EXHIBIT 13.1

TransCanada Corporation

2017 Annual information form

February 14, 2018

TED

TransCanada Annual information form 2017 2

Contents

PRESENTATION OF INFORMATION	2
FORWARD-LOOKING INFORMATION	2
TRANSCANADA CORPORATION	4
Corporate structure	4
Intercorporate relationships	4
GENERAL DEVELOPMENT OF THE BUSINESS	5
Natural Gas Pipelines	5
Liquids Pipelines	13
Energy	16
BUSINESS OF TRANSCANADA	18
Natural Gas Pipelines	18
Liquids Pipelines	18
Regulation of Natural Gas Pipelines and Liquids Pipelines	19
Energy	20
GENERAL	21
Employees	21
Corporate restructuring and business transformation	21
Health, safety and environmental protection and social policies	21
RISK FACTORS	23
DIVIDENDS	23
DESCRIPTION OF CAPITAL STRUCTURE	23
Share capital	23
CREDIT RATINGS	26
Moody's	26
S&P	27
Fitch	27
DBRS	27
MARKET FOR SECURITIES	28
Common shares	28
Preferred shares	29
DIRECTORS AND OFFICERS	30
Directors	30
Board committees	32
Officers	33
Conflicts of interest	34
CORPORATE GOVERNANCE	34
AUDIT COMMITTEE	35
Relevant education and experience of members	35
Pre-approval policies and procedures	36
External auditor service fees	36
LEGAL PROCEEDINGS AND REGULATORY ACTIONS	37
TRANSFER AGENT AND REGISTRAR	37
MATERIAL CONTRACTS	37
INTEREST OF EXPERTS	37
ADDITIONAL INFORMATION	37
GLOSSARY	38
SCHEDULE A	39
SCHEDULE B	40

TransCanada Annual information form 2017 1

Presentation of information

Throughout this Annual information form (AIF), the terms, we, us, our, the Company and TransCanada mean TransCanada Corporation and its subsidiaries. In particular, TransCanada includes references to TransCanada PipeLines Limited (TCPL). Where TransCanada is referred to with respect to actions that occurred prior to its 2003 plan of arrangement (Arrangement) with TCPL, which is described in the TransCanada Corporation – Corporate structure section below, such actions were taken by TCPL or its subsidiaries. The term subsidiary, when referred to in this AIF, with reference to TransCanada means direct and indirect wholly owned subsidiaries of, and legal entities controlled by, TransCanada or TCPL, as applicable.

Unless otherwise noted, the information contained in this AIF is given at or for the year ended December 31, 2017 (Year End). Amounts are expressed in Canadian dollars unless otherwise indicated. Information in relation to metric conversion can be found at Schedule A to this AIF. The Glossary found at the end of this AIF contains certain terms defined throughout this AIF and abbreviations and acronyms that may not otherwise be defined in this document.

Certain portions of TransCanada's management's discussion and analysis dated February 14, 2018 (MD&A) are incorporated by reference into this AIF as stated below. The MD&A can be found on SEDAR (www.sedar.com) under TransCanada's profile.

Financial information is presented in accordance with United States (U.S.) generally accepted accounting principles (GAAP). We use certain financial measures that do not have a standardized meaning under GAAP and therefore they may not be comparable to similar measures presented by other entities. Refer to the About this document – Non-GAAPmeasures section of the MD&A for more information about the non-GAAP measures we use and a reconciliation to their GAAP equivalents, which section of the MD&A is incorporated by reference herein.

Forward-looking information

This AIF, including the MD&A disclosure incorporated by reference herein, contains certain information that is forward-looking and is subject to important risks and uncertainties. We disclose forward-looking information to help current and potential investors understand management’s assessment of our future plans and financial outlook, and our future prospects overall.

Statements that are forward-looking are based on certain assumptions and on what we know and expect today and generally include words like anticipate, expect, believe, may, will, should, estimate or other similar words.

Forward-looking statements included or incorporated by reference in this document include information about the following, among other things:

• planned changes in our business

• 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 dividend growth

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

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

• expected regulatory processes and 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

• the expected impact of H.R. 1, the Tax Cuts and Jobs Act (U.S. Tax Reform)

• expected industry, market and economic conditions.

Forward-looking statements do not guarantee future performance. Actual events and results could be significantly different because of assumptions, risks or uncertainties related to our business or events that happen after the date of this document.

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Our forward-looking information is based on the following key assumptions, and subject to the following risks and uncertainties:

Assumptions

• planned wind-down of our U.S. Northeast power marketing business

• inflation rates and commodity prices

• nature and scope of hedging

• regulatory decisions and outcomes

• interest, tax and foreign exchange rates, including the impact of U.S. Tax Reform

• 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.

Risks and uncertainties

• our ability to successfully implement our strategic priorities and whether they 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 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, including the impact of U.S. Tax Reform

• weather

• cyber security

• technological developments

• economic conditions in North America as well as globally.

You can read more about these factors and others in reports we have filed with Canadian securities regulators and the U.S. Securities and Exchange Commission (SEC).

As actual results could vary significantly from the forward-looking information, you should not put undue reliance on forward-looking information and should not use future-oriented financial information or financial outlooks for anything other than their intended purpose. We do not update our forward-looking statements due to new information or future events, unless we are required to by law.

TransCanada Annual information form 2017 3

TransCanada Corporation

CORPORATE STRUCTURE

Our head office and registered office are located at 450 – 1st Street S.W., Calgary, Alberta, T2P 5H1. TransCanada was incorporated pursuant to the provisions of the Canada Business Corporations Act (CBCA) on February 25, 2003 in connection with the Arrangement, which established TransCanada as the parent company of TCPL. The Arrangement was approved by TCPL common shareholders on April 25, 2003 and, following court approval and the filing of Articles of Arrangement, the Arrangement became effective May 15, 2003. Pursuant to the Arrangement, the common shareholders of TCPL exchanged each of their TCPL common shares for one common share of TransCanada. The debt securities and preferred shares of TCPL remained obligations and securities of TCPL (the preferred shares of TCPL have been subsequently redeemed). TCPL continues to carry on business as the principal operating subsidiary of TransCanada. TransCanada does not hold any material assets directly other than the common shares of TCPL and receivables from certain of TransCanada's subsidiaries.

INTERCORPORATE RELATIONSHIPS

The following diagram presents the name and jurisdiction of incorporation, continuance or formation of TransCanada’s principal subsidiaries as at Year End. Each of the subsidiaries shown has total assets that exceeded ten per cent of the total consolidated assets of TransCanada as at Year End or revenues that exceeded ten per cent of the total consolidated revenues of TransCanada as at Year End. TransCanada beneficially owns, controls or directs, directly or indirectly, 100 per cent of the voting shares or units in each of these subsidiaries.

TransCanada Corporation Canada TransCanada PipeLines Limited Canada TransCanada PipeLine USA Ltd. Nevada TransCanada Oil Pipelines Inc. Delaware TransCanada Keystone Pipeline, LP Delaware Columbia Pipeline Group, Inc. Delaware Columbia Energy Group Delaware CPG OpCo LP Delaware Columbia Gas Transmission, LLC Delaware NOVA Gas Transmission Ltd. Alberta

The above diagram does not include all of the subsidiaries of TransCanada. The assets and revenues of excluded subsidiaries in the aggregate did not exceed 20 per cent of the total consolidated assets of TransCanada as at Year End or total consolidated revenues of TransCanada as at Year End.

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General development of the business

We operate in three core businesses – Natural Gas Pipelines, Liquids Pipelines and Energy. As a result of our acquisition of Columbia Pipeline Group, Inc. (Columbia) on July 1, 2016 and the sale of the U.S. Northeast power business, we determined that a change in our operating segments was appropriate. Accordingly, we consider ourselves to be operating in the following five segments: Canadian Natural Gas Pipelines, U.S. Natural Gas Pipelines, Mexico Natural Gas Pipelines, Liquids Pipelines and Energy. This provides information that is aligned with how management decisions about our business are made and how performance of our business is assessed. We also have a non-operational Corporate segment consisting of corporate and administrative functions that provide governance and other support to our operational business segments.

Natural Gas Pipelines and Liquids Pipelines are principally comprised of our respective natural gas and liquids pipelines in Canada, the U.S. and Mexico, as well as our regulated natural gas storage operations in the U.S. Energy includes our power operations and the non-regulated natural gas storage business in Canada.

Summarized below are significant developments that have occurred in our Natural Gas Pipelines, Liquids Pipelines and Energy businesses, respectively, and certain acquisitions, dispositions, events or conditions which have had an influence on those developments, during the last three financial years and year to date in 2018. Further information about changes in our business that we expect to occur during the current financial year can be found in the Canadian Natural Gas Pipelines, U.S. Natural Gas Pipelines, Mexico Natural Gas Pipelines, Liquids Pipelines and Energy sections of the MD&A, which sections of the MD&A are incorporated by reference herein.

