exhibit131tcc04262013.htm

1	Results from TQM, Northern Border, Iroquois, TransGas and Gas Pacifico/INNERGY reflect our share of equity income from these investments.

2	Does not include depreciation and amortization from equity investments.

3	Represents our 75 per cent direct ownership interest.

4	Represents our 53.6 per cent direct ownership interest.

5	Represents our 33.3 per cent direct ownership interest of TC PipeLines, LP and our effective ownership through TC PipeLines, LP of 8.3 per cent of each of GTN and Bison, 16.7 per cent of Northern Border and an additional effective ownership of 15.4 per cent of Great Lakes.

6	Represents our 61.7 per cent ownership interest.

7	Comparable EBITDA for the portions of TC PipeLines, LP and Portland we do not own.

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NET INCOME - WHOLLY OWNED CANADIAN PIPELINES

three months ended March 31 (millions of $)	2013	2012

Canadian Mainline - net income	151	47
Canadian Mainline - comparable earnings	67	47
NGTL System	56	48
Foothills	4	5

OPERATING STATISTICS - WHOLLY OWNED CANADIAN PIPELINES

three months ended March 31	Canadian Mainline1		NGTL System2		ANR3
(unaudited)	2013	2012	2013	2012	2013	2012

Average investment base (millions of dollars)	5,870	5,812	5,824	5,282	n/a	n/a
Delivery volumes (Bcf)
Total	426	430	994	998	465	482
Average per day	4.7	4.7	11.0	11.0	5.2	5.3

1	Canadian Mainline’s throughput volumes represent physical deliveries to domestic and export markets. Physical receipts originating at the Alberta border and in Saskatchewan for the three months ended March 31, 2013 were 231 Bcf (2012 – 247 Bcf). Average per day was 2.6 Bcf (2012 – 2.7 Bcf).

2	Field receipt volumes for the NGTL System for the three months ended March 31, 2013 were 916 Bcf (2012 – 948 Bcf). Average per day was 10.2 Bcf (2012 – 10.4 Bcf).

3	Under its current rates, which are approved by the FERC, changes in average investment base do not affect results.

CANADIAN PIPELINES

Comparable EBITDA and net income for our rate-regulated Canadian Pipelines are affected by our approved ROE, our investment base, the level of deemed common equity and incentive earnings. Changes in depreciation, financial charges and taxes also impact comparable EBITDA and EBIT but do not impact net income as they are recovered in revenue on a flow-through basis.

Net income for the Canadian Mainline this quarter was $104 million higher than first quarter 2012 because of the impact of the NEB’s March 27, 2013 decision on the Canadian Restructuring Proposal. Among other things, the NEB approved an ROE of 11.50 per cent on a 40 per cent deemed common equity effective for the years 2012 to 2017 compared to the last approved ROE of 8.08 per cent on a 40 per cent deemed common equity which was used to record earnings in 2012. Comparable earnings in first quarter 2013 excludes $84 million related to the 2012 impact of the NEB decision.

Net income for the NGTL System (formerly known as the Alberta System) was $8 million higher than first quarter 2012 because of a higher average investment base and termination of the annual fixed operating, maintenance and administration (OM&A) costs component included in the 2010 - 2012 Revenue Requirement which expired at the end of 2012. The NGTL System’s results this quarter reflected the last approved ROE of 9.70 per cent on deemed common equity of 40 per cent and no incentive earnings.

U.S. PIPELINES AND INTERNATIONAL

EBITDA for our U.S. operations is generally affected by contracted volume levels, volumes delivered and the rates charged, as well as by the cost of providing services, including OM&A and property taxes. ANR is also affected by the contracting and pricing of its storage capacity and incidental commodity sales.

Comparable EBITDA for the U.S. and international pipelines was US$255 million this quarter, or US$15 million lower than first quarter 2012. This was the net effect of:

·	lower revenue at Great Lakes because of lower rates and uncontracted capacity

·	higher costs at ANR relating to services provided by other pipelines

·	higher short term and interruptible revenues at Portland.

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COMPARABLE DEPRECIATION AND AMORTIZATION

Comparable depreciation and amortization was $8 million higher this quarter than in first quarter 2012 mainly because of the higher rate base on the NGTL System.

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Oil Pipelines

Comparable EBITDA and comparable EBIT are non-GAAP measures. See non-GAAP measures section for more information.

three months ended March 31 (unaudited - millions of $)	2013		2012

Keystone Pipeline System	186		174
Oil Pipeline Business Development	(7	)	(1	)
Oil Pipelines - comparable EBITDA	179		173
Comparable depreciation and amortization	(37	)	(36	)
Oil Pipelines - comparable EBIT	142		137

Comparable EBIT denominated as follows:
Canadian dollars	47		48
U.S. dollars	94		89
Foreign exchange	1		-
	142		137

Comparable EBITDA for the Keystone Pipeline System was $12 million higher this quarter than in first quarter 2012. This increase reflected higher revenues primarily resulting from:

·	higher contracted volumes

·	higher final fixed tolls on committed pipeline capacity to Cushing, Oklahoma, which came into effect in July 2012.

BUSINESS DEVELOPMENT

Business development expenses this quarter were $6 million higher than in first quarter 2012 because of increased activity on various development projects.

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Energy

Comparable EBITDA and comparable EBIT are non-GAAP measures. See non-GAAP measures section for more information.

three months ended March 31 (unaudited - millions of $)	2013		2012

Canadian Power
Western Power1	79		131
Eastern Power1,2	95		93
Bruce Power1	31		(13	)
General, administrative and support costs	(10	)	(11	)
Canadian Power - comparable EBITDA1	195		200
Comparable depreciation and amortization3	(43	)	(40	)
Canadian Power - comparable EBIT1	152		160

U.S. Power (US$)
Northeast Power	77		46
General, administrative and support costs	(10	)	(10	)
U.S. Power - comparable EBITDA	67		36
Comparable depreciation and amortization	(28	)	(30	)
U.S. Power - comparable EBIT	39		6
Foreign exchange	1		-
U.S. Power - comparable EBIT (Cdn$)	40		6

Natural Gas Storage
Alberta Storage	20		15
General, administrative and support costs	(2	)	(2	)
Natural Gas Storage - comparable EBITDA1	18		13
Comparable depreciation and amortization3	(3	)	(3	)
Natural Gas Storage - comparable EBIT1	15		10

Business Development comparable EBITDA and EBIT	(4	)	(5	)

Energy - comparable EBIT1	203		171

Summary
Energy - comparable EBITDA1	277		244
Comparable depreciation and amortization3	(74	)	(73	)
Energy - comparable EBIT1	203		171

1	Includes our share of equity income from our investments in ASTC Power Partnership, which holds the Sundance B PPA, Portlands Energy, Bruce Power and, in 2012, CrossAlta. In December 2012, we acquired the remaining 40 per cent interest in CrossAlta, bringing our ownership interest to 100 per cent.

2	Includes Cartier phase two of Gros-Morne starting in November 2012.

3	Does not include depreciation and amortization of equity investments.

Comparable EBITDA for Energy was $277 million this quarter, or $33 million higher than first quarter 2012. This was the net effect of:

higher equity income from Bruce Power because of incremental earnings from Units 1 and 2, which were returned to service in October 2012, the recognition of a business interruption insurance recovery and a Unit 3 outage in first quarter 2012 partially offset by the extended outage of Unit 4 in first quarter 2013

·	higher earnings from U.S. Power mainly because of higher realized power prices

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·	lower earnings from Western Power because of the Sundance A PPA force majeure and lower realized power prices.

