

which will be recovered from rates charged to Sierra Pacific Power under the Transportation Service Agreement (TSA)
signed with Sierra Pacific Power. The TSA is for a period of 22.5 years from the commencement date.

The FERC issued a Certificate of Public Convenience and Necessity for Tuscarora’s 2008 Expansion Project on July 24,
2007 in response to Tuscarora’s November 2006 application for approval to construct the compressor station and
related facilities. The expansion is currently expected to go into service in March of 2008.

Net Income

To supplement our financial statements we have presented a comparison of the earnings contribution components from
each of our investments. We have presented net income in this format in order to enhance investors’ understanding of
the way management analyzes the Partnership’s financial performance. We believe this summary provides a more
meaningful comparison of the Partnership’s net income to prior years, as we account for our partially owned pipeline
systems using the equity method. The presentation of this additional information is not meant to be considered in
isolation or as a substitute for results prepared in accordance with GAAP.

The shaded areas in the tables below disclose the results from Great Lakes, Northern Border and Tuscarora, representing
100 per cent of each entity’s operations for the given period.

2007 

(millions of dollars)

Partnership

Tuscarora(1)

Great Lakes(2)
Corporate Feb 23 - Dec 31

Northern
Border(3)

Transmission revenues
Operating expenses

Depreciation
Financial charges, net and

other

Equity income

Net income

27.2
(8.3)

18.9
(6.3)

(33.8)

110.2

89.0

27.2
(4.9)

22.3
(6.3)

(4.4)

–

11.6

–
(3.4)

(3.4)
–

(29.4)

–

(32.8)

236.2
(53.7)

182.5
(49.4)

(27.6)

105.5

49.0

49.0

309.4
(83.5)

225.9
(60.7)

(41.1)

124.1

61.2

61.2

(1) TC PipeLines owns a 100 per cent general partner interest in Tuscarora following the acqusition of an additional two per cent interest on

December 31, 2007.

(2) TC PipeLines acquired a 46.45 per cent general partner interest in Great Lakes on February 22, 2007.

(3) TC PipeLines owns a 50 per cent general partner interest in Northern Border. Equity income from Northern Border includes amortization
of a $10 million transaction fee paid to the operator of Northern Border at the time of the additional 20 per cent acquisition in April
2006.

2007 ANNUAL REPORT

47

2006 

(millions of dollars)

Partnership

Tuscarora(4)
Dec 20 - Dec 31

Corporate

Tuscarora(4)
Jan 1 - Dec 19

Northern
Border(5)

Transmission revenues
Operating expenses

Depreciation
Financial charges, net

and other

Equity income

Net income

0.9
(2.7)

(1.8)
(0.2)

(15.8)

62.5

44.7

0.9
(0.1)

0.8
(0.2)

(0.2)

–

0.4

–
(2.6)

(2.6)
–

(15.6)

–

(18.2)

28.6
(4.6)

24.0
(6.0)

(5.1)

12.9

5.9

5.9

310.9
(81.0)

229.9
(58.7)

(41.3)

129.9

56.6

56.6

(4) With the acquisition of an additional 49 per cent general partner interest in Tuscarora on December 19, 2006, TC PipeLines changed its

method of accounting for this investment from equity accounting to consolidation.

(5) Equity income from TC PipeLines’ investment in Northern Border was based upon its 30 per cent ownership to April 5, 2006 and 50 per
cent ownership following the acquisition of an additional 20 per cent general partner interest on April 6, 2006. Equity income from
Northern Border includes amortization of a $10 million transaction fee paid to the operator of Northern Border at the time of the
acquisition.

2005 

(millions of dollars)

Transmission revenues
Operating expenses

Depreciation
Financial charges, net and other

Equity income

Net income

Partnership

Corporate

Tuscarora(6)

–
(2.0)

(2.0)
–
(1.0)

53.2

50.2

–
(2.0)

(2.0)
–
(1.0)

–

(3.0)

32.3
(4.4)

27.9
(6.2)
(5.6)

16.1

7.5

7.5

Northern
Border(7)

321.7
(70.8)

250.9
(58.1)
(40.5)

152.3

45.7

45.7

(6) TC PipeLines owned a 49 per cent general partner interest in Tuscarora. Equity income from Tuscarora includes an acquisition allocation

amortization related to the initial purchase of the Partnership’s general partner interest in Tuscarora.

(7) TC PipeLines owned a 30 per cent general partner interest in Northern Border.

Year Ended December 31, 2007 Compared with the Year Ended December 31, 2006
Net income increased $44.3 million, or 99 per cent, to $89.0 million in 2007, compared to $44.7 million in 2006. This
increase was due primarily to acquisition activities in 2007 and 2006. Equity income in 2007 included $49.0 million
from our investment in Great Lakes, which we acquired on February 22, 2007. The Partnership’s earnings increased
$4.6 million in 2007 as a result of its ownership interest in Northern Border. Of this increase, $7.1 million is due to the
additional 20 per cent general partner interest in Northern Border acquired on April 6, 2006, offset by a $2.5 million
decrease due to a reduction in Northern Border’s net income. The Partnership’s earnings increased $5.1 million in 2007
as a result of its ownership interest in Tuscarora. Tuscarora contributed $11.4 million to the Partnership’s earnings in
2007, including a $0.2 million non-controlling interest recorded by the Partnership. The Partnership’s earnings increased
by $6.0 million due to the additional 49 per cent general partner interest in Tuscarora acquired on December 19, 2006,
offset by a $0.9 million decrease due to a reduction in Tuscarora’s net income. The increase in the Partnership’s earnings
as a result of acquisitions is partially offset by a $13.8 million increase in the Partnership’s financing costs.

48

TC PIPELINES, LP

Great Lakes’ net income for the period from acquisition to December 31, 2007 was $105.5 million, in line with our
expectations. The Partnership completed the acquisition of Great Lakes on February 22, 2007 and included 46.45 per
cent of its earnings from this date. Great Lakes’ revenues are primarily derived from its interstate natural gas
transmission service. In 2007, approximately 91 per cent of Great Lakes’ transportation revenues was derived from
long-term firm service contracts.

Northern Border’s net income decreased $5.8 million, or four per cent, to $124.1 million in 2007 compared to
$129.9 million in 2006. Slight increases in depreciation and operating expenses, along with a small reduction in
transmission revenues contributed to the decrease in net income. Depreciation expense increased by $2.0 million over
the prior year primarily due to the change in depreciation rates effective January 1, 2007 as a result of the 2005 rate
case settlement. Operating expenses increased $2.5 million over the prior year primarily due to a $2.3 million transition
related charge in 2007 related to the reimbursement for shared equipment and furnishings acquired by ONEOK Partners
and previously used to support Northern Border’s operations. Increases in electric compression charges due to increased
usage and electric rates were mostly offset by decreased taxes other than income. Excluding the positive impact of the
higher ownership interest, the $5.8 million decrease in Northern Border’s net income resulted in a $2.5 million decrease
to the Partnership’s net income.

Tuscarora’s net income decreased $1.7 million, or 13 per cent, to $11.6 million in 2007. This decrease was mainly due
to a full year impact of the settlement transportation rates that went into effect on June 1, 2006. The decrease in
Tuscarora’s net income contributed to a $0.9 million decrease to the Partnership’s net income.

Year Ended December 31, 2006 Compared with the Year Ended December 31, 2005
Net income decreased $5.5 million, or 11 per cent, to $44.7 million in 2006, compared to $50.2 million in 2005. Net
income of Northern Border and Tuscarora decreased in 2006 when compared to 2005 which contributed to an
$8.1 million decrease in Partnership’s earnings; however, this decrease was partially offset by an increased earnings
contribution resulting from the 2006 acquisitions net of financing charges. The Partnership’s earnings increased
$17.6 million and $0.2 million in 2006 due to the acquisition of the additional 20 per cent interest in Northern Border
and the additional 49 per cent general interest in Tuscarora, respectively. An increased outstanding debt balance
resulted in increased financial charges of $14.8 million that partially offset the increases in earnings as a result of
acquisitions.

Northern Border’s net income decreased $22.4 million to $129.9 million in 2006, compared to $152.3 million in 2005.
A one-time revenue amount related to the sale of the bankruptcy claims held against Enron by Northern Border in 2005
contributed $9.4 million to Northern Border’s 2005 revenues. Decreased firm demand revenue and commodity charges
were partially offset by additional revenue from transportation contracts related to the Chicago III Expansion Project.
Increased operating expenses due to increased general and administrative expenses and electric compression charges
associated with the Chicago III Expansion Project contributed $10.2 million to the decrease in net income at Northern
Border. The $22.4 million decrease in Northern Border’s net income contributed to a $6.7 million decrease to the
Partnership’s net income.

Tuscarora’s net income decreased $2.8 million to $13.3 million in 2006, compared to $16.1 million in 2005, primarily
due to lower net revenues resulting from settlement transportation rates that went into effect on June 1, 2006. The
decrease in Tuscarora’s net income contributed to a $1.4 million decrease to the Partnership’s net income.

Partnership Cash Flows

To supplement our financial statements, we disclose ‘‘Partnership cash flows’’. We have presented this additional
information to enhance investors’ understanding of the way that management analyzes the Partnership’s financial
performance. We believe this summary provides a more meaningful comparison of the Partnership’s financial
performance to prior years, as Partnership cash flows fund the cash distributions that the Partnership pays to its

2007 ANNUAL REPORT

49

unitholders. The presentation of this additional information is not meant to be considered in isolation or as a substitute
for results prepared in accordance with GAAP.

(millions of dollars except per common unit amounts)

Total cash distributions received(a)
Cash flows from Tuscarora’s operating activities(b)
Partnership costs(c)

Partnership cash flows(c)

Partnership cash flows per common unit
Cash distributions paid
Cash distributions paid per common unit

2007

147.6
19.9
(32.8)

134.7

$4.17
86.7
$2.565

2006

88.1
–
(18.2)

69.9

$3.99
43.5
$2.325

2005

69.2
–
(3.0)

66.2

$3.78
43.0
$2.300

(a) Reconciliation of non-GAAP financial measure: Total cash distributions received is a non-GAAP financial measure which is the sum of
equity income from investment in Great Lakes, return of capital from Great Lakes, equity income from investment in Northern Border,
return of capital from Northern Border and up until December 19, 2006, equity income from investment in Tuscarora and return of
capital from Tuscarora. It is provided as a supplement to results reported in accordance with GAAP. Management believes that this is a
meaningful measure to assist investors in evaluating the levels of cash distributions from the Partnership’s investments. Below is a
reconciliation of total cash distributions received to GAAP financial measures:

(millions of dollars)

Equity income from investment in Great Lakes
Return of capital from Great Lakes

Cash distributions from Great Lakes

Equity income from investment in Northern Border
Return of capital from Northern Border

Cash distributions from Northern Border
Equity income from investment in Tuscarora
Return of capital from Tuscarora

Cash distributions from Tuscarora

Total cash distributions received

2007

49.0
12.3

61.3
61.2
25.1

86.3
–
–

–

147.6

2006

–
–

–
56.6
23.8

80.4
5.9
1.8

7.7

88.1

2005

–
–

–
45.7
15.2

60.9
7.5
0.8

8.3

69.2

(b) Refer to Note 5 of the Partnership’s financial statements for cash flows from Tuscarora’s operating activities for the year ended

December 31, 2007. TC PipeLines accounted for its investment in Tuscarora using the equity method until December 19, 2006 and began
consolidating Tuscarora’s operations upon acquisition of an additional 49 per cent general partner interest. Cash flows from Tuscarora’s
operating activities for 2006 have not been included in the above analysis as the Partnership effectively accounted for Tuscarora on a
consolidated basis for only the last 11 days of the year.

(c) Reconciliation of non-GAAP financial measure: Partnership cash flows is a non-GAAP financial measure which is the sum of cash

distributions received and cash flows from Tuscarora’s operating activities less Partnership costs. We exclude Tuscarora’s costs from the
Partnership costs so that investors may evaluate our costs independent of costs directly attributable to our investments. Management
believes that this is a useful measure to assist investors in evaluating the Partnership’s cash flow from its operating activities. A
reconciliation of Partnership costs is summarized below:

(millions of dollars)

Operating expenses
Financial charges, net and other
Less:
Operating expenses and financial charges from Tuscarora

Partnership costs

2007

8.3
33.8

(9.3)

32.8

2006

2.7
15.8

(0.3)

18.2

2005

2.0
1.0

–

3.0

Year Ended December 31, 2007 Compared with the Year Ended December 31, 2006
Partnership cash flows increased $64.8 million, or 93 per cent, to $134.7 million in 2007, compared to $69.9 million in
2006. This increase was primarily a result of cash flows received from acquisitions made in 2007 and 2006. Partnership

50

TC PIPELINES, LP

cash flows in 2007 included cash distributions received of $61.3 million resulting from the acquisition of Great Lakes.
Cash distributions received from Northern Border increased $5.9 million in 2007 compared to the prior year due
primarily to the additional 20 per cent interest in Northern Border. The Partnership began consolidating Tuscarora’s
operations on December 19, 2006, when it acquired a controlling interest in Tuscarora. Cash flows from Tuscarora’s
operating activities in 2007 were $19.9 million, while the distributions received from Tuscarora in 2006 were
$7.7 million. Partnership costs increased $14.6 million to $32.8 million, compared to $18.2 million in 2006 primarily
due to increased financial charges related to higher outstanding debt balances.

Excluding the returns of capital from our investments, the Partnership used $758.8 million of cash flows for investing
activities in 2007 compared to $407.6 million used in 2006. In 2007, the Partnership acquired a 46.45 per cent general
partner interest in Great Lakes from El Paso Corporation for $733.4 million in cash. In 2006, the Partnership incurred
costs of $308.0 million to acquire an additional 20 per cent interest in Northern Border and $97.2 million related to its
acquisition of the additional 49 per cent interest in Tuscarora. The Partnership made equity contributions of $7.5 million
to Northern Border in 2007, compared to $3.1 million made in 2006. Tuscarora made capital expenditures of
$13.2 million in 2007, of which $12.2 million related to the compressor station expansion project in Likely, California.

The Partnership generated $625.6 million of net cash flows from financing activities in 2007 compared to
$337.6 million in 2006. The acquisition of a 46.45 per cent general partner interest in Great Lakes was partially
financed through a private placement of 17,356,086 common units at $34.57 per common unit for gross proceeds of
$600.0 million. In addition, TC PipeLines GP maintained its two per cent general partner interest in the Partnership by
contributing $12.6 million to the Partnership in connection with the private placement. The Partnership funded the
balance of the total consideration with a draw on its senior credit facility, which was amended and restated in
connection with this transaction. The Partnership incurred $1.2 million of costs associated with the amended senior
credit facility. The Partnership incurred debt of $171.5 million in 2007, which included $126.0 million in connection
with the Great Lakes acquisition. The Partnership repaid $66.2 million of the outstanding balance on its senior credit
facility and senior notes throughout the year.

Distributions paid by the Partnership increased $43.2 million, or 99 per cent, to $86.7 million in 2007 compared to
$43.5 million in 2006 due to the increased number of common units outstanding and increases in quarterly per
common unit distribution amounts declared in each of the last three quarters of 2007. In 2007, the Partnership paid
the $86.7 million in distributions in the following manner: $79.0 million to common unitholders (including $5.2 million
to the general partner as holder of 2,035,106 common units and $17.1 million to a TransCan Northern as holder of
8,678,045 common units), $5.9 million to the general partner as holder of the incentive distribution rights, and
$1.8 million to the general partner in respect of its two per cent general partner interest.

Year Ended December 31, 2006 Compared with the Year Ended December 31, 2005
Partnership cash flows increased $3.7 million, or 6 per cent, to $69.9 million in 2006, compared to $66.2 million in
2005. Cash distributions received from Northern Border increased $19.5 million in 2006 compared to 2005. The
additional 20 per cent ownership interest in Northern Border resulted in an additional $26.7 million in distributions
received partially offset by a $7.2 million reduction in distributions attributable to the Partnerships’ original 30 per cent
interest in Northern Border. The Partnership’s cash flows were also impacted by an increase in Partnership financial
charges of $14.6 million due to the higher outstanding debt balance. Distributions made by Northern Border were
higher in 2005 mainly due to higher revenues and $9.4 million realized on the sale of its unsecured bankruptcy claims
held against Enron.

Excluding the returns of capital from our investments, the Partnership used $407.6 million of cash flows for investing
activities in 2006 compared to $0.3 million used in 2005. In 2006, the Partnership incurred costs of $308.0 million to
acquire an additional 20 per cent interest in Northern Border, and in addition, made equity contributions of $3.1 million
which were used by Northern Border to repay indebtedness. The Partnership made a $0.3 million contribution to
Tuscarora in 2005 related to construction of the Barrick Lateral.

2007 ANNUAL REPORT

51

The Partnership generated $337.6 million of cash flows from financing activities in 2006 compared to $66.0 million in
cash flows used for financing activities in 2005. The increase in financing was to support the acquisition activities in
2006. To finance the 2006 acquisitions, the Partnership borrowed a net $383.5 million from bridge, term and revolving
credit facilities. Tuscarora repaid $2.4 million of the outstanding balance on its senior secured notes in December 2006.

Distributions paid increased $0.5 million to $43.5 million in 2006 compared to $43.0 million in 2005. The increase was
due to an increase in the Partnership’s quarterly cash distribution from $0.575 per common unit to $0.60 per common
unit beginning in the fourth quarter of 2006.

LIQUIDITY AND CAPITAL RESOURCES OF TC PIPELINES, LP

Overview

Our principal sources of liquidity include distributions received from our investments in Great Lakes and Northern
Border, operating cash flow from Tuscarora and our bank credit facility. The Partnership funds its operating expenses,
debt service and cash distributions primarily with operating cash flow. Long-term capital needs may be met through the
issuance of long-term debt and/or equity.

Summary of the Partnership’s Contractual Obligations

The Partnership’s contractual obligations as of December 31, 2007 included the following:

(millions of dollars)

Senior Credit Facility due 2011
Series A Senior Notes due 2010
Series B Senior Notes due 2010
Series C Senior Notes due 2012
Interest payments on Senior Credit

Facility(a)

Interest payments on Senior Notes
Operating leases
Capital commitments(b)

Payments Due by Period

Less Than
1 Year

2-3 Years

4-5 Years

After 5
Years

–
3.3
0.5
0.8

25.1
4.7
0.1
3.0

37.5

–
51.2
5.0
1.7

50.6
8.4
–
–

507.0
–
–
3.9

26.8
0.3
–
–

116.9

538.0

–
–
–
–

–
–
–
–

–

Total

507.0
54.5
5.5
6.4

102.5
13.4
0.1
3.0

692.4

(a)

Interest payments on Senior Credit Facility include the hedging effect of the derivative financial instruments placed on $475 million of the
outstanding debt.

(b) Capital commitments relate to the Likely Compressor Station construction.

The Partnership’s Debt and Credit Facilities
On March 31, 2006, the Partnership entered into an unsecured credit agreement for a $310.0 million credit facility
(Bridge Loan Credit Facility) with a banking syndicate. Borrowings under the Bridge Loan Credit Facility bore interest, at
the option of the Partnership, at the LIBOR or the base rate plus an applicable margin. On April 5, 2006, the
Partnership borrowed $307.0 million under the Bridge Loan Credit Facility to finance the acquisition of an additional
20 per cent general partner interest in Northern Border. The remaining $3.0 million commitment under the Bridge Loan
Credit Facility was terminated. On December 12, 2006, the Bridge Loan Credit Facility was refinanced through a
$297.0 million draw on a $410.0 million credit agreement (Senior Credit Facility) with a banking syndicate and the use

52

TC PIPELINES, LP

of $10.0 million cash on hand. The interest rate on the Bridge Loan Credit Facility averaged 6.29 per cent for the year
ended December 31, 2006.

On December 12, 2006, the Partnership entered into a credit agreement for the Senior Credit Facility. On December 19,
2006, TC PipeLines borrowed an additional $100.0 million under the Senior Credit Facility to finance the acquisition of
an additional 49 per cent interest in Tuscarora.

On February 13, 2007, the Senior Credit Facility was amended and restated in connection with the Great Lakes
acquisition. The amount available under the Senior Credit Facility increased from $410.0 million to $950.0 million,
consisting of a $700.0 million senior term loan and a $250.0 million senior revolving credit facility, with $194.0 million
of the senior term loan available being terminated upon closing of the Great Lakes acquisition. In accordance with the
Senior Credit Facility agreement, once repaid, a senior term loan cannot be re-borrowed. On November 29, 2007,
$18.0 million of the senior term loan was repaid, and hence terminated, leaving $488.0 million available and
outstanding under the senior term loan. At December 31, 2007, $19.0 million is outstanding under the senior revolving
credit facility, leaving $231.0 million available for future borrowings.

The Senior Credit Facility matures on December 12, 2011, subject to two one-year extensions at the option of the
Partnership and with the approval of a majority of the lenders thereunder. Amounts borrowed may be repaid in part or
in full prior to that time without penalty. Borrowings under the Senior Credit Facility will bear interest based, at the
Partnership’s election, on the LIBOR or the prime rate plus, in either case, an applicable margin. There was
$507.0 million outstanding under the Senior Credit Facility at December 31, 2007 (2006 – $397.0 million). The interest
rate on the Senior Credit Facility averaged 6.01 per cent for the year ended December 31, 2007 (2006 – 6.16 per cent).
After hedging activity, the interest rate incurred on the Senior Credit Facility averaged 5.75 per cent for the year ended
December 31, 2007. Prior to hedging activities, the interest rate was 5.62 per cent at December 31, 2007 (2006 –
6.07 per cent).

The Senior Credit Facility requires the Partnership to maintain a leverage ratio (debt to adjusted cash flow) of not more
than 4.75 to 1.00 at the end of any fiscal quarter. The permitted leverage ratio will increase to 5.50 to 1.00 for the first
three fiscal reporting periods during any 12-month period immediately following the consummation of specified
material acquisitions. At December 31, 2007, the Partnership was in compliance with all of its financial covenants.

In 1995, Tuscarora issued $91.7 million of 7.13 per cent senior secured notes, which mature on December 21, 2010
(Series A). In 2000, Tuscarora issued $8.0 million of 7.99 per cent senior secured notes, which mature on December 21,
2010 (Series B). In 2002, Tuscarora issued $10.0 million of 6.89 per cent senior secured notes, which mature on
December 21, 2012 (Series C). Series C proceeds were used to finance the construction of Tuscarora’s expansion
facilities. The Series A, Series B and Series C notes (collectively, the Notes) have a final payment at maturity of
$46.7 million, $4.1 million and $2.7 million, respectively. The Notes are secured by Tuscarora’s transportation contracts,
supporting agreements and substantially all of Tuscarora’s property. The credit agreement for the Notes contains certain
provisions that include, among other items, limitations on additional indebtedness and distributions to partners. On
December 31, 2007, $54.5 million, $5.5 million and $6.4 million were outstanding on the Series A, Series B and
Series C Senior Notes, respectively. On December 31, 2006, $57.9 million, $6.0 million and $7.2 million were
outstanding on the Series A, Series B and Series C Senior Notes, respectively.

