EX-13.1 2 a2145425zex-13_1.htm EXHIBIT 13.1
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Exhibit 13.1

MANAGEMENT'S DISCUSSION AND ANALYSIS

Management's discussion and analysis (MD&A) dated October 26, 2004 should be read in conjunction with the accompanying unaudited consolidated financial statements of TransCanada Corporation (TransCanada or the company) for the nine months ended September 30, 2004 and should also be read in conjunction with the audited consolidated financial statements and MD&A contained in TransCanada's 2003 Annual Report for the year ended December 31, 2003. Additional information relating to TransCanada, including the company's Annual Information Form and continuous disclosure documents, is available on SEDAR at www.sedar.com under TransCanada Corporation.

Consolidated Results-at-a-Glance

		Three months ended September 30				Nine months ended September 30
		2004		2003		2004		2003
		(unaudited) (millions of dollars except per share amounts)
Net Income
	Continuing operations		193		198		795		608
	Discontinued operations		52		50		52		50

			245		248		847		658

Net Income Per Share — Basic
	Continuing operations	$	0.40	$	0.41	$	1.64	$	1.26
	Discontinued operations		0.11		0.10		0.11		0.10

		$	0.51	$	0.51	$	1.75	$	1.36

Results of Operations

Consolidated

TransCanada's net income for third quarter 2004 was $245 million or $0.51 per share compared to $248 million or $0.51 per share for the same period in 2003. This includes net income from discontinued operations of $52 million or $0.11 per share in third quarter 2004 and $50 million or $0.10 per share in third quarter 2003 reflecting income recognized on releases of the initially deferred gains relating to the disposition in 2001 of the company's Gas Marketing business.

Net income from continuing operations (net earnings) for third quarter 2004 of $193 million or $0.40 per share decreased by $5 million or $0.01 per share compared to $198 million or $0.41 per share for third quarter 2003. This decrease was primarily due to lower net earnings from the Gas Transmission business, partially offset by lower net expenses in the Corporate segment.

Lower net earnings of $26 million in the Gas Transmission business for third quarter 2004 compared to the same period in the prior year were primarily due to a decline in the Alberta System's net earnings which reflect the impact of the Generic Cost of Capital (GCOC) decision in July 2004 and the year-to-date impact of the August 2004 decision from the Alberta Energy and Utilities Board (EUB) on Phase I of the Alberta System 2004 General Rate Application (GRA). The GRA decision disallowed the recovery of a significant amount of costs which reduced the Alberta System's revenue requirement, including the impact of reductions to forecasted rate base in 2004. Third quarter 2003 net earnings included TransCanada's $11 million share of future income tax benefits recognized by TransGas de Occidente (TransGas). The decrease in net expenses in the Corporate segment was mainly due to a $12 million after-tax adjustment as a result of the release in third quarter 2004 of previously established restructuring provisions and the recognition of an $8 million income tax benefit related to additional non-capital loss carryforwards utilized. Earnings in the Power business for third quarter 2004 were comparable to the same period in the prior year.

TransCanada's net income for the nine months ended September 30, 2004 was $847 million or $1.75 per share including net income from discontinued operations of $52 million or $0.11 per share, compared to $658 million or $1.36 per share for the comparable period in 2003 including net income from discontinued operations of $50 million or $0.10 per share.

TransCanada's net earnings for the nine months ended September 30, 2004 were $795 million or $1.64 per share compared to $608 million or $1.26 per share for the comparable period in 2003. The increase of $187 million or $0.38 per share in the first nine months of 2004 compared to the same period in 2003 was due to significantly higher net earnings from the Power business. In addition, lower net earnings from the Gas Transmission business were primarily offset by lower net expenses in the Corporate segment.

The increased Power earnings are primarily due to the second quarter 2004 gain of $15 million after tax ($25 million pre tax) or $0.03 per share on the sale of the ManChief and Curtis Palmer assets to TransCanada Power, L.P. (Power LP) and the recognition of $172 million or $0.36 per share of dilution and other gains resulting from a reduction in TransCanada's ownership interest in Power LP and the removal of Power LP's obligation, in 2017, to redeem units not owned by TransCanada. TransCanada was required to fund this redemption, therefore the removal of Power LP's obligation eliminates this requirement.

Excluding the above-mentioned $187 million of combined gains included in net earnings related to Power LP and the recognition in second quarter 2003 of a $19 million after-tax settlement with a former counterparty, Power's net earnings for the nine months ended September 30, 2004 were $21 million higher than the same period in 2003. Higher net earnings from TransCanada's investment in Bruce Power L.P. (Bruce Power) were partially offset by lower contributions from Eastern Operations.

The lower net earnings of $33 million in the Gas Transmission business for the nine months ended September 30, 2004 compared to the same period in 2003 were primarily due to lower earnings from the Canadian Mainline and Alberta System, partially offset by a $7 million gain on sale of the company's equity interest in the Millennium Pipeline project (Millennium) in second quarter 2004 and higher earnings from certain Other Gas Transmission investments. The 2003 net earnings included $11 million of future income tax benefits recognized by TransGas.

The decrease in net expenses of $31 million in the Corporate segment for the nine months ended September 30, 2004 was primarily due to the release in third quarter of previously established restructuring provisions and income tax related items, including refunds in first quarter 2004 and the recognition of the benefit of additional loss carryforwards utilized. These positive variances were partially offset by additional interest costs due to the issuance of new debt in late 2003 and early 2004.

Segment Results-at-a-Glance

		Three months ended September 30			Nine months ended September 30
		2004	2003		2004	2003
		(unaudited) (millions of dollars)
Gas Transmission		134	160		429	462
Power		51	50		365	176
Corporate		8	(12	)	1	(30	)

	Continuing operations	193	198		795	608
	Discontinued operations	52	50		52	50

Net Income		245	248		847	658

Funds generated from continuing operations of $394 million for third quarter 2004 decreased $122 million compared to third quarter 2003. Funds generated from operations of $1,207 million for the nine months ended September 30, 2004 decreased $200 million compared to the same period in 2003. These decreases mainly result from higher current income tax expense in 2004 compared to 2003.