CANADIAN POWER

Western and Eastern Power1

Comparable EBITDA and comparable EBIT are non-GAAP measures. See non-GAAP measures section for more information.

three months ended March 31 (unaudited - millions of $)	2013		2012

Revenue
Western power	142		224
Eastern power1	109		103
Other2	31		25
	282		352

Income from equity investments3	22		23

Commodity purchases resold
Western power	(65	)	(94	)
Other4	(2	)	(2	)
	(67	)	(96	)
Plant operating costs and other	(63	)	(55	)
General, administrative and support costs	(10	)	(11	)
Comparable EBITDA	164		213
Comparable depreciation and amortization5	(43	)	(40	)
Comparable EBIT	121		173

1	Includes Cartier phase two of Gros-Morne starting in November 2012.

2	Includes sale of excess natural gas purchased for generation and sales of thermal carbon black.

3	Includes our share of equity income from our investments in ASTC Power Partnership, which holds the Sundance B PPA, and Portlands Energy.

4	Includes the cost of excess natural gas not used in operations.

5	Does not include depreciation and amortization of equity investments.

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Sales volumes and plant availability

Includes our share of volumes from our equity investments.

three months ended March 31 (unaudited)	2013	2012

Sales volumes (GWh)
Supply
Generation
Western Power	670	671
Eastern Power1	1,346	1,143
Purchased
Sundance A & B and Sheerness PPAs2	1,707	2,039
Other purchases	-	45
	3,723	3,898
Sales
Contracted
Western Power	1,707	2,295
Eastern Power1	1,346	1,143
Spot
Western Power	670	460
	3,723	3,898
Plant availability3
Western Power4	97%	99%
Eastern Power1,5	96%	93%

1	Includes Cartier phase two of Gros-Morne starting in November 2012.

2	Includes our 50 per cent ownership interest of Sundance B volumes through the ASTC Power Partnership. No volumes were delivered under the Sundance A PPA in 2012 and 2013.

3	The percentage of time the plant was available to generate power, regardless of whether it was running.

4	Does not include facilities that provide power to TransCanada under PPAs.

5	Does not include Bécancour because power generation has been suspended since 2008.

Western Power’s comparable EBITDA was $79 million this quarter, or $52 million lower than first quarter 2012. Revenue also decreased by $82 million this quarter to $142 million. These decreases were mainly due to:

·	the Sundance A PPA force majeure

·	lower realized power prices and

·	lower purchased PPA volumes during periods of lower spot prices.

In first quarter 2012, we recorded revenues and costs related to the Sundance A PPA as though the outages of Units 1 and 2 were interruptions of supply in accordance with the terms of the PPA. In July 2012, we received the Sundance A PPA arbitration decision which determined the units were in force majeure in first quarter 2012. In response, we recorded a charge of $30 million in second quarter 2012 equivalent to the pre-tax income we had recorded in first quarter 2012. Because the plant continues to be in force majeure, we will not record further revenues and costs until the units are returned to service. See Energy - Significant Events in the MD&A in our 2012 Annual Report for more information about the Sundance A PPA arbitration decision.

Average spot market power prices in Alberta were $64 per MWh this quarter, compared to $60 per MWh in first quarter 2012. This increase was mainly the result of high spot market prices in the month of March driven by plant outages and increased demand. Western Power’s average realized power price this quarter was lower than first quarter 2012 because of contracting activities. Purchased volumes were lower than first quarter 2012 mainly because of lower utilization of the Sheerness and Sundance B PPAs and higher Sundance B plant outage days.

Western Power’s commodity purchases resold were $65 million this quarter, or $29 million lower than first quarter 2012, because of the Sundance A PPA force majeure and lower purchased volumes during periods of lower spot prices.

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Eastern Power’s comparable EBITDA of $95 million was $2 million higher than first quarter 2012 because of the start up of phase two of Cartier Gros-Morne in November 2012, partially offset by lower contractual earnings at Bécancour.

Plant operating costs and other, which includes natural gas fuel consumed in power generation, were $63 million this quarter, or $8 million higher than first quarter 2012, mainly due to higher natural gas fuel prices in 2013.

Approximately 72 per cent of Western Power sales volumes were sold under contract this quarter, compared to 83 per cent in first quarter 2012. To reduce exposure to spot market prices in Alberta, Western Power has entered into fixed-price power sales contracts to sell approximately 5,300 GWh for the remainder of 2013 and approximately 5,200 GWh in 2014.

BRUCE POWER

Our proportionate share

three months ended March 31 (unaudited - millions of $ unless noted otherwise)	2013	2012

Income/(loss) from equity investments1
Bruce A	36	(33	)
Bruce B	(5)	20
	31	(13	)

Comprised of:
Revenues	287	162
Operating expenses	(173)	(135	)
Depreciation and other	(83)	(40	)
	31	(13	)

Bruce Power - Other information
Plant availability2
Bruce A3	66%	48%
Bruce B	78%	86%
Combined Bruce Power	72%	62%
Planned outage days
Bruce A	90	91
Bruce B	70	46
Unplanned outage days
Bruce A	8	-
Bruce B	9	4
Sales volumes (GWh)1
Bruce A3	2,097	747
Bruce B	1,735	1,909
	3,832	2,656

Realized sales price per MWh
Bruce A	$68	$66
Bruce B4	$53	$54
Combined Bruce Power	$59	$57

1	Represents our 48.9 per cent ownership interest in Bruce A and 31.6 per cent ownership interest in Bruce B.

2	The percentage of time the plant was available to generate power, regardless of whether it was running.

3	Plant availability and sales volumes for 2013 include the incremental impact of Units 1 and 2 which were returned to service in October 2012.

4	Includes revenues under the floor price mechanism, revenues from contract settlements and volumes and revenues associated with deemed generation.

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Equity income from Bruce A increased by $69 million this quarter, compared to first quarter 2012. The increase was due to:

·	incremental earnings from Units 1 and 2 which returned to service in October 2012

·	recognition of an insurance recovery of approximately $40 million related to the May 2012 Unit 2 electrical generator failure and the impact the event had on Bruce A in 2012 and 2013

·	higher earnings from Unit 3 due to the West Shift Plus planned outage during first quarter 2012.

These increases were partially offset by the impact of the Unit 4 planned outage which began in August 2012 and was completed April 13, 2013.

The availability percentage for Units 1 and 2 increased through first quarter 2013 with an average availability in the mid 80s. These units are now able to operate at full power; however, as Units 1 and 2 have not operated for an extended period of time they may experience slightly higher forced outage rates and reduced availability percentages in 2013.

Equity loss from Bruce B was $5 million this quarter, compared to equity income of $20 million in first quarter 2012. The decrease was mainly due to lower volumes and higher operating costs resulting from higher planned outage days.

Under the contract with the Ontario Power Authority (OPA), all of the output from Bruce A is sold at a fixed price per MWh, adjusted annually for inflation on April 1. Bruce A also recovers fuel costs from the OPA.

Bruce A Fixed price	Per MWh

April 1, 2013 - March 31, 2014	$69.19
April 1, 2012 - March 31, 2013	$68.23
April 1, 2011 - March 31, 2012	$66.33

Under the same contract, all output from Bruce B is subject to a floor price adjusted annually for inflation on April 1.

Bruce B Floor price	Per MWh

April 1, 2013 - March 31, 2014	$52.34
April 1, 2012 - March 31, 2013	$51.62
April 1, 2011 - March 31, 2012	$50.18

Amounts received under the Bruce B floor price mechanism within a calendar year are subject to repayment if the monthly average spot price exceeds the floor price. We currently expect 2013 spot prices to be less than the floor price for the year and therefore no amounts recorded in revenues in first quarter 2013 are expected to be repaid.

