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

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•	anticipated business prospects, including the expected closing and financing of the Columbia Pipeline Group, Inc. (Columbia) acquisition

•	planned changes in our business including the divestiture of certain assets

•	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.

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•	timing and completion of the Columbia acquisition including receipt of regulatory and Columbia stockholder approval

•	planned monetization of our U.S. Northeast power assets and a minority interest in our Mexican natural gas pipeline business

•	inflation rates, commodity prices and capacity prices

•	timing of financings and hedging

•	regulatory decisions and outcomes

•	termination of the Alberta PPAs

•	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.

•	length of time to complete the acquisition of Columbia

•	our ability to realize the anticipated benefits of the acquisition of Columbia

•	timing and execution of our planned asset sales

•	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 and credit risk of our counterparties

•	changes in market commodity prices

•	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, tax and foreign exchange rates

•	weather

•	cyber security

•	technological developments

•	economic conditions in North America as well as globally.

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•	EBITDA

•	EBIT

•	funds generated from operations

•	distributable cash flow

•	distributable cash flow per common share

•	comparable earnings

•	comparable earnings per common share

•	comparable EBITDA

•	comparable EBIT

•	comparable distributable cash flow

•	comparable distributable cash flow per common share

•	comparable income from equity investments

•	comparable interest expense

•	comparable interest income and other expense

•	comparable income tax expense.

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•	certain fair value adjustments relating to risk management activities

•	income tax refunds and adjustments and changes to enacted rates

•	gains or losses on sales of assets

•	legal, contractual and bankruptcy settlements

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

•	restructuring costs

•	impairment of assets and investments

•	acquisition costs.

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•	a $176 million after-tax impairment charge on the carrying value of our Alberta PPAs as a result of our decision to terminate the PPAs

•	a charge of $26 million relating to costs associated with the acquisition of Columbia

•	a charge of $6 million after tax related to Keystone XL costs for the maintenance and liquidation of project assets which are being expensed pending further advancement of the project

•	an additional $3 million after-tax loss on the sale of TC Offshore which closed on March 31, 2016.

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•	higher interest income and other due to realized gains in 2016 compared to realized losses in 2015 on derivatives used to manage our net exposure to foreign exchange rate fluctuations on U.S. dollar denominated income and increased AFUDC related to our rate-regulated projects

•	higher earnings from Bruce Power mainly due to higher gains from contracting activities, lower depreciation and our increased ownership interest, partially offset by higher planned outage days

•	higher interest expense from debt issuances and lower capitalized interest from Keystone XL

•	lower earnings from U.S. Power mainly due to decreased margins on sales to wholesale, commercial and industrial customers, the impact of lower realized prices in both New England and New York and lower capacity prices in New York, partially offset by incremental earnings from the Ironwood power plant in Lebanon, Pennsylvania acquired February 1, 2016

•	lower earnings from Eastern Power due to lower earnings on the sale of unused natural gas transportation and lower contractual earnings at Bécancour

•	lower earnings from Liquids Pipelines due to lower uncontracted volumes on the Keystone Pipeline System and lower volumes on Marketlink

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

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1	Reflects U.S. foreign exchange rate of $1.30 at March 31, 2016.

1	Our proportionate share.

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1	Our proportionate share.

2	Carrying value reflects amount remaining after impairment charge recorded in fourth quarter 2015.

3	Excludes transfer of Canadian Mainline natural gas assets.

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1	Results from TQM, Northern Border, Iroquois and TransGas reflect our share of equity income from these investments. On March 31, 2016, we purchased an additional 4.87 per cent interest in Iroquois.

3	Represents our 53.6 per cent direct ownership interest. The remaining 46.4 per cent is held by TC PipeLines, LP.

4	Effective April 1, 2015, we have no direct ownership in GTN. Prior to that our direct ownership interest was 30 per cent effective July 1, 2013.

5	Represents our 61.7 per cent ownership interest in 2015. Effective January 1, 2016, our direct ownership interest in PNGTS was 11.8 per cent as a result of the dropdown transaction between us and TC PipeLines, LP.

