<Page>
EXHIBIT 1
[TRANSCANADA LOGO]
TRANSCANADA CORPORATION
- -------------------------------------------------------------------------------
FOURTH QUARTER 2003
Q u a r t e r l y R e p o r t t o
S h a r e h o l d e r s
CONSOLIDATED RESULTS-AT-A-GLANCE
<Table>
<Caption>
(unaudited) Three months ended December 31 Year ended December 31
(millions of dollars except per share amounts) 2003 2002 2003 2002
- ------------------------------------------------------------------- ----------------- --------------- --------------
NET INCOME
Continuing operations 193 180 801 747
Discontinued operations - - 50 -
---------------- ----------------- --------------- --------------
193 180 851 747
================ ================= =============== ==============
NET INCOME PER SHARE - BASIC
Continuing operations $0.40 $0.37 $1.66 $1.56
Discontinued operations - - 0.10 -
---------------- ----------------- --------------- --------------
$0.40 $0.37 $1.76 $1.56
================ ================= =============== ==============
</Table>
MANAGEMENT'S DISCUSSION AND ANALYSIS
On January 27, 2004, the Board of Directors of TransCanada Corporation
(TransCanada or the company) raised the quarterly dividend on the company's
common shares from $0.27 per share to $0.29 per share, an increase of seven
per cent, for the quarter ending March 31, 2004.
The following discussion and analysis should be read in conjunction with the
accompanying unaudited consolidated financial statements of TransCanada
for the year ended December 31, 2003 and the notes thereto.
RESULTS OF OPERATIONS
CONSOLIDATED
TransCanada's net income from continuing operations (net earnings) and net
income for fourth quarter 2003 were $193 million or $0.40 per share compared to
$180 million or $0.37 per share for fourth quarter 2002. The increase of $13
million or $0.03 per share was primarily due to higher earnings from the Power
business. Higher net earnings from the Power business included $7 million after
tax from TransCanada's investment in Bruce Power L.P. (Bruce Power) and lower
general, administrative and support costs.
TransCanada's net income for the year ended December 31, 2003 was $851 million
or $1.76 per share compared to $747 million or $1.56 per share for the
comparable period in 2002. Included in 2003 was net income from discontinued
operations of $50 million or $0.10 per share reflecting the third quarter 2003
income recognition of a portion of the initially deferred gain of approximately
$100 million after tax relating to the 2001 disposition of the company's Gas
Marketing business.
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FOURTH QUARTER REPORT 2003
TRANSCANADA [2
TransCanada's net earnings for the year ended December 31, 2003 were $801
million or $1.66 per share compared to $747 million or $1.56 per share for the
comparable period in 2002. The increase of $54 million or $0.10 per share in
2003 compared to 2002 was primarily due to higher net earnings of $74 million
from the Power business and lower net expenses in the Corporate segment,
partially offset by lower net earnings from the Gas Transmission business.
Net earnings from the Power business for the year ended December 31, 2003
included $73 million after tax from TransCanada's investment in Bruce Power
which was acquired in February 2003 and a $19 million positive after-tax
earnings impact of a June 2003 settlement with a former counterparty which
defaulted in 2001 under power forward contracts. This amount represents the
value of power forward contracts terminated at the time of the counterparty's
default. These increases were partially offset by reduced operating and other
income from the Northeastern U.S. Operations, combined with higher general,
administrative and support costs.
The $11 million decrease in 2003 net expenses in the Corporate segment was
primarily due to the positive impacts of a weaker U.S. dollar in 2003
compared to 2002.
The lower net earnings of $31 million in the Gas Transmission business for
the year ended December 31, 2003 compared to the prior year were primarily
due to the decline in the Alberta System's 2003 net earnings, reflecting the
one-year fixed revenue requirement settlement reached between TransCanada and
its stakeholders in February 2003. In June 2002, TransCanada received the
National Energy Board (NEB) decision on its Fair Return application (Fair
Return decision) to determine the cost of capital to be included in the
calculation of 2001 and 2002 final tolls on its Canadian Mainline. The
results for the year ended December 31, 2002 included after-tax income of $16
million representing the impact of the Fair Return decision for 2001. The
2003 results for the Gas Transmission segment included TransCanada's $11
million share of future income tax benefits recognized by TransGas de
Occidente (TransGas) while the 2002 results included TransCanada's $7 million
share of a favourable ruling for Great Lakes related to Minnesota use tax
paid in prior years.