Bruce B also enters into fixed-price contracts under which it receives or pays the difference between the contract price and the spot price.

The overall plant availability percentage in 2013 is expected to be in the mid 80s for Bruce A and the high 80s for Bruce B. Planned maintenance on two of the Bruce B units and one of the Bruce A units is expected to be completed in second quarter 2013.

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U.S. POWER

Comparable EBITDA and comparable EBIT are non-GAAP measures. See non-GAAP measures section for more information.

three months ended March 31 (unaudited - millions of US $)	2013		2012

Revenue
Power1	433		195
Capacity	47		40
Other2	29		19
	509		254
Commodity purchases resold	(306	)	(117	)
Plant operating costs and other2	(126	)	(91	)
General, administrative and support costs	(10	)	(10	)
Comparable EBITDA	67		36
Comparable depreciation and amortization	(28	)	(30	)
Comparable EBIT	39		6

1	The realized gains and losses from financial derivatives used to buy and sell power, natural gas and fuel oil to manage U.S. Power’s assets are presented on a net basis in power revenues.

2	Includes revenues and costs related to a third party service agreement at Ravenswood, the activity level of which increased in 2013.

Sales volumes and plant availability

three months ended March 31 (unaudited)	2013	2012

Physical sales volumes (GWh)
Supply
Generation	1,051	1,154
Purchased	2,479	1,570
	3,530	2,724

Plant availability1	79%	80%

1	The percentage of time the plant was available to generate power, regardless of whether it is running.

U.S. Power’s comparable EBITDA was US$67 million this quarter, or US$31 million higher than first quarter 2012. This was the net effect of:

·	higher realized power prices

·	higher realized capacity prices in New York

·	higher revenues on sales to wholesale, commercial and industrial customers

·	higher operating costs due to higher fuel prices.

Commodity prices in both New York and New England were significantly higher this quarter than first quarter 2012. The combination of higher natural gas prices, pipeline constraints and an increase in demand for natural gas resulted in higher spot power prices this quarter.

Physical sales volumes this quarter were higher than the same period in 2012 due to higher purchased volumes to serve increased sales to wholesale, commercial and industrial customers in the New England and PJM markets. Generation volumes were lower, mainly due to lower generation in New England partly offset by higher Ravenswood generation.

Power revenue was US$433 million this quarter, or US$238 million higher than first quarter 2012. This was mainly because of the combination of higher realized power prices and higher sales volumes to wholesale, commercial and industrial customers.

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Capacity revenue was US$47 million this quarter, or US$7 million higher than first quarter 2012. A two per cent increase in New York Zone J spot capacity prices and the impact of hedging activities resulted in higher realized prices in New York, partially offset by lower capacity prices in New England.

Commodity purchases resold were US$306 million this quarter, or US$189 million higher than first quarter 2012 because we purchased higher volumes of power at higher prices to fulfill increased power sales commitments to wholesale, commercial and industrial customers.

Plant operating costs and other, which includes fuel gas consumed in generation, was US$126 million this quarter, or US$35 million higher than first quarter 2012 because of higher natural gas fuel prices.

As at March 31, 2013, approximately 2,600 GWh or 41 per cent of U.S. Power’s planned generation is contracted for 2013, and 2,400 GWh or 27 per cent for 2014. Planned generation fluctuates depending on hydrology, wind conditions, commodity prices and the resulting dispatch of the assets. Power sales fluctuate based on customer usage.

NATURAL GAS STORAGE

Comparable EBITDA and comparable EBIT are non-GAAP measures. See non-GAAP measures section for more information.

three months ended March 31 (unaudited - millions of $)	2013		2012

Alberta Storage	20		15
General, administrative and support costs	(2	)	(2	)
Comparable EBITDA	18		13
Comparable depreciation and amortization	(3	)	(3	)
Comparable EBIT	15		10

Comparable EBITDA was $18 million this quarter, or $5 million higher than first quarter 2012, mainly due to higher earnings from CrossAlta resulting from the acquisition of the remaining 40 per cent interest in December 2012. The seasonal nature of natural gas storage generally results in higher revenues in the winter season.

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Recent developments

NATURAL GAS PIPELINES

NEB decision on the Canadian Restructuring Proposal

On March 27, 2013, the NEB issued its decision on our application to change the business structure and the terms and conditions of service for the Canadian Mainline, including tolls for 2012 and 2013.

The NEB approved several of our proposed changes, including the Canadian Mainline’s revenue requirement for 2011 and 2012. At the same time, the NEB agreed with us that the Canadian Mainline has been significantly affected by market forces with the result that throughput has decreased significantly, and as a result, the Canadian Mainline tolls have increased over a short period of time eroding the Canadian Mainline’s competitiveness. The response of the NEB was to adopt a multi-year fixed tolls approach which it believes will provide shippers with greater toll certainty and stability. Under the decision, long-term firm tolls are fixed through 2017 (subject to being re-opened under certain circumstances) at what the NEB determined is a competitive level. Although long-term firm tolls are fixed, the Canadian Mainline has been given pricing discretion for interruptible and short-term firm services. The NEB concluded in the decision that this framework will provide us with reasonable opportunity to recover our costs, over a reasonable period of time. Under or over collection variances to the revenue requirement inclusive of the return on and of capital will be carried over in deferral accounts to be dealt with in future NEB proceedings in 2017 (or earlier under certain circumstances). At that time, the NEB will determine how any variances contained in the deferral accounts will be addressed and the extent of cost disallowances, if any. As a result of the multi-year fixed tolls and increased risk associated with fluctuations in cash flow, the NEB increased the allowed return to 11.50 per cent on a 40 per cent equity ratio.

The decision significantly alters the regulatory framework that has formed the basis for more than $10 billion of regulated pipeline investment over the last sixty years. We have determined that we will seek regulatory and potentially legal review and variance of certain aspects of the decision.

NGTL System

The Alberta System is now known as the NGTL System to better reflect the service provided and continued growth in British Columbia.

Our application to contract for capacity on the Canadian Mainline and Foothills Pipelines was denied as part of the NEB’s decision regarding the Canadian Restructuring Proposal. Therefore, the location of our export delivery will remain at Empress and the Alberta/BC border.

NGTL System expansion projects

We have been continuing our expansion of the NGTL System and have placed approximately $340 million of new facilities into service to date in 2013. We have applied and received approval from the NEB for an additional $300 million of new facilities with in-service dates planned for later in 2013. The NEB has also recommended approval for the Chinchaga lateral, an approximate $100 million project, that is planned to be placed in service in early 2014. To date in 2013, we have applied for an additional $60 million of facilities and are planning regulatory applications for further expansion into B.C. which we estimate will cost between $1.0 billion and $1.5 billion to accommodate the Prince Rupert Gas Transmission Project.

Prince Rupert Gas Transmission Project

We signed the project development agreement for the Prince Rupert Gas Transmission Project with Progress Energy Canada Ltd. in February 2013 and are now working to initiate the environmental assessment process, including developing and filing the project description that we plan to submit to the B.C. Environmental Assessment Office and the Canadian Environmental Assessment Agency (CEAA) in second quarter 2013.

Coastal GasLink Pipeline Project

We are currently focused on community, landowner, government and First Nations engagement as the Coastal GasLink pipeline project advances through the regulatory process with the B.C. Environmental Assessment Office and the CEAA. We expect to begin an NGTL open season to provide delivery service to Vanderhoof, B.C. on Coastal GasLink in second quarter 2013.