Gas Transmission

The Gas Transmission business generated net earnings of $134 million and $429 million for the three and nine months ended September 30, 2004, respectively, compared to $160 million and $462 million for the comparable periods in 2003.

Gas Transmission Results-at-a-Glance

	Three months ended September 30				Nine months ended September 30
	2004		2003		2004		2003
	(unaudited) (millions of dollars)
Wholly-Owned Pipelines
Alberta System	31		50		110		136
Canadian Mainline	71		73		201		215
Foothills*	6		5		17		14
BC System	2		—		5		4

	110		128		333		369

Other Gas Transmission
Great Lakes	12		10		43		38
Iroquois	3		4		14		15
TC PipeLines, LP	4		4		13		11
Portland**	—		—		6		7
Ventures LP	3		3		10		7
Trans Québec & Maritimes	2		2		6		6
CrossAlta	4		—		6		4
TransGas de Occidente	3		13		9		20
Northern Development	(1	)	(1	)	(3	)	(2	)
General, administrative, support costs and other	(6	)	(3	)	(8	)	(13	)

	24		32		96		93

Net earnings	134		160		429		462

*: The remaining ownership interests in Foothills, previously not held by TransCanada, were acquired on August 15, 2003.
**: TransCanada increased its ownership interest in Portland to 43.4 per cent from 33.3 per cent on September 29, 2003 and to 61.7 per cent from 43.4 per cent on December 3, 2003.

Wholly-Owned Pipelines

The Alberta System's net earnings of $31 million in third quarter 2004 decreased $19 million compared to $50 million in the same quarter of 2003. Net earnings for the nine months ended September 30, 2004 decreased $26 million compared to the same period in 2003. These decreases were primarily due to the year-to-date impacts of the EUB decisions on Phase I of the 2004 GRA in August 2004 and on the GCOC in July 2004. The GRA decision disallowed approximately $24 million pre tax of operating costs associated with the operation of the pipeline and, as a result, adjustments were made to third quarter 2004 earnings to reflect the year-to-date impacts of this decision. The GCOC decision resulted in a lower return on deemed common equity in 2004 compared to earnings implicit in the 2003 negotiated settlement which included a fixed revenue requirement component, before non-routine adjustments, of $1.277 billion. Earnings in 2004 reflect a return of 9.60 per cent on deemed common equity of 35 per cent as approved in the GCOC decision.

The Canadian Mainline's net earnings decreased $2 million and $14 million for the three and nine months ended September 30, 2004, respectively, when compared to the corresponding periods in 2003. The decrease in net earnings was primarily due to a lower rate of return on common equity of 9.56 per cent in 2004 compared to 9.79 per cent in 2003, and a lower average investment base.

Foothills' net earnings of $17 million for the nine months ended September 30, 2004 were $3 million higher than the same period in 2003 reflecting TransCanada's acquisition in August 2003 of the remaining ownership interests in Foothills not held previously.

Operating Statistics

		Nine months ended September 30
		Alberta System*		Canadian Mainline**		Foothills***		BC System
		2004	2003	2004	2003	2004	2003	2004	2003
		(unaudited)
Average investment base ($ millions)		4,642	4,909	8,233	8,601	718	742	229	237
Delivery volumes (Bcf)
	Total	2,872	2,893	1,947	1,990	844	813	255	227
	Average per day	10.5	10.6	7.1	7.3	3.1	3.0	0.9	0.8

*: Field receipt volumes for the Alberta System for the nine months ended September 30, 2004 were 2,959 Bcf (2003 — 2,926 Bcf); average per day was 10.8 Bcf (2003 — 10.7 Bcf).
**: Canadian Mainline deliveries originating at the Alberta border and in Saskatchewan for the nine months ended September 30, 2004 were 1,503 Bcf (2003 — 1,572 Bcf); average per day was 5.5 Bcf (2003 — 5.8 Bcf).
***: The remaining interests in Foothills were acquired in August 2003. The delivery volumes in the table represent 100 per cent of Foothills.

Other Gas Transmission

TransCanada's proportionate share of net earnings from its Other Gas Transmission businesses was $24 million for the three months ended September 30, 2004 compared to $32 million for the same period in 2003. The 2003 results included TransCanada's $11 million share of future income tax benefits recognized by TransGas. Excluding this adjustment, net earnings for the quarter increased $3 million compared to the same period in 2003. The increase was due to higher earnings from Great Lakes as a result of successful marketing of short-term services and higher earnings from CrossAlta as a result of favourable storage market conditions, partially offset by higher general, administrative, support costs and other.

Net earnings for the nine months ended September 30, 2004 were $96 million compared to $93 million for the same period in 2003. Excluding the $7 million gain on sale of Millennium recognized in 2004 and the $11 million of future income tax benefits recognized by TransGas in 2003, year-to-date earnings were $7 million higher compared to the same period in 2003. The increase was due to higher earnings from Great Lakes as a result of successful marketing of short-term services and increased earnings from Ventures LP, TC PipeLines LP and CrossAlta. These increases were partially offset by the impact of a weaker U.S. dollar and higher general, administrative, support costs and other.

Power

Power Results-at-a-Glance

	Three months ended September 30				Nine months ended September 30
	2004		2003		2004		2003
	(unaudited) (millions of dollars)
Western operations	43		26		113		129
Eastern operations	21		30		77		91
Bruce Power investment	29		38		125		92
Power LP investment	6		8		22		26
General, administrative, support costs and other	(21	)	(23	)	(70	)	(66	)

Operating and other income	78		79		267		272
Financial charges	(4	)	(2	)	(9	)	(8	)
Income taxes	(23	)	(27	)	(80	)	(88	)

	51		50		178		176
Gains related to Power LP (after tax)	—		—		187		—

Net earnings	51		50		365		176

Power's net earnings in third quarter 2004 of $51 million increased $1 million compared to $50 million in third quarter 2003. Higher earnings from Western Operations were more than offset by lower contributions from Bruce Power and Eastern Operations.