SEGMENT RESULTS-AT-A-GLANCE
<Table>
<Caption>
(unaudited) Three months ended December 31 Year ended December 31
(millions of dollars) 2003 2002 2003 2002
- ------------------------------------------------------------------- ----------------- -------------- --------------
Gas Transmission 160 162 622 653
Power 44 30 220 146
Corporate (11) (12) (41) (52)
----------------- ----------------- -------------- --------------
Continuing operations 193 180 801 747
Discontinued operations - - 50 -
----------------- ----------------- -------------- --------------
NET INCOME 193 180 851 747
================= ================= ============== ==============
</Table>
Funds generated from continuing operations of $403 million for fourth quarter
2003 decreased $64 million compared to fourth quarter 2002. Funds generated from
continuing operations of $1,810 million for the year ended December 31, 2003
decreased $17 million compared to last year.
GAS TRANSMISSION
The Gas Transmission business generated net earnings of $160 million and $622
million for the quarter and year ended December 31, 2003, respectively, compared
to $162 million and $653 million for the same periods in 2002.
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FOURTH QUARTER REPORT 2003
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GAS TRANSMISSION RESULTS-AT-A-GLANCE
<Table>
<Caption>
(unaudited) Three months ended December 31 Year ended December 31
(millions of dollars) 2003 2002 2003 2002
- -------------------------------------------------------------------- ----------------- --------------- --------------
WHOLLY-OWNED PIPELINES
Alberta System 54 56 190 214
Canadian Mainline 75 75 290 307
Foothills* 6 4 20 17
BC System 2 2 6 6
---------------- ----------------- --------------- --------------
137 137 506 544
---------------- ----------------- --------------- --------------
OTHER GAS TRANSMISSION
Great Lakes 14 17 52 66
Iroquois 3 3 18 18
TC PipeLines, LP 4 5 15 17
Portland** 4 - 11 2
Ventures LP 3 2 10 7
Trans Quebec & Maritimes 2 2 8 8
CrossAlta 2 4 6 13
TransGas de Occidente 2 1 22 6
Northern Development (2) (1) (4) (6)
General, administrative, support and other (9) (8) (22) (22)
---------------- ----------------- --------------- --------------
23 25 116 109
---------------- ----------------- --------------- --------------
Net earnings 160 162 622 653
================ ================= =============== ==============
</Table>
* The remaining ownership interests in Foothills, previously not held by
TransCanada, were acquired on August 15, 2003.
** TransCanada increased its ownership interest in Portland from 33.3 per cent
to 43.4 per cent on September 29, 2003 and from 43.4 per cent to 61.7 per
cent on December 3, 2003.
WHOLLY-OWNED PIPELINES
The Alberta System's net earnings of $54 million in fourth quarter 2003
decreased $2 million compared to $56 million in the same quarter of 2002. Net
earnings for the year ended December 31, 2003 decreased $24 million compared to
the prior year. This decrease is primarily due to lower earnings from the
one-year 2003 Alberta System Revenue Requirement Settlement (the 2003
Settlement) reached in February 2003. The 2003 Settlement includes a fixed
revenue requirement component, before non-routine adjustments, of $1.277 billion
compared to $1.347 billion in 2002. As discussed in the third quarter 2003
Quarterly Report to Shareholders, the lower negotiated 2003 revenue requirement
was expected to reduce 2003 earnings by approximately $30 million relative to
2002 earnings of $214 million. However, lower financing and operating costs
partially offset the previously anticipated reduction in earnings.
The Canadian Mainline's fourth quarter net earnings of $75 million are
consistent with net earnings in the same quarter of 2002. The
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FOURTH QUARTER REPORT 2003
TRANSCANADA [4
2003 net earnings of $290 million are $17 million lower than 2002 net earnings
due to the impact of the NEB's Fair Return decision in 2002. This decision
included an increase in the deemed common equity ratio from 30 to 33 per cent
effective January 1, 2001 and resulted in additional net earnings of $16 million
for the year ended December 31, 2001, recognized in June 2002. The impact of a
lower average investment base was substantially offset by an increase in the
approved rate of return on common equity from 9.53 per cent in 2002 to 9.79 per
cent in 2003.