Interest Rate Swaps and Options
The Partnership uses derivatives to assist in managing its exposure to interest rate risk. At December 31, 2007, the fair
value of the interest rate swaps and options accounted for as hedges was negative $9.8 million (2006 – positive
$1.6 million). The fair value of interest rate swaps and options have been calculated using year-end market rates. The
notional amount hedged was $475 million. $300.0 million of variable-rate debt is hedged by an interest rate swap
during the period from March 12, 2007 through December 12, 2011, where the weighted average fixed interest rate
paid is 4.89 per cent. $100.0 million of variable-rate debt is hedged by an interest rate option during the period from
May 22, 2007 through May 22, 2009 to an interest rate range between a weighted average floor of 4.09 per cent and
a cap of 5.35 per cent. $75.0 million of variable-rate debt is hedged by an interest rate swap during the period from

2007 ANNUAL REPORT

53

February 29, 2008 through February 28, 2011, where the fixed interest rate paid will be 3.86 per cent. In addition to
these fixed rates, the Partnership pays an applicable margin in accordance with the Senior Credit Facility agreement. The
interest rate swaps and options are structured such that the cash flows match those of the Senior Credit Facility.

Capital Requirements

In 2007, the Partnership made an equity contribution of $7.5 million to Northern Border, representing the Partnership’s
50 per cent share of a $15.0 million cash call issued by Northern Border, which fulfilled the previously approved 2007
equity cash calls. The proceeds were used by Northern Border to repay indebtedness. In 2006, the Partnership made an
equity contribution of $3.1 million, representing the Partnership’s then 30 per cent share of a $10.3 million cash call
issued by Northern Border, where the proceeds were used to fund a portion of the Chicago III Expansion Project capital
costs.

In 2007, Tuscarora incurred $13.2 million of capital expenditures, of which $12.2 million related to its compressor
station expansion in Likely, California. These capital expenditures were funded with operating cash flows. In 2005, the
Partnership made an equity contribution of $0.3 million to Tuscarora, representing the Partnership’s then 49 per cent
share of a $0.7 million cash call issued by Tuscarora. Those proceeds were used to fund the construction of the Barrick
Lateral that went into service June 2005.

To the extent the Partnership has any additional capital requirements with respect to our pipeline systems or makes
acquisitions in 2008, we expect to fund these requirements with operating cash flows, debt and/or equity.

Cash Distribution Policy of TC PipeLines

The Partnership makes distributions of Available Cash, as defined in the Partnership Agreement, in the following
manner:

• First, 98 per cent to the common units, pro rata, and two per cent to the general partner, until there is distributed
for each outstanding common 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 calculated in
the following manner:

• First, 85 per cent to all units, pro rata, and 15 per cent to the general partner, until each unitholder has received a

total of $0.5275 for that quarter;

• Second, 75 per cent to all units, pro rata, and 25 per cent to the general partner, until each unitholder has

received a total of $0.6900 for that quarter; and

• Third, 50 per cent to all units, pro rata, and 50 per cent to the general partner.

The distribution to the general partner described above, other than in its capacity as a holder of 2,035,106 common
units that are in excess of its aggregate two per cent general partner interest, represent the incentive distribution rights.

2007 Fourth Quarter Cash Distribution

On January 17, 2008, the Board of Directors of the general partner declared the Partnership’s 2007 fourth quarter cash
distribution. The fourth quarter cash distribution which was paid on February 14, 2008 to unitholders of record as of
January 31, 2008, totaled $25.6 million and was paid in the following manner: $23.2 million to common unitholders
(including $1.4 million to the general partner as holder of 2,035,106 common units and $5.8 million to TransCan
Northern as holder of 8,678,045 common units), $1.9 million to the general partner as holder of the incentive
distribution rights, and $0.5 million to the general partner in respect of its two per cent general partner interest.

54

TC PIPELINES, LP

LIQUIDITY AND CAPITAL RESOURCES OF OUR PIPELINE SYSTEMS

Overview

Our pipeline systems’ principal source of liquidity is cash generated from operating activities and bank credit facilities.
Our pipeline systems fund their operating expenses, debt service and cash distributions to partners primarily with
operating cash flow.

Capital expenditures are funded by a variety of sources, including cash generated from operating activities, borrowings
under bank credit facilities, issuance of senior notes or equity contributions from our pipeline systems’ partners. The
ability of our pipeline systems to access capital markets for debt under reasonable terms depends on their financial
condition, credit ratings and market conditions.

Our pipeline systems believe that their ability to obtain financing at reasonable rates and their history of consistent cash
flow from operating activities provide a solid foundation to meet their future liquidity and capital resource requirements.

Summary of Great Lakes’ Contractual Obligations

Great Lakes’ contractual obligations related to debt as of December 31, 2007 included the following:

(millions of dollars)

8.74% series Senior Notes due 2008

to 2011

9.09% series Senior Notes due 2012

to 2021

6.73% series Senior Notes due 2009

to 2018

6.95% series Senior Notes due 2019

to 2028

8.08% series Senior Notes due 2021

to 2030

Interest payments on debt

Payments Due by Period

Total

40.0

100.0

90.0

110.0

100.0
390.0

830.0

Less Than
1 Year

10.0

–

–

–

–
34.2

44.2

2-3 Years

4-5 Years

20.0

–

18.0

–

–
64.3

102.3

10.0

10.0

18.0

–

–
58.3

96.3

After 5
Years

–

90.0

54.0

110.0

100.0
233.2

587.2

Long-Term Financing
All of Great Lakes’ outstanding debt securities are senior unsecured notes with similar terms except for interest rates,
maturity dates and prepayment premiums.

Great Lakes is required to comply with certain financial, operational and legal covenants. Under the most restricted
covenants in the Senior Note Agreements, approximately $237.0 million of Great Lakes’ partners’ capital was restricted
as to distributions as of December 31, 2007. In addition, Great Lakes is required to maintain a minimum consolidated
tangible net worth of $175 million. At December 31, 2007, Great Lakes was in compliance with all of its financial
covenants.

The aggregate estimated fair value of long-term debt was $525 million for 2007. The aggregate annual required
repayments of senior notes are $10 million in 2008 and $19 million for each year 2009 through 2012. In 2007, interest
expense related to Great Lakes’ senior notes was $35 million.

2007 ANNUAL REPORT

55

Summary of Northern Border’s Contractual Obligations

Northern Border’s contractual obligations related to debt, operating leases and other long-term obligations as of
December 31, 2007, included the following:

(millions of dollars)

7.75% senior notes due 2009
7.50% senior notes due 2021
$250 million credit agreement due

2012

Interest payments on debt
Operating leases
Other long-term obligations

Payments Due by Period

Less Than
1 Year

2-3 Years

4-5 Years

–
–

–
43.1
2.5
0.8

46.4

200.0
–

–
65.6
4.7
1.5

271.8

–
–

166.0
49.3
3.8
0.8

219.9

Total

200.0
250.0

166.0
321.3
72.1
3.1

1,012.5

After 5
Years

–
250.0

–
163.3
61.1
–

474.4

Operating Leases
Northern Border is required to make future minimum payments for office space and rights-of-way under non-cancelable
operating leases.

Other
Northern Border is required to pay $3.6 million over a five year period under a transition services agreement between
ONEOK Partners GP and TransCanada Northern Border, related to the reimbursement for shared assets acquired by
ONEOK Partners. In 2007, a charge of $2.3 million was recorded in operations and maintenance expense and
$1.3 million was recorded as plant, property and equipment.

Amended and Restated Credit Agreement
On April 27, 2007, Northern Border entered into a $250 million amended and restated revolving credit agreement (the
‘‘2007 Credit Agreement’’) with certain financial institutions. The 2007 Credit Agreement was used to refinance the
outstanding indebtedness under Northern Border’s $175 million revolving credit agreement dated as of May 16, 2005
and was used to repay all of the $150 million of its 6.25 per cent Senior Notes due May 1, 2007. The 2007 Credit
Agreement can also be used to finance permitted acquisitions, pay related fees and expenses, issue letters of credit and
provide for ongoing working capital needs and for other general business purposes, including capital expenditures.

Northern Border may, at its option, so long as no default or event of default has occurred and is continuing, elect to
increase the capacity under its 2007 Credit Agreement by an aggregate amount not to exceed $100 million, provided
that lenders are willing to commit additional amounts. At Northern Border’s option, the interest rate on the outstanding
borrowings may be the lenders’ base rate or the LIBOR plus a spread that is based on its long-term unsecured credit
ratings. The 2007 Credit Agreement permits Northern Border to specify the portion of the borrowings to be covered by
specific interest rate options and to specify the interest rate period. Northern Border is required to pay a facility fee of
0.05 per cent based on the principal amount of the commitment of $250 million. The term of the agreement is five
years, with options for two one-year extensions.

Under the 2007 Credit Agreement, Northern Border is required to comply with certain financial, operational and legal
covenants. Among other things, Northern Border is required to maintain a ratio of total debt to EBITDA (net income
plus interest expense, income taxes, depreciation and amortization and all other non-cash charges) of no more than
4.75 to 1. Pursuant to the 2007 Credit Agreement, if one or more acquisitions are consummated in which the
aggregate purchase price is $25 million or more, the allowable ratio of total debt to EBITDA is increased to 5.50 to 1
for the first three full calendar quarters following the acquisition. Upon any breach of these covenants, amounts

56

TC PIPELINES, LP

outstanding under the 2007 Credit Agreement may become immediately due and payable. At December 31, 2007,
Northern Border was in compliance with all of its financial covenants.

The fair value of Northern Border’s variable rate debt was approximately the carrying value since the interest rates are
periodically adjusted to reflect current market conditions. As of December 31, 2007, Northern Border’s outstanding
borrowings under its credit agreement were $166 million. The average interest rate on Northern Border’s credit
agreement at December 31, 2007 was 5.35 per cent.

Interest Rate Collar Agreement
In August 2007, Northern Border entered into a zero cost interest rate collar agreement (the ‘‘Collar Agreement’’) to
limit the variability of the interest rate on $140 million of variable-rate borrowings during the period from October 30,
2007 through October 30, 2009 to a range between a floor of 4.35 per cent and a cap of 5.36 per cent. Northern
Border has designated the Collar Agreement as a cash flow hedge. At December 31, 2007, Northern Border’s balance
sheet reflected an unrealized loss of approximately $1.9 million with a corresponding decrease to accumulated other
comprehensive income (loss) related to the changes in fair value of the Collar Agreement since inception. Since
inception, Northern Border has not recognized any amounts in income due to ineffectiveness of the Collar Agreement.

Long-Term Financing – Debt Securities
Northern Border periodically issues long-term debt securities to meet its capital resource requirements. All of Northern
Border’s outstanding debt securities are senior unsecured notes with similar terms except for interest rates, maturity
dates and prepayment premiums.

Northern Border’s senior notes issuances of $200 million due in 2009 and $250 million due in 2021 are borrowed at
fixed interest rates of 7.75 per cent and 7.50 per cent, respectively. Northern Border intends to maintain the current
schedule of maturities, which will result in no gains or losses on their respective repayments. Northern Border intends to
refinance the senior notes due in 2009 with a mix of long-term fixed rate debt and short-term variable rate debt. The
indentures of the notes do not limit the amount of unsecured debt Northern Border may incur but do restrict secured
indebtedness. In 2007, Northern Border repaid all of the $150 million of its 6.25 per cent senior notes due May 1,
2007 with borrowings under the 2007 Credit Agreement. At December 31, 2007, the aggregate fair value of the
outstanding senior notes was approximately $493 million. In 2007, interest expense related to the senior notes was
$37.4 million.

CASH FROM OUR PIPELINE SYSTEMS

Cash Distribution Policies of Great Lakes and Northern Border

Distributions to partners are made on a pro rata basis according to each general partner’s ownership percentage,
approximately one month following the end of a quarter. Great Lakes’ and Northern Border’s respective Management
Committees determine the amount and timing of cash distributions, where the amount of such distributions is based
on available cash flow as determined by a prescribed formula. Any changes to, or suspension of, Great Lakes’ or
Northern Border’s cash distribution policy requires the unanimous approval of its respective Management Committee.

Northern Border’s Management Committee changed its cash distribution policy effective in January 2004 to distribute
100 per cent of the distributable cash flow based on earnings before interest, taxes, depreciation and amortization less
interest expense and maintenance capital expenditures. In 2006, upon the closing of the purchase and sale of the
20 per cent interest in Northern Border, the Northern Border Management Committee adopted certain changes to the
Northern Border cash distribution policy related to financial ratio targets and equity contributions. The change defined
minimum equity to total capitalization ratios to be used by the Northern Border Management Committee to establish
the timing and amount of required equity contributions. In addition, any shortfall due to the inability to refinance
maturing debt will be funded by equity contributions.

2007 ANNUAL REPORT

57

On February 1, 2008, a cash distribution of $46.3 million was declared and paid by Northern Border for the fourth
quarter of 2007, of which TC PipeLines’ 50 per cent share was $23.2 million. On February 1, 2008, a cash distribution
of $25.0 million was declared and paid by Great Lakes for the fourth quarter of 2007, of which TC PipeLines’
46.45 per cent share was $11.6 million.

Investing Activities for our Pipeline Systems

Capital spending for maintenance of existing facilities and growth projects were as follows for each of our investments:

(millions of dollars)

Great Lakes(a):

Maintenance
Growth

Great Lakes’ capital spending

Northern Border:
Maintenance
Growth

Northern Border’s capital spending

Tuscarora:

Maintenance
Growth

Tuscarora’s capital spending

2007

2006

2005

16.7
–

16.7

10.6
–

10.6

0.1
13.1

13.2

10.4
10.5

20.9

0.3
1.3

1.6

18.3
10.3

28.6

0.2
0.7

0.9

(a) Great Lakes’ capital spending information includes only capital expenditures from the date of acquisition.

Our pipeline systems fund their investing activities primarily with operating cash, issuances of new debt or additional
borrowings under existing facilities, and equity contributions from general partners.

In 2008, Great Lakes expects to invest approximately $20.3 million for maintenance capital expenditures. No significant
growth capital expenditures are planned for 2008.

Northern Border’s maintenance capital expenditures decreased $7.9 million in 2006 compared with 2005 due to a
decrease in expenditures related to compressor station overhauls. Growth capital expenditures in 2006 and 2005 were
primarily related to spending for the Chicago III Expansion project. In 2008, Northern Border expects to spend
approximately $30 million for capital expenditures of which $13 million relates to maintenance capital and $17 million
relates to growth capital in regards to the Des Plaines project, subject to receipt of the required regulatory approvals.
Northern Border intends to finance half of its growth capital expenditures with equity contributions from its general
partners.

$12.2 million of Tuscarora’s growth capital expenditures in 2007 relate to the compressor station expansion project in
Likely, California. In 2008, Tuscarora expects to spend an additional $7.0 million to fund the completion of the
compressor station expansion. Tuscarora expects to fund these capital expenditures with operating cash flow.

58

TC PIPELINES, LP

CONTINGENCIES

Legal

Various legal actions or governmental proceedings that have arisen in the ordinary course of business are pending. Our
pipeline systems believe that the resolution of these issues will not have a material adverse impact on their results of
operations or financial position.

Environmental

Our pipeline systems are not aware of any material contingent liabilities with respect to compliance with applicable
environmental laws and regulations.

RELATED PARTY TRANSACTIONS

Great Lakes earns transportation revenues from TransCanada and its affiliates under fixed priced contracts with
remaining terms ranging from one to ten years. Great Lakes earned $113.9 million of transportation revenues under
these contracts for the period February 23, 2007 to December 31, 2007. This amount represents 48.2 per cent of total
revenues earned by Great Lakes for the period February 23, 2007 to December 31, 2007. $52.9 million of
transportation revenue is included in the Partnership’s equity income from Great Lakes during the same period. Please
read Item 1. ‘‘Business’’, Item 1A. ‘‘Risk Factors’’, and Item 13. ‘‘Certain Relationships and Related Transactions’’ for
additional information regarding Great Lakes’ transportation agreements with TransCanada and ANR.

OUTLOOK

Great Lakes

At January 31, 2008, the remaining weighted average contract life of Great Lakes’ contracts was 2.4 years and
substantially all of its design capacity was contracted on a firm basis for the first quarter of 2008. As of January 31,
2008, Great Lakes had approximately ten per cent of its design capacity uncontracted beginning in the second quarter
of 2008. Dependent on competitive factors and prevailing market conditions, Great Lakes may discount transportation
capacity as needed to optimize revenue.

Northern Border

At January 31, 2008, the weighted average contract life of Northern Border’s contracts was 1.3 years and substantially
all of its design capacity was contracted on a firm basis for the first quarter of 2008. As of January 31, 2008, Northern
Border had approximately 890 MMcf/d or 37 per cent of its design capacity uncontracted beginning in the second
quarter of 2008 and 48 per cent uncontracted by the end of 2008. Prevailing market conditions and increasing
competitive factors in North America, including the Rockies Express Pipeline, could cause Northern Border to discount
their rates or otherwise experience a reduction in their revenues. These factors will continue to impact Northern Border’s
ability to market this available capacity. Northern Border expects to continue to discount transportation capacity as
needed to optimize revenue.

2007 ANNUAL REPORT

59

Tuscarora

At January 31, 2008, the weighted average remaining contract life of Tuscarora’s contracts was 10.4 years. As of
January 31, 2008, Tuscarora has approximately five MMcf/d or two per cent of its design capacity uncontracted
beginning in the second quarter of 2008.

Item 7A. Quantitative and Qualitative Disclosures about Market Risk

OVERVIEW

Our exposure to market risk discussed below includes forward-looking statements and represents an estimate of
possible changes in future earnings that would occur assuming hypothetical future movements in interest rates. Our
views on market risk are not necessarily indicative of actual results that may occur and do not represent the maximum
possible gains and losses that may occur, since actual gains and losses will differ from those estimated, based on actual
fluctuations in interest rates and the timing of transactions.

TC PipeLines is exposed to market risk due to interest rate fluctuations. Market risk is the risk of loss arising from
adverse changes in market rates. We utilize financial instruments to manage the risks of certain identifiable or
anticipated transactions and achieve a more predictable cash flow. Our risk management function follows established
policies and procedures to monitor interest rates to ensure our hedging activities mitigate market risks. We do not use
financial instruments for trading purposes.

In accordance with SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities we record financial
instruments on the balance sheet as assets and liabilities based on fair value. We estimate the fair value of financial
instruments using available market information and appropriate valuation techniques. Changes in financial instruments’
fair value are recognized in earnings unless the instrument qualifies as a hedge under SFAS No. 133 and meets specific
hedge accounting criteria. Qualifying financial instruments’ gains and losses may offset the hedged items’ related results
in earnings for a fair value hedge or be deferred in accumulated other comprehensive income for a cash flow hedge.

INTEREST RATE RISK

TC PipeLines’ interest rate exposure results from its Senior Credit Facility, which is subject to variability in LIBOR interest
rates. The Partnership regularly assesses the impact of interest rate fluctuations on future cash flows and evaluates
hedging opportunities to mitigate its interest rate risk. The notional amount hedged at December 31, 2007 was
$475.0 million. $300.0 million of variable-rate debt is hedged by an interest rate swap during the period from
March 12, 2007 through December 12, 2011, where the weighted average fixed interest rate paid is 4.89 per cent.
$100.0 million of variable-rate debt is hedged by an interest rate option during the period from May 22, 2007 through
May 22, 2009 to an interest rate range between a weighted average floor of 4.09 per cent and a cap of 5.35 per cent.
$75.0 million of variable-rate debt is hedged by an interest rate swap during the period from February 29, 2008
through February 28, 2011, where the fixed interest rate paid will be 3.86 per cent. The interest rate swaps and
options are structured such that the cash flows match those of the Senior Credit Facility. The fair value of interest rate
derivatives has been calculated using year-end market rates. At December 31, 2007, the fair value of the Partnership’s
interest rate swaps and options accounted for as hedges was negative $9.8 million.

At December 31, 2007, TC PipeLines had $507.0 million outstanding on its Senior Credit Facility. Utilizing the conditions
of the interest rate swaps and options, if LIBOR interest rates hypothetically increased by one per cent compared to the
rates in effect as of December 31, 2007, the Partnership’s interest expense for the year ended December 31, 2007
would have increased by $1.4 million; and if LIBOR interest rates hypothetically decreased one per cent compared to the
rates in effect as of December 31, 2007, the Partnership’s interest expense for the year would have decreased by
$2.0 million. These amounts have been determined by considering the impact of the hypothetical interest rates on
variable rate borrowings outstanding as of December 31, 2007.

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TC PIPELINES, LP

Northern Border utilizes both fixed-rate and variable-rate debt and is exposed to market risk due to the floating interest
rates on its credit facility. Northern Border regularly assesses the impact of interest rate fluctuations on future cash flows
and evaluates hedging opportunities to mitigate its interest rate risk. As of December 31, 2007, 73 per cent of
Northern Border’s outstanding debt was at fixed rates. In August 2007, Northern Border entered into a Collar
Agreement to limit the variability of the interest rate on $140.0 million of variable-rate borrowings during the period
from October 30, 2007 through October 30, 2009 to a range between a floor of 4.35 per cent and a cap of 5.36 per
cent.

Utilizing the conditions of the Collar Agreement, if interest rates hypothetically increased one per cent compared with
rates in effect as of December 31, 2007, Northern Border’s annual interest expense would increase and its net income
would decrease by approximately $0.8 million; and if interest rates hypothetically decreased one per cent compared
with rates in effect as of December 31, 2007, Northern Border’s annual interest expense would decrease and its net
income would increase by approximately $1.1 million.

Great Lakes and Tuscarora utilize fixed-rate debt; therefore, they are not exposed to market risk due to floating interest
rates.

OTHER RISKS

The Partnership is influenced by the same factors that influence our pipeline systems. None of our pipeline systems own
any of the natural gas they transport; therefore, they do not assume any of the related natural gas commodity price
risk.

The state of Minnesota currently requires Great Lakes to pay use tax on the value of the shipper provided compressor
fuel burned in its Minnesota compressor engines. Great Lakes is subject to primarily commodity price volatility and some
volume volatility in determining the amount of use tax owed. If natural gas prices changed by $1 per million British
thermal units, Great Lakes’ annual use tax expense would change by approximately $0.7 million.

The Partnership does not have any material foreign exchange risks.

Item 8.

Financial Statements and Supplementary Data

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

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

None.

Item 9A. Controls and Procedures

EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES

Based on their evaluation of the Partnership’s disclosure controls and procedures as of the end of the year covered by
this annual report, the principal executive officer and principal financial officer of the general partner of the Partnership
have concluded that the Partnership’s disclosure controls and procedures were effective in ensuring that the information
required to be disclosed by the Partnership in the reports that it files or submits under the Securities Exchange Act of
1934 is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms
and that information required to be disclosed by the Partnership in the reports that the Partnership files or submits
under the Exchange Act is accumulated and communicated to the management of the general partner of the

2007 ANNUAL REPORT

61

Partnership, including the principal executive officer and principal financial officer, as appropriate to allow timely
decisions regarding required disclosure.

Changes in Internal Control Over Financial Reporting

During the quarter ended December 31, 2007, there has been no change in the Partnership’s internal control over
financial reporting that has materially affected or is reasonably likely to materially affect our internal control over
financial reporting.

MANAGEMENT’S ANNUAL REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as
such term is defined in Rule 13a-15(f) promulgated under the Securities Exchange Act of 1934. Internal control over
financial reporting, no matter how well designed, has inherent limitations and can only provide reasonable assurance
with respect to the preparation and fair presentation of published financial statements. Under the supervision and with
the participation of our management, including our chief executive officer and principal financial officer, we conducted
an evaluation of the effectiveness of our internal control over financial reporting based on the framework in Internal
Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

Based on our assessment according to the above criteria, management has concluded that our internal control over
financial reporting was effective as of December 31, 2007 to provide reasonable assurance regarding the reliability of
financial reporting and the preparation of financial statements for external purposes in accordance with U.S. generally
accepted accounting principles. There were no material weaknesses.