NATURAL GAS PIPELINES

Developments in the Canadian Natural Gas Pipelines Segment

Date	Description of development
CANADIAN REGULATED PIPELINES
NGTL System
2015	The NGTL System had approximately $6.7 billion of new supply and demand facilities under development and we continued to advance several of these capital expansion projects by filing the regulatory applications with the National Energy Board (Canada) (NEB). In 2015, we placed approximately $0.35 billion of facilities in service.
2016	In 2016, the NGTL System continued to develop new supply and demand facilities. We had approximately $2.3 billion of facilities that received regulatory approval and approximately $0.45 billion under construction. On October 6, 2016, the NEB recommended government approval of the Towerbirch Project and the continued use of the existing rolled-in toll methodology for the project. On October 31, 2016, the Government of Canada also approved our application for a $1.3 billion NGTL System expansion program. This NGTL System expansion program consists of five pipeline loops ranging in size from 24 to 48-inch pipe of approximately 230 km (143 miles) in length, and two compressor station unit additions of approximately 46.5 MW (62,360 hp). In December 2016, we announced the $0.6 billion Saddle West expansion of the NGTL System to increase natural gas transportation capacity on the northwest portion of our system, consisting of 29 km (18 miles) of 36-inch pipeline looping of existing mainlines, the addition of five compressor units at existing station sites and new metering facilities. The project is underpinned by incremental firm service contracts and is expected to be in-service in 2019. In 2016, we placed approximately $0.5 billion of facilities in service.
2017	In March 2017, the Government of Canada approved the $0.4 billion Towerbirch Project, which consists of a 55 km (34 mile), 36-inch pipeline loop and a 32 km (20 mile), 30-inch pipeline extension of the NGTL System in northwest Alberta and northeast British Columbia (B.C.), which was subsequently placed in service in November 2017. In June 2017, we announced a new $2 billion expansion program on our NGTL System based on new contracted customer demand for approximately 3.2 PJ/d (3 Bcf/d) of incremental firm receipt and delivery services, subject to regulatory approvals. In 2017, we placed approximately $1.7 billion of new facilities in service on the NGTL System, and reduced project estimates by $0.6 billion.
2018	In February 2018, we announced a new NGTL System expansion totaling $2.4 billion, with in-service dates between 2019 and 2021. The new expansion program includes approximately 375 km (233 miles) of 16- to 48-inch pipeline, four compressor units totaling 120 MW, and associated metering stations and facilities. We anticipate incremental firm receipt contracts of 664 TJ/d (620 MMcf/d) and firm delivery contracts to our major border export and intra-basin delivery locations of 1.1 PJ/d (1.0 Bcf/d).

TransCanada Annual information form 2017 5

Date	Description of development
NGTL Revenue Requirement Settlements
2015	In February 2015, we received NEB approval for our revenue requirement settlement with our shippers on the NGTL System. The terms of the settlement included the continuation of the 2014 return on equity (ROE) of 10.1 per cent on 40 per cent deemed equity, continuation of the 2014 depreciation rates and a mechanism for sharing variances above and below a fixed operating, maintenance and administration (OM&A) expense amount that was based on an escalation of 2014 actual costs. In December 2015, we reached a two-year revenue requirement agreement (2016-2017 Settlement) with customers and other interested parties on the annual costs, including ROE and depreciation required to operate the NGTL System for 2016 and 2017. The 2016-2017 Settlement fixed ROE at 10.1 per cent on 40 per cent deemed equity, established depreciation at a forecast composite rate of 3.16 per cent and fixed OM&A costs at $222.5 million annually. An incentive mechanism for variances enabled NGTL to capture savings from improved performance and provided for the flow-through of all other costs, including pipeline integrity expenses and emissions costs.
2017	The 2016-2017 Settlement expired on December 31, 2017. We continue to work with interested parties towards a new revenue requirement arrangement for 2018 and longer. While these discussions are underway, NGTL is operating under interim tolls for 2018 that were approved by the NEB on November 24, 2017.
North Montney
2015	In June 2015, the NEB approved the $1.7 billion North Montney Mainline (NMML) project, subject to certain terms and conditions. Under one of these conditions, construction on the NMML project was only to begin after a positive final investment decision (FID) had been made on the Pacific North West liquefied natural gas (LNG) project (PNW LNG). The NMML project provides substantial new capacity on the NGTL System to meet the transportation requirements associated with rapidly increasing development of natural gas resources in the Montney supply basin in northeastern B.C. The NMML project connects Montney and other Western Canadian Sedimentary Basin (WCSB) supply to existing and new natural gas markets, including LNG markets. The project also includes an interconnection with our Prince Rupert Gas Transmission Project (PRGT) to provide natural gas supply to the proposed PNW LNG liquefaction and export facility near Prince Rupert, B.C.
2016	In September 2016, the Government of Canada approved a sunset clause extension request that we filed in March 2016, for the NMML Certificate of Public Convenience and Necessity, for one year to June 10, 2017.
2017	In March 2017, we filed an application with the NEB for a variance to the existing approvals for the NMML project on the NGTL System to remove the condition that the NMML project could only proceed once a positive FID was made for the PNW LNG project. The NMML project is now underpinned by restructured 20-year commercial contracts with shippers and is not dependent on PNW LNG project proceeding. A hearing on the matter began the week of January 22, 2018 and a decision from the NEB is anticipated in second quarter 2018.
Sundre Crossover Project
2017	On December 28, 2017, the NEB approved the Sundre Crossover project on the NGTL System. The approximate $100 million, 21 km (13 mile), 42-inch pipeline project will increase delivery of 245 TJ/d (229 MMcf/d) to the Alberta/ B.C. border to connect with TransCanada downstream pipelines. In-service is planned for April 1, 2018.
Canadian Mainline – Kings North and Station 130 Facilities
2016	In fourth quarter 2016, we placed in service the approximate $310 million Kings North Connector and the approximate $75 million compressor unit addition at Station 130 on the Canadian Mainline system. These two projects are consistent with our current LDC Settlement (defined below) with our shippers and provide optionality to access alternative supply sources while contracting for increased short-haul transportation service within the Eastern Triangle area of the Canadian Mainline system.
Canadian Mainline – Eastern Mainline Project
2015	In August 2015, we announced that we had reached an agreement with eastern local distribution companies (LDCs) that resolved their issues with the Energy East pipeline project and the Eastern Mainline project. Application amendments were filed in December 2015 that reflected the agreement. The agreement provided gas consumers in eastern Canada with sufficient natural gas transmission capacity and provides for reduced natural gas transmission costs.
2016	The Eastern Mainline project was conditioned on the approval and construction of the Energy East pipeline. Refer to the General development of the business – Liquids Pipelines section for information on Energy East.
2017	In October 2017, after a careful review of the changed circumstances, we informed the NEB that we would not be proceeding with the Energy East and Eastern Mainline project applications, that in effect provided public notice that the projects were canceled. Refer to the General development of the business – Liquids Pipelines section for information on Energy East.

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Date	Description of development
Canadian Mainline – Other Expansions
2016	In addition to the Eastern Mainline Project, new facilities investments totaling approximately $700 million over the 2016-2017 period in the Eastern Triangle portion of the Canadian Mainline were required to meet contractual commitments from shippers. In third quarter 2016, we launched an open season for the Canadian Mainline, seeking binding commitments on our new long-term, fixed-price proposal to transport WCSB supply from the Empress receipt point in Alberta to the Dawn hub in Southern Ontario. The open season for the proposed service resulted in bids that fell short of the volumes required to make the proposal viable. On November 15, 2016 we announced we would not proceed with the service offering. Refer to the Canadian Mainline – Kings North and Station 130 Facilities section above.
2017	Including the Vaughan Loop, which was placed in service in November 2017, we had approximately $245 million of additional investment to meet contractual commitments from shippers that went into service in 2017 on the Canadian Mainline. The Canadian Mainline also received requests for expansion capacity to the southern Ontario market plus delivery to Atlantic Canada via the Trans-Québec & Maritimes and PNGTS (defined below) systems. The requests for approximately 86 TJ/d (80 MMcf/d) of firm service underpin the need for new compression at the existing Maple compressor site. Customers have executed 15-year precedent agreements to proceed with the project, which has an estimated cost of $110 million. An application to the NEB seeking project approval was filed on November 2, 2017. We have requested a decision by the NEB to proceed with the project in first quarter 2018 to meet an anticipated in-service date of November 1, 2019.
Dawn Long-Term Fixed-Price Service
2017	On November 1, 2017, we began offering a new NEB-approved service on the Mainline referred to as the Dawn Long-Term Fixed-Price (LTFP) service. This LTFP service enables WCSB producers to transport up to 1.5 PJ/d (1.4 Bcf/d) of natural gas at a simplified toll of $0.77/GJ from the Empress receipt point in Alberta to the Dawn hub in Southern Ontario. The LTFP service is underpinned by ten-year contracts that have early termination rights after five years. Any early termination will result in an increased toll for the last two years of the contract.
Canadian Mainline Settlement
2015	In 2015, the Canadian Mainline began operating under the NEB-approved Canadian Mainline's 2015-2030 Tolls and Tariff Application.
2017	While the 2015-2030 settlement (LDC Settlement) specified tolls for 2015 to 2020, the NEB ordered a toll review halfway through this six-year period, to be filed by December 31, 2017. The 2018-2020 toll review must include costs, forecast volumes, contracting levels, the deferral account balance, and any other material changes. A supplemental agreement for the 2018-2020 period was executed between TransCanada and eastern LDCs on December 8, 2017, and filed for approval with the NEB on December 18, 2017 (the Supplemental Agreement). The Supplemental Agreement, supported by a majority of Canadian Mainline stakeholders, proposes lower tolls, preserves an incentive arrangement that provides an opportunity for 10.1 per cent, or greater return, on a 40 per cent deemed equity and describes the revenue requirements and billing determinants for the 2018-2020 period. We anticipate the NEB will provide directions and process to adjudicate the application in first quarter 2018. Interim tolls for 2018, as established by the Supplemental Agreement, were filed and subsequently approved by the NEB on December 19, 2017.
LNG PIPELINE PROJECTS
Prince Rupert Gas Transmission
2015	In June 2015, PNW LNG announced a positive FID for its proposed liquefaction and export facility, subject to two conditions. The first condition, approval by the Legislative Assembly of B.C. of a project development agreement between PNW LNG and the Province of B.C., was satisfied in July 2015. The second condition was a positive regulatory decision on PNW LNG’s environmental assessment by the Government of Canada. Environmental permits for the project were received in November 2014 from the B.C. Environmental Assessment Office (BCEAO). In third quarter 2015, we received all remaining permits from the B.C. Oil and Gas Commission (OGC). With these permits, PRGT received all of the primary regulatory permits required for the project.
2016	In September 2016, PNW LNG received an environmental certificate from the Government of Canada for a proposed LNG plant at Prince Rupert, B.C. In December 2016, PNW LNG received an LNG export license from the NEB which extended the export term from 25 years to 40 years. We continued our engagement with Indigenous groups and signed project agreements with 14 First Nation groups along the pipeline route, which outlined financial and other benefits and commitments that would be provided to each First Nation for as long as the project was in service.
2017	In July 2017, we were notified that PNW LNG would not be proceeding with their proposed LNG project and that Progress Energy would be terminating their agreement with us for development of the PRGT project. In accordance with the terms of the agreement, we received a payment of $0.6 billion from Progress Energy in October 2017 for full recovery of our costs plus carrying charges.

