Exhibit 13.1

Management’s Discussion and Analysis

The Management’s Discussion and Analysis (MD&A) dated April 26, 2007 should be read in conjunction with the accompanying unaudited Consolidated Financial Statements of TransCanada Corporation (TransCanada or the Company) for the three months ended March 31, 2007. It should also be read in conjunction with the audited Consolidated Financial Statements and notes thereto, and the MD&A contained in TransCanada’s 2006 Annual Report for the year ended December 31, 2006. 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. Amounts are stated in Canadian dollars unless otherwise indicated. Capitalized and abbreviated terms that are used but not otherwise defined herein are identified in the Glossary of Terms contained in TransCanada’s 2006 Annual Report.

Forward-Looking Information

This MD&A may contain certain information that is forward looking and is subject to important risks and uncertainties. The words “anticipate”, “expect”, “may”, “should”, “estimate”, “project”, “outlook”, “forecast” or other similar words are used to identify such forward-looking information. All forward-looking statements are based on TransCanada’s beliefs and assumptions based on information available at the time such statements were made. 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, changes in environmental and other laws and regulations, competitive factors in the pipeline and energy industry sectors, construction and completion of capital projects, access to capital markets, interest and currency exchange rates, technological developments and the current economic conditions in North America. By its nature, such forward-looking information is subject to various risks and uncertainties which could cause TransCanada’s actual results and experience to differ materially from the anticipated results or other expectations expressed. For additional information on these and other factors, see the reports filed by TransCanada with Canadian securities regulators and with the U.S. Securities and Exchange Commission. Readers are cautioned not to place undue reliance on this forward-looking information, which is given as of the date it is expressed in this MD&A or otherwise, and TransCanada undertakes no obligation to update publicly or revise any forward-looking information, whether as a result of new information, future events or otherwise, except as required by law.

Non-GAAP Measures

The Company uses the measures “comparable earnings”, “comparable earnings per share”, “funds generated from operations” and “operating income” in this MD&A. These measures do not have any standardized meaning prescribed by generally accepted accounting principles (GAAP) and are therefore considered to be non-GAAP measures. These measures are unlikely to be comparable to similar measures presented by other entities. These measures have been used to provide readers with additional information on the Company’s operating performance, liquidity and its ability to generate funds to finance its operations.

Comparable earnings is comprised of net income from continuing operations adjusted for specified items that are significant and not typical of the Company’s operations. Specified items may include, but are not limited to certain income tax refunds and adjustments, gains or losses on sales of assets, legal settlements and bankruptcy settlements received from former customers. A reconciliation of comparable earnings to net income is presented in the Consolidated Results of Operation section in this MD&A. Comparable earnings per share is calculated by dividing comparable earnings by the weighted average number of shares outstanding for the period.

Funds generated from operations is comprised of net cash provided by operations before changes in operating working capital. A reconciliation of funds generated from operations to net cash provided by operations is presented in the Liquidity and Capital Resources section in this MD&A. Operating income is used in the Energy segment and is comprised of revenues less operating expenses as shown on the consolidated income statement. Refer to the Energy section in this MD&A for a reconciliation of operating income to net earnings.

Acquisitions

ANR and Great Lakes

On February 22, 2007, TransCanada acquired American Natural Resources Company and the ANR Storage Company (together ANR) and an additional 3.55 per cent interest in Great Lakes from El Paso Corporation for approximately US$3.4 billion, subject to certain post-closing adjustments, including US$491 million of assumed long-term debt. The acquisition of ANR added approximately 17,000 kilometres (km) of natural gas transmission pipeline with a peak-day capacity of 6.8 billion cubic feet per day (Bcf/d). ANR also owns and operates natural gas storage facilities with a total capacity of approximately 230 billion cubic feet (Bcf). TransCanada began consolidating ANR and Great Lakes in the Pipelines segment subsequent to the acquisition date. The acquisition was financed with a combination of proceeds from the Company’s recent equity offering, cash on hand and funds drawn on existing and newly established loan facilities. The equity offering and debt financings are discussed in the Liquidity and Capital Resources section in this MD&A.

Great Lakes

On February 22, 2007, PipeLines LP acquired a 46.45 per cent interest in Great Lakes from El Paso Corporation for approximately US$942 million, which included US$209 million of assumed long-term debt, subject to certain post-closing adjustments. The acquisition was financed with debt from new and existing facilities, which is discussed in the Liquidity and Capital Resources section in this MD&A, and a private placement offering, discussed below.

In February 2007, PipeLines LP completed a private placement offering of 17,356,086 common units at a price of US$34.57 per unit, of which 50 per cent were acquired by TransCanada for US$300 million. Additionally, TransCanada invested US$12 million to maintain its general partnership ownership interest in PipeLines LP. As a result of TransCanada’s additional investments in PipeLines LP, its ownership interest in PipeLines LP increased to 32.1 per cent from 13.4 per cent. The total private placement plus TransCanada’s additional investment resulted in gross proceeds to PipeLines LP of US$612 million, which were used to partially finance its Great Lakes acquisition.

Consolidated Results of Operations

Reconciliation of Comparable Earnings to Net Income

Three months ended March 31
(unaudited)
(millions of dollars except per share amounts)	2007			2006

Pipelines
Comparable earnings	155			139
Specified item:
Bankruptcy settlement with Mirant	—			18
Net earnings	155			157

Energy	106			100

Corporate
Comparable expenses	(11		)	(12		)
Specified item:
Corporate income tax adjustments	15			—
Net earnings/(expenses)	4			(12		)
Net Income
Continuing operations (1)	265			245
Discontinued operations	—			28
Net Income	265			273

Net Income Per Share
Continuing operations (2)	$	0.52		$	0.50
Discontinued operations	—			0.06
Basic	$	0.52		$	0.56
Diluted	$	0.52		$	0.56

(1) Comparable Earnings	250		227
Specified items (net of tax, where applicable):
Bankruptcy settlement with Mirant	—		18
Corporate income tax adjustments	15		—
Net Income from Continuing Operations	265		245

(2) Comparable Earnings Per Share	$	0.49	$	0.46
Specified items - per share
Bankruptcy settlement with Mirant	—		0.04
Corporate income tax adjustments	0.03		—
Net Income Per Share from Continuing Operations	$	0.52	$	0.50

TransCanada’s net income for first quarter 2007 was $265 million or $0.52

per share compared to $273 million or $0.56 per share for first quarter 2006. Net income from continuing operations (net earnings) for the same period in 2007 was $265 million, or $0.52 per share, compared to $245 million or $0.50 per share, in 2006. The 2007 net earnings were higher than 2006 by $20 million, primarily due to income from the acquisition of ANR, start-up of the Bécancour cogeneration plant and the commencement of operations of Tamazunchale. Net earnings also increased due to positive adjustments in the first quarter of 2007, including the resolution of certain income tax matters and an internal restructuring. Comparable earnings for first quarter 2007 was $250 million or $0.49 per share, compared to $227 million or $0.46 per share for the same period in 2006. Comparable earnings excluded positive income tax adjustments of $15 million in first quarter 2007. In first quarter 2006, comparable earnings excluded an $18 million ($29 million pre-tax) bankruptcy settlement with Mirant Corporation and certain of its subsidiaries (Mirant), a former shipper on the Gas Transmission Northwest System.

