Annual Report & Accounts Pt 3

Name	Symbol	Market	Type
Citi Fun 24	LSE:BC93	London	Medium Term Loan

RNS Number:4665Z
TransCanada Pipelines Ld
07 March 2006

PART 3

TRANSCANADA PIPELINES LIMITED 1

TABLE OF CONTENTS
CONSOLIDATED FINANCIAL REVIEW
Highlights 3
Results-at-a-Glance 3
FORWARD-LOOKING INFORMATION 5

OVERVIEW AND STRATEGIC PRIORITIES
TCPL Overview 6
TCPL's Strategy 6
Core Businesses and Significant Developments in 2005
Gas Transmission 7
Power 9
Operational Excellence and "SPIRIT" 10
Competitive Strength and Enduring Value 11
Outlook 11
GAS TRANSMISSION
Highlights 13
Results-at-a-Glance 16
Financial Analysis 17
Opportunities and Developments 18
Regulatory Developments 22
Business Risks 24
Other 26
Outlook 27
POWER
Highlights 29
Results-at-a-Glance 32
Financial Analysis 33
Opportunities and Developments 41
Business Risks 41
Other 42
Outlook 43
CORPORATE 44
LIQUIDITY AND CAPITAL RESOURCES 45
CONTRACTUAL OBLIGATIONS 46
FINANCIAL AND OTHER INSTRUMENTS 50
RISK MANAGEMENT 55
CRITICAL ACCOUNTING POLICY 57
CRITICAL ACCOUNTING ESTIMATE 57
ACCOUNTING CHANGES 57
DISCONTINUED OPERATIONS 59
SUBSIDIARIES AND INVESTMENTS 60
SELECTED THREE YEAR CONSOLIDATED FINANCIAL DATA 61
SELECTED QUARTERLY CONSOLIDATED FINANCIAL DATA 62
FOURTH QUARTER 2005 HIGHLIGHTS 64
SHARE INFORMATION 65
OTHER INFORMATION 65
GLOSSARY OF TERMS 66

2 MANAGEMENT'S DISCUSSION AND ANALYSIS

The Management's Discussion and Analysis (MD&A) dated February 27, 2006 should
be read in conjunction with the audited Consolidated Financial Statements of
TransCanada PipeLines Limited (TCPL or the company) and the notes thereto for
the year ended December 31, 2005. Amounts are stated in Canadian dollars unless
otherwise indicated.

CONSOLIDATED FINANCIAL REVIEW

HIGHLIGHTS

Net Income

*
In 2005, net income applicable to common shares was $1,208 million
compared to $1,030 million in 2004.

Net Earnings

*
In 2005, TCPL's net income applicable to common shares from continuing
operations (net earnings) increased $230 million to $1,208 million
compared to $978 million in 2004.

*
Excluding gains on sale of assets, TCPL's net earnings increased $67
million to $851 million compared to $784 million.

Investing Activities

*
In 2005, TCPL invested more than $2.0 billion in the Gas Transmission
and Power businesses.

Balance Sheet

*
In 2005, TCPL's shareholders' equity increased by more than $0.6
billion.

CONSOLIDATED RESULTS-AT-A-GLANCE
Year ended December 31 (millions of dollars)
2005 2004 2003
Net income applicable to common shares
Continuing operations 1,208 978 801
Discontinued operations - 52 50
1,208 1,030 851

MANAGEMENT'S DISCUSSION AND ANALYSIS 3

SEGMENT RESULTS-AT-A-GLANCE
Year ended December 31 (millions of dollars)
2005 2004 2003

Gas Transmission Net Earnings
Excluding gains 635 579 622
Gain on sale of PipeLines LP units 49 - -
Gain on sale of Millennium - 7 -

684 586 622

Power Net Earnings
Excluding gains 253 209 220
Gain on sale of Paiton Energy 115 - -
Gains related to Power LP 193 187 -

561 396 220

Corporate (37 ) (4 ) (41 )

Net income applicable to common shares
Continuing Operations(1) 1,208 978 801
Discontinued Operations - 52 50

1,208 1,030 851

(1)Net Income Applicable To Common Shares From Continuing
Operations:
Excluding gains 851 784 801
Gains related to Paiton Energy, PipeLines LP, Power LP and 357 194 -
Millennium
1,208 978 801

Net income applicable to common shares for the year ended December 31, 2005 was
$1,208 million compared to $1,030 million for 2004 and $851 million for 2003.
This includes net income from discontinued operations of $52 million in 2004 and
$50 million in 2003, reflecting income recognized on the initially deferred
gains relating to the disposition in 2001 of the company's Gas Marketing
business.

TCPL's net earnings for the year ended December 31, 2005 were $1,208 million
compared to $978 million and $801 million in 2004 and 2003, respectively. Net
earnings for 2005 included after-tax gains of $193 million on the sale of the
company's interest in TransCanada Power, L.P. (Power LP), $115 million on the
sale of the company's interest in P.T. Paiton Energy Company (Paiton Energy) and
$49 million on the sale of TC PipeLines, LP (PipeLines LP) units, while net
earnings for 2004 included after-tax gains of $187 million on the sale of the
ManChief and Curtis Palmer assets to Power LP and the recognition of dilution
gains resulting from a reduction in TCPL's ownership interest in Power LP and
other previously deferred gains, as well as a $7 million after-tax gain on sale
of the company's equity interest in the Millennium Pipeline Project
(Millennium).

Excluding the total gains of $357 million recorded in 2005 and total gains of
$194 million recorded in 2004, net earnings for 2005 of $851 million increased
$67 million compared to 2004. This was mainly due to an increase in net earnings
from the Gas Transmission and Power businesses, partially offset by an increase
in net expenses in Corporate.

Excluding the gains on sale of PipeLines LP units in 2005 and the Millennium
interest in 2004, the $56 million increase in net earnings from the Gas
Transmission business for 2005 compared to 2004 was primarily attributable to a

4 MANAGEMENT'S DISCUSSION AND ANALYSIS

$57 million increase as a result of a full year of net earnings from the Gas
Transmission Northwest System and the North Baja System (collectively GTN),
acquired on November 1, 2004. In addition, Gas Transmission's net earnings for
2005 included approximately $35 million ($13 million related to 2004 and $22
million related to 2005) as a result of the April 2005 National Energy Board
(NEB) decision on the Canadian Mainline's 2004 Tolls and Tariff Application
(Phase II). This decision dealt with capital structure and included an increase
in the deemed common equity ratio to 36 per cent from 33 per cent for 2004,
which was also effective for 2005 under the 2005 tolls settlement. The increase
in Canadian Mainline's net earnings for 2005 as a result of this NEB decision
was partially offset by a combination of a lower average investment base, lower
earnings related to operating cost savings and a decrease in the approved rate
of return on common equity (ROE) in 2005 compared to 2004. These increases in
net earnings were partially offset by lower net earnings from TCPL's Other Gas
Transmission businesses.

Excluding the gains related to the company's investments in Power LP in 2004
and 2005 and Paiton Energy in 2005, Power's net earnings for 2005 increased $44
million compared to 2004 as a result of higher operating and other income from
Bruce Power (being the collective investments in Bruce Power A L.P. (Bruce A)
and Bruce Power L.P. (Bruce B)) and Eastern Operations, partially offset by a
lower contribution from Western Operations and higher general, administrative,
support costs and other.

The increase in net expenses of $33 million in Corporate in 2005 compared to
2004 was primarily due to increased net interest expense on higher average
long-term debt and commercial paper balances in 2005 as well as the release in
2004 of previously established restructuring provisions.

The increase in net earnings of $177 million in 2004 compared to 2003 included
$187 million of gains related to Power LP and a $7 million gain on sale of
Millennium. Excluding these gains, 2004 net earnings decreased $17 million from
2003. Lower net earnings in the Gas Transmission and Power businesses were
partially offset by reduced net expenses in Corporate. The decrease in net
earnings, excluding gains, of $43 million in the Gas Transmission business in
2004 compared to 2003 was primarily due to a decline in the Alberta System's and
Canadian Mainline's net earnings. The $11 million decrease in Power's net
earnings, excluding gains, in 2004 compared to 2003 was primarily due to a $19
million after-tax settlement with a counterparty in 2003. The decrease in net
expenses of $37 million in Corporate in 2004 compared to 2003 was primarily due
to the positive impacts of income tax, foreign exchange related items and
release of the restructuring provisions in 2004.

FORWARD-LOOKING INFORMATION

Certain information in this MD&A includes forward-looking statements. All
forward-looking statements are based on TCPL's beliefs and assumptions based on
information available at the time the assumptions were made. Forward-looking
statements relate to, among other things, anticipated financial performance,
business prospects, strategies, regulatory developments, new services, market
forces, commitments and technological developments. By its nature, such
forward-looking information is subject to various risks and uncertainties,
including those material risks discussed in this MD&A under "Gas Transmission -
Business Risks" and "Power - Business Risks", which could cause TCPL's actual
results and experience to differ materially from the anticipated results or
other expectations expressed. The material assumptions in making these
forward-looking statements are disclosed in this MD&A under the headings
"Overview and Strategic Priorities", "Gas Transmission - Opportunities and
Developments", "Gas Transmission - Outlook", "Power - Opportunities and
Developments" and "Power - Outlook". Readers are cautioned not to place undue
reliance on this forward-looking information, which is given as of the date it
is expressed in this MD&A or otherwise, and TCPL undertakes no obligation to
update publicly or revise any forward-looking information, whether as a result
of new information, future events or otherwise.

MANAGEMENT'S DISCUSSION AND ANALYSIS 5

TCPL OVERVIEW

TCPL is a leading North American energy infrastructure company with a strong
focus on natural gas transmission and power generation opportunities located in
regions in which it has significant competitive advantages. Natural gas
transmission and power are complementary businesses for TCPL. They are driven by
similar supply and demand fundamentals, they are both capital intensive
businesses, and they use similar technology and operating practices. They are
also businesses with significant long-term growth prospects.

North American natural gas demand is growing and is mainly driven by the demand
for electricity. Experts predict that demand for electricity will increase at an
average annual rate of approximately two per cent over the next ten years
primarily due to a growing population and an increase in gross domestic product.
A large part of this growth is expected to be met through higher utilization of
natural gas-fired power generating plants that were built as part of the
significant capacity additions that occurred in many North American markets over
the last five years.

Nuclear facilities have played, and will continue to play, a significant role
in supplying North America with power and new nuclear capacity is expected to
come on stream over time. Coal-fired plants remain the largest source of
electric power in North America and coal reserves are significant. However, the
long lead times required to complete new coal and nuclear projects, the
associated environmental and socio-economic issues, the high capital costs and
the difficulty in locating these plants near load centres may impede the
development and completion of new coal or nuclear generation over the next five
to ten years. As a result, North America is expected to continue to rely on
natural gas-fired generation to satisfy its growing electricity needs in the
near term. This is expected to lead to a significant increase in natural gas
consumption. Natural gas demand in North America, including Mexico, is expected
to grow to approximately 92 billion cubic feet per day (Bcf/d) by 2015, an
increase of 16 Bcf/d when compared to 2005. New natural gas-fired power
generation is expected to account for approximately 10 Bcf/d of that growth.

While growing demand will provide a number of opportunities, the natural gas
industry also faces a number of challenges. North America has entered a period
when it will no longer be able to rely solely on traditional sources of natural
gas supply to meet its growing needs. Current high natural gas prices suggest
that North America is in a period of transition and significant change. Natural
gas supply is tight and this is likely to continue until major investments are
made in the infrastructure required to bring new supply to market. Looking
forward, production from North America's traditional basins is expected to
essentially remain flat over the next decade. An increase in production in the
United States Rockies will likely only offset declines in other basins,
including the Gulf of Mexico. This outlook for traditional basins means that
northern gas and offshore liquefied natural gas (LNG) will be required to fill
the expected shortfall between supply and demand. TCPL is well positioned in
North America to serve growing power demand in the near term and to bring new
natural gas supplies to market in the medium to longer term.

TCPL'S STRATEGY

TCPL's strong position is the direct result of successfully executing its
corporate strategy which was first adopted in 2000. While the plan has evolved
over time in response to actual and anticipated changes in the business
environment, it fundamentally remains the same. Today, TCPL's corporate strategy
consists of the following five components:

*
Grow the North American Gas Transmission business.

*
Maximize the long-term value of existing Gas Transmission assets.

*
Grow the North American Power business.

*
Drive for operational excellence.

*
Maximize TCPL's competitive strength, its opportunities and options, and
its enduring value.

6 MANAGEMENT'S DISCUSSION AND ANALYSIS

Gas Transmission

Strategy

The company's strategy in Gas Transmission is focused on growing its North
American business while maximizing the long-term value of its existing natural
gas transmission assets. In order to grow the Gas Transmission business, TCPL is
focusing its efforts on expanding and extending its existing systems to connect
new supply to growing markets, increasing its ownership in partially-owned
entities, acquiring or constructing pipelines that provide it with a significant
regional presence, expanding into crude oil transmission and in the long term,
connecting new sources of supply in the form of northern natural gas and LNG.

Over the past 50 years, TCPL has developed significant expertise in
large-diameter, cold-climate natural gas pipeline design, construction,
operation and maintenance. It has also developed significant expertise in the
design, optimization and operation of large gas turbine compressor stations.
Today, TCPL operates one of the largest, most sophisticated, remote-controlled
pipeline networks in the world with a solid reputation for safety and
reliability. TCPL also has strong project development and management skills and
is committed to the highest levels of operational excellence. The company's
strong financial position allows it to build large-scale infrastructure and act
quickly on quality opportunities as they arise.

In addition to growing the North American Gas Transmission business, the
company continues to place a strategic priority on maximizing the long-term
value of its wholly-owned pipelines. Efforts in this area are focused on
achieving a fair return on invested capital, developing highly competitive
tariff structures, and streamlining and harmonizing processes and tariff
provisions for and among TCPL's regulated pipelines. Further, the company
continues to work collaboratively with its customers to develop and implement
new services that deliver value to customers while sustaining TCPL's Gas
Transmission business.

Existing Pipelines

TCPL's natural gas transmission assets link the Western Canada Sedimentary Basin
(WCSB) with premium North American markets. With more than 41,000 kilometres
(km) of pipeline, the company's wholly-owned gas transmission network is one of
the largest in North America.

In 2005, the wholly-owned Alberta System gathered 66 per cent of the natural
gas produced in Western Canada, equal to 17 per cent of total North American
production. TCPL exports gas from the WCSB to Eastern Canada as well as the U.S.
West, Midwest and Northeast through four wholly-owned pipeline systems:

*
the Canadian Mainline;

*
the Gas Transmission Northwest System;

*
the Foothills System; and

*
the BC System.

TCPL also exports gas from the WCSB to Eastern Canada as well as the U.S. West,
Midwest and Northeast through six pipeline systems in which TCPL holds the
following ownership interests:

*
Trans Quebec & Maritimes System (TQM) - 50 per cent;

*
Great Lakes Gas Transmission System (Great Lakes) - 50 per cent;

*
Iroquois Gas Transmission System (Iroquois) - 44.5 per cent;

*
Portland Natural Gas Transmission System (Portland) - 61.7 per cent;

*
Northern Border Pipeline (Northern Border) - 4 per cent; and

*
Tuscarora Gas Transmission System (Tuscarora) - 7.6 per cent.

MANAGEMENT'S DISCUSSION AND ANALYSIS 7

Northern Development

In 2005, TCPL continued to pursue pipeline opportunities to move both Mackenzie
Delta and Alaska North Slope natural gas to markets throughout North America. If
the Mackenzie Gas Pipeline Project and the Alaska Highway Pipeline Project are
constructed and connected to TCPL's existing infrastructure, they will represent
additional growth opportunities for TCPL and enhance the long-term viability and
value of the company's existing Gas Transmission business, especially the
wholly-owned pipelines.

Mexico

In June 2005, TCPL was awarded a contract to construct, own and operate a
natural gas pipeline in east-central Mexico. The 36 inch, 125 km Tamazunchale
Pipeline will extend from the facilities of Pemex Gas near Naranjos, Veracruz
and transport natural gas to an electricity generation station near
Tamazunchale, San Luis Potosi. TCPL expects to invest approximately US$181
million in the project with a planned in-service date of December 1, 2006. The
pipeline will be designed to transport initial volumes of 170 million cubic feet
per day (mmcf/d). Under the contract, the capacity of the Tamazunchale Pipeline
is expected to be expanded beginning in 2009 to approximately 430 mmcf/d to meet
the needs of two additional proposed power plants near Tamazunchale. TCPL
continues to explore other pipeline and energy infrastructure opportunities in
Mexico.

