Segment Results-at-a-Glance
(unaudited)	Three months ended June 30				Six months ended June 30
(millions of dollars except per share amounts)	2005		2004		2005		2004
GasTransmission Net Income
Excluding gains	164		139		327		288
Gain related to PipeLines LP	1		—		49		—
Gain related to Millennium	—		7		—		7
	165		146		376		295
Power Net Income
Excluding gains	42		62		72		127
Gains related to Power LP	—		187		—		187
	42		249		72		314
Corporate	(8	)	(7	)	(17	)	(7	)
Net Income Applicable to Common Shares (1)	199		388		431		602

(1) Net Income is comprised of:
Excluding gains	198	194	382	408
Gains related to PipeLines LP, Power LPand Millennium	1	194	49	194
	199	388	431	602

TCPL’s net income applicable to common shares (net earnings) for second quarter 2005 was $199 million compared to $388 million for the same period in 2004. The decrease of $189 million was primarily due to the recording in second quarter 2004 of $187 million of after-tax gains relating to the sale of the ManChief and Curtis Palmer assets to TransCanada Power, L.P. (Power LP) and the recognition of dilution gains resulting from a reduction in TCPL’s ownership interest in Power LP and other previously deferred gains, as well as a $7 million after-tax gain on sale of the company’s equity interest in the Millennium Pipeline project (Millennium).

Excluding the total gains of $194 million recorded in second quarter 2004 related to Power LP and Millennium and $1 million recorded in second quarter 2005 related to TC PipeLines, LP (PipeLines LP), earnings for second quarter 2005 increased $4 million to $198 million, compared to second quarter 2004. This was mainly due to a $25 million increase in Gas Transmission’s net income for second quarter 2005, partially offset by a decrease of $20 million in Power’s net income. The increase in Gas Transmission’s net income was primarily due to net income of approximately $21 million ($13 million related to 2004 and $8 million related to the first six months of 2005) recorded in second quarter 2005 as a result of the decision from the National Energy Board (NEB) on the Canadian Mainline’s 2004 Tolls and Tariff Application (Phase II) dealing with capital structure which increased deemed equity thickness to 36 per cent from 33 per cent effective January 1, 2004. In addition, $16 million was generated from the Gas Transmission Northwest System and the North Baja

System (collectively GTN), which were acquired by TCPL on November 1, 2004. The decrease in Power’s net income was primarily due to lower equity income from Bruce Power L.P. (Bruce Power) and lower operating and other income from Western Operations, partially offset by higher operating and other income from Eastern Operations as a result of the USGen New England, Inc. (USGen) acquisition. Corporate net expenses for second quarter 2005 were consistent with the prior year second quarter.

TCPL’s net earnings for the six months ended June 30, 2005 was $431 million compared to $602 million for the comparable period in 2004. The decrease of $171 million in the first six months of 2005 compared to the same period in 2004 was primarily due to the 2004 gains related to Power LP and, in 2005, lower Power net income and higher net expenses in the Corporate segment, partially offset by higher net income from the Gas Transmission business.

Excluding the above-mentioned $187 million of gains related to Power LP in the first six months of 2004, Power net income for the six months ended June 30, 2005 decreased $55 million as a result of lower equity income from Bruce Power and reduced contributions from Eastern and Western Operations.

The increase in net expenses of $10 million in the Corporate segment in the six months ended June 30, 2005 was primarily as a result of higher interest expense compared to the same period in 2004. In second quarter 2005, this higher interest expense was primarily offset by income tax refunds and certain positive income tax adjustments.

Excluding the $49 million after-tax gain on sale of PipeLines LP units in 2005 and the $7 million after-tax gain on sale of the company’s equity interest in Millennium in 2004, the $39 million increase in net income in the Gas Transmission business for the six months ended June 30, 2005 compared to the same period in 2004 was primarily attributable to $39 million generated from GTN.

Funds generated from operations of $478 million and $885 million for the three and six months ended June 30, 2005 increased $96 million and $88 million, respectively, when compared to the same periods in 2004.

Gas Transmission

The Gas Transmission business generated net income of $165 million and $376 million for the three and six months ended June 30, 2005, respectively, compared to $146 million and $295 million for the same periods in 2004.

GasTransmission Results-at-a-Glance
(unaudited)	Three months ended June 30				Six months ended June 30
(millions of dollars)	2005		2004		2005		2004
Wholly-Owned Pipelines
Canadian Mainline	86		66		149		130
Alberta System	37		39		74		79
GTN (1)	16				39
Foothills System	6		5		11		11
BC System	1		1		3		3
	146		111		276		223
Other Gas Transmission
Great Lakes	11		14		25		31
Iroquois	3		3		7		11
PipeLines LP	1		5		5		9
Portland	—		—		6		6
Ventures LP	3		4		6		7
TQM	1		2		3		4
CrossAlta	2		1		7		2
TransGas	3		3		6		6
Northern Development	(1	)	(1	)	(2	)	(2	)
General, administrative, support costs and other	(5	)	(3	)	(12	)	(9	)
	18		28		51		65
Gain related to PipeLines LP	1		—		49		—
Gain related to Millenium	—		7		—		7
	19		35		100		72
Net Income	165		146		376		295

(1) TCPL acquired GTN on November 1, 2004.