TransCanada Annual information form 2017 7

Date	Description of development
Coastal GasLink
2016	In first quarter 2016, we continued to engage with Indigenous groups and announced project agreements with 11 First Nation groups along the pipeline route which outlined financial and other benefits and commitments that would be provided to each First Nation group for as long as the project was in service. We also continued to engage with stakeholders along the pipeline route and progressed detailed engineering and construction planning work to refine the capital cost estimate. In response to feedback received, we applied for a minor route amendment to the BCEAO in order to provide an option in the area of concern. In July 2016, the LNG Canada joint venture participants announced a delay to their FID for the proposed LNG facility in Kitimat, B.C. We worked with LNG Canada to maintain the appropriate pace of the Coastal GasLink development schedule and work activities. We continued our engagement with Indigenous groups along our pipeline route and concluded long-term project agreements with 17 First Nation communities.
2017	The continuing delay in the FID for the LNG Canada project triggered a restructuring of the provisions in the Coastal GasLink project agreement with LNG Canada that resulted in the payment of certain amounts to TransCanada with respect to carrying charges on costs incurred. In September 2017, an approximate $80 million payment was received related to costs incurred since inception of the project. Following a payment of $8 million in fourth quarter 2017, additional quarterly payments of approximately $7 million will be received until further notice. We continue to work with LNG Canada under the agreement towards an FID. Coastal GasLink filed an amendment to the Environmental Assessment Certificate in November 2017 for an alternate route on a portion of the pipeline. A decision from the BCEAO is expected in 2018. Should the project not proceed, our project costs, including carrying charges are fully recoverable.

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Developments in the U.S. Natural Gas Pipelines Segment

Date	Description of development
U.S. NATURAL GAS PIPELINES - COLUMBIA
Columbia Acquisition
2016	On July 1, 2016, we acquired 100 per cent ownership of Columbia for a purchase price of US$10.3 billion in cash. The acquisition was initially financed through proceeds of $4.4 billion from the sale of subscription receipts, draws on acquisition bridge facilities in the aggregate amount of US$6.9 billion and existing cash on hand. The sale of the subscription receipts was completed on April 1, 2016, through a public offering, and following the closing of the acquisition, the subscription receipts were exchanged into 96.6 million TransCanada common shares.
Columbia Pipeline Partners LP (CPPL)
2016	In November 2016, we announced that we entered into an agreement and plan of merger through which Columbia agreed to acquire, for cash, all of the outstanding publicly held common units of CPPL.
2017	In February 2017, we completed the acquisition, for cash, of all outstanding publicly held common units of CPPL at a price of US$17.00 and a stub period distribution of US$0.10 per common unit for an aggregate transaction value of US$921 million.
Leach XPress
2015	The Federal Energy Regulatory Commission (U.S.) (FERC) 7(C) application for this Columbia Gas project was filed in June 2015. The project transports approximately 1.6 PJ/d (1.5 Bcf/d) of Marcellus and Utica gas supply to delivery points along the pipeline and to the Leach interconnect with Columbia Gulf. The project consists of 260 km (160 miles) of 36-inch greenfield pipe, 39 km (24 miles) of 36-inch loop, three km (two miles) of 30-inch greenfield pipe, 82.8 MW (111,000 hp) of greenfield compression and 24.6 MW (33,000 hp) of brownfield compression.
2016	The Final Environmental Impact Statement (FEIS) for the project was received in September 2016.
2018	The US$1.6 billion project was placed in service on January 1, 2018.
Mountaineer XPress
2016	The FERC 7(C) application for this Columbia Gas project was filed in April 2016. The project is designed to transport approximately 2.9 PJ/d (2.7 Bcf/d) of Marcellus and Utica gas supply to delivery points along the pipeline and to the Leach interconnect with Columbia Gulf. The project consists of 275 km (171 miles) of 36-inch greenfield pipeline, ten km (six miles) of 24-inch lateral pipeline, 0.6 km (0.4 miles) of 30-inch replacement pipeline, 114.1 MW (153,000 hp) of greenfield compression and 55.9 MW (75,000 hp) of brownfield compression.
2017	The FERC certificate for the Mountaineer Xpress project was received on December 29, 2017. The project is expected to have a US$0.6 billion increase in its capital project cost due to increased construction cost estimates. As a result of a cost sharing mechanism, overall project returns are not anticipated to be materially affected. The US$2.6 billion project is expected to be placed in service in fourth quarter 2018.
Rayne XPress
2015	The FERC 7(C) application for this Columbia Gulf project was filed in July 2015. The project transports approximately 1.1 PJ/d (1 Bcf/d) of supply from an interconnect with the Leach XPress pipeline project and another interconnect, to markets along the system and to the Gulf Coast. The project consists of bi-directional compressor station modifications along Columbia Gulf, 38.8 MW (52,000 hp) of greenfield compression, 20.1 MW (27,000 hp) of replacement compression and six km (four miles) of 30-inch pipe replacement.
2016	The FEIS for the project was received in September 2016.
2017	The US$0.4 billion project was placed in service on November 2, 2017.
Gulf XPress
2016	The FERC 7(C) application for this Columbia Gulf project was filed in April 2016. The project is designed to transport approximately 0.9 Bcf/d associated with the Mountaineer XPress expansion to various delivery points on Columbia Gulf and the Gulf Coast. The project consists of adding seven greenfield midpoint compressor stations along the Columbia Gulf route totaling 182.7 MW (245,000 hp).
2017	The FERC certificate for Gulf Xpress project was received on December 29, 2017. We expect this project, with an estimated capital investment of US$0.6 billion, to be placed in service in 2018.
Cameron Access Project
2015	The FERC certificate for this Columbia Gulf project was received in September 2015. The project is designed to transport approximately 0.8 Bcf/d of gas supply to the Cameron LNG export terminal in Louisiana. The project consists of 55 km (34 miles) of 36-inch greenfield pipeline, 11 km (seven miles) of 30-inch looping and 9.7 MW (13,000 hp) of greenfield compression. We expect this project, with an estimated capital investment of US$0.3 billion, to be in service in first quarter 2018.