LNG

TCPL continues to work toward gaining regulatory approval for its two LNG
projects: Cacouna in Quebec, a joint venture with Petro-Canada; and the
Broadwater Energy project (Broadwater), offshore of New York State in Long
Island Sound, a joint venture with Shell US Gas & Power LLC (Shell). TCPL, on
behalf of Broadwater, filed a formal application with the U.S. Federal Energy
Regulatory Commission (FERC) on January 30, 2006 for federal approval to
construct and operate Broadwater.

Natural Gas Storage

The company's initiatives in the natural gas storage business are a logical
extension of its Gas Transmission business. TCPL believes Alberta-based natural
gas storage will continue to serve market needs and could play an important role
should northern gas be connected to North American markets. In the first quarter
of 2005, TCPL started development of a natural gas storage facility near Edson,
Alberta. The Edson facility is expected to have a capacity of approximately 60
petajoules (PJ) and will connect to TCPL's Alberta System. In addition, in 2004,
the company secured a long-term contract with a third party for existing
Alberta-based natural gas storage capacity, increasing from 20 PJ in 2005 to 30
PJ in 2006 and to 40 PJ in 2007. These initiatives, combined with the company's
current 60 per cent ownership interest in CrossAlta Gas Storage & Services Ltd.
(CrossAlta), position TCPL to become one of the largest natural gas storage
providers in Western Canada. With more than 130 PJ of storage capacity by 2007,
TCPL will own or lease approximately one-third of the natural gas storage
capacity available in Alberta.

Oil Transmission

In November 2005, TCPL, ConocoPhillips Company and ConocoPhillips Pipe Line
Company (CPPL), a wholly-owned subsidiary of ConocoPhillips Company, signed a
Memorandum of Understanding (MOU) which commits ConocoPhillips Company to ship
crude oil on the proposed Keystone oil pipeline (Keystone pipeline), and gives
CPPL the right to acquire up to a 50 per cent participating interest in the
pipeline. On January 31, 2006, TCPL announced that through the binding Open
Season held in fourth quarter 2005 it had secured firm, long-term contracts
totalling 340,000 barrels per day of crude oil with an average term of 18 years.
The Keystone pipeline, expected to cost approximately US$2.1 billion, will have
an initial capacity to transport approximately 435,000 barrels per day of crude
oil from Hardisty, Alberta to Patoka, Illinois through a 2,960 km pipeline
system.

Regulatory

In 2005, TCPL's principal regulatory activities and events included:

*
a decision by the NEB to increase the deemed equity ratio of the
Canadian Mainline to 36 per cent from 33 per cent following the
completion of the hearings of the Canadian Mainline's 2004 Tolls and
Tariff Application (Phase II);

*
a negotiated settlement with respect to 2005 Canadian Mainline tolls;

8 MANAGEMENT'S DISCUSSION AND ANALYSIS

*
a revenue requirement settlement for 2005, 2006 and 2007 for the Alberta
System;

*
a hearing before the Alberta Energy and Utilities Board (EUB) on the
rate design of the Alberta System, with potential implications for the
competitiveness of the Alberta System;

*
an agreement with the Canadian Association of Petroleum Producers (CAPP)
and other stakeholders to increase the deemed common equity ratios on
the Foothills System and the BC System to 36 per cent from 30 per cent,
effective January 1, 2006; and

*
commencement of settlement negotiations with its Canadian Mainline
shippers regarding 2006 tolls.

Power

TCPL has built a substantial power business over the past decade. The power
plants and power supply that TCPL owns, operates and/or controls, including
projects under construction, represent approximately 6,700 megawatts (MW) of
power generation capacity in Canada and the U.S. The company's power assets are
concentrated in two main regions - the western business focused in Alberta and
the eastern business focused in the Northeastern U.S. and Eastern Canada
markets.

Strategy

TCPL's strategy for growth and value creation in Power is driven by four
principles:

*
acquire low-cost, base-load generation in markets it knows. The company
believes that being a low-cost provider is critical to being successful
in volatile power markets;

*
develop low-risk, greenfield generation projects, backed by long-term
input and sales contracts with quality counterparties. The company
believes that long-term contracts are an essential part of most
greenfield development projects.

*
actively participate in markets that are in transition. The changes that
took place in Alberta and the Northeastern U.S., and the changes that
continue in Ontario and Quebec, allow the company to capture
opportunities that are created as a result of power markets in
transition; and

*
optimize the existing asset portfolio by running the company's
facilities as efficiently and cost-effectively as possible through
operational excellence.

TCPL's ability to successfully execute its strategy is directly related to the
following core competencies in the power business:

*
broad understanding of North American energy markets and a deep
understanding of its core markets in Alberta, Eastern Canada and the
Northeastern U.S.;

*
active participation in deregulated and deregulating markets;

*
ability to structure transactions and manage risk which is critical to
mitigating volatility and uncertainty for industrial customers and
shareholders;

*
a strong financial position which allows the company to build
large-scale infrastructure and gives it the ability to act quickly on
quality opportunities as they arise; and

*
strong project development, project management and operational skills.

In 2005, TCPL continued to add to its diverse portfolio of quality power
generation assets.

Becancour and Cartier Wind

Throughout 2005, TCPL continued to advance the Becancour and Cartier Wind Energy
(Cartier Wind) power projects. Construction of the 550 MW Becancour cogeneration
plant near Trois Rivieres, Quebec, remains on schedule to begin operations in
September 2006. The 739.5 MW Cartier Wind project, 62 per cent owned by TCPL,
awarded construction contracts in late 2005, and is expected to commence
construction in early 2006. Located in the Gaspesie region of

MANAGEMENT'S DISCUSSION AND ANALYSIS 9

Quebec, the first of the six projects that comprise Cartier Wind is anticipated
to be commissioned beginning in late 2006 with the remaining projects being
commissioned through to 2012. The entire power output from both Becancour and
Cartier Wind will be supplied to Hydro-Quebec Distribution (Hydro-Quebec) under
20 year power purchase contracts.

TC Hydro

In April 2005, TCPL acquired from USGen New England, Inc. (USGen), hydroelectric
generation assets (TC Hydro) with total generating capacity of 567 MW, for
approximately US$503 million. These are low operating cost power generation
assets serving the New England market.

Bruce Power

In October 2005, Bruce Power and the Ontario Power Authority (OPA), entered into
a long-term agreement whereby Bruce A will restart and refurbish the currently
idle Units 1 and 2, extend the operating life of Unit 3 by replacing its steam
generators and fuel channels when required and replace the steam generators on
Unit 4. The capital program for the restart and refurbishment work is expected
to total approximately $4.25 billion and TCPL's approximate $2.125 billion share
will be financed through capital contributions to 2011. Work to refurbish Units
1 and 2 was initiated in 2005 and the first unit is expected to be on-line in
2009. Restarting Units 1 and 2 will add approximately 1,500 MW to Bruce Power's
existing generation capacity of 4,700 MW All of the Bruce A output will be sold
to the OPA under fixed price contract terms.

As a result of the agreement between Bruce Power and the OPA, and the decision
by Cameco Corporation (Cameco) not to participate in the restart and
refurbishment program, a new partnership, Bruce A, was created. The Bruce A
partnership subleases the Bruce A facilities, comprised of Units 1 to 4, from
Bruce B. The effect of these transactions was that TCPL and BPC Generation
Infrastructure Trust (BPC) each incurred a net cash outlay of $100 million and
as at December 31, 2005 each owned a 47.9 per cent interest in Bruce A.

Sheerness PPA

In December 2005, TCPL acquired the remaining rights and obligations under the
756 MW Sheerness Power Purchase Arrangement (PPA) from the Alberta Balancing
Pool for $585 million. The remaining term of the PPA is 15 years. The Sheerness
power plant, which consists of two low-cost coal-fired thermal power generating
units, is located approximately 230 km northeast of Calgary, Alberta.

Grandview

Construction of the 90 MW Grandview natural gas-fired cogeneration power plant
located in Saint John, New Brunswick, was completed at the end of 2004. It was
commissioned in January 2005. Under a 20 year tolling arrangement, 100 per cent
of the plant's heat and electricity output is sold to Irving Oil (Irving).

TCPL expects its Power business to continue to be a key growth driver. The
company is committed to growing the Power business through asset acquisitions,
selected greenfield developments and further expansions of its existing
business. TCPL's goal is to build and establish a diverse portfolio of high
quality assets that deliver strong returns to shareholders.

OPERATIONAL EXCELLENCE AND "SPIRIT"

In addition to growing its Gas Transmission and Power businesses, TCPL is
committed to an operational excellence business model. The company's focus is on
being a low-cost, reliable and safe operator that provides responsive services
to its customers in an effective and timely manner.

The company's values guide the way business is conducted at TCPL. Within TCPL,
these values are commonly referred to as "SPIRIT". They are the principles that
direct how the company works and they include: Social responsibility, Passion,
Integrity, Results, Innovation and Teamwork. The company's commitment to these
values helps ensure it maintains its reputation as one of North America's
premier energy infrastructure companies.

10 MANAGEMENT'S DISCUSSION AND ANALYSIS

COMPETITIVE STRENGTH AND ENDURING VALUE

TCPL's strategy also focuses on developing and enhancing those strengths that
are at the core of its corporate success:

*
developing excellence in value-creating strategy, analysis and
investment execution;

*
continuing to improve its financial capacity and flexibility;

*
maintaining its corporate governance initiatives and its culture of
honesty and integrity;

*
developing and sustaining its relationships and reputation with all key
stakeholders; and

*
creating sustainable organizational and people strengths.

These initiatives bring competitive advantage and facilitate the effective
delivery of results for the company's Gas Transmission and Power businesses.

TCPL has approximately 2,350 employees who through their talent, integrity,
hard work and results provide the company with a strong competitive advantage
driven by industry-leading expertise in pipeline and power operations, depth of
market and industry knowledge, financial acumen and exceptional infrastructure
project capabilities.

OUTLOOK

TCPL's corporate strategy is underpinned by a long-term focus on growing its Gas
Transmission and Power businesses in a disciplined and measured manner. This
strategy was initiated in 2000 and has been consistently followed. In 2006 and
beyond, the company's net earnings and cash flow, combined with a strong balance
sheet, are expected to continue to provide the financial flexibility for TCPL to
capture further opportunities and create additional long-term value for
shareholders.

In Gas Transmission, the company will continue to focus its efforts on
maximizing the long-term value from its pipeline and natural gas storage assets,
including efforts to connect new long-term supply to growing markets. This focus
will take a variety of forms in 2006 including:

*
working with natural gas producers and the Aboriginal Pipeline Group
(APG), including participating in regulatory proceedings as may be
required, to advance the Mackenzie Gas Pipeline Project with an ultimate
goal of connecting new northern natural gas supply to TCPL's existing
facilities and obtaining an equity ownership interest in the project;

*
working with natural gas producers and the State of Alaska to advance
the proposed Alaska Highway Pipeline Project, thereby connecting another
source of northern natural gas supply to TCPL's facilities;

*
advancing development of the Cacouna and Broadwater LNG facilities which
will, upon completion, connect new natural gas supply to existing and
growing markets in Eastern North America. TCPL will have a 50 per cent
ownership interest in each of these projects and these new natural gas
supplies are expected to increase natural gas flows on certain of TCPL's
natural gas pipeline systems;

*
advancing development of the innovative Keystone pipeline which includes
conversion of a portion of TCPL's existing facilities from natural gas
to crude oil transmission, thereby providing cost-effective and much
needed pipeline capacity for the Alberta oil sands;

*
completing construction of the Tamazunchale natural gas pipeline in
Mexico, which is expected at the end of 2006;

*
continuing discussions with Canadian Mainline stakeholders towards a
settlement on 2006 tolls;

*
advancing the expansion of the North Baja System;

*
transitioning to the operatorship of Northern Border Pipeline in early
2007; and

*
filing a rate case with FERC with a goal of establishing new rates for
the Gas Transmission Northwest System.

MANAGEMENT'S DISCUSSION AND ANALYSIS 11

In addition, Gas Transmission will continue to grow its natural gas storage
business in 2006 through completion of the Edson facility, an expanded CrossAlta
facility and increased capacity under a long-term contract with a third party.
TCPL will also seek to continue to capitalize on opportunities to increase its
ownership in its partially-owned pipelines and acquire interests in new
pipelines in markets where TCPL has a significant regional presence.

In Power, TCPL has had significant success in growing this segment and, in
2006, will continue to focus its efforts on further growth. As in 2005 and prior
years, this growth is expected to come from a combination of greenfield
developments, new acquisitions and organic growth within its existing assets and
markets. In particular, in 2006, TCPL is expected to:

*
work with Bruce A and its partners to advance the restart and
refurbishment of the Bruce A units;

*
complete construction of the 550 MW Becancour power plant in late 2006;

*
complete construction of the first of six Cartier Wind projects at the
end of 2006 and continue construction of the second wind facility;

*
integrate the newly acquired Sheerness PPA into Power's Western
Operations; and

*
pursue additional greenfield projects and acquisition opportunities in
TCPL's key regional markets.

The following discussion reflects management's expectations for 2006, as
discussed throughout this MD&A. A number of risk factors and developments may
positively or negatively affect the actual results for 2006, including new
acquisitions, advancement of greenfield developments, regulatory decisions and
settlements, customer bankruptcies, market changes in commodity prices, weather
and interest rates as well as unplanned outages on various Gas Transmission and
Power assets. The performance of the Canadian dollar relative to the U.S. dollar
would either positively or negatively impact TCPL's net earnings, although this
impact is mitigated by partially offsetting exposures in certain of the
company's businesses as well as through the company's hedging activities.

In 2006, TCPL expects reduced net earnings from the Gas Transmission business
compared to 2005 (excluding the gain on sale of PipeLines LP units in 2005). The
combined effects of an expected net decline in the rate base of each of the
Canadian Mainline and Alberta System and the decline in each of their respective
allowed ROEs are expected to decrease net earnings on these systems compared to
2005. In addition, reduced firm contract volumes on the Gas Transmission
Northwest System, partially due to the effects of customer bankruptcies, are
expected to have a slightly negative impact on the Gas Transmission Northwest
System results compared to 2005, although it is uncertain what impact the 2006
rate case filing may have on the system's results. Lastly, anticipated lower
firm service revenues on certain partially-owned pipelines and a full year of
reduced ownership of PipeLines LP are expected to be only partially offset by
the effects of a higher allowed deemed common equity component on the Foothills
System and the BC System and the expected growth in natural gas storage net
earnings.

In the Power business, 2006 net earnings are expected to be higher than in 2005
(excluding the gains on sales related to Power LP and Paiton Energy in 2005) due
to higher Bruce Power results reflecting an increased ownership in Bruce A and
fewer planned outages, increased contributions from Western Operations
reflecting the acquisition of the Sheerness PPA, slightly improved Eastern
Operations' results reflecting a full year of TC Hydro operations as well as
initial contributions from Becancour and Cartier Wind expected in late 2006.
Offsetting these improved results is the loss of income due to the sale of Power
LP in 2005.

12 MANAGEMENT'S DISCUSSION AND ANALYSIS

GAS TRANSMISSION

HIGHLIGHTS

Net Earnings

*
Net earnings from Gas Transmission increased $98 million to $684 million
in 2005 compared to $586 million in 2004.

*
This increase is primarily due to a full year of GTN earnings in 2005
and the gain on sale of PipeLines LP units.

Canadian Mainline

*
The NEB, in its decision on the 2004 Tolls and Tariff Application (Phase
II), approved an increase in the deemed common equity component of the
Canadian Mainline's capital structure to 36 per cent from 33 per cent,
effective January 1, 2004.

*
The NEB approved a negotiated settlement of 2005 Canadian Mainline
tolls.

Alberta System

*
The EUB approved a three year revenue requirement settlement negotiated
with shippers and other stakeholders. The settlement finalized the 2005
revenue requirement as well as established a framework for calculating
the 2006 and 2007 revenue requirements. Most costs are treated on a flow
through basis but certain costs have been fixed in each of the three
years.

GTN

*
GTN contributed $71 million of earnings in 2005.

*
Successfully integrated into TCPL's business.