Wholly-Owned Pipelines

The Canadian Mainline’s net income increased $20 million and $19 million for the three and six months ended June 30, 2005, respectively, when compared to the corresponding periods in 2004. This increase reflects the impact of the NEB’s decision on the Canadian Mainline’s 2004 Tolls and Tariff Application (Phase II) in April 2005, which included an increase in the deemed common equity ratio from 33 per cent to 36 per cent for 2004 and which is also effective for 2005 under the 2005 tolls settlement with shippers, partially offset by a decrease in the approved rate of return on common equity to 9.46 per cent in 2005 from 9.56 per cent in 2004. As a result of the NEB decision, Canadian Mainline’s net income increased $21 million ($13 million related to 2004 and $8 million related to the first six months of 2005) in second quarter 2005.

The Alberta System’s net income of $37 million in second quarter 2005 is $2 million lower than the same quarter in 2004. Net income for the six months ended June 30, 2005 decreased $5 million compared to the same period in 2004. These decreases were primarily due to a lower investment base in 2005 as well as a lower approved rate of return in 2005. Net income in 2005 reflects a rate of return of 9.50 per cent, as prescribed by the Alberta Energy and Utilities Board (EUB), on deemed common equity of 35 per cent compared to a rate of return of 9.60 per cent in 2004.

GTN, which was acquired by TCPL in November 2004, generated net income of $16 million in second quarter 2005 and $39 million in the six months ended June 30, 2005. Net income for the Foothills System for the three and six months ended June 30, 2005 is comparable to the same period in the prior year.

Operating Statistics

Gas

Transmission

Canadian

Northwest

Six months ended June 30

Mainline (1)

Alberta System (2)

System (3)

Foothills System

BC System

(unaudited)

2005

2004

2005

2004

2005

2004

2005

2004

Average investment base ($ millions)

7,873

8,274

4,534

4,719

n/a

(3)

687

722

219

230

Delivery volumes (Bcf)

Total

1,437

1,355

1,936

1,925

383

520

552

162

162

Average per day

7.9

7.4

10.7

10.6

2.1

2.9

3.0

0.9

0.9

(1) Canadian Mainline deliveries originating at the Alberta border and in Saskatchewan for the six months ended June 30, 2005 were 1,044 Bcf (2004 - 1,016 Bcf); average per day was 5.8 Bcf (2004 - 5.6 Bcf).

(2) Field receipt volumes for the Alberta System for the six months ended June 30, 2005 were 1,979 Bcf (2004 - 1,958 Bcf); average per day was 10.9 Bcf (2004 - 10.8 Bcf).

(3) TCPL acquired the Gas Transmission Northwest System on November 1, 2004. The system is currently operating under a fixed rate model approved by the United States Federal Energy Regulatory Commission and, as a result, the system’s current results are not dependent on average investment base.

Other Gas Transmission

TCPL’s proportionate share of net income from its Other Gas Transmission businesses was $19 million for the three months ended June 30, 2005 compared to $35 million for the same period in 2004. The second quarter 2004 results include a $7 million after-tax gain on sale of the company’s equity interest in Millennium. Excluding this gain, and the $1 million after-tax gain on sale of additional units of PipeLines LP recorded in second quarter 2005, income for second quarter 2005 decreased $10 million compared to the same period in 2004. The decrease was mainly due to lower earnings from PipeLines LP reflecting a reduced ownership interest, lower earnings from Great Lakes as a result of lower short-term revenues and higher operating and maintenance costs, as

well as the negative impact of a weaker U.S. dollar on the company’s U.S. operations.

Net income for the six months ended June 30, 2005 was $100 million compared to $72 million for the corresponding period in 2004. Excluding the $49 million after-tax gain on sale of PipeLines LP units recorded in 2005, and the $7 million after-tax gain on sale of Millennium recorded in 2004, year-to-date earnings are $14 million lower compared to the same period in 2004. The decrease is due to lower earnings from Great Lakes, lower earnings from Iroquois primarily due to a tax adjustment recorded in first quarter 2004 and lower earnings from PipeLines LP reflecting a reduced ownership interest. Results were also negatively impacted by a weaker U.S. dollar in 2005. These decreases were partially offset by higher earnings from CrossAlta as a result of favourable conditions in the natural gas storage market.

As at June 30, 2005, TCPL had capitalized $8 million of costs related to its Broadwater liquified natural gas (LNG) project.

Power

Power Results-at-a-Glance
(unaudited)	Three months ended June 30				Six months ended June 30
(millions of dollars)	2005		2004		2005		2004
Western operations	28		35		58		70
Eastern operations	39		22		44		56
Bruce Power investment	13		48		43		96
Power LP investment	8		6		17		16
General, administrative, support costs and other	(26	)	(24	)	(51	)	(49	)
Operating and other income	62		87		111		189
Financial charges	(3	)	(3	)	(7	)	(5	)
Income taxes	(17	)	(22	)	(32	)	(57	)
	42		62		72		127
Gains related to Power LP(after tax)	—		187		—		187
Net Income	42		249		72		314

Power’s net income in second quarter 2005 of $42 million decreased $207 million compared to second quarter 2004, primarily due to $187 million of gains related to Power LP in second quarter 2004. Excluding these gains, Power’s net income of $42 million for second quarter 2005 decreased $20 million compared to $62 million for the same period in 2004. Higher operating and other income from Eastern Operations partially offset lower operating and other income from Bruce Power and Western Operations.