TransCanada Annual information form 2017 9

Date	Description of development
WB XPress
2015	The FERC 7(C) application for both segments of this Columbia Gas project was filed in December 2015. The project is designed to transport approximately 1.3 Bcf/d of Marcellus gas supply westbound (0.8 Bcf/d) to the Gulf Coast via an interconnect with the Tennessee Gas Pipeline, and eastbound (0.5 Bcf/d) to Mid-Atlantic markets. The project consists of 47 km (29 miles) of various diameter pipeline, 338 km (210 miles) of restoring and uprating maximum operating pressure of existing pipeline, 29.8 MW (40,000 hp) of greenfield compression and 99.9 MW (134,000 hp) of brownfield compression.
2017	The FERC certificate for the WB XPress project was received in November 2017. We expect this project, with an estimated capital investment of US$0.8 billion, to be fully in service in 2018.
Buckeye XPress
2017	The Buckeye XPress project represents an upsizing of an existing pipeline replacement project in conjunction with our Columbia Gas modernization program. The US$0.2 billion cost to upsize the replacement pipe and install compressor upgrades will enable us to offer 290 TJ/d (275 MMcf/d) of incremental pipeline capacity to accommodate growing Appalachian production. We expect the project to be placed in service in late-2020.
Modernization I & II
2017	Columbia Gas and its customers entered into a settlement arrangement, approved by the FERC, which provides recovery and return on investment to modernize its system, improve system integrity, and enhance service reliability and flexibility. The modernization program includes, among other things, replacement of aging pipeline and compressor facilities, enhancements to system inspection capabilities, and improvements in control systems. The US$1.5 billion Modernization I arrangement was completed under the terms of a 2012 settlement agreement, with the final US$0.2 billion spent in 2017. Modernization II has been approved for up to US$1.1 billion of work starting in 2018 and to be completed through 2020. As per terms of the arrangements, facilities in service by October 31 collect revenues effective February 1 of the following year.
Gibraltar
2016	The first phase of the multi-phase project was completed in December 2016.
2017	The US$0.3 billion Midstream project to construct an approximate 1,000 TJ/d (934 MMcf/d) dry gas header pipeline in southwest Pennsylvania was placed in service on November 1, 2017.
OTHER U.S. NATURAL GAS PIPELINES
ANR Pipeline
2016	ANR Pipeline filed a Section 4 Rate Case that requested an increase to ANR's maximum transportation rates in January 2016. Shifts in ANR’s traditional supply sources and markets, necessary operational changes, needed infrastructure updates, and evolving regulatory requirements were driving required investment in facility maintenance, reliability and system integrity as well as an increase in operating costs that resulted in the current tariff rates not providing a reasonable return on our investment. We also pursued a collaborative process to find a mutually beneficial outcome with our customers through settlement negotiations. ANR's last rate case filing was more than 20 years ago. ANR reached a settlement with its shippers effective August 1, 2016 and received FERC approval on December 16, 2016. Per the settlement, transmission reservation rates would increase by 34.8 per cent and storage rates would remain the same for contracts one to three years in length, while increasing slightly for contracts of less than one year and decreasing slightly for contracts more than three years in duration. There is a moratorium on any further rate changes until August 1, 2019. ANR may file for new rates after that date if it has spent more than US$0.8 billion in capital additions, but must file for new rates no later than an effective date of August 1, 2022.
Great Lakes
2015	We test goodwill for impairment annually or more frequently if events or changes in circumstances lead us to believe it might be impaired. Our share of the goodwill related to Great Lakes, net of non-controlling interests, was US$386 million at December 31, 2015.
2016	Our share of the goodwill related to Great Lakes, net of non-controlling interests, was US$382 million at December 31, 2016.
2017	On October 30, 2017, Great Lakes filed a rate settlement with the FERC to satisfy its obligations from its previous 2013 rate settlement for new rates to be in effect by January 1, 2018. The settlement, if approved by the FERC, will decrease Great Lakes’ maximum transportation rates by 27 per cent effective October 1, 2017. Great Lakes expects that the impact from other changes, including the recent long-term transportation contract with the Canadian Mainline as described below, other revenue opportunities on the system and the elimination of the revenue sharing mechanism with its customers, will essentially offset the full year impact of the reduction in Great Lakes’ rates beginning in 2018. In conjunction with the Canadian Mainline's LTFP service (see Canadian Regulated Pipelines – Dawn Long-Term Fixed-Price Service above), Great Lakes entered into a new ten-year gas transportation contract with the Canadian Mainline. This contract received NEB approval in September 2017, effective November 1, 2017, and contains volume reduction options up to full contract quantity beginning in year three.

10 TransCanada Annual information form2017

Date	Description of development
2017 (continued)	In relation to goodwill impairment, although evolving market conditions and other factors relevant to Great Lakes' long term financial performance have been positive, there is a risk that reductions in future cash flow forecasts or adverse changes in other key assumptions could result in a future impairment of a portion of the goodwill balance relating to Great Lakes. Our share of the goodwill related to Great Lakes, net of non-controlling interests, was US$379 million at Year End. At Year End, the estimated fair value of Great Lakes exceeded its carrying value by less than ten per cent. Further information about impairment of goodwill can be found in the MD&A in the Other Information – Critical Accounting Estimates – Impairment of long-lived assets, equity investments and goodwill section, which section of the MD&A is incorporated by reference herein.
Northern Border
2017	Northern Border filed a rate settlement with the FERC on December 4, 2017, reflecting a settlement-in-principle with its shippers, which precludes the need to file a general rate case as contemplated by its previous 2012 settlement. Northern Border anticipates that the FERC will accept the settlement agreement and that it will be unopposed. This is expected to provide Northern Border with rate stability over the longer term. We have a 12.9 per cent indirect ownership interest in Northern Border though TC PipeLines, LP (TCLP).
Portland Natural Gas Transmission System (PNGTS)
2016	In January 2016, we closed the sale of our 49.9 per cent of our total 61.7 per cent interest in PNGTS to TCLP for US$223 million. Proceeds were comprised of US$188 million in cash and the assumption of US$35 million of a proportionate share of PNGTS debt.
2017	In June 2017, we closed the sale of a 49.34 per cent of our 50 per cent interest in Iroquois, along with an option to sell the remaining 0.66 per cent at a later date, to TCLP. At the same time, we closed the sale of our remaining 11.81 per cent interest in PNGTS to TCLP. Proceeds from these transactions were US$765 million, before post-closing adjustments, and were comprised of US$597 million in cash and US$168 million representing a proportionate share of Iroquois and PNGTS debt. In December 2017, PNGTS executed precedent agreements with several LDCs in New England and Atlantic Canada to re-contract certain system capacity set to expire in 2019, as well as expand the PNGTS system to bring its certificated capacity from 222 TJ/d (210 MMcf/d) up to 290 TJ/d (275 MMcf/d). The approximate US$80 million Portland XPress Project (PXP) will proceed concurrently with upstream capacity expansions. The in-service dates of PXP are being phased-in over a three-year period beginning November 1, 2018.
Iroquois Gas Transmission System, L.P. (Iroquois)
2016	FERC approvals were obtained for settlements with shippers for our Iroquois, Tuscarora and Columbia Gulf pipelines in third quarter 2016. On March 31, 2016, we acquired an additional 4.87 per cent interest in Iroquois for an aggregate purchase price of US$54 million and on May 1, 2016, a further 0.65 per cent was acquired for US$7 million. As a result, our interest in Iroquois increased to 50 per cent.
2017	In June 2017, we closed the sale of a 49.34 per cent of our 50 per cent interest in Iroquois, along with an option to sell the remaining 0.66 per cent at a later date, to TCLP. At the same time, we closed the sale of our remaining 11.81 per cent interest in PNGTS to TCLP. Refer to the Portland Natural Gas Transmission System section above.
Gas Transmission Northwest LLC (GTN)
2015	In April 2015, we closed the sale of our remaining 30 per cent interest in GTN to TCLP for an aggregate purchase price of US$457 million. Proceeds were comprised of US$246 million in cash, the assumption of US$98 million of debt, being proportional GTN debt and US$95 million of new Class B units of TCLP.
TC Offshore LLC (TC Offshore)
2015	We entered into an agreement to sell TC Offshore to a third party. As a result, at December 31, 2015, the related assets and liabilities were classified as held for sale and were recorded at their fair values less costs to sell. This resulted in a pre-tax loss provisions of $125 million recorded in 2015.
2016	We completed the sale of TC Offshore in March 2016.
LNG PIPELINE PROJECTS
Alaska LNG Project
2015	In November 2015, we sold our interest in the Alaska LNG project to the State of Alaska. The proceeds of US$65 million from this sale provide a full recovery of costs incurred to advance the project since January 1, 2014 including a carrying charge. With this sale, our involvement in developing a pipeline system for commercializing Alaska North Slope natural gas ceased.