In December 2002, the NEB approved TransCanada's application to charge interim
tolls for transportation service, effective January 1, 2003. In August 2003,
subsequent to the NEB's decision on the 2003 Tolls and Tariff Application, it
approved interim tolls that the company charged from September 1, 2003 to
December 31, 2003. The NEB ordered that tolls will remain interim pending a
decision from the Federal Court of Appeal on TransCanada's appeal of the NEB's
decision on TransCanada's Fair Return Review and Variance Application, which is
expected to be heard commencing February 16, 2004.
OPERATING STATISTICS
<Table>
<Caption>
Year ended December 31 Alberta Canadian BC
(unaudited) System* Mainline** Foothills*** System
- --------------------------------------- ------------------- ------------------- ----------------- ------------------
2003 2002 2003 2002 2003 2002 2003 2002
------------------- ------------------- ----------------- ------------------
Average investment base ($ millions) 4,878 5,074 8,565 8,884 739 *** 236 211
Delivery volumes (Bcf)
Total 3,883 4,146 2,628 2,630 1,110 *** 325 371
Average per day 10.6 11.4 7.2 7.2 3.0 *** 0.9 1.0
- ----------------------------------------------------------------------------------------------------------------------
</Table>
* Field receipt volumes for the Alberta System for the year ended December
31, 2003 were 3,892 Bcf (2002 - 4,101 Bcf); average per day was 10.7 Bcf
(2002 - 11.2 Bcf).
** Canadian Mainline deliveries originating at the Alberta border and in
Saskatchewan for the year ended December 31, 2003 were 2,055 Bcf (2002 -
2,221 Bcf); average per day was 5.6 Bcf (2002 - 6.1 Bcf).
*** The remaining interests in Foothills were acquired in August 2003. The
annual 2003 delivery volumes in the table represent 100 per cent of
Foothills.
OTHER GAS TRANSMISSION
TransCanada's proportionate share of net earnings from Other Gas Transmission
was $23 million and $116 million for the quarter and year ended December 31,
2003, respectively.
Net earnings for fourth quarter 2003 were slightly lower than the same
quarter in 2002. Higher contributions from Portland, Ventures LP and TransGas
were more than offset by lower earnings from CrossAlta, higher project
development costs, and the impact of a weaker U.S. dollar.
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FOURTH QUARTER REPORT 2003
TRANSCANADA [5
The 2002 results 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 ruling in 2002, net earnings for 2003 increased $14
million compared to 2002. Earnings from TransGas were $16 million higher as a
result of higher contractual tolls and the recognition of future tax benefits in
2003. TransCanada's share of Portland's net earnings in 2003 has increased $9
million compared to last year primarily due to the impacts of a rate settlement
in early 2003 and TransCanada's increased ownership interest in 2003. These
increases were partially offset by a weaker U.S. dollar and lower earnings from
CrossAlta due to reduced storage margins as a result of unfavourable market
conditions.
On December 3, 2003, TransCanada increased its ownership interest in Portland
Natural Gas Transmission System Partnership (Portland) from 43.4 per cent to
61.7 per cent. The company acquired the additional interest from El Paso
Corporation for US$82 million, including US$50 million of assumed debt.
POWER
POWER RESULTS-AT-A-GLANCE
<Table>
<Caption>
(unaudited) Three months ended December 31 Year ended December 31
(millions of dollars) 2003 2002 2003 2002
- ----------------------------------------------------------------------- --------------- -------------- ---------------
Western operations 31 30 160 131
Northeastern U.S. operations 36 35 127 149
Bruce Power L.P. investment 7 - 99 -
Power LP investment 9 9 35 36
General, administrative and support costs (20) (25) (86) (73)
---------------- --------------- -------------- ---------------
Operating and other income 63 49 335 243
Financial charges (4) (4) (12) (13)
Income taxes (15) (15) (103) (84)
---------------- --------------- -------------- ---------------
Net earnings 44 30 220 146
================ =============== ============== ===============
</Table>
Power's net earnings in fourth quarter 2003 of $44 million increased $14 million
compared to $30 million in fourth quarter 2002. Earnings from the February 2003
acquisition of the 31.6 per cent interest in Bruce Power and reduced general,
administrative and support costs were the primary reasons for the increase.
