Exhibit 4.217


 





FIRST QUARTER 2003


 


Quarterly
Report to Shareholders
Consolidated Results-at-a-Glance


 


	
  Three months ended March 31 (unaudited)

  (millions
  of dollars except per share amounts)

  	
   

  	
  2003

  	
   

  	
  2002

  	
   

  
	
  Net
  Income Applicable to Common Shares

  	
   

  	
  208

  	
   

  	
  187

  	
   

  
	
   

  	
   

  	
   

  	
   

  	
   

  	
   

  
	
  Net
  Income Per Share - Basic and Diluted

  	
   

  	
  $

  	
  0.43

  	
   

  	
  $

  	
  0.39

  	
   

  
								



 


 


Management’s Discussion and Analysis


 


The following discussion and
analysis should be read in conjunction with the accompanying unaudited
consolidated financial statements of TransCanada PipeLines Limited (TransCanada
or the company) for the three months ended March 31, 2003 and the notes
thereto.


 


Results of Operations


 


Consolidated


 


TransCanada’s net income
applicable to common shares for the three months ended March 31, 2003 was $208
million or $0.43 per share compared to $187 million or $0.39 per share for
first quarter 2002.  The increase of $21
million or $0.04 per share in first quarter 2003 compared to first quarter 2002
was primarily due to higher earnings from the Power business and reduced net
expenses in the Corporate segment, partially offset by lower earnings from the
Transmission segment.  In first quarter
2003, the Power segment earnings included $27 million related to TransCanada’s
earnings from its investment in Bruce Power L.P. (Bruce) which was acquired by
TransCanada in February 2003.  The lower
earnings in the Transmission segment were primarily due to the decline in the 


 

















 


Alberta System’s net earnings
reflecting the one-year fixed 2003 revenue requirement settlement reached
between TransCanada and its stakeholders in February 2003.


 


Funds generated from operations
of $457 million for the three months ended March 31, 2003 were consistent with
the same period in the prior year.


 

















 


Segment
Results-at-a-Glance


 


	
  Three months ended March 31 (unaudited)

  (millions of dollars)

  	
   

  	
  2003

  	
   

  	
  2002

  	
   

  
	
  Transmission

  	
   

  	
  158

  	
   

  	
  163

  	
   

  
	
  Power

  	
   

  	
  63

  	
   

  	
  41

  	
   

  
	
  Corporate

  	
   

  	
  (13

  	
  )

  	
  (17

  	
  )

  
	
   

  	
   

  	
   

  	
   

  	
   

  	
   

  
	
  Net
  Income Applicable to Common Shares

  	
   

  	
  208

  	
   

  	
  187

  	
   

  



 


Transmission


 


The Transmission business
generated net earnings of $158 million and $163 million for the three months
ended March 31, 2003 and 2002, respectively.


 


Transmission
Results-at-a-Glance


 


	
  Three months ended March 31 (unaudited)

  (millions
  of dollars)

  	
   

  	
  2003

  	
   

  	
  2002

  	
   

  
	
  Wholly-Owned
  Pipelines

  	
   

  	
   

  	
   

  	
   

  	
   

  
	
  Alberta System

  	
   

  	
  42

  	
   

  	
  50

  	
   

  
	
  Canadian Mainline

  	
   

  	
  71

  	
   

  	
  68

  	
   

  
	
  BC System

  	
   

  	
  2

  	
   

  	
  2

  	
   

  
	
   

  	
   

  	
  115

  	
   

  	
  120

  	
   

  
	
  North
  American Pipeline Ventures

  	
   

  	
   

  	
   

  	
   

  	
   

  
	
  Great Lakes

  	
   

  	
  17

  	
   

  	
  22

  	
   

  
	
  TC PipeLines, LP

  	
   

  	
  3

  	
   

  	
  4

  	
   

  
	
  Iroquois

  	
   

  	
  7

  	
   

  	
  5

  	
   

  
	
  Portland

  	
   

  	
  7

  	
   

  	
  1

  	
   

  
	
  Foothills

  	
   

  	
  4

  	
   

  	
  5

  	
   

  
	