Eastern Operations’ operating and other income was $17 million higher in second quarter 2005 compared to second quarter 2004

primarily due to the acquisition of hydroelectric generation assets from USGen on April 1, 2005.

Bruce Power’s equity income was lower by $35 million in second quarter 2005 compared to second quarter 2004 primarily due to lower generation volumes and higher costs resulting from a planned maintenance outage on Unit 7 (54 days) and an unplanned maintenance outage on Unit 6 (27 days) as a result of a transformer fire outside the generating facility. Higher realized power prices in second quarter 2005 partially offset the impact of the lower generation volumes as well as increased outage and operating costs.

Western Operations’ operating and other income was $7 million lower in second quarter 2005 compared to second quarter 2004 primarily due to fee revenues earned in 2004 on the sale of ManChief and Curtis Palmer to Power LP and reduced margins from lower market heat rates on uncontracted volumes of power generated.

Net income for the six months ended June 30, 2005 of $72 million decreased $242 million compared to $314 million in 2004. Excluding the $187 million of Power LP-related gains in 2004, Power’s net income for the six months ended June 30, 2005 of $72 million decreased $55 million compared to $127 million in 2004 as a result of lower equity income from Bruce Power and reduced operating and other income from Eastern and Western Operations.

Western Operations

Western Operations Results-at-a-Glance (1)
(unaudited)	Three months ended June 30				Six months ended June 30
(millions of dollars)	2005		2004		2005		2004
Revenue
Power	151		167		315		314
Other (2)	37		30		79		63
	188		197		394		377
Cost of sales
Power	(102	)	(113	)	(217	)	(203	)
Other (2)	(18	)	(14	)	(41	)	(38	)
	(120	)	(127	)	(258	)	(241	)
Other costs and expenses	(35	)	(30	)	(68	)	(54	)

Depreciation	(5	)	(5	)	(10	)	(12	)
Operating and other income	28		35		58		70

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

(2) Other revenue includes Cancarb Thermax and natural gas sales. Other cost of sales includes the cost of natural gas sold.

Western Operations Sales Volumes (1)
(unaudited)	Three months ended June 30		Six months ended June 30
(GWh)	2005	2004	2005	2004
Supply
Generation	511	390	1,147	752
Purchased
Sundance A & B PPAs	1,713	1,885	3,544	3,696
Other purchases (2)	614	654	1,345	1,357
	2,838	2,929	6,036	5,805
Contracted vs. Spot
Contracted	2,462	2,677	5,147	5,355
Spot	376	252	889	450
	2,838	2,929	6,036	5,805

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

(2) Includes Sheerness Power Purchase Arrangement (PPA) volumes.

Western Operations’ operating and other income of $28 million and $58 million for the three and six months ended June 30, 2005 was $7 million and $12 million lower, respectively, compared to the same periods in 2004. The decreases were mainly due to fee revenues earned in second quarter 2004 on the sale of ManChief and Curtis Palmer to Power LP and reduced margins resulting from lower market heat rates on uncontracted volumes of power generated. Lower market heat rates were the result of weak spot market power prices in Alberta that averaged approximately $9 per megawatt hour (MWh) less in second quarter 2005 and $6 per MWh less for the six months ended June 30, 2005, compared to the same periods in 2004, while average natural gas prices were slightly higher. A significant portion of plant generation in Western Operations is sold under long-term contract to mitigate price risk. Some output is intentionally not committed under long-term contract to assist in managing Power’s overall portfolio of generation. This approach to portfolio management assists in minimizing costs in situations where TCPL would otherwise have to purchase electricity in the open market to fulfill its contractual obligations.

Western Operations’ power sales revenues and power cost of sales decreased in second quarter 2005 primarily due to lower plant availability as a result of maintenance outages at Sundance B. Power sales revenues also decreased as a result of lower contracted and spot market prices realized in second quarter 2005. Partially offsetting this decrease were revenues from the 2004 start-up of the MacKay River facility. Other costs and expenses were higher in second quarter 2005 primarily due to operating costs associated with the MacKay River facility. Generation volumes in second quarter 2005 increased 121 gigawatt hours (GWh) to 511 GWh primarily due to the start-up of the MacKay River facility, partially offset by a decrease in volumes associated with unplanned outages at the Bear Creek cogeneration facility.

In second quarter 2005, approximately 13 per cent of power sales volumes were sold into the spot market compared to approximately nine per cent for the same period in 2004. To reduce its exposure to spot market prices on uncontracted volumes, as at June 30, 2005, Western Operations had fixed price sales contracts to sell forward approximately 5,100 GWh for the remainder of 2005 and approximately 8,000 GWh for 2006.

Eastern Operations

Eastern Operations Results-at-a-Glance (1)
(unaudited)	Three months ended June 30				Six months ended June 30
(millions of dollars)	2005		2004		2005		2004
Revenue
Power	129		130		244		276
Other (2)	73		52		143		117
	202		182		387		393
Cost of sales
Power	(51	)	(66	)	(113	)	(145	)
Other (2)	(74	)	(49	)	(139	)	(105	)
	(125	)	(115	)	(252	)	(250	)
Other costs and expenses	(32	)	(40	)	(81	)	(75	)

Depreciation	(6	)	(5	)	(10	)	(12	)
Operating and other income	39		22		44		56

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

(2) Other includes natural gas.