Net earnings for the year ended December 31, 2003 of $220 million were $74
million higher compared to the prior year. Bruce Power earnings, a second
quarter 2003 settlement in Western Operations for the value of power forward
contracts terminated with a former counterparty and the addition of the ManChief
plant in late 2002 were the primary reasons for the increase. Partially
offsetting
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FOURTH QUARTER REPORT 2003
TRANSCANADA [6
the increase were lower earnings from the Northeastern U.S. Operations and
higher general, administrative and support costs.
WESTERN OPERATIONS
Operating and other income for fourth quarter 2003 in Western Operations of $31
million was comparable to fourth quarter 2002. Higher contributions from the
Sundance power purchase arrangements reflecting lower transmission costs were
partially offset by the unfavourable effects in fourth quarter 2003 of lower
prices achieved on the overall sale of power.
Operating and other income for the year ended December 31, 2003 in Western
Operations of $160 million was $29 million higher compared to the prior year,
mainly due to a $31 million pre-tax ($19 million after tax) positive earnings
impact related to a June 2003 settlement with a former counterparty which
defaulted in 2001 under power forward contracts. A full year of earnings from
the ManChief plant, acquired in late 2002, and higher contributions from the
Sundance power purchase arrangements reflecting lower transmission costs also
contributed to higher operating income. Partially offsetting these increases
were the effects in 2003 of lower prices achieved on the overall sale of power
and the higher cost of natural gas fuel at the carbon black facility.
NORTHEASTERN U.S. OPERATIONS
Operating and other income for fourth quarter 2003 in Northeastern U.S.
Operations of $36 million increased marginally compared to fourth quarter 2002.
Increased water flows through the Curtis Palmer hydroelectric facility and
earnings from the Cobourg temporary generation facility were partially offset by
the unfavourable impact of a weaker U.S. dollar and higher natural gas fuel cost
at Ocean State Power (OSP) resulting from an arbitration process.
Operating and other income for the year ended December 31, 2003 in Northeastern
U.S. Operations of $127 million decreased $22 million compared to 2002 primarily
due to the impact of higher operating costs at OSP and the unfavourable impact
of a weaker U.S. dollar. Partially offsetting these decreases were incremental
earnings from the growth in volumes and margins in the Northeastern U.S. retail
business with large commercial and industrial customers. The long-term gas
supply for OSP is subject to a yearly price renegotiation, taking effect after
the tenth year of the contract. If OSP and the suppliers are unable to reach an
agreement on price in a given year, the matter is settled by arbitration. OSP is
currently in arbitration with its natural gas fuel suppliers regarding changes
to the pricing of its fuel supply.
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FOURTH QUARTER REPORT 2003
TRANSCANADA [7
BRUCE POWER L.P. INVESTMENT
BRUCE POWER RESULTS-AT-A-GLANCE
<Table>
<Caption>
(unaudited) Three months ended Year ended
(millions of dollars) December 31, 2003 December 31, 2003
- ------------------------------------------------------------------------------------------------ ---------------------
BRUCE POWER (100 per cent basis)
Revenues 269 1,208
Operating expenses 254 853
----------------------- ---------------------
Operating income 15 355
Financial charges 20 69
----------------------- ---------------------
(Loss)/Income before income taxes (5) 286
======================= =====================
TransCanada's interest in Bruce Power (loss)/income before income taxes* (1) 65
Adjustments** 8 34
----------------------- ---------------------
TransCanada's income from Bruce Power before income taxes 7 99
======================= =====================
</Table>
* TransCanada acquired its interest in Bruce Power on February 14, 2003.
Bruce Power's 100 per cent income before income taxes from February 14,
2003 to December 31, 2003 was $205 million.
** See Note 8 to the December 31, 2003 financial statements for an explanation
of the amounts included in Adjustments.