TransCanada Annual information form 2017 11

Developments in the Mexico Natural Gas Pipelines segment

Date	Description of development
MEXICO NATURAL GAS PIPELINES
Topolobampo
2016	In November 2012, we were awarded the contract to build, own and operate the Topolobampo project. Construction on the project is supported by a 25-year Transportation Service Agreement (TSA) for 717 TJ/d (670 MMcf/d) with the Comisión Federal de Electricidad (Mexico) (CFE). The Topolobampo project is a 560 km (348 mile), 30-inch pipeline that will receive gas from the upstream pipelines near El Encino, in the state of Chihuahua, and deliver natural gas from these interconnecting pipelines to delivery points along the pipeline route including our Mazatlán pipeline at El Oro, in the state of Sinaloa.
2017	The Topolobampo project is substantially complete, excluding a 20 km (12 mile) section due to delays experienced by the Secretary of Energy, the government department which conducts indigenous consultations in Mexico. The issue has been resolved and construction on this final section is expected to be completed in second quarter 2018. Under the terms of the TSA, the delays were recognized as a force majeure event with provisions allowing for the collection of revenue as per the original TSA service commencement date of July 2016. The pipeline cost estimate is approximately US$1.2 billion, an increase of US$0.2 billion from the original estimate, due to the delays.
Mazatlán
2015	The Mazatlán project is a 430 km (267 mile), 24-inch pipeline running from El Oro to Mazatlán, in the state of Sinaloa, with an estimated cost of US$0.4 billion. This pipeline is supported by a 25-year natural gas TSA for 214 TJ/d (200 MMcf/d) with the CFE.
2016	Physical construction was completed in 2016 and was awaiting natural gas supply from upstream interconnecting pipelines. We met our obligations and have been collecting revenue as per provisions in the contract and per the original TSA service commencement date of December 2016.
2017	The Mazatlán project was commissioned and brought into full service in July 2017.
Tula
2015	In November 2015, we were awarded the contract to build, own and operate the US$0.7 billion, 36-inch, 300 km (186 mile) pipeline with a 16-inch, 24 km (15 mile) lateral, supported by a 25-year natural gas TSA for 949 TJ/d (886 MMcf/d) with the CFE. The pipeline will transport natural gas from Tuxpan, Veracruz to markets near Tula, Querétaro extending through the states of Puebla and Hidalgo.
2017	Construction of the Tula pipeline was substantially completed in 2017, with the exception of approximately 90 km (56 miles) of the pipeline. Project completion has been revised to late 2019 due to delays experienced by the Secretary of Energy, the governmental department which conducts indigenous consultations in Mexico. The delay has been recognized by the CFE as a force majeure event and we are finalizing amending agreements to formalize the schedule and payment impacts. As a result of the delay and increased cost of land and permitting, estimated project costs have increased by US$0.1 billion from the original estimate. Full completion of the project has been revised to the end of 2019.
Villa de Reyes
2016	In April 2016, we were awarded the contract to build, own and operate the Villa de Reyes pipeline in Mexico. Construction of the pipeline is supported by a 25-year natural gas TSA for 949 TJ/d (886 MMcf/d) with the CFE. We expect to invest approximately US$0.6 billion to construct 36- and 24-inch pipelines totaling 420 km (261 miles). The bi-directional pipeline will transport natural gas between Tula, in the state of Hidalgo, and Villa de Reyes, in the state of San Luis Potosí. The project will interconnect with our Tamazunchale and Tula pipelines as well as with other transporters in the region.
2017	Construction of the project has commenced, however, delays due to archeological investigations by state authorities have caused the in-service date to be revised to late 2018. The delay has been recognized as a force majeure event by the CFE and we are finalizing amending agreements to formalize the schedule and payment impacts. As a result of the delay and increased cost of land and permitting, estimated project costs have increased by US$0.2 billion from the original estimate.
Sur de Texas
2016	The US$2.1 billion Sur de Texas project is a joint venture with IEnova in which we hold a 60 per cent interest representing an investment of approximately US$1.3 billion. Construction of the pipeline is supported by a 25-year natural gas TSA for 2.8 PJ/d (2.6 bcf/d) with the CFE. The 42-inch, approximately 800 km (497 mile) pipeline will start offshore in the Gulf of Mexico, at the border point near Brownsville, Texas, and end in Tuxpan in the state of Veracruz. The project will deliver natural gas to our Tamazunchale and Tula pipelines and to other transporters in the region.
2017	Pipeline construction is progressing toward an anticipated in-service date of late 2018, with approximately 60 per cent of the off-shore construction completed as at Year End.

Further information about developments in the Natural Gas Pipelines business, including changes that we expect will occur in the current financial year, can be found in the MD&A in the Natural Gas Pipelines business section; Canadian Natural Gas Pipelines – Understanding our Canadian Natural Gas Pipelines segment, Significant events, Financial results and Outlook sections; U.S. Natural Gas Pipelines – Understanding our U.S. Natural Gas Pipelines segment, Significant events, Financial results and Outlook sections; and Mexico Natural Gas Pipelines – Understanding our Mexico Natural Gas Pipelines segment, Significant events, Financial results and Outlook sections, which sections of the MD&A are incorporated by reference herein.

12 TransCanada Annual information form2017

LIQUIDS PIPELINES

Development in the Liquids Pipelines Segment

Date	Description of development
Keystone Pipeline System
2015	In 2015, we entered into an agreement with CITGO Petroleum (CITGO) to construct a US$65 million pipeline connection between the Keystone Pipeline and CITGO’s Sour Lake, Texas terminal, which supplies their 425,000 Bbl/d Lake Charles, Louisiana refinery. We secured additional long-term contracts bringing our total contract position up to 545,000 Bbl/d.
2016	In January 2016, we entered into an agreement with Magellan Midstream Partners L.P. (Magellan) to connect our Houston Terminal to Magellan's Houston and Texas City, Texas delivery system. We will own 50 per cent of this US$50 million pipeline project which will enhance connections for our Keystone Pipeline to the Houston market. 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 Centre (NRC) and the Pipeline and Hazardous Materials Safety and Administration (PHMSA). Temporary repairs were completed and the Keystone Pipeline was restarted by mid-April 2016. Shortly thereafter in early May 2016, permanent pipeline repairs were completed and restoration work was completed by early July 2016. Corrective measures required by PHMSA were completed in September 2016. This shutdown did not significantly impact our 2016 earnings. The Houston Lateral pipeline and terminal, an extension from the Keystone Pipeline to Houston, Texas, went into service in August 2016. The terminal has an initial storage capacity for 700,000 barrels of crude oil. The HoustonLink pipeline which connects the Houston Terminal to Magellan's Houston and Texas City, Texas delivery system was completed in December 2016. The CITGO Sour Lake pipeline connection between the Keystone Pipeline and CITGO's Sour Lake, Texas terminal was placed into service in December 2016.
2017	In fourth quarter 2017, we concluded open seasons for the Keystone pipeline and Marketlink and secured incremental long-term contractual support. On November 16, 2017, the Keystone pipeline was temporarily shut down after a leak was detected in Marshall County, South Dakota. The estimated volume of the release was 5,000 barrels as reported to the NRC and the PHMSA. On November 29, 2017, the pipeline was repaired and returned to service at a reduced pressure in the affected section of the pipeline. Further investigative activities and corrective measures required by PHMSA are planned for 2018. This shutdown did not have a significant impact on our 2017 earnings.
Keystone XL
2015	In January 2015, the Nebraska State Supreme Court vacated a lower court's ruling, which had given the state Public Service Commission (PSC) rather than the governor, the authority to approve an alternative route through Nebraska for Keystone XL, as unconstitutional. As a result, the Governor’s January 2013 approval of the alternate route through Nebraska for Keystone XL remained valid. Landowners filed lawsuits in two Nebraska counties seeking to enjoin Keystone XL from condemning easements on state constitutional grounds. The decision on the Keystone XL Presidential permit application was delayed throughout 2015 by the U. S. Department of State (DOS) and was ultimately denied in November 2015. At December 31, 2015, as a result of the denial of the Presidential permit, we evaluated our investment in Keystone XL and related projects, including Keystone Hardisty Terminal, for impairment. As a result of our analysis, we determined that the carrying amount of these assets was no longer recoverable, and recognized a total non-cash impairment charge of $3.7 billion ($2.9 billion after-tax). The impairment charge was based on the excess of the carrying value of $4.3 billion over the fair value of $621 million, which includes $93 million fair value for Keystone Hardisty Terminal. The calculation of this impairment is discussed further in the Other information – Critical accounting estimates section of the MD&A, which section is incorporated by reference herein. In November 2015, we withdrew our application to the PSC for approval of the route for Keystone XL in the state. The application was initially filed in October 2015. The withdrawal was made without prejudice to potentially refile if we elect to pursue the project.
2016	On January 5, 2016, the South Dakota Public Utilities Commission (PUC) accepted Keystone XL’s certification that it continued to comply with the conditions in its existing 2010 permit authority in the state. On January 6, 2016, we filed a Notice of Intent to initiate a claim under Chapter 11 of North American Free Trade Agreement (NAFTA) in response to the U.S. Administration’s decision to deny a Presidential permit for the Keystone XL Pipeline on the basis that the denial was arbitrary and unjustified. Through the NAFTA claim, we were seeking to recover more than US$15 billion in costs and damages that we estimated to have suffered as a result of the U.S. Administration’s breach of its NAFTA obligations. In June 2016, we filed a Request for Arbitration in a dispute against the U.S. Government pursuant to the Convention on Settlement of Investment Disputes between States and Nationals of Other States, the Rules of Procedure for the Institution of Conciliation and Arbitration Proceedings and Chapter 11 of NAFTA. On January 5, 2016, we also filed a lawsuit in the U.S. Federal Court in Houston, Texas, asserting that the U.S. President’s decision to deny construction of Keystone XL exceeded his power under the U.S. Constitution. The federal court lawsuit did not seek damages, but rather a declaration that the permit denial was without legal merit and that no further Presidential action was required before construction of the pipeline could proceed.