Our independent registered public accounting firm, KPMG LLP, independently assessed the effectiveness of the
Partnership’s internal control over financial reporting. KPMG has issued an attestation report concurring with
management’s assessment, which is included on page F-3 of the financial statements included in this Form 10-K.

Item 9B. Other Information

None.

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TC PIPELINES, LP

Part III

Item 10. Directors, Executive Officers and Corporate Governance

TC PipeLines is a limited partnership and as such has no officers, directors or employees. Set forth below is certain
information concerning the directors and officers of the general partner who manage the operations of TC PipeLines.
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 which is a wholly-owned subsidiary of
TransCanada.

Name

Russell K. Girling
Mark A.P. Zimmerman
Jack F. Jenkins-Stark
David L. Marshall
Walentin (Val) Mirosh
Gregory A. Lohnes
Kristine L. Delkus
Steven D. Becker
Terry C. Ofremchuk
Sean M. Brett
Donald J. DeGrandis
Amy W. Leong

Age

Position with General Partner

45
43
57
68
62
51
50
57
57
42
59
40

Chairman, Chief Executive Officer and Director
President
Independent Director
Independent Director
Independent Director
Director
Director
Director
Vice-President, Taxation
Vice-President and Treasurer
Secretary
Controller, Principal Financial Officer

Mr. Girling was appointed a director of the general partner in April 1999 and Chief Executive Officer of the general
partner in June 2006. Mr. Girling’s principal occupation is President, Pipelines Division of TransCanada, a position he has
held since June 2006. From March 2003 to June 2006, he was Executive Vice-President, Corporate Development and
Chief Financial Officer of TransCanada. Prior to March 2003, Mr. Girling was Executive Vice-President and Chief
Financial Officer of TransCanada. Mr. Girling is also a director of Agrium Inc.

Mr. Zimmerman was appointed President of the general partner in January 2007. Mr. Zimmerman’s principal occupation
is Vice-President, Commercial Transactions of TransCanada, a position he has held since June 2006. From September
2003 to June 2006, he was Director, Project Finance for TransCanada, and prior to September 2003, he was Director,
Corporate Evaluations and Planning for TransCanada.

Mr. Jenkins-Stark was appointed a director of the general partner in July 1999. Mr. Jenkins-Stark’s principal occupation
is Chief Financial Officer of BrightSource Energy Inc. (designs and builds large scale solar plants that deliver solar energy
in the form of steam and/or electricity), a position he has held since April 2007. Mr. Jenkins-Stark was Chief Financial
Officer of Silicon Valley Bancshares (offering financial products and services, including commercial, investment, merchant
and private banking and private equity services) from April 2004 to April 2007. Prior to that he was Vice-President,
Business Operations and Technology at Itron Inc. (a manufacturer of automated meter reading technology and a
developer of energy management software), a position he held from January 2004 to March 2004. In March 2003,
Mr. Jenkins-Stark was named a Managing Director at Itron Inc. following the purchase of Silicon Energy Corp. (internet-
based energy and data management software) by Itron Inc. Prior to the acquisition, Mr. Jenkins-Stark was Chief
Financial Officer of Silicon Energy.

Mr. Marshall was appointed a director of the general partner in July 1999. Mr. Marshall is a corporate director.

Mr. Mirosh was appointed a director of the general partner in September 2004. Mr. Mirosh’s principal occupation is
Vice-President of NOVA Chemicals Corporation and President of Olefins and Feedstocks, division of NOVA Chemicals
Corporation (commodity chemical company), a position he has held since July 2003. Mr. Mirosh was Partner, MacLeod,

2007 ANNUAL REPORT

63

Dixon (law firm) from January 2002 to July 2003. Mr. Mirosh is also a director of Taylor NGL Limited Partnership and
Superior Plus Income Fund.

Mr. Lohnes was appointed a director of the general partner in January 2007. Mr. Lohnes’ principal occupation is
Executive Vice-President and Chief Financial Officer of TransCanada, a position he has held since June 2006. Prior to
June 2006, he was President and Chief Executive Officer of Great Lakes Gas Transmission Company.

Ms. Delkus was appointed a director of the general partner in November 2003. Ms. Delkus’ principal occupation is
Deputy General Counsel, Pipelines and Regulatory Affairs of TransCanada, a position she has held since September
2006. From June 2006 to September 2006, she was Vice-President, Pipeline Law and Regulatory Affairs of TransCanada.
From December 2005 to June 2006, she was Vice-President, Law, Gas Transmission of TransCanada. Prior to December
2005, she was Vice-President, Law, Power and Regulatory.

Mr. Becker was appointed a director of the general partner in January 2007 and appointed Vice-President, Business
Development of the general partner in September 2003. Mr. Becker’s principal occupation is Vice-President, Pipeline
Development of TransCanada, a position he has held since June 2006. From April 2003 to June 2006, he was
Vice-President, Gas Development of TransCanada. Prior to April 2003, Mr. Becker was Vice-President, Market
Development and Vice-President, Gas Strategy of TransCanada.

Mr. Ofremchuk was appointed Vice-President, Taxation of the general partner in July 2007. Mr. Ofremchuk’s principal
occupation is Manager, Corporate Taxation of TransCanada.

Mr. Brett was appointed Vice-President and Treasurer of the general partner in January 2007. Mr. Brett’s principal
occupation is Assistant Treasurer for TransCanada, a position he has held since January 2007. Prior to January 2007, he
was Director, Capital Markets for TransCanada.

Mr. DeGrandis was appointed Secretary of the general partner in April 2005. Mr. DeGrandis’ principal occupation is
Corporate Secretary of TransCanada, a position he has held since June 2006. From June 2004 to June 2006, he was
Associate General Counsel, Corporate, Corporate Secretarial of TransCanada. Prior to June 2004, Mr. DeGrandis was
Director of Corporate Legal Services and Senior Legal Counsel of TransCanada.

Ms. Leong was appointed principal financial officer of the general partner in January 2007 and Controller of the
general partner in September 2003. Ms. Leong’s principal occupation is Director, Pipeline Accounting of TransCanada, a
position she has held since January 2005. From April 2003 until January 2005, Ms. Leong was Manager, Gas
Transmission Accounting of TransCanada. Prior to April 2003, Ms. Leong was Manager, Regulatory Accounting and
Capital Accounting of TransCanada.

Audit Committee Financial Expert

The Board of Directors has determined that David Marshall and Jack Jenkins-Stark are ‘‘audit committee financial
experts’’, are ‘‘independent’’ and are ‘‘financially sophisticated’’ as defined under applicable SEC and NASDAQ Stock
Market Corporate Governance rules. The Board’s affirmative determination for both David Marshall and Jack Jenkins-
Stark was based on their respective education and extensive experience as chief financial officers for corporations that
presented a breadth and level of complexity of accounting issues that are generally comparable to those of TC
PipeLines.

Identification of the Audit Committee

The general partner of the Partnership has a separately designated audit committee consisting of three independent
board members. The members of the committee are David Marshall, as Chair, Jack Jenkins-Stark and Walentin (Val)
Mirosh. All members of the Audit Committee meet the criteria for independence as set forth under the rules of the SEC
and those of the NASDAQ Stock Market. None of the Audit Committee members have participated in the preparation

64

TC PIPELINES, LP

of the financial statements of the Partnership or any of its subsidiaries at any time during the past three years. In
addition, all members of the audit committee are able to read and understand fundamental financial statements,
including a company’s balance sheet, income statement, and cash flow statement.

Code of Ethics

TC PipeLines believes that director, management and employee honesty and integrity are important factors in ensuring
good corporate governance. The employees of the general partner, as employees of TransCanada, are subject to
TransCanada’s code of business ethics. In addition, the general partner has adopted a code of business ethics for its
Chief Executive Officer, President and Principal Financial Officer and one which applies to its independent directors,
being the code of business ethics for directors. All codes are published on its website at www.tcpipelineslp.com. If any
substantive amendments are made to the code for senior officers or if any waivers are granted, the amendment or
waiver will be published on TC PipeLines’ website or filed in a report on Form 8-K.

Corporate Governance

The Audit Committee has adopted a charter which specifically provides that it is responsible for the appointment,
compensation, retention and oversight of the work of the independent public accountants engaged in preparing or
issuing TC PipeLines’ audit report, that the committee has the authority to engage independent counsel and other
advisors as it determines necessary to carry out its duties and for the committee to be responsible for establishing
procedures for the receipt, retention and treatment of complaints regarding accounting, internal accounting controls or
auditing matters, including procedures for the confidential, anonymous submission by employees of the general partner
concerns regarding questionable accounting or auditing matters. The committee has adopted TransCanada’s Ethics help
line in fulfillment of its responsibility to establish a confidential and anonymous whistle blowing process. The toll free
Ethics Help-Line number and the audit committee’s charter are published on TC PipeLines’ website at
www.tcpipelineslp.com.

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 ten per cent 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 Global Market. Executive officers, directors
and greater than ten per cent 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, 2007.

Item 11. Executive Compensation

Compensation Discussion and Analysis

We are a master limited partnership and we do not directly employ any of the individuals responsible for managing or
operating our business nor do we have any directors. We are managed by the executive officers of our general partner
who are also our executive officers. The executive officers of our general partner are compensated directly by
TransCanada.

2007 ANNUAL REPORT

65

The compensation policies and philosophy of TransCanada govern the types and amount of compensation granted each
of the named executive officers. Since these policies and philosophy are those of TransCanada, we refer you to a
discussion of those items as set forth in the Executive Compensation section of the TransCanada ‘‘Management Proxy
Circular’’ on the TransCanada website at www.transcanada.com. The TransCanada ‘‘Management Proxy Circular’’ is
produced by TransCanada pursuant to Canadian securities regulations and is not incorporated into this document by
reference or deemed furnished or filed by us under the Securities Exchange Act of 1934, as amended; rather the
reference is to provide our investors with an understanding of the compensation policies and philosophy of the ultimate
parent of our general partner.

The board of directors of our general partner does not have a separate compensation committee, nor does it make any
determination with respect to the amount of compensation to be paid to our executive officers. The board of our
general partner does have responsibility for evaluating and determining the reasonableness of the total amount we are
charged for managerial, administrative and operational support provided by TransCanada, and its affiliates, including our
general partner. The board specifically approves the allocation of the salary of the CEO to the Partnership on an annual
basis. Please read Item 13. ‘‘Certain Relationships and Related Transactions’’ for more information regarding this
arrangement.

In addition to base salary, we also reimburse our general partner for certain benefit and incentive compensation
expenses related to the officers of our general partner and employees of an affiliate of our general partner who
perform services on our behalf. The base salaries that are allocable to us vary for each officer or employee of an affiliate
of our general partner performing services on our behalf and are based on the amount of time an employee devotes to
matters related to our business as compared to the amount of time such employee devotes to matters related to the
business of TransCanada and its other affiliates. We are allocated and reimburse the general partner for each officer’s
salary expense. Other benefit and incentive compensation expenses related to our officers are reimbursed to the general
partner based upon an agreed upon calculation.

The following table summarizes the salary allocated to and paid by us in 2006 and 2007 for our principal executive
officer, president and principal financial officers. None of the other executive officers of our general partner allocated to
us more than $100,000 related to their salary.

Summary Compensation Table

Name and Principal Position

Russell K. Girling, Chief Executive Officer

Mark A.P. Zimmerman, President

Gregory A. Lohnes, Chief Financial Officer

Amy W. Leong, Controller and Principal Financial Officer

Base Salary Allocated to the Partnership

Canadian
Dollars

60,250
49,835

United States
Dollar
Equivalent(1)

60,973
42,763

Total(1)

60,973
42,763

102,500

103,729

103,729

–
–

16,475
15,500

–
–

16,673
13,301

–
–

16,673
13,301

Year

2007
2006

2007

2007
2006

2007
2006

(1) The compensation of executive officers of the general partner is paid by TransCanada in Canadian dollars. The United States dollar
equivalents have been calculated using the applicable December 31, 2007 and 2006 noon buying rates of 1.0120 and 0.8581,
respectively, as reported by the Bank of Canada.

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TC PIPELINES, LP

We reimburse our general partner for benefit and incentive compensation expenses based on a set formula, which
expenses are attributable to additional compensation paid to each of them and other compensation and employment-
related expenses, including TransCanada’s restricted stock unit and stock option awards, retirement plans, health and
welfare plans, employer-related payroll taxes, matching contributions made under a TransCanada’s employee savings
plan, and premiums for health and life insurance. This reimbursement is determined monthly and calculated based on
total monthly base salary allocated to us multiplied by a factor of .38 for benefits and a factor of .30 for incentive
compensation. The total amount reimbursed for benefits and incentive compensation were $334,678 in 2006 and
$548,665 in 2007.

Director Compensation

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 $20,000 per annum. The independent director appointed as Lead Director and
chair of the Conflicts Committee is entitled to an additional fee of $6,000 per annum, while the independent director
appointed as chair of the Audit Committee is entitled to an additional fee of $4,000 per annum. 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 $1,500 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.

Director Compensation Table

Name

David L. Marshall
Jack F. Jenkins-Stark
Walentin (Val) Mirosh

Fees Earned or
Paid in Cash

60,000
64,500
53,000

Total

60,000
64,500
53,000

In October 2007, a revised compensation plan was approved for independent directors. Effective January 1, 2008, the
directors’ retainer fee was increased to $30,000 per annum from $20,000 per annum and directors will receive an
annual grant of Partnership units under the Deferred Share Unit (DSU) Plan with a value of $20,000, as an equity
component of the annual retainer. No adjustments were made to meeting attendance fees or retainers for the Lead
Director and chair of Conflicts Committee or chair of Audit Committee.

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

Matters

The following table sets forth the beneficial ownership of the voting securities of the Partnership as of February 25,
2008 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 one per cent of TransCanada’s issued and

2007 ANNUAL REPORT

67

outstanding shares. Other than as set forth below, no person is known by the general partner to own beneficially more
than five per cent of the voting securities of the Partnership.

Name and Business Address

Common Units(1) Number of DSUs(2)

Per cent of Class(3)

Amount and Nature of Beneficial Ownership

Number of

TransCan Northern Ltd.(4)
450 1st Street SW
Calgary, Alberta T2P 5H1

TC Pipelines GP, Inc.(5)(6)
450 1st Street SW
Calgary, Alberta T2P 5H1

David L. Marshall(7)
450 1st Street SW
Calgary, Alberta T2P 5H1

Walentin (Val) Mirosh(8)
10th Floor, 1000-7th Avenue SW
Calgary, Alberta T2P 5L5

Jack F. Jenkins-Stark(9)
1999 Harrison Street, Suite 500
Oakland, CA 94612

Gregory A. Lohnes
450 1st Street SW
Calgary, Alberta T2P 5H1

Steven D. Becker
450 1st Street SW
Calgary, Alberta T2P 5H1

Russell K. Girling
450 1st Street SW
Calgary, Alberta T2P 5H1

Kristine L. Delkus
450 1st Street SW
Calgary, Alberta T2P 5H1

Directors and Executive officers as a Group(10)(11)
(12 persons)

(1) A total of 34,856,086 common units are issued and outstanding.

8,678,045

2,035,106

450

–

4,933

–

–

6,000

–

–

–

–

550

550

550

–

–

–

–

–

24.9

5.8

*

*

*

–

–

*

–

*

(2) A deferred share unit is a bookkeeping entry, equivalent to the value of a TC Pipelines common unit, and does not entitle the holder to
voting or other shareholder rights, other than the accrual of additional deferred share units for the value of dividends. A director cannot
redeem deferred share units until the director ceases to be a member of the Board. Directors can then redeem their units for cash or
shares.

(3) Any deferred share units shall be deemed to be outstanding for the purpose of computing the percentage of outstanding common units
owned by such person, but shall not be deemed to be outstanding for the purpose of computing the percentage of common units by
any other person.

(4) TransCan Northern Ltd. is a wholly-owned indirect subsidiary of TransCanada.

(5) TC PipeLines GP, Inc. is a wholly-owned indirect subsidiary of TransCanada.

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TC PIPELINES, LP

(6) TC PipeLines GP, Inc. owns an aggregate of two per cent general partner interest of TC PipeLines.

(7) 450 common units are held directly by Mr. Marshall.

(8) No common units are currently held by Mr. Mirosh.

(9) 4,933 common units are held by the Jenkins-Stark Family Trust dated June 16, 1995.

(10) With the exception of the two named directors above and Russell K. Girling, none of the other directors and executive officers hold any

common units of TC PipeLines.

(11) Walentin (Val) Mirosh holds 726 shares of TransCanada, Russell K. Girling holds 394,108 options and 13,674 shares of TransCanada;

Kristine L. Delkus holds 91,784 options and 3,874 shares of TransCanda; Steven D. Becker holds 103,275 options and 2,620 shares of
TransCanada; Terry C. Ofremchuk holds 6,750 options and 5,216 shares of TransCanada; Gregory A. Lohnes holds 48,497 options and
9,880 shares of TransCanada; Amy W. Leong holds 5,600 options and 3,327 shares of TransCanada; Donald J. DeGrandis holds 17,300
options and 528 shares of TransCanada; Mark A.P. Zimmerman holds 20,413 options and 380 shares of TransCanada and Sean M. Brett
holds 15,500 options of TransCanada, 9,713 shares of TransCanada and 500 Series U preferred shares of TransCanada PipeLines Limited,
a wholly-owned subsidiary of TransCanada. The directors and executive officers as a group hold 703,227 options of TransCanada, 49,938
shares of TransCanada and 500 Series U preferred shares of TransCanada PipeLines Limited. All options listed above are exercisable within
60 days from February 28, 2008.

* Less than one per cent.

Item 13. Certain Relationships and Related Transactions, and Director Independence

At February 28, 2008, TransCan Northern owns 8,678,045 common units and the Partnership’s general partner owns
2,035,106 common units, representing an aggregate 30.1 per cent limited partner interest in the Partnership. In
addition, the general partner owns an aggregate two per cent 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
32.1 per cent by virtue of its indirect ownership of the general partner and 30.1 per cent 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.

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69

• 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. Such costs include (i) overhead costs
(such as office space and equipment) and (ii) out-of-pocket expenses related to the provision of such services. The
Partnership Agreement provides that the general partner will determine the costs that are allocable to the Partnership in
any reasonable manner determined by the general partner in its sole discretion. Total costs charged to the Partnership
by the general partner were $1.9 million for the year ended December 31, 2007.

Pursuant to our Partnership agreement, whenever a potential conflict of interest exists or arises between the general
partner or any of its affiliates and the Partnership, any resolution or course of action by the general partner or its
affiliates in respect of such conflict of interest shall be permitted if the resolution or course of action is deemed to be
fair and reasonable to the Partnership. As such, the general partner has established a Conflicts Committee, of not less
than two independent directors, to oversee all matters relating to the resolution of conflicts of interest and to provide
to our Board of Directors recommendation for such resolution of conflicts of interest.

On February 22, 2007, the Partnership acquired a 46.45 per cent general partner interest in Great Lakes from El Paso
Corporation. The acquisition was partially financed through a private placement of common units for gross proceeds of
$600.0 million which closed concurrently with the acquisition. TransCan Northern purchased 8,678,045 of the
17,356,086 common units issued for gross proceeds of $300 million. In addition, TC PipeLines GP maintained its two
per cent general partner interest in the Partnership by contributing $12.6 million to the Partnership in connection with
the private placement. TransCanada, which previously held a 50 per cent interest in Great Lakes, acquired the other
3.55 per cent interest simultaneously with the Partnership’s acquisition of its interest. A wholly-owned subsidiary of
TransCanada became the operator of Great Lakes through TransCanada’s acquisition of Great Lakes Gas Transmission
Company.

TCNB became the operator of Northern Border effective April 1, 2007. On December 19, 2006, the Partnership
acquired an additional 49 per cent general partner interest in Tuscarora. In connection with this transaction, TCNB
became the operator of Tuscarora. TransCanada and its affiliates provide capital and operating services to our pipeline
systems. TransCanada and its affiliates also incur costs on behalf of our pipeline systems, including, but not limited to,
employee benefit costs, property and liability insurance costs, and transition costs. Total costs charged to our pipeline
systems in 2007 by TransCanada and its affiliates and amounts owed to TransCanada and its affiliates at December 31,
2007 are summarized in the following table:

(millions of dollars)

Great Lakes

Northern Border

Tuscarora

Costs charged by TransCanada and its affiliates
Impact on the Partnership’s net income
Amount owed to TransCanada and its affiliates

25.6
11.2
1.9

22.5
11.0
3.0

1.8
0.9
3.5

70

TC PIPELINES, LP

Great Lakes earns transportation revenues from TransCanada and its affiliates under fixed priced contracts with
remaining terms ranging from one to ten years. Great Lakes earned $113.9 million of transportation revenues under
these contracts for the period February 23, 2007 to December 31, 2007. This amount represents 48.2 per cent of total
revenues earned by Great Lakes for the period February 23, 2007 to December 31, 2007. $52.9 million of
transportation revenue is included in the Partnership’s equity income from Great Lakes during the same period. At
December 31, 2007, $10.0 million is included in Great Lakes’ receivables in regards to the transportation contracts with
TransCanada and its affiliates.

For the year ended December 31, 2007, the Partnership recorded transmission revenues of $19.4 million in regards to
various contracts with Sierra Pacific Power Company, a wholly-owned subsidiary of Sierra Pacific Resources.

On May 8, 2007, the Partnership reimbursed TransCanada $2.8 million for third party costs related to the Partnership’s
acquisition of its interest in Great Lakes. On September 26, 2007, the Partnership reimbursed TransCanada $1.2 million
for a working capital adjustment related to the Partnership’s acquisition of its interest in Great Lakes.

On December 31, 2007, the Partnership acquired a one per cent general partner interest in Tuscarora from a wholly-
owned subsidiary of TransCanada for $2.0 million. The purchase price of this acquisition was derived from the formula
used to calculate the purchase price of a different one per cent general partner interest in Tuscarora which was
purchased from Tuscarora Gas Pipeline Co, a wholly-owned subsidiary of Sierra Pacific Resources on the same day.

Item 14. Principal Accounting Fees and Services

The following table sets forth, for the periods indicated, the fees billed by the principal accountants.

Audit Fees(1)
Audit Related Fees(2)
Tax Fees(3)
All Other Fees(3)

2007

310,745
170,014
–
–

2006

217,803
26,500
–
–

(1) Audit Fees include services performed related to Sarbanes-Oxley Act reporting requirements.

(2) The increase in Audit Related Fees is primarily due to prospectus work in connection with the Great Lakes acquisition.

(3) The Partnership has not engaged its external auditors for any tax or other services in 2007 or 2006.

Audit Fees

Audit fees include fees for the audit of annual GAAP financial statements, reviews of the related quarterly financial
statements and related consents and comforts letters for documents filed with the SEC. Before our independent
principal accountant is engaged each year for annual audit and other audit and any non-audit services, these services
and fees are reviewed and approved by our Audit Committee.

2007 ANNUAL REPORT

71

PART IV

Item 15. Exhibits, Financial Statement Schedules

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) Exhibits

No.

*+2.1

*+2.2

*+2.3

*+2.4

2.5

*3.1

Description

Partnership Interest Purchase and Sale Agreement dated as of December 31, 2005 by and between
Northern Border Intermediate Limited Partnership and TC PipeLines Intermediate Limited Partnership
(Exhibit 2.1 to TC PipeLines, LP’s Form 8-K filed on February 15, 2006 (File No. 000-26091)).

