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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

•	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

•	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

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•	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

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

•	a net loss resulting from the termination of a contract with Niska Gas Storage of $31 million after tax.

•	a gain on 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 $31 million after tax.

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•	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

•	lower equity income from Bruce Power mainly due to increased planned and unplanned outage days at Bruce A, partially offset by fewer outage days at Bruce B

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

•	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.

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1	A force majeure has delayed completion of construction, however, revenue has been recorded in second quarter 2014 as per the terms of the Transportation Service Agreement.

2	Represents our 50 per cent share.

3	Subject to cost adjustments due to market conditions, route refinement, permitting conditions and scheduling.

4	Estimated project cost will increase depending 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 Niksa 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 is adjusted by $13 million relating to the impact from the NEB decision (RH-003-2011).

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

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2	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.

•

contract revenues recognized from the Tamazunchale Extension in the three months ended June 30, 2014. The Tamazunchale Extension project has experienced delays in completing the 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 and higher contributions from TC PipeLines, LP reflecting colder winter weather and increased demand

•	higher OM&A costs at ANR as well as lower storage revenues in first quarter 2014.

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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 six months ended June 30, 2014 were 599 Bcf (2013 – 397 Bcf). Average per day was 3.3 Bcf (2013 – 2.2 Bcf).

2	Field receipt volumes for the NGTL System for the six months ended June 30, 2014 were 1,879 Bcf (2013 – 1,840 Bcf). Average per day was 10.4 Bcf (2013 – 10.2 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 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 $41 million ($31 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.

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

•	lower equity income from Bruce Power mainly due to increased planned and unplanned outage days at Bruce A, partially offset by fewer outage days at Bruce B

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

•	lower earnings from Natural Gas Storage due to lower realized natural gas storage spreads.

•	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 Eastern Power due to the incremental earnings from the Ontario solar facilities acquired in 2013.

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1	Includes four Ontario solar facilities acquired between June and December 2013.

2	Includes sale of excess natural gas purchased for generation and Cancarb sales of thermal carbon black. Sale of Cancarb closed April 15, 2014.

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

1	Includes four Ontario solar facilities acquired between June and December 2013.

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.

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•	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 and sales.

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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 revenues from contract settlements.

•	lower earnings from Unit 3 due to a planned outage which began in April 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.

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 hydro facilities

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

•	higher realized capacity prices in New York

•	higher realized power prices and higher generation in New England

•	higher realized power prices and higher generation in New York offset by higher plant operating costs due to higher fuel prices

•	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

•	higher foreign exchange on interest expense related to U.S. denominated debt, partially offset by Canadian and U.S. dollar-denominated debt maturities.

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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 six months ended June 30, 2014 included net realized gains of $5 million and $11 million, respectively, (2013 - gains of $7 million and $14 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 June 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 $5 million (2013 - $7 million) and a notional amount of US$300 million (2013 - US$200 million). For the three and six months ended June 30, 2014, net realized gains on fair value hedges were $2 million and $3 million, respectively (2013 - $2 million and $4 million, respectively) and were included in interest expense. For the three and six months ended June 30, 2014 and 2013, we did not record any amounts in net income related to ineffectiveness for fair value hedges.

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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 six months ended June 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.

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

2	Reported within Energy revenues on the condensed consolidated statement of income.

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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.

•	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 losses of $39 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 $9 million ($4 million, net of tax) at June 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 are net of tax. Amounts in parentheses indicate losses recorded to OCI.

2	Other comprehensive (loss)/income before reclassifications on currency translation adjustments is net of non-controlling interest gains of $5 million.

3

Losses 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 $9 million ($4 million, net of tax) at June 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 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 six months ended June 30, 2014 included net realized gains of $5 million and $11 million, respectively, (2013 - gains of $7 million and $14 million, respectively) related to the interest component of cross-currency swaps which is included in interest expense.

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.

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3	Long-term debt is recorded at amortized cost, except for US$300 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 six months ended June 30, 2014 included gains of $1 million and losses of $5 million, respectively, (2013 - gains of $3 million and losses of $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$300 million of long-term debt at June 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 June 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 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$300 million as at June 30, 2014. For the three and six months ended June 30, 2014, net realized gains on fair value hedges were $2 million and $3 million, respectively, and were included in interest expense. For the three and six months ended June 30, 2014, the Company did not record any amounts in net income related to ineffectiveness for fair value hedges.

7	For the three and six months ended June 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.

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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 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 fair value hedges for the three and six months ended June 30, 2013 were $2 million and $4 million, respectively, and were included in interest expense. For the three and six months ended June 30, 2013, the Company did not record any amounts in net income related to ineffectiveness for fair value hedges.