6	Includes our share of the equity income from 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 PNGTS we do not own.

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•	higher ANR Southeast mainline transportation revenues offset by a first quarter 2015 non-recurring settlement

•	lower contributions from Mexico Pipelines

•	higher transportation revenues from Great Lakes.

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, 2016 were 274 Bcf (2015 – 302 Bcf). Average per day was 3.0 Bcf (2015 – 3.4 Bcf).

2	Field receipt volumes for the NGTL System for the three months ended March 31, 2016 were 1,074 Bcf (2015 – 1,009 Bcf). Average per day was 11.8 Bcf (2015 – 11.2 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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•	lower uncontracted volumes on Keystone Pipeline System

•	lower volumes on Marketlink

•	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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•	a $240 million pre-tax charge, which included a $29 million impairment of our equity investment in ASTC Power Partnership, on the carrying value of our Alberta PPAs as a result of our decision to terminate the PPAs

•	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	Included Sundance A and Sheerness PPAs, and Sundance B through our investment in ASTC Power Partnership up to March 7, 2016.

2	Included our share of equity income from our investments in ASTC Power Partnership up to March 7, 2016, Portlands Energy and Bruce Power.

•	lower earnings from U.S. Power mainly due to decreased margins on sales to wholesale, commercial and industrial customers, the impact of lower realized prices in both New England and New York and lower capacity prices in New York, partially offset by incremental earnings from the Ironwood power plant in Lebanon, Pennsylvania acquired February 1, 2016

•	higher earnings from Bruce Power mainly due to higher gains from contracting activities, lower depreciation and our increased ownership interest, partially offset by higher planned outage days

•	lower earnings from Eastern Power due to lower earnings on the sale of unused natural gas transportation and lower contractual earnings at Bécancour

•	lower earnings from Western Power as a result of lower realized power prices and PPA volumes following the termination of the PPAs

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

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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 included in revenue are excluded to arrive at Comparable EBITDA.

2	Includes revenues from the sale of unused natural gas transportation and sale of excess natural gas purchased for generation.

3	Includes our share of equity income from our investments in ASTC Power Partnership, which held the Sundance B PPA, and Portlands Energy. Comparable equity income excludes $29 million related to the Sundance B PPA termination which is held in ASTC Power Partnership and does not include any earnings related to our risk management activities.

4	Includes Sundance A, Sundance B and Sheerness PPAs up to March 7, 2016.

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1	Includes volumes from Sundance A and Sheerness PPAs and our 50 per cent ownership interest of Sundance B PPA through the ASTC Power Partnership up to March 7, 2016.

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

3	Does not include facilities that provided power to us under PPAs.

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

5	Plant availability was lower in the three months ended March 31, 2016 than the same period in 2015 due to an unplanned outage at the Halton Hills facility.

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1	Represents our 48.5 per cent ownership interest in Bruce Power after the merger on December 4, 2015 and our 48.9 per cent ownership interest in Bruce A and 31.6 per cent ownership interest in Bruce B up to December 3, 2015. Sales volumes include deemed generation.

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

3	Calculation based on actual and deemed generation. Realized sales prices per MWh includes revenues from contract settlements and cost flow-through items.

4	Excludes unrealized gains and losses on contracting activities and revenues from cobalt sales.

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1	Includes fuel and lease expenses recovery on a flow-through basis estimated at $8.00 per MWh.

1	Includes fuel expense recovery on flow-through basis estimated at $5.00 per MWh.

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

2	Includes the cost of fuel consumed in generation.

1	Increase primarily due to Ironwood acquisition.

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

3	Plant availability was lower in the three months ended March 31, 2015 than the same period in 2016 due to an unplanned outage at the Ravenswood facility from September 2014 to May 2015.

1	New England ISO all hours Mass Hub price.

2	Zone J market in New York City where the Ravenswood plant operates.

3	The METED Zone price in Pennsylvania where the Ironwood plant operates. Average price for 2016 is from February 1 to March 31, 2016.