Eastern Operations Sales Volumes (1)
(unaudited)	Three months ended June 30		Six months ended June 30
(GWh)	2005	2004	2005	2004
Supply
Generation	962	423	1,406	800
Purchased	494	1,051	1,305	2,285
	1,456	1,474	2,711	3,085
Contracted vs. Spot
Contracted	1,228	1,456	2,417	3,000
Spot	228	18	294	85
	1,456	1,474	2,711	3,085

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

Operating and other income in second quarter 2005 from Eastern Operations of $39 million was $17 million higher compared to $22 million earned in the same period in 2004. The increase was due primarily to income from the acquisition of hydroelectric generation assets (hydro assets) from USGen on April 1, 2005 and from the Grandview cogeneration facility which was placed in service in January 2005. Partially offsetting these increases was the loss of income associated with the sale of the Curtis Palmer hydroelectric facilities to Power LP in April 2004.

Operating and other income for the six months ended June 30, 2005 was $44 million or $12 million lower than the $56 million earned in 2004. Income from the acquisition of the hydro assets and income from the Grandview cogeneration facility were more than offset by a $16 million pre-tax ($10 million after-tax) contract restructuring payment made by Ocean State Power (OSP) to its natural gas fuel suppliers in first quarter 2005 and a $16 million pre-tax ($10 million after-tax) reduction in income as a result of the sale of Curtis Palmer to Power LP in April 2004. The contract restructuring at OSP reduced the term of the long-term gas supply contracts with its suppliers by approximately three years (now ending in October 2008) and adjusted the pricing to track spot pricing of natural gas at the Niagara delivery point versus the previously arbitrated pricing that had resulted in above-market cost of gas for OSP.

Generation volumes in second quarter 2005 increased 539 GWh to 962 GWh compared to 423 GWh in 2004 primarily due to the acquisition of the hydro assets and the placing in-service of the Grandview cogeneration facility. Partially offsetting these increases were decreases in volumes associated with the sale of the Curtis Palmer hydroelectric facility to Power LP in April 2004 and reduced generation from the OSP facility.

Power sales revenues of $129 million and sales volumes of 1,456 GWh for second quarter 2005 were consistent with the same period in 2004. Power sales revenues and volumes sold from the new hydro assets and Grandview were offset by the loss of revenues and volumes from the sale of Curtis Palmer, the expiration of long-term sales contracts held at the end of 2004 which did not carry-over into 2005, and an unplanned outage at OSP. This outage is expected to continue into third quarter 2005. Realized average power prices were consistent in second quarter of 2004 and 2005. Power cost of sales of $51 million and purchased volumes of 494 GWh were lower in second quarter 2005 due to the impact of the purchase of the hydro assets. Volumes generated from the hydro assets reduced some of the requirement to purchase power to fulfill contractual sales obligations. Other revenue and cost of sales increased year-over-year primarily as a result of gas purchased and resold from new gas supply contracts at OSP. Other costs and expenses of $32 million, which includes fuel gas

consumed in generation, decreased $8 million primarily due to lower fuel costs from reduced dispatch at the OSP facility.

In second quarter 2005, approximately 16 per cent of power sales volumes were sold into the spot market compared to approximately one per cent in 2004 reflecting the sale to the spot market of a portion of the generation of the the hydro assets acquired on April 1, 2005. Eastern Operations is focused on selling the majority of its power under contract to wholesale, commercial and industrial customers while managing a portfolio of power supplies sourced from its own generation, wholesale power purchases and power purchased from Power LP’s Castleton plant. To reduce its exposure to spot market prices, as at June 30, 2005, Eastern Operations had entered into fixed price sales contracts to sell forward approximately 2,800 GWh of power for the remainder of 2005 and approximately 3,300 GWh of power for 2006. Certain contracted volumes are dependent on customer usage levels.

Bruce Power Investment

Bruce Power Results-at-a-Glance
(unaudited)	Three months ended June 30				Six months ended June 30
(millions of dollars)	2005		2004		2005		2004
Bruce Power (100 per cent basis)
Revenues	393		434		811		833
Operating expenses
Cash costs (materials, labour, services and fuel)	(287	)	(243	)	(552	)	(462	)
Non-cash costs (depreciation and amortization)	(49	)	(43	)	(97	)	(74	)
	(336	)	(286	)	(649	)	(536	)
Operating income	57		148		162		297
Financial charges	(17	)	(15	)	(34	)	(33	)
Income before income taxes	40		133		128		264
TCPL’s interest in Bruce Power income before income taxes	12		42		40		83

Adjustments	1		6		3		13

TCPL’s income from Bruce Power before income taxes	13		48		43		96

TCPL’s share of Bruce Power’s income before income taxes (equity income) was lower by $35 million in second quarter 2005 compared to second quarter 2004 primarily due to lower generation volumes and higher costs resulting from a planned maintenance outage on Unit 7 (54 days) and Unit 4 (27 days) and an unplanned maintenance outage on Unit 6 (29 days) relating to a transformer fire outside the generating facility. Higher realized power prices in second quarter 2005 partially offset the reduction in revenues from lower generation volumes and an increase in outage and operating costs.

TCPL’s share of power output from Bruce Power for second quarter 2005 was 2,306 GWh compared to 2,962 GWh in second quarter 2004. This decrease primarily reflects lower output in 2005 as a result of an increase in planned maintenance outages compared to second

quarter 2004 as well as lost output as a result of the Unit 6 transformer fire outage in second quarter 2005. On April 15, 2005, Bruce Power experienced a transformer fire outside of the generating facility. As a result, Unit 6 went offline and, after the successful replacement of its main output transformer, was returned to service on May 14, 2005.