TransCanada’s net income for the three months ended March 31, 2006 included net income from discontinued operations of $28 million or $0.06 per share reflecting bankruptcy settlements with Mirant received in first quarter 2006 related to TransCanada’s Gas Marketing business divested in 2001.

Results from each business segment for the three months ended March 31, 2007 are discussed further in the Pipelines, Energy and Corporate sections of this MD&A.

Funds generated from operations of $582 million for the three months ended March 31, 2007 increased $65 million when compared to the same period in 2006.

Pipelines

The Pipelines business generated net earnings of $155 million for the three months ended March 31, 2007, compared to $157 million for the same period in 2006.

Pipelines Results-at-a-Glance

Three months ended March 31
(unaudited)
(millions of dollars)	2007		2006

Wholly Owned Pipelines
Canadian Mainline	57		59
Alberta System	31		33
ANR (1)	21		—
GTN	11		32
Foothills (2)	6		7
	126		131
Other Pipelines
Great Lakes (3)	14		12
Iroquois	5		4
Portland	5		6
PipeLines LP (4)	2		1
Ventures LP	3		3
TQM	2		2
TransGas	3		3
Tamazunchale	3		—
Northern Development	(1	)	(1	)
General, administrative, support costs and other	(7	)	(4	)
	29		26
Net Earnings	155		157

(1) ANR includes results of operations since February 22, 2007.

(2) Foothills reflects the combined operations of Foothills and the BC System.

(3) Great Lakes’ results reflect TransCanada’s 53.55 per cent ownership in Great Lakes since February 22, 2007.

(4) PipeLines LP’s results include TransCanada’s effective ownership of an additional 15 per cent in Great Lakes as a result of TransCanada's 32.1 per cent interest in PipeLines LP since February 22, 2007.

Wholly Owned Pipelines

Canadian Mainline’s first quarter 2007 net earnings decreased $2 million compared to first quarter 2006. The decrease was primarily due to a lower investment base and a lower rate of return on common equity (ROE) as determined by the National Energy Board (NEB) of 8.46 per cent in 2007, compared to 8.88 per cent in 2006, on a deemed common equity ratio of 36 per cent.

The Alberta System’s net earnings for first quarter 2007 decreased $2 million compared to the same period in 2006. The decrease was primarily due to a lower investment base and a lower ROE in 2007. Net earnings in 2007 reflect an ROE of 8.51 per cent on a deemed common equity ratio

of 35 per cent compared to an ROE of 8.93 per cent on a deemed common equity ratio of 35 per cent in 2006.

TransCanada completed the acquisition of ANR on February 22, 2007 and included net earnings from this date. ANR’s revenues are primarily derived from its interstate natural gas transmission, storage, gathering and related services.

GTN’s net earnings for the three months ended March 31, 2007 decreased $21 million from the same period in 2006 primarily due to the receipt of the $18 million bankruptcy settlement ($29 million pre-tax) in first quarter 2006 with Mirant, a former shipper on the Gas Transmission Northwest System. Also contributing to the decrease are lower operating revenues in 2007 due to lower contracted long-term firm volumes and a provision taken in first quarter 2007 for non-payment of contract transportation revenues from a subsidiary of Calpine Corporation (Calpine) that filed for bankruptcy protection.

Operating Statistics

Gas

Canadian

Alberta

ANR

Transmission
Northwest

Three months ended March 31

Mainline(1)

System(2)

(3) (4)

System(3)

Foothills System (5)

(unaudited)

2007

2006

2007

2006

2007

2006

2007

2006

Average investment base
($ millions)

7,401

7,471

4,261

4,319

n/a

n/a

818

870

Delivery volumes (Bcf)

Total

881

829

1,070

1,062

172

193

171

356

345

Average per day

9.8

9.2

11.9

11.8

4.6

2.1

1.9

4.0

3.8

(1) Canadian Mainline deliveries originating at the Alberta border and in Saskatchewan for the three months ended March 31, 2007 were 576 Bcf (2006 - 584 Bcf); average per day was 6.4 Bcf (2006 - 6.5 Bcf).

(2) Field receipt volumes for the Alberta System for the three months ended March 31, 2007 were 1,005 Bcf (2006 - 1,021 Bcf); average per day was 11.2 Bcf (2006 - 11.3 Bcf).

(3) ANR and the Gas Transmission Northwest System operate under a fixed rate model approved by the United States Federal Energy Regulatory Commission (FERC) and, as a result, the systems’ current results are not dependent on average investment base.

(4) ANR includes results of operations since February 22, 2007.

(5) Foothills reflects the combined operations of Foothills and the BC System.

Other Pipelines

TransCanada’s proportionate share of net earnings from Other Pipelines was $29 million for the three months ended March 31, 2007 compared to $26 million for the same period in 2006. The increase was mainly due to earnings from the Tamazunchale pipeline, which commenced operations in December 2006, and increased earnings from Great Lakes reflecting an effective 19 per cent increase in ownership interest. These increases were partially offset by the impact of higher project development and support costs in 2007.

As at March 31, 2007, TransCanada had advanced $125 million to the Aboriginal Pipeline Group with respect to the Mackenzie Gas Pipeline Project and had capitalized $43 million related to the Keystone pipeline.

Energy

Energy’s net earnings of $106 million in first quarter 2007 increased $6 million compared to $100 million in first quarter 2006.

