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1	Comparable EBITDA, comparable earnings, comparable earnings per common share and funds generated from operations are all non-GAAP measures. See non-GAAP measures section for more information.

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•	anticipated business prospects

•	our financial and operational performance, including the performance of our subsidiaries

•	expectations or projections about strategies and goals for growth and expansion

•	expected cash flows and future financing options available to us

•	expected costs for planned projects, including projects under construction and in development

•	expected schedules for planned projects (including anticipated construction and completion dates)

•	expected regulatory processes and outcomes

•	expected impact of regulatory outcomes

•	expected outcomes with respect to legal proceedings, including arbitration and insurance claims

•	expected capital expenditures and contractual obligations

•	expected operating and financial results

•	the expected impact of future accounting changes, commitments and contingent liabilities

•	expected industry, market and economic conditions.

•	inflation rates, commodity prices and capacity prices

•	timing of financings and hedging

•	regulatory decisions and outcomes

•	foreign exchange rates

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•	interest rates

•	tax rates

•	planned and unplanned outages and the use of our pipeline and energy assets

•	integrity and reliability of our assets

•	access to capital markets

•	anticipated construction costs, schedules and completion dates

•	acquisitions and divestitures.

•	our ability to successfully implement our strategic initiatives

•	whether our strategic initiatives will yield the expected benefits

•	the operating performance of our pipeline and energy assets

•	amount of capacity sold and rates achieved in our pipeline businesses

•	the availability and price of energy commodities

•	the amount of capacity payments and revenues we receive from our energy business

•	regulatory decisions and outcomes

•	outcomes of legal proceedings, including arbitration and insurance claims

•	performance of our counterparties

•	changes in the political environment

•	changes in environmental and other laws and regulations

•	competitive factors in the pipeline and energy sectors

•	construction and completion of capital projects

•	costs for labour, equipment and materials

•	access to capital markets

•	interest and foreign exchange rates

•	weather

•	cyber security

•	technological developments

•	economic conditions in North America as well as globally.

•	EBITDA

•	EBIT

•	funds generated from operations

•	comparable earnings

•	comparable earnings per common share

•	comparable EBITDA

•	comparable EBIT

•	comparable depreciation and amortization

•	comparable interest expense

•	comparable interest income and other

•	comparable income tax expense.

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•	certain fair value adjustments relating to risk management activities

•	income tax refunds and adjustments

•	gains or losses on sales of assets

•	legal, contractual and bankruptcy settlements

•	impact of regulatory or arbitration decisions relating to prior year earnings

•	write-downs of assets and investments.

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1	Previously Oil Pipelines.

•	a gain on the sale of Cancarb Limited and its related power generation business of $99 million after tax

•	a net loss resulting from a termination payment to Niska Gas Storage for contract restructuring of $32 million after tax

•	unrealized gains and losses from changes in certain risk management activities.

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•	incremental earnings from the Gulf Coast extension of the Keystone Pipeline System

•	higher earnings from Mexico pipelines resulting from contract revenues recognized from the Tamazunchale Extension

•	higher interest expense from debt issuances, higher foreign exchange on interest related to U.S. dollar-denominated debt and lower capitalized interest on projects placed in service

•	lower earnings from Western Power as a result of lower realized power prices.

•	incremental earnings from the Gulf Coast extension of the Keystone Pipeline System

•	lower earnings from Western Power as a result of lower realized power prices

•	higher earnings from U.S. Power mainly because of higher realized capacity and power prices

•	higher earnings from Mexico pipelines resulting from contract revenues recognized from the Tamazunchale Extension

•	higher earnings from U.S. natural gas pipelines due to higher transportation revenues at Great Lakes and higher contributions from TC PipeLines, LP reflecting colder winter weather and increased demand

•	higher interest expense from debt issuances, higher foreign exchange on interest related to U.S. dollar-denominated debt and lower capitalized interest on projects placed in service.

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1	A force majeure has delayed completion of construction, however, revenue is being recorded from the original in service date of March 9, 2014 as per the terms of the Transportation Service Agreement.

2	Approximately two years from the date the Keystone XL permit is received.

3	Represents our 50 per cent share.

4	Estimated project cost dependent on the timing of the Presidential permit.

5	Excludes transfer of Canadian Mainline natural gas assets.

•	the gain on sale of Cancarb Limited and its related power generation facility

•	the termination payment to Niska Gas Storage for the contract restructuring

•	increased outage days at Bruce A.