Approximately 81 reactor days of planned maintenance outages as well as 57 reactor days of unplanned outages (including the Unit 6 outage of 29 days) occurred in second quarter 2005. In second quarter 2004, Bruce Power experienced 36 reactor days of planned maintenance outages and four reactor days of unplanned outages. The Bruce units ran at an average availability of 71 per cent in second quarter 2005, compared to a 92 per cent average availability during second quarter 2004. Unit 4 returned to service on April 28, 2005 following a planned maintenance inspection that began on March 12, 2005. Unit 7 was taken offline on May 7, 2005 to begin its planned maintenance outage, including the completion of major Spacer Location and Relocation work and turbine replacement, which is expected to last about three months.

Overall prices achieved during second quarter 2005 were $53 per MWh, compared to $46 per MWh in second quarter 2004. Prices realized for the six months ending June 30, 2005 were $51 per MWh compared to $47 per MWh for the same period in 2004. Approximately 49 per cent of the available output was sold into Ontario’s wholesale spot market during the first six months of 2005 with the remainder being sold under longer term contracts. Bruce Power’s operating expenses increased to $46 per MWh in second quarter 2005 from $30 per MWh in second quarter 2004. This $16 per MWh increase was due to reduced output and increased outage costs, primarily related to the Unit 7 and Unit 4 planned maintenance outages as well as the forced outage at Unit 6. Adjustments to TCPL’s interest in Bruce Power’s income before income taxes for the three and six months ended June 30, 2005 were lower than in 2004 primarily due to lower amortization of the purchase price allocated to the fair value of sales contracts in place at the time of acquisition. The six months ended June 30, 2005 adjustment was also lower due to the cessation of interest capitalization upon the return to service of Unit 3 in March 2004.

Pre-tax equity income for the six months ended June 30, 2005 was $43 million compared to $96 million for the same period in 2004. Effective March 1, 2004, Bruce Power moved from a five-unit operation to a six-unit operation with the commercial startup of Unit 3. Planned maintenance outages, as well as the forced outage due to the April 15, 2005 transformer fire at Unit 6 and other minor forced outages, reduced the otherwise potential increase in total plant output as a result of adding a sixth operating unit. This lower output resulted in reduced sales revenue from that

achieved in 2004 which was partially offset by higher realized sales prices for the six months ended June 30, 2005. Bruce Power’s operating expenses increased to $42 per MWh for the six months ended June 30, 2005 from $31 per MWh for the same period in 2004. This was the result of reduced output as well as higher maintenance costs, higher depreciation and lower capitalization of labour and other in-house costs following the restart of Unit 3.

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 36 per cent of planned output for the balance of 2005. Bruce Power expects a two month planned maintenance outage on Unit 5 in fourth quarter 2005. Overall plant availability for Bruce Power in 2005 is expected to remain at 83 per cent.

In June 2005, Bruce Power made a $50 million cash distribution to its partners (TCPL’s share was $16 million). The partners have agreed that all excess cash will be distributed on a monthly basis and that separate cash calls will be made for major capital projects.

Bruce Power continues to negotiate an agreement with the Ontario government for the potential restart of Units 1 and 2 at Bruce Power.

Power LP Investment

Power LP’s operating and other income of $8 million and $17 million for the three and six months ended June 30, 2005, was $2 million and $1 million higher, respectively, compared to the same

periods in 2004. The increase was primarily due to additional earnings from Power LP’s 2004 acquisitions of the Curtis Palmer, ManChief, Mamquam and Queen Charlotte facilities. Partially offsetting this increase was TCPL’s reduced ownership interest in Power LP in 2004 and the effect of 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, TCPL was recognizing the amortization of these deferred gains into income over a period through to 2017.

General, Administrative, Support Costs and Other

General, administrative, support costs and other of $26 million in second quarter 2005 and $51 million for the six months ended June 30, 2005 were both $2 million higher compared to the same periods

in 2004 primarily due to the negative impact of TCPL’s proportionate share of Power LP’s unrealized foreign exchange losses on its U.S. dollar denominated debt.

Power Sales Volumes and Plant Availability

Power SalesVolumes
(unaudited)	Three months ended June 30		Six months ended June 30
(GWh)	2005	2004	2005	2004
Western operations (1)	2,838	2,929	6,036	5,805
Eastern operations (1)	1,456	1,474	2,711	3,085
Bruce Power investment (2)	2,306	2,962	4,904	5,492
Power LPinvestment (1) (3)	723	536	1,420	1,108
Total	7,323	7,901	15,071	15,490

(1) ManChief and Curtis Palmer volumes are included in Power LP investment effective April 30, 2004.

(2) Sales volumes reflect TCPL’s 31.6 per cent share of Bruce Power output.

(3) TCPL operates and manages Power LP. The volumes in the table represent 100 percent of Power LP’s sales volumes.

Weighted Average Plant Availability (1)	Three months ended June 30				Six months ended June 30
(unaudited)	2005		2004		2005		2004

Western operations (2)	83	%	93	%	88	%	96	%
Eastern operations (2)	80	%	95	%	79	%	97	%
Bruce Power investment (3)	71	%	92	%	76	%	86	%
Power LP investment (2)	87	%	96	%	92	%	97	%
All plants, excluding Bruce Power investment	83	%	95	%	86	%	97	%
All plants	79	%	94	%	82	%	92	%

(1) Plant availability represents the percentage of time in the period 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) Unit 3 is included effective March 1, 2004.