  Trans Québec & Maritimes

  	
   

  	
  2

  	
   

  	
  2

  	
   

  
	
  CrossAlta

  	
   

  	
  3

  	
   

  	
  5

  	
   

  
	
  Northern Development

  	
   

  	
  (1

  	
  )

  	
  (1

  	
  )

  
	
  Other

  	
   

  	
  1

  	
   

  	
  —

  	
   

  
	
   

  	
   

  	
  43

  	
   

  	
  43

  	
   

  
	
  Net earnings

  	
   

  	
  158

  	
   

  	
  163

  	
   

  



 


Wholly-Owned Pipelines


 


The Alberta System’s net
earnings of $42 million in first quarter 2003 decreased $8 million compared to
$50 million in the same quarter of 2002. 
The decrease in net earnings is primarily due to lower earnings as a
result of the one-year 2003 revenue requirement settlement which includes a
fixed revenue


 

















 


requirement component of $1.277
billion compared to a fixed revenue requirement component of $1.347 billion in
2002.  The Alberta System’s annual net
earnings in 2003 are expected to be lower by approximately $40 million after
tax compared to annual 2002 net earnings of $214 million.


 


The Canadian Mainline’s net
earnings have increased $3 million for the three months ended March 31, 2003
when compared to the corresponding period in 2002.  The increase in 2003 net earnings is mainly due to the National
Energy Board’s decision on TransCanada’s Fair Return application (Fair Return
decision) which included an increase in the deemed common equity ratio from 30
to 33 per cent, effective January 1, 2001. 
The Fair Return decision was made in June 2002, and was therefore not reflected
in first quarter 2002 earnings.  Earnings
in first quarter 2003 also reflect an increase in the approved rate of return
on common equity from 9.53 per cent in 2002 to 9.79 per cent in 2003, partially
offset by a lower average investment base. 
The NEB hearing which commenced February 26, 2003 to consider the
Canadian Mainline 2003 Tolls and Tariff Application is still in process.


 


Operating Statistics


 


	
  Three months ended March 31 (unaudited)

  	
   

  	
  Alberta

  System*

  	
   

  	
  Canadian

  Mainline**

  	
   

  	
  BC

  System

  	
   

  
	
   

  	
   

  	
  2003

  	
   

  	
  2002

  	
   

  	
  2003

  	
   

  	
  2002

  	
   

  	
  2003

  	
   

  	
  2002

  	
   

  
	
   

  	
   

  	
   

  	
   

  	
   

  	
   

  	
   

  	
   

  	
   

  	
   

  	
   

  	
   

  	
   

  	
   

  
	
  Average investment base ($millions)

  	
   

  	
  4,966

  	
   

  	
  5,088

  	
   

  	
  8,692

  	
   

  	
  8,974

  	
   

  	
  238

  	
   

  	
  200

  	
   

  
	
  Delivery volumes (Bcf)

  	
   

  	
   

  	
   

  	
   

  	
   

  	
   

  	
   

  	
   

  	
   

  	
   

  	
   

  	
   

  	
   

  
	
  Total

  	
   

  	
  1,061

  	
   

  	
  1,067

  	
   

  	
  805

  	
   

  	
  697

  	
   

  	
  61

  	
   

  	
  105

  	
   

  
	
  Average per day

  	
   

  	
  11.8

  	
   

  	
  11.9

  	
   

  	
  8.9

  	
   

  	
  7.7

  	
   

  	
  0.7

  	
   

  	
  1.2

  	
   

  



 












*Field receipt
volumes for the Alberta System for the three months ended March 31, 2003 were
956 Bcf (2002 - 997 Bcf); average per day were 10.6 Bcf (2002 - 11.1 Bcf).


 


**Canadian
Mainline deliveries originating at the Alberta border and in Saskatchewan for
the three months ended March 31, 2003 were 592 Bcf (2002 - 552 Bcf); average
per day were 6.6 Bcf (2002 - 6.1 Bcf).


 


North American Pipeline Ventures


 


TransCanada’s proportionate
share of net earnings of $43 million from its other Transmission businesses for
the three months ended March 31, 2003 was consistent with the same period in
2002.