Net earnings for the nine months ended September 30, 2004 of $365 million increased $189 million compared to $176 million in the same period in 2003 primarily due to the $187 million of gains related to Power LP recorded in second quarter 2004. During second quarter 2004, TransCanada completed the sale of the ManChief and Curtis Palmer power facilities to Power LP for US$402.6 million resulting in an after-tax gain on sale of $15 million (pre-tax gain of $25 million). At a meeting in April 2004, Power LP unitholders approved these acquisitions and the removal of Power LP's obligation to redeem all units not owned by TransCanada in 2017. TransCanada was required to fund this redemption, thus the removal of Power LP's obligation eliminates this requirement. In addition, in second quarter 2004, Power LP issued 8.1 million subscription receipts which were subsequently converted into partnership units and TransCanada contributed $20 million of the net proceeds of $286.8 million that Power LP realized from this issue. The net impact of this issue reduced TransCanada's ownership interest in Power LP from 35.6 per cent to 30.6 per cent. As a result of these events, TransCanada recognized dilution and other gains of $172 million in second quarter 2004, $132 million of which were previously deferred and were being amortized into income to 2017. Dilution gains arose when TransCanada's ownership interest in Power LP was decreased as a result of the Power LP issuing new partnership units at a market price in excess of TransCanada's per unit carrying value of the investment.

Excluding the $187 million of Power LP-related gains, Power's net earnings for the nine months ended September 30, 2004 of $178 million increased $2 million compared to $176 million in the same period in 2003. Earnings from Bruce Power of $125 million increased by $33 million compared to $92 million for the same period in 2003 and were mostly offset by lower contributions from other Power operations.

Western Operations

Operating and other income in third quarter 2004 from Western Operations of $43 million was $17 million higher compared to $26 million earned in the same period in 2003. The increase was mainly due to earnings from the newly constructed MacKay River cogeneration plant, fees earned as a result of Power LP's third quarter 2004 acquisition of hydroelectric facilities in British Columbia and higher net margins achieved on the overall portfolio management. A higher than expected quarterly contribution from the MacKay River plant arose due to the recognition of revenues which were deferred in the first six months of 2004.

Operating and other income for the nine months ended September 30, 2004 of $113 million was $16 million lower compared to the same period in 2003. The decrease was mainly due to recognition in second quarter 2003 of a $31 million ($19 million after-tax) settlement with a former counterparty which defaulted in 2001 under power forward contracts, as well as reduced ManChief income following the sale of the plant to Power LP in April 2004. Partially offsetting these decreases were contributions from the MacKay River plant, fees earned with respect to Power LP's asset acquisitions in 2004 and the impact of higher net margins achieved on the overall portfolio in second and third quarter 2004.

Eastern Operations

Operating and other income in third quarter 2004 from Eastern Operations of $21 million was $9 million lower compared to $30 million earned in the same period in 2003. The decrease was primarily due to a reduction in income from the sale of the Curtis Palmer hydroelectric facilities to Power LP in April 2004, the unfavourable impact of higher natural gas fuel costs at Ocean State Power (OSP) and a weaker U.S. dollar in 2004 compared to 2003. At the end of August 2004, OSP concluded its third arbitration process with respect to its cost of fuel gas and, as in previous decisions received in December 2002 and March 2003, the decision substantially increased OSP's cost of fuel gas. This most recent arbitration decision, effective September 1, 2004, established a pricing mechanism for fuel gas which results in prices in excess of market price and, as a result, impedes OSP's ability to economically and competitively produce power. The potential impacts of this negative decision and related courses of action are under review by management. OSP has commenced the process for the next arbitration which would be expected to be completed in mid-2005.

Operating and other income for the nine months ended September 30, 2004 was $77 million or $14 million lower compared to the $91 million earned in the same period in 2003. This decrease was mainly due to a reduction in income from 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.

Bruce Power Investment

Bruce Power Results-at-a-Glance

		Three months ended September 30				Nine months ended September 30
		2004		2003		2004		2003
		(unaudited) (millions of dollars)
Bruce Power (100 per cent basis)
	Revenues	395		297		1,228		939
	Operating expenses	(297	)	(196	)	(833	)	(599	)

	Operating income	98		101		395		340
	Financial charges	(17	)	(17	)	(50	)	(49	)

	Income before income taxes	81		84		345		291

TransCanada's interest in Bruce Power income before income taxes*		26		27		109		66
Adjustments		3		11		16		26

TransCanada's income from Bruce Power before income taxes		29		38		125		92

*: 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 September 30, 2003 was $210 million.

Bruce Power contributed $29 million of pre-tax equity income in third quarter 2004 compared to $38 million in third quarter 2003. TransCanada's share of power output for third quarter 2004 was 2,765 gigawatt hours (GWh) compared to 2,041 GWh in third quarter 2003. This increase primarily reflects higher output in 2004 as a result of the restart of Bruce A Units 3 and 4 which expanded Bruce Power's capacity by approximately 1,500 megawatts (MW) compared to third quarter 2003 and correspondingly increased Bruce Power's operating expenses. The four Bruce B units were offline during a vacuum building inspection which commenced on September 18, 2004 and partially offset the increased output from Units 3 and 4. Overall prices achieved during third quarter 2004 were approximately $45 per megawatt hour (MWh), the same as in third quarter 2003. Approximately 55 per cent of the output was sold into Ontario's wholesale spot market in third quarter 2004 with the remainder being sold under longer term contracts. On a per unit basis, the Bruce operating cost increased to $34 per MWh in third quarter 2004 from $30 per MWh in third quarter 2003. This increase in operating costs on a per unit basis was primarily due to higher costs as a result of more planned maintenance outages in third quarter 2004 as compared to 2003 and lost generation as a result of the Bruce B vacuum building outage.

Adjustments to TransCanada's interest in Bruce Power income before income taxes for the three and nine months ended September 30, 2004 were lower than the comparable periods in 2003 primarily due to no interest being capitalized upon the return to service of the Bruce A units.