TransCanada Annual information form 2017 13

Date	Description of development
2017	On January 24, 2017, the U.S. President signed a Presidential Memorandum inviting TransCanada to refile an application for the U.S. Presidential Permit. On January 26, 2017, we filed a Presidential Permit application with the DOS for the project. In February 2017, we filed an application with the PSC to seek approval for the Keystone XL pipeline route through the state. In March 2017, the DOS issued a U.S. Presidential Permit authorizing construction of the U.S./ Canada border crossing facilities of the Keystone XL project. We discontinued our claim under Chapter 11 of NAFTA and withdrew the U.S. Constitutional challenge. Later in March 2017, two lawsuits were filed in Montana District Court challenging the validity of the Presidential Permit. Along with the U.S. Government, we filed motions for dismissal of these lawsuits which were subsequently denied on November 22, 2017. The cases will now proceed to the consideration of summary judgment motions. In July 2017, we launched an open season to solicit additional binding commitments from interested parties for transportation of crude oil on the Keystone pipeline and for the Keystone XL project from Hardisty, Alberta to Cushing, Oklahoma and the U.S. Gulf Coast. The successful open season concluded on October 26, 2017. On November 20, 2017, we received PSC approval for the alternative mainline route. On November 24, 2017, we filed a motion with the PSC to reconsider its ruling and permit us to file an amended application that would support their decision and would address certain issues related to their selection of the alternative route, which was denied on December 19, 2017. On December 27, 2017, opponents of the Keystone XL project and intervenors in the Keystone XL Nebraska regulatory proceeding filed an appeal of the PSC decision seeking to have that decision overturned. TransCanada supports the decision of the PSC and will actively participate in the appeal process to defend that decision. In January 2018, we secured sufficient commercial support to commence construction preparation for the Keystone XL project. Subject to certain conditions, we expect to commence primary construction in 2019, and once commenced, construction is anticipated to take approximately two years to complete.
Energy East
2015	In April 2015, we announced that the proposed marine terminal and associated tank terminal in Cacouna, Québec would not be built as a result of the recommended reclassification of the beluga whale, indigenous to the site, as an endangered species. In November 2015, following consultation with stakeholders and shippers, we announced the intention to amend the Energy East pipeline application to remove a port in Québec and proceed with a single marine terminal in Saint John, New Brunswick. In December 2015, we filed an amendment to the existing project application with the NEB that adjusted the proposed route, scope and capital cost of the project reflecting refinement and scope change including the removal of the port in Québec.
2016	In May 2016, we filed a consolidated application with the NEB for the Energy East pipeline. In June 2016, Energy East achieved a major milestone with the NEB’s announcement determining the Energy East pipeline application was sufficiently complete to initiate the formal regulatory review process. However, in August 2016, panel sessions were canceled as three NEB panelists recused themselves from continuing to sit on the panel to review the project due to allegations of reasonable apprehension of bias. The Chair of the NEB and the Vice-Chair, who is also a panel member, recused themselves of any further duties related to the project. As a result, all hearings for the project were adjourned until further notice.
2017	On January 9, 2017, the NEB appointed three new permanent panel members to undertake the review of the Energy East and Eastern Mainline projects. On January 27, 2017, the new NEB panel members voided all decisions made by the previous hearing panel members and all decisions were removed from the official hearing record. We were not required to refile the application and parties were not required to reapply for intervener status. On September 7, 2017, we requested the NEB suspend the review of the Energy East and Eastern Mainline project applications for 30 days to provide time for us to conduct a careful review of the NEB's changes, which were announced on August 23, 2017, regarding the list of issues and environmental assessment factors related to the projects and how these changes impact the projects' costs, schedules and viability. On October 5, 2017, after careful review of the changed circumstances, we informed the NEB that we would not be proceeding with the Energy East and Eastern Mainline project applications. We also notified Québec’s Ministère du Développement durable, de l'Environnement et la Lutte contre les changements climatiques (MDDELCC) that we were withdrawing the Energy East project from the environmental review process. As the Energy East pipeline was also to provide transportation services for the Upland pipeline, the DOS was notified in October 2017, that we would no longer be pursuing the U.S. Presidential Permit application for that project. We reviewed the $1.3 billion carrying value of the projects, including allowance of funds used during construction (AFUDC) capitalized since inception, and recorded a $954 million after-tax non-cash charge in our fourth quarter 2017 results. We ceased capitalizing AFUDC on the projects effective August 23, 2017, the date of the NEB's announced scope changes. With Energy East's inability to reach a regulatory decision, no recoveries of costs from third parties are forthcoming.

14 TransCanada Annual information form2017

Date	Description of development
Grand Rapids
2015	In August 2015, we announced a joint venture between Grand Rapids and Keyera Corp. (Keyera) for provision of diluent transportation service on the 20-inch pipeline between Edmonton and Fort Saskatchewan, Alberta. The joint venture was incorporated into Grand Rapids to provide enhanced diluent supply alternatives to our shippers.
2016	Construction continued on the Grand Rapids pipeline. We entered into a partnership with Brion Energy Corporation (Brion) to develop Grand Rapids with each party owning 50 per cent of the pipeline project. Our partner also entered into a long-term transportation service contract in support of the project. Construction progressed on the 20-inch diluent joint venture pipeline between Edmonton and Fort Saskatchewan, Alberta. The joint venture between Grand Rapids and Keyera was incorporated into Grand Rapids to provide enhanced diluent supply alternatives to our shippers.
2017	In late August 2017, the Grand Rapids pipeline, jointly owned by TransCanada and PetroChina Canada Ltd. (formerly Brion), was placed in service. The 460 km (287 mile) crude oil transportation system connects producing areas northwest of Fort McMurray, Alberta to terminals in the Edmonton/ Heartland region.
Northern Courier
2016	Construction continued on the Northern Courier pipeline to transport bitumen and diluent between the Fort Hills mine site and Suncor Energy's terminal located north of Fort McMurray, Alberta. The project is fully underpinned by long-term contracts with the Fort Hills partnership.
2017	In November 2017, the Northern Courier pipeline, a 90 km (56 mile) pipeline system, achieved commercial in-service.
White Spruce
2016	In December 2016, we finalized a long-term transportation agreement to develop and construct the 20-inch White Spruce pipeline, which would transport crude oil from Canadian Natural Resources Limited's Horizon facility in northeast Alberta, to the Grand Rapids pipeline system. The total capital cost for the project amounts to approximately $200 million.
2018	In first quarter 2018, we anticipate receiving a decision from the AER on the regulatory permit to construct the $200 million White Spruce pipeline. Due to the delay in the regulatory process, we expect the White Spruce pipeline to be in-service in 2019.
Upland Pipeline
2015	In April 2015, we filed an application to obtain a U.S. Presidential permit for the Upland pipeline, which would provide crude oil transportation from and between multiple points in North Dakota and interconnect with the Energy East pipeline system at Moosomin, Saskatchewan. The commercial contracts that we executed for Upland pipeline were conditioned on the Energy East pipeline project proceeding.
2016	We reviewed the Canadian federal government's interim measures for pipeline reviews to assess their impact to Upland Pipeline.
2017	On October 5, 2017, after careful review of the changed circumstances, we informed the NEB that we would not be proceeding with the Energy East and Eastern Mainline project applications. We notified MDDELCC that we were withdrawing the Energy East project from the environmental review process. As the Energy East pipeline was also to provide transportation services for the Upland pipeline, the DOS was notified on October 5, 2017, that we would no longer be pursuing the U.S. Presidential Permit application for that project. Refer to the Energy East section above.
Liquids Marketing
2015	We established a liquids marketing business to expand into other areas of the liquids business value chain. Our liquids marketing business provides customers with a variety of crude oil marketing services including transportation, storage and crude oil supply, primarily transacted through purchase and sale of physical crude oil.

Further information about developments in the Liquids Pipelines business, including changes that we can expect will occur in the current financial year, can be found in the MD&A in the Liquids Pipelines – Understanding our Liquids Pipelines business, Significant events, Financial results and Outlook sections, which sections of the MD&A are incorporated by reference herein.