Foothills System and BC System

*
Following an agreement with CAPP and other stakeholders to increase the
deemed common equity component of the capital structure to 36 per cent
from 30 per cent for the Foothills System and BC System and discussions
with its shippers on those two systems, on December 2, 2005, TCPL filed
applications with the NEB for final 2006 tolls. On December 21, 2005,
the NEB approved the Foothills System 2006 tolls as final tolls,
effective January 1, 2006. On February 22, 2006, the NEB finalized the
BC System's 2006 tolls as filed.

Other Gas Transmission

*
TCPL sold approximately 3.5 million common units of PipeLines LP for an
after-tax gain on sale of approximately $49 million.

*
TCPL continued to fund the APG participation in the Mackenzie Gas
Pipeline Project.

*
TCPL commenced development of a natural gas storage project near Edson,
Alberta.

*
TCPL was awarded the contract to construct, own and operate the
Tamazunchale Pipeline in east-central Mexico. Construction commenced in
2005.

*
TCPL closed the acquisition of a 3.5 per cent ownership interest in
Iroquois, increasing its ownership interest to 44.5 per cent.

MANAGEMENT'S DISCUSSION AND ANALYSIS 13

CANADIAN MAINLINE TCPL's 100 per cent owned, 14,898 km natural gas
transmission system in Canada extends from the Alberta/Saskatchewan border east
to the Quebec/Vermont border and connects with other natural gas pipelines in
Canada and the U.S.

ALBERTA SYSTEM TCPL's 100 per cent owned natural gas transmission system in
Alberta gathers natural gas for use within the province and delivers it to
provincial boundary points for connection with the Canadian Mainline, BC System,
the Foothills System and other pipelines. The 23,339 km system is one of the
largest carriers of natural gas in North America.

GAS TRANSMISSION NORTHWEST SYSTEM TCPL's 100 per cent owned, 2,174 km natural
gas transmission system links the BC System and the Foothills System with
Pacific Gas and Electric Company's California Gas Transmission System, with the
Northwest Pipeline and with Tuscarora, a partially-owned entity that runs from
the Oregon/California border into Nevada.

FOOTHILLS SYSTEM TCPL's 100 per cent owned, 1,040 km natural gas transmission
system in Western Canada carries natural gas for export from central Alberta to
the U.S. border to serve markets in the U.S. Midwest, Pacific Northwest,
California and Nevada.

BC SYSTEM TCPL's 100 per cent owned natural gas transmission system extends
201 km from Alberta's western border through British Columbia to connect with
the Gas Transmission Northwest System at the U.S. border, serving markets in
B.C. as well as the Pacific Northwest, California and Nevada.

14 MANAGEMENT'S DISCUSSION AND ANALYSIS

NORTH BAJA SYSTEM TCPL's 100 per cent owned, 129 km natural gas transmission
system extends from southwestern Arizona to a point near Ogilby, California on
the California/Mexico border and connects with the Gasoducto Bajanorte pipeline
system in Mexico.

VENTURES LP Ventures LP, which is 100 per cent owned by TCPL, owns a 121 km
pipeline and related facilities which supply natural gas to the oil sands region
of northern Alberta, and a 27 km pipeline which supplies natural gas to a
petrochemical complex at Joffre, Alberta.

GREAT LAKES Great Lakes connects with the Canadian Mainline at Emerson,
Manitoba and serves markets in central Canada and the eastern and midwestern
U.S. TCPL has a 50 per cent ownership interest in this 3,402 km pipeline system.

TQM TQM is a 572 km natural gas pipeline system which connects with the
Canadian Mainline and transports natural gas from Montreal to Quebec City and to
the Portland system. TCPL holds a 50 per cent ownership interest in TQM.

IROQUOIS Iroquois connects with the Canadian Mainline near Waddington, New
York and delivers natural gas to customers in the Northeastern U.S. TCPL has a
44.5 per cent ownership interest in this 663 km pipeline system.

PORTLAND Portland is a 474 km pipeline that connects with TQM near East
Hereford, Quebec and delivers natural gas to customers in the Northeastern U.S.
TCPL has a 61.7 per cent ownership interest in Portland.

NORTHERN BORDER Northern Border is a 2,010 km natural gas pipeline system
which serves the U.S. Midwest from a connection with the Foothills System near
Monchy, Saskatchewan. TCPL indirectly owns approximately 4 per cent of Northern
Border through its 13.4 per cent ownership interest in PipeLines LP.

TUSCARORA Tuscarora operates a 386 km pipeline system transporting natural gas
from the Gas Transmission Northwest System at Malin, Oregon to Wadsworth, Nevada
with delivery points in northeastern California and northwestern Nevada. TCPL
owns an aggregate 7.6 per cent interest in Tuscarora, of which 6.6 per cent is
held through TCPL's interest in PipeLines LP.

TAMAZUNCHALE TCPL is currently constructing the Tamazunchale natural gas
pipeline in east central Mexico. The 125 km pipeline will extend from the
facilities of Pemex Gas near Naranjos, Veracruz to an electricity generation
station near Tamazunchale, San Luis Potosi. TCPL will operate and own 100 per
cent of the pipeline. This pipeline is expected to be in service on December 1,
2006.

TRANSGAS TransGas is a 344 km natural gas pipeline system which runs from
Mariquita in the central region of Colombia to Cali in the southwest of
Colombia. TCPL holds a 46.5 per cent ownership interest in this pipeline.

GAS PACIFICO Gas Pacifico is a 540 km natural gas pipeline extending from Loma
de la Lata, Argentina to Concepcion, Chile. TCPL holds a 30 per cent ownership
interest in Gas Pacifico.

INNERGY INNERGY is an industrial natural gas marketing and distribution
company based in Concepcion, Chile that markets and distributes natural gas
transported on Gas Pacifico. TCPL holds a 30 per cent ownership interest in
INNERGY.

CROSSALTA CrossAlta is an underground natural gas storage facility connected
to the Alberta System and is located near Crossfield, Alberta. CrossAlta has a
working natural gas capacity of 56 PJ with a maximum deliverability capability
of 0.45 PJ per day. TCPL holds a 60 per cent ownership interest in CrossAlta.

EDSON TCPL is currently developing the Edson natural gas storage facility near
Edson, Alberta. The Edson facility is expected to have a capacity of
approximately 60 PJ and will connect to TCPL's Alberta System. Storage capacity
is expected to be available from the Edson facility, on a phased-in basis,
commencing mid-2006.

BROADWATER Broadwater, a joint venture with Shell, is a proposed LNG project
offshore of New York State in Long Island Sound, capable of receiving, storing
and regasifying imported LNG with an average send-out capacity of approximately
one Bcf/d of natural gas.

CACOUNA Cacouna, a joint venture with Petro-Canada, is a proposed LNG project
at Gros Cacouna harbour on the St. Lawrence River, capable of receiving, storing
and regasifying imported LNG with an average send-out capacity of approximately
500 mmcf/d of natural gas.

MANAGEMENT'S DISCUSSION AND ANALYSIS 15

GAS TRANSMISSION RESULTS-AT-A-GLANCE
Year ended December 31 (millions of dollars)
2005 2004 2003

Wholly-Owned Pipelines
Canadian Mainline 283 272 290
Alberta System 150 150 190
GTN(1) 71 14 -
Foothills System(2) 21 22 20
BC System 6 7 6

531 465 506

Other Gas Transmission
Great Lakes 46 55 52
Iroquois 17 17 18
PipeLines LP(3) 9 16 15
Portland(4) 11 10 11
Ventures LP(5) 12 15 10
TQM 7 8 8
CrossAlta 19 13 6
TransGas 11 11 22
Northern Development (4 ) (6 ) (4 )
General, administrative, support costs and other (24 ) (25 ) (22 )

104 114 116
Gain on sale of PipeLines LP units (after tax) 49 - -
Gain on sale of Millennium (after tax) - 7 -

153 121 116

Net earnings 684 586 622

(1)
TCPL acquired GTN on November 1, 2004. Amounts in this table reflect TCPL's
100 per cent ownership interest in GTN's net earnings from the acquisition
date.

(2)
The remaining ownership interests in the Foothills System, previously not
held by TCPL, were acquired on August 15, 2003.

(3)
During 2005, TCPL decreased its ownership interest in PipeLines LP to 13.4
per cent from 33.4 per cent.

(4)
TCPL increased its ownership interest in Portland to 61.7 per cent from 33.3
per cent in 2003.

(5)
TransCanada Pipeline Ventures Limited Partnership.

In 2005, net earnings from the Gas Transmission business were $684 million
compared to $586 million and $622 million in 2004 and 2003, respectively. The
increase in 2005 compared to 2004 was mainly due to higher net earnings from
Wholly-Owned Pipelines and a gain on sale of PipeLines LP units, partially
offset by lower net earnings from Other Gas Transmission. The increase in
Wholly-Owned Pipelines' net earnings in 2005 was primarily due to a full year of
GTN net earnings and higher Canadian Mainline net earnings. Lower net earnings
in 2005 from Other Gas Transmission were primarily due to decreased earnings
from Great Lakes and PipeLines LP, partially offset by higher earnings for
CrossAlta.

The overall decrease of $36 million in 2004 Gas Transmission net earnings
compared to 2003 was mainly due to lower net earnings from Wholly-Owned
Pipelines. The decrease in Wholly-Owned Pipelines' net earnings in 2004 was
primarily due to a reduction in the Alberta System's net earnings, reflecting
the EUB's disallowance of certain operating costs in

16 MANAGEMENT'S DISCUSSION AND ANALYSIS

its decision on Phase I of the 2004 General Rate Application (GRA) and in its
decision in the generic cost of capital (GCOC) proceeding to allow an ROE in
2004 lower than the return implicit in the 2003 revenue requirement settlement
with stakeholders. In addition, net earnings on the Canadian Mainline were lower
in 2004 compared to 2003 due to a decline in both the average investment base
and the allowed ROE. The addition of GTN had a positive effect on net earnings
in 2004.

GAS TRANSMISSION - FINANCIAL ANALYSIS

Canadian Mainline

The Canadian Mainline is regulated by the NEB. The NEB sets tolls which provide
TCPL the opportunity to recover projected costs of transporting natural gas,
including the return on the Canadian Mainline's average investment base. In
addition, new facilities are approved by the NEB before construction begins. Net
earnings of the Canadian Mainline are affected by changes in investment base,
the ROE, the level of deemed common equity and the potential for incentive
earnings.

The Canadian Mainline generated net earnings of $283 million in 2005, an
increase of $11 million over 2004. The increase in net earnings is primarily due
to the NEB's decision on the 2004 Tolls and Tariff Application (Phase II) which
included an increase in the deemed common equity ratio to 36 per cent from 33
per cent for 2004 which is also effective for 2005 under the tolls settlement.
The Phase II decision resulted in a $35 million ($13 million related to 2004 and
$22 million related to 2005) increase to Canadian Mainline's 2005 net earnings
compared to 2004. However, this earnings increase was partially offset by the
combination of a lower average investment base, lower operating cost savings and
a lower approved ROE in 2005. The NEB-approved ROE decreased to 9.46 per cent in
2005 from 9.56 per cent in 2004.

Net earnings of $272 million in 2004 were $18 million lower than 2003 net
earnings of $290 million. The decrease was primarily due to a lower average
investment base and allowed ROE. The NEB-approved ROE was 9.56 per cent in 2004
compared to 9.79 per cent in 2003.

Alberta System

The Alberta System is regulated by the EUB primarily under the provisions of the
Gas Utilities Act (Alberta) (GUA) and the Pipeline Act (Alberta). Under the GUA,
its rates, tolls and other charges, and terms and conditions of service are
subject to approval by the EUB. In addition, major facilities are approved by
the EUB before construction begins.

Net earnings of $150 million in 2005 were unchanged from 2004 due to the
negative impacts of a lower investment base and a lower approved rate of return
in 2005 being offset by the positive impact of higher allowed operating costs in
2005 than in 2004 as a result of cost disallowances in 2004 as a result of the
EUB's decision on Phase I of the 2004 GRA. Net earnings in 2004 and 2005 reflect
an ROE of 9.60 and 9.50 per cent, respectively, as prescribed by the EUB, on
deemed common equity of 35 per cent.

MANAGEMENT'S DISCUSSION AND ANALYSIS 17

Net earnings in 2004 of $150 million were $40 million lower than 2003 net
earnings of $190 million. The decrease was primarily due to the impact of the
EUB decisions in respect of Phase I of the 2004 GRA and the GCOC proceeding. The
GRA Phase I decision disallowed approximately $24 million of operating costs,
and the GCOC decision resulted in a lower return on deemed common equity in 2004
compared to 2003.

GTN

Both the Gas Transmission Northwest System and the North Baja System operate
under fixed rate models, under which maximum and minimum rates for various
service types have been ordered by FERC and which GTN is permitted to discount
or negotiate on a non-discriminatory basis. The Gas Transmission Northwest
System's last filed rate case was in 1994 and it was settled and approved by
FERC in 1996. The North Baja System's rates were established in FERC's initial
order in 2002, certifying construction and operation of the system. The net
earnings of GTN are impacted by variations in volumes delivered and prices
charged under the various service types that are provided, as well as by
variations in the costs of providing transportation service. Net earnings were
$71 million for the year ended December 31, 2005 compared to $14 million for
November and December 2004.

Other Gas Transmission

TCPL's other direct and indirect investments in various natural gas pipelines
and gas transmission related businesses are included in Other Gas Transmission.
It also includes TCPL's natural gas storage facilities and project development
activities related to TCPL's pursuit of new pipeline and natural gas and crude
oil transmission related opportunities throughout North America.

TCPL's net earnings from Other Gas Transmission in 2005 were $153 million
compared to $121 million and $116 million in 2004 and 2003, respectively.
Excluding the gains on sale of PipeLines LP units in 2005 and Millennium in
2004, net earnings for 2005 were $10 million lower compared to 2004. The
decrease was primarily due to lower net earnings of Great Lakes as a result of
lower short-term revenues and higher operating and maintenance costs, and lower
earnings from PipeLines LP as a result of the reduced ownership. Results were
also negatively impacted by a weaker U.S. dollar in 2005. These decreases were
partially offset by higher earnings from CrossAlta as a result of more
favourable natural gas storage conditions in 2005.

Excluding the gain on sale of Millennium, net earnings in 2004 were $2 million
lower than 2003. Higher net earnings from CrossAlta and Ventures LP were more
than offset by an $11 million positive tax adjustment recorded in TransGas de
Occidente S.A. (TransGas) in 2003 and the negative impact of a weaker U.S.
dollar in 2004 compared to 2003.

GAS TRANSMISSION - OPPORTUNITIES AND DEVELOPMENTS

Tamazunchale Pipeline

In June 2005, TCPL announced it was awarded a contract by Mexico's Comision
Federal de Electricidad (CFE) to construct, own and operate a natural gas
pipeline in east-central Mexico. The 36 inch, 125 kilometre Tamazunchale
Pipeline will extend from the facilities of Pemex Gas near Naranjos, Veracruz
and transport natural gas under a 26 year

18 MANAGEMENT'S DISCUSSION AND ANALYSIS

contract with the CFE to an electricity generation station near Tamazunchale,
San Luis Potosi. TCPL expects to invest approximately US$181 million in the
project with a planned in-service date of December 1, 2006.

The pipeline will be designed to transport initial volumes of 170 mmcf/d. Under
the contract, the capacity of the Tamazunchale Pipeline is expected to be
expanded beginning in 2009 to approximately 430 mmcf/d to meet the needs of two
additional proposed power plants near Tamazunchale.

North Baja System

In February 2006, the North Baja System filed an application with FERC for a
certificate for a two-phase expansion of its existing natural gas pipeline in
southern California and the construction of a new pipeline lateral in
California's Imperial Valley. The expansion project envisions substantially
increasing the capacity of the existing pipeline and allowing for bi-directional
flow of natural gas. Natural gas currently flows on the North Baja System
southward from its interconnection with El Paso Natural Gas Company at
Ehrenberg, Arizona.

The proposed North Baja System expansion links to a corresponding expansion of
the Gasoducto Bajanorte line in Mexico owned by Sempra Energy. Together, the
expansions may allow for import into the U.S. of up to 2.7 Bcfd/d of natural gas
supplied from several potential LNG terminals near Baja California, Mexico,
including the Costa Azul terminal that is currently under construction. Shippers
have indicated their commercial support for the projects by signing precedent
agreements in support of the expansion plan as filed with FERC.