Pre-tax equity income for the nine months ended September 30, 2004 was $125 million compared to $92 million for the same period in 2003. This increase was primarily due to higher output in 2004 as a result of the return to service of the two Bruce A units as well as a full nine months of earnings in 2004 compared to earnings from February 14 to September 30 in 2003, reflecting TransCanada's period of ownership in 2003. Operating costs for the nine months ended September 30, 2004 were $32 per MWh compared to $33 per MWh for the period February 14 to September 30, 2003. Average realized prices in the nine months ended September 30, 2004 were $46 per MWh compared to $49 per MWh during TransCanada's period of ownership ended September 30, 2003.

The Bruce units ran at an average availability of 85 per cent in third quarter 2004, compared to an average availability during third quarter 2003 of 94 per cent reflecting higher planned maintenance outage hours in third quarter 2004. Availability for the nine months ended September 30, 2004 was 85 per cent compared to 88 per cent for the period from February 14 to September 30, 2003. A scheduled maintenance outage on Unit 6 began on September 11, 2004 and the unit is expected to be returned to service in December 2004. The planned vacuum building inspection that began for all of the Bruce B units on September 18, 2004 was completed ahead of schedule and Units 8 and 7 were returned to service on October 11 and 13, 2004, respectively. Unit 5 will remain offline for additional maintenance as a result of tests performed during the vacuum building inspection and is expected back in service by mid-November 2004.

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. Approximately 40 per cent of planned output for the remainder of 2004 is under fixed price sales contracts.

Power LP Investment

Operating and other income of $6 million and $22 million for the three and nine months ended September 30, 2004 was $2 million and $4 million lower, respectively, compared to the same periods in 2003. The decrease was primarily due to TransCanada's reduced ownership interest in Power LP in 2004 (30.6 per cent compared to 35.6 per cent) and the recognition in second quarter 2004 of all previously deferred gains resulting from the removal of the Power LP redemption obligation. Prior to the removal of the redemption obligation, Power was recognizing into income the amortization of these deferred gains over a period through to 2017. Additional earnings from Power LP's second quarter acquisition of the Curtis Palmer and ManChief facilities partially offset these decreases.

General, Administrative, Support Costs and Other

General, administrative, support costs and other decreased $2 million in third quarter 2004 compared to third quarter 2003 primarily due to foreign exchange unrealized gains recognized by Power LP on its U.S. dollar denominated debt, partially offset by higher support costs. General, administrative, support costs and other for the nine months ended September 30, 2004 of $70 million were $4 million higher compared to the same period in 2003 primarily due to higher support costs resulting from the company's increased investment in the Power business. Partially offsetting these higher support costs were the positive impact of the recognition of Power LP's foreign exchange unrealized gains and lower business development expenditures.

Power Sales Volumes

	Three months ended September 30		Nine months ended September 30
	2004	2003	2004	2003
	(unaudited) (GWh)
Western operations⁽²⁾	2,754	3,070	8,559	9,310
Eastern operations⁽²⁾	1,631	1,717	4,716	5,126
Bruce Power investment⁽¹⁾	2,765	2,041	8,257	4,809
Power LP investment⁽²⁾	642	582	1,750	1,604

Total	7,792	7,410	23,282	20,849

(1): Acquired on February 14, 2003. Sales volumes reflect TransCanada's 31.6 per cent share of Bruce Power output from the date of acquisition.
(2): ManChief and Curtis Palmer volumes are included in Power LP investment effective April 30, 2004.

Weighted Average Plant Availability⁽¹⁾

	Three months ended September 30		Nine months ended September 30
	2004	2003	2004	2003
	(unaudited)
Western operations⁽²⁾	94%	91%	96%	93%
Eastern operations⁽²⁾	98%	99%	97%	92%
Bruce Power investment⁽³⁾	85%	94%	85%	88%
Power LP investment⁽²⁾	97%	99%	97%	95%
All plants	92%	96%	92%	91%

(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): ManChief and Curtis Palmer are included in Power LP investment effective April 30, 2004.
(3): Comparative 2003 percentage is calculated from the February 14, 2003 date of acquisition. Bruce A Unit 3 is included effective March 1, 2004.

Corporate

Net earnings for the three and nine months ended September 30, 2004 were $8 million and $1 million, respectively, compared to net expenses of $12 million and $30 million for the corresponding periods in 2003.

The $20 million increase in Corporate net earnings for the three months ended September 30, 2004 compared to the same period in 2003 was primarily due to a $12 million after-tax adjustment as a result of the release in the quarter of previously established restructuring provisions and the recognition of an $8 million income tax benefit relating to additional non-capital loss carryforwards utilized.

The $31 million increase for the nine months ended September 30, 2004 compared to the same period in 2003 was primarily due to the release in third quarter 2004 of previously established restructuring provisions and income tax related items, including refunds in first quarter 2004 and the recognition of the benefit of additional loss carryforwards utilized. These positive variances were partially offset by additional interest costs due to the issuance of new debt in late 2003 and early 2004.

Discontinued Operations

The Board of Directors approved a plan in July 2001 to dispose of the company's Gas Marketing business. The company's exit from Gas Marketing was substantially completed by December 31, 2001. At September 30, 2004, TransCanada reviewed the provision for loss on discontinued operations and the remaining deferred gain with respect to the divested Gas Marketing business. As a result of this review, it was determined that TransCanada's contingent liability pursuant to guarantees and obligations under certain contracts related to the divested Gas Marketing business had decreased and, accordingly, the remaining $52 million after-tax deferred gain was recognized in income in third quarter 2004. In addition, TransCanada concluded that the remaining provision for loss on discontinued operations was adequate.

Liquidity and Capital Resources

Funds Generated from Operations

Funds generated from continuing operations were $394 million and $1,207 million for the three and nine months ended September 30, 2004, respectively, compared with $516 million and $1,407 million for the same periods in 2003.

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, 2003.