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1	In 2014, comparable depreciation and amortization is equivalent to the GAAP measure, depreciation and amortization. In 2013, comparable depreciation and amortization for the nine months ended September 30, 2013 is adjusted by $13 million relating to the impact of the NEB decision (RH-003-2011).

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

2

Beginning in August 2014, TC PipeLines, LP began its at-the-market equity issuance program which will decrease our ownership interest in TC PipeLines, LP going forward. Effective May 22, 2013, our ownership interest in TC PipeLines, LP decreased from 33.3 per cent to 28.9 per cent. On July 1, 2013, we sold 45 per cent of GTN and Bison to TC PipeLines, LP. The following shows our ownership interest in TC PipeLines, LP and our effective ownership of GTN, Bison, and Great Lakes through our ownership interest in TC PipeLines, LP for the periods presented.

3	Represents our 53.6 per cent direct ownership interest.

4	Effective July 1, 2013, represents our 30 per cent direct ownership interest. Prior to July 1, 2013, our direct ownership interest was 75 per cent.

5	Represents our 61.7 per cent ownership interest.

6	Includes our share of the equity income from Gas Pacifico/INNERGY and TransGas as well as general and administration costs relating to our U.S. and International Pipelines.

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

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•

contract revenues recognized from the Tamazunchale Extension from the original in-service date of March 9, 2014. The Tamazunchale Extension project has experienced delays in completing construction due to archeological findings along the pipeline route. The CFE agreed that, under the terms of the TSA, these delays constitute force majeure and, as a result, collection and recognition of revenue commenced on March 9, 2014.

•	higher transportation revenues at Great Lakes mainly due to colder winter weather and increased demand.

•	higher OM&A costs at ANR as well as lower storage revenues.

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 nine months ended September 30, 2014 were 940 Bcf (2013 – 547 Bcf). Average per day was 3.5 Bcf (2013 – 2.0 Bcf).

2	Field receipt volumes for the NGTL System for the nine months ended September 30, 2014 were 2,857 Bcf (2013 – 2,748 Bcf). Average per day was 10.5 Bcf (2013 – 10.1 Bcf).

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

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1	Previously Oil Pipelines.

2	Comparable depreciation and amortization is equivalent to the GAAP measure, depreciation and amortization.

•	incremental earnings from the Gulf Coast extension which was placed in service in January 2014

•	a stronger U.S. dollar which had a positive impact on the Canadian dollar equivalent comparable earnings from our U.S. operations.

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1	Comparable depreciation and amortization is equivalent to the GAAP measure, depreciation and amortization.

•	a gain of $108 million ($99 million after tax) on the sale of Cancarb Limited and its related power generation business, which closed on April 15, 2014

•	a net loss resulting from the contract termination payment to Niska Gas Storage of $43 million ($32 million after-tax) effective April 30, 2014

•	unrealized gains and losses from changes in the fair value of certain derivatives used to reduce our exposure to certain commodity price risks as follows:

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1	Includes four Ontario solar facilities acquired between June and December 2013. Three additional solar facilities were acquired at the end of September 2014.

2	Includes our share of equity income from our investments in ASTC Power Partnership, Portlands Energy and Bruce Power.

•	lower earnings from Western Power as a result of lower realized power prices

•	higher earnings from U.S. Power mainly because of higher realized capacity prices

•	incremental earnings from Ontario solar facilities acquired in 2013.

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1	The realized and unrealized gains and losses from financial derivatives used to manage Canadian Power’s assets are presented on a net basis in Western and Eastern Power revenues. The unrealized gains and losses from financial derivatives are excluded to arrive at Comparable EBITDA.

2	Includes four Ontario solar facilities acquired between June and December 2013. Three additional solar facilities were acquired at the end of September 2014.

3	Includes sale of excess natural gas purchased for generation and Cancarb sales of thermal carbon black. Cancarb was sold on April 15, 2014.

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

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1	Includes four Ontario solar facilities acquired between June and December 2013. Three additional solar facilities were acquired at the end of September 2014.

2	Sundance A Unit 1 returned to service in September 2013 and Unit 2 returned to service in October 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.

•	lower realized power prices

•	incremental earnings from the return to service of the Sundance A PPA Unit 1 in September 2013 and Unit 2 in October 2013 which also resulted in increased volume purchases

•	sale of Cancarb in April 2014.