Energy Results-at-a-Glance

Three months ended March 31
(unaudited)
(millions of dollars)	2007		2006

Bruce Power	29		63
Western Power Operations	73		58
Eastern Power Operations	67		49
Natural Gas Storage	30		22
General, administrative, support costs and other	(36	)	(30	)
Operating income	163		162
Financial charges	(4	)	(7	)
Interest income and other	3		2
Income taxes	(56	)	(57	)
Net Earnings	106		100

Bruce Power

Bruce Power Results-at-a-Glance(1)

Three months ended March 31
(unaudited)	2007			2006
Bruce Power (100 per cent basis) (millions of dollars)
Revenues
Power	460			479
Other (2)	20			17
	480			496
Operating expenses
Operations and maintenance	(295		)	(220		)
Fuel	(25		)	(20		)
Supplemental rent	(43		)	(43		)
Depreciation and amortization	(36		)	(31		)
	(399		)	(314		)
Operating Income	81			182

TransCanada’s proportionate share	31			62
Adjustments	(2		)	1
TransCanada’s operating income from Bruce Power	29			63

Bruce Power — Other Information
Plant availability
Bruce A	90		%	78		%
Bruce B	78		%	95		%
Combined Bruce Power	82		%	90		%
Sales volumes (GWh) (3)
Bruce A — 100 per cent	2,910			2,520
Bruce B — 100 per cent	5,430			6,620
Combined Bruce Power — 100 per cent	8,340			9,140
TransCanada’s proportionate share	3,129			3,306
Results per MWh (4)
Bruce A revenues	$	59		$	57
Bruce B revenues	$	53		$	50
Combined Bruce Power revenues	$	55		$	52
Combined Bruce Power fuel	$	3		$	2
Combined Bruce Power operating expenses (5)	$	47		$	34
Percentage of output sold to spot market (6)	35		%	38		%

(1) All information in the table includes adjustments to eliminate the effects of inter-partnership transactions between Bruce A and Bruce B.

(2) Includes fuel cost recoveries for Bruce A of $8 million for first quarter 2007 and $6 million for first quarter 2006.

(3) Gigawatt hours.

(4) Megawatt hours.

(5) Net of fuel cost recoveries.

(6) Represents the percentage of volumes sold into the short-term power market and are subject to spot market price volatility.

TransCanada’s operating income of $29 million from its investment in Bruce Power decreased $34 million in first quarter 2007 compared to first quarter 2006, primarily due to lower generation volumes and higher operating costs associated with additional planned outage days. The increase in Bruce Power’s operations and maintenance expense is primarily due to the significant increase in planned outage days from 86 reactor days in first quarter 2007, compared to only 30 days in first quarter 2006. In addition, higher post-employment benefit costs contributed to higher operating costs. These impacts were partially offset by higher realized prices.

TransCanada’s share of Bruce Power’s generation for first quarter 2007 decreased 177 GWh to 3,129 GWh, compared to first quarter 2006 generation of 3,306 GWh, as a result of an increase in planned maintenance outage days in first quarter 2007. Bruce Power prices achieved during first quarter 2007 (excluding other revenues) were $55 per MWh, compared to $52 per MWh in first quarter 2006. Bruce Power’s combined operating expenses (net of fuel cost recoveries) in first quarter 2007 increased to $47 per MWh from $34 per MWh in first quarter 2006 primarily due to higher outage and other operating costs combined with lower output in first quarter 2007.

Approximately 86 reactor days of planned maintenance outages as well as approximately 4 reactor days of unplanned outages occurred on the six operating units in first quarter 2007. In first quarter 2006, Bruce Power experienced approximately 30 reactor days of planned maintenance outages and 13 reactor days of unplanned outages. The Bruce Power units ran at a combined average availability of 82 per cent in first quarter 2007, compared to a 90 per cent average availability in first quarter 2006.

The overall plant availability percentage in 2007 is expected to be in the low 90s for the four Bruce B units and in the mid 70s for the two operating Bruce A units. Two planned outages are scheduled for Bruce A Unit 3 in 2007, with the first outage expected to last one month in second quarter 2007 and a second outage expected to last approximately two months beginning in late third quarter 2007. A planned one month outage for Bruce A Unit 4 and a planned two and a half month maintenance outage for Bruce B Unit 6 were both completed in April 2007.

Income from Bruce B is directly impacted by the fluctuations in wholesale spot market prices for electricity. Income from both Bruce A and Bruce B units is impacted by overall plant availability, which in turn is impacted by scheduled and unscheduled maintenance. As a result of a contract with the Ontario Power Authority (OPA), all of the output from Bruce A in first quarter 2007 was sold at a fixed price of $58.63 per MWh (before recovery of fuel costs from the OPA) compared to $57.37 per MWh in first quarter 2006. In addition, sales from the Bruce B Units 5 to 8 were subject to a floor price of $45.99 per MWh in first quarter 2007 and $45.00 per MWh in first quarter 2006. Both of these reference prices are adjusted annually for inflation on April 1. Effective April 1, 2007, the Bruce A price is $59.69 per MWh and the Bruce B floor price is $46.82 per MWh. Payments received pursuant to the Bruce B floor price mechanism may be subject to a recapture payment dependent on annual spot prices over the term of the contract. Bruce B net earnings included no amounts received under this floor mechanism to date. To further reduce its exposure to spot market prices, Bruce B has entered into fixed price sales contracts to sell forward approximately 5,900 GWh of output for the remainder of 2007 and 5,400 GWh for 2008.

The capital cost of Bruce A’s four-unit, seven-year restart and refurbishment project is expected to total approximately $4.25 billion with TransCanada’s share being approximately $2.125 billion. As at March 31, 2007, Bruce A had incurred $1.338 billion with respect to the restart and refurbishment project. The Bruce A restart project remains on schedule and on budget.

Western Power Operations
Western Power Operations Results-at-a-Glance

Three months ended March 31
(unaudited)
(millions of dollars)	2007		2006

Revenues
Power	286		275
Other (1)	28		64
	314		339
Commodity purchases resold
Power	(179	)	(190	)
Other (1)	(23	)	(48	)
	(202	)	(238	)
Plant operating costs and other	(34	)	(38	)
Depreciation	(5	)	(5	)
Operating income	73		58

(1) Other includes Cancarb Thermax and natural gas.

Western Power Operations Sales Volumes

Three months ended March 31
(unaudited)
(GWh)	2007	2006

Supply
Generation	592	585
Purchased
Sundance A & B and Sheerness PPAs	3,253	3,391
Other purchases	449	486
	4,294	4,462
Contracted vs. Spot
Contracted (1)	3,492	3,164
Spot (2)	802	1,298
	4,294	4,462

(1) Represents volumes sold to wholesale, commercial and industrial customers under short-and long-term contracts at predetermined prices.

(2) Represents volumes sold into the short-term power market and are subject to spot market price volatility.