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•	lower margins on sales to wholesale, commercial and industrial customers in both the New England and PJM markets

•	lower realized power prices at our facilities in New York and New England, partially offset by lower fuel costs and higher generation volumes

•	lower capacity revenues at Ravenswood due to lower realized capacity prices in New York and the impact of lower availability at the facility, partially offset by insurance recoveries, net of deductibles

•	higher earnings due to our acquisition of the Ironwood power plant on February 1, 2016.

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1	There were no specific items in the periods.

•	higher interest expense as a result of long-term debt issuances in 2015 and first quarter 2016, partially offset by Canadian and U.S. dollar-denominated debt maturities

•	a stronger U.S. dollar and its effect on the foreign exchange impact on interest expense related to U.S. dollar-denominated debt

•	lower capitalized interest on Keystone XL and related projects following the November 6, 2015 denial of a U.S. Presidential Permit, partially offset by higher capitalized interest on LNG projects and the Napanee power generating facility.

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•	realized gains in 2016 compared to realized losses in 2015 on derivatives used to manage our net exposure to foreign exchange rate fluctuations on U.S. dollar denominated income

•	increased AFUDC related to our rate-regulated projects including Mexico pipelines, NGTL's expansion and Energy East.

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

•	our ability to generate cash flow from operations

•	our access to capital markets

•	approximately $6.9 billion of unutilized, unsecured committed credit facilities.

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•	expansion of the NGTL System

•	construction of Mexico pipelines

•	expansion of the ANR pipeline

•	construction of the Northern Courier pipeline

•	expansion of the Canadian Mainline

•	construction of the Napanee power generating facility.

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1	Includes repurchases of common shares pursuant to private agreements with third-parties.

2	Includes brokerage fees.

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1	Holders of the cumulative redeemable first preferred shares set out in this table are entitled to receive a fixed cumulative quarterly preferred dividend, as and when declared by the Board, with the exception of Series 6 preferred shares. The holders of Series 6 preferred shares are entitled to receive a quarterly floating rate cumulative preferred dividend as and when declared by the Board.

2

We may, at our option, redeem all or a portion of the outstanding preferred shares for the redemption price per share, plus all accrued and unpaid dividends, on the redemption option date and on every fifth anniversary date thereafter. In addition, Series 6 preferred shares are redeemable by us at any time other than on a designated redemption option date for $25.50 per share plus all accrued and unpaid dividends on such redemption date.

3	Commencing March 31, 2016, the floating quarterly dividend rate for the Series 6 preferred shares is 2.002 per cent and will reset every quarter going forward.

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1	Dividend equivalents are a term of the subscription receipts and are not declared by the Board.

2	If the Merger Agreement with Columbia is terminated after the common share dividend declaration date of April 29, 2016 but before the common share dividend record date of June 30, 2016, subscription receipt holders of record on the termination date shall receive a pro-rata payment of the dividend as the dividend equivalent payment.

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1	Proceeds from asset sales must be used to repay these facilities. See Recent developments section for more information.

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•	accounts receivable

•	portfolio investments

•	the fair value of derivative assets

•	cash and notes receivable.

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1	Fair values equal carrying values.

2	In the three months ended March 31, 2016, net realized gains of $2 million (2015 - gains of $3 million) related to the interest component of cross-currency swaps settlements are included in interest expense.

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1	Realized and unrealized gains and losses on held for trading derivative instruments used to purchase and sell commodities are included net in 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	Following the March 17, 2016 announcement of our intention to sell the U.S. Northeast power assets, a loss of $49 million and a gain of $7 million (2015 - nil) were recorded in net income relating to discontinued cash flow hedges where it was probable that the anticipated underlying transaction would not occur as a result of a future sale.

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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 revenues on the condensed consolidated statement of income.

3	Reported within interest income and other on the condensed consolidated statement of income.

4	Reported within interest expense on the condensed consolidated statement of income.

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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 for natural gas and power

•	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.