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1	Represents our 48.9 per cent ownership interest in Bruce A and 31.6 per cent ownership interest in Bruce B. Sales volumes exclude deemed generation.

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

3	Calculated based on actual and deemed generation. Bruce B realized sales prices per MWh includes revenues under the floor price mechanism and from contract settlements.

•	lower earnings from Unit 3 due to a planned outage which began in April 2014 and was completed in early August 2014

•	lower volumes due to increased unplanned outage days, primarily on Units 1 and 2.

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1	The realized and unrealized 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. The unrealized gains and losses from financial derivatives are excluded to arrive at Comparable EBITDA.

2	Includes the cost of fuel consumed in generation.

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

•	higher realized capacity prices in New York

•	higher generation at our Ravenswood facility offset by lower realized power prices

•	higher costs on volumes purchased to fulfill power sales commitments to wholesale, commercial and industrial customers

•	lower generation and lower realized power prices at our hydro facilities.

•	higher realized capacity prices in New York

•	higher realized power prices and higher generation at our Ravenswood facility offset by higher fuel prices

•	higher realized power prices in New England

•	higher prices and related costs on volumes purchased to fulfill power sales commitments to wholesale, commercial and industrial customers.

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•	higher interest expense due to debt issues of:

◦	US$1.25 billion in February 2014

◦	US$1.25 billion in October 2013

◦	US$500 million in July 2013

◦	$750 million in July 2013

◦	US$500 million in July 2013 by TC PipeLines, LP

◦	partially offset by Canadian and U.S. dollar-denominated debt maturities

•	higher foreign exchange on interest expense related to U.S. denominated debt

•	lower capitalized interest due to the completion of the Gulf Coast extension of the Keystone Pipeline System in first quarter 2014 offset by higher capitalized interest primarily for Keystone XL.

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

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•	accounts receivable

•	the fair value of derivative assets

•	notes receivable.

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1	Fair values equal carrying values.

2	Net income in the three and nine months ended September 30, 2014 included net realized gains of $5 million and $16 million, respectively, (2013 - gains of $8 million and $22 million, respectively) related to the interest component of cross-currency swaps.

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1	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 energy revenues. Realized and unrealized gains and losses on interest rate and foreign exchange held for trading derivative instruments are included net in interest expense and interest income and other, respectively.

2

At September 30, 2014, all hedging relationships were designated as cash flow hedges except for interest rate derivative financial instruments designated as fair value hedges with a fair value of $3 million (2013 - $7 million) and a notional amount of US$400 million (2013 - US$200 million). For the three and nine months ended September 30, 2014, net realized gains on fair value hedges were $2 million and $5 million, respectively (2013 - $1 million and $5 million, respectively) and were included in interest expense. For the three and nine months ended September 30, 2014 and 2013, we did not record any amounts in net income related to ineffectiveness for fair value hedges.

3

The effective portion of the change in fair value of derivative instruments in hedging relationships is initially recognized in OCI and reclassified to energy revenues, interest expense and interest income and other, as appropriate, as the original hedged item settles. For the three and nine months ended September 30, 2014 and 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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1	No amounts have been excluded from the assessment of hedge effectiveness. Amounts in parentheses indicate losses recorded to OCI.

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1	Previously Oil Pipelines.

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•	regulatory decisions

•	negotiated settlements with shippers

•	acquisitions and divestitures

•	developments outside of the normal course of operations

•	newly constructed assets being placed in service.

•	developments outside of the normal course of operations

•	newly constructed assets being placed in service

•	regulatory decisions.

•	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

•	regulatory decisions.

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1	Previously Oil Pipelines.

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1	Previously Oil Pipelines.

1	Previously Oil Pipelines.

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1	All amounts are net of tax. Amounts in parentheses indicate losses recorded to OCI.

2	Other comprehensive income before reclassifications on currency translation adjustments is net of non-controlling interest gains of $72 million.

3

Gains related to cash flow hedges reported in AOCI and expected to be reclassified to net income in the next 12 months are estimated to be $65 million ($39 million, net of tax) at September 30, 2014. These estimates assume constant commodity prices, interest rates and foreign exchange rates over time, however, the amounts reclassified will vary based on the actual value of these factors at the date of settlement.

1	All amounts are net of tax. Amounts in parentheses indicate losses recorded to OCI.

2	Other comprehensive income before reclassifications on currency translation adjustments is net of non-controlling interest gains of $77 million.