 


Net earnings for the three
months ended March 31, 2002 included TransCanada’s $7 million share of a
favourable ruling for Great Lakes related to Minnesota use tax paid in prior
years.  Excluding the impact of the
Great Lakes favourable ruling in 2002, net earnings for the three months ended
March 31, 2003 increased mainly due to higher earnings from Portland which
included a depreciation adjustment related to 2002 and higher tolls in first
quarter 2003 compared to first quarter 2002, both as a result of Portland’s
rate settlement in early 2003.


 

















 


Power


 


Power
Results-at-a-Glance


 


	
  Three
  months ended March 31 (unaudited)

  (millions of dollars)

  	
   

  	
  2003

  	
   

  	
  2002

  	
   

  
	
  Western operations

  	
   

  	
  43

  	
   

  	
  34

  	
   

  
	
  Northeastern U.S.
  operations

  	
   

  	
  25

  	
   

  	
  41

  	
   

  
	
  Bruce Power L.P.
  investment

  	
   

  	
  38

  	
   

  	
  —

  	
   

  
	
  Power LP investment

  	
   

  	
  11

  	
   

  	
  10

  	
   

  
	
  General, administrative
  and support costs

  	
   

  	
  (21

  	
  )

  	
  (17

  	
  )

  
	
  Operating and other income

  	
   

  	
  96

  	
   

  	
  68

  	
   

  
	
  Financial charges

  	
   

  	
  (2

  	
  )

  	
  (3

  	
  )

  
	
  Income taxes

  	
   

  	
  (31

  	
  )

  	
  (24

  	
  )

  
	
  Net earnings

  	
   

  	
  63

  	
   

  	
  41

  	
   

  



 


Power’s net earnings of $63
million for the three months ended March 31, 2003 were $22 million higher when
compared to the same period in 2002. 
Strong earnings from the recently acquired interest in Bruce and the addition
of the ManChief plant in late 2002 were the major contributors to this
increase, partially offset by lower earnings from the Northeastern U.S.
Operations.


 


Operating and other income from
Western Operations of $43 million for the three months ended March 31, 2003 was
$9 million higher compared to the same period in 2002 mainly due to the
acquisition of the ManChief facility in November 2002 and lower electricity
transmission tariffs.


 


Operating and other income from
the Northeastern U.S. Operations was $16 million lower for first quarter 2003
compared to first quarter 2002.  The
decrease is primarily due to the higher cost of fuel gas at Ocean State Power
(OSP) and subsequent limited opportunity to resell gas at a profit, and lower
water flows from the Curtis Palmer hydroelectric facility.


 

















 


In December 2002, OSP concluded
an arbitration process with respect to its cost of fuel gas, which
substantially increased the cost of fuel for December 2002 through to March
2003.  A decision was received on a second
arbitration in late March 2003, effective April 2003.  This decision is not materially different from the December 2002
decision.


 


Power completed the acquisition
of a 31.6 per cent interest in Bruce on February 14, 2003.  Bruce consists of two nuclear plants.  Bruce B has four reactors currently
generating a total of 3,140 megawatts (MW). 
Bruce A consists of four 769 MW reactors which are not operating,
however, two units are currently undergoing restart activities. Bruce
contributed $38 million of equity income ($27 million after tax) in first
quarter 2003 from the date of acquisition with an achieved average selling
price of $63/MW hour.  The four Bruce B
units ran at 100 per cent availability during the entire first quarter 2003,
the best performance in the plant’s history, and approximately 45 per cent of
this output was sold into Ontario’s wholesale spot market.  The $38 million contribution reflected
strong plant performance and higher than expected market prices in the
wholesale spot market as a result of colder than normal weather conditions and
increased demand for electricity.


 


Given the
expected critical demand for power in Ontario this summer, Bruce has
accelerated its restart activities to ensure the two Bruce A units are
available during this critical period. 
The expectation is that the facility should have full production from
the two Bruce A units by the end of June 2003. 
As a result of these additional efforts, the total restart costs to be
incurred by Bruce are expected to be approximately 20 per cent higher than the
previous estimate of $450 million (TransCanada's 31.6 per cent share—$142
million), which was comprised of $400 million for the Bruce A Restart Project
and $50 million of deferred startup costs.