TransCanada Annual information form 2017 15

ENERGY

Development in the Energy Segment

Date	Description of development
CANADIAN POWER
Alberta PPAs
2015	In June 2015, the Alberta government announced a renewal and change to the Specified Gas Emitters Regulation (SGER) in Alberta. Since 2007, under the SGER, established industrial facilities with greenhouse gas (GHG) emissions above a certain threshold are required to reduce their emissions by 12 per cent below an average intensity baseline, and a carbon levy of $15 per tonne is placed on emissions above this target. The changes to the SGER included an increase in the emissions reductions target to 15 per cent in 2016 and 20 per cent in 2017, along with an increase in the carbon levy to $20 per tonne in 2016 and $30 per tonne in 2017. Starting in 2018, coal-fired generators will pay $30 per tonne of CO2 on emissions above what Alberta's cleanest natural gas-fired plant would emit to produce an equivalent amount of electricity.
2016	On March 7, 2016, we issued notice to the Balancing Pool to terminate our Alberta PPAs. On July 22, 2016, we, along with the ASTC Power Partnership (ASTC), issued a notice referring the matter to be resolved by binding arbitration pursuant to the dispute resolution provisions of the PPAs. On July 25, 2016, the Government of Alberta brought an application in the Court of Queen’s Bench to prevent the Balancing Pool from allowing termination of a PPA held by another party which contains identically worded termination provisions to our PPAs. The outcome of this court application could have affected resolution of the arbitration of the Sheerness, Sundance A and Sundance B PPAs. In December 2016, management engaged in settlement negotiations with the Government of Alberta and finalized terms of the settlement of all legal disputes related to the PPA terminations. The Government of Alberta and the Balancing Pool agreed to our termination of the PPAs resulting in the transfer of all our obligations under such PPAs to the Balancing Pool. Upon final settlement of the PPA terminations, we transferred to the Balancing Pool a package of environmental credits held to offset the PPA emissions costs and recorded a non-cash charge of $92 million before-tax ($68 million after-tax) related to the carrying value of our environmental credits. In first quarter 2016, as a result of our decision to terminate the PPAs, we recorded a non-cash impairment charge of $240 million before-tax ($176 million after-tax) comprised of $211 million before-tax ($155 million after-tax) related to the carrying value of our Sundance A and Sheerness PPAs and $29 million before-tax ($21 million after-tax) on our equity investment in the ASTC which previously held the Sundance B PPA.
Ontario Cap and Trade
2016	Legislation enabling Ontario’s cap and trade program came into force effective July 1, 2016. This regulation set a limit on annual province-wide GHG emissions beginning in January 2017 and introduced a market to administer the purchase and trading of emissions allowances. The regulation places the compliance obligation for emissions from our natural gas-fired power facilities on local gas distributors, with the distributors then flowing the associated costs to the facilities themselves. The IESO has proposed contract amendments for contract holders to address costs and other issues associated with this change in law. We do not expect a significant overall impact to our Energy business as a result of this new regulation.
Napanee
2015	In January 2015, we began construction activities on our 900 MW natural gas-fired power plant at Ontario Power Corporation's (OPG) Lennox site in in the town of Greater Napanee.
2017	Construction continued on the power plant. We expect to invest approximately $1.3 billion in the Napanee facility during construction and commercial operations are expected to begin in fourth quarter 2018. Costs have increased due to delays in the construction schedule. Once in service, production from the facility is fully contracted with IESO for a 20-year period.
Bécancour
2015	We executed an agreement with Hydro-Québec Distribution (HQ) allowing HQ to dispatch up to 570 MW of peak winter capacity from our Bécancour facility for a term of 20 years commencing in December 2016.
2016	In November 2016, HQ released a new ten-year supply plan indicating additional peak winter capacity from Bécancour is not required at this time. Prior to this development, the regulator in Québec, Régie de l'énergie, reversed its initial decision to approve this agreement. Management does not expect further developments at Bécancour until November 2019 when the next ten-year supply plan is filed.
Bruce Power
2015	Bruce Power entered into an agreement with the IESO to extend the operating life of the facility to the end of 2064. This new agreement represents an extension and material amendment to the earlier agreement that led to the refurbishment of Units 1 and 2 at the site. The amended agreement, effective January 1, 2016, allows Bruce Power to immediately invest in life extension activities for Units 3 through 8. Our estimated share of investment in the Asset Management program to be completed over the life of the agreement is approximately $2.5 billion (2014 dollars). Our estimated share of investment in the Major Component Replacement (MCR) work that is expected to begin in 2020 is approximately $4 billion (2014 dollars). Under certain conditions, Bruce Power and the IESO can elect to not proceed with the remaining MCR investments should the cost exceed certain thresholds or prove to not provide sufficient economic benefits. The agreement was structured to account for changing cost inputs over time, including ongoing operating costs and additional capital investments.

16 TransCanada Annual information form2017

Date	Description of development
2015 (continued)	Beginning in January 2016, Bruce Power received a uniform price of $65.73 per MWh for all units, which included certain flow-through items such as fuel and lease expense recovery. Over time, the uniform price is subject to adjustments for the return of and on capital invested at Bruce Power under the Asset Management and MCR capital programs, along with various other pricing adjustments that would allow for a better matching of revenues and costs over the long-term. In connection with this opportunity, we exercised our option to acquire an additional 14.89 per cent ownership interest in Bruce B for $236 million from the Ontario Municipal Employees Retirement System. Subsequent to this acquisition, Bruce A and Bruce B were merged to form a single partnership structure, of which we hold a 48.4 per cent interest. In 2015, we recognized a $36 million charge, representing our proportionate share on the retirement of Bruce Power debt in conjunction with this merger.
2016	Bruce Power issued bonds and borrowed under its bank credit facility as part of a financing program to fund its capital program and make distributions to its partners. Distributions received by us from Bruce Power in second quarter 2016 included $725 million from this financing program.
2017	In February 2017, Bruce Power issued senior notes in capital markets under its financing program and distributed $362 million to TransCanada.
Ontario Solar
2017	On October 24, 2017, we entered into an agreement to sell our Ontario solar assets comprised of eight facilities with a total generating capacity of 76 MW, to Axium Infinity Solar LP. On December 19, 2017, we closed the sale for $541 million resulting in a gain of $127 million ($136 million after-tax).
U.S. POWER
Monetization of U.S. Northeast Power Business
2016	In November 2016, we announced the sale of Ravenswood, Ironwood, Ocean State Power and Kibby Wind to Helix Generation, LLC, an affiliate of LS Power Equity Advisors and the sale of TC Hydro to Great River Hydro, LLC, an affiliate of ArcLight Capital Partners, LLC.
2017	In April 2017, we closed the sale of TC Hydro to Great River Hydro, LLC for US$1.07 billion, before post-closing adjustments and recorded a gain of $715 million ($440 million after-tax). In June 2017, we closed the sale of Ravenswood, Ironwood, Ocean State Power and Kibby Wind to Helix Generation, LLC for US$2.029 billion, before post-closing adjustments. In addition to the pre-tax losses of approximately $829 million ($863 million after-tax) that we recorded in 2016 upon entering into agreements to sell these assets, an additional pre-tax loss on sale of approximately $211 million ($167 million after-tax) was recorded in 2017, primarily related to an adjustment to the purchase price and repair costs for an unplanned outage at Ravenswood prior to close, partially offset by insurance recoveries for a portion of the repair costs. Proceeds from the sale transactions were used to fully retire the remaining bridge facilities that partially funded the acquisition of Columbia. On December 22, 2017, we entered into an agreement to sell our U.S. power retail contracts as part of the continued wind down of our U.S. power marketing operations. The transaction is expected to close in first quarter 2018, subject to regulatory and other approvals.
Ironwood
2016	In February 2016, we acquired the 778 MW Ironwood natural gas fired, combined cycle power plant located in Lebanon, Pennsylvania for US$653 million in cash after post-acquisition adjustments. The Ironwood power plant delivers energy into the PJM Interconnection area power market. Refer to the Monetization of U.S. Northeast Power Business section above.

Further information about developments in the Energy business, including changes that we expect will occur in the current financial year, can be found in the MD&A in the About our business – Our strategy, Energy – Understanding our Energy business, Significant events, Financial results and Outlook sections, which sections of the MD&A are incorporated by reference herein.

TransCanada Annual information form 2017 17

Business of TransCanada

We are a leading North American energy infrastructure company focused on Natural Gas Pipelines, Liquids Pipelines and Energy. Refer to the About our business – Three core businesses – 2017 Financial highlights – Consolidated results section of the MD&A for our revenues from operations by segment, for the years ended December 31, 2017 and 2016, which section of the MD&A is incorporated by reference herein.

The following is a description of each of TransCanada's three core businesses.

NATURAL GAS PIPELINES

Our natural gas pipeline network transports natural gas from supply basins to local distribution companies, power generation and individual facilities, interconnecting pipelines and other businesses across Canada, the U.S. and Mexico. Our Natural Gas Pipelines business is split into three operating segments representing its geographic diversity: Canadian Natural Gas Pipelines, U.S. Natural Gas Pipelines and Mexico Natural Gas Pipelines.

A description of the natural gas pipelines and regulated natural gas storage assets we operate in addition to further information about our pipeline holdings, developments and opportunities, significant regulatory developments and competitive position which relate to our Natural Gas Pipelines business can be found in the Natural Gas Pipelines Business, Canadian Natural Gas Pipelines, U.S. Natural Gas Pipelines and Mexico Natural Gas Pipelines sections of the MD&A, which sections of the MD&A are incorporated by reference herein.

LIQUIDS PIPELINES

Our existing liquids pipelines infrastructure connects Alberta crude oil supplies to U.S. refining markets in Illinois and Oklahoma, as well as connecting U.S. crude oil supplies from the Cushing, Oklahoma hub to refining and export markets in the U.S. Gulf Coast. We also provide intra-Alberta liquids transportation. Our proposed future pipeline infrastructure would expand capacity for Canadian and U.S. crude oil to access key markets. We will also pursue enhancing our transportation service offerings to other areas of the liquids pipelines business value chain.

A description of pipelines and properties we operate, in addition to further information about our pipeline holdings, developments and opportunities, significant regulatory developments and competitive position which relate to our Liquids Pipelines business can be found in the MD&A in the Liquids Pipelines section, which section of the MD&A is incorporated by reference herein.

18 TransCanada Annual information form2017

REGULATION OF NATURAL GAS PIPELINES AND LIQUIDS PIPELINES

Canada

Natural Gas Pipelines

The NGTL System, Canadian Mainline, and Foothills System (collectively, the Systems) are regulated by the NEB under the National Energy Board Act (Canada). The NEB regulates the construction and operation of facilities, and the terms and conditions of services, including rates, for these Canadian regulated natural gas transmission systems.