Portland

We are holding a 45-day binding open season from April to May 2013 to determine the demand for new natural gas supply options for the New England and Atlantic Canada markets. The results could support an increase in our capacity from 168 MMcf/d to between 300 MMcf/d and 350 MMcf/d. The project will require upstream expansion on the Canadian Mainline that will be subject to an assessment of the implications of the recent NEB decision on the Canadian Restructuring Proposal.

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Tamazunchale

A variety of construction activities are underway on the Tamazunchale Extension and the project remains on schedule to meet the planned in-service date of first quarter 2014.

OIL PIPELINES

Gulf Coast Project

We are constructing a 36-inch pipeline from Cushing, Oklahoma to the U.S. Gulf Coast and expect to begin delivering crude oil to Port Arthur, Texas at the end of 2013. Construction is approximately 70 per cent complete and we estimate the total cost of the Cushing to Port Arthur facilities to be US$2.3 billion.

Construction of the 76 km (47 mile) Houston Lateral pipeline to transport crude oil to Houston refineries is expected to begin in mid 2013 and be complete by mid 2014 at a total cost of approximately US$300 million.

The Gulf Coast Project will have an initial capacity of up to 700,000 barrels per day.

Keystone XL Pipeline

In January 2013, the Governor of Nebraska approved our proposed re-route after the Nebraska Department of Environmental Quality issued its final evaluation report noting that construction and operation of Keystone XL is expected to have minimal environmental impacts in Nebraska.

On March 1, 2013, the U.S. Department of State (DOS) released its Draft Supplemental Environmental Impact Statement for the Keystone XL Pipeline. The impact statement reaffirmed that construction of the proposed pipeline from the U.S./Canada border in Montana to Steele City, Nebraska would not result in any significant impact to the environment. The DOS is in the process of reviewing comments on the impact statement that it received during a public comment period that ended on April 22, 2013. Once the DOS has completed its review, it is anticipated it will issue a Final Supplemental Environmental Impact Statement and then consult with other governmental agencies during a National Interest Determination period of up to 90 days, before making a decision on our Presidential Permit application.

Due to ongoing delays in the issuance of a Presidential Permit for Keystone XL, we now expect the pipeline to be in service in the second half of 2015 and, based on our pipeline construction experience, the US$5.3 billion cost estimate will increase depending on the timing of the permit. As of March 31, 2013, we had invested $1.8 billion in the project.

Energy East Pipeline

We announced in April 2013 that we are holding an open season to obtain firm commitments for a pipeline to transport crude oil from western receipt points to eastern Canadian markets. The open season, which follows a successful expression of interest phase and discussions with prospective shippers, began in April 2013 and closes in June 2013.

The Energy East Pipeline project involves converting natural gas pipeline capacity in approximately 3,000 kilometres of our existing Canadian Mainline to crude oil service and constructing up to approximately 1,400 kilometres of new pipeline. Subject to the results of the open season, the project will have the capacity to transport as much as 850,000 barrels of crude oil per day, increasing access to eastern Canadian markets.

We have begun Aboriginal and stakeholder engagement and field work as part of our initial design and planning. If the open season is successful, we will apply for regulatory approval to build and operate the facilities, with a potential in-service date of late 2017.

Northern Courier Pipeline

The Fort Hills Energy Limited Partnership has not indicated that their recent decision to cancel the Voyageur upgrader project has changed their current plans for Northern Courier. We have nearly completed the field work and Aboriginal and stakeholder engagement necessary to allow us to file the permit application with the Energy Resources Conservation Board and expect to file the application in second quarter 2013.

ENERGY

Ontario Solar

In late 2011, we agreed to buy nine Ontario solar projects (combined capacity of 86 MW) from Canadian Solar Solutions Inc. We expect to close the acquisition of the first three projects (combined capacity of 29

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MW) by mid 2013 for a total cost of approximately $175 million. We expect to acquire the remaining six projects later in 2013 and 2014, subject to regulatory approvals.

Bruce Power

Bruce Power returned Unit 4 to service on April 13, 2013 after completing an expanded life extension outage investment program which began in August 2012. It is anticipated that this investment will allow Unit 4 to operate until at least 2021.

On April 5, 2013, Bruce Power announced that it had reached an agreement with the OPA to extend the Bruce B floor price through to the end of the decade which is expected to coincide with the 2019 and 2020 end of life dates for the Bruce B units.

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Other income statement items

three months ended March 31 (unaudited - millions of $)	2013	2012

Comparable interest expense	257	242
Comparable interest income and other	(18	) (25	)
Comparable income taxes	159	140
Net income attributable to non-controlling interests	31	35

three months ended March 31 (unaudited - millions of $)	2013		2012

Comparable interest on long-term debt (including interest on junior subordinated notes)
Canadian dollar-denominated	122		128
U.S. dollar-denominated	188		186
Foreign exchange	1		-
	311		314

Other interest and amortization expense	1		2
Capitalized interest	(55	)	(74	)
Comparable interest expense	257		242

Comparable interest expense this quarter was $15 million higher than first quarter 2012 because of the following:

·	lower capitalized interest as a result of placing the refurbished units at Bruce Power in service, partially offset by increased capitalized interest for the Gulf Coast Project

·	lower interest expense due to Canadian and U.S. dollar-denominated debt maturities, partially offset by debt issues of US$750 million in January 2013, US$1 billion in August 2012 and US$500 million in March 2012.

Comparable interest income and other this quarter was $7 million lower than first quarter 2012 because we had realized losses in 2013 compared to realized gains in 2012 on derivatives used to manage our net exposure to foreign exchange rate fluctuations on U.S. dollar-denominated income.

Comparable income taxes were $159 million this quarter compared to $140 million in first quarter 2012. The increase was mainly the result of higher pre-tax earnings in 2013 compared to 2012 and changes in the proportion of income earned between Canadian and foreign jurisdictions.

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Financial condition

We strive to maintain financial strength and flexibility in all parts of an economic cycle, and rely on our operating cash flows to sustain our business, pay dividends and fund a portion of our growth.

We access capital markets to meet our financing needs, manage our capital structure and preserve our credit ratings.

We believe we have the capacity to fund our existing capital program through predictable cash flow from our operations, access to capital markets, cash on hand and substantial committed credit facilities.

CASH FROM OPERATING ACTIVITIES

three months ended March 31 (unaudited - millions of $)	2013		2012

Funds generated from operations1	916		871
Increase in operating working capital	(210	)	(169	)
Net cash from operations	706		702

1	See the non-GAAP measures section in this MD&A for further discussion of funds generated from operations.

Net cash provided by operations this quarter was $4 million higher than first quarter 2012, mainly because of an increase in funds generated from our operations which is consistent with our increase in earnings, partly offset by changes in operating working capital.

Our current assets were $2.5 billion and current liabilities were $5.5 billion, leaving us with a working capital deficit of $3.0 billion at March 31, 2013 compared to $3.1 billion at the end of 2012. This working capital deficiency is considered to be in the normal course of business and any funding of working capital is managed through our ability to generate cash flow and our ongoing access to capital markets.

CASH USED IN INVESTING ACTIVITIES

three months ended March 31 (unaudited - millions of $)	2013		2012

Capital expenditures		929		464
Equity investments		32		216

Our capital expenditures this quarter were primarily related to the Gulf Coast Project and expansion of the NGTL System.

CASH PROVIDED BY/(USED IN) FINANCING ACTIVITIES

three months ended March 31 (unaudited - millions of $)	2013		2012

Long-term debt issued, net of issue costs		734		492
Long-term debt repaid		(14	)	(548	)
Notes payable repaid		(829	)	(46	)
Dividends and distributions paid		(350	)	(343	)
Equity financing activities		618		14

In January 2013, we issued US$750 million of senior notes, maturing on January 15, 2016 and bearing interest at 0.75 per cent. These notes were issued under the US$4.0 billion debt shelf prospectus filed in November 2011.