Investing Activities

In the three and nine months ended September 30, 2004, capital expenditures, excluding acquisitions, totalled $97 million (2003 — $81 million) and $291 million (2003 — $264 million), respectively, and related primarily to construction of new power plants, and maintenance and capacity capital in the Gas Transmission business.

In the nine months ended September 30, 2004, disposition of assets totalled $408 million (2003 — nil) and related primarily to the sale of ManChief and Curtis Palmer to Power LP in second quarter 2004.

Acquisitions for the three and nine months ended September 30, 2004 were $49 million (2003 — $135 million) and $63 million (2003 — $547 million), respectively.

Financing Activities

TransCanada retired long-term debt of $9 million and $510 million in the three and nine months ended September 30, 2004, respectively. In February 2004, the company issued $200 million of five year medium-term notes bearing interest at 4.1 per cent. In March 2004, the company issued US$350 million of 30 year senior unsecured notes bearing interest at 5.6 per cent. For the nine months ended September 30, 2004, outstanding notes payable decreased by $367 million, while cash and short-term investments increased by $794 million. The increase in cash and short-term investments and decrease in outstanding notes payable positions TransCanada to complete the acquisition of Gas Transmission Northwest Corporation (GTN) which is expected in fourth quarter 2004 (see Other Recent Developments — Gas Transmission — Gas Transmission Northwest Corporation).

Dividends

On October 26, 2004, TransCanada's Board of Directors declared a quarterly dividend of $0.29 per share for the quarter ending December 31, 2004 on the outstanding common shares. This is the 164^th consecutive quarterly dividend paid by TransCanada and its subsidiary on the common shares. It is payable on January 31, 2005 to shareholders of record at the close of business on December 31, 2004.

Contractual Obligations

At September 30, 2004, TransCanada held a 30.6 per cent interest in Power LP which is a publicly-held limited partnership. Until April 29, 2004, Power LP was required to redeem all units outstanding at June 30, 2017, not held directly or indirectly by TransCanada and TransCanada was required to fund the redemption in accordance with the terms of the Power LP Partnership Agreement. At a special meeting held on April 29, 2004, Power LP's unitholders approved the amendment of the terms of the Power LP Partnership Agreement to remove Power LP's obligation to redeem all units not owned by TransCanada in 2017.

Excluding the removal of the Power LP obligation, there have been no material changes to TransCanada's contractual obligations, including payments due for the next five years and thereafter, since December 31, 2003. For further information on these contractual obligations, refer to the MD&A in TransCanada's 2003 Annual Report.

Financial and Other Instruments

The following represents the material changes to the company's risk management and financial instruments since December 31, 2003 and reflects the impacts of the hedge accounting changes adopted prospectively, effective January 1, 2004, as further discussed under Accounting Changes — Hedging Relationships.

Foreign Exchange and Interest Rate Management Activity

The company manages certain foreign exchange risks of U.S. dollar debt and interest rate exposures of the Alberta System, the Canadian Mainline and the Foothills System through the use of foreign currency and interest rate derivatives. These derivatives are comprised of contracts for periods up to eight years. Certain of the realized gains and losses on interest rate derivatives are shared with shippers on predetermined terms.

		September 30, 2004				December 31, 2003
		Carrying Amount		Fair Value		Carrying Amount		Fair Value
		(unaudited)
		(millions of dollars)
Asset/(Liability)
Foreign Exchange
Cross-currency swaps		(33	)	(33	)	(26	)	(26	)
Interest Rate
Interest rate swaps
	Canadian dollars	16		16		2		15
	U.S. dollars	8		8		—		8

At September 30, 2004, the principal amount of cross-currency swaps was US$282 million (December 31, 2003 — US$282 million). In addition, at September 30, 2004, the company has associated interest rate swaps with cross-currency swaps with notional principal amounts of $210 million (December 31, 2003 — $210 million) and US$162 million (December 31, 2003 — US$162 million). Notional principal amounts for interest rate swaps were $569 million (December 31, 2003 — $964 million) and US$100 million (December 31, 2003 — US$100 million).

The company manages the foreign exchange risk and interest rate exposures of its other U.S. dollar debt through the use of foreign currency and interest rate derivatives. These derivatives are comprised of contracts for periods up to nine years. The fair values of the interest rate derivatives are shown in the table below.

		September 30, 2004				December 31, 2003
		Carrying Amount		Fair Value		Carrying Amount	Fair Value
		(unaudited)
		(millions of dollars)
Asset/(Liability)
Interest Rate
Interest rate swaps
	Canadian dollars	(4	)	(4	)	1	(3	)
	U.S. dollars	34		34		2	37
Foreign Exchange
Forward Foreign Exchange Contracts
	U.S. dollars	(7	)	(6	)	—	1

At September 30, 2004, the notional principal amounts for interest rate swaps were $225 million (December 31, 2003 — $150 million) and US$450 million (December 31, 2003 — US$450 million). The principal amount of forward foreign exchange contracts was US$148 million (December 31, 2003 — US$19 million).

Risk Management

With respect to continuing operations, TransCanada's market, financial and counterparty risks remain substantially unchanged since December 31, 2003. For further information on risks, refer to the MD&A in TransCanada's 2003 Annual Report.

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, 2003, is the use of regulatory accounting for its regulated operations. For further information on this critical accounting policy, refer to the MD&A in TransCanada's 2003 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 estimate from December 31, 2003 continues to be depreciation expense. In third quarter 2004, TransCanada recognized in income the critical accounting estimate with respect to the remaining after-tax deferred gain related to the 2001 sale of the Gas Marketing business as further discussed under Results of Operations — Discontinued Operations. For further information on these critical accounting estimates, refer to the MD&A in TransCanada's 2003 Annual Report.

Accounting Changes

Asset Retirement Obligations

Effective January 1, 2004, the company adopted the new standard of the Canadian Institute of Chartered Accountants (CICA) Handbook Section "Asset Retirement Obligations", which addresses financial accounting and reporting for obligations associated with asset retirement costs. This section requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. The fair value is added to the carrying amount of the associated asset. The liability is accreted at the end of each period through charges to operating expenses. This accounting change was applied retroactively with restatement of prior periods.