General Partnership Interest Purchase Agreement dated as of November 1, 2006 by and between Tuscarora
Gas Pipeline Co. and TC Tuscarora Intermediate Limited Partnership (Exhibit 2.1 to TC PipeLines, LP’s
Form 8-K filed on November 7, 2006 (File No. 000-26091)).

General Partner Interest Holder Agreement dated as of November 1, 2006 by and between Tuscarora Gas
Pipeline Co. and TC Tuscarora Intermediate Limited Partnership (Exhibit 2.2 to TC PipeLines, LP’s Form 8-K
filed on November 7, 2006 (File No. 000-26091)).

Purchase and Sale Agreement among El Paso Great Lakes Company, L.C.C., as Seller, and TC GL
Intermediate Limited Partnership and TransCanada PipeLine USA Ltd., as Buyers dated as of December 22,
2006 (Exhibit 2.1 to TC PipeLines, LP’s Form 8-K filed on December 26, 2006 (File No. 000-26091)).

General Partnership Interest Purchase Agreement dated as of December 20, 2007 by and between TCPL
Tuscarora Ltd. and TC Pipelines Tuscarora LLC.

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 filed on March 28, 2000 (File No. 333-69947)).

3.1.1 Amendment to the Amended and Restated Agreement of Limited Partnership of TC PipeLines, LP dated

November 19, 2007.

*3.2

*4.1

*4.2

*4.3

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 filed on December 30, 1998).

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, Trustee (Exhibit 4.1 to Northern Border
Pipeline Company’s Form S-4 Registration Statement, Registration No. 333-88577 filed on October 7,
1999).

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 filed on November 13, 2000 (File No.333-69947)).

Indenture dated September 17, 2001, between Northern Border Pipeline Company and Bank One Trust
Company, N.A., Trustee (Exhibit 4.2 to Northern Border Pipeline Company’s Form S-4 Registration
Statement, Registration No. 333-73282 filed on November 13, 2001).

72

TC PIPELINES, LP

No.

Description

*4.4

*10.1

*10.2

*10.3

*10.4

*10.5

*10.6

*10.7

Registration Rights Agreement between TC PipeLines, LP, TransCan Northern Ltd., Kayne Anderson MLP
Investment Company, Kayne Anderson Energy Total Return Fund, Inc., Kayne Anderson MLP Fund, L.P.,
Kayne Anderson Capital Income Partners (QP), L.P., Strome MLP Fund, LP, Royal Bank of Canada, Tortoise
Energy Infrastructure Corporation, Tortoise Energy Capital Corporation, Tortoise North American Energy
Corporation, GPS Income Fund LP, GPS High Yield Equities Fund, HFR RVAGPS Master Trust, GPS New
Equity Fund LP, TPG-Axon Partners, LP, Lehman Brothers Inc., Structured Finance Americas, LLC, The
Cushing MLP Opportunity Fund I, LP, Swank MLP Convergence Fund, LP, and Citigroup Global Markets, Inc.
dated February 22, 2007 (Exhibit 4.1 to TC PipeLines, LP’s Form 8-K filed on February 23, 2007 (File
No. 000-26091)).

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 filed on March 28, 2000 (File
No. 333-69947)).

First Amended and Restated General Partnership Agreement of Northern Border Pipeline Company dated
April 6, 2006, by and between Northern Border Intermediate Limited Partnership and TC Pipelines
Intermediate Limited Partnership (Exhibit 3.1 to Northern Border Pipeline Company’s Form 8-K filed on
April 12, 2006 (File No. 333-87753)).

Revolving Credit Agreement, dated as of April 27, 2007, among Northern Border Pipeline Company, the
lenders from time to time party thereto, SunTrust Bank, as Administrative Agent, Wachovia Bank National
Association, as Syndication Agent, BMO Capital Markets, Citibank, N.A. and Mizuho Corporate Bank, LTD.,
as Co-Documentation Agents, JP Morgan Chase Bank, N.A. and Export Development Canada, as Managing
Agents and Wachovia Capital Markets, LLC and SunTrust Capital Markets, Inc., as Co-Lead Arrangers and
Book Managers. (Exhibit 10.1 to Northern Border Pipeline Company’s Form 10-Q filed on April 30, 2007
(File No. 333-88577)).

Amended and Restated Revolving Credit and Term Loan Agreement among TC PipeLines, LP, the lenders
from time to time party thereto, SunTrust Bank as Administrative Agent, UBS Securities LLC and Royal Bank
of Canada, as Co-Documentation Agents, BMO Capital Markets Financing Inc. and the Royal Bank of
Scotland PLC, as Co-Syndication Agents, Deutsche Bank AG New York Branch and the Bank of Tokyo-
Mitsubishi UFJ, Ltd., as Managing Agents, and SunTrust Capital Markets, Inc. as Arranger and Book
Manager, dated February 13, 2007 (Exhibit 10.1 to TC PipeLines, LP’s Form 8-K filed on February 15, 2007
(File No. 000-26091)).

Subordinated Loan Agreement between TC PipeLines, LP and TransCanada PipeLines Limited, dated
February 13, 2007 (Exhibit 10.2 to TC PipeLines, LP’s Form 8-K filed on February 15, 2007 (File
No. 000-26091)).

Subordination and Intercreditor Agreement among TransCanada PipeLines Limited, TC PipeLines, LP, and
SunTrust Bank, as Administrative Agent, dated February 13, 2007 (Exhibit 10.3 to TC PipeLines, LP’s
Form 8-K filed on February 15, 2007 (File No. 000-26091)).

Common Unit Purchase Agreement by and among TC PipeLines, LP and TransCan Northern Ltd., Kayne
Anderson MLP Investment Company, Kayne Anderson Energy Total Return Fund, Inc., Kayne Anderson MLP
Fund, L.P., Kayne Anderson Capital Income Partners (QP), L.P., Strome MLP Fund, LP, Royal Bank of Canada,
Tortoise Energy Infrastructure Corporation, Tortoise Energy Capital Corporation, Tortoise North American
Energy Corporation, GPS Income Fund LP, GPS High Yield Equities Fund, HFR RVAGPS Master Trust, GPS
New Equity Fund LP, TPG-Axon Partners, LP, Lehman Brothers Inc., Structured Finance Americas, LLC, The
Cushing MLP Opportunity Fund I, LP, Swank MLP Convergence Fund, LP, and Citigroup Global Markets, Inc.
dated February 22, 2007 (Exhibit 10.1 to TC PipeLines, LP’s Form 8-K filed on February 23, 2007 (File
No. 000-26091)).

2007 ANNUAL REPORT

73

No.

*10.8

*10.9

*10.10

*10.11

*10.12

*10.13

*10.14

*10.15

*10.16

*10.17

*10.18

*10.19

10.20

10.21

Description

Form of Conveyance, Contribution and Assumption Agreement among Northern Plains Natural Gas
Company, Northwest Border Pipeline Company, Pan Border Gas Company, Northern Border Partners, L.P.,
and Northern Border Intermediate Limited Partnership. (Exhibit 10.16 to Northern Border Pipeline
Company’s Form S-1 Registration Statement filed on July 16, 1993 (Registration No. 33-66158)).

Form of Contribution, Conveyance and Assumption Agreement among TC PipeLines, L.P., and Northern
Border Intermediate Limited Partnership. (Exhibit 10.2 to TC PipeLines, LP’s Form S-1/A filed on May 3,
1999 (File No. 333-69947)).

Operating Agreement by and between Northern Border Pipeline Company and TransCan Northwest
Border Ltd. (Exhibit 10.2 to Northern Border Pipeline Company’s Form 8-K filed on April 12, 2006 (File
No. 333-88577)).

Operating Agreement by and between Tuscarora Gas Transmission Company and TransCan Northwest
Border Ltd. dated as of December 19, 2006 (Exhibit 10.11 to TC PipeLines, LP’s Form 10-Kfiled on
March 2, 2007 (File No. 000-26091)).

Transportation Service Agreement FT4760 between Great Lakes Gas Transmission Limited Partnership and
TransCanada PipeLines Limited, dated November 30, 2006. (Exhibit 10.1 to TC PipeLines, LP’s Form 10-Q
filed on April 30, 2007 (File No. 000-26091)).

Transportation Service Agreement FT4761 between Great Lakes Gas Transmission Limited Partnership and
TransCanada PipeLines Limited, dated November 4, 2004. (Exhibit 10.2 to TC PipeLines, LP’s Form 10-Q
filed on April 30, 2007 (File No. 000-26091)).

Transportation Service Agreement FT4762 between Great Lakes Gas Transmission Limited Partnership and
TransCanada PipeLines Limited, dated November 4, 2004. (Exhibit 10.3 to TC PipeLines, LP’s Form 10-Q
filed on April 30, 2007 (File No. 000-26091)).

Transportation Service Agreement FT4763 between Great Lakes Gas Transmission Limited Partnership and
TransCanada PipeLines Limited, dated November 4, 2004. (Exhibit 10.4 to TC PipeLines, LP’s Form 10-Q
filed on April 30, 2007 (File No. 000-26091)).

Transportation Service Agreement FT4764 between Great Lakes Gas Transmission Limited Partnership and
TransCanada PipeLines Limited, dated November 30, 2006. (Exhibit 10.5 to TC PipeLines, LP’s Form 10-Q
filed on April 30, 2007 (File No. 000-26091)).

Transportation Service Agreement FT5840 between Great Lakes Gas Transmission Limited Partnership and
TransCanada PipeLines Limited, dated December 1, 2005. (Exhibit 10.6 to TC PipeLines, LP’s Form 10-Q
filed on April 30, 2007 (File No. 000-26091)).

Transportation Service Agreement FT5841 between Great Lakes Gas Transmission Limited Partnership and
TransCanada PipeLines Limited, dated December 1, 2005. (Exhibit 10.7 to TC PipeLines, LP’s Form 10-Q
filed on April 30, 2007 (File No. 000-26091)).

Transportation Service Agreement FT5842 between Great Lakes Gas Transmission Limited Partnership and
TransCanada PipeLines Limited, dated November 30, 2006. (Exhibit 10.8 to TC PipeLines, LP’s Form 10-Q
filed on April 30, 2007 (File No. 000-26091)).

Transportation Service Agreement FT4760 between Great Lakes Gas Transmission Limited Partnership and
TransCanada Pipelines Limited, dated December 7, 2007.

Transportation Service Agreement FT8742 between Great Lakes Gas Transmission Limited Partnership and
TransCanada Pipelines Limited, dated December 6, 2007.

74

TC PIPELINES, LP

No.

Description

*10.22

Amended and Restated Agreement of Limited Partnership of Great Lakes Gas Transmission Limited
Partnership between TransCanada GL, Inc., TC GL Intermediate Limited Partnership and Great Lakes Gas
Transmission Company, dated February 22, 2007. (Exhibit 10.9 to TC PipeLines, LP’s Form 10-Q filed on
April 30, 2007 (File No. 000-26091)).

*10.23

Operating Agreement between Great Lakes Gas Transmission Limited Partnership and Great Lakes Gas
Transmission Company, dated April 5, 1990. (Exhibit 10.10 to TC PipeLines, LP’s Form 10-Q filed on
April 30, 2007 (File No. 000-26091)).

#10.24

The TC PipeLines GP, Inc. Share Unit Plan for Non-Employee Directors (2007), dated October 18, 2007.

21.1

23.1

23.2

23.3

31.1

31.2

32.1

32.2

Subsidiaries of the Registrant.

Consent of KPMG LLP with respect to the financial statements of TC PipeLines, LP

Consent of KPMG LLP with respect to the financial statements of Great Lakes Gas Transmission Limited
Partnership

Consent of KPMG LLP with respect to the financial statements of Northern Border Pipeline Company

Certification of Principal Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

Certification of Principal Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

Certification of Principal Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

Certification of Principal Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

*99.1

Consolidated Balance Sheets of TC PipeLines GP, Inc. as of December 31, 2006 and 2005. (Exhibit 99.1 to
TC PipeLines, LP’s Form 10-Q filed on April 30, 2007 (File No. 000-26091)).

* Indicates exhibits incorporated by reference.

+ Pursuant to item 601(b)(2) of Regulation S-K, the registrant agrees to furnish supplementally a copy of any omitted exhibit or schedule to

the SEC upon request.

# Management contract or compensatory plan or arrangement.

2007 ANNUAL REPORT

75

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly
caused this report to be signed on its behalf by the undersigned, thereunto duly authorized on this 28th day of
February 2008.

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

By: /s/ RUSSELL K. GIRLING

Russell K. Girling
Chairman, Chief Executive Officer and Director
TC PipeLines GP, Inc. (Principal Executive Officer)

By: /s/ AMY W. LEONG

Amy W. Leong
Controller
TC PipeLines GP, Inc. (Principal Financial Officer)

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

Signature

Title

Date

/s/ RUSSELL K. GIRLING

Russell K. Girling

/s/ AMY W. LEONG

Amy W. Leong

/s/ GREGORY A. LOHNES

Gregory A. Lohnes

/s/ KRISTINE L. DELKUS

Kristine L. Delkus

/s/ STEVEN D. BECKER

Steven D. Becker

/s/ WALENTIN (VAL) MIROSH

Walentin (Val) Mirosh

/s/ JACK F. JENKINS-STARK

Jack F. Jenkins-Stark

/s/ DAVID L. MARSHALL

David L. Marshall

Chairman, Chief Executive Officer
and Director (Principal Executive Officer)

February 28, 2008

Controller and Principal Financial Officer

February 28, 2008

Director

Director

Director

Director

Director

Director

February 28, 2008

February 28, 2008

February 28, 2008

February 28, 2008

February 28, 2008

February 28, 2008

F-1

TC PIPELINES, LP

TC PIPELINES, LP
INDEX TO FINANCIAL STATEMENTS

FINANCIAL STATEMENTS OF TC PIPELINES, LP

Reports of Independent Registered Public Accounting Firm

Balance Sheet – December 31, 2007 and 2006

Statement of Income – Years Ended December 31, 2007, 2006 and 2005

Statement of Comprehensive Income – Years Ended December 31, 2007, 2006 and 2005

Statement of Cash Flows – Years Ended December 31, 2007, 2006 and 2005

Statement of Changes in Partners’ Equity – Years Ended December 31, 2007, 2006 and 2005

Notes to Financial Statements

FINANCIAL STATEMENTS OF GREAT LAKES GAS TRANSMISSION LIMITED PARTNERSHIP

Report of Independent Registered Public Accounting Firm

Statement of Income and Partners’ Capital – Years Ended December 31, 2007, 2006 and 2005

Balance Sheet – December 31, 2007 and 2006

Statement of Cash Flows – Years Ended December 31, 2007, 2006 and 2005

Notes to Financial Statements

FINANCIAL STATEMENTS OF NORTHERN BORDER PIPELINE COMPANY

Report of Independent Registered Public Accounting Firm

Balance Sheet – December 31, 2007 and 2006

Statement of Income – Years Ended December 31, 2007, 2006 and 2005

Statement of Comprehensive Income – Years Ended December 31, 2007, 2006 and 2005

Statement of Cash Flows – Years Ended December 31, 2007, 2006 and 2005

Statement of Changes in Partners’ Equity – Years Ended December 31, 2007, 2006 and 2005

Notes to Financial Statements

Page No.

F-2

F-4

F-5

F-5

F-6

F-7

F-8

F-20

F-21

F-22

F-23

F-24

F-28

F-29

F-30

F-30

F-31

F-32

F-33

2007 ANNUAL REPORT

F-2

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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

We have audited the accompanying consolidated balance sheets TC PipeLines, LP (a Delaware limited partnership) and
subsidiaries as of December 31, 2007 and 2006, and the related consolidated 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,
2007. These consolidated financial statements are the responsibility of the General Partner’s management. Our
responsibility is to express an opinion on these consolidated financial statements based on our audits.

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

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the
financial position of TC PipeLines, LP and subsidiaries as of December 31, 2007 and 2006, and the results of their
operations and their cash flows for each of the years in the three-year period ended December 31, 2007, in conformity
with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United
States), TC PipeLines, LP’s internal control over financial reporting as of December 31, 2007, based on criteria
established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the
Treadway Commission (COSO), and our report dated February 27, 2008 expressed an unqualified opinion on the
effectiveness of the Partnership’s internal control over financial reporting.

/s/ KPMG LLP

Calgary, Canada
February 27, 2008

F-3

TC PIPELINES, LP

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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

We have audited TC PipeLines, LP’s internal control over financial reporting as of December 31, 2007, based on criteria
established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the
Treadway Commission (COSO). Management of the General Partner of TC PipeLines, LP is responsible for maintaining
effective internal control over financial reporting and for its assessment of the effectiveness of internal control over
financial reporting, included in the accompanying Management’s Report on Internal Controls over Financial Reporting.
Our responsibility is to express an opinion on the Partnership’s internal control over financial reporting based on our
audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United
States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether
effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining
an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and
testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit
also included performing such other procedures as we considered necessary in the circumstances. We believe that our
audit provides a reasonable basis for our opinion.

An entity’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the
reliability of financial reporting and the preparation of financial statements for external purposes in accordance with
generally accepted accounting principles. An entity’s internal control over financial reporting includes those policies and
procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the
transactions and dispositions of the assets of the entity; (2) provide reasonable assurance that transactions are recorded
as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles,
and that receipts and expenditures of the entity are being made only in accordance with authorizations of management
and directors of the entity; and (3) provide reasonable assurance regarding prevention or timely detection of
unauthorized acquisition, use, or disposition of the entity’s assets that could have a material effect on the financial
statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements.
Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become
inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may
deteriorate.

In our opinion, TC PipeLines, LP maintained, in all material respects, effective internal control over financial reporting as
of December 31, 2007, based on criteria established in Internal Control – Integrated Framework issued by the
Committee of Sponsoring Organizations of the Treadway Commission.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United
States), the consolidated balance sheets of TC PipeLines, LP as of December 31, 2007 and 2006, and the related
consolidated 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, 2007, and our report dated February 27, 2008 expressed an
unqualified opinion on those consolidated financial statements.

/s/ KPMG LLP

Calgary, Canada
February 27, 2008

2007 ANNUAL REPORT

F-4

TC PIPELINES, LP
CONSOLIDATED BALANCE SHEET

December 31 (millions of dollars)

2007

2006

Assets
Current Assets

Cash and short-term investments
Accounts receivable and other

Investment in Great Lakes (Note 3)
Investment in Northern Border (Note 4)
Plant, property and equipment (Note 6)
Goodwill (Note 7)
Other assets

Liabilities and Partners’ Equity
Current Liabilities

Bank indebtedness
Accounts payable
Accrued interest
Current portion of long-term debt (Note 8)

Hedging deferrals
Long-term debt (Note 8)

Non-controlling interests (Note 5)
Partners’ Equity (Note 9)

Common units
General partner
Accumulated other comprehensive (loss)/income

6.8
4.2

11.0

721.1
541.9
134.1
81.7
2.8

1,492.6

1.4
4.8
3.0
4.6

13.8
9.9
568.8

592.5

–

892.3
19.1
(11.3)

900.1

1,492.6

4.0
2.5

6.5

–
561.2
127.0
79.2
3.9

777.8

–
3.3
1.3
4.7

9.3
–
463.4

472.7

1.2

295.6
6.5
1.8

303.9

777.8

Subsequent events (Note 18)

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

F-5

TC PIPELINES, LP

TC PIPELINES, LP
CONSOLIDATED STATEMENT OF INCOME

Year ended December 31 (millions of dollars except per common unit amounts)

Equity income from investment in Great Lakes (Note 3)
Equity income from investment in Northern Border (Note 4)
Equity income from investment in Tuscarora (Note 5)
Transmission revenues
Operating expenses
Depreciation
Financial charges, net and other (Note 10)

Net income

Net income per common unit (Note 11)
Common units outstanding, end of the year (millions)

2007

49.0
61.2
–
27.2
(8.3)
(6.3)
(33.8)

89.0

$2.51
34.9

2006

–
56.6
5.9
0.9
(2.7)
(0.2)
(15.8)

44.7

$2.39
17.5

2005

–
45.7
7.5
–
(2.0)
–
(1.0)

50.2

$2.70
17.5

TC PIPELINES, LP
CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME

Year ended December 31 (millions of dollars)

Net income
Other comprehensive (loss)/income

Change associated with current period hedging transactions (Note 16)
Change associated with current period hedging transactions of investees

Total comprehensive income

2007

2006 2005

89.0

44.7

50.2

(11.4)
(1.7)

1.6
(0.5)

(13.1)

1.1

–
(0.5)

(0.5)

75.9

45.8

49.7

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

2007 ANNUAL REPORT

F-6

TC PIPELINES, LP
CONSOLIDATED STATEMENT OF CASH FLOWS

Year ended December 31 (millions of dollars)

2007

2006

2005

Cash Generated From Operations
Net income
Depreciation
Amortization of other assets (Note 10)
Non-controlling interests (Note 5)
Equity allowance for funds used during construction
Decrease/(increase) in operating working capital

Investing Activities
Return of capital from Great Lakes
Return of capital from Northern Border
Return of capital from Tuscarora
Investment in Great Lakes (Note 3)
Investment in Northern Border (Note 4)
Investment in Tuscarora, net of cash acquired (Notes 5 and 7)
Increase in cash due to the consolidation of Tuscarora (Note 7)
Capital expenditures
Other assets

Financing Activities
Distributions paid (Note 12)
Equity issuances, net
Long-term debt issued (Note 8)
Long-term debt repaid (Note 8)

Increase/(decrease) in cash and short-term investments
Cash and short-term investments, beginning of year

Cash and short-term investments, end of year

Interest payments made

89.0
6.3
0.4
0.2
(0.2)
2.9

98.6

12.3
25.1
–
(733.0)
(7.5)
(3.9)
–
(13.2)
(1.2)

(721.4)

(86.7)
607.0
171.5
(66.2)

625.6

2.8
4.0

6.8

34.3

44.7
0.2
0.9
–
–
0.3

46.1

–
23.8
1.8
–
(311.1)
(97.2)
2.6
–
(1.9)

(382.0)

(43.5)
–
707.0
(325.9)

337.6

1.7
2.3

4.0

13.9

50.2
–
–
–
–
(0.1)

50.1

–
15.2
0.8
–
–
(0.3)
–
–
–

15.7

(43.0)
–
–
(23.0)

(66.0)

(0.2)
2.5

2.3

1.0

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

F-7

TC PIPELINES, LP

TC PIPELINES, LP
CONSOLIDATED STATEMENT OF CHANGES IN PARTNERS’ EQUITY

Accumulated
Other
General Comprehensive
Income/(Loss)
Partner
(millions
(millions
of dollars)
of dollars)

Common Units
(millions
of dollars)

(millions
of units)

17.5
–
–
–

17.5
–
–
–

17.5
–
17.4
–
–

34.9

287.4
47.3
(40.3)
–

294.4
41.8
(40.6)
–

295.6
81.3
594.4
(79.0)
–

892.3

6.3
2.9
(2.7)
–

6.5
2.9
(2.9)
–

6.5
7.7
12.6
(7.7)
–

19.1

1.2
–
–
(0.5)

0.7
–
–
1.1

1.8
–
–
–
(13.1)

(11.3)

Partners’ Equity
(millions
(millions
of dollars)
of units)

17.5
–
–
–

17.5
–
–
–

17.5
–
17.4
–
–

34.9

294.9
50.2
(43.0)
(0.5)

301.6
44.7
(43.5)
1.1

303.9
89.0
607.0
(86.7)
(13.1)

900.1

Partners’ equity at December 31, 2004
Net income
Distributions paid
Other comprehensive loss

Partners’ equity at December 31, 2005
Net income
Distributions paid
Other comprehensive income

Partners’ equity at December 31, 2006
Net income
Equity issuances, net
Distributions paid
Other comprehensive loss

Partners’ equity at December 31, 2007

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

2007 ANNUAL REPORT

F-8

TC PIPELINES, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1 ORGANIZATION

TC PipeLines, LP and its subsidiary limited partnerships and limited liability company, including TC PipeLines Intermediate Limited Partnership,
TC Tuscarora Intermediate Limited Partnership and TC GL Intermediate Limited Partnership, all Delaware limited partnerships, and TC Pipelines
Tuscarora LLC, are collectively referred to herein as TC PipeLines or the Partnership. TC PipeLines was formed by TransCanada PipeLines
Limited, a wholly-owned subsidiary of TransCanada Corporation (collectively referred to herein as TransCanada), to acquire, own and
participate in the management of energy infrastructure assets in North America.