Corporate

Net expenses for the three and six months ended June 30, 2005 were $8 million and $17 million, respectively, compared to net expenses of $7 million for each of the corresponding periods in 2004.

For the three months ended June 30, 2005, net expenses were comparable to the same period in the prior year. Income tax refunds and positive tax adjustments in second quarter 2005 were offset by tax adjustments recorded in second quarter 2004 and higher interest expense on long-term debt that was issued in late 2004 and on higher commercial paper balances in 2005.

The $10 million increase for the six months ended June 30, 2005 compared to the same period in 2004 was primarily due to increased

interest expense on long-term debt that was issued in 2004 as well as on higher commercial paper balances in 2005. Income tax refunds and related interest in the six months ended June 30, 2004 were comparable to income tax refunds and positive tax adjustments recorded in the six months ended June 30, 2005.

Liquidity and Capital Resources

Funds Generated from Operations

Funds generated from operations were $478 million and $885 million for the three and six months ended June 30, 2005, respectively, compared with $382 million and $797 million for the same periods in 2004.

TCPL expects that its ability to generate adequate amounts of cash in the short term and the long term, when needed, and to maintain financial capacity and flexibility to provide for planned growth remains substantially unchanged since December 31, 2004.

Investing Activities

In the three and six months ended June 30, 2005, capital expenditures, excluding acquisitions, totalled $135 million (2004 - $93 million) and $243 million (2004 - $194 million), respectively, and related primarily to construction of new power plants, and maintenance and capacity capital in the Gas Transmission business.

In the three and six months ended June 30, 2005, disposition of assets generated $2 million (2004 - $408 million) and $153 million (2004 - $408 million), respectively. The disposition in 2005 related to the sale of PipeLines LP units and the dispositions in 2004 related primarily to the sale of ManChief and Curtis Palmer to Power LP.

Acquisitions for the three and six months ended June 30, 2005 were $632 million (2004 – $14 million) and related to the purchase of USGen hydro assets and the acquisition of an additional 3.52 per cent interest in Iroquois Gas Transmission System L.P. (Iroquois).

Financing Activities

TCPL retired $615 million and $936 million of long-term debt in the three and six months ended June 30, 2005, respectively. TCPL issued $499 million and $799 million of long-term debt in the three and six months ended June 30, 2005, respectively. Please refer to Other Recent Developments – Other for further information on long-term debt. For the six months ended June 30, 2005, outstanding notes payable increased by $533 million, while cash and short-term investments increased by $22 million.

Dividends

On July 28, 2005, TCPL’s Board of Directors declared a dividend for the quarter ending September 30, 2005 in an aggregate amount equal to the aggregate quarterly dividend to be paid on October 31, 2005 by TransCanada Corporation on the issued and outstanding common shares as at the close of business on September 30, 2005. The Board also declared regular dividends on TCPL’s preferred shares.

Contractual Obligations

Primarily as a result of new contracts in the six months ended June 30, 2005, Power’s future purchase obligations are estimated at June 30, 2005 to be as follows.

Purchase Obligations
(unaudited - millions of dollars)	2005 (1)	2006	2007	2008	2009	2010+
Power
Commodity purchases (2)	393	632	627	556	278	2,658
Capital expenditures (3)	269	181	66	1	1	—
Other (4)	24	43	32	23	28	113
	686	856	725	580	307	2,771

(1) Includes purchase obligations for the six months ending December 31, 2005.

(2) Commodity purchases include fixed and variable components. The variable components are estimates and are subject to variability in plant production, market prices, and regulatory tariffs.

(3) Amounts are estimates and are subject to variability based on timing of construction and project enhancements.

(4) Includes estimates of certain amounts which are subject to change depending on plant fired hours, the consumer price index, actual plant maintenance costs, plant salaries as well as changes in regulated rates for transportation.

There have been no other material changes to TCPL’s contractual obligations from December 31, 2004 to June 30, 2005, including payments due for the next five years and thereafter. For further information on these contractual obligations, refer to the MD&A in TCPL’s 2004 Annual Report.

Financial and Other Instruments

The following represents the material changes to the company’s financial instruments since December 31, 2004.

Energy Price Risk Management

The company executes power, natural gas and heat rate derivatives in order to manage exposure and risks associated with its overall asset portfolio. Heat rate contracts are contracts for the sale

or purchase of power that are priced based on a natural gas index. The fair values and notional volumes of the swap, option, future and heat rate contracts are shown in the tables below. In accordance with the company’s accounting policy, each of the derivatives in the table below is recorded on the balance sheet at its fair value at June 30, 2005 and December 31, 2004.