Bruce Power contributed $7 million of pre-tax equity income in fourth quarter
2003 compared to $38 million in third quarter 2003. The decrease reflected lower
power output and higher maintenance costs compared to third quarter 2003,
primarily due to a maintenance outage at one of the Bruce B units for the entire
fourth quarter 2003. Overall prices achieved during fourth quarter 2003 were
approximately $45 per megawatt hour (MWh) which is consistent with third quarter
2003. The average price achieved for the year ended December 31, 2003 was
approximately $48 per MWh. Approximately 30 per cent of the output was sold into
Ontario's wholesale spot market in fourth quarter 2003 with the remainder being
sold under longer term contracts. TransCanada's share of power output for fourth
quarter 2003 from four Bruce B units and one Bruce A unit was 1,846 gigawatt
hours (GWh) compared to 2,041 GWh in third quarter 2003. This includes power
output from Bruce A Unit 4 from November 1, 2003 to December 31, 2003 of
approximately 275 GWh. Bruce A Unit 4 began producing electricity to the Ontario
electricity grid on October 7, 2003 and was considered commercially in-service
November 1, 2003. Bruce B Unit 8 was offline for the entire fourth quarter for
maintenance. As well, Bruce B Unit 7 incurred a week long forced outage in the
fourth quarter. The Bruce units ran at an average availability of 73 per cent in
the fourth quarter 2003. The average availability during TransCanada's period of
ownership ending December 31, 2003 was 83 per cent.
Bruce A Unit 3 reconnected to the Ontario electricity grid on January 8, 2004.
Similar to the Bruce A Unit 4 startup process, after performing and evaluating
tests of the shutdown system, Bruce A Unit 3 is expected to reconnect to the
grid and begin
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FOURTH QUARTER REPORT 2003
TRANSCANADA [8
ramping up to full power. Bruce Power's cumulative restart cost for the two
Bruce A units was approximately $720 million. Bruce Power incurred approximately
$300 million on the two unit restart program for the period February 14, 2003 to
December 31, 2003, of which approximately $32 million was incurred in fourth
quarter 2003. TransCanada did not provide any funding to Bruce Power subsequent
to the acquisition of its ownership interest in February 2003. The two Bruce A
units add 1,500 megawatts (MW) of capacity bringing Bruce Power's total capacity
to 4,660 MW.
Bruce Power spent approximately $147 million on capital expenditures at Bruce B
for the period February 14, 2003 to December 31, 2003, the majority of which was
for safety systems and power uprate programs. In 2004, Bruce Power's capital
expenditure program for the two Bruce A and four Bruce B reactors is expected to
total approximately $400 million.
Equity income from Bruce Power is directly impacted by fluctuations in wholesale
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 Power has entered into fixed price sales
contracts for approximately 1,560 MW of output for 2004. The average
availability in 2004 for the six Bruce units is expected to be 80 per cent
compared to 85 per cent for the year ended December 31, 2003. This decrease
reflects planned maintenance outages for two Bruce B and two Bruce A units and a
test of the Bruce B vacuum building expected in the fall, which will require all
four Bruce B units to be taken offline for approximately one month. There is a
planned maintenance outage at one of the Bruce A units for approximately one
month, towards the end of the first quarter 2004.
POWER LP INVESTMENT
Operating and other income of $9 million and $35 million for the three and
twelve months ended December 31, 2003, was consistent with the same periods in
2002.
GENERAL, ADMINISTRATIVE AND SUPPORT COSTS
General, administrative and support costs for fourth quarter 2003 of $20 million
were $5 million lower compared to fourth quarter 2002. The decrease is primarily
due to lower business development costs in fourth quarter 2003.
General, administrative and support costs for the year ended December 31, 2003
increased $13 million compared to the prior year, mainly reflecting higher
support costs as part of the company's continued investment in Power.
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FOURTH QUARTER REPORT 2003
TRANSCANADA [9
POWER SALES VOLUMES
<Table>
<Caption>
(unaudited) Three months ended December 31 Year ended December 31
(GWh) 2003 2002 2003 2002
- ------------------------------------------------ --------------------------------- -------------------------
Western operations* 2,972 2,864 12,296 12,065
Northeastern U.S. operations 1,794 1,513 6,906 5,630
Bruce Power L.P. investment** 1,846 n/a 6,655 n/a
Power LP investment 549 637 2,153 2,416
---------------- ---------------- ---------- ------------
Total 7,161 5,014 28,010 20,111
=================================================================================== =========================
</Table>
* Sales volumes include TransCanada's share of the Sundance B power purchase
arrangement (50 per cent).