TC PipeLines, through TC GL Intermediate Limited Partnership, owns a 46.45 per cent general partner interest in Great Lakes Gas Transmission
Limited Partnership (Great Lakes), a Delaware limited partnership. Great Lakes owns a 2,115-mile pipeline that transports natural gas serving
markets in Minnesota, Wisconsin, Michigan and Eastern Canada.

TC PipeLines, through TC PipeLines Intermediate Limited Partnership, owns a 50 per cent general partner interest in Northern Border Pipeline
Company (Northern Border), a Texas general partnership. Northern Border owns a 1,249-mile U.S. interstate pipeline system that transports
natural gas from the Montana-Saskatchewan border to markets in the Midwestern U.S.

TC PipeLines also, through TC Tuscarora Intermediate Limited Partnership and TC Pipelines Tuscarora LLC, wholly-owns Tuscarora Gas
Transmission Company (Tuscarora), a Nevada general partnership. Tuscarora owns a 240-mile U.S. interstate pipeline system that transports
natural gas from Oregon, where it interconnects with facilities of Gas Transmission Northwest Corporation (GTN), a wholly-owned subsidiary of
TransCanada, to Northern Nevada.

TC PipeLines is managed by its general partner, TC PipeLines GP, Inc. (TC PipeLines GP), a wholly-owned subsidiary of TransCanada. The
general partner provides administrative services for the Partnership and is reimbursed for its costs and expenses. In addition to its aggregate
two per cent general partner interest in TC PipeLines, on a combined basis, the general partner owns 2,035,106 common units, representing
an effective 7.7 per cent limited partner interest in the Partnership at December 31, 2007. TransCanada also indirectly holds 8,678,045
common units representing an effective 24.4 per cent limited partner interest in the Partnership at December 31, 2007.

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, 2007 and 2006
and the results of its operations, cash flows and changes in partners’ equity for the years ended December 31, 2007, 2006 and 2005. The
Partnership uses the equity method of accounting for its investments in Great Lakes and Northern Border, over which it is able to exercise
significant influence. TC PipeLines accounted for its investment in Tuscarora using the equity method until December 19, 2006. On this date,
the Partnership acquired an additional 49 per cent general partner interest in Tuscarora and as a result of acquiring a controlling interest in
Tuscarora, began to consolidate Tuscarora’s operations. Amounts are stated in U.S. dollars. Certain comparative figures have been reclassified
to conform to the current year’s presentation.

(b) Use of Estimates
The preparation of financial statements in conformity with generally accepted accounting principles 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 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.

(c) Cash and Short-Term Investments
The Partnership’s short-term investments with original maturities of three months or less are considered to be cash equivalents and are
recorded at cost, which approximates market value.

(d) Plant, Property and Equipment
Plant, property and equipment relates solely to Tuscarora and is stated at original cost. Costs of restoring the land above and around the
pipeline are capitalized to pipeline facilities and depreciated over the remaining life of the related pipeline facilities. Depreciation of pipeline
facilities and compression equipment is provided on a straight-line composite basis over the estimated useful life of the pipeline of 30 years
and of the compression equipment of 25 years. Metering and other is depreciated on a straight-line basis over the estimated useful lives of
the equipment, which range from 3 to 30 years. Repair and maintenance costs are expensed as incurred. Costs that are considered a

F-9

TC PIPELINES, LP

betterment are capitalized. An allowance for funds used during construction, using the rate of return on rate base approved by the Federal
Energy Regulatory Commission (FERC), is capitalized and included in the cost of plant, property and equipment.

Long-lived assets are assessed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may
not be recoverable. Recoverability is assessed by comparing the carrying amount of an asset to future net cash flows expected to be
generated by the asset. If such assets are considered to be impaired, the impairment to be recognized is measured by the amount by which
the carrying amounts of such assets exceed the fair value of the assets.

(e) Partners’ Equity
Costs incurred in connection with the issuance of units are deducted from the proceeds received.

(f) Revenue Recognition
Transmission revenues are recognized in the period in which the service is provided. When rate cases are pending final FERC approval, a
portion of revenue collected is subject to possible refund. As of December 31, 2007, the Partnership has not recognized any transmission
revenue that is subject to refund.

Income Taxes

(g)
As a partnership, TC PipeLines is not subject to Federal or state income tax. The tax effect of the Partnership’s activities accrues to its partners.
The Partnership’s taxable income or loss, which may vary substantially from the net income or loss reported in the consolidated statement of
income, is includable in the federal income tax returns of each partner. The aggregate difference in the basis of the Partnership’s net assets for
financial and income tax purposes cannot be readily determined because all information regarding each partner’s tax attributes related to the
partnership is not available.

(h) Acquisitions and Goodwill
The Partnership accounts for business acquisitions using the purchase method of accounting and accordingly the assets and liabilities of the
acquired entities are recorded at their estimated fair values at the date of acquisition. The excess of the purchase price over the fair value of
net assets acquired is attributed to goodwill. Goodwill is not amortized for accounting purposes; however, it is tested on an annual basis for
impairment, or more frequently if any indicators of impairment are evident.

(i) Derivative Financial Instruments and Hedging Activities
The Partnership utilizes derivative and other financial instruments to manage its exposure to changes in interest rates. Derivatives and other
instruments must be designated as hedges and be effective to qualify for hedge accounting. Derivatives are recorded at their fair value at each
balance sheet date. For cash flow hedges, unrealized gains or losses relating to derivatives are recognized as other comprehensive income. In
the event that a derivative does not meet the designation or effectiveness criteria, any unrealized gain or loss on the instrument is recognized
immediately in earnings.

If a derivative that previously qualified as a hedge is settled, de-designated or ceases to be effective, the gain or loss at that date is deferred
and recognized in the same period and in the same financial statement category as the corresponding hedged transactions. If a hedged
anticipated transaction is no longer probable to occur, related gains or losses are immediately recognized in earnings and amounts previously
recognized in other comprehensive income are reclassified to earnings prospectively. Costs associated with the purchase of certain hedging
instruments are deferred and amortized against interest expense.

(j) Asset Retirement Obligation
Statement of Financial Accounting Standards (SFAS) No. 143, Accounting for Asset Retirement Obligations, provides accounting requirements
for the recognition and measurement of liabilities associated with the retirement of tangible long-lived assets. Under the standard, these
liabilities are recognized at fair value as incurred and capitalized as part of the cost of the related tangible long-lived assets. Accretion of the
liabilities due to the passage of time is classified as an operating expense. Retirement obligations associated with long-lived assets included
within the scope of SFAS No. 143 are those for which a legal obligation exists under enacted laws, statutes, ordinances, or written or oral
contracts, including obligations arising under the doctrine of promissory estoppel.

FIN 47, Accounting for Conditional Asset Retirement Obligations – an interpretation of SFAS No. 143, clarifies the term ‘‘conditional asset
retirement obligation,’’ as used in SFAS No. 143 and the circumstances under which an entity would have sufficient information to reasonably
estimate the fair value of an asset retirement obligation. No amount is recorded for asset retirement obligations relating to the assets as it is
not possible to make a reasonable estimate of the fair value of the liability due to the inability to determine the scope and timing of the asset

2007 ANNUAL REPORT

F-10

retirements. Management believes it is reasonable to assume that all retirement costs associated with the pipeline system will be recovered
through rates in future periods.

(k) Government Regulation
Tuscarora, our wholly-owned pipeline system, is subject to regulation by the FERC. The Partnership’s accounting policies conform to SFAS
No. 71, Accounting for the Effects of Certain Types of Regulation. Accordingly, certain assets or liabilities that result from the regulated
ratemaking process are recorded that would not be recorded under generally accepted accounting principles for non-regulated entities. The
Partnership regularly evaluates the continued applicability of SFAS No. 71, considering such factors as regulatory changes, the impact of
competition, and the ability to recover regulatory assets. As of December 31, 2007 and 2006, the Partnership has no regulatory assets or
liabilities.

NOTE 3 INVESTMENT IN GREAT LAKES

On February 22, 2007, the Partnership acquired a 46.45 per cent general partner interest in Great Lakes. TransCanada, which previously held a
50 per cent interest in Great Lakes, acquired the other 3.55 per cent interest concurrent with the Partnership’s acquisition of its interest.
Effective February 22, 2007, a wholly-owned subsidiary of TransCanada became the operator of Great Lakes. Great Lakes is regulated by the
FERC.

TC GL Intermediate Limited Partnership, as one of the general partners, may be exposed to the commitments and contingencies of Great
Lakes. TC PipeLines, LP holds a 98.9899 per cent limited partnership interest in TC GL Intermediate Limited Partnership.

The Partnership uses the equity method of accounting for its investment in Great Lakes. TC PipeLines’ equity income from its investment in
Great Lakes amounted to $49.0 million for the period February 23, 2007 to December 31, 2007. Great Lakes had no undistributed earnings
for the year ended December 31, 2007.

The following sets out summarized financial information for Great Lakes as at December 31, 2007 and for the period February 23, 2007 to
December 31, 2007:

Summarized Consolidated Great Lakes Balance Sheet

December 31 (millions of dollars)

Assets
Cash and short-term investments
Other current assets
Plant, property and equipment, net

Liabilities and Partners’ Equity
Current liabilities
Deferred credits
Long-term debt, including current maturities
Partners’ capital

Summarized Consolidated Great Lakes Income Statement

For the period February 23 to December 31 (millions of dollars)

Transmission revenues
Operating expenses
Depreciation
Financial charges, net and other

Net income

2007

32.0
55.5
969.2

1,056.7

50.7
0.4
440.0
565.6

1,056.7

2007

236.2
(53.7)
(49.4)
(27.6)

105.5

F-11

TC PIPELINES, LP

NOTE 4 INVESTMENT IN NORTHERN BORDER

The Partnership owns a 50 per cent general partner interest in Northern Border. The remaining 50 per cent partnership interest in Northern
Border is held by ONEOK Partners, L.P. (ONEOK), a publicly traded limited partnership. The Northern Border system was operated by ONEOK
Partners GP, LLC (ONEOK Partners GP), a wholly-owned subsidiary of ONEOK, Inc. during the three months ended March 31, 2007. Effective
April 1, 2007, TransCanada Northern Border Inc. (TCNB), a wholly-owned subsidiary of TransCanada, became the operator of Northern Border.
Northern Border is regulated by the FERC.

TC PipeLines Intermediate Limited Partnership, as one of the general partners, may be exposed to the commitments and contingencies of
Northern Border. TC PipeLines, LP holds a 98.9899 per cent limited partnership interest in TC PipeLines Intermediate Limited Partnership.

On April 6, 2006, the Partnership acquired an additional 20 per cent general partner interest in Northern Border. The Partnership uses the
equity method of accounting for its investment in Northern Border. TC PipeLines’ equity income for the year ended December 31, 2006
includes 30 per cent of the net income of Northern Border up to April 6, 2006 and 50 per cent thereafter. Equity income from Northern
Border includes amortization of a $10 million transaction fee paid to the operator of Northern Border as an inducement to become operator
at the time of the additional 20 per cent acquisition in April 2006. TC PipeLines’ equity income from its investment in Northern Border
amounted to $61.2 million for the year ended December 31, 2007 (2006 – $56.6 million; 2005 – $45.7 million). Northern Border had no
undistributed earnings for the years ended December 31, 2007, 2006 and 2005.

The following sets out summarized financial information for Northern Border as at December 31, 2007 and 2006 and for the years ended
December 31, 2007, 2006 and 2005:

Summarized Northern Border Balance Sheet

December 31 (millions of dollars)

Assets
Cash and short-term investments
Other current assets
Plant, property and equipment, net
Other assets

Liabilities and Partners’ Equity
Current liabilities
Deferred credits and other
Long-term debt, including current maturities and notes payable
Partners’ equity

Partners’ capital
Accumulated other comprehensive (loss)/income

Summarized Northern Border Income Statement

Year ended December 31 (millions of dollars)

Transmission revenues
Operating expenses
Depreciation
Financial charges, net and other

Net income

NOTE 5 INVESTMENT IN TUSCARORA

2007

2006

22.9
39.8
1,428.3
23.9

1,514.9

53.4
8.1
615.3

840.5
(2.4)

1,514.9

2007

309.4
(83.5)
(60.7)
(41.1)

124.1

11.0
35.5
1,475.7
22.5

1,544.7

47.7
2.1
619.8

874.1
1.0

1,544.7

2006

310.9
(81.0)
(58.7)
(41.3)

129.9

2005

321.7
(70.8)
(58.1)
(40.5)

152.3

As of December 31, 2007, the Partnership wholly-owns Tuscarora. On December 19, 2006, the Partnership acquired an additional 49 per cent
general partner interest in Tuscarora from Tuscarora Gas Pipeline Co., a wholly-owned subsidiary of Sierra Pacific Resources. Prior to this
acquisition, the Partnership used the equity method of accounting for its investment in Tuscarora. Subsequent to this acquisition, the
Partnership used the consolidation method of accounting for its investment in Tuscarora. On December 31, 2007, the Partnership acquired the

2007 ANNUAL REPORT

F-12

remaining two per cent general partner interest in Tuscarora, with one per cent purchased from a wholly-owned subsidiary of TransCanada
and the other one per cent purchased from Tuscarora Gas Pipeline Co. Tuscarora is operated by TCNB. Tuscarora is regulated by the FERC.

The Partnership recorded net income from Tuscarora under the consolidation method of $11.4 million and $0.4 million for the year ended
December 31, 2007 and the period December 20, 2006 to December 31, 2006, respectively. TC PipeLines’ equity income from its investment
in Tuscarora amounted to $5.9 million and $7.5 million for the period January 1, 2006 to December 19, 2006 and the year ended
December 31, 2005, respectively. Tuscarora had no undistributed earnings for the years ended December 31, 2007, 2006 and 2005. For the
year ended December 31, 2007, the following customers contributed to more than 10 per cent of Tuscarora’s revenue: Sierra Pacific Power
Company (72 per cent), Southwest Gas Company (13 per cent) and Barrick Goldstrike Mines (11 per cent).

The following sets out summarized financial information for Tuscarora as at December 31, 2007 and 2006 and for the years ended
December 31, 2007, 2006 and 2005:

Summarized Tuscarora Balance Sheet

December 31 (millions of dollars)

Assets
Cash and short-term investments
Other current assets
Plant, property and equipment, net
Other assets

Liabilities and Partners’ Equity
Current liabilities
Long-term debt, including current maturities
Partners’ equity

Partners’ capital
Accumulated other comprehensive income

Summarized Tuscarora Income Statement

Year ended December 31 (millions of dollars)

Transmission revenues
Operating expenses
Depreciation
Financial charges, net and other

Net income

Summarized Tuscarora Cash Flow Statement

Year ended December 31 (millions of dollars)

Cash flows provided by operating activities
Cash flows used in investing activities
Cash flows used in financing activities

Increase/(decrease) in cash and short-term investments
Cash and short-term investments, beginning of year

Cash and short-term investments, end of year

2007

5.5
2.6
134.1
1.2

143.4

6.1
66.4

70.9
–

143.4

2007

27.2
(4.9)
(6.3)
(4.4)

11.6

2007

19.9
(13.2)
(3.4)

3.3
2.2

5.5

2006

2.2
2.5
127.0
1.2

132.9

2.4
71.1

59.3
0.1

132.9

2006

29.5
(4.7)
(6.2)
(5.3)

13.3

2006

20.5
(1.5)
(20.6)

(1.6)
3.8

2.2

2005

32.3
(4.4)
(6.2)
(5.6)

16.1

2005

22.3
(0.9)
(21.2)

0.2
3.6

3.8

F-13

TC PIPELINES, LP

NOTE 6 PLANT, PROPERTY AND EQUIPMENT

2007

Accumulated
Depreciation

Net Book Value

53.1
5.5
3.1
–

61.7

93.5
19.5
7.9
13.2

134.1

Cost

146.6
25.0
11.0
13.2

195.8

2006

Accumulated
Depreciation

Net Book Value

48.2
4.5
2.7
–

55.4

97.9
20.5
7.3
1.3

127.0

Cost

146.1
25.0
10.0
1.3

182.4

December 31
(millions of dollars)

Tuscarora
Pipeline
Compression
Metering and other
Under construction

NOTE 7 ACQUISITIONS

Great Lakes
On February 22, 2007, the Partnership acquired a 46.45 per cent general partner interest in Great Lakes from El Paso Corporation (El Paso).
The total purchase price was $942.4 million, subject to certain closing adjustments, and included the indirect assumption of $209.0 million of
debt. The acquisition was partially financed through a private placement of common units for gross proceeds of $600.0 million which closed
concurrently with the acquisition. In addition, TC PipeLines GP maintained its two per cent general partner interest in the Partnership by
contributing $12.6 million to the Partnership in connection with the private placement. The Partnership funded the balance of the total
consideration with a draw on its senior credit facility, which was amended and restated in connection with the acquisition.

The acquisition was accounted for using the purchase method of accounting. The purchase price was allocated using an estimate of fair value
of the net assets at the date of acquisition. The difference between the purchase price and the estimated fair value of net assets of
$457.5 million, being goodwill, was recorded as part of the Partnership’s investment in Great Lakes.

Great Lakes’ business is subject to rate regulation based on historical costs which do not change with market conditions or change of
ownership. Accordingly, upon acquisition, the assets and liabilities of Great Lakes were determined to have a fair value equal to the rate
regulated historical costs. No intangibles other than goodwill were identified in the acquisition.

TransCanada, which previously held a 50 per cent interest in Great Lakes, acquired the other 3.55 per cent general partner interest
simultaneously with the Partnership’s acquisition of its interest. In connection with these transactions, a wholly-owned subsidiary of
TransCanada became the operator of Great Lakes.

Northern Border
On April 6, 2006, the Partnership acquired an additional 20 per cent general partner interest in Northern Border for $298.0 million plus a
$10.0 million transaction fee payable to TCNB, bringing the Partnership’s total interest to 50 per cent. Through the acquisition, TC PipeLines
indirectly assumed $121.7 million of debt. The Partnership funded the transaction through a Bridge Loan Credit Facility (see note 8). In
connection with this transaction, TCNB became the operator of Northern Border in April 2007.

The acquisition was accounted for using the purchase method of accounting. The purchase price was allocated using an estimate of fair value
of the net assets at the date of acquisition. The difference between the purchase price and the fair value of net assets of $115.0 million,
being goodwill, was recorded as part of the Partnership’s investment in Northern Border. The $10.0 million transaction fee payable to the
operator has been recorded as part of the Partnership’s investment in Northern Border and is being amortized over the term of the related
operating agreement.

Northern Border’s business is subject to rate regulation based on historical costs which do not change with market conditions or change of
ownership. Accordingly, upon acquisition, the assets and liabilities of Northern Border were determined to have a fair value equal to the rate
regulated historical costs. No intangibles other than goodwill were identified in the acquisition.

Tuscarora
On December 19, 2006, the Partnership acquired an additional 49 per cent general partnership interest in Tuscarora for $99.8 million.
Through the acquisition TC PipeLines indirectly assumed $37.5 million of Tuscarora debt. The Partnership funded the transaction through the
Senior Credit Facility (see note 8). In connection with this transaction, TCNB became the operator of Tuscarora.

The acquisition was accounted for using the purchase method of accounting. The purchase price was allocated as follows using an estimate of
fair value of the assets acquired and liabilities assumed at the date of acquisition:

2007 ANNUAL REPORT

F-14

Purchase Price Allocation

(millions of dollars)

Current assets
Plant, property and equipment
Other non-current assets
Goodwill
Current liabilities
Long-term debt
Non-controlling interests

Acquisition of
additional 49% interest

4.7
56.6
0.7
79.1
(2.6)
(37.5)
(1.2)

99.8

On December 31, 2007, the Partnership acquired the other two per cent general partner interest in Tuscarora. One per cent was purchased
from a wholly-owned subsidiary of TransCanada, while the other one per cent was purchased from Tuscarora Gas Pipeline Co. for a total
purchase price of $3.9 million. The acquisitions were accounted for using the purchase method of accounting. The difference between the
combined purchase prices and the non-controlling interest recorded on the Partnership’s balance sheet of $2.6 million was recorded as
goodwill.

Tuscarora’s business is subject to rate regulation based on historical costs which do not change with market conditions or change of
ownership. Accordingly, upon acquisition, the assets and liabilities of Tuscarora were determined to have a fair value equal to the rate
regulated historical costs. No intangibles other than goodwill were identified in the acquisitions.

Pro forma financial information for the Great Lakes, Northern Border and Tuscarora acquisitions
The following unaudited Partnership pro forma financial information for the years ended December 31, 2007 and 2006 has been prepared as
if the significant acquisitions mentioned above occurred on January 1, 2006:

Year ended December 31 (millions of dollars except per unit amounts)

Equity income from investment in Great Lakes
Equity income from investment in Northern Border
Transmission revenues
Net income
Net income per common unit

NOTE 8 CREDIT FACILITIES AND LONG-TERM DEBT

(millions of dollars)

Senior Credit Facility
Series A Senior Notes
Series B Senior Notes
Series C Senior Notes

2007

59.6
61.2
27.2
98.3
$2.58

2007

507.0
54.5
5.5
6.4

573.4

2006

56.8
64.1
29.5
99.9
$2.70

2006

397.0
57.9
6.0
7.2

468.1

On February 28, 2006, the Partnership renewed a $20.0 million unsecured credit facility (Revolving Credit Facility). In 2006, TC PipeLines
repaid the Revolving Credit Facility in full and it was terminated. The interest rate on the Revolving Credit Facility averaged 5.60 per cent for
the year ended December 31, 2006.

On March 31, 2006, the Partnership entered into an unsecured credit agreement for a $310.0 million credit facility (Bridge Loan Credit Facility)
with a banking syndicate. Borrowings under the Bridge Loan Credit Facility bore interest, at the option of the Partnership, at the LIBOR or the
base rate plus an applicable margin. On April 5, 2006, the Partnership borrowed $307.0 million under the Bridge Loan Credit Facility to
finance the purchase price and a $10.0 million transaction fee payable in connection with the acquisition of an additional 20 per cent general
partner interest in Northern Border. The remaining $3.0 million commitment under the Bridge Loan Credit Facility was terminated. On
December 12, 2006, the Bridge Loan Credit Facility was refinanced through a $297.0 million draw on a $410.0 million credit agreement

F-15

TC PIPELINES, LP

(Senior Credit Facility) with a banking syndicate and the use of $10.0 million cash on hand. The interest rate on the Bridge Loan Credit Facility
averaged 6.29 per cent for the year ended December 31, 2006.