In March 2013, we completed a public offering of 24 million Series 7 cumulative redeemable first preferred shares at a price of $25 per share for aggregate gross proceeds of $600 million. Investors will be entitled to receive fixed cumulative dividends at an annual rate of $1.00 per share, payable quarterly. Investors will have the right to convert their shares into cumulative redeemable first preferred shares, Series 8, every fifth year beginning on April 30, 2019. The holders of Series 8 will be entitled to receive quarterly floating rate cumulative dividends at an annualized rate equal to the then 90-day Government of Canada treasury bill rate plus 2.38 per cent.

The net proceeds of the two offerings will be used to fund our capital program, for general corporate purposes and to reduce short term indebtedness.

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FIRST QUARTER REPORT 2013

DIVIDENDS

On April 25, 2013 we declared quarterly dividends as follows:

Quarterly dividend on our common shares

$0.46 per share (for the quarter ending June 30, 2013)

Payable on July 31, 2013 to shareholders of record at the close of business on June 28, 2013

Quarterly dividends on our preferred shares

Series 1 $0.2875 (for the quarter ending June 30, 2013)

Series 3 $0.25 (for the quarter ending June 30, 2013)

Payable on July 2, 2013 to shareholders of record at the close of business on May 31, 2013

Series 5 $0.275 (for the three month period ending July 30, 2013)

Series 7 $0.25 (for the three month period ending July 30, 2013)

Payable on July 30, 2013 to shareholders of record at the close of business on June 28, 2013

SHARE INFORMATION

as at April 22, 2013
Common shares	Issued and outstanding 707 million
Preferred shares	Issued and outstanding	Convertible to
Series 1	22 million	22 million Series 2 preferred shares
Series 3	14 million	14 million Series 4 preferred shares
Series 5	14 million	14 million Series 6 preferred shares
Series 7	24 million	24 million Series 8 preferred shares
Options to buy common shares	Outstanding 8 million	Exercisable 5 million

CREDIT FACILITIES

We use committed, revolving credit facilities to support our commercial paper programs, along with additional demand facilities, for general corporate purposes including issuing letters of credit and providing additional liquidity.

At March 31, 2013, we had $5 billion in unsecured credit facilities, including:

Amount	Unused capacity	Subsidiary	For	Matures

$2.0 billion	$2.0 billion	TransCanada PipeLines Limited (TCPL)	Committed, revolving, extendible credit facility that supports TCPL’s Canadian commercial paper program	October 2017
US$1.0 billion	US$1.0 billion	TransCanada PipeLine USA Ltd. (TCPL USA)	Committed, revolving extendible credit facility that supports a TCPL USA U.S. dollar commercial paper program in the U.S.	October 2013
US$1.0 billion	US$1.0 billion	TransCanada Keystone Pipeline, LP	Committed, revolving, extendible credit facility that supports a U.S. dollar commercial paper program in Canada dedicated to funding a portion of Keystone	November 2013
$0.9 billion, US$0.1 billion	$360 million	TCPL, TCPL USA	Demand lines for issuing letters of credit and as a source of additional liquidity. At March 31, 2013, we had outstanding $640 million in letters of credit under these lines	Demand

See Risks and financial instruments for more information about liquidity, market and other risks.

CONTRACTUAL OBLIGATIONS

Other than a decrease of $560 million to our capital commitments and $190 million to other purchase commitments, there were no material changes to our contractual obligations in first quarter 2013 or to payments due in the next five years or after. See the MD&A in our 2012 Annual Report for more information about our contractual obligations.

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FIRST QUARTER REPORT 2013

Financial risks and financial instruments

We are exposed to liquidity risk, counterparty credit risk and market risk, and have strategies, policies and limits in place to mitigate their impact on our earnings, cash flow and ultimately shareholder value. These are designed to ensure our risks and related exposures are in line with our business objectives and risk tolerance.

Please see our 2012 Annual Report for more information about the risks we face in our business. In addition to those disclosed risks, in the NEB’s March 2013 decision on our Canadian Restructuring Proposal, the NEB found that the fundamental business risk facing the Canadian Mainline has increased. The tolling framework created by the NEB decision results in higher variability in cash flows and greater uncertainty about the ultimate recovery of the Canadian Mainline’s cost of service. Otherwise, our risks have not changed substantially since December 31, 2012.

LIQUIDITY RISK

We manage our liquidity by continuously forecasting our cash flow for a 12 month period and making sure we have adequate cash balances, cash flow from operations, committed and demand credit facilities and access to capital markets to meet our operating, financing and capital expenditure obligations under both normal and stressed economic conditions.

COUNTERPARTY CREDIT RISK

We have exposure to counterparty credit risk in the following areas:

·	accounts receivable

·	portfolio investments

·	the fair value of derivative assets

·	notes, loans and advances receivable.

We review our accounts receivable regularly and record allowances for doubtful accounts using the specific identification method. At March 31, 2013, we had not incurred any significant credit losses and had no significant amounts past due or impaired. We had a credit risk concentration of $256 million with one counterparty at March 31, 2013 (December 31, 2012 - $259 million). This amount is secured by a guarantee from the counterparty’s parent company and we anticipate collecting the full amount.

We have significant credit and performance exposure to financial institutions because they hold cash deposits and provide committed credit lines and letters of credit that help manage our exposure to counterparties and provide liquidity in commodity, foreign exchange and interest rate derivative markets.

FOREIGN EXCHANGE RISK

Certain of our businesses generate income in U.S. dollars, but since we report in Canadian dollars, changes in the value of the U.S. dollar against the Canadian dollar can affect our net income. As our U.S. operations continue to grow, our exposure to changes in currency rates increases. Some of this risk is offset by interest expense on U.S. dollar-denominated debt and by using foreign exchange derivatives.

We use foreign exchange derivatives to manage other foreign exchange transactions, including foreign exchange exposures that arise on some of our regulated assets. We defer some of the realized gains and losses on these derivatives as regulatory assets and liabilities until we recover or pay them to shippers according to the terms of the shipping agreements.

AVERAGE EXCHANGE RATE - U.S. TO CANADIAN DOLLARS

First quarter 2013	1.01
First quarter 2012	1.00

The impact of changes in the value of the U.S. dollar on our U.S. operations is significantly offset by other U.S. dollar-denominated items, as set out in the table below. Comparable EBIT is a non-GAAP measure.

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FIRST QUARTER REPORT 2013

SIGNIFICANT U.S. DOLLAR-DENOMINATED AMOUNTS

three months ended March 31 (unaudited - millions of US$)	2013		2012

U.S. and International Natural Gas Pipelines comparable EBIT		200		215
U.S. Oil Pipelines comparable EBIT		94		89
U.S. Power comparable EBIT		39		6
Interest expense on U.S. dollar-denominated long-term debt		(188	)	(186	)
Capitalized interest on U.S. capital expenditures		44		26
U.S. non-controlling interests and other		(48	)	(51	)
		141		99

NET INVESTMENT IN FOREIGN OPERATIONS

We hedge our net investment in foreign operations (on an after-tax basis) with U.S. dollar-denominated debt, cross-currency interest rate swaps, forward foreign exchange contracts and foreign exchange options. The fair values and notional amounts for the derivatives designated as a net investment hedge were as follows:

	March 31, 2013			December 31, 2012
Asset/(liability) (unaudited - millions of $)	Fair value1		Notional amount	Fair value1	Notional amount

U.S. dollar cross-currency swaps
(maturing 2013 to 2019)2		5	US 3,800	82	US 3,800
U.S. dollar forward foreign exchange contracts
(maturing 2013)		(1)	US 850	-	US 250
		4	US 4,650	82	US 4,050

1	Fair values equal carrying values.

2	Net income in first quarter 2013 included net realized gains of $7 million (2012 - gains of $7 million) related to the interest component of cross-currency swap settlements.