** Acquired in February 2003. Sales volumes reflect TransCanada's share of
Bruce Power output (31.6 per cent) for the period February 14, 2003 to
December 31, 2003.
<Table>
<Caption>
WEIGHTED AVERAGE PLANT AVAILABILITY* Three months ended December 31 Year ended December 31
(unaudited) 2003 2002 2003 2002
- -------------------------------------------- ---------------------------------- ----------------------------
Western operations 94% 99% 93% 99%
Northeastern U.S. operations 99% 82% 94% 95%
Bruce Power L.P. investment** 73% n/a 83% n/a
Power LP investment 98% 98% 96% 94%
All plants 89% 92% 90% 96%
=============================================================================== ============================
</Table>
* Plant availability is reduced by planned and unplanned outages.
** Acquired in February 2003. TransCanada's availability reflects the period
February 14, 2003 to December 31, 2003.
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FOURTH QUARTER REPORT 2003
TRANSCANADA [10
CORPORATE
Net expenses were $11 million and $12 million for the three months ended
December 31, 2003 and 2002, respectively. Net expenses were $41 million for the
year ended December 31, 2003 compared to $52 million for 2002. The $11 million
decrease in net expenses for 2003 is primarily due to the positive impacts of a
weaker U.S. dollar compared to the prior year. These positive impacts
substantially offset the negative impacts of a weaker U.S. dollar reflected
in the other segments.
DISCONTINUED OPERATIONS
The company's exit from the Gas Marketing business was substantially completed
by December 31, 2001. In third quarter 2003, $50 million of the original
approximately $100 million after-tax deferred gain related to Gas Marketing was
recognized in income. At December 31, 2003, TransCanada reviewed the provision
for loss on discontinued operations and the deferred gain and concluded that the
remaining provision was adequate and the deferral of the remaining approximately
$50 million of deferred after-tax gain related to the Gas Marketing business was
appropriate.
TransCanada's investments in Gasoducto del Pacifico, INNERGY Holdings S.A.
and P.T. Paiton Energy Company, which were approved for disposal under a plan
in December 1999, will be accounted for as part of continuing operations as
of December 31, 2003 due to the length of time it has taken the company to
dispose of these assets. It is the intention of the company to continue with
the plan to dispose of these investments.
LIQUIDITY AND CAPITAL RESOURCES
FUNDS GENERATED FROM OPERATIONS
Funds generated from continuing operations were $403 million and $1,810 million
for the three and twelve months ended December 31, 2003, respectively, compared
with $467 million and $1,827 million for the same periods in 2002.
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 and year ended December 31, 2003, capital expenditures,
excluding acquisitions, totalled $127 million (2002 - $202 million) and $391
million (2002 - $599 million), respectively, and related primarily to Iroquois'
ongoing Eastchester Expansion project into New York City, maintenance and
capacity capital in wholly-owned pipelines and construction of the MacKay River
power plant in Alberta.
Acquisitions for the year ended December 31, 2003 totalled $570 million (2002 -
$228 million) and were primarily comprised of:
o in fourth quarter 2003, the increase in interest in Portland from 43.4 per
cent to 61.7 per cent for approximately US$32 million,
o in third quarter 2003, the increase in interest in Portland from 33.3 per
cent to 43.4 per cent for approximately US$19 million,
o in third quarter 2003, the acquisition of the remaining interests in
Foothills for approximately $105 million, and
o in first quarter 2003, the acquisition of a 31.6 per cent interest in Bruce
Power for approximately $409 million including closing adjustments.
In addition, TransCanada assumed $154 million and US$78 million of debt on the
Foothills and Portland acquisitions, respectively.
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FOURTH QUARTER REPORT 2003
TRANSCANADA [11
FINANCING ACTIVITIES
TransCanada used a portion of its cash resources to retire long-term debt of
$358 million and $744 million in the quarter and year ended December 31,
2003, respectively. In November 2003, the company issued $450 million of ten
year notes bearing interest at 5.65 per cent and in June 2003, the company
issued US$350 million of ten year notes bearing interest at 4.00 per cent.
For the year ended December 31, 2003, outstanding notes payable decreased by
$62 million, while cash and short-term investments increased by $126 million.