In addition to its FERC certificate of public convenience and necessity (which
includes a determination on environmental issues), the project will need various
permits and leases from the federal Bureau of Land Management, the California
State Lands Commission and other agencies.

Mackenzie Gas Pipeline Project

The Mackenzie Gas Pipeline Project would result in a natural gas pipeline being
constructed from Inuvik, Northwest Territories, to the northern border of
Alberta, where it would then connect with the Alberta System. Through 2005, the
Mackenzie Gas Pipeline Project continued to progress, with substantial
milestones being achieved in reaching agreement with certain of the northern
aboriginal groups as to the terms of land access for the pipeline right of way.
As a consequence, in late 2005, the project proponents indicated their readiness
to proceed to the public hearings phase of the regulatory review of the project.
Hearings commenced in January 2006 and are expected to continue throughout 2006.

In 2003, TCPL entered into an agreement with the Mackenzie Valley Aboriginal
Pipeline Limited Partnership (known as the APG) by which TCPL agreed to finance
the APG's one-third share of the pipeline pre-development costs associated with
the Mackenzie Gas Pipeline Project. Cumulative advances made by TCPL in this
respect constitute a loan to the APG, which becomes repayable only after the
date upon which the pipeline commences commercial operations. If the project
does not proceed, TCPL has no recourse against the APG for recovery of advances
made.

TCPL's loan advances to the APG were originally estimated to total
approximately $90 million, with an acknowledgement that these costs could rise
as a result of project delays and increased project costs. Given that the
project has experienced delays and is entering into a protracted regulatory
hearing process, the total loan advances by TCPL, on behalf of the APG, are
currently forecast to increase to approximately $145 million. These advances are
expected to ultimately form part of the rate base of the pipeline, and the loan
will subsequently be repaid from the APG's share of available future pipeline
revenues or from alternate financing. As at December 31, 2005, TCPL had funded
$87 million of this loan. The ability to recover this investment remains
dependent upon the successful outcome of the project. Under the terms of the
agreement, TCPL gains an immediate opportunity to acquire up to five per cent
equity ownership of the pipeline at the time of the decision to construct. In
addition, TCPL gains certain rights of first refusal to acquire 50 per cent of
any divestitures of existing partners and an entitlement to obtain a one-third
interest in all expansion opportunities once the APG reaches a one-third
ownership share, with the producers and the APG sharing the balance.

MANAGEMENT'S DISCUSSION AND ANALYSIS 19

Alaska Highway Pipeline Project

In 2005, TCPL continued its discussions with Alaska North Slope producers and
the State of Alaska relating to the Alaskan portion of the proposed Alaska
Highway Pipeline Project. In June 2004, TCPL filed an application under the
State of Alaska's Stranded Gas Development Act and requested the State resume
processing of its long-pending application for a right-of-way lease across State
lands. If the right-of-way lease is approved, TCPL is prepared to convey the
lease to another entity if that entity is willing to connect the final project
to TCPL's pipeline system. The lease conveyance would require an interconnection
agreement with TCPL at the Yukon/Alaska border. TCPL's Stranded Gas Application
is one of three applications currently before the State. In October 2005, the
State Administration and ConocoPhillips Company reached a preliminary agreement
under the Stranded Gas Development Act. On February 21, 2006, the State
announced that it had reached a preliminary agreement with BP Resources and
ExxonMobil. In addition, on February 21, 2006, the State announced it would be
proposing legislation for a new oil and gas production tax regime. It is not
expected that a natural gas deal would be submitted to the legislative assembly
of Alaska for ratification until after a new oil and gas production tax regime
has been enacted.

Foothills Pipe Lines Ltd. (Foothills) holds the priority right to build, own
and operate the first pipeline through Canada for the transportation of Alaskan
natural gas. This right was granted under the Northern Pipeline Act of Canada
(NPA), following a lengthy competitive hearing before the NEB in the late 1970s,
which resulted in a decision in favour of Foothills. The NPA creates a single
window regulatory regime that is uniquely available to Foothills. It has been
used by Foothills to construct facilities in Alberta, British Columbia and
Saskatchewan which constitute a prebuild for the Alaska Highway Pipeline
Project, and to expand those facilities five times, the latest of which was in
1998. TCPL continues to seek commercial alignment with the Alaska North Slope
producers on the Canadian portion of the project. Continued development under
the NPA should ensure the earliest in-service date for the project.

Supply

In 2005, the upstream energy sector responded to high natural gas prices by
drilling a record number of natural gas wells in the WCSB. TCPL continued to see
supply growth from the west central foothills area as well as unconventional
production from coalbed methane (CBM), primarily from the Horseshoe Canyon coals
located in central Alberta between Edmonton and Calgary.

TCPL will continue to focus on the cost effective and timely connection of
these volumes that will enable customers to access markets where natural gas
continues to achieve premium prices. As well, service flexibility will continue
to be a focus to ensure TCPL remains competitive.

Western Markets

TCPL continues to pursue growth opportunities within existing and new natural
gas markets. In 2005, TCPL further pursued the provision of cost effective
incremental delivery service into the Fort McMurray, Alberta market. As demand
for natural gas continued to grow at unprecedented levels, numerous oil sands
projects, both mining and in-situ, were announced in this region in 2005
resulting in incremental natural gas demand.

In late 2004 and throughout 2005, TCPL executed firm contracts for delivery
service to the Fort McMurray area on the Alberta System for volumes in excess of
900 mmcf/d. As a result of the ten and 20 year contracts, TCPL has filed
applications with the EUB to construct new natural gas transmission facilities
to serve the contracted demand. The construction will begin in late 2006 with a
contracted on-stream date of April 1, 2007. In 2008 and 2009, TCPL expects to
add additional facilities as the Fort McMurray oil sands demand continues to
grow.

Eastern Markets

Power generation continues to be the primary driver for incremental natural gas
demand in Eastern Canada and the U.S. Northeast markets. Power projects that
will require significant incremental natural gas volumes continue to be
developed and, as a result, the Canadian Mainline is expected to see modest
throughput increases in the short to medium term on a long haul basis. Modest
expansions, underpinned with long term firm transportation (FT) contracts, are
expected to be placed into service in 2006 and 2007 to meet incremental demand
in the eastern markets.

20 MANAGEMENT'S DISCUSSION AND ANALYSIS

Desire for options in accessing natural gas supply is reflected in the
continuing trend towards increased demand for short haul contracts by customers
in the eastern markets. TCPL continues to work with these customers to provide
service flexibility and optionality.

LNG

In September 2005, the village of Cacouna, Quebec, voted 57.2 per cent in favour
of an LNG terminal to be built in the area. The Cacouna Energy joint venture
between Petro-Canada and TCPL was originally announced in September 2004 and
proposes a $660 million project at Gros Cacouna harbour on the St. Lawrence
River, capable of receiving, storing and regasifying imported LNG with an
average send-out capacity of approximately 500 mmcf/d of natural gas. TCPL will
operate the planned facility, while Petro-Canada will contract for all of the
capacity and supply the LNG. Quebec's Ministry of Environment commenced its 45
day public consultation period on February 22, 2006, regarding the next phase
for this project.

In November 2004, TCPL and Shell announced plans to jointly develop an offshore
LNG regasification terminal, Broadwater, in the New York State waters of Long
Island Sound. The proposed floating storage and regasification unit would be
located approximately 15 km off the Long Island coast and 18 km off the
Connecticut coast. The proposed terminal would be capable of receiving, storing
and regasifying imported LNG with an average send-out capacity of approximately
one Bcf/d of natural gas. Broadwater Energy LLC, an entity which will be owned
50 per cent by TCPL, will own and operate the facility, while Shell will
contract for all of the capacity and supply the LNG. The estimated cost of
construction is expected to be approximately US$700 million to US$1 billion.
Construction of the facility is subject to regulatory approval from U.S. federal
and state governments. On January 30, 2006, a formal application was filed with
FERC for federal approval to construct and operate Broadwater. Provided the
necessary approvals are received, it is expected the facility will be in service
in late 2010 or early 2011.

Natural Gas Storage

TCPL's natural gas storage business is situated in Alberta, and is comprised of
a long-term natural gas storage contract, 60 per cent ownership in CrossAlta and
the wholly-owned Edson facility which is currently under construction. By
mid-2007, TCPL will own or lease more than 130 PJ, or approximately one-third of
the natural gas storage capacity in Alberta.

Natural gas market price volatility, partly due to extreme weather, supply
disruptions and sharp increases in oil prices, contributed to strong storage
values during 2005. TCPL commenced commercial natural gas storage operations in
second quarter 2005 through marketing and optimizing the 20 PJ of contracted
natural gas storage capacity. The capacity under contract increases to 30 PJ in
2006 and to 40 PJ in 2007.

TCPL commenced construction of the Edson facility in early 2005. The
construction cost of the project is currently expected to be approximately $270
million, which is a $70 million increase from the initial estimate due to higher
drilling and construction costs, and higher base gas costs. The Edson facility
is expected to have a capacity of approximately 60 PJ and will connect to TCPL's
Alberta System. Storage capacity is expected to be available from the Edson
facility, on a phased-in basis, commencing in mid-2006.

TCPL also has a 60 per cent interest in the CrossAlta natural gas storage
facility, which has a total working natural gas capacity of 56 PJ. In 2005,
CrossAlta completed expansion projects that improved the injection and
withdrawal rates and increased developed capacity from 44 PJ to 56 PJ.

Current market fundamentals for natural gas storage are expected to remain
strong. The imbalance in North American natural gas supply and demand has
created natural gas price volatility, resulting in demand for storage service.
TCPL believes Alberta-based storage will continue to serve market needs and
could play an even more important role when northern natural gas is connected to
North American markets.

MANAGEMENT'S DISCUSSION AND ANALYSIS 21

Keystone Pipeline

In November 2005, TCPL, ConocoPhillips Company and CPPL signed an MOU which
commits ConocoPhillips Company to ship crude oil on the proposed Keystone
pipeline, and gives CPPL the right to acquire up to a 50 per cent ownership
interest in the pipeline. On January 31, 2006, TCPL announced it has secured
firm, long-term contracts totalling 340,000 barrels per day with a duration
averaging 18 years. The commitments were obtained through the successful
completion of a binding Open Season held during fourth quarter 2005. With these
commitments from shippers, TCPL will proceed with regulatory filings for
approval of the project.

At an estimated cost of approximately US$2.1 billion, the Keystone pipeline is
intended to transport approximately 435,000 barrels per day of crude oil from
Hardisty, Alberta, to Patoka, Illinois through a 2,960 km pipeline system. The
pipeline can be expanded to 590,000 barrels per day with additional pump
stations. In addition to approximately 1,730 km of new pipeline construction in
the U.S., the Canadian portion of the proposed project includes the construction
of approximately 370 km of new pipeline and the conversion of approximately 860
km of TCPL's existing pipeline facilities from natural gas to crude oil
transmission. The Keystone pipeline, upon receipt of the appropriate regulatory
approvals in Canada and the U.S., is expected to be in service in 2009.
Construction is proposed to begin in late 2007.

Shippers have also expressed interest in proposed extensions of the Keystone
pipeline to Cushing, Oklahoma and Fort Saskatchewan, Alberta. TCPL expects to
hold a binding Open Season for these two extensions later in 2006.

TCPL is in the business of connecting energy supplies to markets and it views
this opportunity as another way of providing a valuable service to its
customers. Converting one of the company's natural gas pipeline assets for crude
oil transportation is an innovative, cost-competitive way to meet the need for
pipeline expansions to accommodate anticipated growth in Canadian crude oil
production during the next decade.

GAS TRANSMISSION - REGULATORY DEVELOPMENTS

In 2005, TCPL's principal regulatory activities included receiving the decision
from the NEB regarding the Canadian Mainline's 2004 Tolls and Tariff Application
(Phase II); a negotiated settlement with respect to 2005 Canadian Mainline
tolls; a three year revenue requirement settlement for the Alberta System; a
hearing before the EUB on the rate design of the Alberta System, with potential
implications for the competitiveness of the Alberta System; and the successful
negotiation with shippers and CAPP for their support on increasing the deemed
common equity ratio on the Foothills System and the BC System. TCPL is also
currently in negotiation for a settlement with its Canadian Mainline shippers
regarding 2006 tolls.

Canadian Mainline

In April 2005, the NEB issued its decision on the Canadian Mainline's 2004 Tolls
and Tariff Application (Phase II) which increased the Canadian Mainline deemed
common equity to 36 per cent from 33 per cent for 2004 tolls.

In April 2005, the NEB approved TCPL's application for a negotiated settlement
of the 2005 Canadian Mainline tolls as filed. The settlement established
operating, maintenance and administration (OM&A) costs for 2005 at $169.5
million with variances between actual OM&A costs in 2005 and those agreed to in
the settlement accruing to TCPL. The majority of other cost elements of the 2005
revenue requirement were to be treated on a flow through basis. Further, the
2005 ROE was set at 9.46 per cent and the deemed common equity component in 2005
reflected the outcome of the NEB's Phase II decision with respect to the
Canadian Mainline's 2004 capital structure.

In May 2005, in compliance with the NEB's decision regarding the Canadian
Mainline's 2004 Tolls and Tariff Application (Phase II), TCPL filed separate
final tolls applications with the NEB for 2004 and 2005. In June 2005, the NEB
issued its decision approving the 2004 and 2005 final tolls applications as
filed.

In December 2005, the NEB approved the 2006 interim tolls, effective January 1,
2006. TCPL is currently engaged in settlement discussions with its stakeholders
on matters related to the Canadian Mainline's 2006 tolls and tariff. Pending

22 MANAGEMENT'S DISCUSSION AND ANALYSIS

progress on the settlement discussions, TCPL intends to file an application for
approval of the 2006 tolls and tariff with the NEB in first quarter 2006.

The formula-based ROE for the Canadian Mainline for 2006 is 8.88 per cent.

Alberta System

In December 2004, TCPL filed its 2005 Phase I GRA with the EUB. In March 2005, a
settlement was reached with shippers and other interested parties regarding the
annual revenue requirements of the Alberta System for the years 2005, 2006 and
2007. The settlement encompasses all elements of the Alberta System revenue
requirement, including OM&A costs, return on equity, depreciation, and income
and municipal taxes.

In the Alberta System settlement, OM&A costs were fixed at $193 million for
2005, $201 million for 2006, and $207 million for 2007. Any variance between
actual OM&A and other fixed costs and those agreed to in the settlement in each
year accrue to TCPL. The majority of other cost elements of the 2005, 2006 and
2007 revenue requirements are treated on a flow through basis.

The return on equity will be calculated annually during the term of the
settlement using the EUB formula for the purpose of establishing the annual
generic rate of return for Alberta utilities on deemed common equity of 35 per
cent. For 2005, ROE under the EUB formula was 9.50 per cent. In addition,
depreciation expenses are determined using the depreciation rates and
methodology that was proposed to the EUB in the 2004 GRA. Depreciation expense
was $303 million in 2005 and is expected to be approximately $285 million in
2006 and $282 million in 2007.

In June 2005, the EUB approved the negotiated settlement of the Alberta
System's three year revenue requirement. As stipulated in the settlement, TCPL
then discontinued the action it had commenced to appeal the EUB's disallowance
of certain incentive compensation and long-term incentive compensation costs in
the 2004 revenue requirement and its work on an application to the EUB to review
and vary this same decision.

Interim tolls approved in December 2004 were charged throughout 2005 for
transportation service on the Alberta System. With the issuance on February 21,
2006 of the EUB's decision on Phase II of the Alberta System's 2005 GRA, in
which the application to retain the Alberta System's current rate design and
cost allocation methodologies was approved, final tolls for 2005 can be
determined. An application for 2005 final tolls will be made in March 2006.

On December 15, 2005, the EUB approved the application to charge interim tolls
for transportation service, effective January 1, 2006. The 2006 interim tolls,
which replaced the 2005 interim tolls, will be finalized through an application
to the EUB in March 2006 in which the flow-through cost components of the
revenue requirement will be updated to reflect actual costs and revenues from
the prior year as stipulated under the Alberta System's 2005, 2006 and 2007
revenue requirement settlement.

The formula-based ROE for the Alberta System for 2006 is 8.93 per cent.