U.S. DOLLAR-DENOMINATED DEBT DESIGNATED AS A NET INVESTMENT HEDGE

(unaudited - billions of $)	March 31, 2013	December 31, 2012

Carrying value	12.1 (US 11.9)	11.1 (US 11.2)
Fair value	15.0 (US 14.7)	14.3 (US 14.4)

FAIR VALUE OF DERIVATIVES USED TO HEDGE OUR

U.S. DOLLAR INVESTMENT IN FOREIGN OPERATIONS

The classification of the fair value of derivatives to hedge our net investments on the balance sheet.

(unaudited - millions of $)	March 31, 2013	December 31, 2012

Other current assets	47	71
Intangible and other assets	22	47
Accounts payable and other	10	6
Other long-term liabilities	55	30

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FIRST QUARTER REPORT 2013

NON-DERIVATIVE FINANCIAL INSTRUMENTS SUMMARY

	March 31, 2013		December 31, 2012
(unaudited - millions of $)	Carrying amount1	Fair value2	Carrying amount1	Fair value2

Financial assets
Cash and cash equivalents	443	443	551	551
Accounts receivable and other3	1,269	1,322	1,288	1,337
Available for sale assets3	49	49	44	44
	1,761	1,814	1,883	1,932

Financial liabilities4
Notes payable	1,474	1,474	2,275	2,275
Accounts payable and other long-term liabilities5	1,034	1,034	1,535	1,535
Accrued interest	352	352	368	368
Long-term debt	19,926	25,081	18,913	24,573
Junior subordinated notes	1,015	1,083	994	1,054
	23,801	29,024	24,085	29,805

Recorded at amortized cost, except for US$350 million (December 31, 2012 - US$350 million) of long-term debt that is attributed to hedged risk which is recorded at fair value. This debt which is recorded at fair value on a recurring basis is classified in Level II of the fair value hierarchy using the income approach based on interest rates from external data service providers.

2	The fair value measurement of financial assets and liabilities recorded at amortized cost for which fair value is not equal to the carrying value would be included in Level II of the fair value hierarchy using the income approach based on interest rates from external data service providers.

3	At March 31, 2013, financial assets of $1.0 billion (December 31, 2012 - $1.1 billion) are included in accounts receivable, $70 million (December 31, 2012 - $40 million) in other current assets and $217 million (December 31, 2012 - $240 million) in intangible and other assets.

Condensed consolidated statement of income in first quarter 2013 included losses of $10 million (2012 - losses of $15 million) for fair value adjustments related to interest rate swap agreements on US$350 million of long-term debt at March 31, 2013 (December 31, 2012 - US$350 million). There were no other unrealized gains or losses from fair value adjustments to non-derivative financial instruments.

5	At March 31, 2013, financial liabilities of $1.0 billion (December 31, 2012 - $1.5 billion) are included in accounts payable, and $41 million (December 31, 2012 - $38 million) in other long-term liabilities.

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FIRST QUARTER REPORT 2013

DERIVATIVE INSTRUMENTS SUMMARY

The following summary does not include hedges of our net investment in foreign operations.

2013 (unaudited - millions of $ unless noted otherwise)	Power		Natural gas		Foreign exchange		Interest

Derivative instruments held for trading1
Fair values2
Assets	$159		$85		$-		$13
Liabilities	$(206	)	$(93	)	$(8	)	$(13)
Notional values
Volumes3
Sales	36,445		71		-		-
Purchases	34,536		102		-		-
Canadian dollars	-		-		-		620
U.S. dollars	-		-		US 1,396		US 200
Net unrealized (losses)/gains in the three months ended March 31, 20134	$(8	)	$9		$(6	)	$-
Net realized losses in the three months ended March 31, 20134	$(7	)	$(2	)	$(1	)	$-
Maturity dates	2013-2017		2013-2016		2013-2014		2013-2016

Derivative instruments in hedging relationships5,6
Fair values2
Assets	$70		$-		$-		$10
Liabilities	$(73	)	$(1	)	$(36	)	$-
Notional values
Volumes3
Sales	6,358		-		-		-
Purchases	14,400		1		-		-
U.S. dollars	-		-		US 23		US 350
Cross-currency	-		-		136/US 100		-
Net realized gains in the three months ended March 31, 20134	$73		$-		$-		$2
Maturity dates	2013-2018		2013		2013-2014		2013-2015

All derivative instruments held for trading have been entered into for risk management purposes and are subject to our risk management strategies, policies and limits. These include derivatives that have not been designated as hedges or do not qualify for hedge accounting treatment but have been entered into as economic hedges to manage our exposure to market risk.

2	Fair values equal carrying values.

3	Volumes for power and natural gas derivatives are in GWh and Bcf, respectively.

Realized and unrealized gains and losses on held for trading derivative instruments used to purchase and sell power and natural gas are included net in revenues. Realized and unrealized gains and losses on interest rate and foreign exchange derivative financial instruments held for trading are included in interest expense and interest income and other, respectively. The effective portion of the change in fair value of derivative instruments in hedging relationships is initially recognized in OCI and reclassified to revenues, interest expense and interest income and other, as appropriate, as the original hedged item settles.

All hedging relationships are designated as cash flow hedges except for interest rate derivative financial instruments designated as fair value hedges with a fair value of $10 million and a notional amount of US$350 million. For the three months ended March 31, 2013, net realized gains on fair value hedges were $2 million and were included in interest expense. For the three months ended March 31, 2013, we did not record any amounts in net income related to ineffectiveness for fair value hedges.

6	For the three months ended March 31, 2013, there were no gains or losses included in net income relating to discontinued cash flow hedges where it was probable that the anticipated transaction would not occur.

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FIRST QUARTER REPORT 2013

The following summary does not include hedges of our net investment in foreign operations.

2012 (unaudited - millions of $ unless noted otherwise)	Power		Natural gas		Foreign exchange		Interest

Derivative instruments held for trading1
Fair values2,3
Assets	$139		$88		$1		$14
Liabilities	$(176	)	$(104	)	$(2	)	$(14	)
Notional values3
Volumes4
Sales	31,066		65		-		-
Purchases	31,135		83		-		-
Canadian dollars	-		-		-		620
U.S. dollars	-		-		US 1,408		US 200
Net unrealized (losses)/gains in the three months ended March 31, 20125	$(7	)	$(14	)	$6		$-
Net realized (losses)/gains in the three months ended March 31, 20125	$15		$(10	)	$9		$-
Maturity dates	2013 -2017		2013-2016		2013		2013-2016

Derivative instruments in hedging relationships 6,7
Fair values2,3
Assets	$76		$-		$-		$10
Liabilities	$(97	)	$(2	)	$(38	)	$-
Notional values3
Volumes4
Sales	7,200		-		-		-
Purchases	15,184		1		-		-
U.S. dollars	-		-		US 12		US 350
Cross-currency	-		-		136/US 100		-
Net realized (losses)/gains in the three months ended March 31, 20125	$(32	)	$(6	)	$-		$1
Maturity dates	2013-2018		2013		2013-2014		2013-2015

All derivative instruments held for trading have been entered into for risk management purposes and are subject to our risk management strategies, policies and limits. This includes derivatives that have not been designated as hedges or do not qualify for hedge accounting treatment but have been entered into as economic hedges to manage our exposure to market risk.