On December 12, 2006, the Partnership entered into a credit agreement for the Senior Credit Facility. On December 19, 2006, TC PipeLines
borrowed an additional $100.0 million under the Senior Credit Facility to finance the purchase price of an additional 49 per cent general
partner interest in Tuscarora.

On February 13, 2007, the Senior Credit Facility was amended and restated in connection with the Great Lakes acquisition. The amount
available under the Senior Credit Facility increased from $410.0 million to $950.0 million, consisting of a $700.0 million senior term loan and
a $250.0 million senior revolving credit facility, with $194.0 million of the senior term loan available being terminated upon closing of the
Great Lakes acquisition. In accordance with the Senior Credit Facility agreement, once repaid, a senior term loan cannot be re-borrowed. On
November 29, 2007, $18.0 million of the senior term loan was repaid and hence terminated, leaving $488.0 million available and outstanding
under the senior term loan. At December 31, 2007, $19.0 million is outstanding under the senior revolving credit facility, leaving
$231.0 million available for future borrowings.

The Senior Credit Facility matures on December 12, 2011, at which time all amounts outstanding will be due and payable. Amounts borrowed
may be repaid in part or in full prior to that time without penalty. Borrowings under the Senior Credit Facility will bear interest based, at the
Partnership’s election, on the LIBOR or the prime rate plus, in either case, an applicable margin. There was $507.0 million outstanding under
the Senior Credit Facility at December 31, 2007 (2006 – $397.0 million). The interest rate on the Senior Credit Facility averaged 6.01 per cent
for the year ended December 31, 2007 (2006 – 6.16 per cent). After hedging activity, the interest rate incurred on the Senior Credit Facility
averaged 5.75 per cent for the year ended December 31, 2007. Prior to hedging activities, the interest rate was 5.62 per cent at
December 31, 2007 (2006 – 6.07 per cent). At December 31, 2007, the Partnership was in compliance with its financial covenants.

In 1995, Tuscarora issued $91.7 million of 7.13 per cent senior secured notes, which mature on December 21, 2010 (Series A). In 2000,
Tuscarora issued $8.0 million of 7.99 per cent senior secured notes, which mature on December 21, 2010 (Series B). In 2002, Tuscarora issued
$10.0 million of 6.89 per cent senior secured notes, which mature on December 21, 2012 (Series C). The Series A, Series B and Series C notes
(collectively, the Notes) have a final payment at maturity of $46.7 million, $4.1 million and $2.7 million, respectively. The Notes are secured by
Tuscarora’s transportation contracts, supporting agreements and substantially all of Tuscarora’s property. The credit agreement for the Notes
contains certain provisions that include, among other items, limitations on additional indebtedness and distributions to partners.

Annual maturities of the Senior Credit Facility and the Notes are summarized as follows:

(millions of dollars)

2008
2009
2010
2011
2012

NOTE 9 PARTNERS’ EQUITY

4.6
4.4
53.5
507.8
3.1

573.4

On February 22, 2007, the Partnership completed a private placement of 17,356,086 common units at $34.57 per common unit for gross
proceeds of $600.0 million which closed concurrently with the Great Lakes acquisition. TransCan Northern Ltd. (TransCan Northern), a wholly-
owned subsidiary of TransCanada, purchased 8,678,045 of

the 17,356,086 common units issued for gross proceeds of $300.0 million. In addition, TC PipeLines GP maintained its two per cent general
partner interest in the Partnership by contributing $12.6 million to the Partnership in connection with the private placement.

At December 31, 2007, Partners’ equity consists of 34,856,086 common units representing an aggregate 98 per cent limited partner interest
in the Partnership (including 2,035,106 common units held by the general partner and 8,678,045 common units held by TransCan Northern)
and an aggregate two per cent general partner interest. In aggregate, the general partner’s interests represent an effective 7.7 per cent
ownership in the Partnership at December 31, 2007 (December 31, 2006 – 13.4 per cent).

NOTE 10 FINANCIAL CHARGES, NET AND OTHER

Year ended December 31 (millions of dollars)

Interest expense on long-term debt
Interest expense on short-term debt
Interest income
Amortization of other assets
Other

2007 ANNUAL REPORT

F-16

2007

34.9
0.3
(0.9)
0.4
(0.9)

33.8

2006

14.8
0.3
(0.4)
0.9
0.2

15.8

2005

–
1.1
(0.1)
–
–

1.0

NOTE 11 NET INCOME PER COMMON UNIT

Net income per common unit is computed by dividing net income, after deduction of the general partner’s allocation, by the weighted
average number of common units outstanding. The general partner’s allocation is equal to an amount based upon the general partner’s two
per cent interest, adjusted to reflect an amount equal to incentive distributions. Incentive distributions are received by the general partner if
quarterly cash distributions on the common units exceed levels specified in the partnership agreement. Net income per common unit was
determined as follows:

Year ended December 31 (millions of dollars except per unit amounts)

Net income

Net income allocated to general partner

General partner interest
Incentive distribution income allocation

Net income allocable to common units
Weighted average common units outstanding (millions)

Net income per common unit

NOTE 12 CASH DISTRIBUTIONS

2007

89.0

(1.8)
(5.9)

(7.7)

81.3
32.3

$2.51

2006

44.7

(0.9)
(2.0)

(2.9)

41.8
17.5

$2.39

2005

50.2

(1.0)
(1.9)

(2.9

47.3
17.5

$2.70

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 currently receive a quarterly distribution of $0.665 per unit if and to the extent
there is sufficient available cash.

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 per cent, 25 per cent, and 50 per cent of all quarterly distributions of
Available Cash that exceed target levels of $0.45, $0.5275 and $0.69, respectively, per unit. For the year ended December 31, 2007, the
Partnership distributed $2.565 per unit (2006 – $2.325 per unit; 2005 – $2.30 per unit). The distributions for the year ended December 31,
2007 included incentive distributions to the general partner in the amount of $5.9 million (2006 – $2.0 million; 2005 – $1.9 million).
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 per cent to the general partner.

NOTE 13 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. Such costs
include (i) overhead costs (such as office space and equipment) and (ii) out-of-pocket expenses related to the provision of such services. The
Partnership Agreement provides that the general partner will determine the costs that are allocable to the Partnership in any reasonable
manner determined by the general partner in its sole discretion. Total costs charged to the Partnership by the general partner were
$1.9 million for the year ended December 31, 2007 (2006 – $1.2 million; 2005 – $1.1 million).

F-17

TC PIPELINES, LP

A wholly-owned subsidiary of TransCanada became the operator of Great Lakes through TransCanada’s acquisition of Great Lakes Gas
Transmission Company on February 22, 2007. On December 19, 2006, the Partnership acquired an additional 49 per cent general partner
interest in Tuscarora. In connection with this transaction, TCNB became the operator of Tuscarora. TransCanada and its affiliates provide capital
and operating services to our pipeline systems. TransCanada and its affiliates incur costs on behalf of our pipeline systems, including, but not
limited to, employee benefit costs, property and liability insurance costs, and transition costs. Total costs charged to our pipeline systems in
2007 by TransCanada and its affiliates and amounts owed to TransCanada and its affiliates at December 31, 2007 are summarized in the
following table:

(millions of dollars)

Costs charged by TransCanada and its affiliates
Impact on the Partnership’s net income
Amount owed to TransCanada and its affiliates

Great Lakes

Northern Border

Tuscarora

25.6
11.2
1.9

22.5
11.0
3.0

1.8
0.9
3.5

Great Lakes earns transportation revenues from TransCanada and its affiliates under fixed priced contracts with remaining terms ranging from
one to ten years. Great Lakes earned $113.9 million of transportation revenues under these contracts for the period February 23, 2007 to
December 31, 2007. This amount represents 48.2 per cent of total revenues earned by Great Lakes for the period February 23, 2007 to
December 31, 2007. $52.9 million of transportation revenue is included in the Partnership’s equity income from Great Lakes during the same
period. At December 31, 2007, $10.0 million is included in Great Lakes’ receivables in regards to the transportation contracts with
TransCanada and its affiliates.

For the year ended December 31, 2007, the Partnership recorded transmission revenues of $19.4 million in regards to various contracts with
Sierra Pacific Power Company, a wholly-owned subsidiary of Sierra Pacific Resources.

On April 6, 2006, the Partnership acquired an additional 20 per cent general partner interest in Northern Border. At the time of this
transaction, the Partnership paid a $10.0 million transaction fee to TransCanada Northern Border related to the assumption of operatorship.
This fee has been recorded as part of the Partnership’s investment in Northern Border and is being amortized over the term of the related
operating agreement partially offsetting equity income.

On May 8, 2007, the Partnership reimbursed TransCanada $2.8 million for third party costs related to the Partnership’s acquisition of its
interest in Great Lakes. On September 26, 2007, the Partnership reimbursed TransCanada $1.2 million for a working capital adjustment related
to the Partnership’s acquisition of its interest in Great Lakes.

On December 31, 2007, the Partnership acquired a one per cent general partner interest in Tuscarora from a wholly-owned subsidiary of
TransCanada for $2.0 million. The purchase price of this acquisition was derived from the formula used to calculate the purchase price of a
separate one per cent general partner interest in Tuscarora which was purchased from Tuscarora Gas Pipeline Co. on the same day.

NOTE 14 QUARTERLY FINANCIAL DATA (unaudited)

The following sets forth selected financial data for the four quarters of each of 2007 and 2006.

Quarter ended (millions of dollars except per unit amounts)

Mar 31

Jun 30

Sep 30

Dec 31

2007
Equity income
Transmission revenues
Net income
Net income per common unit
Cash distributions paid

2006
Equity income
Transmission revenues
Net income
Net income per common unit
Cash distributions paid

24.8
6.9
20.0
$0.73
11.3

13.2
–
12.4
$0.67
10.7

23.4
6.7
17.7
$0.45
24.9

13.9
–
9.0
$0.47
10.8

30.4
6.7
24.6
$0.64
25.1

17.9
–
12.0
$0.65
10.7

31.6
6.9
26.7
$0.70
25.4

17.5
0.9
11.3
$0.60
11.3

2007 ANNUAL REPORT

F-18

NOTE 15 CAPITAL REQUIREMENTS

On April 30, 2007, the Partnership made a contribution of $7.5 million to Northern Border, representing the Partnership’s 50 per cent share of
a $15.0 million cash call issued by Northern Border. The funds were used by Northern Border to repay indebtedness.

Tuscarora incurred $13.2 million of capital expenditures during 2007, of which $12.2 million related to its compressor station expansion in
Likely, California. These capital expenditures were funded with operating cash flows.

The Partnership contributed $3.1 million to Northern Border during 2006, representing its then 30 per cent share of a $10.3 million cash call
issued by Northern Border. The funds were used by Northern Border to fund an expansion project.

NOTE 16 DERIVATIVE FINANCIAL INSTRUMENTS

The carrying value of cash and short-term investments, accounts receivable and other, accounts payable and accrued interest approximate their
fair values because of the short maturity or duration of these instruments, or because the instruments carry a variable rate of interest or a rate
that approximates current rates. The fair value of the Partnership’s long-term debt is estimated by discounting the future cash flows of each
instrument at current borrowing rates.

The estimated fair values of the Partnership’s and its subsidiary’s long-term debt as of December 31, 2007 and 2006 are as follows:

(millions of dollars)

Senior Credit Facility
Series A Senior Notes
Series B Senior Notes
Series C Senior Notes

2007

2006

Carrying Value

Fair Value

Carrying Value

Fair Value

507.0
54.5
5.5
6.4

573.4

507.0
58.7
6.0
7.0

578.7

397.0
57.9
6.0
7.2

468.1

397.0
60.9
6.4
7.5

471.8

The Partnership’s short-term and long-term debt results in exposures to changing interest rates. The Partnership uses derivatives to assist in
managing its exposure to interest rate risk.

At December 31, 2007, the fair value of the interest rate swaps and options accounted for as hedges was negative $9.8 million (2006 –
positive $1.6 million). The fair value of interest rate swaps and options have been calculated using year-end market rates. The notional amount
hedged was $475.0 million as at December 31, 2007 (2006 – $200.0 million). $300.0 million of variable-rate debt is hedged by an interest
rate swap during the period from March 12, 2007 through December 12, 2011, where the weighted average fixed interest rate paid is
4.89 per cent. $100.0 million of variable-rate debt is hedged by an interest rate option during the period from May 22, 2007 through
May 22, 2009 to an interest rate range between a weighted average floor of 4.09 per cent and a cap of 5.35 per cent. $75.0 million of
variable-rate debt is hedged by an interest rate swap during the period from February 29, 2008 through February 28, 2011, where the fixed
interest rate paid will be 3.86 per cent. In addition to these fixed rates, the Partnership pays an applicable margin in accordance with the
Senior Credit Facility agreement. The interest rate swaps and options are structured such that the cash flows match those of the Senior Credit
Facility.

NOTE 17 ACCOUNTING PRONOUNCEMENTS

In 2006, the Financial Accounting Standards Board issued SFAS No. 157, Fair Value Measurements, and during 2007,issued SFAS No. 141(R),
Business Combinations – revised, SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities – including an amendment
of FASB Statement No. 115, and SFAS No. 160, Noncontrolling Interests in Consolidated financial Statements.

SFAS No. 157 establishes a framework for measuring fair value and requires additional disclosures about fair value measurements. The effect
of adopting SFAS No. 157 is not expected to be material to our results of operations or financial position.

SFAS No. 141(R) replaces SFAS No. 141, Business Combinations. SFAS No. 141 (R) retains the fundamental requirements of SFAS No. 141 that
the acquisition method of accounting be used for all business combinations and for an acquirer to be identified for each business
combination, with the objective of improving the relevance and comparability of the information that a reporting entity provides in its financial
reports about a business combination and its effects. The requirements of this standard will not have a material impact on the results of the
Partnership.

F-19

TC PIPELINES, LP

SFAS No. 159 permits entities to choose to measure selected financial assets and financial liabilities at fair value. The fair value option
established by SFAS No. 159 permits all entities to choose to measure eligible items at fair value at specified election dates. The effect of
adopting SFAS No. 159 is not expected to be material to our results of operations or financial position.

SFAS No. 160 clarifies the classification of noncontrolling interests in consolidated statements of financial position and the accounting for and
reporting of transactions between the reporting entity and holders of such noncontrolling interests. The Partnership does not have
noncontrolling interests and therefore, is not affected by the changes resulting from this standard.

In June 2007 the Emerging Issues Task Force of the FASB issued EITF 07-4, ‘‘Application of the Two-Class Method under FASB Statement
No. 128, Earnings per Share, to Master Limited Partnerships’’. EITF 07-4 addresses how current period earnings of a Master Limited Partnership
(MLP) should be allocated to the general partner, limited partners and when applicable, incentive distribution rights when applying the
two-class method under Statement 128. A tentative conclusion was ratified by the FASB in December 2007. We are currently reviewing the
applicability of EIFT 07-4 to our results of operations and financial position.

NOTE 18 SUBSEQUENT EVENTS

On January 17, 2008, the Board of Directors of the general partner declared the Partnership’s 2007 fourth quarter cash distribution. The
fourth quarter cash distribution which was paid on February 14, 2008 to unitholders of record as of January 31, 2008, totaled $25.6 million
and was paid in the following manner: $23.2 million to common unitholders (including $1.4 million to the general partner as holder of
2,035,106 common units and $5.8 million to TransCan Northern as holder of 8,678,045 common units), $1.9 million to the general partner as
holder of the incentive distribution rights, and $0.5 million to the general partner in respect of its two per cent general partner interest.

Great Lakes declared and paid a distribution of $25.0 million on February 1, 2008, of which the Partnership received its 46.45 per cent share
or $11.6 million.

Northern Border declared and paid a distribution of $46.3 million on February 1, 2008, of which the Partnership received its 50 per cent share
or $23.2 million.

2007 ANNUAL REPORT

F-20

Report of Independent Registered Public Accounting Firm

The Partners and Management Committee
Great Lakes Gas Transmission Limited Partnership:

We have audited the accompanying consolidated balance sheets of Great Lakes Gas Transmission Limited Partnership
and subsidiary (partnership) as of December 31, 2007 and 2006, and the related consolidated statements of income
and partners’ capital, and cash flows for each of the years in the three-year period ended December 31, 2007. These
consolidated financial statements are the responsibility of the Partnership’s management. Our responsibility is to express
an opinion on these consolidated 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 consideration of internal control over financial reporting
as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of
expressing an opinion on the effectiveness of the Partnership’s internal control over financial reporting. Accordingly, we
express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and
disclosures in the financial statements, 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 consolidated financial statements referred to above present fairly, in all material respects, the
financial position of Great Lakes Gas Transmission Limited Partnership and subsidiary as of December 31, 2007 and
2006, and the results of their operations and their cash flows for each of the years in the three-year period ended
December 31, 2007 in conformity with U.S. generally accepted accounting principles.

The Partnership’s consolidated financial statements for 2006 and 2005 were previously prepared as though the
Partnership was a corporation and current income taxes and amounts equivalent to deferred income taxes were
recorded in those financial statements. As more fully described in note 2 to the consolidated financial statements, the
Partnership adopted a policy to exclude income taxes from the consolidated financial statements at the beginning of
the current year. Consequently, the Partnership’s consolidated financial statements for 2006 and 2005 have been
restated to exclude income taxes.

/s/ KPMG LLP

Detroit, Michigan
January 22, 2008

F-21

TC PIPELINES, LP

GREAT LAKES GAS TRANSMISSION LIMITED PARTNERSHIP
CONSOLIDATED STATEMENTS OF INCOME AND PARTNERS’ CAPITAL

Years ended December 31 (Thousands of dollars)

2007

2006
As Adjusted

2005
As Adjusted

Transportation Revenues
Affiliated Revenues
Nonaffiliated Revenues

Operating Expenses

Operation and Maintenance
Depreciation
Property and Other Non Income Taxes

Operating Income

Other Income (Expense)

Interest on Long Term Debt
Other, Net

$ 137,166
145,660

282,826

42,125
58,046
22,195

122,366

160,460

(35,096)
2,937

(32,159)

161,605
110,652

272,257

34,083
57,612
25,965

117,660

154,597

(35,970)
3,704

(32,266)

173,796
106,947

280,743

41,312
57,693
26,756

125,761

154,982

(36,844)
1,897

(34,947)

Net Income

$ 128,301

122,331

120,035

Partners’ Capital
Balance at Beginning of Year
Contributions by General Partners
Net Income
Distributions to Partners

Balance at End of Year

$ 630,849
–
128,301
(193,500)

$ 565,650

640,617
–
122,331
(132,099)

630,849

674,409
30,976
120,035
(184,803)

640,617

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

GREAT LAKES GAS TRANSMISSION LIMITED PARTNERSHIP
CONSOLIDATED BALANCE SHEETS

As of December 31 (Thousands of dollars)

ASSETS
Current Assets

Cash and Cash Equivalents
Accounts Receivable (Net of allowance of $800 in 2007 and $1,000 in 2006)
Receivable from Affiliates
Materials and Supplies
Prepayments

Gas Utility Plant

Property, Plant and Equipment
Less Accumulated Depreciation

LIABILITIES AND PARTNERS’ CAPITAL

Current Liabilities
Current Maturities of Long Term Debt
Accounts Payable
Payable to Affiliates
Property Taxes
Other Non Income Taxes
Accrued Interest
Other

Long Term Debt

Other Liabilities

Partners’ Capital

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

2007 ANNUAL REPORT

F-22

2007

2006
As Adjusted

$

31,960
29,229
11,607
11,257
3,424

87,477

78,641
16,327
18,954
10,908
4,286

129,116

2,045,133
1,075,873

2,038,123
1,030,059

969,260

1,008,064

$1,056,737

1,137,180

$

10,000
26,468
1,871
9,300
3,645
9,143
264

60,691

430,000

396

565,650

10,000
16,579
2,362
17,793
3,939
9,289
4,136

64,098

440,000

2,233

630,849

$1,056,737

1,137,180

F-23

TC PIPELINES, LP

GREAT LAKES GAS TRANSMISSION LIMITED PARTNERSHIP
CONSOLIDATED STATEMENTS OF CASH FLOWS

Years ended December 31 (Thousands of dollars)

Cash Flow Increase (Decrease) from:
Operating Activities

2006
As Adjusted

2005
As Adjusted

2007

Net Income
Adjustments to Reconcile Net Income to Operating Cash Flows:

$ 128,301

122,331

120,035

Depreciation
Allowance for Funds Used During Construction
Changes in Current Assets and Liabilities:

Accounts Receivable
Receivable from Affiliates
Accounts Payable
Payable to Affiliates
Property and Other Non Income Taxes
Other

Investing Activities

Investment in Utility Plant
Insurance Proceeds

Financing Activities

Repayment of Long Term Debt
Contributions by General Partners
Distribution to Partners

Change in Cash and Cash Equivalents
Cash and Cash Equivalents:
Beginning of Year

End of Year

Supplemental Disclosure of Cash Flow Information

Cash Paid During the Year for Interest

58,046
(438)

(12,902)
7,347
9,889
(491)
(8,787)
(5,342)

57,612
(386)

17,477
(2,233)
(15,048)
(2,393)
(2,716)
(3,309)

57,693
(135)

(2,516)
(3,872)
6,631
1,767
341
1,187

175,623

171,335

181,131

(18,804)
–

(18,804)

(18,953)
8,122

(10,831)

(16,102)
–

(16,102)

(10,000)
–
(193,500)

(10,000)
–
(132,099)

(10,000)
30,976
(184,803)

(203,500)

(142,099)

(163,827)

(46,681)

18,405

1,202

78,641

$ 31,960

60,236

78,641

59,034

60,236

(Net of Amounts Capitalized of $184, $153 and $47, Respectively)

$ 35,294

36,132

37,018

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

2007 ANNUAL REPORT

F-24

GREAT LAKES GAS TRANSMISSION LIMITED PARTNERSHIP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. ORGANIZATION AND MANAGEMENT

Great Lakes Gas Transmission Limited Partnership (Partnership) is a Delaware limited partnership that owns and operates an interstate natural
gas pipeline system. The Partnership transports natural gas for delivery to wholesale customers in the Midwestern and northeastern United
States and eastern Canada. The partners, their parent companies, and partnership ownership percentages at December 31 are as follows:

Partner (Parent Company)

General Partners:

El Paso Great Lakes Company, LLC (El Paso Corporation)
TransCanada GL, Inc. (TransCanada Pipelines Limited)
TC GL Intermediate Limited Partnership (TC PipeLines, LP)

Limited Partner:

Ownership %

2007

–
46.45
46.45

2006

46.45
46.45
–

Great Lakes Gas Transmission Company (TransCanada Pipelines Limited – 2007 and El Paso

Corporation and TransCanada Pipelines Limited – 2006)

7.10

7.10

On February 22, 2007 (acquisition date), TC PipeLines, LP (TCPL) and TransCanada Corporation (TransCanada) acquired El Paso Corporation’s
(El Paso) 46.45% ownership interest in the Partnership and 50% interest in Great Lakes Gas Transmission Company (Company), respectively.

The day-to-day operation of the Partnership activities is the responsibility of the Company pursuant to the Partnership’s Operating Agreement
with the Company. As of the acquisition date, the Company uses TransCanada and its affiliates to provide operating services. The Partnership
is charged for the salaries, benefits and expenses of TransCanada and its affiliates for services attributable to its operations.

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Principles of Consolidation and Basis of Presentation

The consolidated financial statements include the accounts of the Partnership and GLGT Aviation Company, a wholly owned subsidiary. GLGT
Aviation Company owns a fractional interest in a transport aircraft used principally for pipeline operations. Intercompany amounts have been
eliminated.