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•	a $176 million after-tax impairment charge on the carrying value of our Alberta PPAs as a result of our decision to terminate the PPAs

•	a charge of $26 million relating to costs associated with the acquisition of Columbia

•	a charge of $6 million after tax related to Keystone XL costs for the maintenance and liquidation of project assets which are being expensed pending further advancement of the project

•	an additional $3 million after-tax loss on the sale of TC Offshore which closed on March 31, 2016.

•	a $2,891 million after-tax impairment charge on the carrying value of our investment in Keystone XL and related projects

•	an $86 million after-tax loss provision related to the sale of TC Offshore expected to close in early 2016

•

a net charge of $60 million after tax for our business restructuring and transformation initiative comprised of $28 million mainly related to 2015 severance costs and a provision of $32 million for 2016 planned severance costs and expected future losses under lease commitments. These charges form part of a restructuring initiative which commenced in 2015 to maximize the effectiveness and efficiency of our existing operations and reduce overall costs

•	a $43 million after-tax charge relating to an impairment in value of turbine equipment held for future use in our Energy business

•	a charge of $27 million after tax related to Bruce Power's retirement of debt in conjunction with the merger of the Bruce A and Bruce B partnerships

•	a $199 million positive income adjustment related to the impact on our net income from non-controlling interests of TC PipeLines, LP's impairment of their equity investment in Great Lakes.

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1	Holders of the cumulative redeemable first preferred shares set out in this table are entitled to receive a fixed cumulative quarterly preferred dividend, as and when declared by the Board, with the exception of Series 6 preferred shares. The holders of Series 6 preferred shares are entitled to receive a quarterly floating rate cumulative preferred dividend as and when declared by the Board.

2

TransCanada may, at its option, redeem all or a portion of the outstanding shares for the redemption price per share, plus all accrued and unpaid dividends on the applicable redemption option date and on every fifth anniversary date thereafter. In addition, Series 6 preferred shares are redeemable by TransCanada at any time other than on a designated redemption option date for $25.50 per share plus all accrued and unpaid dividends on such redemption date.

3	The holder will have the right, subject to certain conditions, to convert their first preferred shares of a specified series into first preferred shares of another specified series on the conversion option date and every fifth anniversary thereafter.

4	Commencing March 31, 2016, the floating quarterly dividend rate for the Series 6 preferred shares is 2.002 per cent and will reset every quarter going forward.

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

2	Other comprehensive loss before reclassifications on currency translation adjustments and cash flow hedges is net of non-controlling interest losses of $104 million and $2 million, respectively.

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 $47 million ($28 million, net of tax) at March 31, 2016. 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	In the three months ended March 31, 2016, net realized gains of $2 million (2015 - gains of $3 million) related to the interest component of cross-currency swap settlements are 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	Long-term debt is recorded at amortized cost except for US$900 million (December 31, 2015 - US$850 million) that is attributed to hedged risk and recorded at fair value.

3

Consolidated net income for the three months ended March 31, 2016 included unrealized losses of $12 million (March 31, 2015 - losses of $3 million) for fair value adjustments attributable to the hedged interest rate risk associated with interest rate swap fair value hedging relationships on US$900 million of long-term debt at March 31, 2016 (December 31, 2015 - US$850 million). There were no other unrealized gains or losses from fair value adjustments to the non-derivative financial instruments.

1	Available for sale assets are recorded at fair value and included in intangible and other assets on the condensed consolidated balance sheet.

2	Other restricted investments have been set aside to fund insurance claim losses to be paid by the Company's wholly-owned captive insurance subsidiary.

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1	Gains and losses arising from changes in the fair value of LMCI restricted investments impact the subsequent amounts to be collected through tolls to cover future pipeline abandonment costs. As a result, the Company records these gains and losses as regulatory assets or liabilities.

2	Unrealized gains and losses on other restricted investments are included in OCI.

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1	Fair value equals carrying value.

2	Includes purchases and sales of power, natural gas, and liquids.

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1	Fair value equals carrying value.