In July 2003, TransCanada redeemed all of its outstanding US$160 million, 8.75
per cent Junior Subordinated Debentures, also known as Cumulative Trust
Originated Preferred Securities. Holders of these debentures received US$25.0122
per US$25.00 of the principal amount, which included accrued and unpaid interest
to the redemption date.
DIVIDENDS
On January 27, 2004, TransCanada's Board of Directors declared a quarterly
dividend of $0.29 per share for the quarter ending March 31, 2004 on the
outstanding common shares. This is the 161st consecutive quarterly dividend paid
by TransCanada and its subsidiary on its common shares, and is payable on April
30, 2004 to shareholders of record at the close of business on March 31, 2004.
RISK MANAGEMENT
With respect to continuing operations, TransCanada's market, financial and
counterparty risks remain substantially unchanged since December 31, 2002. See
explanation for discontinued operations' risk management activity under Results
of Operations - Discontinued Operations. For further information on risks, refer
to Management's Discussion and Analysis in TransCanada PipeLines Limited'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 and financial risk exposures in accordance with its
corporate market risk policy and position
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FOURTH QUARTER REPORT 2003
TRANSCANADA [12
limits. The company's primary market risks result from volatility in commodity
prices, interest rates and foreign currency exchange rates. TransCanada's
counterparty risk exposure results from the failure of a counterparty to meet
its contractual financial obligations, and is managed in accordance with its
corporate counterparty risk policy.
CONTROLS AND PROCEDURES
As of the end of the period covered by this quarterly report, TransCanada's
management, together with TransCanada's President and Chief Executive Officer
and Chief Financial Officer, evaluated the effectiveness of the design and
operation of the company's disclosure controls and procedures. Based on this
evaluation, the President and Chief Executive Officer and the Chief Financial
Officer of TransCanada have concluded that the disclosure controls and
procedures are effective.
There were no changes in TransCanada's internal control over financial reporting
during the most recent fiscal quarter that have materially affected or are
reasonably likely to materially affect TransCanada's internal control over
financial reporting.
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 PipeLines Limited'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
from December 31, 2002 continue to be 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 Results
of Operations - Discontinued Operations and to Management's Discussion and
Analysis in TransCanada PipeLines Limited's 2002 Annual Report.
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FOURTH QUARTER REPORT 2003
TRANSCANADA [13
OUTLOOK
In 2004, the outcome of regulatory proceedings could have a significant impact
on the expected results for the Alberta System and Canadian Mainline. Plant
availability and fluctuating power prices could have a significant impact on
Power results. Excluding these impacts as well as the settlement with a former
counterparty in 2003 and the recognition of the TransGas future tax benefits in
2003, the outlook for the company is relatively unchanged since December 31,
2002. For further information on outlook, refer to Management's Discussion and
Analysis in TransCanada PipeLines Limited's 2002 Annual Report.
The company's net 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 Gas Transmission and Power.
The strengthening of the Canadian dollar compared to the U.S. dollar in 2003 has
not significantly impacted TransCanada's consolidated financial results in 2003
and is not expected to have a significant impact in 2004. Credit ratings on
TransCanada PipeLines Limited'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. DBRS and Moody's both
maintain a `stable' outlook on their ratings and Standard & Poor's maintains a
`negative' outlook on its rating.
OTHER RECENT DEVELOPMENTS
GAS TRANSMISSION
WHOLLY-OWNED PIPELINES
ALBERTA SYSTEM
In July 2003, TransCanada, along with other utilities, filed evidence in the
Generic Cost of Capital (GCOC) Proceeding with the Alberta Energy and Utilities
Board (EUB). TransCanada has requested a return on equity of 11 per cent based
on a deemed common equity of 40 per cent in its GCOC Application. The EUB
expects to adopt a standardized approach to determining the rate of return
and capital structure for all utilities under its jurisdiction at the
conclusion of this proceeding. The oral portion of the hearing was completed
on January 16, 2004 with written arguments to follow.
In September 2003, TransCanada filed Phase I of the 2004 General Rate
Application (GRA) with the EUB, consisting of evidence in support of the applied
for rate base and revenue requirement. The company applied for a composite
depreciation rate of 4.13 per cent compared to the current depreciation rate of
4.00 per cent.
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Phase II of the application, dealing primarily with rate design and services,
was filed in December 2003. EUB hearings to consider the 2004 GRA Phase I and
Phase II applications are scheduled to commence, in Calgary, on April 1, 2004
and June 1, 2004, respectively.