For purposes of reporting cash flows, the Partnership considers all liquid investments with original maturities of three months or less to be
cash equivalents. Under the Partnership’s cash management system, the bank notifies the Partnership daily of checks presented for payment
against its disbursement account. The Company transfers funds from short-term investments to cover the checks presented for payment. This
system results in a book cash overdraft in the disbursement account as a result of checks outstanding. The book overdraft, which was
reclassified to accounts payable, was $5.8 million and $0.3 million at December 31, 2007 and 2006, respectively.

The fair value of long term debt is discussed in footnote 4. All other financial instruments approximate fair value due to the short maturity of
these instruments.

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires
the use of estimates and assumptions that affect the amounts reported as assets, liabilities, revenues and expenses and the disclosures in these
financial statements. Although management believes these estimates are reasonable, actual results could differ from those estimates.

Regulation

The Partnership is subject to the rules, regulations and accounting procedures of the Federal Energy Regulatory Commission (FERC). The
Partnership’s accounting policies follow regulatory accounting principles prescribed under Statement of Financial Accounting Standards (SFAS)
No. 71, Accounting for the Effects of Certain Types of Regulation. There are no regulatory assets or liabilities reflected in these consolidated
financial statements.

F-25

TC PIPELINES, LP

Revenue and Accounts Receivable

The Partnership generates transportation revenues based on transportation service contracts under a tariff regulated by the FERC. The tariff
specifies maximum transportation rates and the contracts’ general terms and conditions of service. The majority of the service contracts are for
firm service in which the customers pay a reservation fee for capacity on the pipeline system regardless of whether they actually utilize their
reserved capacity. The Partnership recognizes reservation revenues on firm contracted capacity ratably over the contract period regardless of
the amount of natural gas that is transported. In addition to the reservation fee, a utilization fee is charged and the related revenue is
recognized based on the volume of natural gas transported.

Accounts receivable are reported at the invoiced amount. The Partnership establishes an allowance for losses on accounts receivable if it is
determined that all or a portion of the outstanding balance will not be collected. The Partnership also considers historical industry data and
customer credit trends. Account balances are charged against the allowance after all means of collection have been exhausted and the
potential for recovery is considered remote.

Natural Gas Imbalances

Natural gas imbalances occur when the actual amount of natural gas delivered or received differs from the scheduled amount of natural gas
delivered or received. The Partnership values these imbalances due to or from customers and interconnecting pipelines at fair value. Imbalances
are made up in kind, in accordance with the terms of the tariff.

Imbalances due from others are reported on the consolidated balance sheet as either accounts receivable or receivable from affiliates.
Imbalances owed to others are reported on the consolidated balance sheet as either accounts payable or payable to affiliates. Imbalances are
expected to settle within a year.

Materials and Supplies

Materials and supplies are valued at the lower of cost or market value with cost determined using the average cost method.

Gas Utility Plant and Depreciation

Gas utility plant is stated at cost and includes certain administrative and general expenses, plus an allowance for funds used during
construction. The Partnership capitalizes major units of property replacements or improvements and expenses minor items. Planned major
maintenance is accrued when, and only when, an obligating event occurs, and is recorded using the direct expensing method or the deferral
method. The cost of plant retired is charged to accumulated depreciation net of salvage and cost of removal. Depreciation of gas utility plant
is computed using the composite (group) method. Under this method, assets with similar lives and characteristics are grouped and depreciated
as one asset. The Partnership’s principal operating assets, which comprise approximately 98% of total property, plant and equipment, are
depreciated at an annual rate of 2.75%. The remaining assets are depreciated at an annual rate ranging from 4% to 20%.

The allowance for funds used during construction represents the debt and equity costs of capital funds applicable to utility plant under
construction, calculated in accordance with a uniform formula prescribed by the FERC. The rates used were 10.25%, 10.37%, and 10.50%
for years 2007, 2006, and 2005, respectively.

Asset Retirement Obligations

In the fourth quarter of 2005, the Partnership adopted Financial Accounting Standards Board Interpretation (FIN) No. 47, Accounting for
Conditional Asset Retirement Obligations. FIN No. 47 requires companies to record a liability for those asset retirement obligations in which
the timing and/or amount of settlement of the obligations are uncertain. These conditional obligations were not addressed by SFAS No. 143,
Accounting for Asset Retirement Obligations, which the Partnership adopted on January 1, 2003. FIN No. 47 requires accrual of a liability
when a range of scenarios indicates that the potential timing and/or settlement amounts of conditional asset retirement obligations can be
determined. The Partnership has asset retirement obligations if it were to permanently retire all or part of the pipeline system; however, the
amount of asset retirement obligations cannot be reasonably estimated due to the inability to determine the scope and timing of asset
retirements.

2007 ANNUAL REPORT

F-26

Impairment of Long-Lived Assets

The Partnership assesses its long-lived assets for impairment based on SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived
Assets. A long-lived asset is tested for impairment whenever events or changes in circumstances indicate that its carrying amount may exceed
the undiscounted cash flows expected to be generated by the asset. If the carrying amount exceeds the undiscounted cash flows, an
impairment is recognized to the extent the carrying amount exceeds its fair value.

Accounting for Pipeline Integrity Costs

Prior to January 1, 2006, the Partnership capitalized certain costs incurred related to its pipeline integrity assessment programs as part of
property, plant and equipment.

In June 2005, the FERC issued an order on Accounting for Pipeline Assessment Costs which generally requires that pipeline inspections and
assessments incurred after January 1, 2006 be expensed. The Partnership expensed $3.3 million and $2.4 million of pipeline integrity costs in
2007 and 2006, respectively.

Change in Accounting Principle

In previously issued financial statements, the Partnership accounted for income taxes as if it were a corporation and recorded current income
taxes and amounts equivalent to deferred income taxes in those financial statements. In 2007, the Partnership has concluded that a preferable
accounting method is to exclude income taxes from its consolidated financial statements, as federal and most state income taxes are the
responsibility of the partners.

The change in accounting principle is reported through retrospective application in accordance with SFAS No. 154, Accounting Changes and
Error Corrections. The change in accounting principle increased 2007, 2006 and 2005 Operating Income and Net Income by $46 million,
$44 million and $43 million, respectively. Cash flows from Operating Activities/Financing Activities increased/decreased by $41 million,
$39 million and $33 million in 2007, 2006 and 2005, respectively. In addition, amounts equivalent to deferred income tax liabilities were
removed and Partners’ Capital was increased by approximately $254 million as of January 1, 2005, $264 million as of December 31, 2005,
$269 million as of December 31, 2006, and $139 million as of December 31, 2007.

Income Taxes

Income taxes are the responsibility of our partners and are not reflected in these consolidated financial statements. The Partnership is required,
for FERC regulatory purposes, to account for income taxes as if it were a corporation. As a result, for purposes of determining Partners’ capital
for regulatory accounting purposes, it is reduced by the amounts equivalent to the net deferred income tax liability balances.

As a result of the sale of the partnership interest, and a corresponding Internal Revenue Code Section 754 election, the pre-acquisition
amounts equivalent to net deferred income tax liability balances were reduced by 46.45%. In addition, amounts equivalent to net deferred tax
liabilities for pre-acquisition retirement plans were eliminated. As a result, Partners’ Capital and amounts equivalent to net deferred tax
liabilities were adjusted on the acquisition date by approximately $135 million as approved by the FERC. Amounts equivalent to net deferred
income tax liabilities were approximately $139 million and $269 million at December 31, 2007 and 2006, respectively, and are primarily
related to accelerated depreciation on utility plant.

In the third quarter of 2007, the state of Michigan enacted the Michigan Business Tax (MBT), which replaces the Michigan Single Business Tax
effective January 1, 2008. The MBT is an income tax levied at the partnership level. The MBT is expected to result in an annual income tax
expense of approximately $4 to $5 million and to provide a property tax credit of approximately $1 million, for a net annual impact of $3 to
$4 million beginning in 2008.

Fair Value Measurements

In September 2006, the FASB issued SFAS No. 157, ‘‘Fair Value Measurements’’, which provides guidance on measuring the fair value of assets
and liabilities in the financial statements. Certain provisions are effective in 2008 and others in 2009. The effect of adopting SFAS No. 157 is
not expected to be material to the consolidated financial statements.

In February 2007, the FASB issued SFAS No. 159, ‘‘Fair Value Option for Financial Assets and Financial Liabilities – Including an Amendment of
FASB Statement No. 115,’’ which permits entities to choose to measure selected financial assets and financial liabilities at fair value. The fair
value option established by SFAS No. 159 permits all entities to choose to measure eligible items at fair value at specified election dates. A
business entity shall report unrealized gains and losses in earnings, on items for which the fair value option has been elected, at each

F-27

TC PIPELINES, LP

subsequent reporting date. SFAS No. 159 is effective for our fiscal year beginning January 1, 2008. The effect of adopting SFAS No. 159 is not
expected to be material to the consolidated financial statements.

Reclassifications

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

Affiliated company amounts included in the Partnership’s consolidated financial statements, not otherwise disclosed, are as follows:

Transportation Revenues (In thousands)

TransCanada and affiliates
El Paso and affiliates

2007

$135,629
1,537

2006

150,067
11,538

2005

156,561
17,235

Affiliated transportation revenues are primarily provided under fixed priced contracts with remaining terms ranging from 1 to 10 years.

The Partnership reimbursed the Company and affiliates for salaries, benefits and other administrative and operating incurred expenses. Benefits
include pension, defined contribution plans, and other post-retirement benefits. Operating expenses charged by the Company and affiliates in
2007, 2006, and 2005 were $26,836,000, $18,022,000 and $23,913,000, respectively.

The Company participated in El Paso sponsored pension and defined contribution plans until February 28, 2007. The Company also
participated in a post-retirement health care plan. After the acquisition date, the Partnership is charged for benefit plan expenses and other
benefits by a TransCanada affiliate through a benefit rate on labor costs.

4. DEBT

(In thousands)

Senior Notes, unsecured, interest due semiannually, principal due as follows:
8.74% series, due 2008 to 2011
9.09% series, due 2012 to 2021
6.73% series, due 2009 to 2018
6.95% series, due 2019 to 2028
8.08% series, due 2021 to 2030

Less current maturities

Total long term debt less current maturities

2007

2006

$ 40,000
100,000
90,000
110,000
100,000

440,000
10,000

$430,000

50,000
100,000
90,000
110,000
100,000

450,000
10,000

440,000

The aggregate estimated fair value of long term debt was $525,104,000 and $516,698,000 for 2007 and 2006, respectively. The fair value is
determined using discounted cash flows based on the Partnership’s estimated current interest rates for similar debt.

The aggregate annual required repayments of Senior Notes is $10,000,000 in 2008 and $19,000,000 for each year 2009 through 2012.

Under the most restrictive covenants in the Senior Note Agreements, approximately $237,000,000 of partners’ capital is restricted as to
distributions as of December 31, 2007.

2007 ANNUAL REPORT

F-28

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Management Committee
Northern Border Pipeline Company:

We have audited the accompanying balance sheets of Northern Border Pipeline Company (the Company) as of
December 31, 2007 and 2006, 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, 2007. 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 consideration of internal control over financial reporting
as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of
expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we
express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and
disclosures in the financial statements, 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, 2007 and 2006, and the results of its operations and its cash
flows for each of the years in the three-year period ended December 31, 2007 in conformity with U.S. generally
accepted accounting principles.

/s/ KPMG LLP

Omaha, Nebraska
February 27, 2008

F-29

TC PIPELINES, LP

NORTHERN BORDER PIPELINE COMPANY
BALANCE SHEETS

December 31, (In thousands)

ASSETS
Current assets:

Cash and cash equivalents
Accounts receivable
Related party receivables
Materials and supplies, at cost
Prepaid expenses and other

Total current assets

Property, plant and equipment:

In service natural gas transmission plant
Construction work in progress

Total property, plant and equipment
Less: Accumulated provision for depreciation and amortization

Property, plant and equipment, net

Other assets:

Regulatory assets (Note 2)
Unamortized debt expense
Other

Total other assets

Total assets

LIABILITIES AND PARTNERS’ EQUITY
Current liabilities:

Current maturities of long-term debt (Note 6)
Accounts payable
Related party payables
Accrued taxes other than income
Accrued interest
Other

Total current liabilities

Long-term debt, net of current maturities (Note 6)

Deferred credits and other liabilities

Related party payables
Regulatory liabilities (Note 2)
Derivative financial instruments (Note 7)
Other

Total deferred credits and other liabilities

Commitments and contingencies (Note 8)
Partners’ equity:

Partners’ capital
Accumulated other comprehensive income (loss)

Total partners’ equity

Total liabilities and partners’ equity

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

2007

2006

$

22,937
31,307
2,754
4,205
1,506

62,709

2,485,607
2,876

2,488,483
1,060,195

1,428,288

20,638
2,662
589

23,889

$

10,997
30,073
355
3,970
1,118

46,513

2,488,765
2,522

2,491,287
1,015,646

1,475,641

19,144
3,284
109

22,537

$1,514,886

$1,544,691

$

–
7,179
5,852
27,625
11,283
1,487

53,426

615,286

2,260
2,393
1,852
1,616

8,121

$ 170,000
4,577
2,539
27,571
11,515
1,511

217,713

449,844

–
–
–
2,099

2,099

840,494
(2,441)

838,053

874,057
978

875,035

$1,514,886

$1,544,691

NORTHERN BORDER PIPELINE COMPANY
STATEMENTS OF INCOME

Years Ended December 31, (In thousands)

Operating revenue

Operating expenses

Operations and maintenance
Depreciation and amortization
Taxes other than income

Operating expenses

Operating income

Interest expense

Interest expense
Interest expense capitalized

Interest expense, net

Other income (expense)

Allowance for equity funds used during construction
Other income (Note 10)
Other expense (Note 10)

Other income, net

Net income to partners

NORTHERN BORDER PIPELINE COMPANY
STATEMENTS OF COMPREHENSIVE INCOME

Years Ended December 31, (In thousands)

Net income to partners
Other comprehensive income:

2007 ANNUAL REPORT

F-30

2007

2006

2005

$309,376

$310,900

$321,651

54,057
60,733
29,379

144,169

165,207

43,082
(11)

43,071

30
2,427
(488)

1,969

49,500
58,721
31,541

139,762

171,138

43,218
(137)

43,081

192
2,218
(622)

1,788

39,506
58,052
31,345

128,903

192,748

42,792
(157)

42,635

269
2,396
(532)

2,133

$124,105

$129,845

$152,246

2007

2006

2005

$124,105

$129,845

$152,246

Changes associated with hedging transactions

(3,419)

(1,284)

(1,500)

Total comprehensive income

$120,686

$128,561

$150,746

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

F-31

TC PIPELINES, LP

NORTHERN BORDER PIPELINE COMPANY
STATEMENTS OF CASH FLOWS

Years Ended December 31, (In thousands)

CASH FLOW FROM OPERATING ACTIVITIES

Net income to partners

2007

2006

2005

$ 124,105

$129,845

$152,246

Adjustments to reconcile net income to partners to net cash

provided by operating activities:
Depreciation and amortization
Allowance for equity funds used during construction
Changes in components of working capital
Other

Total adjustments

61,115
(30)
1,457
(2,146)

60,396

59,325
(192)
1,827
(5,479)

55,481

58,404
(269)
(127)
(3,793)

54,215

Net cash provided by operating activities

184,501

185,326

206,461

CASH FLOW FROM INVESTING ACTIVITIES

Capital expenditures for property, plant and equipment, net

(10,636)

(20,857)

(28,555)

CASH FLOW FROM FINANCING ACTIVITIES

Equity contributions from partners
Distributions to partners
Issuance of debt
Retirement of debt
Debt financing costs

Net cash used in financing activities

Net change in cash and cash equivalents
Cash and cash equivalents at beginning of year

15,000
(172,668)
269,000
(273,000)
(257)

(161,925)

11,940
10,997

10,330
(178,841)
105,000
(112,000)
–

(175,511)

(11,042)
22,039

–
(202,901)
136,000
(109,000)
(321)

(176,222)

1,684
20,355

Cash and cash equivalents at end of year

$ 22,937

$ 10,997

$ 22,039

Supplemental disclosures for cash flow information:
Cash paid for interest, net of amount capitalized

Changes in components of working capital:

Accounts receivable
Related party receivables
Materials and supplies
Prepaid expenses and other
Accounts payable
Related party payables
Accrued taxes other than income
Accrued interest
Other current liabilities

Total

$ 44,481

$ 45,170

$ 44,067

$ (1,234)
(2,399)
(235)
(388)
2,602
3,313
54
(232)
(24)

$

8,179
1,939
(404)
422
(5,973)
(1,016)
(66)
(10)
(1,244)

$ (5,694)
(983)
(157)
149
6,491
(1,731)
524
160
1,114

$

1,457

$

1,827

$

(127)

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

NORTHERN BORDER PIPELINE COMPANY
STATEMENTS OF CHANGES IN PARTNERS’ EQUITY

(In thousands)

Partners’ equity at December 31, 2004

Net income to partners
Changes associated with hedging

transactions
Distributions paid

Partners’ equity at December 31, 2005

Net income to partners
Changes associated with hedging

transactions

Equity contributions received
Distributions paid
Ownership change

Partners’ equity at December 31, 2006

Net income to partners
Changes associated with hedging

transactions

Equity contributions received
Distributions paid

TC PipeLines
Intermediate
Limited
Partnership

$289,014
45,674

–
(60,870)

273,818
57,452

–
3,099
(80,420)
183,080

437,029
62,052

–
7,500
(86,334)

2007 ANNUAL REPORT

F-32

Total Partners’
Equity

ONEOK
Partners
Intermediate

Accumulated
Other
Limited Comprehensive
Income (Loss)

Partnership

$ 674,364
106,572

$ 3,762
–

$ 967,140
152,246

–
(142,031)

638,905
72,393

–
7,231
(98,421)
(183,080)

437,028
62,053

–
7,500
(86,334)

(1,500)
–

2,262
–

(1,284)
–
–
–

978
–

(3,419)
–
–

(1,500)
(202,901)

914,985
129,845

(1,284)
10,330
(178,841)
–

875,035
124,105

(3,419)
15,000
(172,668)

Partners’ equity at December 31, 2007

$420,247

$ 420,247

$(2,441)

$ 838,053

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

F-33

TC PIPELINES, LP

NORTHERN BORDER PIPELINE COMPANY
NOTES TO FINANCIAL STATEMENTS

1. ORGANIZATION AND MANAGEMENT

In this report, references to ‘‘we, ‘‘us’’ or ‘‘our’’ collectively refer to Northern Border Pipeline Company.

We are a Texas general partnership formed in 1978. We own 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. In April 2006, ONEOK Partners
Intermediate Limited Partnership (ONEOK Partners) completed the sale of a 20 percent partnership interest in us to TC PipeLines Intermediate
Limited Partnership (TC PipeLines). As a result of the transaction, our General Partnership Agreement was amended and restated effective
April 6, 2006.

The ownership and voting percentages of our partners at December 31, 2007 and 2006 are as follows:

Partner

ONEOK Partners
TC PipeLines

Ownership

50%
50%

We are managed by a Management Committee that consists of four members. Each partner designates two members, and TC PipeLines
designates one of its members as chairman. The Management Committee designates the members of the Audit Committee, which consists of
three members. One member is selected by the members of the Management Committee designated by the partner whose affiliate is the
operator and two members are selected by the members of the Management Committee designated by the other partner.

The day-to-day management of our affairs is the responsibility of TransCanada Northern Border, Inc., (TransCanada Northern Border) pursuant
to an operating agreement between us and TransCanada Northern Border effective April 1, 2007. TransCanada Northern Border utilizes the
services of TransCanada Corporation (TransCanada) and its affiliates for management services related to us. We are charged for the salaries,
benefits and expenses of TransCanada and its affiliates attributable to our operations. For the year ended December 31, 2007, our charges
from TransCanada and its affiliates totaled approximately $22.5 million.

Prior to April 1, 2007, the day-to-day management of our affairs was the responsibility of ONEOK Partners GP, L.L.C. (ONEOK Partner GP)
pursuant to an operating agreement between us and ONEOK Partners GP. ONEOK Partners GP also utilized ONEOK, Inc. (ONEOK) and its
affiliates for management services related to us. We were charged for the salaries, benefits and expenses of ONEOK Partners GP, ONEOK and
its affiliates attributable to our operations. For the years ended December 31, 2007, 2006, and 2005, our charges from ONEOK Partners GP
and its current and former affiliates totaled approximately $9.3 million, $26.2 million and $20.1 million, respectively. Our 2007 charges include
$3.6 million for transition related costs. See Note 8 for further discussion of transition related costs.

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Use of Estimates

The preparation of financial statements in conformity with U.S. generally accepted accounting principles requires management to make
assumptions and use estimates that affect the reported amounts of assets, liabilities, revenue and expenses as well as the disclosure of
contingent assets and liabilities during the reporting period. Actual results could differ from these estimates if the underlying assumptions are
incorrect.

Government Regulation

We are subject to regulation by the Federal Energy Regulatory Commission (FERC). Our accounting policies conform to Statement of Financial
Accounting Standards (SFAS) No. 71, ‘‘Accounting for the Effects of Certain Types of Regulation.’’ Accordingly, certain assets and liabilities that
result from the regulated ratemaking process are reflected on the balance sheets as regulatory assets and regulatory liabilities.

2007 ANNUAL REPORT

F-34

At December 31, 2007 and 2006, we have reflected regulatory assets of approximately $20.6 million and $19.1 million, respectively, on the
balance sheets. These assets are being amortized, as directed by the FERC, over varying time periods up to 43 years.

The following table presents a summary of regulatory assets, net of amortization, at December 31, 2007, and 2006.

December 31, (In thousands)

Fort Peck lease option
Pipeline extension project
Unamortized loss on reacquired debt
Deferred rate case expenditures
Compressor usage surcharge tracker

Total regulatory assets

2007

$10,797
6,459
308
1,953
1,121

$20,638

2006

$ 9,507
6,920
376
2,341
–

$19,144

At December 31, 2007, we have reflected a regulatory liability of $2.4 million on the balance sheet related to negative salvage accrued for
estimated net costs of removal of transmission plant. See the Property, Plant and Equipment and Related Depreciation and Amortization policy
in this note for further discussion of negative salvage.

We assess the recoverability of costs recognized as regulatory assets and liabilities and the ability to continue to account for our activities
based on the criteria set forth in SFAS No. 71, which includes such factors as regulatory changes and the impact of competition. Our review
of these criteria currently supports the continuing application of SFAS No. 71. If we cease to meet the criteria of SFAS No. 71, a write-off of
related regulatory assets and liabilities could be required.

Revenue Recognition

We transport gas for shippers under a tariff regulated by the FERC. The tariff specifies the maximum rates we may charge shippers and the
general terms and conditions of transportation service on our pipeline system. We recognize revenue according to each transportation contract
for transportation service that is provided to our customers. Customers with firm service transportation agreements pay a reservation fee for
capacity on the pipeline system known as a reservation charge regardless of whether they actually utilize their reserved capacity. Firm service
transportation customers also pay a fee known as a commodity charge that is based on the mileage and the volume of natural gas they
transport. Customers with interruptible service transportation agreements may utilize available capacity on our pipeline after firm service
transportation requests are satisfied. Interruptible service customers are assessed commodity charges based on mileage and the volume of
natural gas they transport. An allowance for doubtful accounts is recorded in situations where collectibility is not reasonably assured. We had
no allowance for doubtful accounts at December 31, 2007 and 2006. We do not own the gas that we transport, and therefore we do not
assume the related natural gas commodity price risk.