3

Gains related to cash flow hedges reported in AOCI and expected to be reclassified to net income in the next 12 months are estimated to be $65 million ($39 million, net of tax) at September 30, 2014. These estimates assume constant commodity prices, interest rates and foreign exchange rates over time, however, the amounts reclassified will vary based on the actual value of these factors at the date of settlement.

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1	All amounts in parentheses indicate expenses to the condensed consolidated statement of income.

2	These accumulated other comprehensive loss components are included in the computation of net benefit cost. Refer to Note 9 for additional detail.

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1	Fair values equal carrying values.

2	Net income in the three and nine months ended September 30, 2014 included net realized gains of $5 million and $16 million, respectively, (2013 - gains of $8 million and $22 million, respectively) related to the interest component of cross-currency swaps which is included in interest expense.

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1	Notes receivable are included in other current assets and intangible and other assets on the condensed consolidated balance sheet.

2	Available for sale assets are included in intangible and other assets on the condensed consolidated balance sheet.

3	Long-term debt is recorded at amortized cost, except for US$400 million (December 31, 2013 - US$200 million) that is attributed to hedged risk and recorded at fair value.

4

Consolidated net income for the three and nine months ended September 30, 2014 included gains of $2 million and losses of $3 million, respectively, (2013 - losses of nil and $7 million, respectively) for fair value adjustments attributable to the hedged interest rate risk associated with interest rate swap fair value hedging relationships on US$400 million of long-term debt at September 30, 2014 (December 31, 2013 - US$200 million). There were no other unrealized gains or losses from fair value adjustments to the non-derivative financial instruments.

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1	All derivative instruments held for trading have been entered into for risk management purposes and are subject to the Company’s 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 the Company’s exposures to market risk.

2	Fair values equal carrying values.

3	As at September 30, 2014.

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

5	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

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6

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 $3 million and a notional amount of US$400 million as at September 30, 2014. For the three and nine months ended September 30, 2014, net realized gains on fair value hedges were $2 million and $5 million, respectively, and were included in interest expense. For the three and nine months ended September 30, 2014, the Company did not record any amounts in net income related to ineffectiveness for fair value hedges.

7	For the three and nine months ended September 30, 2014, there were no gains or losses included in net income for discontinued cash flow hedges where it was probable that the anticipated transaction would not occur.

1	All derivative instruments held for trading have been entered into for risk management purposes and are subject to the Company’s 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 the Company’s exposures to market risk.

2	Fair values equal carrying values.

3	As at December 31, 2013.

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

5

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 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.

6	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 $5 million and a notional amount of US$200 million as at December 31, 2013. Net realized gains on

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7	For the three and nine months ended September 30, 2013, there were no gains or losses included in net income for discontinued cash flow hedges where it was probable that the anticipated transaction would not occur.

1	No amounts have been excluded from the assessment of hedge effectiveness. Amounts in parentheses indicate losses recorded to OCI.

1	Amounts available for offset do not include cash collateral pledged or received.

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1	Amounts available for offset do not include cash collateral pledged or received.

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1	There were no transfers from Level I to Level II or from Level II to Level III for the nine months ended September 30, 2014.

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1	There were no transfers from Level I to Level II or from Level II to Level III for the year ended December 31, 2013.

1	For the three and nine months ended September 30, 2014, Energy revenues include unrealized gains attributed to derivatives in the Level III category that were still held at the reporting date of $2 million and nil, respectively (2013 - nil).

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1	TransCanada’s share of the potential estimated current or contingent exposure.

2	Except for one guarantee with no termination date.

1.	I have reviewed this quarterly report on Form 6-K of TransCanada Corporation;

2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the issuer as of, and for, the periods presented in this report;

4.	The issuer’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the issuer and have:

(a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the issuer, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)	Evaluated the effectiveness of the issuer’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)	Disclosed in this report any change in the issuer’s internal control over financial reporting that occurred during the issuer’s most recent fiscal quarter (the issuer’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the issuer’s internal control over financial reporting; and

5.	The issuer’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the issuer’s auditors and the audit committee of the issuer’s board of directors (or persons performing the equivalent functions):

(a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the issuer’s ability to record, process, summarize and report financial information; and

(b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the issuer’s internal control over financial reporting.