Western Power Operations’ operating income of $73 million in first quarter 2007 increased $15 million compared to the $58 million earned in first quarter 2006. This increase was primarily due to increased margins from higher overall realized power prices on both contracted and uncontracted volumes of power sold. Average spot market power prices in Alberta increased 12 per cent, or $6.85 per MWh, in first quarter 2007 compared to first quarter 2006. The power price increase was also the main contributor to an approximately 15 per cent increase in market heat rates in first quarter 2007 as average spot market natural gas prices remained relatively unchanged from first quarter 2006. The market heat rate is determined by dividing the average price of power per MWh by the

average price of natural gas per gigajoule (GJ) for a given period. Western Power Operations’ revenues increased in first quarter 2007, compared to first quarter 2006, primarily due to the higher overall power sales prices realized in first quarter 2007 and slightly higher generation volumes, while commodity purchases resold decreased $11 million due to a decrease in purchased power volumes. Other revenues and commodity purchases resold decreased in first quarter 2007, compared to first quarter 2006, due to increased natural gas transactions recorded in first quarter 2006. Western Power Operations manages the sale of its supply volumes on a portfolio basis. A portion of its supply is held for sale in the spot market for operational reasons and is dependent upon the ability to transact in forward sales markets at acceptable contract terms. This approach to portfolio management assists in minimizing costs in situations where Western Power Operations would otherwise have to purchase electricity in the open market to fulfill its contractual sales obligations. Approximately 19 per cent of power sales volumes were sold into the spot market in first quarter 2007 compared to 29 per cent in first quarter 2006. To reduce its exposure to spot market prices on uncontracted volumes, as at March 31, 2007, Western Power Operations had fixed price power sales contracts to sell approximately 8,000 GWh for the remainder of 2007 and 7,400 GWh for 2008.

Eastern Power Operations

Eastern Power Operations Results-at-a-Glance (1)

Three months ended March 31
(unaudited)
(millions of dollars)	2007		2006
Revenue
Power	354		161
Other (2)	83		117
	437		278
Commodity purchases resold
Power	(177	)	(101	)
Other (2)	(58	)	(96	)
	(235	)	(197	)
Plant operating costs and other	(124	)	(25	)
Depreciation	(11	)	(7	)
Operating income	67		49

(1) Eastern Power Operations includes Bécancour and Baie-des-Sables effective September 17, 2006 and November 21, 2006, respectively.

(2) Other includes natural gas.

Eastern Power Operations Sales Volumes (1)

Three months ended March 31
(unaudited)
(GWh)	2007	2006

Supply
Generation	2,023	705
Purchased	1,526	730
	3,549	1,435
Contracted vs. Spot
Contracted (2)	3,357	1,383
Spot (3)	192	52
	3,549	1,435

(1) Eastern Power Operations includes Bécancour and Baie-des-Sables effective September 17, 2006 and November 21, 2006, respectively.

(2) Represents volumes sold to wholesale, commercial and industrial customers under short- and long-term contacts at predetermined prices.

(3) Represents volumes sold into the short-term power market and are subject to spot market price volatility.

Eastern Power Operations’ operating income of $67 million in first quarter 2007 increased $18 million compared to the $49 million earned first quarter 2006. The increase was primarily due to incremental income earned in 2007 from the startup of both the 550 MW Bécancour cogeneration plant in September 2006 and the first of six wind farms (Baie-des-Sables) at the Cartier Wind project in November 2006.

Generation volumes in first quarter 2007 of 2,023 GWh increased 1,318 GWh compared to 705 GWh generated in first quarter 2006 primarily due to the placing into service of the Bécancour and Baie-des-Sables facilities, as well as increased dispatch of the OSP facility.

Eastern Power Operations’ revenues of $354 million increased $193 million in first quarter 2007, compared to first quarter 2006, primarily due to the placing into service of the Bécancour facility and increased sales volumes to commercial and industrial customers. Power commodity purchases resold of $177 million and purchased power volumes of 1,526 GWh were higher in first quarter 2007, compared to first quarter 2006, primarily due to the impact of increased purchases to supply sales contracts. First quarter 2007 other revenue and other commodity purchases resold of $83 million and $58 million, respectively, decreased year-over-year primarily as a result of a reduction in the quantity of natural gas being resold under the OSP natural gas sales contracts and lower gas prices. Plant operating costs and other of $124 million, which includes fuel gas consumed in generation, increased in first quarter 2007 from the prior year primarily as a result of the startup of the Bécancour facility.

In first quarter 2007, approximately five per cent of power sales volumes were sold into the spot market compared to approximately four per cent in first quarter 2006. Eastern Power 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 and wholesale power purchases. To reduce its exposure to spot market prices, as at March 31, 2007, Eastern Power

Operations had entered into fixed price power sales contracts to sell approximately 10,100 GWh for the remainder of 2007 and 10,300 GWh for 2008, although certain contracted volumes are dependent on customer usage levels.

Power Plant Availability

Weighted Average Power Plant Availability (1)

Three months ended March 31
(unaudited)	2007		2006

Bruce Power	82	%	90	%
Western Power Operations	99	%	90	%
Eastern Power Operations (2)	97	%	95	%
All plants, excluding Bruce Power	97	%	94	%
All plants	91	%	91	%

(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 unplannned outages.

(2) Eastern Operations includes Bécancour and Baie-des-Sables effective September 17, 2006 and November 21, 2006, respectively.

Natural Gas Storage

Natural Gas Storage operating income of $30 million in first quarter 2007 increased $8 million compared to $22 million in first quarter 2006. The increase was primarily due to higher earnings from CrossAlta as a result of increased capacity and higher natural gas storage spreads as well as incremental income earned in 2007 from the startup of the Edson facility in December 2006.

General, Administrative and Support Costs

General, administrative and support costs of $36 million in first quarter 2007 increased $6 million compared to first quarter 2006 primarily due to higher costs associated with growing the Energy business.

As at March 31, 2007, TransCanada had capitalized $32 million related to the Broadwater liquefied natural gas (LNG) project.

Corporate

Net earnings from Corporate for the three months ended March 31, 2007 were $4 million, compared to net expenses of $12 million for the same period in 2006. The increase in earnings was primarily due to favourable income tax adjustments recorded in first quarter 2007, including a $10 million benefit on the resolution of certain income tax matters, a $5 million benefit resulting from an internal restructuring, as well as certain other tax items relating to changes in estimates and tax rate differentials. Partially offsetting these increases was an increase to financial charges as a result of financing the recent ANR and Great Lakes acquisitions.

Liquidity and Capital Resources

Funds Generated from Operations

Three months ended March 31 (unaudited)
(millions of dollars)	2007	2006

Cash Flows
Funds generated from operations (1)	582	517
Decrease/(increase) in operating working capital	36	(2	)
Net cash provided by operations	618	515

(1) For a further discussion on funds generated from operations, refer to the Non-GAAP Measures section in this MD&A.

Net cash provided by operations increased $103 million in first quarter 2007 compared to first quarter 2006. The increase in cash was primarily due to a decrease in operating working capital. Funds generated from operations were $582 million for the three months ended March 31, 2007, compared to $517 million for the same period in 2006. The increase was mainly due to an increase in cash generated through earnings.

TransCanada expects that its ability to generate adequate amounts of cash in the short and long term, when needed, and to maintain financial capacity and flexibility to provide for planned growth remains substantially unchanged since December 31, 2006.