Power

		June 30, 2005
		(unaudited)		December 31, 2004
Asset/(Liability)	Accounting	Fair		Fair
(millions of dollars)	Treatment	Value		Value

Power - swaps
(maturing 2005 to 2011)	Hedge	(60	)	7
(maturing 2005 to 2010)	Non-hedge	2		(2	)
Gas - swaps, futures and options
(maturing 2005 to 2016)	Hedge	(27	)	(39	)
(maturing 2005 to 2006)	Non-hedge	1		(2	)
Heat rate contracts
(maturing 2005 to 2006)	Hedge	—		(1	)

Notional Volumes
June 30, 2005	Accounting	Power (GWh)		Gas (Bcf)
(unaudited)	Treatment	Purchases	Sales	Purchases	Sales

Power - swaps
(maturing 2005 to 2011)	Hedge	1,299	7,177	—	—
(maturing 2005 to 2010)	Non-hedge	878	—	—	—
Gas - swaps, futures and options
(maturing 2005 to 2016)	Hedge	—	—	85	73
(maturing 2005 to 2006)	Non-hedge	—	—	5	7
Heat rate contracts
(maturing 2005 to 2006)	Hedge	—	55	—	—

Notional Volumes	Accounting	Power (GWh)		Gas (Bcf)
December 31, 2004	Treatment	Purchases	Sales	Purchases	Sales

Power - swaps	Hedge	3,314	7,029	—	—
	Non-hedge	438	—	—	—

Gas - swaps, futures and options	Hedge	—	—	80	84
	Non-hedge	—	—	5	8

Heat rate contracts	Hedge	—	229	2	—

Risk Management

TCPL’s market, financial and counterparty risks remain substantially unchanged since December 31, 2004. For further information on risks, refer to the MD&A in TCPL’s 2004 Annual Report.

Controls and Procedures

As of the end of the period covered by this quarterly report, TCPL’s management, together with TCPL’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 TCPL have concluded that the disclosure controls and procedures are effective.

There were no changes in TCPL’s internal control over financial reporting during the most recent fiscal quarter that have materially affected or are reasonably likely to materially affect TCPL’s internal control over financial reporting.

Critical Accounting Policy

TCPL’s critical accounting policy, which remains unchanged since December 31, 2004, is the use of regulatory accounting for its regulated operations. For further information on this critical accounting policy, refer to the MD&A in TCPL’s 2004 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. TCPL’s critical accounting estimate from December 31, 2004 continues to be depreciation expense. For further information on this critical accounting estimate, refer to the MD&A in TCPL’s 2004 Annual Report.

Accounting Change

Financial Instruments – Disclosure and Presentation

Effective January 1, 2005, the company adopted the provisions of the Canadian Institute of Chartered Accountants’ amendment to the existing Handbook Section “Financial Instruments – Disclosure and Presentation” which provides guidance for classifying certain financial instruments that embody obligations that may be settled by issuance of the issuer’s equity shares as debt when the instrument does not establish an ownership relationship. In accordance with this amendment, TCPL reclassified the non-controlling interest component of preferred securities as long-term debt.

This accounting change was applied retroactively with restatement of prior periods. The impact of this change on TCPL’s net income in second quarter 2005 and prior periods was nil.

The impact of the accounting change on the company’s consolidated balance sheet as at December 31, 2004 is as follows.

(unaudited - millions of dollars)	Increase/(Decrease)
Deferred Amounts (1)	135
Preferred Securities	535
Non-Controlling Interest Preferred securities of subsidiary	(670	)
Total Liabilities and Shareholders’ Equity	—

(1) Regulatory deferral

U.S. GAAP Restatement

In second quarter 2005, the company restated Note 23 (U.S. GAAP) to the 2004 consolidated financial statements. TCPL records its investment in Power LP using the proportionate consolidation method for Canadian generally accepted accounting principles (GAAP) purposes and as an equity investment for U.S. GAAP purposes. During the period from 1997 to April 2004, the company was obligated to fund the redemption of Power LP units in 2017. As a result, under both Canadian and U.S. GAAP, TCPL accounted for the issuance of units by Power LP to third parties as a sale of a future net revenue stream and the resulting gains were deferred and amortized to income over the period to 2017. The redemption obligation was removed in April 2004 and the unamortized gains were recognized as income.

For U.S. GAAP purposes, under the provisions of the U.S. Securities and Exchange Commission’s Staff Accounting Bulletin Topic 5:H, certain transactions involving Power LP, in the period 1997 to 2001, should have been accounted for as dilution gains rather than as sales of a future net revenue stream. As the company was committed to fund the redemption of the Power LP units, these gains should have been recorded, on an after-tax basis, as equity transactions in shareholders’ equity. This has been corrected on a retroactive basis. The correction had no impact on the accumulated shareholders’ equity at December 31, 2004 for U.S. GAAP purposes. The impact on previously reported income amounts for U.S. GAAP purposes is as follows.

(millions of dollars)	2004	2003	2002
Decrease in:
Income from continuing operations	135	10	10

Net Income Applicable to Common Shares	135	10	10

TCPL’s restated 2004 audited consolidated financial statements will be available in Canada on SEDAR at www.sedar.com and in the U.S. on EDGAR at www.sec.gov. under TransCanada PipeLines Limited and are available on the company’s website at www.transcanada.com.

Outlook

In 2005, the company expects higher net income from the Gas Transmission segment than originally anticipated as a result of the $49 million after-tax gain related to the sale of PipeLines LP units. In addition, the company expects higher Power net income in 2005 than originally anticipated as a result of the expected gains on sale of the Power LP of approximately $200 million after tax and the company’s investment in PT Paiton Energy Company (Paiton Energy) of approximately $115 million after tax. For further information on these transactions, please refer to Other Recent Developments. Excluding these impacts, the company’s outlook is relatively unchanged since December 31, 2004. For further information on outlook, refer to the MD&A in TCPL’s 2004 Annual Report.