2	Includes purchases and sales of power and natural gas.

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1	Volumes for power, natural gas and liquids derivatives are in GWh, Bcf and MMBbls, respectively.

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

1	Realized and unrealized gains and losses on held for trading derivative instruments used to purchase and sell commodities are included net in Revenues. Realized and unrealized gains and losses on interest rate and foreign exchange derivative instruments held for trading are included net in Interest expense and Interest income and other, respectively.

2	Following the March 17, 2016 announcement of the Company's intention to sell the U.S. Northeast merchant power assets, a loss of $49 million and a gain of $7 million (2015 - nil) were recorded in net income relating to discontinued cash flow hedges where it was probable that the anticipated underlying transaction would not occur as a result of a future sale.

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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 revenues on the condensed consolidated statement of income.

3	Reported within interest income and other on the condensed consolidated statement of income.

4	Reported within interest expense 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 three months ended March 31, 2016.

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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, 2015.

1	For the three months ended months ended March 31, 2016, revenues include unrealized gains of $2 million attributed to derivatives in the Level III category that were still held at March 31, 2016 (2015 - losses of $3 million).

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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.

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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.

•	First quarter financial results

•	Declared a quarterly dividend of $0.565 per common share for the quarter ending June 30, 2016. Subscription receipts to receive dividend equivalent payment.

•	Announced an agreement and plan of merger to acquire Columbia Pipeline Group, Inc. for US$13 billion including the assumption of approximately US$2.8 billion in debt

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•	Completed the sale of $4.4 billion of subscription receipts which will be used to finance a portion of the Columbia acquisition

•	Announced our intention to monetize the U.S. Northeast power assets and a minority interest in our Mexican natural gas pipeline business

•	Awarded a contract to construct the US$550 million Tula-Villa de Reyes Pipeline in Mexico

•	Terminated our Alberta Power Purchase Arrangements (PPAs)

•

Acquisition of Columbia Pipeline Group: On March 17, 2016, we entered into an agreement and plan of merger to acquire Columbia Pipeline Group, Inc. (Columbia). Columbia owns one of the largest interstate natural gas pipeline systems in the U.S., providing transportation, storage and related services to a variety of customers in the northeast, mid-west, mid-Atlantic and Gulf Coast regions. Its assets include Columbia Gas Transmission, which operates approximately 18,000 km (11,300 miles) of pipelines and 286 billion cubic feet of working gas storage capacity in the Marcellus and Utica shale production areas, and Columbia Gulf Transmission, an approximate 5,400 km (3,300 mile) pipeline system that extends from Appalachia to the Gulf Coast.

•	Subscription Receipts: On April 1, 2016, we issued 96.6 million subscription receipts to partially fund the Columbia acquisition at a price of $45.75 each for total proceeds of approximately $4.4 billion. Each subscription receipt will entitle the holder to automatically receive one common share upon closing of the

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•

Preferred Share Issuance: On April 20, 2016, we completed a public offering of 20 million Series 13 cumulative redeemable, minimum rate reset, first preferred shares at $25 per share resulting in gross proceeds of $500 million. The fixed dividend rate on the Series 13 preferred shares was set for five years at 5.5 per cent per annum. The dividend rate will reset every five years at a rate equal to the sum of the applicable five-year Government of Canada bond yield plus 4.69 per cent, provided that such rate shall be not less than 5.5 per cent per annum.

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ANR Section 4 Rate Case: On January 29, 2016, ANR filed a Section 4 Rate Case with the FERC that requests an increase to ANR's maximum transportation rates. On February 29, 2016, the FERC issued an order that accepted and suspended ANR’s rate and tariff changes to become effective August 1, 2016, subject to refund and the outcome of a hearing. In addition, on March 23, 2016, the FERC established a procedural schedule for the hearing and appointed a settlement judge to assist the parties in their settlement negotiations. The hearing is currently scheduled for early February 2017 and settlement conferences will be held throughout the process.