Investing Activities

Acquisitions, net of cash acquired, for the three months ended March 31, 2007 were $4,265 million (2006 - nil) due to the acquisition of ANR and an additional 3.55 per cent interest in Great Lakes for approximately US$3.4 billion, including US$491 million of assumed long-term debt. Acquisitions also include PipeLines LP’s 46.45 per cent interest in Great Lakes for approximately US$942 million, including US$209 million of assumed long-term debt. These acquisitions are discussed further in the Acquisitions section of this MD&A.

For the three months ended March 31, 2007, capital expenditures totalled $306 million (2006 - $303 million) and related to the restart and refurbishment of Bruce A Units 1 and 2, the construction of new power plants and capital expenditures in Pipelines.

Financing Activities

TransCanada retired $325 million of long-term debt in the three months ended March 31, 2007 ($140 million – March 31, 2006), and issued $1.362 billion of long-term debt ($878 million – March 31, 2006). For the three months ended March 31, 2007, notes payable increased $1.065 billion, and cash and short-term investments decreased $49 million.

On March 20, 2007, TCPL filed debt shelf prospectuses in Canada and the U.S. qualifying for the issuance of $1.5 billion of medium-term notes and US$1.5 billion of debt securities, respectively.

On March 20, 2007, ANR Pipeline Company provided notice to the New York Stock Exchange of its intention to voluntarily withdraw from listing its 9.625 per cent Debentures due 2021, 7.375 per cent Debentures due 2024,

and 7.0 per cent Debentures due 2025. Following the delisting, which became effective April 12, 2007, ANR Pipeline Company deregistered these securities from registration with the U.S. Securities Exchange Commission (SEC).

In February 2007, through a subscription receipts offering, TransCanada issued 39,470,000 common shares at a price of $38.00 each. The offering resulted in gross proceeds to TransCanada of $1.5 billion which were used towards financing the acquisition of ANR. On March 6, 2007, under an option granted to the underwriters, TransCanada issued an additional 5,920,500 common shares at $38.00 per common share, resulting in additional gross proceeds of $225 million.

In February 2007, the Company executed an agreement for a US$2.2 billion, committed, unsecured, one-year bridge loan facility. Interest is charged at a floating rate based on the London Interbank Offered Rate (LIBOR). The Company utilized $1.5 billion and US$700 million from this facility to partially finance the ANR and Great Lakes acquisition. At March 31, 2007, the Company had an outstanding balance of US$488 million on this facility. The undrawn balance of this facility has been cancelled and is no longer available to the Company.

In February 2007, the Company, through a wholly owned subsidiary, established a US$1.0 billion committed, unsecured credit facility, consisting of a US$700 million five-year term loan and a US$300 million five-year, extendible revolving facility. Interest is charged at a floating rate based on LIBOR. The Company utilized US$1.0 billion from this facility and an additional US$100 million from an existing demand line to partially finance the ANR acquisition as well as its additional investment in PipeLines LP described previously. At March 31, 2007, the Company had an outstanding balance of US$1.0 billion on the credit facility and US$85 million on the demand line.

On February 22, 2007, PipeLines LP increased the size of its syndicated revolving credit and term loan facility in connection with its Great Lakes acquisition. The amount available under the facility increased from US$410 million to US$950 million, consisting of a US$700 million senior term loan and a US$250 million senior revolving credit facility, with US$194 million of the senior term loan available being terminated upon closing of the Great Lakes acquisition. Interest is charged at a floating rate based on LIBOR.

In January 2007, TransCanada filed a short form shelf prospectus with securities regulators in Canada and the U.S. to allow for the offering of up to $3.0 billion of common shares, preferred shares and/or subscription receipts in Canada and the U.S. until February 2009. As at March 31, 2007, the Company had issued $1.725 billion in common shares, which were used towards financing the acquisition of ANR.

Dividends

On April 26, 2007, TransCanada’s Board of Directors declared a quarterly dividend of $0.34 per share for the quarter ending June 30, 2007 on the outstanding common shares. This is the 175th consecutive quarterly dividend paid by TransCanada and its subsidiary on the common shares. It is payable on July 31, 2007 to shareholders of record at the close of business on June 29, 2007.

Directors also approved the issuance of common shares from treasury at a two per cent discount under TransCanada’s Dividend Reinvestment and Share Purchase Plan for the dividend payable July 31, 2007. The Company reserves the right to alter the discount or return to purchasing shares on the open market at any time.

Changes in Accounting Policy

Changes for 2007

Effective January 1, 2007, the Company adopted the new Canadian Institute of Chartered Accountants (CICA) Handbook accounting requirements for Section 1506 “Accounting Changes”, Section 1530 “Comprehensive Income”, Section 3251 “Equity”, Section 3855 “Financial Instruments – Recognition and Measurement”, Section 3861 “Financial Instruments – Disclosure and Presentation”, and Section 3865 “Hedges”. Adjustments to first quarter consolidated financial statements for 2007 have been made in accordance with the transitional provisions for these new standards.

Comprehensive Income and Equity

The Company’s financial statements include a statement of Consolidated Comprehensive Income. In addition, as required by Section 3251, the Company now presents separately in its Changes in Consolidated Shareholders’ Equity the changes for each of its components of Shareholders’ Equity. A new component, Accumulated Other Comprehensive Income, has been added to the Company’s Shareholders’ Equity as a result of the implementation of this new standard.

Financial Instruments

All financial instruments, including derivatives, are included on the balance sheet initially at fair value. The financial assets are classified as held-for-trading, held-to-maturity, loans and receivables, or available-for-sale. Financial liabilities are classified as held-for-trading or other financial liabilities. Subsequent measurement is determined by classification.

Held-for-trading financial assets and liabilities are entered into with the intention of generating a profit and consist of swaps, options, forwards and futures. These financial instruments are initially accounted for at their fair value and changes to fair value are recorded in income. Held-to-maturity financial assets are accounted for at their amortized cost using the effective interest method. The Company did not have any of these financial instruments at March 31, 2007. Loans and receivables are accounted for at their amortized cost using the effective interest method. The available-for-sale classification includes non-derivative financial assets that are designated as available-for-sale or are not included in the other three classifications. These instruments are initially accounted for at their fair value and changes to fair value are recorded through Other Comprehensive Income. Income earned from these assets is included in Interest Income and Other.

Other financial liabilities not classified as held-for-trading are accounted for at their amortized cost, using the effective interest method. Interest expense is included in Financial Charges and Financial Charges of Joint Ventures.