 


Equity income from Bruce is directly
impacted by fluctuations in spot market prices for electricity as well as
overall plant availability which, in turn, is impacted by scheduled and
unscheduled maintenance.  To reduce its
exposure to spot market prices, Bruce has entered into fixed price sales
contracts for approximately 1,600 MW of output for the remainder of 2003.  There is a planned maintenance outage at one
of the four Bruce B units for most of the second quarter 2003, which will
reduce quarterly output accordingly. 
Similarly, there is an approximate one month planned outage at one Bruce
B unit and one Bruce A unit in the third and fourth quarter 2003, respectively.


 

















 


Operating and other income from
the investment in TransCanada Power, L.P. was slightly higher for the three
months ended March 31, 2003 compared to the same period in 2002, mainly due to
increased earnings from the Ontario plants and the unplanned outage that
occurred at the Williams Lake plant in first quarter 2002.


 


Power Sales
Volumes*


 


	
  Three
  months ended March 31 (unaudited)

  (gigawatt hours)

  	
   

  	
  2003

  	
   

  	
  2002

  	
   

  
	
   

  	
   

  	
   

  	
   

  	
   

  	
   

  
	
  Western
  operations

  	
   

  	
  2,614

  	
   

  	
  2,828

  	
   

  
	
  Northeastern
  U.S. operations

  	
   

  	
  1,669

  	
   

  	
  1,152

  	
   

  
	
  Bruce
  Power L.P. investment

  	
   

  	
  1,087

  	
   

  	
  —

  	
   

  
	
  Power
  LP investment

  	
   

  	
  565

  	
   

  	
  571

  	
   

  
	
  Total

  	
   

  	
  5,935

  	
   

  	
  4,551

  	
   

  



 












*Power sales volumes
include TransCanada’s share of Bruce Power L.P. (31.6 per cent) and Sundance B
power purchase arrangement (50 per cent) output.


 


Weighted Average Plant Availability


 


	
  Three months ended March 31 (unaudited)

  	
   

  	
  2003

  	
   

  	
  2002

  	
   

  
	
  Western operations

  	
   

  	
  98

  	
  %

  	
  98

  	
  %

  
	
  Northeastern U.S. operations

  	
   

  	
  84

  	
  %

  	
  99

  	
  %

  
	
  Bruce Power L.P. investment

  	
   

  	
  100

  	
  %

  	
  —

  	
   

  
	
  Power LP investment

  	
   

  	
  98

  	
  %

  	
  93

  	
  %

  
	
  All plants

  	
   

  	
  96

  	
  %

  	
  97

  	
  %

  



 


Corporate


 


Net expenses were $13 million
and $17 million for the three months ended March 31, 2003 and 2002,
respectively.  This $4 million
improvement is primarily due to the positive impact of lower interest costs in
first quarter 2003 compared to the same period in the prior year.


 


Liquidity and Capital Resources


 


Funds Generated from Operations


 


Funds generated from operations
of $457 million for first quarter 2003 are consistent with the same period in
the prior year.


 


TransCanada expects that its
ability to generate sufficient 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 is adequate, and remains substantially unchanged since
December 31, 2002.


 

















 


Investing Activities


 


In the three months ended March
31, 2003, capital expenditures, excluding acquisitions, totalled $76 million
(2002 - $117 million) and related primarily to Iroquois’ ongoing Eastchester
Expansion project into New York City, maintenance and capacity capital in
wholly-owned pipelines and ongoing construction of the MacKay River power plant
in Alberta.  Acquisitions for the three
months ended March 31, 2003 totalled $409 million (2002 - nil) and were almost
entirely comprised of the acquisition of a 31.6 per cent interest in Bruce for
$376 million plus closing adjustments.


 


Financing Activities


 


TransCanada used a portion of
its cash resources to fund long-term debt maturities of $9 million.  The company issued notes payable of $209
million in first quarter 2003.