The plant, property and equipment of the regulated natural gas transmission operations consist primarily of underground pipelines and above ground compression equipment and other facilities. No amount has been recorded for asset retirement obligations relating to these assets as it is not possible to make a reasonable estimate of the fair value of the liability due to the indeterminate timing and scope of the asset retirements. Management believes it is reasonable to assume that all retirement costs associated with the regulated pipelines will be recovered through tolls in future periods.

The impact of this accounting change resulted in an increase of $2 million in the estimated fair value of the liability for TransCanada's Other Gas Transmission assets as at January 1, 2003 and December 31, 2003. The estimated fair value of this liability as at September 30, 2004 was $11 million.

The plant, property and equipment in the Power business consists primarily of power plants in Canada and the United States. The impact of this accounting change resulted in an increase of $6 million and $7 million in the estimated fair value of the liability for the power plants and associated assets as at January 1, 2003 and December 31, 2003, respectively. The asset retirement cost, net of accumulated depreciation that would have been recorded if the cost had been recorded in the period in which it arose, is recorded as an additional cost of the assets as at January 1, 2003. The estimated fair value of the liability as at September 30, 2004 was $23 million. The company has no legal liability for asset retirement obligations with respect to its investment in Bruce Power and the Sundance A and B power purchase arrangements.

The impact of this change on TransCanada's net income in prior periods was nil while the impact of this change in the three and nine months ended September 30, 2004 was nil and approximately $1 million, respectively.

Hedging Relationships

Effective January 1, 2004, the company adopted the provisions of the CICA's new Accounting Guideline "Hedging Relationships" that specifies the circumstances in which hedge accounting is appropriate, including the identification, documentation, designation and effectiveness of hedges, and the discontinuance of hedge accounting. In accordance with the provisions of this new guideline, TransCanada has recorded all derivatives on the Consolidated Balance Sheet at fair value.

This new guideline was applied prospectively and resulted in a decrease in net income of $2 million and nil for the three and nine months ended September 30, 2004, respectively. The significant impact of the accounting change on the Consolidated Balance Sheet as at January 1, 2004 is as follows.

		Increase/(Decrease)
		(unaudited — millions of dollars)
Current Assets
	Other	8
Other Assets		123

Total Assets		131

Current Liabilities
	Accounts Payable	8
Deferred Amounts		132
Long-Term Debt		(7	)
Future Income Taxes		(1	)

Total Liabilities		132

Generally Accepted Accounting Principles

Effective January 1, 2004, the company adopted the new standard of the CICA Handbook Section "Generally Accepted Accounting Principles" that defines primary sources of generally accepted accounting principles (GAAP) and the other sources that need to be considered in the application of GAAP. The new standard eliminates the ability to rely on industry practice to support a particular accounting policy.

This accounting change was applied prospectively and there was no impact on net income in the three and nine months ended September 30, 2004. In prior periods, in accordance with industry practice, certain assets and liabilities related to the company's regulated activities, and offsetting deferral accounts, were not recognized on the balance sheet. The impact of the change on the consolidated balance sheet as at January 1, 2004 is as follows.

	Increase/(Decrease)
	(unaudited — millions of dollars)
Other Assets	153

Deferred Amounts	80
Long-Term Debt	76
Preferred Securities	(3	)

Total Liabilities	153

Outlook

In 2004, the closing of the pending acquisition of GTN and the gain on sale of Millennium are expected to have a positive impact on the results of the Gas Transmission segment. However, the EUB's decisions received in July 2004 and August 2004 on the GCOC for Alberta utilities and on Phase I of the 2004 GRA for Alberta System, respectively, will have a negative impact on the expected results of the Gas Transmission segment. For further information on the pending GTN acquisition and the EUB's and NEB's decisions, please refer to Other Recent Developments. In addition, the company expects higher Power net earnings in 2004 than originally anticipated as a result of the gains related to Power LP. Power earnings for the remainder of 2004 will be negatively impacted due to the recognition of previously deferred gains related to Power LP in second quarter 2004 and OSP's August 2004 arbitration settlement. Income tax related items and the release of the previously established restructuring provisions will have a positive impact on the expected results of the Corporate segment. Excluding these impacts, the company's outlook is relatively unchanged since December 31, 2003. For further information on outlook, refer to the MD&A in TransCanada's 2003 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. 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 2004, the EUB released its decision in the GCOC proceeding. The Alberta System, as all other Alberta provincially regulated utilities, was given a rate of return on equity (ROE) of 9.60 per cent for 2004. This generic ROE will be adjusted annually by 75 per cent of the change in long-term Government of Canada bonds from the previous year, consistent with the approach used by the NEB. The EUB also established a deemed common equity of 35 per cent for the Alberta System. This result is less than the applied for ROE of 11 per cent on deemed common equity of 40 per cent. The EUB also indicated that a review of its ROE adjustment mechanism would not occur prior to 2009, unless the ROE resulting from its application is less than 7.6 per cent or greater than 11.6 per cent. As for changes in capital structure, it expects changes would only be pursued if there is a material change in investment risk.

In September 2003, TransCanada filed Phase I of the 2004 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 2003 composite depreciation rate of 4.00 per cent. On August 24, 2004 the EUB issued its decision and approved a composite depreciation rate of 4.06 per cent, approved the purchase of the Simmons Pipeline System (Simmons) for approximately $22 million and approved the Transportation by Others arrangements that currently exist on the Foothills, Simmons and Ventures LP systems. However, a significant amount of costs were disallowed for recovery, which reduced revenue requirement and rate base.