Derivatives embedded in other financial instruments or contracts (the host instrument) are recorded as separate derivatives and are measured at fair value if the economic characteristics of the embedded derivative are not closely related to the host instrument, the terms of the embedded derivative are the same as those of a stand-alone derivative and the total contract is not held-for-trading or accounted for at fair value. Changes in fair value of the embedded derivative are included in income. All derivatives, other than those that meet the normal purchases and sales exceptions, are carried on the balance sheet at fair value. The Company used January 1, 2003 as the transition date for embedded derivatives.

Transaction costs are incremental costs that are directly attributable to the acquisition, issue or disposal of a financial instrument. Effective January 1, 2007, the Company began offsetting long-term debt transaction costs against the associated debt and began amortizing these costs using the effective interest method. Previously, these costs were amortized straight-line over the life of the debt. There was no material effect on the Company’s financial statements as a result of this change in policy. In first quarter 2007, the charge to Net Income for the amortization of transaction costs using the effective interest method was immaterial.

As part of the accounting for the Company’s regulated operations, gains or losses from the changes in the fair value of financial instruments within the regulated operations are included in regulatory assets or regulatory liabilities.

Hedges

The new standard specifies the circumstances under which hedge accounting is permissible, how hedge accounting may be performed and where the impacts should be recorded. The standard introduces three specific types of hedging relationships: fair value hedges, cash flow hedges and hedges of a net investment in self-sustaining foreign operations.

As part of its asset and liability management, the Company uses derivatives for hedging positions to reduce its exposure to credit and market risk. The Company designates certain derivatives as hedges and prepares documentation at the inception of the hedging contract. The Company performs an assessment at inception and during the term of the contract to determine if the derivative used as a hedge is effective in offsetting the risks in the values or cash flows of the hedged financial instrument. All derivatives are initially recorded at fair value and adjusted to fair value at each reporting date.

Fair value hedges primarily consist of interest rate swaps used to mitigate the effect of changes in the fair value of fixed-rate long-term financial instruments due to movements in market interest rates. Changes in the value of fair value hedges are recorded in Financial Charges and Interest Income and Other, for interest rate and foreign exchange hedges, respectively. Any gains or losses arising from the ineffectiveness are recognized immediately in income in the same financial category as the underlying transaction.

The Company uses cash flow hedges to reduce its exposure to fluctuations in interest rates, foreign exchange and changes in commodity prices. The effective portion of changes in the value of cash flow hedges is recognized in Other Comprehensive Income. Ineffective portions and amounts excluded from effectiveness testing of hedges are included in income in the same financial category as the underlying transaction. Gains or losses from cash flow hedges that have been included in Accumulated Other Comprehensive Income are included in Net Income when the underlying transaction has occurred or becomes probable of not occurring. The maximum length of time the Company is hedging its exposure to variability in future cash flows is 10 years.

The Company hedges its foreign currency exposure of investments in self-sustaining foreign operations with certain cross-currency swaps, forward exchange contracts and options. These financial instruments are adjusted to fair value and the effective portion of gains or losses associated with these adjustments are included in Other Comprehensive Income. In addition, the Company hedges its net investment with U.S. dollar-denominated debt, which is valued at period-end foreign exchange rates. Gains or losses arising from ineffective portions of the hedge are included in income. Gains or losses from these hedges that have been included in Accumulated Other Comprehensive Income are reclassified to Net Income in the event the Company settles or otherwise reduces its investment.

Net Effect of Accounting Policy Changes

The net effect to the Company’s financial statements at January 1, 2007 resulting from the above-mentioned changes in accounting policies is as follows.

Increases/ (decreases) (unaudited) (millions of dollars)

Other current assets	(127	)
Other assets	(203	)
Accounts payable	(29	)
Deferred amounts	(75	)
Future income taxes	(42	)
Long-term debt	(85	)
Long-term debt of joint ventures	(7	)
Accumulated other comprehensive loss	(186	)
Foreign exchange adjustment	90
Retained earnings	4

Future Accounting Changes

Section 1535 Capital Disclosures

Effective for interim and annual financial statements for fiscal years beginning on or after October 1, 2007, the new CICA Handbook Section 1535 “Capital Disclosures” requires the disclosure of qualitative and quantitative information about the Company’s objectives, policies and processes for managing capital.

Section 3862 Financial Instruments – Disclosures and Section 3863 – Financial Instruments – Presentation

Effective for interim and annual financial statements for fiscal years beginning on or after October 1, 2007, the new CICA Handbook Sections 3862 and 3863 will replace Section 3861 to prescribe the requirements for presentation and disclosure of financial instruments.

Contractual Obligations

As a result of TransCanada’s acquisition of ANR, Pipelines’ future purchase obligations, primarily consisting of operating lease and purchase obligations, increased $152 million at March 31, 2007, compared to December 31, 2006.

Other than the above-mentioned ANR commitments and future debt and interest payments on debt utilized to acquire ANR, there have been no material changes to TransCanada’s contractual obligations from December 31, 2006 to March 31, 2007, including payments due for the next five years and thereafter. For further information on these contractual obligations, refer to the MD&A in TransCanada’s 2006 Annual Report.

Financial and Other Instruments

Interest, Foreign Exchange and Energy Risk Management

During the three-month period ended March 31, 2007, the Company had positions in the following types of derivatives:

· Forwards and future contracts — contractual agreements to buy or sell a specific financial instrument at a specified price and date in the future. The Company enters into foreign exchange and commodity forwards and futures to mitigate volatility in changes in foreign exchange rates and power and gas prices, respectively.

· Swaps — contractual agreements between two parties to exchange streams of payments over time according to specified terms. The Company enters into interest rate and cross-currency swaps to mitigate changes in interest rates and foreign exchange, respectively.

· Options — contractual agreements to convey the right, but not the obligation, for the purchaser either to buy or sell a specific amount of a financial instrument at a fixed price, either at a fixed date or at any time within a specified period. The Company enters into option agreements to mitigate changes in interest rates, foreign exchange and commodity prices.

The Company has long-term debt, interest rate swaps and interest rate options that have a fixed interest rate and, therefore, are subject to interest rate price risk. The Company has long-term debt, interest-rate swaps and interest-rate options, which have a floating interest rate and, therefore, are subject to interest rate cash flow risk.

The Company calculated the fair value of foreign exchange and interest rate derivatives using quoted market rates. The changes in fair value for interest rate and foreign exchange derivatives are included in Financial Charges and Interest Income and Other, respectively.

The Company executes power, natural gas and heat rate derivatives for overall management of its asset portfolio. Heat rate contracts are agreements for the sale or purchase of power that are priced based on a natural gas index. The fair value of power and natural gas derivatives was calculated using estimated forward prices for the relevant period. In accordance with the Company’s accounting policy, the fair values of these derivatives are recorded as financial assets and liabilities.