 


Dividends


 


On April 25, 2003,
TransCanada’s Board of Directors declared a quarterly dividend of $0.27 per
share for the quarter ending June 30, 2003 on the outstanding common
shares.  This is the 158th
consecutive quarterly dividend paid by TransCanada on its common shares, and is
payable on July 31, 2003 to shareholders of record at the close of business on
June 30, 2003.  The Board also declared
regular dividends on TransCanada’s preferred shares.


 


Risk Management


 


With respect to continuing
operations, TransCanada’s market, financial and counterparty risks remain
substantially unchanged since December 31, 2002.  The company has retained certain exposures as a result of the
divestiture of the Gas Marketing business. 
For further information on risks, refer to Management’s Discussion and
Analysis in TransCanada’s 2002 Annual Report.


 


The processes within
TransCanada’s risk management function are designed to ensure that risks are
properly identified, quantified, reported and managed.  Risk management strategies, policies and
limits are designed to ensure TransCanada’s risk-taking is consistent with its
business objectives and risk tolerance. 
Risks are managed within limits ultimately established by the Board of
Directors and implemented by senior management, monitored by risk management
personnel and audited by internal audit personnel.


 


TransCanada manages market risk
exposures in accordance with its corporate market risk policy and position
limits.  The company’s primary market
risks result from volatility in commodity prices,


 

















 


interest rates, foreign
currency exchange rates and the failure of counterparties to meet contractual
financial obligations.


 


Controls and Procedures


 


Within 90 days prior to the filing of this quarterly
report, TransCanada’s management evaluated the effectiveness of the design and
operation of the company’s disclosure controls and procedures (disclosure
controls) and internal controls for financial reporting purposes (internal
controls). Based on that evaluation, the Chief Executive Officer and the Chief
Financial Officer have concluded that:


 


•                  TransCanada’s
disclosure controls are effective in ensuring that material information
relating to TransCanada is made known to management on a timely basis, and is
included in this quarterly report; and


 


•                  TransCanada’s
internal controls are effective in providing assurance that the financial
statements for this quarter are fairly presented in accordance with Canadian
generally accepted accounting principles.


 


To the best of these officers’ knowledge and belief,
there have been no significant changes in internal controls or in other factors
that could significantly affect internal controls subsequent to the date on
which such evaluation was completed in connection with this quarterly report.


 


Critical Accounting Policy


 


TransCanada’s critical
accounting policy, which remains unchanged since December 31, 2002, is the use
of regulatory accounting for its regulated operations.  For further information on this critical
accounting policy, refer to Management’s Discussion and Analysis in
TransCanada’s 2002 Annual Report.


 


Critical Accounting Estimates


 


Since a determination of many
assets, liabilities, revenues and expenses is dependent upon future events, the
preparation of the company’s consolidated financial statements requires the use
of estimates and assumptions which have been made using careful judgment.  TransCanada’s critical accounting estimates,
which remain unchanged since December 31, 2002, are depreciation expense and
certain deferred after-tax gains and remaining obligations related to the Gas
Marketing business.  For further information
on these critical accounting estimates, refer to Management’s Discussion and
Analysis in TransCanada’s 2002 Annual Report.


 

















 


Outlook


 


The strong contribution from
Bruce in first quarter 2003 is expected to result in higher Power net earnings
in 2003 than originally anticipated. 
The company does not expect its quarterly net earnings from Bruce to
continue at this rate for the remaining quarters of 2003.  The outlook for the company’s other segments
remains relatively unchanged since December 31, 2002.  For further information on outlook, refer to Management’s
Discussion and Analysis in TransCanada’s 2002 Annual Report.


 


The company’s earnings and cash
flow combined with a strong balance sheet continue to provide the financial
flexibility for TransCanada to make disciplined investments in its core
businesses of Transmission and Power. 
Credit ratings on the company’s senior unsecured debt assigned by
Dominion Bond Rating Service Limited (DBRS), Moody’s Investors Service
(Moody’s) and Standard & Poor’s are currently A, A2 and A-,
respectively.  Standard & Poor’s has
placed its rating of TransCanada’s senior unsecured debt on ‘CreditWatch’ with
negative implications.  DBRS and Moody’s
continue to maintain a ‘stable’ outlook.