1.	I have reviewed this quarterly report on Form 6-K of TransCanada Corporation;

2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the issuer as of, and for, the periods presented in this report;

4.	The issuer’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the issuer and have:

(a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the issuer, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)	Evaluated the effectiveness of the issuer’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)	Disclosed in this report any change in the issuer’s internal control over financial reporting that occurred during the issuer’s most recent fiscal quarter (the issuer’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the issuer’s internal control over financial reporting; and

5.	The issuer’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the issuer’s auditors and the audit committee of the issuer’s board of directors (or persons performing the equivalent functions):

(a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the issuer’s ability to record, process, summarize and report financial information; and

(b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the issuer’s internal control over financial reporting.

1.	the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

2.	the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

1.	the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

2.	the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

•	Third quarter financial results

•	Filed regulatory applications with the National Energy Board (NEB) for the $12 billion Energy East Project and the $1.5 billion Eastern Mainline Project on October 30, 2014

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•	Announced an additional $2.7 billion of expansion projects on the NGTL System

•	Executed new short-haul contracts on the Canadian Mainline that require new, or modifications to existing, facilities totaling $500 million

•	Received regulatory approval for the $800 million Northern Courier Pipeline Project in July

•	Closed the $181 million purchase of three additional solar facilities in Ontario in late September

•	Received regulatory approval for the $1.5 billion Grand Rapids Pipeline Project in October

•	Advanced our master limited partnership strategy with the drop down of the remaining 30 per cent interest in Bison for US$215 million

•

Energy East Pipeline: On October 30, 2014, we filed the necessary regulatory applications for approvals to construct and operate the Energy East Pipeline project and terminal facilities with the NEB. The 1.1 million barrel per day (bbl/d) project received approximately 900,000 bbl/d of firm, long-term contracts during a binding open season to transport crude oil from Western Canada to eastern refineries and export terminals. The project is estimated to cost approximately $12 billion, excluding the transfer value of Canadian Mainline natural gas assets. Subject to regulatory approvals, the pipeline is anticipated to commence deliveries to Québec and New Brunswick by the end of 2018.

•

Keystone XL: On January 31, 2014, the Department of State (DOS) released its Final Supplemental Environmental Impact Statement (FSEIS) for the Keystone XL project. The results included in the report were consistent with previous environmental reviews of Keystone XL. The FSEIS concluded Keystone XL is “unlikely to significantly impact the rate of extraction in the oil sands” and that all other alternatives to Keystone XL are less efficient methods of transporting crude oil, and would result in significantly more greenhouse gas emissions, oil spills and risks to public safety. The report initiated the National Interest Determination period that was to last up to 90 days which involves consultation with other governmental agencies and provides an opportunity for public comment. On April 18, 2014, the DOS announced that the National Interest Determination period has been extended indefinitely to allow them to consider the potential impact of the case discussed below on the Nebraska portion of the pipeline route.

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Grand Rapids Pipeline Project: On October 9, 2014, the Alberta Energy Regulator (AER) issued a permit approving the majority of our application to construct and operate the Grand Rapids Pipeline Project. The $3 billion Grand Rapids Pipeline Project is a 50/50 joint venture between us and Brion Energy Corporation (Brion), formerly Phoenix Energy Holdings Limited, to develop an oil and diluent pipeline system connecting the producing area northwest of Fort McMurray, Alberta to terminals in the Edmonton/Heartland region. Brion has also entered into a long-term transportation service contract in support of the project. Construction is expected to begin in fourth quarter 2014 and the system is expected to become operational in stages, with initial crude oil transported by mid-2016. Once completed in 2017, the full system will have an ultimate capacity to move up to 900,000 bbl/d of crude oil and 330,000 bbl/d of diluent.

•

Northern Courier Pipeline Project: On July 18, 2014, the AER issued a permit approving our application to construct and operate the Northern Courier Pipeline Project. Construction commenced in third quarter 2014 and the pipeline system is expected to begin service in 2017. The $800 million pipeline will transport bitumen and diluent between the Fort Hills oil sands mining project and Suncor Energy’s East Tank Farm located north of Fort McMurray, Alberta, and is fully contracted under a long-term agreement.

•

NGTL System Expansions: We continue to experience significant growth on the NGTL System as a result of increasing natural gas supply in northwestern Alberta and northeastern British Columbia (B.C.) from unconventional gas plays and substantive growth in intra-basin delivery markets driven primarily by oil sands development and demand for gas-fired electric power generation. This demand for NGTL System services is expected to result in a total of approximately 4.0 billion cubic feet per day (Bcf/d) of incremental firm service contracts. Approximately 3.1 Bcf/d of this volume relates to firm receipt service and 0.9 Bcf/d relates to firm delivery service. Significant new facilities consisting of approximately 540 kilometres (336 miles) of pipeline, seven compressor stations, and 40 meter stations will be required in 2016 and 2017 (2016/17 Facilities). The estimated total capital cost for the 2016/17 Facilities is approximately $2.7 billion.