In September 2004, TransCanada filed with the Alberta Court of Appeal for leave to appeal the EUB's decision on Phase I of the 2004 GRA with respect to the disallowance of applied-for incentive compensation costs. In its decision, the EUB disallowed approximately $24 million (pre tax) of operating costs, which included $19 million of applied-for incentive compensation costs. TransCanada believes the EUB made errors of law in deciding to deny the inclusion of these costs in the revenue requirement. The company believes these are necessary costs that it will reasonably and prudently incur for the safe, reliable, and efficient operation of the Alberta System. Subsequently, at the request of TransCanada, the Court of Appeal adjourned the appeal for an indefinite period of time while TransCanada considers the merits of a Review and Variance application to the EUB in respect of 2004 costs, and works toward a negotiated settlement of future years' tolls with its customers. The EUB has limited the term of a settlement to three years.

In October 2004, Simmons became part of TransCanada's Alberta System. The assets include 380 kilometres of pipeline and metering facilities and four compressor units located in northern Alberta. Simmons delivers natural gas to the Fort McMurray area from several connecting receipt points within the Alberta System, along with production connected directly to the pipeline and has a capacity of approximately 185 million cubic feet per day.

Phase II of the 2004 GRA, dealing primarily with rate design and services, was filed in December 2003. The oral portion of the Phase II hearing began in Calgary on June 9, 2004, with arguments filed in July 2004. An EUB decision is expected on October 26, 2004.

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 in fourth quarter based on the EUB decisions on the 2004 GRA and will incorporate the outcome from the EUB decision in the GCOC proceeding.

Canadian Mainline

The NEB has approved interim tolls for 2004 for the Canadian Mainline. The 2004 Tolls and Tariff Application for the Canadian Mainline was filed in January 2004, and included a request for an 11 per cent return on a 40 per cent deemed common equity component. In light of a Federal Court of Appeal decision, TransCanada informed the NEB that it would not contest the ROE formula in its 2004 Tolls and Tariff Application and revised the Application to reflect the formula-based ROE of 9.56 per cent on 40 per cent deemed common equity. Phase I of the hearing in which the NEB considered all issues raised by the Application with the exception of cost of capital, concluded June 25, 2004. The NEB issued its decision for Phase I on September 10, 2004 and approved virtually all cost elements of the Application as well as a new non-renewable firm transportation service. It suspended the fuel gas incentive program for 2004. The proceedings for Phase II of the hearing, which will address capital structure, will take place in fourth quarter 2004. A decision is not expected until the end of first quarter 2005.

Other Gas Transmission

Gas Transmission Northwest Corporation

As described in the MD&A in TransCanada's 2003 Annual Report, TransCanada executed a Stock Purchase Agreement with National Energy & Gas Transmission, Inc., (NEGT) and certain of its subsidiaries to acquire GTN for US$1.7 billion, including US$0.5 billion of assumed debt, subject to closing adjustments. GTN owns and operates two pipeline systems — the Gas Transmission Northwest Pipeline System and the North Baja Pipeline System (North Baja). The acquisition of North Baja was subject to a right of first refusal in favour of a third party. That third party has now agreed to waive its right of first refusal in respect of the sale of North Baja to TransCanada and, accordingly, TransCanada now expects to close on the Gas Transmission Northwest Pipeline System and North Baja at the same time.

In second quarter 2004, NEGT's bankruptcy court approved both its Chapter 11 plan of reorganization and the sale of GTN to TransCanada. TransCanada has satisfied its pre-closing conditions under the purchase agreement and is awaiting the implementation of NEGT's Chapter 11 plan of reorganization, which is the only remaining material closing condition in the transaction. NEGT has informed TransCanada that, prior to implementing its Chapter 11 plan of reorganization, it is diligently pursuing the resolution of other issues in the reorganization that are unrelated to GTN or the GTN transaction but nonetheless it believes are in the best interests of the estate and its creditors. NEGT has further stated that it believes that its plan will become effective in the fourth quarter of this year. The parties expect to close the GTN transaction promptly thereafter.

Northern Development

In October 2004, Imperial Oil Resources announced that applications for the main regulatory approvals required for the Mackenzie Gas Pipeline Project were submitted to the boards, panels and agencies responsible for assessing and regulating energy developments in the Northwest Territories. These filings mark a significant milestone in the project definition phase. TransCanada will continue both to support the project through its position established under the various project agreements and to facilitate the interconnection of Mackenzie gas into TransCanada's Alberta System.

Liquefied Natural Gas

In September 2004, TransCanada and Petro-Canada signed a memorandum of understanding to develop a liquefied natural gas (LNG) facility, Cacouna Energy, in Gros Cacouna, Québec. TransCanada and Petro-Canada will equally share the costs to construct the LNG receiving, storage and regasification facility and TransCanada will operate the facility, while Petro-Canada will supply the LNG. The proposed facility would be capable of receiving, storing, and regasifying imported LNG with an average annual send-out capacity of approximately 500 million cubic feet of natural gas a day. The estimated cost of construction is $660 million. Construction of the facility is subject to regulatory approval from federal, provincial and municipal governments and is expected to take approximately two years. If approval is received, the facility is expected to be in service towards the end of the decade.

Gas Storage

In addition to the company's investment in the CrossAlta natural gas storage facility, TransCanada has entered into long-term arrangements, commencing in second quarter 2005, for 20 petajoules (PJ) of additional natural gas storage capacity in Alberta. The capacity under contract increases to 30 PJ in 2006 and 40 PJ in 2007. TransCanada intends to utilize this capacity as part of its Alberta gas storage services business. The company also continues to explore other gas storage opportunities.

Power

USGen New England, Inc.

In September 2004, USGen New England, Inc. (USGen) and TransCanada signed an Asset Purchase Agreement for TransCanada to purchase hydroelectric generation assets with a total generating capacity of 567 MW for US$505 million. The assets include generating systems on two rivers in New England: the 484 MW Connecticut River system in New Hampshire and Vermont and the 83 MW Deerfield River system in Massachusetts and Vermont. The output is not currently subject to long-term contracts.

USGen is a subsidiary of NEGT and voluntarily filed for protection under Chapter 11 of the U.S. Bankruptcy Code in July 2003. The sale will be subject to bankruptcy court approval. Through a court-sanctioned auction process in accordance with customary bidding procedures, USGen will seek offers that are higher or otherwise better than the TransCanada agreement.