In December 2003, the EUB approved TransCanada's application to charge interim
tolls for transportation service, effective January 1, 2004. Final tolls for
2004 will be determined based on the EUB decisions for the GCOC hearing and both
phases of the GRA.
On December 1 and 2, 2003, two natural gas pipeline failures occurred on the
Alberta System. Deliveries of gas to local communities were not impacted as a
result of either incident. Following preliminary investigations into the causes
of the two pipeline ruptures, TransCanada found evidence of external corrosion
on the pipeline. No one was injured and the impacted segment of the Alberta
System was repaired within days. The incidents are not expected to have an
impact on the company's earnings.
CANADIAN MAINLINE
In July 2003, TransCanada filed a notice of appeal with the Federal Court of
Appeal and served notice of appeal on parties to the NEB proceeding on
TransCanada's Fair Return Review and Variance Application. In September 2003,
TransCanada filed a Memorandum of Fact and Law with the Federal Court of Appeal,
and in October 2003 all interested parties filed their memoranda in response to
TransCanada's filing. The case will be heard in an oral hearing scheduled to
commence February 16, 2004.
In December 2003, the NEB approved interim tolls effective January 1, 2004 for
the Canadian Mainline. The 2004 Tolls and Tariff Application for the Canadian
Mainline was filed on January 26, 2004 and includes a request for an 11 per cent
return on a 40 per cent deemed common equity component.
OTHER GAS TRANSMISSION
IROQUOIS
Iroquois continues to make progress on the construction of the Eastchester
expansion project and is expected to place the expansion facilities into service
in February 2004.
NORTHERN DEVELOPMENT
For the Mackenzie Gas Pipeline Project, TransCanada has agreed to finance the
Aboriginal PipeLine Group (APG) for its one-third
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TRANSCANADA [15
share of project definition phase costs which is estimated to be approximately
$90 million over three years. In the year ended December 31, 2003, TransCanada
funded $34 million which is included in Other Assets. Regulatory applications
for the Mackenzie Gas Pipeline Project have been delayed and are expected to
be filed mid-2004.
LIQUEFIED NATURAL GAS
In September 2003, TransCanada and ConocoPhillips Company announced the
Fairwinds partnership to jointly evaluate a site in Harpswell, Maine for the
development of a liquefied natural gas (LNG) regasification facility. The
residents of the Town of Harpswell are expected to vote in first quarter 2004 on
leasing a town-owned site for the facility. If leasing of the site is approved
and necessary regulatory approvals are subsequently received, construction of
the LNG facility could begin in 2006 with the facility becoming operational in
2009. Natural gas from the LNG facility would be delivered by pipeline to
markets in the northeast U.S.
POWER
In August 2003, TransCanada successfully commenced operations under a
fee-for-service power purchase arrangement with the Ontario government through
the Ontario Electricity Financial Corporation (OEFC). Under the agreement,
TransCanada supplied 110 MW of capacity from a temporary facility adjacent to
the Canadian Mainline near Cobourg, Ontario up to December 31, 2003.
Demobilization of the temporary facility began in early January 2004 and is
expected to be complete by late spring.
On October 24, 2003, TransCanada and Grandview Cogeneration Corporation, an
affiliate of Irving Oil Limited (Irving), announced an agreement to build a 90
MW natural gas-fired cogeneration power plant in Saint John, New Brunswick. This
cogeneration facility will be developed and owned by TransCanada. Under a 20
year tolling arrangement, Irving will provide fuel for the plant and contract
for 100 per cent of the plant's heat and electricity output. Construction of the
plant commenced in December 2003 and is expected to be in-service in December
2004.
Construction of MacKay River, a 165 MW facility near Fort McMurray, Alberta, was
completed in fourth quarter 2003 and commissioning is underway.
The fourth quarter scheduled maintenance outage of Bruce B Unit 8 was originally
planned to take approximately eight weeks, but was extended after inspections
identified some erosion on support
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FOURTH QUARTER REPORT 2003
TRANSCANADA [16
plates in three of the unit's eight steam generators. Repairs have been
completed and approved by the Canadian Nuclear Safety Commission and the unit
is in the process of being returned to service.
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.