GTN

TCPL is preparing a rate case for the Gas Transmission Northwest System that is
expected to be filed by summer 2006. The primary reason for a rate case is
decreased revenues due to contract non-renewals and shipper defaults. Currently,
the Gas Transmission Northwest System has about 12 per cent of its long-term
capacity unsubscribed and there is a risk of additional contracts not being
renewed during the remainder of 2006. FERC typically suspends the effectiveness
of rate increase filings for a five month period, so the company anticipates
that the new rates, which are subject to refund pending the final result of the
case, would go into effect near the end of 2006.

Foothills and BC Systems

TCPL filed applications with the NEB in early December 2005 for approval of 2006
tolls for the Foothills System and the BC System reflecting an agreement with
CAPP and other stakeholders to increase the deemed equity component of the
capital structure of each system to 36 per cent from 30 per cent. On December
21, 2005, the NEB approved the Foothills System application as filed. On
February 22, 2006, the NEB finalized the BC System's 2006 tolls as filed.

MANAGEMENT'S DISCUSSION AND ANALYSIS 23

GAS TRANSMISSION - BUSINESS RISKS

Competition

TCPL faces competition at both the supply end and the market end of its systems.
The competition is a result of other pipelines accessing an increasingly mature
WCSB and markets served by TCPL's pipelines. In addition, the continued
expiration of long-term FT contracts has resulted in significant reductions in
long-term firm contracted capacity on the Canadian Mainline, the Alberta System,
the BC System and the Gas Transmission Northwest System, and shifts to
short-term firm contracts.

As of December 2004, the WCSB had remaining discovered natural gas reserves of
approximately 55 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. Natural gas prices in the
future are expected to be higher than long-term historical averages due to a
tighter supply/demand balance which should stimulate exploration and production
in the WCSB. However, WCSB supply is expected to remain essentially flat. With
the expansion of capacity on TCPL's wholly- and partially-owned pipelines over
the past decade, and the competition provided by other pipelines, combined with
significant growth in natural gas demand in Alberta, TCPL anticipates there will
be excess pipeline capacity out of the WCSB for the foreseeable future.

TCPL's Alberta System is the major natural gas gathering and transportation
system for the WCSB which connects most of the natural gas processing plants in
Alberta to domestic and export markets. The Alberta System has faced, and will
continue to face, increasing competition from other pipelines.

The Canadian Mainline is TCPL's cross-continental natural gas pipeline serving
mid-western and eastern markets in Canada and the U.S. The demand for natural
gas in TCPL's key eastern markets is expected to continue to increase,
particularly to meet the expected growth in natural gas-fired power generation.
Although there are opportunities to increase market share in Canadian and U.S.
export markets, TCPL faces significant competition in these regions. Consumers
in the U.S. Northeast have access to an array of pipeline and supply options.
Eastern Canadian markets that historically received Canadian supplies only from
TCPL are now capable of receiving supplies from new pipelines into the region
that can source Western Canadian, Atlantic Canadian and U.S. supplies.

Over the last few years, the Canadian Mainline has experienced reductions in
long haul FT contracts. This has been partially offset by increases in short
haul contracts. While decreases in throughput do not directly impact Canadian
Mainline earnings, such decreases will impact the competitiveness of its tolls.
Over the course of 2005, strong natural gas prices in Eastern Canada and the
Northeast U.S. resulted in higher than anticipated flows on the Canadian
Mainline to serve those markets. In addition to increases in flow, the Canadian
Mainline has also experienced an increase in short-term contracts and a
resulting decrease in tolls. Looking forward, in the short to medium term, there
is expected to be limited opportunity to further reduce tolls by increasing long
haul volumes on the Canadian Mainline. Further, throughput and contract levels
are expected to return to more modest levels.

The Gas Transmission Northwest System must compete with other pipelines to
access natural gas supplies as well as to access markets. Transportation service
capacity on the Gas Transmission Northwest System provides customers with access
to supplies of natural gas primarily from the WCSB and serves markets in the
Pacific Northwest, California and Nevada. These three markets may also access
supplies from other competing basins in addition to supplies from the WCSB.
Historically, natural gas supplies from the WCSB have been competitively priced
in relation to natural gas supplies from the other supply regions serving these
markets. The Gas Transmission Northwest System experienced contract non-renewals
in 2005 and additional contracts may not be renewed in 2006. Natural gas
transported from the WCSB on the Gas Transmission Northwest System competes in
the California and Nevada markets against supplies from the Rocky Mountain and
southwest U.S. supply basins. In the Pacific Northwest market, natural gas
transported on the Gas Transmission Northwest System competes against Rocky
Mountain gas supply as well as additional Western Canadian supply that is
transported by the Northwest Pipeline.

Transportation service on the North Baja System provides access to natural gas
supplies primarily from both the Permian Basin, located in western Texas and
southeastern New Mexico, and the San Juan Basin, primarily located in

24 MANAGEMENT'S DISCUSSION AND ANALYSIS

northwestern New Mexico and Colorado. The North Baja System delivers natural gas
to the Gasoducto Bajanorte pipeline at the California/Mexico border, which
transports the natural gas to markets in northern Baja California, Mexico. While
there are currently no direct competitors to deliver natural gas to the North
Baja System's downstream markets, the pipeline may compete with fuel oil which
is an alternative to natural gas in the operation of some electric generation
plants in the North Baja region.

Counterparty Risk

The risk of customer defaults and bankruptcy has always been present. In
December 2005, Calpine Corporation and certain of its subsidiaries (Calpine)
filed for bankruptcy protection. Calpine has transportation contracts on certain
of TCPL's Canadian and U.S. pipelines. TCPL presently holds the maximum
financial assurances allowable under the respective tariffs. As at February 27,
2006, these transportation contracts had not been accepted or rejected. Should
the Calpine contracts with TCPL's Canadian pipeline systems be rejected, TCPL
considers that it has been prudent in obtaining the maximum financial assurances
and would make an application to the regulator for recovery under the current
regulatory model of any lost revenue, net of the assurances, and any revenues
from the defaulted capacity. Should contracts be rejected on TCPL's U.S.
systems, the unmitigated annual after-tax exposure of the contract obligations
is estimated at $10 million for the Gas Transmission Northwest System and $10
million for Portland Natural Gas Transmission System Partnership, in which TCPL
holds a 61.7 per cent ownership interest. Mitigating factors exist which are
expected to reduce this exposure including recovery through future general rate
case filings, recontracting at maximum or discounted rates where applicable,
recontracting as short-term or interruptible service, and recovery from
bankruptcy proceedings. The potential impact of such mitigating factors and the
resulting net exposure are unknown at this time.

Financial Risk

Regulatory decisions continue to have a significant impact on the financial
returns for existing and future investments in TCPL's Canadian wholly-owned
pipelines. TCPL remains concerned the approved financial returns discourage
additional investment in existing Canadian natural gas transmission systems.
TCPL had applied for a return of 11 per cent on 40 per cent deemed common equity
for both the Canadian Mainline and the Alberta System to the NEB and EUB,
respectively. The outcome of these proceedings resulted in the current Canadian
Mainline's 36 per cent deemed equity thickness and Alberta System's 35 per cent
deemed equity thickness. Additionally, the NEB reaffirmed its return on equity
formula, while the EUB set a generic ROE which largely aligns with the formula
of the NEB. In 2005, the NEB's ROE formula provided an ROE of 9.46 per cent and
the EUB's generic ROE was 9.50 per cent. In 2006, the Canadian Mainline and
Alberta System's ROEs decline to 8.88 percent and 8.93 per cent, respectively.

The company remains cognizant of the views and shares the concerns of credit
rating agencies regarding the Canadian regulatory environment. Credit ratings
and liquidity continue to be at the forefront of investor attention. While
recent regulatory decisions increasing the deemed equity component of the
capital structure of the company's Canadian pipelines may serve to somewhat
mitigate these concerns in the long run, significantly reduced allowed ROE on
NEB and EUB regulated pipelines are expected to offset any positive effect in
2006.

Foreign Exchange

TCPL's earnings from GTN, as well as a significant amount of earnings in Other
Gas Transmission are generated in U.S. dollars. The performance of the Canadian
dollar relative to the U.S. dollar would either positively or negatively impact
Gas Transmission's net earnings, although this impact is mitigated by offsetting
exposures in certain of TCPL's other businesses as well as through the company's
hedging activities.

Throughput Risk

As transportation contracts expire on Great Lakes, Northern Border and GTN,
these pipelines will be more exposed to throughput risk and their revenues will
more likely experience increased variability. Throughput risk is created by
supply and market competition, gas basin pricing, economic activity, weather
variability, pipeline competition and pricing of alternative fuels.

MANAGEMENT'S DISCUSSION AND ANALYSIS 25

GAS TRANSMISSION - OTHER

Operational Excellence

TCPL continued its commitment to operational excellence in 2005 by further
advancing initiatives that will improve the company's ability to provide
low-cost, reliable and responsive service to customers. TCPL continues to pursue
the operational excellence strategy in order to continue to be the preferred
company for customers wishing to connect new natural gas supplies and markets.

TCPL maintained a high level of plant operating performance, as measured by the
number of operational perfect days on both the Canadian Mainline and the Alberta
System. GTN was effectively integrated in 2005, and maintained high levels of
operating performance as well.

Receiving the American Society of Mechanical Engineers' inaugural award for
pipeline technology in 2005 further recognized the efforts of TCPL to ensure
high reliability levels are sustained over the long term.

The annual Customer Satisfaction Survey, conducted by Ipsos Reid in the fall of
2005, found that TCPL maintained high levels of overall customer satisfaction
and improved significantly in the area of senior management relationships. As
part of the Customer Express website, TCPL launched the "Toll Calculator", an
online tool that allows customers to quickly obtain the cost of shipping on
TCPL's wholly-owned and affiliated pipeline systems. Feedback from customers and
other stakeholders indicates this tool was well received and support for further
development of on-line tools is strong.

Also, 2005 was a very productive year with respect to collaborative efforts
with customers. The Tolls Task Force, the Canadian Mainline stakeholder group,
produced twenty resolutions in 2005 including process improvements, several
service enhancements, a new service and a settlement for the Canadian Mainline.
The Tolls, Tariff, Facilities and Procedures committee, the Alberta System
stakeholder group, had eleven resolutions in 2005 focusing on greater service
flexibility and process efficiency for the Alberta System. Many of these
initiatives will result in increasing service flexibility and more efficient
service delivery. Productive collaborative processes also result in costs
savings for both TCPL and industry by avoiding costs associated with regulatory
proceedings.

In 2006, TCPL will continue to focus efforts on efficiencies, operational
reliability, and environmental and safety performance. Greenhouse gas emissions
management programs will continue to receive focused attention and in 2006
further efforts will be undertaken to improve contractor safety performance.

Safety

TCPL worked closely with regulators, customers and communities during 2005 to
ensure the continued safety of employees and the public. Pipeline safety
performance in 2005 was very good with only one small diameter pipeline
line-break located in a relatively remote area of northern Alberta. The break
resulted in minimal impact with no injuries or property damage. Under the
approved regulatory models in Canada, expenditures on pipeline integrity for the
NEB and EUB regulated pipelines have no negative impact on TCPL's earnings. The
company expects to spend approximately $105 million in 2006 for pipeline
integrity on its Wholly-Owned Pipelines, which is an increase from the $64
million spent in 2005. The increase is due primarily to initial inspections of
the Gas Transmission Northwest System, additional inspections for stress
corrosion cracking on the Canadian Mainline and repairs to several water
crossings in southern Alberta that were damaged during flood events in June
2005. TCPL continues to use a rigorous risk management system that focuses
spending on issues and areas that have the largest impact on maintaining or
improving the reliability and safety of the pipeline system.

Environment

In 2005, TCPL continued to address and assess environmental issues through
proactive sampling, monitoring and remediation programs. Activities on the
Canadian Mainline included the completion of three ongoing remediation projects,
as well as building containment integrity improvement projects at seven
compressor stations. All facilities on the Foothills System were assessed
through the company's Site Assessment, Remediation and Monitoring program in
2005, along with the majority of facilities on GTN. In addition, the
decommissioning and reclamation of four Canadian

26 MANAGEMENT'S DISCUSSION AND ANALYSIS

Mainline compressor plants and two Alberta System compressor plants was carried
out in 2005. TCPL will continue to actively invest in improved environmental
protection measures.

For information on management of risks with respect to the Gas Transmission
business, see the "Risk Management" section.

GAS TRANSMISSION - OUTLOOK

As demand for natural gas continues to grow across North America, TCPL's Gas
Transmission business will continue to play a critical role in the reliable
transportation of natural gas. For 2006, the business will focus on the reliable
delivery of natural gas to growing markets, connecting new supply and
progressing development of new infrastructure to connect northern gas. TCPL will
also focus on development of the Keystone pipeline.

Looking forward, it is expected that producers will continue to explore and
develop new fields, particularly in northeastern B.C. and the west central
foothills regions of Alberta, as well as unconventional supply such as gas
production from CBM reserves. New facilities will be required to move this
incremental supply based on the location of the resource, even though overall
WCSB supply is expected to remain essentially flat. The Alberta System
anticipates filing an application during 2006 with the EUB, to construct new
facilities required to connect additional natural gas supplies anticipated to be
delivered to the Alberta System from the Mackenzie Delta.

In 2006, TCPL will continue to focus on serving the growing demand in the Fort
McMurray area with construction of new natural gas transmission facilities,
beginning in late 2006, with a contractual on-stream date of April 1, 2007. In
2008 and 2009, TCPL anticipates constructing additional facilities as the Fort
McMurray oil sands demand for natural gas continues to grow.

It is expected that incremental supply from LNG will serve growing North
American markets in the mid to long term. As a result, TCPL will take prudent
steps to further evaluate the potential commercial and operational implications
of connecting LNG facilities to those systems affected.

Prior to the onset of new supply from LNG and northern gas, many of the markets
served by TCPL's systems may be exposed to volatile natural gas prices. As a
result, TCPL will continue to focus on operational excellence and collaborative
efforts with all stakeholders on negotiated settlements and service options that
will increase the value of TCPL's business to customers and shareholders.

Earnings

TCPL's earnings from its Canadian wholly-owned pipelines are primarily
determined by the average investment base, ROE, deemed common equity and
opportunity for incentive earnings. In the short to medium term, the company
expects a modest level of investment in these mature assets and therefore
anticipates a continued net decline in the average investment base due to
depreciation expense in excess of capital expenditures. Accordingly, without an
increase in ROE, deemed common equity or incentive opportunities, future
earnings are anticipated to decrease. However, these mature assets will continue
to generate strong cash flows that can be redeployed to other projects offering
higher returns. Under the current regulatory model, earnings from the Canadian
wholly-owned pipelines are not affected by short-term fluctuations in the
commodity price of natural gas, changes in throughput volumes or changes in
contract levels.

In December 2005, the NEB established the 2006 ROE for the Canadian Mainline at
8.88 per cent compared to 9.46 per cent in 2005. In addition, the 2006 average
investment base is expected to continue to decline. These two factors are
expected to lower earnings on the Canadian Mainline in 2006 relative to 2005 if
there are no offsetting factors. TCPL is currently engaged in settlement
discussions with its stakeholders on matters related to the Canadian Mainline's
2006 tolls.

Alberta System earnings in 2006 will be negatively influenced by the decrease
in the EUB's generic ROE to 8.93 per cent in 2006 from 9.50 per cent in 2005,
and an anticipated decrease in the average investment base.

MANAGEMENT'S DISCUSSION AND ANALYSIS 27

The three year revenue requirement settlement reached in 2005 does provide the
opportunity for limited incentive earnings as the settlement contains some
at-risk cost components. If TCPL is successful in its focus on cost efficiency,
there is an opportunity to partially mitigate the effect of a lower ROE and
average investment base for the Alberta System in 2006.

In 2006, earnings from Portland and the Gas Transmission Northwest System may
be negatively impacted should Calpine contracts be rejected on the respective
systems. Calpine's FT contract accounts for approximately 24 per cent of
Portland's total FT revenues. On the Gas Transmission Northwest System,
approximately seven per cent of transportation revenues come from Calpine's FT
contracts. It is not possible at this time to determine the impact of any
potential mitigating factors on 2006 earnings if these contracts are rejected.

Reduced firm contract volumes on the Gas Transmission Northwest System,
including the effects of customer bankruptcies, are expected to have a slightly
negative impact on the Gas Transmission Northwest System results compared to
2005. The impact of the 2006 rate case filing on the system's results in 2006 is
uncertain at this time.