In 2005, TCPL will continue to direct its resources towards long-term growth opportunities that will strengthen its financial performance and create long-term value for shareholders. The company’s net income and cash flow combined with a strong balance sheet continue to provide the financial flexibility for TCPL 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

Canadian Mainline

In November 2004, the Canadian Association of Petroleum Producers (CAPP) filed an application with the NEB to review and vary its decision on the Canadian Mainline’s 2004 Tolls and Tariff Application with respect to three items:

• non-renewable firm transportation (FT-NR) service;

• long-term incentive compensation; and

• regulatory and legal costs.

On February 18, 2005, the NEB decided to review its decision on the tolls to be charged for FT-NR, not to review its decision on disputed regulatory and legal costs and, at CAPP’s request, to

defer its consideration of a review of its decision regarding long-term incentive compensation. On April 13, 2005, CAPP filed notice with the NEB to withdraw the portion of its application dealing with long-term incentive compensation. The NEB heard oral arguments in Calgary in late April 2005 to consider tolling issues with respect to FT-NR. In a decision issued May 30, 2005, the NEB overturned its initial ruling that FT-NR be tolled on a biddable basis with a floor price equal to the 100 per cent load factor toll for Firm Transportation (FT) Service and determined that it should be offered at the same toll as FT.

In April 2005, TCPL received the NEB’s decision on the Canadian Mainline’s 2004 Tolls and Tariff Application (Phase II). The NEB, in its decision, approved an increase in the deemed common equity component of the Canadian Mainline’s capital structure from 33 per cent to 36 per cent for 2004 which is also effective for 2005 under the 2005 tolls settlement with shippers. This increase in the common equity component is expected to increase TCPL’s 2005 net earnings by approximately $29 million, of which $13 million relates to 2004 and $16 million relates to 2005.

The return on equity for the Canadian Mainline remains at 9.56 per cent for 2004 and 9.46 per cent for 2005.

On May 30, 2005, in compliance with the NEB’s decision regarding TCPL’s 2004 Mainline Tolls and Tariff Application(Phase II), TCPL filed a separate final tolls application with the NEB for 2004 and 2005. On June 23, 2005, the NEB issued its decision approving the 2004 and 2005 final tolls applications as filed.

Alberta System

On June 7, 2005, the EUB granted approval of a negotiated settlement for the Alberta System’s 2005-2007 Revenue Requirement. As stipulated in the settlement, following the approval of the settlement, TCPL withdrew its motion filed with the Alberta Court of Appeal for leave to appeal Decision 2004-069 which dealt with Phase I of the 2004 General Rate Application (GRA). TCPL also agreed that it would not pursue a review and variance application on the EUB’s findings regarding incentive compensation and long-term incentive costs.

TCPL will continue to charge interim tolls for 2005 for transportation service on the Alberta System. The interim tolls, approved by the EUB in December 2004, will remain in effect until final tolls are established following the Phase II proceeding of the Alberta System’s 2005 GRA. In this second phase of the EUB’s rate making process, the allocation of 2005 approved costs among transportation services and rate design are determined. The EUB has scheduled a hearing for Phase II during fourth quarter 2005.

option on April 1, 2005. Although the option was exercised, closing remains subject to certain regulatory approvals as well as other conditions specified in the option agreement. The Vermont Public Service Board issued its approval in June 2005, which approval was conditioned on a further vote of Town residents in which at least a majority of the votes cast had to approve the transaction. On July 12, 2005, the vote took place but did not achieve the requisite majority. That rejection does not, of itself, terminate the option. The Town is scheduled to have another vote on this matter in August 2005.

Power LP

In May 2005, TCPL announced that it had entered into an agreement with EPCOR Utilities Inc. (EPCOR) whereby EPCOR will purchase TCPL’s interest in Power LP for $529 million. EPCOR’s acquisition includes 14.5 million units of Power LP, representing 30.6 per cent of the outstanding units; 100 per cent ownership of the General Partner of Power LP; and management and operations’ agreements governing the ongoing operation of Power LP’s generation assets.

The Boards of Directors of each of TCPL, EPCOR and Power LP have approved this transaction. This transaction is expected to close in third quarter 2005 pending receipt of regulatory approvals. TCPL expects to realize an after-tax gain of approximately $200 million from this sale. TCPL will continue to operate and maintain Power LP’s power plants until closing.

Paiton Energy

In June 2005, TCPL reached an agreement to sell its approximate 11 per cent interest in Paiton Energy to subsidiaries of The Tokyo Electric Power Company for US$103 million ($127 million), subject to adjustments. TCPL originally purchased its interest in Paiton Energy in 1996. Paiton Energy owns two 615 megawatt coal-fired plants in East Java, Indonesia. Pending various approvals, this transaction is expected to close in third quarter 2005. Upon closing, TCPL expects to realize an after-tax gain of approximately $115 million.

Other

On June 1, 2005, Gas Transmission Northwest Corporation (GTNC) redeemed all of its outstanding US$150 million 7.80 per cent Senior Unsecured Debentures (Debentures) and US$250 million 7.10 per cent Senior Unsecured Notes. As a consequence, upon application by GTNC, the Debentures were de-listed from the New York Stock Exchange and GTNC no longer has any securities registered under U.S. securities laws.

Tamazunchale Pipeline Project

Power LP