At March 31, 2007, the Company had included net losses of $4 million (March 31, 2006 – net gains of $5 million) in Net Income as a result of its swaps, futures, options and contracts. At March 31, 2007, there were unrealized gains from unsettled derivatives of $52 million (December 31, 2006 – $41 million) included in Other Current Assets and $210 million (December 31, 2006 – $39 million) included in Other Assets. At March 31, 2007, unrealized losses of $116 million (December 31, 2006 – $144 million) were included in Accounts Payable and $259 million (December 31, 2006 – $158 million) included in Deferred Amounts.

The Company hedges its net investment in self-sustaining foreign operations with U.S. dollar-denominated debt, cross-currency swaps, forward exchange contracts and options. At March 31, 2007, the Company had designated U.S. dollar-denominated debt with a carrying value of $3,333 million (US$2,891 million) and a fair value of $3,511 million (US$3,045 million) as a portion of this hedge and swaps, forwards and options with a fair value of $73 million (US$64 million) as net investment hedges.

Other Risk Management

Currency risk arises when the fair value or future cash flows of a financial instrument fluctuate due to changes in foreign exchange rates. The Company manages currency risk through the use of derivatives such as cross-currency swaps, options and forward foreign exchange contracts. Market risk is the risk that the fair value of future cash flows of financial instruments will fluctuate due to changes in market variables such as interest rates, foreign exchange and commodity prices. In order to manage market risk, the Company enters into offsetting physical positions and derivative financial instruments. Liquidity risk is the risk that an entity will encounter difficulty in meeting obligations associated with financial instruments. Additional risks faced by the Company are discussed in the MD&A in TransCanada’s 2006 Annual Report. These risks have not had a material effect on the Company’s financial results at March 31, 2007 and have been mitigated by risk management strategies.

TransCanada’s market, financial and counterparty risks remain substantially unchanged since December 31, 2006. For further information on risks, refer to the MD&A in TransCanada’s 2006 Annual Report.

Risk and Risk Management Related to Environmental Regulations

In March 2007, the Alberta Government released its Climate Change and Emissions Management Act aimed at reducing greenhouse gas starting in July 2007. The Alberta Government is currently seeking comments on the proposed regulations and many of the specifics have yet to be determined. The Canadian Federal Government is expected to release similar legislation imminently. As these legislative initiatives have the potential to significantly impact the energy industry, the Company continues to assess and monitor the implications to TransCanada’s businesses.

Controls and Procedures

As of March 31, 2007, an evaluation was carried out under the supervision of, and with the participation of, management including the President and Chief Executive Officer and Chief Financial Officer, of the effectiveness of TransCanada’s disclosure controls and procedures as defined under the rules adopted by the Canadian securities regulatory authorities and by the U.S. Securities and Exchange Commission. Based on that evaluation, the President and Chief Executive Officer and Chief Financial Officer concluded that the design and operation of TransCanada’s disclosure controls and procedures were effective as at March 31, 2007.

During the recent fiscal quarter, there have been no changes in TransCanada’s internal control over financial reporting that have materially affected, or are reasonably likely to materially affect,

TransCanada’s internal control over financial reporting. With respect to the recent acquisitions, the Company has not yet determined whether or not to apply the acquisitions exemption allowed under the Sarbanes-Oxley Act of 2002.

Significant Accounting Policies and Critical Accounting Estimates

Since determining the value of certain 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 significant accounting policies and critical accounting estimates are the use of regulatory accounting for the Company’s regulated operations and the policies the Company adopts to account for derivatives and depreciation and amortization expense. Effective January 1, 2007, the Company adopted the new accounting standards for financial instruments and hedges, as discussed in the section Changes in Accounting Policies in this MD&A. For further information on the Company’s accounting policies and estimates refer to the MD&A in TransCanada’s 2006 Annual Report.

Outlook

Excluding the $15 million of income tax adjustments recorded in first quarter 2007, the Company’s outlook is relatively unchanged since the disclosure in the Company’s 2006 Annual Report. For further information on outlook, refer to the MD&A in TransCanada’s 2006 Annual Report.

TransCanada’s issuer rating assigned by Moody’s Investors Service (Moody’s) is A3 with a stable outlook. TransCanada PipeLines Limited’s (TCPL) senior unsecured debt is rated A, with a stable outlook, by DBRS; A2, with a stable outlook, by Moody’s; and A-, with a stable outlook, by Standard & Poor’s.

Other Recent Developments

Pipelines

Wholly Owned Pipelines

Canadian Mainline

In February 2007, TransCanada reached a multi-year tolls settlement for the years 2007 to 2011 on the Canadian Mainline.

TransCanada and its stakeholders agreed that the cost of capital will reflect an ROE, as determined by the NEB’s return on equity formula, on a deemed common equity ratio of 40 per cent, an increase from 36 per cent. The remaining capital structure will consist of senior debt following the agreed upon redemption of US$460 million Preferred Securities currently included in the Canadian Mainline’s investment base.

The settlement also establishes certain elements of the Canadian Mainline’s fixed operating, maintenance and administration (OM&A) costs for each year of the settlement. Any variance between actual OM&A costs and those agreed to in the settlement will accrue to TransCanada from

2007 to 2009. Variances in certain elements of OM&A costs will be shared equally between TransCanada and its customers in 2010 and 2011. All other cost elements of the revenue requirement will be treated on a flow-through basis.

The performance-based incentive arrangements, similar to those agreed to in the 2006 settlement, are focused on aligning interests in achieving cost savings and increased value, thereby providing mutual benefits to both TransCanada and its customers. TransCanada and its stakeholders have agreed to a slight decrease in the depreciation rate for the term of the settlement and to seek NEB approval to put the requirement for an updated depreciation study due in 2008 into abeyance until 2012.

Interim tolls as approved by the NEB in March 2007 will continue to be charged for transportation service on the Canadian Mainline until final tolls are approved by the NEB pursuant to this settlement. In March 2007, TransCanada applied to the NEB for approval of this settlement, and a decision is expected in second quarter 2007. Until this decision is received, TransCanada is recording its Canadian Mainline net earnings using the NEB ROE formula on a deemed common equity ratio of 36 per cent.

Alberta System

In March 2007, the Alberta Energy and Utilities Board (EUB) approved the 2007 final rates for the Alberta System as filed. The rates are effective April 1, 2007 to December 31, 2007 and reflect the 2005-2007 Revenue Requirement Settlement on the Alberta System.

Northern Border

Effective April 1, 2007, TransCanada became the operator of Northern Border. TransCanada owns 16 per cent of Northern Border through its 32.1 per cent ownership of PipeLines LP.

BC System and Foothills

In February 2007, the NEB approved the integration of the BC System into Foothills. In March 2007, the NEB approved a compliance filing confirming an April 1, 2007 effective date for the transfer and providing final 2007 tolls.