•

NGTL System Revenue Requirement Settlement: We have reached a revenue requirement settlement with our shippers for 2015. The terms of the one year settlement include no changes to the return on equity of 10.1 per cent on 40 per cent deemed equity, a continuation of the 2014 depreciation rates and a mechanism for sharing variances above and below a fixed operating, maintenance and administrative expense amount. The settlement was filed with the NEB on October 31, 2014.

•

Canadian Mainline - LDC Settlement: In March 2014, the NEB responded to the LDC Settlement application we filed in December 2013. The NEB did not approve the application as a settlement but allowed us the option to continue with the application as a contested tolls application, amend the application or terminate the processing of the application. We amended the application with additional information. In May 2014, the NEB released a Hearing Order that set out a hearing process and schedule for the 2015 - 2030 Mainline Tolls application that incorporates the LDC Settlement. The hearing concluded September 25, 2014. We anticipate a decision from the NEB before the end of 2014.

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Canadian Mainline Expansions: On October 30, 2014 we filed an application seeking NEB approval to build, own and operate new facilities for our existing Canadian Mainline natural gas transmission system in southeastern Ontario. The new facilities are a result of the proposed transfer of a portion of Canadian Mainline capacity to crude oil from natural gas service as part of our Energy East Pipeline and an open season that closed in January 2014. The $1.5 billion Eastern Mainline Project will add 0.6 Bcf/d of new capacity and will ensure appropriate levels of capacity are available to meet the

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Bison Pipeline Sale: On October 1, 2014, the remaining 30 per cent interest in Bison was sold to our master limited partnership, TC PipeLines, LP for cash proceeds of US$215 million. This transaction advances our previously stated commitment to sell the remainder of TransCanada's U.S. natural gas pipeline assets to the Partnership to help fund our capital program and enhance the size and diversity of the Partnership's asset base, positioning it with visible, high quality future growth. The U.S. natural gas pipeline assets that remain directly-held by TransCanada are expected to generate approximately US$480 million of EBITDA in 2016 and beyond.

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Tamazunchale Pipeline Extension Project: Construction of the US$600 million extension is now expected to be completed in fourth quarter 2014 with delays attributed to archeological findings along the pipeline route. Under the terms of the Transportation Service Agreement, these delays are recognized as a force majeure with provisions allowing for collection of revenue as per the original service commencement date of March 9, 2014.

•	Coastal GasLink Pipeline Project: On October 24, 2014, the B.C. Environmental Assessment Office (EAO) issued the Environmental Assessment Certificate which contains 32 conditions, the majority of which reflect current best practices for natural gas pipeline construction and operation.

•	Prince Rupert Gas Transmission Project: We continue to support information requests related to the regulatory applications with the B.C. EAO and B.C. Oil and Gas Commission. Work continues towards refining a capital cost estimate for the final investment decision, which is expected to be made by Pacific NorthWest LNG by the end of 2014.

•	Genesee PPA Purchase: In October 2014, we acquired a 100 megawatt (MW) energy contract from the Alberta Balancing Pool. The contract includes a monthly capacity payment for a three year term, commencing on November 1, 2014, and is derived from the 762 MW Genesee Power Purchase Arrangement held by the Alberta Balancing Pool.

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Ravenswood: In late September 2014, the 972 MW Unit 30 at the Ravenswood Generating Station experienced an unplanned outage as a result of a problem with the generator associated with the high pressure turbine. Insurance is expected to cover the repair costs and lost revenues associated with the unplanned outage, which are yet to be finalized. As a result of the expected insurance recoveries, the Unit 30 unplanned outage is not expected to have a significant impact on our earnings.

•	Ontario Solar: In late September 2014, we completed the acquisition of three additional Ontario solar facilities for $181 million. All power produced by the solar facilities is sold under 20-year contracts with the Ontario Power Authority.

•	Our Board of Directors declared a quarterly dividend of $0.48 per share for the quarter ending December 31, 2014 on TransCanada’s outstanding common shares. The quarterly amount is equivalent to $1.92 per common share on an annualized basis.

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