Anticipated lower firm service revenues on certain partially-owned pipelines
and a full year of reduced ownership of PipeLines LP are expected to be
partially offset by the effects of a higher deemed equity structure on the
Foothills System and BC System and the expected growth in natural gas storage
net earnings.

Capital Expenditures

Total capital spending for the Wholly-Owned Pipelines during 2005 was $135
million. Overall capital spending on the Wholly-Owned Pipelines in 2006 is
expected to be approximately $382 million. Capital expenditures on the Edson
natural gas storage project and the Tamazunchale Pipeline are expected to be
approximately $105 million and $95 million, respectively, in 2006.

NATURAL GAS THROUGHPUT VOLUMES
(Bcf)(1)
2005 2004 2003
Canadian Mainline(2) 2,997 2,621 2,628
Alberta System(3) 3,999 3,909 3,883
Gas Transmission Northwest System(4) 777 181
Foothills System 1,051 1,139 1,110
BC System 321 360 325
North Baja System(4) 84 13
Great Lakes 850 801 856
Northern Border 808 845 850
Iroquois 394 356 341
TQM 166 159 164
Ventures LP 192 136 111
Portland 62 50 53
Tuscarora 25 25 22
TransGas 19 18 16
(1)
Billion cubic feet.

(2)
Canadian Mainline deliveries originating at the Alberta border and in
Saskatchewan for the year ended December 31, 2005 were 2,215 Bcf (2004 -
2,017 Bcf; 2003 - 2,055 Bcf).

(3)
Field receipt volumes for the Alberta System for the year ended December 31,
2005 were 4,034 Bcf (2004 - 3,952 Bcf; 2003 - 3,892 Bcf).

(4)
TCPL acquired the Gas Transmission Northwest System and the North Baja
System on November 1, 2004. The volumes for 2004 represent November and
December 2004 throughput.

28 MANAGEMENT'S DISCUSSION AND ANALYSIS

POWER

HIGHLIGHTS

Net Earnings

*
Power's net earnings in 2005 were $561 million compared to $396 million
in 2004.

*
Excluding gains related to Power LP and Paiton Energy, Power's net
earnings for 2005 increased $44 million to $253 million compared to $209
million in 2004.

*
TCPL's operating and other income before income taxes from Bruce Power
for 2005 of $195 million increased by $65 million compared to $130
million in 2004.

Expanding Asset Base

*
In October 2005, Bruce Power and the OPA completed a long-term agreement
whereby Bruce A will restart and refurbish the currently idle Units 1
and 2, extend the life of Unit 3 by replacing its steam generators and
fuel channels when required and replace the steam generators on Unit 4.
Restarting Units 1 and 2, which have a capacity of approximately 1,500
MW, will boost Bruce Power's output to more than 6,200 MW of which
approximately 2,450 MW is TCPL's share. As at December 31, 2005, TCPL
owned 47.9 per cent of Bruce A and 31.6 per cent of Bruce B.

*
Effective December 31, 2005, TCPL acquired the remaining rights and
obligations of the 756 MW Sheerness PPA from the Alberta Balancing Pool
for $585 million. The remaining term of the PPA is approximately 15
years. The plant consists of two coal-fired thermal power generating
units.

*
In April 2005, TCPL acquired the hydroelectric generation assets from
USGen with a total generating capacity of 567 MW for US$503 million.

*
In January 2005, the 90 MW Grandview natural gas-fired cogeneration
plant located in Saint John, New Brunswick was commissioned and placed
in service.

*
Construction continued on the 550 MW Becancour cogeneration plant and it
is expected to be in service in late 2006.

*
The 739.5 MW Cartier Wind project awarded construction contracts in
2005. Construction on the first two projects is expected to commence
early 2006 and the first project is scheduled to be commissioned in late
2006.

Plant Availability

*
Weighted average plant availability was 87 per cent in 2005, excluding
Bruce Power, compared to 96 per cent in 2004.

*
Including Bruce Power, weighted average plant availability was 84 per
cent in 2005, compared to 90 per cent in 2004.

MANAGEMENT'S DISCUSSION AND ANALYSIS 29

BEAR CREEK An 80 MW natural gas-fired cogeneration plant located near Grande
Prairie, Alberta.

MACKAY RIVER A 165 MW natural gas-fired cogeneration plant located near Fort
McMurray, Alberta.

REDWATER A 40 MW natural gas-fired cogeneration plant located near Redwater,
Alberta.

SUNDANCE A&B The Sundance power facility in Alberta is the largest coal-fired
electrical generating facility in Western Canada. TCPL owns the 560 MW Sundance
A PPA, ending in 2017. TCPL effectively owns 50 per cent of the 706 MW Sundance
B PPA, ending in 2020.

SHEERNESS In December 2005, TCPL acquired the remaining rights and obligations
of the 756 MW Sheerness PPA with a remaining term of 15 years. The plant
consists of two coal-fired thermal power generating units.

CARSELAND An 80 MW natural gas-fired cogeneration plant located near
Carseland, Alberta.

CANCARB The 27 MW Cancarb facility at Medicine Hat, Alberta is fuelled by
waste heat from TCPL's adjacent thermal carbon black facility.

30 MANAGEMENT'S DISCUSSION AND ANALYSIS

BRUCE POWER At December 31, 2005, TCPL owned 31.6 per cent of Bruce B,
consisting of operating Units 5 to 8 with approximately 3,200 MW of generating
capacity. In addition, TCPL owned 47.9 per cent of Bruce A, consisting of
operating Units 3 and 4 with approximately 1,500 MW of generating capacity and
currently idle Units 1 and 2 with approximately 1,500 MW of generating capacity.
Units 1 and 2 are currently being refurbished for expected restart of the first
unit commencing in 2009.

OSP The OSP plant is a 560 MW natural gas-fired, combined-cycle facility in
Rhode Island.

BECANCOUR The 550 MW Becancour natural gas-fired cogeneration power plant
located near Trois-Rivieres, Quebec is under construction and is expected to be
in service in late 2006. The entire power output will be supplied to
Hydro-Quebec under a 20 year power purchase contract. Steam will also be sold to
local businesses.

CARTIER WIND Cartier Wind, 62 per cent owned by TCPL, is comprised of six wind
projects totalling 739.5 MW to be commissioned between 2006 and 2012.
Construction on the first two projects, with a combined generating capacity of
210 MW, is expected to commence early 2006 and the first project is expected to
be in service in late 2006. The entire power output will be supplied to
Hydro-Quebec under a 20 year power purchase contract.

GRANDVIEW A 90 MW natural gas-fired cogeneration power plant located in Saint
John, New Brunswick was commissioned and in service in January 2005. Under a 20
year tolling arrangement, 100 per cent of the plant's heat and electricity
output is sold to Irving.

TC HYDRO In April 2005, TCPL closed the acquisition of hydroelectric
generation assets from USGen. These merchant assets have a total generating
capacity of 567 MW and are located in New Hampshire, Vermont and Massachusetts.

MANAGEMENT'S DISCUSSION AND ANALYSIS 31

POWER RESULTS-AT-A-GLANCE
Year ended December 31 (millions of dollars)
2005 2004 2003

Bruce Power 195 130 99
Western operations 123 138 160
Eastern operations 137 108 127
Power LP investment 29 29 35
General, administrative, support costs and other (102 ) (89 ) (86 )

Operating and other income 382 316 335
Financial charges (11 ) (13 ) (12 )
Income taxes (118 ) (94 ) (103 )

253 209 220
Gains related to Power LP and Paiton Energy (after tax) 308 187 -

Net earnings 561 396 220

Power's net earnings in 2005 of $561 million increased $165 million compared to
$396 million in 2004 primarily due to gains related to Paiton Energy and Power
LP. In 2005, TCPL sold its approximate 11 per cent interest in Paiton Energy to
subsidiaries of The Tokyo Electric Power Company for gross proceeds of US$103
million ($122 million) resulting in an after-tax gain of $115 million. In August
2005, TCPL sold its ownership interest in Power LP to EPCOR Utilities Inc.
(EPCOR) for net proceeds of $523 million resulting in an after-tax gain of $193
million. Included in 2004 net earnings was an after-tax gain of $187 million
comprised of a $15 million after-tax gain on the sale of TCPL's Curtis Palmer
and ManChief power facilities to Power LP as well as $172 million of after-tax
dilution and other gains.

Excluding the Paiton Energy and Power LP-related gains in 2005 and 2004,
respectively, Power's net earnings for the year ended December 31, 2005 of $253
million increased $44 million compared to $209 million in 2004. The increase was
primarily due to higher operating and other income from Bruce Power and Eastern
Operations, partially offset by a reduced contribution from Western Operations
and higher general, administrative, support costs and other.

In 2003, Western Operations' results included a $31 million pre-tax ($19
million after tax) settlement with a former counterparty that defaulted in 2001
under power forward contracts. Power's net earnings for 2004, excluding gains
related to Power LP in 2004 and the counterparty settlement in 2003, increased
$8 million year-over-year. Pre-tax equity income from Bruce Power of $130
million in 2004 increased $31 million compared to TCPL's period of ownership in
2003. This was partially offset by lower contributions from Eastern Operations
and Power LP investment.

32 MANAGEMENT'S DISCUSSION AND ANALYSIS

POWER PLANTS - NOMINAL GENERATING CAPACITY AND FUEL TYPE
MW Fuel Type
Bruce Power(1) 2,450 Nuclear

Western operations
Sheerness(2) 756 Coal
Sundance A(3) 560 Coal
Sundance B(3) 353 Coal
MacKay River 165 Natural gas
Carseland 80 Natural gas
Bear Creek 80 Natural gas
Redwater 40 Natural gas
Cancarb 27 Natural gas
2,061

Eastern operations
TC Hydro(4) 567 Hydro
OSP 560 Natural gas
Becancour(5) 550 Natural gas
Cartier Wind(6) 458 Wind
Grandview(7) 90 Natural gas
2,225
Total Nominal Generating Capacity 6,736
(1)
Represents TCPL's 47.9 per cent proportionate interest in Bruce A and 31.6
per cent proportionate interest in Bruce B at December 31, 2005. Bruce A
consists of four 750 MW reactors. Bruce A Unit 4 was returned to service in
fourth quarter 2003. Bruce A Unit 3 was returned to service in first quarter
2004. Bruce A Units 1 and 2 are currently being refurbished and are expected
to restart commencing in 2009. Bruce B consists of four reactors which are
currently in operation, with a combined capacity of approximately 3,200 MW.

(2)
TCPL directly acquires 756 MW from Sheerness through a long-term PPA
acquired in December 2005.

(3)
TCPL directly or indirectly acquires 560 MW from Sundance A and 353 MW from
Sundance B through long-term PPAs, which represents 100 per cent of the
Sundance A and 50 per cent of the Sundance B power plant output,
respectively.

(4)
Acquired in April 2005.

(5)
Currently under construction.

(6)
Currently under construction. Represents TCPL's 62 per cent of 739.5 MW.

(7)
Placed in-service in January 2005.

POWER - FINANCIAL ANALYSIS

Bruce Power

On October 31, 2005, Bruce Power and the OPA completed a long-term agreement
whereby Bruce A will restart and refurbish the currently idle Units 1 and 2,
extend the operating life of Unit 3 by replacing its steam generators and fuel
channels when required and replace the steam generators on Unit 4. As a result
of the agreement between Bruce Power and the OPA, and Cameco's decision not to
participate in the restart and refurbishment program, a new partnership was
created. Bruce A subleases its facilities, which are comprised of Units 1 to 4,
from Bruce B. TCPL and BPC each incurred a net cash outlay of approximately $100
million on the formation of Bruce A. As at December 31, 2005, TCPL and BPC each
owned a 47.9 per cent interest in Bruce A. The remaining 4.2 per cent is owned
by the Power Worker's Union Trust No. 1 and The Society of Energy Professionals
Trust. The day-to-day operations of the Bruce

MANAGEMENT'S DISCUSSION AND ANALYSIS 33

Power facilities are expected to be unaffected by the formation of Bruce A and
TCPL continues to own 31.6 per cent of the Bruce B Units 5 to 8.

Upon reorganizing, both Bruce A and Bruce B became jointly controlled entities
and TCPL proportionately consolidated these investments on a prospective basis
from October 31, 2005. The following Bruce Power financial results reflect the
operations of the full six-unit operation for all periods. The Bruce Power
information below includes adjustments to eliminate the effect of certain
intercompany transactions between Bruce A and Bruce B.

Bruce Power Results-at-a-Glance
Year ended December 31 (millions of dollars)
2005 2004 2003

Bruce Power (100 per cent basis)
Revenues
Power 1,907 1,563 1,183
Other(1) 35 20 25

1,942 1,583 1,208

Operating expenses
Operations and maintenance (871 ) (793 ) (608 )
Fuel (77 ) (68 ) (45 )
Supplemental rent (164 ) (156 ) (111 )
Depreciation and amortization (198 ) (161 ) (89 )

(1,310 ) (1,178 ) (853 )

Operating income 632 405 355

Financial charges under equity accounting - to October 31, 2005 (58 ) (67 ) (69 )

574 338 286

TCPL's proportionate share 188 107 65
Adjustments 7 23 34

TCPL's operating and other income from Bruce Power(2) 195 130 99

Bruce Power - Other Information
Plant availability 80% 82% 83%
Sales volumes (GWh)(3)
Bruce Power - 100 per cent 32,900 33,600 21,060
TCPL's proportionate share 10,732 10,608 6,655
Results per MWh(4)
Power revenues $58 $47 $48
Fuel $2 $2 $2
Total operating expenses(5) $40 $35 $36
Percentage of output sold to spot market 49% 52% 35%
(1)
Includes fuel cost recoveries for Bruce A of $4 million for 2005.

(2)
TCPL's consolidated equity income includes $168 million which represents
TCPL's 31.6 per cent share of Bruce Power earnings for the ten months ended
October 31, 2005. TCPL acquired a 31.6 per cent interest in Bruce B in
February 2003, which at the time owned the currently idle Bruce A Units 1
and 2 as well as the currently operating Bruce A Units 3 and 4 and Bruce B
Units 5 to 8.

(3)
Gigawatt hours.

(4)
Megawatt hours.

(5)
Net of cost recoveries.

34 MANAGEMENT'S DISCUSSION AND ANALYSIS

TCPL's operating and other income from its combined investment in Bruce Power
for 2005 was $195 million compared to $130 million for 2004. The increase of $65
million was primarily due to higher realized prices in 2005 and was offset in
part by higher maintenance costs, higher depreciation and lower capitalization
of labour and other in-house costs following the restart of Unit 3 in first
quarter 2004. Adjustments to TCPL's combined interest in Bruce Power's income
before income taxes for 2005 were lower than in 2004 primarily due to a lower
amortization of the purchase price allocated to the fair value of sales
contracts in place at the time of acquisition in 2003.

Combined Bruce Power prices achieved during 2005 (excluding Bruce cost
recoveries) were $58 per MWh compared to $47 per MWh in 2004 reflecting higher
prices on uncontracted volumes sold into the spot market. Bruce Power's combined
operating expenses (net of cost recoveries) increased to $40 per MWh for 2005
from $35 per MWh in 2004. This was primarily the result of one additional
planned maintenance outage in 2005 compared to 2004 as well as higher
maintenance costs, higher depreciation and lower capitalization of labour and
other in-house costs following the restart of Unit 3.

The Bruce units ran at a combined average availability of 80 per cent in 2005,
compared to an 82 per cent average availability during 2004. The lower
availability in 2005 was the result of 67 additional days of planned maintenance
outages plus an additional 45 forced outage days in 2005 as compared to 2004.
The additional forced outage days in 2005 are due in large part to a 27 day
forced outage that occurred as a result of a transformer fire at Unit 6.

TCPL's operating and other income from its combined investment in Bruce Power
for 2004 was $130 million compared to $99 million for 2003. This increase was
primarily due to higher output in 2004 as a result of the return to service of
Units 3 and 4 as well as a full year of earnings in 2004 on Units 5 to 8
compared to earnings from February 14 to December 31 in 2003, reflecting TCPL's
period of ownership in 2003. Adjustments to TCPL's interest in Bruce Power
income before taxes for 2004 were lower than the same period in 2003 primarily
due to the cessation of interest capitalization upon the return to service of
Units 3 and 4.