2	Fair values equal carrying values.

3	As at December 31, 2012.

4	Volumes for power and natural gas derivatives are in GWh and Bcf, respectively.

All hedging relationships are designated as cash flow hedges except for interest rate derivative financial instruments designated as fair value hedges with a fair value of $10 million and a notional amount of US$350 million. For the three months ended March 31, 2012, net realized gains on fair value hedges were $2 million and were included in interest expense. For the three months ended March 31, 2012, we did not record any amounts in net income related to ineffectiveness for fair value hedges.

7	For the three months ended March 31, 2012, there were no gains or losses included in net income relating to discontinued cash flow hedges where it was probable that the anticipated transaction would not occur.

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BALANCE SHEET PRESENTATION OF DERIVATIVE INSTRUMENTS

The fair value of the derivative instruments on the balance sheet.

(unaudited - millions of $)	March 31, 2013		December 31, 2012

Current
Other current assets	248		259
Accounts payable and other	(302	)	(283	)
Long term
Intangible and other assets	158		187
Other long-term liabilities	(193	)	(186	)

DERIVATIVES IN CASH FLOW HEDGING RELATIONSHIPS

The components of other comprehensive income (OCI) related to derivatives in cash flow hedging relationships.

Cash flow hedges1 three months ended March 31	Power				Natural gas			Foreign exchange			Interest
(unaudited - millions of $, pre-tax)	2013		2012		2013	2012		2013	2012		2013	2012

Change in fair value of derivative instruments recognized in OCI (effective portion)	36		(66	)	-	(10	)	2	(3	)	-	-
Reclassification of gains and losses on derivative instruments from AOCI to net income (effective portion)	(11	)	47		-	13		-	-		4	6
Gains and losses on derivative instruments recognized in earnings (ineffective portion)	(5	)	(6	)	-	(2	)	-	-		-	-

1	No amounts have been excluded from the assessment of hedge effectiveness.

CREDIT RISK RELATED CONTINGENT FEATURES

Derivatives contracts often contain financial assurance provisions that may require us to provide collateral if a credit risk-related contingent event occurs (for example, if our credit rating is downgraded to non-investment grade).

Based on contracts in place and market prices at March 31, 2013, the aggregate fair value of all derivative contracts with credit-risk-related contingent features that were in a net liability position was $34 million (December 31, 2012 - $37 million), with collateral provided in the normal course of business of nil (December 31, 2012 - nil). If the credit-risk-related contingent features in these agreements had been triggered on March 31, 2013, we would have been required to provide collateral of $34 million (December 31, 2012 - $37 million) to our counterparties. Collateral may also need to be provided should the fair value of derivative instruments exceed pre-defined contractual exposure limit thresholds.

We feel we have sufficient liquidity in the form of cash and undrawn committed revolving bank lines to meet these contingent obligations should they arise.

FAIR VALUE HIERARCHY

Assets and liabilities that are recorded at fair value are required to be categorized into three levels based on the fair value hierarchy.

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FIRST QUARTER REPORT 2013

Levels	How fair value has been determined

Level I	Quoted prices in active markets for identical assets and liabilities that we have the ability to access at the measurement date.
Level II	Valuation based on the extrapolation of inputs, other than quoted prices included within Level I, for which all significant inputs are observable directly or indirectly. Inputs include published exchange rates, interest rates, interest rate swap curves, yield curves and broker quotes from external data service providers. This category includes interest rate and foreign exchange derivative assets and liabilities where fair value is determined using the income approach and power and natural gas commodity derivatives where fair value is determined using the market approach.
Level III	Valuation of assets and liabilities measured on a recurring basis using a market approach based on inputs that are unobservable and significant to the overall fair value measurement. This category includes long-dated commodity transactions in certain markets where liquidity is low. Long term electricity prices are estimated using a third-party modeling tool which takes into account physical operating characteristics of generation facilities in the markets in which we operate. Model inputs include market fundamentals such as fuel prices, power supply additions and retirements, power demand, seasonal hydro conditions and transmission constraints. Long-term North American natural gas prices are based on a view of future natural gas supply and demand, as well as exploration and development costs. Significant decreases in fuel prices or demand for electricity or natural gas, or increases in the supply of electricity or natural gas is expected to or may result in a lower fair value measurement of contracts included in Level III.

The fair value of our assets and liabilities measured on a recurring basis, including both current and non-current positions.

	Quoted prices in active markets (Level I)1				Significant other observable inputs (Level II)				Significant unobservable inputs (Level III)				Total
(unaudited - millions of $, pre-tax)	Mar 31, 2013		Dec 31, 2012		Mar 31, 2013		Dec 31, 2012		Mar 31, 2013		Dec 31, 2012		Mar 31, 2013		Dec 31, 2012

Derivative instrument assets:
Power commodity contracts	-		-		224		213		5		2		229		215
Natural gas commodity contracts	77		75		8		13		-		-		85		88
Foreign exchange contracts	-		-		69		119		-		-		69		119
Interest rate contracts	-		-		23		24		-		-		23		24
Derivative instrument liabilities:
Power commodity contracts	-		-		(275	)	(269	)	(4	)	(4	)	(279	)	(273	)
Natural gas commodity contracts	(79	)	(95	)	(15	)	(11	)	-		-		(94	)	(106	)
Foreign exchange contracts	-		-		(109	)	(76	)	-		-		(109	)	(76	)
Interest rate contracts	-		-		(13	)	(14	)	-		-		(13	)	(14	)
Non-derivative financial instruments:
Available for sale assets	49		44		-		-		-		-		49		44
	47		24		(88	)	(1	)	1		(2	)	(40	)	21

The following table presents the net change in the Level III fair value category.

three months ended March 31	Derivatives1
(unaudited - millions of $, pre-tax)	2013		2012

Balance at January 1	(2	)	(15	)
Total gains included in OCI	3		4
Balance at March 31	1		(11	)

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FIRST QUARTER REPORT 2013

1	For the three months ended March 31, 2013, the unrealized gains or losses included in net income attributed to derivatives in the Level III category that were still held at the reporting date was nil (2012 - nil).

A 10 per cent increase or decrease in commodity prices, with all other variables held constant, would result in a $3 million decrease or increase, respectively, in the fair value of outstanding derivative instruments included in Level III at March 31, 2013.

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FIRST QUARTER REPORT 2013

Other information

CONTROLS AND PROCEDURES

Management, including our President and CEO and our CFO, evaluated the effectiveness of our disclosure controls and procedures as at March 31, 2013, as required by the Canadian securities regulatory authorities and by the SEC, and concluded that our disclosure controls and procedures are effective at a reasonable assurance level.

There were no changes in first quarter 2013 that had or are likely to have a material impact on our internal control over financial reporting.

Management is in the process of implementing an Enterprise Resource Planning (ERP) system that will likely affect some processes supporting internal control over financial reporting in subsequent quarters of 2013. The phased implementation period is planned to begin July 1, 2013.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES, AND ACCOUNTING CHANGES

When we prepare financial statements that conform with U.S. GAAP, we are required to make estimates and assumptions that affect the timing and amount we record for our assets, liabilities, revenues and expenses because these items may be affected by future events. We base the estimates and assumptions on the most current information available, using our best judgment. We also regularly assess the assets and liabilities themselves.

Our significant accounting policies and critical accounting estimates have remained unchanged since December 31, 2012. You can find a summary of our significant accounting policies and critical accounting estimates in our 2012 Annual Report.