 


Other Recent Developments


 


Transmission


 


Wholly-Owned Pipelines


 


Canadian Mainline


 


In February 2003, the NEB
denied the September 2002 request made by TransCanada for a review and variance
of the Fair Return decision. 
TransCanada maintains that the Fair Return decision does not recognize
the long-term business risks of the Canadian Mainline.  On March 21, 2003, TransCanada applied to
the Federal Court of Appeal for leave to appeal the Fair Return decision.  If TransCanada’s leave to appeal application
is successful, the appeal will go forward to the Federal Court of Appeal.  TransCanada is basing its leave to appeal
application on two questions of law.


 


The NEB hearing which commenced
February 26, 2003 to consider the Canadian Mainline 2003 Tolls and Tariff
Application is still in process.  In
this application, TransCanada is requesting approval of a higher composite
depreciation rate, introduction of a new tolling zone in southwestern Ontario,
an increase to the Interruptible Transportation bid floor price and
cost/efficiency incentive mechanisms.


 

















 


Alberta System


 


In February 2003, TransCanada
reached a settlement regarding the 2003 revenue requirement for the Alberta
System.  The settlement is the result of
a consultative process that included producers, industrial users, consumer
groups, marketers and export groups. The one-year settlement establishes the
Alberta System’s fixed revenue requirement for 2003.  This settlement is currently before the EUB for approval together
with the Alberta System 2003 Tariff Settlement which includes proposed
modifications to rate design and an application for a new service. These
settlements are expected to form the basis of the Alberta System tolls for
2003.  TransCanada had originally
applied to the EUB for approval of two new services but, after consulting with
its customers, has withdrawn the application for one of the proposed services.


 


Power


 


In February 2003, TransCanada
completed the acquisition of a 31.6 per cent interest in Bruce for $376 million
plus closing adjustments.  TransCanada
also loaned a one-third share ($75 million) of a $225 million accelerated
deferred rent payment to Ontario Power Generation. Bruce is a tenant under a
lease on the Bruce nuclear power facility in Ontario.  The lease expires in 2018 with an option to extend the lease by
up to 25 years.


 


TransCanada’s newest power
facility, the Bear Creek plant, commenced commercial operations in first
quarter 2003.  This 80 megawatt
cogeneration facility near Grande Prairie, Alberta will sell, under a 25 year
agreement, the majority of its power to Weyerhaeuser at its Grande Prairie Pulp
Mill as well as Weyerhaeuser’s other Alberta facilities.


 


Corporate


 


In first quarter 2003,
TransCanada’s Board of Directors unanimously recommended common shareholders
vote in favour of a proposal to create a new holding company, TransCanada
Corporation (Holdco), to become the parent of TransCanada PipeLines Limited.


 

















 


The proposal will be voted on
April 25, 2003 at TransCanada’s Annual and Special Meeting of
Shareholders.  The company will announce
the results of the vote after the Meeting. 
The financial statements of Holdco will be prepared using the continuity
of interests method. Accordingly, the financial statements of Holdco on the
effective date, on a consolidated basis, will in all material respects be the
same as those of TransCanada immediately prior to the arrangement, except as to
the accounting treatment of the company’s preferred securities and preferred
shares.  For further information on
this, refer to TransCanada’s 2003 Management Proxy Circular.


 


Forward-Looking
Information


 


Certain information in this
quarterly report is forward-looking and is subject to important risks and
uncertainties.  The results or events
predicted in this information may differ from actual results or events.  Factors which could cause actual results or
events to differ materially from current expectations include, among other
things, the ability of TransCanada to successfully implement its strategic
initiatives and whether such strategic initiatives will yield the expected
benefits, the availability and price of energy commodities, regulatory
decisions, competitive factors in the pipeline and power industry sectors, and
the prevailing economic conditions in North America.  For additional information on these and other factors, see the
reports filed by TransCanada with Canadian securities regulators and with the
United States Securities and Exchange Commission.  TransCanada disclaims any intention or obligation to update or
revise any forward-looking statements, whether as a result of new information,
future events or otherwise.