Income from Bruce B is directly impacted by fluctuations in wholesale spot
market prices for electricity and income from both Bruce A and Bruce B units is
impacted by overall plant availability, which in turn, is impacted by scheduled
and unscheduled maintenance. To reduce its exposure to spot market prices, Bruce
B had, as at December 31, 2005, entered into fixed price sales contracts to
sell forward approximately 13,000 GWh hours of 2006 output and approximately
3,600 GWh of 2007 output. As a result of the contract with the OPA, all of the
output from Bruce A will be sold at a fixed price of $57.37 per MWh, adjusted
annually on April 1 for inflation, before recovery of fuel costs from the OPA.
Under the terms of the arrangement between Bruce A and the OPA, effective
October 31, 2005, Bruce A receives a contract price for power generated, where
the price is adjusted for inflation annually on April 1 and capital cost
variances associated with the restart and refurbishment project but will not
vary with changes in the wholesale price of power in the Ontario market. As part
of this contract, sales from the Bruce B Units 5 to 8 are subject to a floor
price of $45 per MWh, adjusted annually for inflation on April 1. Receipts by
Bruce Power under this floor price mechanism are refundable if prices
subsequently increase above the floor price.

The overall plant availability percentage in 2006 is expected to be in the low
90s for the four Bruce B units and the low 80s for the two operating Bruce A
units. A planned outage on Bruce A Unit 3 is scheduled to last approximately one
month during first quarter 2006 and a two month maintenance outage of Bruce A
Unit 4 is expected to commence in second quarter 2006. The only planned
maintenance outage for 2006 for Bruce B is an approximate two month outage
scheduled for Unit 8 beginning in third quarter 2006.

In 2005, cash distributions to partners, excluding a special distribution, were
$400 million of which TCPL's share was $126 million. No distributions were made
to partners in 2004. The partners have agreed that all excess cash from both
Bruce A and Bruce B will be distributed on a monthly basis and that separate
cash calls will be made for major capital projects, including the Bruce A
restart and refurbishment project.

Bruce A's capital program for the restart and refurbishment project is expected
to total approximately $4.25 billion and TCPL's approximate $2.125 billion share
will be financed through capital contributions to 2011. A capital cost risk and

MANAGEMENT'S DISCUSSION AND ANALYSIS 35

reward sharing schedule with OPA is in place for spending below or in excess of
the $4.25 billion base case estimate. Work to refurbish Units 1 and 2 has
commenced with the first unit expected to be online in 2009, subject to approval
by the Canadian Nuclear Safety Commission. Restarting Units 1 and 2, which have
a combined capacity of approximately 1,500 MW, will boost the Bruce facilities'
overall output to more than 6,200 MW. As at December 31, 2005, Bruce A had
capitalized $324 million with respect to the restart and refurbishment project.

Western Operations

Western Operations Results-at-a-Glance(1)
Year ended December 31 (millions of dollars)
2005 2004 2003

Revenues
Power 715 606 688
Other(2) 158 120 112

873 726 800

Cost of sales
Power (476 ) (377 ) (442 )
Other(3) (104 ) (64 ) (71 )

(580 ) (441 ) (513 )

Other costs and expenses (149 ) (125 ) (98 )
Depreciation (21 ) (22 ) (29 )

Operating and other income 123 138 160

(1)
ManChief is included until April 30, 2004.

(2)
Includes Cancarb Thermax and natural gas sales.

(3)
Includes the cost of natural gas sold.

Western Operations Sales Volumes(1)
Year ended December 31 (GWh)
2005 2004 2003
Supply
Generation 2,245 2,105 2,010
Purchased
Sundance A & B PPAs 6,974 6,842 6,959
Other purchases 2,687 2,748 3,327
11,906 11,695 12,296

Contracted vs. Spot
Contracted 10,374 10,705 11,039
Spot 1,532 990 1,257
11,906 11,695 12,296
(1)
ManChief is included until April 30, 2004.

36 MANAGEMENT'S DISCUSSION AND ANALYSIS

As at December 31, 2005, Western Operations directly controlled approximately
2,100 MW of power supply in Alberta from its three long-term PPAs and five
natural gas-fired cogeneration facilities. The Western Operations power supply
portfolio is now comprised of approximately 1,700 MW of low-cost, base-load
coal-fired generation supply and approximately 400 MW of natural gas-fired
cogeneration assets. This supply portfolio is among the lowest-cost, most
competitive generation in the Alberta market area. The three long-term PPAs
include the December 2005 acquisition of the remaining rights and obligations of
the 756 MW Sheerness PPA in addition to the Sundance A and Sundance B PPAs
acquired in 2001 and 2002, respectively. The Sheerness PPA was acquired from the
Alberta Balancing Pool for $585 million and has a remaining term of
approximately 15 years. The PPAs entitle TCPL to the output capacity of these
coal facilities, ending in 2017 to 2020.

The focus of Western Operations is to maximize the value of its power supply
portfolio through a balanced portfolio of long- and short-term power sale
contracts. The focus is also on expanding its power supply portfolio though
acquisitions and optimizing the value and output from its existing generation
assets. The success of Western Operations is the direct result of its two
integrated functions - marketing and plant operations.

The marketing function, based in Calgary, Alberta, purchases and resells
electricity sourced from the PPAs, markets uncommitted generation volumes from
the cogeneration facilities and purchases and resells power and natural gas to
maximize the value of the cogeneration facilities. The marketing function is
integral to optimizing Power's return from its portfolio of power supply and
managing risks around uncontracted volumes. The intention for the Sheerness
output is the same as the Sundance output, whereby a significant portion of the
power supply is expected to be sold under long-term contract to the extent
possible in the market. The majority of the expected output from the
cogeneration plants is also sold under long-term contract. Some portion of power
supply from the PPAs and the cogeneration assets is intentionally not committed
under long-term sales contracts to assist in managing Power's overall portfolio
of generation. This approach to portfolio management assists in minimizing costs
in situations where Power would otherwise have to purchase power in the open
market to fulfill its contractual obligations. In 2005, approximately 13 per
cent of power sales volumes were sold into the spot market. To reduce exposure
to spot market prices of uncontracted volumes, as at December 31, 2005, Western
Operations had fixed price sale contracts to sell forward approximately 9,800
GWh for 2006 and 6,000 GWh for 2007.

Plant operations consist of five natural gas-fired cogeneration power plants
located in Alberta with an approximate combined output capacity of 400 MW
ranging from 27 MW to 165 MW per facility. A majority of the expected output is
sold under long-term contracts and the remainder is subject to fluctuations in
the price of power and natural gas. Market heat rates in Alberta in 2005 were at
historic lows earlier in the year but improved substantially by year-end. Market
heat rate is determined by dividing the average price of power per MWh by the
average price of natural gas per gigajoule (GJ) for a given period. To the
extent power is not sold under long-term contract and plant fuel-gas has not
been purchased, the higher the market heat rate, the more profitable is a
natural gas-fired generating facility. Market heat rates averaged approximately
8.3 GJ/MWh in 2005 compared to approximately 8.8 GJ/MWh in 2004. All plants,
except the 80 MW Bear Creek facility located near Grand Prairie, operated with
an average plant availability in 2005 of approximately 93 per cent.

Bear Creek experienced an unplanned outage in 2005 resulting from technical
difficulties with its gas turbine in the early part of 2005 and the facility has
remained on an unplanned outage since May 31, 2005. Technical evaluation
continued throughout 2005 regarding a possible long-term solution and the asset
is expected to be back in service by mid-2006.

Operating and other income for 2005 was $123 million or $15 million lower
compared to $138 million earned in 2004. This decrease was primarily due to
reduced margins in 2005 resulting from the lower market heat rates on
uncontracted volumes of power generated, fee revenues earned in 2004 from Power
LP and a lower contribution from Bear Creek. Revenues and cost of sales
increased in 2005 compared to 2004 primarily due to higher realized prices.
Other costs and expenses, which include fuel gas consumed in generation,
increased due to higher operating and fuel usage costs at MacKay River resulting
from a full year of operation and higher natural gas prices. Generation volumes
in 2005 increased compared to 2004 primarily due to a full year of operations at
MacKay River partially offset by the

MANAGEMENT'S DISCUSSION AND ANALYSIS 37

unplanned outage at Bear Creek. The potential to earn fees to manage and operate
Power LP's plants was eliminated with the sale of Power LP to EPCOR in August
2005. In 2005, approximately 13 per cent of power sales volumes were sold into
the spot market compared to eight per cent in 2004.

Operating and other income in 2004 of $138 million was $22 million lower than
the $160 million earned in 2003. The decrease was mainly due to a positive $31
million pre-tax settlement in June 2003 with a former counterparty that
defaulted in 2001 under power forward contracts, as well as reduced income from
ManChief following the sale of the plant to Power LP in April 2004. Partially
offsetting these decreases were contributions from the MacKay River plant which
was placed in service in 2004, fees earned with respect to Power LP's asset
acquisitions in 2004 and the impact of higher net margins achieved in second and
third quarter 2004 on the overall portfolio.

Eastern Operations

Eastern Operations Results-at-a-Glance(1)
Year ended December 31 (millions of dollars)
2005 2004 2003

Revenues
Power 505 535 608
Other(2) 412 238 200

917 773 808

Cost of sales
Power (215 ) (288 ) (281 )
Other(2) (373 ) (211 ) (185 )

(588 ) (499 ) (466 )

Other costs and expenses (167 ) (146 ) (186 )
Depreciation (25 ) (20 ) (29 )

Operating and other income 137 108 127

(1)
Curtis Palmer is included until April 30, 2004.

(2)
Other includes natural gas.

Eastern Operations Sales Volumes(1)
Year ended December 31 (GWh)
2005 2004 2003
Supply
Generation 2,879 1,467 1,871
Purchased 2,627 4,731 5,035
5,506 6,198 6,906

Contracted vs. Spot
Contracted 4,919 6,055 6,678
Spot 587 143 228
5,506 6,198 6,906
(1)
Curtis Palmer is included until April 30, 2004.

38 MANAGEMENT'S DISCUSSION AND ANALYSIS

Eastern Operations conducts its business primarily in the Northeastern U.S. and
Eastern Canada markets and excludes Bruce Power. In the New England market,
Eastern Operations has established a successful marketing operation and, in
2005, acquired a significant group of hydroelectric generation assets from USGen
with generation capacity of 567 MW. In Eastern Canada, construction continued on
the 550 MW Becancour natural gas-fired plant in Quebec and the 90 MW Grandview
cogeneration facility was placed into service on January 1, 2005. In late 2005,
development plans were finalized and construction is expected to commence early
2006 on the first two of six wind farm projects, with generating capacity of 210
MW of the 739.5 MW Cartier Wind projects in Quebec. Including facilities that
are under construction or in development, Eastern Operations owns more than
2,200 MW of power generation capacity.

Eastern Operations' success in the New England deregulated power markets is the
direct result of a knowledgeable, region-specific marketing operation which is
conducted through its wholly-owned subsidiary, TransCanada Power Marketing
Limited (TCPM), located in Westborough, Massachusetts. TCPM has firmly
established itself as a leading energy provider and marketer and is focused on
selling power under short- and long-term contracts to wholesale, commercial and
industrial customers while managing a portfolio of power supplies sourced from
both its own generation and wholesale power purchases. To reduce its exposure to
spot market prices, as at December 31, 2005, Eastern Operations had entered into
fixed price sales contracts to sell approximately 5,000 GWh of power for 2006
and approximately 3,500 GWh of power for 2007, although certain contracted
volumes are dependent on customer usage levels. TCPM is a full requirement
electricity service provider offering varied products and services to assist
customers in managing their power supply and power prices in volatile
deregulated power markets.

Eastern Operations' operating power generation assets currently consist of TC
Hydro, Ocean State Power (OSP) and Grandview.

The TC Hydro assets, acquired on April 1, 2005, include 13 hydroelectric
stations housing 39 generating units on the Connecticut River System in New
Hampshire and Vermont, and the Deerfield River System in Massachusetts and
Vermont. These facilities were integrated into TCPL in 2005. Water flows in 2005
through the hydro assets were above the long-term average as a result of higher
precipitation in the areas surrounding the river systems.

OSP is a 560 MW natural gas-fired plant located in Rhode Island. In 2005, OSP
was successful in restructuring its long-term natural gas fuel supply contracts
with its suppliers. The contract restructuring at OSP reduced the term of the
long-term natural gas supply contracts by approximately three years (currently
ending in October 2008) and adjusted the pricing to track spot market pricing of
natural gas at the Niagara delivery point versus the previously arbitrated
pricing that had resulted in an above-market cost of natural gas for OSP. The
new contracts, for approximately 100,000 GJ per day, require OSP to take
delivery of the natural gas irrespective of the fuel requirements at the plant.
OSP experienced an unplanned outage for most of the first half of 2005 resulting
from a failure of one of the steam turbines at the plant. This unit was returned
to service in mid-2005; however, due to the nature of the failure, the second
steam turbine at OSP was taken out of service to undertake repairs and was
returned to service in January 2006. An insurance claim has been filed in
respect of this incident, including a claim for business interruption coverage.
This claim is currently under discussion with the insurers.

Grandview is a 90 MW natural gas-fired cogeneration facility on the site of the
Irving refinery in Saint John, New Brunswick. The Grandview facility was
commissioned in January 2005. Under a 20 year tolling arrangement, Irving
supplies fuel for the plant and contracts for 100 per cent of the plant's heat
and electricity output.

Eastern Operations emerging presence in Eastern Canada is represented by the
development and construction in 2006 of the 550 MW natural gas-fired Becancour
plant and the first two of six wind farms of the Cartier Wind project. The first
of the two wind farms is expected to be in service in late 2006. Becancour is
expected to be operational in late 2006. Becancour and Cartier Wind are located
in Quebec.

Operating and other income for 2005 was $137 million or $29 million higher than
the $108 million earned in 2004. Incremental income from the acquisition of the
TC Hydro assets and income from the Grandview cogeneration facility were the
primary reasons for this increase. Partially offsetting these increases were a
$16 million pre-tax ($10 million

MANAGEMENT'S DISCUSSION AND ANALYSIS 39

after tax) contract restructuring payment made by OSP to its natural gas fuel
suppliers in first quarter 2005, a $16 million pre-tax ($10 million after tax)
reduction in income as a result of the sale of Curtis Palmer to Power LP in
April 2004, and a loss of operating income primarily associated with the
expiration of certain long-term sales contracts in 2004.

Eastern Operations' power revenues decreased in 2005 primarily due to lower
long-term sales volumes resulting from the expiration of certain contracts at
the end of 2004. Partially offsetting this were higher realized prices in 2005.
Other revenue and other cost of sales increased year-over-year as a result of
natural gas purchased and resold under the new natural gas supply contracts at
OSP. Cost of sales for power were lower in 2005 due to the impact of lower
purchased volumes partially offset by higher prices for purchased power.
Purchased power volumes were lower in 2005 due to lower contracted sales volumes
and the incremental power generation from the purchase of the TC Hydro assets.
Volumes generated from the TC Hydro assets reduced the requirement to purchase
power to fulfill contractual sales obligations. Other costs and expenses in 2005
were higher primarily due to the acquisition of the TC Hydro assets.

Operating and other income for 2004 was $108 million or $19 million lower than
the $127 million earned in 2003. This decrease was mainly due to a reduction in
income as a result of the sale of the Curtis Palmer hydroelectric facilities to
Power LP in April 2004, the unfavourable impact of higher natural gas fuel costs
at OSP and a weaker U.S. dollar in 2004. Partially offsetting these decreases
was a $16 million positive impact from the restructuring transaction related to
the power purchase contracts in 2004 between OSP and Boston Edison Company
(Boston Edison). TCPL recognized earnings from the transaction's effective date
of April 1, 2004.

Power LP Investment

On August 31, 2005, TCPL closed the sale of all of its interest in Power LP to
EPCOR for net proceeds of $523 million resulting in an after-tax gain of $193
million. This divestiture included approximately 14.5 million Partnership units,
representing approximately 30.6 per cent of the outstanding units, 100 per cent
ownership of the general partner of Power LP, and management and operations
agreements governing the ongoing operation of Power LP's generation assets.
TCPL's investment in Power LP generated operating and other income of $29
million in 2005 compared to $29 million and $35 million in 2004 and 2003,
respectively.