Changes in accounting policies for 2013

Balance sheet offsetting

Effective January 1, 2013, we adopted the Accounting Standards Update (ASU) on disclosures about balance sheet offsetting as issued by the Financial Accounting Standards Board (FASB) to enable understanding of the effects of netting arrangements on our financial position. Adoption of the ASU has resulted in increased qualitative and quantitative disclosures about certain derivative instruments that are either offset in accordance with current U.S. GAAP or are subject to a master netting arrangement or similar agreement.

Accumulated other comprehensive income

Effective January 1, 2013, we adopted the ASU on reporting of amounts reclassified out of accumulated other comprehensive income (AOCI) as issued by the FASB. Adoption of the ASU has resulted in providing additional qualitative and quantitative disclosures about significant amounts reclassified out of AOCI into net income.

Future accounting changes

Obligations resulting from joint and several liability arrangements

In February 2013, the FASB issued guidance for recognizing, measuring, and disclosing obligations resulting from joint and several liability arrangements when the total amount of the obligation is fixed at the reporting date. Debt arrangements, other contractual obligations, and settled litigation and judicial rulings are examples of these obligations. This ASU is effective retrospectively for fiscal years, and interim periods within those years, beginning after December 15, 2013. We are evaluating the impact that adopting the ASU would have on our consolidated financial statements, but do not expect it to be material.

Foreign currency matters - cumulative translation adjustment

In March 2013, the FASB issued amended guidance related to the release of the cumulative translation adjustment into net income when a parent either sells a part or all of its investment in a foreign entity or no longer holds a controlling financial interest in a subsidiary or group of assets that is a business. This ASU is effective prospectively for fiscal years, and interim reporting periods within those years, beginning after December 15, 2013. Early adoption is allowed as of the beginning of the entity's fiscal year. We are evaluating the impact that adopting this ASU would have on our consolidated financial statements, but do not expect it to be material.

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QUARTERLY RESULTS

SELECTED QUARTERLY CONSOLIDATED FINANCIAL DATA

(millions of $, except per share amounts)

	2013	2012				2011
(unaudited)	First	Fourth	Third	Second	First	Fourth	Third	Second

Revenues	2,252	2,089	2,126	1,847	1,945	2,015	2,043	1,851
Net income attributable to common shares	446	306	369	272	352	376	386	353

Share Statistics
Net Income per common share - basic and diluted	$0.63	$0.43	$0.52	$0.39	$0.50	$0.53	$0.55	$0.50
Dividend declared per common share	$0.46	$0.44	$0.44	$0.44	$0.44	$0.42	$0.42	$0.42

FACTORS AFFECTING QUARTERLY FINANCIAL INFORMATION BY BUSINESS SEGMENT

Quarter-over-quarter revenues and net incomes sometimes fluctuate. The causes of this fluctuation vary across our business segments.

In Natural Gas Pipelines, quarter-over-quarter revenues and net income generally remain relatively stable during any fiscal year. Over the long term, however, they fluctuate because of:

·	regulators' decisions

·	negotiated settlements with shippers

·	seasonal fluctuations in short-term throughput volumes on U.S. pipelines

·	acquisitions and divestitures

·	developments outside of the normal course of operations

·	newly constructed assets being placed in service.

In Oil Pipelines, annual revenues and net income are based on contracted crude oil transportation and uncommitted spot transportation. Quarter-over-quarter revenues and net income during any particular fiscal year remain relatively stable.

In Energy, quarter-over-quarter revenues and net income are affected by:

weather

·	customer demand

·	market prices

·	capacity prices and payments

·	planned and unplanned plant outages

·	acquisitions and divestitures

·	certain fair value adjustments

·	developments outside of the normal course of operations

·	newly constructed assets being placed in service.

FACTORS AFFECTING FINANCIAL INFORMATION BY QUARTER

First quarter 2013

·	EBIT included $42 million of pre-tax income ($84 million after-tax) from the Canadian Restructuring Proposal relating to 2012 and net unrealized losses of $10 million pre-tax ($8 million after-tax) from certain risk management activities.

Fourth quarter 2012

·	EBIT included net unrealized losses of $17 million pre-tax ($12 million after-tax) from certain risk management activities.

Third quarter 2012

·	EBIT included net unrealized gains of $31 million pre-tax ($20 million after-tax) from certain risk management activities.

TRANSCANADA [34

FIRST QUARTER REPORT 2013

Second quarter 2012

·	EBIT included a $50 million pre-tax charge ($37 million after-tax) from the Sundance A PPA arbitration decision, and net unrealized losses of $14 million pre-tax ($13 million after-tax) from certain risk management activities.

First quarter 2012

·	EBIT included net unrealized losses of $22 million pre-tax ($11 million after-tax) from certain risk management activities.

Fourth quarter 2011

·	EBIT included net unrealized gains of $13 million pre-tax ($11 million after-tax) from certain risk management activities.

Third quarter 2011

·	EBIT included net unrealized losses of $43 million pre-tax ($30 million after-tax) from certain risk management activities.

Second quarter 2011

·	EBIT included net unrealized losses of $3 million pre-tax ($2 million after-tax) from certain risk management activities.

Comparable measure	Original measure
comparable earnings	net income attributable to common shares
comparable earnings per common share	net income per common share
comparable EBITDA	EBITDA
comparable EBIT	EBIT
comparable depreciation and amortization	depreciation and amortization
comparable interest expense	interest expense
comparable interest income and other	interest income and other
comparable income taxes	income tax expense/(recovery)

three months ended March 31 (unaudited - millions of $, except per share amounts)	2013		2012

Comparable EBITDA	1,168		1,113
Comparable depreciation and amortization	(354	)	(344	)
Comparable EBIT	814		769

Other income statement items
Comparable interest expense	(257	)	(242	)
Comparable interest income and other	18		25
Comparable income taxes	(159	)	(140	)
Net income attributable to non-controlling interests	(31	)	(35	)
Preferred share dividends	(15	)	(14	)
Comparable earnings	370		363
Specific items (net of tax):
Canadian restructuring proposal - 2012	84		-
Risk management activities1	(8	)	(11	)
Net income attributable to common shares	446		352

Comparable depreciation and amortization	(354	)	(344	)
Specific item:
Canadian restructuring proposal	(13	)	-
Depreciation and amortization	(367	)	(344	)

Comparable interest expense	(257	)	(242	)
Specific item:
Canadian restructuring proposal - 2012	(1	)	-
Interest expense	(258	)	(242	)

Comparable interest income and other	18		25
Specific items:
Canadian restructuring proposal - 2012	1		-
Risk management activities1	(6	)	6
Interest income and other	13		31

Comparable income taxes	(159	)	(140	)
Specific items:
Canadian restructuring proposal - 2012	42		-
Risk management activities1	2		11
Income taxes expense	(115	)	(129	)

Comparable earnings per common share	$0.52		$0.52
Specific items (net of tax):
Canadian restructuring proposal - 2012	0.12		-
Risk management activities1	(0.01	)	(0.02	)
Net income per common share	$0.63		$0.50

three months ended March 31, 2013 (unaudited - millions of $)	Natural Gas Pipelines		Oil Pipelines		Energy		Corporate		Total

Comparable EBITDA	746		179		277		(34	)	1,168
Comparable depreciation and amortization	(240	)	(37	)	(74	)	(3	)	(354	)
Comparable EBIT	506		142		203		(37	)	814

three months ended March 31, 2012 (unaudited - millions of $)	Natural Gas Pipelines		Oil Pipelines		Energy		Corporate		Total

Comparable EBITDA	725		173		244		(29	)	1,113
Comparable depreciation and amortization	(232	)	(36	)	(73	)	(3	)	(344	)
Comparable EBIT	493		137		171		(32	)	769