7	For the three and six months ended June 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.

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

2	Reported within Energy revenues on the condensed consolidated statement of income.

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 six months ended June 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 six months ended June 30, 2014, energy revenues include unrealized losses attributed to derivatives in the Level III category that were still held at the reporting date of $2 million (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.

•	Second quarter financial results

•	Continue to progress regulatory applications for several of our major capital projects including Coastal GasLink, Prince Rupert Gas Transmission, Energy East, Grand Rapids, Heartland, the North Montney Mainline and Napanee

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•	Energy East Pipeline: In March 2014, we filed a Project Description with the NEB. This is the first formal step in the regulatory process to receive the necessary approvals to build and operate the pipeline. The project is estimated to cost approximately $12 billion, excluding the transfer value of Canadian Mainline natural gas assets.

•

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. The 30-day public comment period has concluded. 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.

•

Northern Courier Pipeline Project: In October 2013, Suncor Energy announced that Fort Hills Energy LP is proceeding with the Fort Hills oil sands mining project. Our $800 million Northern Courier Pipeline Project will transport bitumen and diluent between the Fort Hills mine site 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: The NGTL System is currently experiencing a significant amount of growth as a result of growing natural gas supply in northwestern Alberta and northeastern 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. Approximately $250 million of capital projects have been placed into service in 2014. Another $3.8 billion of projects are either under construction, or have or will be filed with the NEB for approval. These projects include the North Montney Mainline and the Merrick Mainline Pipeline, along with other new supply and demand facilities. We continue to receive requests for new services and expect that this will lead to additional growth opportunities in the future.

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•

Canadian Mainline - LDC Settlement: In March 2014, the NEB responded to the LDC Settlement application we filed on December 20, 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. On May 9, 2014, the NEB released a Hearing Order that sets out the process and schedule for the 2015 - 2030 Mainline Tolls application that incorporates the LDC Settlement, with the oral portion set to begin September 9, 2014.

•

Canadian Mainline - Eastern Mainline Project: On May 8, 2014, we filed a Project Description with the NEB for the Eastern Mainline Project. The proposed project will add new facilities to our existing Canadian Mainline natural gas transmission system in southeastern Ontario as a result of the proposed transfer of a portion of the Canadian Mainline capacity to crude oil from natural gas service as part of our proposed Energy East Pipeline and an open season that closed in January 2014. The proposed scope of the project will add 0.6 Bcf/d of new capacity and will ensure appropriate levels of capacity are available to meet the requirements of existing shippers as well as new firm service commitments contracted for in the Eastern Triangle segment of the Canadian Mainline. Subject to regulatory approvals, the project is expected to be in service in second quarter 2017.

•

Tamazunchale Pipeline Extension Project: Construction of the US$600 million extension is currently expected to be completed by the end of September 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.

•

Prince Rupert Gas Transmission Project: The Environmental Assessment application submitted to the B.C. Environmental Assessment Office (EAO) in April 2014 was deemed complete. The EAO initiated a 180-day review period which included a 45-day public comment period that was completed on July 10, 2014. A facilities application was also filed with the B.C. Oil and Gas Commission in April 2014. Regulatory approval for the pipeline is expected in fourth quarter 2014 and a final investment decision from Pacific Northwest LNG is expected to follow at the end of 2014.

•

Alaska LNG Project: In April 2014, the State of Alaska passed new legislation that will transition from the Alaska Gasline Inducement Act (AGIA) and enable a new commercial arrangement to be established with us, the three major Alaska North Slope producers, and the Alaska Gasline Development Corp. It was also agreed that a Liquefied Natural Gas (LNG) export project, rather than a pipeline to Alberta, is currently the best opportunity to commercialize Alaska North Slope gas resources in current market conditions.

•	Cancarb: In January 2014, we reached an agreement to sell Cancarb and its related power generation facility for gross proceeds of $190 million. The sale closed on April 15, 2014 and we recognized an after-tax gain of $99 million in second quarter 2014.

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Natural Gas Storage: Effective April 30, 2014, we terminated a 38 billion cubic feet long-term natural gas storage contract in Alberta with Niska Gas Storage. As a result, we recorded a $31 million after-tax charge in second quarter 2014. We have re-contracted for new natural gas storage services in Alberta with Niska Gas Storage starting May 1, 2014 for a six year period at a reduced average volume.

•	Our Board of Directors declared a quarterly dividend of $0.48 per share for the quarter ending September 30, 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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