Income Taxes

Income taxes are the responsibility of our partners and are not reflected in these financial statements. Our FERC tariff, through December 31,
2006, established the method of accounting for and calculating income taxes which would have been paid or accrued if we were organized
during the period as a corporation. Pursuant to the terms of the settlement of our 2005 rate case, during the time period that the rates
effective January 1, 2007 are in effect, the treatment historically accorded income taxes will be observed by us for regulatory accounting
purposes.

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 due to the short maturity of these investments.

F-35

TC PIPELINES, LP

Property, Plant and Equipment and Related Depreciation and Amortization

Property, plant and equipment is stated at original cost. During periods of construction, we are permitted to 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. No retirement gain or loss is included in income except in the case of retirements or
sales of entire regulated operating units or systems.

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 our FERC tariff. As a result of the settlement of our 2005 rate case, the effective depreciation rate applied to our
transmission plant in 2007 is 2.40 percent. The effective depreciation rate applied to our transmission plant in 2006 and 2005 was
2.25 percent. The transmission plant depreciation rate in 2007 of 2.40 percent is comprised of two components: one based on economic
service life or capital recovery and one based on cost of removal, net of salvage value received, or negative salvage. We accrue the estimated
net costs of removal of transmission plant as a regulatory liability, which does not represent an existing legal obligation. The net cost of
removal incurred on retirements of transmission plant is recorded as a reduction to the regulatory liability. As of December 31, 2007,
$2.4 million for accrued negative salvage is included as a regulatory liability on the accompanying balance sheet. Composite rates are applied
to all other functional groups of property having similar economic characteristics. See Note 4 for discussion of our 2005 rate case settlement.

Natural Gas Imbalances

Natural gas imbalances occur when the actual amount of natural gas delivered or received by a pipeline system or storage facility differs from
the contractual amount of natural gas scheduled to be delivered or received. We value these imbalances due to or from shippers and
interconnecting parties at an appropriate index price. Imbalances are made up in-kind, subject to the terms of our tariff.

Imbalances due from others are reported on the balance sheets as accounts receivable. Imbalances owed to others are reported on the
balance sheets as accounts payable. All imbalances are classified as current.

Risk Management

We use financial instruments in the management of our 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. We do 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 all derivative instruments (including certain derivative instruments embedded in other contracts) be recorded
on the balance sheet as either an asset or liability measured at their fair value. We determine the fair value of a derivative instrument by the
present value of its future cash flows based on market prices from third party sources. We record changes in the derivative’s fair value
currently in earnings unless specific hedge accounting criteria are met. 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 us to formally document, designate and assess the
effectiveness of transactions that receive hedge accounting. See Note 7 for a discussion of our derivative instruments and hedging activities.

Unamortized Debt Premium, Discount and Expense

We amortize premiums, discounts and expenses incurred in connection with the issuance of debt consistent with the terms of the respective
debt instrument.

Operating Leases

We have non-cancelable operating leases for office space and rights-of-way. We record rent expense over the lease term as it becomes
payable. If operating leases include escalating rental payments, we determine the cumulative rental payments anticipated and recognize rent
expense on a straight-line basis over the term of the lease.

2007 ANNUAL REPORT

F-36

Impairment of Long-Lived Assets

We assess our long-lived assets for impairment based on SFAS No. 144, ‘‘Accounting for the Impairment or Disposal of Long-Lived Assets.’’ A
long-lived asset is tested for impairment whenever events or changes in circumstances indicate that its carrying amount may exceed its fair
value. Fair values are based on the sum of the undiscounted future cash flows expected to result from the use and eventual disposition of the
assets.

Contingencies

Our accounting for contingencies covers a variety of business activities including contingencies for legal exposures and environmental
exposures. We accrue these contingencies when our assessments indicate that it is probable that a liability has been incurred or an asset will
not be recovered and an amount can be reasonably estimated in accordance with SFAS No. 5, ‘‘Accounting for Contingencies.’’ We base our
estimates on currently available facts and our estimates of the ultimate outcome or resolution. Actual results may differ from our estimates
resulting in an impact, positive or negative, on earnings.

Reclassifications

Certain reclassifications have been made to the financial statements for prior years to conform to the current year presentation. These
reclassifications did not impact previously reported net income or partners’ equity.

3. ASSET RETIREMENT OBLIGATIONS

Effective January 1, 2003, we adopted 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 during the period in which the liability is incurred, if a reasonable estimate of fair
value can be made. Effective December 31, 2005, we adopted FIN 47, ‘‘Accounting for Conditional Asset Retirement Obligations–an
interpretation of SFAS No. 143.’’ FIN 47 clarifies the term ‘‘conditional asset retirement obligation,’’ as used in SFAS No. 143 and the
circumstances under which an entity would have sufficient information to reasonably estimate the fair value of an asset retirement obligation.
We have determined that asset retirement obligations exist for certain of our transmission assets; however, the fair value of the obligations
cannot be determined because the end of the transmission system life is not determinable with the degree of accuracy necessary to currently
establish a liability for the obligations.

4. RATES AND REGULATORY ISSUES

The FERC regulates the rates and charges for transportation of natural gas in interstate commerce. Natural gas companies may not charge
rates that have been determined to be unjust and unreasonable by the FERC. Generally, rates for interstate pipelines are based on the cost of
service, including recovery of and a return on the pipeline’s actual prudent historical cost investment. The rates and terms and conditions for
service are found in each pipeline’s FERC-approved tariff. Under its tariff, an interstate pipeline is allowed to charge for its services on the basis
of stated transportation rates. Transportation rates are established periodically in FERC proceedings known as rate cases. The tariff also allows
the interstate pipeline to provide services under negotiated and discounted rates.

As required by the provisions of the settlement of our 1999 rate case, on November 1, 2005 we filed a rate case with the FERC. In December
2005, the FERC issued an order that identified issues that were raised in the proceeding and accepted the proposed rates, but suspended their
effectiveness until May 1, 2006. Beginning May 1, 2006, the new rates were collected subject to refund through September 30, 2006. Based
on the settlement, discussed below, we refunded $10.8 million to our customers in the fourth quarter of 2006.

The settlement of our 2005 rate case was approved by the FERC in November 2006. The settlement established maximum long-term mileage-
based rates and charges for transportation on our system. Beginning in 2007, overall rates were reduced, compared with rates prior to the
filing, by approximately 5 percent. For the full transportation route from Port of Morgan, Montana to the Chicago area, the previous charge of
approximately $0.46 per Dekatherm (Dth) is now approximately $0.44 per Dth, which is comprised of a reservation rate, commodity rate and
a compressor usage surcharge. The factors used in calculating depreciation expense for transmission plant were increased from 2.25 percent to
2.40 percent. The settlement also provided for seasonal rates for short-term transportation services. Seasonal maximum rates vary on a
monthly basis from approximately $0.54 per Dth to approximately $0.29 per Dth for the full transportation route from Port of Morgan,

F-37

TC PIPELINES, LP

Montana to the Chicago area. The settlement included a three-year moratorium on filing rate cases and participants challenging these rates,
and requires that we file a rate case within six years from the date the new rates went into effect.

The compressor usage surcharge rate is designed to recover the actual costs of electricity at our electric compressors and any compressor fuel
use taxes imposed on our pipeline system. Any difference between the compressor usage surcharge collected and the actual costs for
electricity and compressor fuel use taxes is recorded as either an increase to expense for an over recovery of actual costs or as a decrease to
expense for an under recovery of actual costs, and is included in operations and maintenance expense on the income statement and as either
a regulatory liability or a regulatory asset, respectively, on the balance sheet. The compressor usage surcharge rate is adjusted annually. The
regulatory liability or regulatory asset will reflect the net over or under recovery of actual compressor usage related costs at the date of the
balance sheet. As of December 31, 2007, we had recorded $1.1 million as a regulatory asset on the accompanying balance sheet for the net
under recovery of compressor usage related costs.

5. TRANSPORTATION SERVICE AGREEMENTS

Operating revenues are collected pursuant to the FERC tariff through transportation service agreements. Our firm service agreements at
December 31, 2007, extend for various terms with termination dates that range from one day to approximately eight years. We also have
interruptible transportation service agreements and other transportation service agreements with numerous shippers. Under the capacity
release provisions of our FERC tariff, shippers under firm contracts 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, 2007, our largest shippers, Cargill Inc. (Cargill) and BP Canada Energy Marketing Corp. (BP Canada) were obligated for
approximately 15 percent and 14 percent of summer day design capacity, respectively. The Cargill and BP Canada firm service agreements
extend for various terms with termination dates ranging from March 2008 to December 2008 and January 2008 to April 2014, respectively.

For the year ended December 31, 2007, shippers providing significant operating revenues were BP Canada, Nexen Marketing U.S.A. Inc.
(Nexen) and Cargill with revenues of $49.7 million, $44.1 million, and $42.0 million, respectively. For the year ended December 31, 2006,
shippers providing significant operating revenues were BP Canada and Cargill with revenues of $66.7 million and $43.0 million, respectively.
For the year ended December 31, 2005, shippers providing significant operating revenues were BP Canada, Nexen, EnCana Marketing
(USA) Inc. and Cargill with revenues of $56.1 million, $38.1 million, $37.9 million and $34.1 million, respectively.

For the years ended December 31, 2007, 2006 and 2005, we had contracted firm capacity held by one shipper affiliated with one of our
general partners. ONEOK Energy Services Company, LP (ONEOK Energy), a subsidiary of ONEOK, holds firm service agreements representing
approximately 3 percent of summer day design capacity at December 31, 2007. The firm service agreements with ONEOK Energy extend for
various terms with termination dates that range from March 2008 to November 2011. Revenue from ONEOK Energy for 2007, 2006 and
2005 was $5.1 million, $7.0 million and $7.7 million, respectively. At December 31, 2007 and 2006, we had outstanding receivables from
ONEOK Energy of $0.8 million and $0.3 million, respectively.

6. CREDIT FACILITIES AND LONG-TERM DEBT

Detailed information on long-term debt is as follows:

December 31, (In thousands)

2007 Credit Agreement – average interest rate of 5.35% at December 31, 2007 due 2012
2005 Credit Agreement – average interest rate of 6.33% at December 31, 2006 refinanced in 2007
1999 Senior Notes – 7.75%, due 2009
2001 Senior Notes – 7.50%, due 2021
2002 Senior Notes – 6.25%, due 2007
Unamortized debt discount, net of premium

Subtotal

Current maturities

Long-term debt

2007

$166,000
–
200,000
250,000
–
(714)

615,286
–

2006

$

–
20,000
200,000
250,000
150,000
(156)

619,844
(170,000)

$615,286

$ 449,844

2007 ANNUAL REPORT

F-38

On April 27, 2007, we entered into a $250 million amended and restated revolving credit agreement (2007 Credit Agreement) with certain
financial institutions. The 2007 Credit Agreement was used to refinance the outstanding indebtedness under our $175 million revolving credit
agreement dated as of May 16, 2005 (2005 Credit Agreement) and was used to repay all of the $150 million of our 6.25 percent Senior
Notes due May 1, 2007. The 2007 Credit Agreement can also be used to finance permitted acquisitions, pay related fees and expenses, issue
letters of credit and provide for ongoing working capital needs and for other general business purposes, including capital expenditures.

At December 31, 2007, based on the principal commitment amount of $250 million, available capacity under the 2007 Credit Agreement was
$84 million. We may, at our option, so long as no default or event of default has occurred and is continuing, elect to increase the capacity
under our 2007 Credit Agreement by an aggregate amount not to exceed $100 million, provided that lenders are willing to commit additional
amounts. At our option, the interest rate on the outstanding borrowings may be the lenders’ base rate or the London Interbank Offered Rate
plus a spread that is based on our long-term unsecured credit ratings. The 2007 Credit Agreement permits us to specify the portion of the
borrowings to be covered by specific interest rate options and to specify the interest rate period. We are required to pay a facility fee of
0.05 percent based on the principal amount of the commitment of $250 million. The term of the agreement is five years, with options for
two one-year extensions.

Certain of our long-term debt arrangements contain certain covenants that restrict the incurrence of secured indebtedness or liens upon
property by us. Under the 2007 Credit Agreement, we are required to comply with certain financial, operational and legal covenants. Among
other things, we are required to maintain a ratio of total debt to EBITDA (net income plus interest expense, income taxes, depreciation and
amortization and all other non-cash charges) of no more than 4.75 to 1. Pursuant to the 2007 Credit Agreement, if one or more acquisitions
are consummated in which the aggregate purchase price is $25 million or more, the allowable ratio of total debt to EBITDA is increased to
5.50 to 1 for the first three full calendar quarters following the acquisition. Upon any breach of these covenants, amounts outstanding under
the 2007 Credit Agreement may become immediately due and payable. At December 31, 2007, we were in compliance with all of our
financial covenants.

Aggregate required repayments of long-term debt for the next five years are $200 million in 2009 and $166 million in 2012. Aggregate
required repayments of long-term debt thereafter total $250 million. There are no required repayment obligations for 2008, 2010 or 2011.

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 aggregate of the senior notes outstanding at December 31, 2007 and 2006, was approximately $493 million and
$623 million, respectively. We presently intend to maintain the current schedule of maturities for the 1999 Senior Notes and the 2001 Senior
Notes, which will result in no gains or losses on their respective repayments. The fair value of the 2007 Credit Agreement approximates the
carrying value since the interest rates are periodically adjusted to reflect current market conditions.

7. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

Prior to the anticipated issuance of fixed rate debt, we entered into forward starting interest rate swap agreements. The interest rate swap
agreements were designated as cash flow hedges as they hedged the fluctuations in Treasury rates and spreads between the execution date of
the swap agreements and the issuance of the fixed rate debt. The notional amount of the interest rate swap agreements did not exceed the
expected principal amount of fixed rate debt to be issued. Upon issuance of the fixed rate debt, the swap agreements were terminated and
the proceeds received or amounts paid to terminate the swap agreements were recorded in accumulated other comprehensive income and
amortized to interest expense over the term of the debt.

During the years ended December 31, 2007, 2006, and 2005, respectively, we amortized approximately $1.6 million, $1.3 million, and
$1.5 million related to the terminated interest rate swap agreements as a reduction to interest expense from accumulated other
comprehensive income. We expect to amortize approximately $1.5 million as a reduction to interest expense in 2008.

We record in long-term debt amounts received or paid related to terminated interest rate swap agreements for fair value hedges and amortize
these amounts to interest expense over the remaining original term of the interest rate swap agreements. During the years ended
December 31, 2007, 2006, and 2005, we amortized approximately $0.7 million, $2.1 million and $2.1 million, respectively, as a reduction to
interest expense. Amounts received or paid related to terminated interest rate swap agreements for fair value hedges were fully amortized at
June 30, 2007.

In August 2007, we entered into a zero cost interest rate collar agreement (the ‘‘Collar Agreement’’) to limit the variability of the interest rate
on $140 million of variable-rate borrowings during the period from October 30, 2007 through October 30, 2009 to a range between a floor
of 4.35 percent and a cap of 5.36 percent. We have designated the Collar Agreement as a cash flow hedge. At December 31, 2007, the
balance sheet reflected an unrealized loss of approximately $1.9 million with a corresponding decrease to accumulated other comprehensive

F-39

TC PIPELINES, LP

income (loss) related to the changes in fair value of the Collar Agreement since inception. Since inception, no amounts have been recognized
in income due to ineffectiveness or amounts received or paid under the Collar Agreement.

8. COMMITMENTS AND CONTINGENCIES

Operating Leases

Future minimum lease payments under non-cancelable operating leases on office space and rights-of-way are as follows:

Year ending December 31, (In thousands)

2008
2009
2010
2011
2012
Thereafter

2,540
2,541
2,194
1,889
1,889
61,072

$72,125

Expenses incurred related to these lease obligations for the years ended December 31, 2007, 2006 and 2005 were $1.5 million, $0.7 million,
and $0.6 million, respectively.

In August 2004, we signed an Option Agreement and Expanded Facilities Lease (Option Agreement) with the Assiniboine and Sioux Tribes of
the Fort Peck Indian Reservation. The Option Agreement documented the settlement of certain pipeline and right-of-way lease and taxation
issues. The Option Agreement grants to us, among other things: (i) an option to renew the pipeline right-of-way lease upon agreed terms and
conditions on or before April 1, 2011, for a term of 25 years with a renewal right for an additional 25 years; (ii) a right to use additional tribal
lands for expanded facilities; and (iii) release and satisfaction of all tribal taxes against us. In consideration of this option and other benefits,
we paid a lump sum amount of $7.4 million and will make additional annual option payments of approximately $1.5 million through
March 31, 2011.

Transition Related Costs

We are required to pay $3.6 million over a five year period under a transition services agreement between ONEOK Partners GP and
TransCanada Northern Border, related to the reimbursement for shared equipment and furnishings acquired by ONEOK Partners and previously
used or currently in use for our operations. During the second quarter of 2007 a charge of $2.3 million was recorded in operations and
maintenance expense and $1.3 million was recorded as natural gas transmission plant for the shared equipment and furnishings previously
used or currently in use by us, respectively. Amounts related to this obligation are included in related party payables on the balance sheet.
Future remaining payments for this obligation are as follows:

Year ending December 31, (In thousands)

2008
2009
2010
2011

Environmental Matters

753
753
753
753

$3,012

We are not aware of any material contingent liabilities with respect to compliance with applicable environmental laws and regulations.

2007 ANNUAL REPORT

F-40

Other

Various legal actions that have arisen in the ordinary course of business are pending. We believe that the resolution of these issues will not
have a material adverse impact on our results of operations or financial position.

9. CASH DISTRIBUTION POLICY

Our General Partnership Agreement provides that distributions to our partners are to be made on a pro rata basis according to each partner’s
capital account balance. Our Management Committee determines the amount and timing of the distributions to our partners including equity
contributions and the funding of growth capital expenditures. Any changes to, or suspension of, our cash distribution policy requires the
unanimous approval of the Management Committee. Our cash distributions are equal to 100 percent of our distributable cash flow as
determined from our financial statements based upon earnings before interest, taxes, depreciation and amortization less interest expense and
maintenance capital expenditures. In 2006, upon the closing of the sale of a 20 percent general partnership interest in us from ONEOK
Partners to TC PipeLines, our Management Committee adopted certain changes to our cash distribution policy related to financial ratio targets
and equity contributions. The change defined minimum equity to total capitalization ratios to be used by the Management Committee to
establish the timing and amount of required equity contributions. In addition, any shortfall due to the inability to refinance maturing debt will
be funded by equity contributions.

For the years ended December 31, 2007, 2006 and 2005, we paid distributions to our general partners of $172.7 million, $178.8 million and
$202.9 million, respectively. In 2007, we issued an equity cash call to our general partners in the amount of $15.0 million for the previously
approved 2007 equity cash call. The proceeds were used to repay indebtedness. We issued an equity cash call to our general partners of
$10.3 million in 2006 to fund approximately 50 percent of our growth capital expenditures.

10. OTHER INCOME (EXPENSE)

Other income (expense) on the statements of income includes such items as investment income, nonoperating revenues and expenses, and
nonrecurring other income and expense items. For the years ended December 31, 2007, 2006 and 2005, other income (expense) included:

Years Ended December 31, (In thousands)

2007

2006

2005

Other income

Nonoperating revenue
Investment income
Bad debt expense adjustment
Other

Other income

Other expense

Depreciation and amortization for non-regulated property
Other

Other expense

$1,638
691
–
98

$2,427

$ (382)
(106)

$ (488)

$1,086
627
–
505

$2,218

$ (604)
(18)

$ (622)

$1,134
487
408
367

$2,396

$ (351)
(181)

$ (532)

F-41

TC PIPELINES, LP

11. ACCOUNTING PRONOUNCEMENTS

In September 2006, the FASB issued SFAS No. 157, ‘‘Fair Value Measurements,’’ which establishes a framework for measuring fair value and
requires additional disclosures about fair value measurements. SFAS No. 157 is effective for our fiscal year beginning January 1, 2008. The
effect of adopting SFAS No. 157 is not expected to be material to our results of operations or financial position.

In February 2007, the FASB issued SFAS No. 159 ‘‘The Fair Value Option for Financial Assets and Financial Liabilities – Including an Amendment
of FASB Statement No. 115,’’ which permits entities to choose to measure selected financial assets and financial liabilities at fair value. The fair
value option established by SFAS No. 159 permits all entities to choose to measure eligible items at fair value at specified election dates. A
business entity shall report unrealized gains and losses in earnings, on items for which the fair value option has been elected, at each
subsequent reporting date. SFAS No. 159 is effective for our fiscal year beginning January 1, 2008. The effect of adopting of SFAS No. 159 is
not expected to be material to our results of operations or financial position.

12. SUBSEQUENT EVENTS

We make distributions to our general partners approximately one month following the end of the quarter. A cash distribution of approximately
$46.3 million was declared and paid on February 1, 2008 for the fourth quarter of 2007.

TC PipeLines, LP is a United States limited partnership that offers investors stable 
cash flow and growth prospects.

With the closing of the acquisition of a 46.45 per cent interest in Great Lakes Gas Transmission Limited Partnership 
(Great Lakes) on February 22, 2007, TC PipeLines, LP (the Partnership) has interests in more than 3,600 miles of 
federally regulated U.S. interstate natural gas pipelines, including Northern Border Pipeline Company (Northern 
Border) (50 per cent ownership) and Tuscarora Gas Transmission Company (Tuscarora) (100 per cent ownership). 
The Partnership is managed by its general partner, TC PipeLines GP, Inc., a wholly owned subsidiary of TransCanada 
Corporation (TransCanada), a leading North American energy infrastructure company.

Financial Highlights

Year ended December 31

2007

2006

2005

2004

2003

(millions of dollars, except per unit amounts)

Income Statement
Net income

Cash Flow

89.0

44.7

50.2

55.1

48.0

Partnership cash flows*
Cash distributions paid

134.7
86.7

69.9
43.5

66.2
43.0

66.9
41.8

50.6
39.4

Balance Sheet
Total assets
Long-term debt 
     (including current maturities)
Partners’ equity

Common Units Statistics (per unit)

Net income
Cash distributions paid

1,492.6

777.8

315.7

332.1

288.1

573.4
900.1

468.1
303.9

13.5
301.6

36.5
294.9

5.5
282.0

$ 2.51
$ 2.565

$ 2.39
$ 2.325

$ 2.70
$ 2.300

$ 2.99
$ 2.275

$ 2.63
$ 2.175

Common Units Outstanding**

34.9

17.5

17.5

17.5

17.5

*Partnership cash flows is a non-GAAP financial measure which is the sum of cash distributions received and cash flows 
from Tuscarora’s operating activities less Partnership costs. For a reconciliation of these non-GAAP financial measure see, 
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations in our Form 10-K for the 
year ended December 31, 2007, filed with the SEC and included in this annual report.

** As at December 31, 2007.

Net Income 
(dollars per unit)

2.99

2.63

2.70

2.51

2.39

Cash Distributions 
Paid 
(dollars per unit)

2.275

2.300

2.325

2.175

Partnerhship
Cash Flows 
(millions of dollars)

Total Assets
(millions of dollars)

2.565

134.7

1492.6

66.9

66.2

69.9

50.6

777.8

332.1

315.7

288.1

2003

2004

2005

2006

2007

2003

2004

2005

2006

2007

2003

2004

2005

2006

2007

2003

2004

2005

2006

2007

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