Gas Transmission Northwest System

TransCanada filed a rate case with the FERC for its Gas Transmission Northwest System. In January 2007, TransCanada received a procedural order from the FERC establishing a timeline for the System’s rate case proceeding with a hearing scheduled to commence on October 31, 2007. In April 2007, the Company initiated settlement discussions with its customers and the FERC.

Beginning January 1, 2007, GTN increased its transportation rates in accordance with the FERC’s July 31, 2006 suspension order. The additional revenue collected is subject to refund based upon the outcome of GTN’s rate case proceeding. Until final approval of rates is received from the FERC, the Company has been recording a provision for rate refund equal

to the difference in transportation revenue based on GTN’s new rates and the rates that were in effect prior to January 1, 2007.

North Baja Pipeline Expansion

TransCanada’s North Baja Pipeline has filed an application with the FERC to expand and modify its existing system to facilitate the importation of regassified LNG from Mexico into the California and Arizona markets. The FERC has issued a preliminary determination approving all aspects of North Baja’s proposal other than those related to environmental issues, which will be the subject of a future order. TransCanada expects that the final Environmental Impact Statement will be completed and the FERC will issue its final order authorizing the project by mid year 2007.

Mackenzie Gas Pipeline Project

In March 2007, the proponents of the Mackenzie Gas Project (MGP) filed updated capital cost estimates for the project with the NEB and a Joint Review Panel (JRP). These estimates include $3.5 billion for the gas gathering system, $7.8 billion for the pipeline and $4.9 billion for the development of the proponent’s gas fields. Additional project update information is expected to be filed in June 2007, describing further project adjustments and refinements.

The MGP proponents continue to participate in public hearings convened by the JRP, assessing socio-economic and environmental aspects of the project. These regulatory hearings are expected to conclude in the second half of 2007, with the JRP’s report to follow.

Alaska Highway Pipeline Project

TransCanada is continuing its discussions with the Alaska North Slope producers. The Alaska State administration has introduced the Alaska Gasline Inducement Act (AGIA) as their new process for the portion of the pipeline project in Alaska. The Alaska State Legislature is currently reviewing the bill, with final disposition expected by approximately June 2007. If AGIA is passed in its current form, it is expected the State will choose a licensee for the pipeline project near the end of 2007.

Energy

Broadwater

Broadwater is a partnership between TransCanada and Shell US Gas & Power to construct an facility in the New York State waters of Long Island Sound. TransCanada anticipates that the FERC will issue a Final Environmental Impact Statement in third quarter 2007. A similar timeline is anticipated for the State of New York to render a decision on whether the Broadwater project is consistent with its coastal management policies.

Share Information

As at March 31 2007, TransCanada had 534,721,062 issued and outstanding common shares. In addition, there were 9,525,221 outstanding options to purchase common shares, of which 6,780,132 were exercisable as at March 31, 2007.

Selected Quarterly Consolidated Financial Data(1)

(unaudited)	2007		2006								2005
(millions of dollars except per share amounts)	First		Fourth		Third		Second		First		Fourth		Third		Second

Revenues	2,249		2,091		1,850		1,685		1,894		1,771		1,494		1,449
Net Income
Continuing operations	265		269		293		244		245		350		427		200
Discontinued operations	—		—		—		—		28		—		—		—
	265		269		293		244		273		350		427		200

Share Statistics
Net income per share - Basic
Continuing operations	$	0.52	$	0.55	$	0.60	$	0.50	$	0.50	$	0.72	$	0.88	$	0.41
Discontinued operations	—		—		—		—		0.06		—		—		—
	$	0.52	$	0.55	$	0.60	$	0.50	$	0.56	$	0.72	$	0.88	$	0.41
Net income per share - Diluted
Continuing operations	$	0.52	$	0.54	$	0.60	$	0.50	$	0.50	$	0.71	$	0.87	$	0.41
Discontinued operations	—		—		—		—		0.06		—		—		—
	$	0.52	$	0.54	$	0.60	$	0.50	$	0.56	$	0.71	$	0.87	$	0.41
Dividend declared per common share	$	0.34	$	0.32	$	0.32	$	0.32	$	0.32	$	0.305	$	0.305	$	0.305

(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.

Factors Impacting Quarterly Financial Information

In Pipelines, which consists primarily of the Company’s investments in regulated pipelines and natural gas storage facilities, 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 net earnings during any particular fiscal year remain relatively stable with fluctuations resulting from adjustments being recorded due to regulatory decisions and negotiated settlements with shippers, seasonal fluctuations in short-term throughput on U.S. pipelines and items outside of the normal course of operations.

In Energy, which consists primarily of the Company’s investments in electrical power generation plants and non-regulated natural gas storage facilities, 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.

· Second quarter 2005 net earnings included $21 million ($13 million related to 2004 and $8 million related to 2005) with respect to the NEB’s decision on the Canadian Mainline’s 2004 Tolls and Tariff Application (Phase II). On April 1, 2005, TransCanada completed the acquisition of TC Hydro

generation assets from USGen New England, Inc. Bruce Power’s income from equity investments was lower than previous quarters due to the continuing impact of planned maintenance outages and an unplanned maintenance outage on Unit 6 relating to a transformer fire.

· In third quarter 2005, net earnings included a $193 million after-tax gain related to the sale of the Company’s ownership interest in TransCanada Power, LP. In addition, Bruce Power’s income from equity investments increased from prior quarters due to higher realized power prices and slightly higher generation volumes.

· In fourth quarter 2005, net earnings included a $115 million after-tax gain on the sale of P.T. Paiton Energy Company. In addition, Bruce A was formed and Bruce Power’s results were proportionately consolidated, effective October 31, 2005.

· In first quarter 2006, net earnings included an $18 million after-tax bankruptcy claim settlement from a former shipper on the Gas Transmission Northwest System. In addition, Energy’s net earnings included contributions from the December 31, 2005 acquisition of the 756 MW Sheerness PPA.

· In second quarter 2006, net earnings included $33 million of future income tax benefits ($23 million in Energy and $10 million in Corporate) as a result of reductions in Canadian federal and provincial corporate income tax rates. Pipelines earnings included a $13 million after-tax gain related to the sale of the Company’s general partner interest in Northern Border Partners, L.P.

· In third quarter 2006, net earnings included an income tax benefit of approximately $50 million on the resolution of certain income tax matters with taxation authorities and changes in estimates.

· In fourth quarter 2006, net earnings included approximately $12 million related to income tax refunds and related interest.

· In first quarter 2007, net earnings included approximately $15 million related to positive income tax adjustments. In addition, Pipelines’ net earnings included contributions from the February 22, 2007 acquisition of ANR and additional interests in Great Lakes.