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NGTL System: In first quarter of 2016, we placed approximately $100 million of facilities in service with another $600 million currently under construction. The NGTL System continues to develop approximately $7.3 billion of new supply and demand facilities of which approximately $2.5 billion have received regulatory approval, a further approximately $1.9 billion are currently under regulatory review and applications for approval to construct and operate an additional $2.9 billion of facilities have yet to be filed.

•	North Montney Mainline: On March 28, 2016, we filed a request with the NEB for a one year extension of the Certificate of Public Convenience and Necessity (CPCN) for the North Montney Mainline (NMML) project. The requested extension ensures our regulatory approvals remain valid and do not expire pending a Final Investment Decision (FID) on the proposed Pacific Northwest LNG project.

•	2016-2017 NGTL Revenue Requirement Settlement: On April 7, 2016, the NEB approved, subject to certain reporting requirements, the NGTL revenue requirement settlement application that was filed in December 2015. The settlement includes a return on equity of 10.1 per cent on 40 per cent deemed equity plus certain incentive mechanisms.

•	Iroquois Gas Transmission System: On March 31, 2016, we closed the acquisition of an additional 4.87 per cent interest in Iroquois Gas Transmission System, L.P. (Iroquois) for US$54 million bringing our interest in Iroquois to 49.35 per cent. We also expect to acquire an additional 0.65 per cent in second quarter 2016 that will increase our overall interest to 50 per cent.

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Tula-Villa de Reyes Pipeline: On April 11, 2016, we announced we were awarded a contract to build, own and operate the Tula-Villa de Reyes pipeline in Mexico. Construction of the pipeline is supported by a 25-year natural gas transportation service contract for 886 million cubic feet per day with the Comisión Federal de Electricidad (CFE). We expect to invest approximately US$550 million on a 36-inch diameter, 420-km (261-mile) pipeline with an anticipated in-service in early 2018. The pipeline will extend from our Tamazunchale and Tuxpan-Tula pipelines to a terminus near Villa de Reyes, San Luis Potosí, transporting natural gas to power generation facilities.

•	Prince Rupert Gas Transmission: We are continuing engagement with Aboriginal groups and have now announced project agreements with eleven First Nation groups along the pipeline route which outline financial and other benefits and commitments that will be provided to each First Nation group for as long as the project is in service.

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•	Coastal GasLink: The LNG Canada joint venture participants anticipate reaching a final investment decision on their Kitimat-based LNG project in late 2016. Based on the current schedule, preliminary construction work could begin in January 2017.

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Keystone Pipeline: On April 2, 2016, we shut down the Keystone pipeline after a leak was detected along the pipeline right-of-way in Hutchinson County, South Dakota. We reported the total volume of the release of 400 barrels to the National Response Center and the Pipeline and Hazardous Materials Safety and Administration (PHMSA). Temporary repairs were completed on April 9, 2016, and the Keystone pipeline was restarted on April 10, 2016. Permanent repairs and remaining restoration work at site is planned for May 2016, with further investigative activities and corrective measures required by PHMSA planned in 2016.

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Energy East Pipeline: On March 1, 2016, the Province of Québec filed a court action seeking an injunction to compel the Energy East Pipeline to comply with the province’s environmental regulations. On April 22, 2016, we filed a project review engaging an environmental assessment under the Environmental Quality Act (Québec). This process is in addition to an environmental assessment required under the National Energy Board Act and the Canadian Environmental Assessment Act, 2012. The Attorney General for Québec has agreed to suspend its litigation against TransCanada and Energy East and to withdraw it once the provincial environmental assessment process has been completed. We do not anticipate this will result in a delay with regard to the National Energy Board’s review process.

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Alberta Power Purchase Arrangements: On March 7, 2016, we issued notice to the Balancing Pool terminating our Alberta PPAs. The agreements contain a provision that permits the PPA buyers to terminate the PPAs if there is a change in law that makes the agreements unprofitable or more unprofitable. This termination affects the Sheerness, Sundance A and Sundance B PPAs. We expect the termination will improve cash flow and comparable earnings in the near term.

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