Weighted Average Plant Availability(1)
2005 2004 2003
Bruce Power(2) 80% 82% 83%
Western operations(3) 85% 95% 93%
Eastern operations(3)(4) 83% 95% 94%
Power LP investment(3)(5) 94% 97% 96%
All plants, excluding Bruce Power 87% 96% 94%
All plants 84% 90% 90%
(1)
Plant availability represents the percentage of time in the year that the
plant is available to generate power, whether actually running or not, and
is reduced by planned and unplanned outages.

(2)
Unit 3 is included effective March 1, 2004 and Unit 4 is included effective
November 1, 2003.

(3)
ManChief and Curtis Palmer are included in Power LP Investment effective
April 30, 2004.

(4)
TC Hydro is included in Eastern Operations effective April 1, 2005.

(5)
Power LP is included to August 31, 2005.

Weighted average plant availability, excluding Bruce Power, was 87 per cent in
2005 compared to 96 per cent in 2004. Western Operations' weighted average plant
availability was impacted in 2005 by an unplanned outage at Bear Creek

40 MANAGEMENT'S DISCUSSION AND ANALYSIS

and a planned outage at MacKay River. In 2005, Eastern Operations experienced
two significant outages at OSP. The first outage was completed in mid-2005 and
the second outage was completed in January 2006.

POWER - OPPORTUNITIES AND DEVELOPMENTS

TCPL is committed to growing the Power business through acquisitions and
development of greenfield opportunities in markets it knows and where it has a
competitive advantage - primarily Western Canada, Eastern Canada and the
Northeastern U.S. The North American power industry is expansive and will
provide many opportunities for greenfield growth in power generation and power
infrastructure projects. In addition to greenfield growth opportunities, TCPL
will continue to pursue acquisitions of additional power assets, including
opportunities resulting from, amongst other things, industry and corporate
restructurings and corporate bankruptcies. Power's diverse power supply
portfolio will continue to include low-cost, base-load facilities with low
operating costs and high reliability and/or be underpinned by secure long-term
contracts.

The Cartier Wind project is scheduled to commercially place in service the
first of six wind farms in 2006. The remaining five wind farms are expected to
be placed in service between 2007 and 2012. The Becancour natural gas-fired
cogeneration power plant is expected to be in service in late 2006. Bruce Power
will continue refurbishment of the currently idle Bruce A Units 1 and 2 for
expected restart commencing in 2009.

In February 2006, the Ontario Energy Minister directed the OPA to move forward
to negotiate the terms for the construction of the 550 MW Portlands Energy
Centre (PEC) in downtown Toronto. TCPL has a 50 per cent interest in PEC through
a partnership with Ontario Power Generation.

POWER - BUSINESS RISKS

Plant Availability

Maintaining plant availability is critical to the continued success of the Power
business and this risk is mitigated through a commitment to an operational
excellence model that provides low-cost, reliable operating performance at each
of the company's power plants. This same commitment to operational excellence
will be applied in 2006 and future years. However, unexpected plant outages and/
or the duration of outages could result in lower sales revenue, reduced margins,
increased maintenance costs and may require power purchases at market prices to
enable TCPL to meet the company's contractual power supply obligations.

Fluctuating Market Prices

TCPL operates in highly competitive, deregulated power markets. Volatility in
electricity prices is caused by market factors such as power plant fuel costs,
fluctuating supply and demand which are greatly affected by weather, power
consumption and plant availability. TCPL manages these inherent market risks
through:

*
long-term purchase and sales contracts for both electricity and plant
fuels;

*
control of generation output;

*
matching physical plant contracts or PPA supply with customer demand;

*
fee-for-service managed accounts rather than direct commodity exposure;
and

*
the company's overall risk management program with respect to general
market and counterparty risks.

The company's risk management practices are described further in the section on
"Risk Management". See the section below "Power - Business Risks - Uncontracted
Volumes".

MANAGEMENT'S DISCUSSION AND ANALYSIS 41

Weather

Extreme temperature and weather events often affect power and natural gas demand
and create price volatility, and may also impact the ability to transmit power
to markets. Seasonal changes in temperature also affect the efficiency and
output capability of natural gas-fired power plants.

Hydrology

Power is subject to hydrology risk with its ownership of hydroelectric power
generation facilities in the Northeastern U.S. Climate changes, weather events,
local river management and potential dam failures at these plants or upstream
facilities pose potential risks to the company.

Uncontracted Volumes

Sale of uncontracted power in the open market is subject to market price
volatility which directly impacts earnings. TCPL has uncontracted sales volumes
in both its Eastern Operations and Western Operations. In addition, with the
acquisition of the Sheerness PPA in late 2005, Western Operations significantly
increased its level of uncontracted sales volumes which are subject to price
volatility in the Alberta wholesale marketplace. Although TCPL seeks to
generally secure sales under medium- to long-term contracts, TCPL retains an
amount of unsold generation in the short term in order to provide flexibility in
managing the company's portfolio of owned assets. Also, Bruce B has a
significant amount of uncontracted volumes sold into the wholesale spot market,
although 100 per cent of the Bruce A output will be sold to the OPA under fixed
price contract terms. Sales from the Bruce B Units 5 to 8 are subject to a floor
price of $45 per MWh, adjusted annually for inflation on April 1.

Execution and Capital Cost

TCPL, including its investment in Bruce Power, is subject to execution and
capital cost risk. Bruce A's four unit restart and refurbishment program is
subject to execution and capital cost risk. Bruce A and the OPA share capital
costs that are above and below $4.25 billion on a 50/50 basis for cost overruns
up to $618 million and 75/25 for any additional cost overruns. Similarly, Bruce
A and OPA share 50/50 in cost benefits if costs are $240 million less than
expected and 75/25 on the next $150 million of savings.

Regulatory

TCPL operates in both regulated and deregulated power markets. As electricity
markets evolve across North America, there is the potential for regulatory
bodies to implement new rules that could negatively impact TCPL as a generator
and marketer of electricity. These may be in the form of market rule changes,
price caps, emission controls, unfair cost allocations to generators or attempts
to control the wholesale market by encouraging new plant construction. TCPL
continues to monitor regulatory issues and reform as well as participate in and
lead discussions around these topics.

Foreign Exchange

TCPL's earnings from Northeastern U.S. Operations are generated in U.S. dollars.
The performance of the Canadian dollar relative to the U.S. dollar would either
positively or negatively impact Power's net earnings, although this impact is
mitigated by offsetting exposures in certain of TCPL's other businesses as well
as through the company's hedging activities.

POWER - OTHER

Operational Excellence

TCPL's sale of Power LP to EPCOR allowed it to focus on larger, directly owned
power assets. TC Hydro was effectively integrated in 2005 while maintaining high
levels of operating performance. TCPL continues its commitment to an operational
excellence strategy of providing low cost, reliable performance.

42 MANAGEMENT'S DISCUSSION AND ANALYSIS

POWER - OUTLOOK

Net earnings from Bruce Power are expected to be higher in 2006 as a result of
higher generation volumes of output from fewer planned outages and TCPL's
increased ownership in Bruce A. Bruce B earnings are subject to variability as a
result of prices realized, and both Bruce A and Bruce B results are impacted by
plant availability and operating expense levels. The overall plant availability
percentage in 2006, for planning purposes, is expected to be in the low 90s for
the four Bruce B units and in the low 80s for the two operating Bruce A units.

The contribution from Western Operations is expected to be higher in 2006
primarily due to the December 2005 acquisition of the Sheerness PPA. At December
31, 2005 a significant portion of the acquired generation from Sheerness was
uncontracted. The intention for marketing the Sheerness output is the same as
the Sundance output, whereby a significant portion of the power supply is
expected to be sold under long-term contract, providing this is possible in the
market. The repair of Bear Creek is a high priority in 2006 and management
expects the facility to be back in service in mid-2006.

The contribution from Eastern Operations is expected to rise slightly in 2006
compared to 2005 due to a full year of ownership of the TC Hydro assets and the
expected commercial in-service of Becancour and the first of the Cartier wind
farms in late 2006.

The loss of earnings resulting from the sale of Power LP in August 2005 will
partially offset these impacts.

Earnings opportunities in Power may be affected by factors such as plant
availability, fluctuating market prices for power and natural gas and ultimately
market heat rates, regulatory changes, weather, sales of uncontracted volumes,
currency movements and overall stability of the power industry. See "Power -
Business Risks" for a complete discussion of these factors.

MANAGEMENT'S DISCUSSION AND ANALYSIS 43

CORPORATE

CORPORATE RESULTS-AT-A-GLANCE
Year ended December 31 (millions of dollars)
2005 2004 2003

Indirect financial charges and non-controlling interests 131 81 89
Interest income and other (29 ) (34 ) (21 )
Income taxes (65 ) (43 ) (27 )

Net expenses, after tax 37 4 41

Corporate reflects net expenses not allocated to specific business segments,
including:

* Indirect Financial Charges and Non-Controlling Interests Direct financial
charges are reported in their respective business segments and are primarily
associated with the debt and preferred securities related to the company's
Wholly-Owned Pipelines. Indirect financial charges, including the related
foreign exchange impacts, primarily reside in Corporate. These costs are
directly impacted by the amount of debt that TCPL maintains and the degree to
which TCPL is impacted by fluctuations in interest rates and foreign exchange.

* Interest Income and Other Interest income is primarily earned on invested
cash balances. Gains and losses on foreign exchange related to working capital
in Corporate are included in interest income and other.

* Income Taxes These include income taxes on corporate net expenses and
income tax refunds and adjustments.

Net expenses, after tax, in Corporate were $37 million in 2005 compared to $4
million in 2004 and $41 million in 2003.

The increase of $33 million in net expenses in 2005 compared to 2004 was
primarily due to increased interest expense on higher average long-term debt and
commercial paper balances in 2005 as well as the release in 2004 of previously
established restructuring provisions. Income tax refunds and positive tax
adjustments were comparable in 2004 and 2005.

The decrease of $37 million in net expenses in 2004 compared to 2003 was
primarily due to the positive impacts of income tax related items, including
refunds received and the recognition of income tax benefits relating to
additional loss carryforwards utilized, the release in 2004 of previously
established restructuring provisions and positive impacts of foreign exchange
related items.

In 2006, Corporate is expected to incur higher net expenses compared to 2005
primarily due to the income tax refunds and positive income tax adjustments
recorded in 2005 that are not currently expected to recur in 2006. In addition,
Corporate's results in 2006 could be impacted by debt levels, interest rates,
foreign exchange movements and income tax refunds and adjustments. The
performance of the Canadian dollar relative to the U.S. dollar would either
positively or negatively impact Corporate's results, although this impact is
mitigated by offsetting exposures in certain of TCPL's other businesses as well
as through the company's hedging activities.

44 MANAGEMENT'S DISCUSSION AND ANALYSIS

LIQUIDITY AND CAPITAL RESOURCES

Funds Generated from Operations

Funds generated from operations were approximately $2.0 billion for 2005 compared to approximately
$1.7 billion and $1.8 billion, for 2004 and 2003, respectively. The Gas Transmission business was the
primary source of funds generated from operations for each of the three years. As a result of rapid
growth in the Power business in the last few years, the Power segment's funds generated from
operations increased in 2005 compared to the two prior years. The decrease in 2004 compared to 2003
was mainly a result of higher current income tax expense in 2004 compared to 2003.

At December 31, 2005, TCPL's ability to generate adequate amounts of cash in the short term and the
long term when needed, and to maintain financial capacity and flexibility to provide for planned
growth, was consistent with recent years.

Investing Activities

Capital expenditures, excluding acquisitions, totalled $754 million in 2005
compared to $530 million in 2004 and $395 million in 2003, respectively.
Expenditures in all three years related primarily to construction of new power
plants in Canada and maintenance and capacity capital in TCPL's Gas Transmission
business.

During 2005, TCPL acquired the remaining rights and obligations of the Sheerness PPA for $585
million, invested a net cash outlay of $100 million in Bruce A as part of the Bruce Power
reorganization, purchased the TC Hydro assets for US$503 million and acquired an additional 3.5 per
cent ownership interest in Iroquois Gas Transmission System L.P. for US$14 million. In 2005, TCPL
sold its ownership interest in Power LP for proceeds of $444 million, net of current tax, its
approximate 11 per cent ownership interest in Paiton Energy for proceeds of $125 million, net of
current tax, and PipeLines LP units for proceeds of $102 million, net of current tax.

During 2004, TCPL acquired GTN for US$1.2 billion, excluding assumed debt of approximately US$0.5
billion, and sold the ManChief and Curtis Palmer power facilities to Power LP for US$402.6 million,
excluding closing adjustments.

During 2003, TCPL acquired a 31.6 per cent interest in Bruce Power for $409
million, the remaining interests in Foothills previously not held by the company
for $105 million, excluding assumed debt of $154 million, and increased its
interest in Portland to 61.7 per cent from 33.3 per cent for US$51 million,
excluding assumed debt of US$78 million.

Financing Activities

In 2005, TCPL retired long-term debt of $1,113 million. In June 2005, Gas
Transmission Northwest Corporation (GTNC) redeemed all of its outstanding US$150
million 7.80 per cent Senior Unsecured Debentures (Debentures). As a
consequence, upon application by GTNC, the Debentures were de-listed from the
New York Stock Exchange and GTNC no longer has any securities registered under
U.S. securities laws. In June 2005, GTNC completed a US$400 million
multi-tranche private placement of senior debt with a weighted average interest
rate of 5.28 per cent and weighted average life of approximately 18 years. In
2005, TCPL also issued $300 million of 5.10 per cent medium-term notes due 2017
under the company's Canadian shelf prospectus. The company increased its notes
payable by $416 million during 2005.

In 2004, TCPL retired long-term debt of $1,005 million. The company issued $200
million of 4.10 per cent medium-term notes due 2009, US$350 million of 5.60 per
cent senior unsecured notes due 2034 and US$300 million of 4.875 per cent
senior unsecured notes due 2015. The company increased its notes payable by $179
million during 2004.

MANAGEMENT'S DISCUSSION AND ANALYSIS 45

In 2003, TCPL repaid long-term debt of $753 million, reduced notes payable by
$62 million and redeemed all of its outstanding US$160 million, 8.75 per cent
Junior Subordinated Debentures. The company issued $450 million of ten year,
5.65 per cent medium-term notes and US$350 million of ten year, 4.00 per cent
senior unsecured notes.

Dividends on common and preferred shares of $608 million were paid in 2005
compared to $574 million in 2004 and $532 million in 2003.

In January 2006, TCPL's Board of Directors declared a dividend for the quarter
ending March 31, 2006 in an aggregate amount equal to the aggregate quarterly
dividend to be paid on April 28, 2006 by TransCanada on the issued and
outstanding common shares as at the close of business on March 31, 2006.

Certain terms of the company's preferred shares, preferred securities, and debt
instruments could restrict the company's ability to declare dividends on
preferred and common shares. At December 31, 2005 under the most restrictive
provisions, approximately $1.6 billion was available for the payment of
dividends on common shares.

Financing activities included a net reduction in TCPL's proportionate share of
non-recourse debt of joint ventures of $42 million in 2005 compared to a net
increase of $105 million in 2004 and a net decrease of $12 million in 2003.

Credit Activities

At December 31, 2005, TCPL had shelf prospectuses that qualified for issuance
$1.2 billion of medium-term notes in Canada and US$1 billion of debt securities
in the U.S. In January 2006, $300 million of 4.3 per cent medium-term notes due
2011 were issued under the Canadian shelf prospectus.

At December 31, 2005, total credit facilities of $2.0 billion were available to
support the company's commercial paper program and for general corporate
purposes. Of this total, $1.5 billion is a committed five-year term syndicated
credit facility. The facility is extendible on an annual basis and is revolving.
In December 2005, the maturity date of this facility was extended to December
2010. The remaining amounts are either demand or non-extendible facilities.

At December 31, 2005, TCPL had used approximately $271 million of its total
lines of credit for letters of credit and to support ongoing commercial
arrangements. If drawn, interest on the lines of credit would be charged at
prime rates of Canadian chartered and U.S. banks or at other negotiated
financial bases.

Credit ratings on TCPL's senior unsecured debt assigned by Dominion Bond Rating
Service Limited (DBRS), Moody's and Standard & Poor's are currently A, A2 and A
-, respectively. DBRS and Moody's both maintain a 'stable' outlook on their
ratings and Standard & Poor's maintains a 'negative' outlook on its rating.

This information is provided by RNS
The company news service from the London Stock Exchange

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