As part of its agreement, TransCanada is granted certain protections, subject to court approval, most notably a break fee and expense reimbursement if another bid is accepted. TransCanada also retains the right to amend its offer should USGen receive an offer which is superior to its existing agreement with TransCanada. The agreement contemplates that final bankruptcy court approval of the sale will be obtained approximately 75 days after signing of the agreement. The sale is also subject to U.S. anti-trust and other regulatory reviews.

Hydro-Québec

In October 2004, Hydro-Québec Distribution awarded Cartier Wind Energy Inc., which is 50 per cent owned by TransCanada, six projects representing a total of 739.5 MW. The projects are distributed in various communities of the administrative region of Gaspésie, Iles-de-la-Madeleine and the Regional County Municipality of Matane and will be commissioned between 2006 and 2012 at a total cost of approximately $1.2 billion. Power purchase agreements are being negotiated with Hydro-Québec Distribution for each of the six facilities and are expected to be completed in December 2004. Each agreement will be subject to approval by Le Régie de L'Énergie.

MacKay River

The MacKay River 165 MW cogeneration plant, situated at Petro-Canada's MacKay River oilsands development, was declared contractually commercially in-service on February 1, 2004. Operational issues with the host site in the first half of 2004 were resolved during third quarter 2004 and the plant is operating as designed.

Other

In September 2004, TransCanada announced it will exercise its right to redeem all of its outstanding US$200 million 8.50 per cent Debentures due 2023 on November 1, 2004. Holders of the Debentures will be entitled to US$1,042.7806 per US$1,000 principal amount. This amount includes US$33.10 representing the redemption premium and US$9.6806 representing accrued and unpaid interest to the redemption date.

In October 2004, the company issued US$300 million of ten year senior unsecured notes bearing interest at 4.875 per cent, thereby fully utilizing the remainder of the debt shelf program in the U.S. At September 30, 2004, $1.35 billion of debt securities could be issued under a debt shelf program in Canada. The company expects to renew the debt shelf programs in the U.S. and Canada in fourth quarter 2004.

Share Information

As at September 30, 2004, TransCanada had 484,548,454 issued and outstanding common shares. In addition, there were 10,330,662 outstanding options to purchase common shares, of which 7,604,774 were exercisable as at September 30, 2004.

Selected Quarterly Consolidated Financial Data⁽¹⁾

		2004							2003								2002
		Third			Second		First		Fourth		Third		Second		First		Fourth
		(unaudited)
		(millions of dollars except per share amounts)
Revenues			1,224			1,256		1,233		1,319		1,391		1,311		1,336		1,338
Net Income
	Continuing operations		193			388		214		193		198		202		208		180
	Discontinued operations		52			—		—		—		50		—		—		—

			245			388		214		193		248		202		208		180

Share Statistics
Net income per share — Basic
	Continuing operations	$	0.40		$	0.80	$	0.44	$	0.40	$	0.41	$	0.42	$	0.43	$	0.37
	Discontinued operations		0.11			—		—		—		0.10		—		—		—

		$	0.51		$	0.80	$	0.44	$	0.40	$	0.51	$	0.42	$	0.43	$	0.37

Net income per share — Diluted		$	0.50	⁽²⁾	$	0.80	$	0.44	$	0.40	$	0.51	$	0.42	$	0.43	$	0.37

Dividend declared per common share		$	0.29		$	0.29	$	0.29	$	0.27	$	0.27	$	0.27	$	0.27	$	0.25

(1): The selected quarterly consolidated financial data has been prepared in accordance with Canadian GAAP. Certain comparative figures have been reclassified to conform with the current year's presentation. For a discussion on the factors affecting the comparability of the financial data, including discontinued operations, refer to Note 1 and Note 17 of TransCanada's 2003 audited consolidated financial statements included in TransCanada's 2003 Annual Report.
(2): Diluted net income per share for third quarter 2004 consists of continuing operations — $0.39 per share and discontinued operations — $0.11 per share.

Factors Impacting Quarterly Financial Information

In the Gas Transmission business, which consists primarily of the company's investments in regulated pipelines, annual revenues and net earnings fluctuate over the long term based on regulators' decisions and negotiated settlements with shippers. Generally, quarter over quarter revenues and earnings during any particular fiscal year remain fairly stable with fluctuations arising as a result of adjustments being recorded due to regulatory decisions and negotiated settlements with shippers and due to items outside of the normal course of operations.

In the Power business, which consists primarily of the company's investments in electrical power generation plants, quarter over quarter revenues and net earnings are affected by seasonal weather conditions, customer demand, market prices, planned and unplanned plant outages as well as items outside of the normal course of operations.

Significant items which impacted the last eight quarters' net earnings are as follows.

•: In first quarter 2003, TransCanada completed the acquisition of a 31.6 per cent interest in Bruce Power, resulting in increased earnings in the Power business in 2004 and 2003 compared to 2002. In addition, TransCanada reached a one-year Alberta System Revenue Requirement Settlement for 2003 which included a fixed revenue requirement component of $1.277 billion compared to $1.347 billion in 2002, resulting in lower earnings in the Transmission business in 2003 compared to 2002.
•: Second quarter 2003 net earnings included a $19 million positive after-tax earnings impact of a June 2003 settlement with a former counterparty that had previously defaulted under power forward contracts.
•: Third quarter 2003 net earnings included TransCanada's $11 million share of a future income tax benefit adjustment recognized by TransGas.

•: First quarter 2004 net earnings included approximately $12 million of income tax refunds and refund interest.
•: Second quarter 2004 net earnings included gains related to Power LP of $187 million, of which $132 million were previously deferred and were being amortized into income to 2017.
•: In third quarter 2004, the EUB's decisions on the GCOC and Phase I of the 2004 GRA resulted in lower earnings for the Alberta System compared to the previous quarters. In addition, third quarter 2004 included a $12 million after-tax adjustment related to the release of previously established restructuring provisions and recognition of $8 million of non-capital loss carryforwards.

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.

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Exhibit 13.1