The NEB approves tolls and services that provide TransCanada the opportunity to recover costs of transporting natural gas, including the return of capital (depreciation) and return on the average investment base for each of the Systems. Generally, Canadian natural gas pipelines request the NEB to approve the pipeline’s cost of service and tolls once a year, and recover or refund the variance between actual and expected revenues and costs in future years. The Canadian Mainline, however, operates under a fixed toll arrangement for its longer term firm transportation service and has the flexibility to price its shorter term and discretionary services in order to maximize its revenue. A Supplemental Agreement for the 2018-2020 period for the Canadian Mainline was filed for approval with the NEB in December 2017. Further information relating to the Canadian Mainline LDC Settlement and Supplemental Agreement can be found in the General developments of the business – Natural Gas Pipelines – Developments in the Canadian Natural Gas Pipelines Segment – Canadian Mainline Settlement section above. In addition, the NGTL System concluded its two-year settlement arrangement in 2017 and is currently working with interested parties for a new arrangement for 2018 and longer.

New facilities on or associated with the Systems are approved by the NEB before construction begins and the NEB regulates the operations of each of the Systems. Net earnings of the Systems may be affected by changes in investment base, the allowed ROE and any incentive earnings.

West Coast LNG – Natural Gas Pipeline Project

The Coastal GasLink natural gas pipeline project is being proposed and developed primarily under the regulatory regime administered by the OGC and the BCEAO. The OGC is responsible for overseeing oil and gas operations in B.C., including exploration, development, pipeline transportation and reclamation. The BCEAO is an agency that manages the review of proposed major projects in B.C., as required by the B.C. Environmental Assessment Act.

Liquids Pipelines

The NEB regulates the terms and conditions of service, including rates, construction and operation of the Canadian portion of the Keystone Pipeline System. The rates for transportation service on the Keystone Pipeline System are calculated in accordance with a methodology agreed to in transportation service agreements between Keystone and its shippers, and approved by the NEB. The Northern Courier and Grand Rapids pipelines are regulated by the AER. The AER regulates the construction and operation of pipelines and associated facilities in Alberta.

Liquids Pipelines Projects

The White Spruce pipeline is under development and is primarily under the regulatory regime administered by the AER. The AER administers approvals required to construct and operate the pipelines and associated facilities in accordance with Directive 56, approvals to obtain land access under the Public Land Act and environmental approvals under the Environmental and Protection Enhancement Act.

TransCanada Annual information form 2017 19

United States

Natural Gas Pipelines

TransCanada is subject to regulation by various federal, state and local governmental agencies, including those specifically described below.

The Company's wholly owned and partially owned U.S. pipelines are considered natural gas companies operating under the provisions of the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978, and are subject to the jurisdiction of the FERC. The Natural Gas Act of 1938 grants the FERC authority over the construction, acquisition and operation of pipelines and related facilities utilized in the transportation and sale of natural gas in interstate commerce, including the extension, enlargement or abandonment of service using such facilities. The FERC also has authority to regulate rates and charges for transportation and storage of natural gas in interstate commerce.

TransCanada holds certificates of public convenience and necessity issued by the FERC, authorizing us to operate pipelines, facilities and properties now in operation and to transport and store natural gas in interstate commerce. Our regulated natural gas storage business also has facilities that are regulated by the FERC. The Company is also subject to the Natural Gas Pipeline Safety Act of 1968 and the Pipeline Safety Improvement Act of 2002, which regulate the safety of natural gas pipelines.

Liquids Pipelines

The FERC regulates the terms and conditions of service, including transportation rates, of interstate liquids pipelines, including the U.S. portion of the Keystone Pipeline System and Marketlink. The siting and construction of pipeline facilities are regulated by the specific state regulator in which the pipeline facilities are located. Pipeline safety is regulated by PHMSA. Liquids pipelines that cross the international border between Canada and the U.S., such as the Keystone and Keystone XL pipelines, require a Presidential Permit from the DOS.

Mexico

Natural Gas Pipelines

TransCanada’s pipelines in Mexico are regulated by the Comisión Reguladora de Energía (CRE) who approve construction of new pipeline facilities and ongoing operations of the infrastructure. Our Mexican pipelines have approved tariffs, services and related rates; however, the contracts underpinning the construction and operation of the facilities are long-term negotiated fixed rate contracts. These rates are only subject to change under specific circumstances such as certain types of force majeure events or changes in law.

ENERGY

Our Energy business consists of power generation and unregulated natural gas storage assets.

The power business includes approximately 6,100 MW of operating generation capacity that we own, and approximately 900 MW of generation capacity under development. Our power generation assets are located in Alberta, Ontario, Québec, New Brunswick and Arizona, and are powered by natural gas, nuclear, and wind. A substantial majority of these assets are supported by long-term contracts.

We own and operate approximately 118 Bcf of unregulated natural gas storage capacity in Alberta and hold a contract with a third party for additional storage, in total accounting for approximately one-third of all storage capacity in the province.

Our U.S. Northeast power generation assets were sold in second quarter 2017, and on December 22, 2017, we entered into an agreement to sell our U.S. power retail contracts as part of the continued wind down of our U.S. power marketing operations. The transaction is expected to close in first quarter 2018, subject to regulatory and other approvals.

Further information about Energy assets we operate and Energy assets currently under construction, along with our Energy holdings and significant developments, and opportunities in relation to our Energy business, can be found in the MD&A in the Energy section, which section of the MD&A is incorporated by reference herein.

20 TransCanada Annual information form2017

General

EMPLOYEES

At Year End, TransCanada's principal operating subsidiary, TCPL, had 6,779employees, substantially all of whom were employed in Canada and the U.S., as set forth in the following table.

Calgary (includes U.S. employees working in Canada)	2,530
Western Canada (excluding Calgary)	547
Eastern Canada	319
Houston (includes Canadian employees working in the U.S.)	759
U.S. Midwest	708
U.S. Northeast	277
U.S. Southeast/ Gulf Coast (excluding Houston)	1,296
U.S. West Coast	75
Mexico	268
Total	6,779

CORPORATE RESTRUCTURING AND BUSINESS TRANSFORMATION

In mid-2015, we commenced a business restructuring and transformation initiative. While there is no change to our corporate strategy, we undertook this initiative to reduce overall costs and maximize the effectiveness and efficiency of our existing operations. For more information about our corporate restructuring and business transformation, refer to the Corporate – Corporate restructuring and business transformation section of the MD&A, which section of the MD&A is incorporated by reference herein.

HEALTH, SAFETY AND ENVIRONMENTAL PROTECTION AND SOCIAL POLICIES

The Health, Safety and Environment (HSE) committee of the Board oversees operational risk, people and process safety, security of personnel and environmental risks, and monitors compliance with our HSE programs through regular reporting from management. We use an integrated management system that establishes a framework for managing these risks and which is used to capture, organize, document, monitor and improve our related policies, programs and procedures.

Our management system is modeled after international standards, conforms to external industry consensus standards and voluntary programs, and complies with applicable legislative requirements. It follows a continuous improvement cycle organized into four key areas:

• planning – risk and regulatory assessment, objective and target setting, defining roles and responsibilities

• implementing – development and implementation of programs, procedures and standards to manage operational risk

• reporting – incident reporting and investigation, and performance monitoring

• action – assurance activities and review of performance by management.

The HSE committee reviews HSE performance and operational risk management. It receives detailed reports on:

• overall HSE corporate governance

• operational performance and preventative maintenance metrics

• asset integrity programs

• emergency preparedness, incident response and evaluation

• people and process safety performance metrics

• our Environment Program

• developments in and compliance with applicable legislation and regulations, including those related to the environment.

The HSE committee also receives updates on any specific areas of operational and construction risk management review being conducted by management and the results and corrective action plans flowing from internal and third party audits. Information about the financial and operational effects of environmental protection requirements on the capital expenditures, profit or loss and competitive position of TransCanada can be found in the MD&A in the Other information – Risks and Risk Management – Health, safety and environment section, which section of the MD&A is incorporated by reference herein. Generally, each year the committee or the committee Chair tours one of our existing assets or projects under development as part of its responsibility to monitor and review our HSE practices. Additionally, the Board and the committee have a joint site visit annually.

TransCanada Annual information form 2017 21

Health and Safety

As one of TransCanada's corporate values, safety is an integral part of the way our employees work. Each year we develop goals predicated on achieving year over year sustainable improvement in our safety performance, and meeting or exceeding industry benchmarks.

The safety of our employees, contractors and the public, as well as the integrity of our energy and pipeline infrastructure, is a top priority. All new assets are designed, constructed and commissioned with full consideration given to safety and integrity, and are brought in service only after all necessary requirements have been satisfied.

TransCanada annually conducts emergency response exercises to practice effective coordination between the Company, local emergency responders, regulatory agencies and government officials in the event of an emergency. TransCanada uses the Incident Command System which supports a unified approach to emergency response with these community members. TransCanada also provides annual training to all field staff in the form of table top exercises, online and vendor lead training.

Environmental risk, compliance and liabilities

We maintain an Environment Program to minimize potentially adverse environmental impacts, including risks related to climate change. This program identifies our requirements to proactively and systematically manage environmental hazards and risks throughout the lifecycle of our assets.

Our assets are subject to federal, state, provincial and local environmental statutes and regulations governing environmental protection, including, but not limited to, air and GHG emissions, water quality, species at risk, wastewater discharges and waste management. Operating our assets requires obtaining and complying with a wide variety of environmental registrations, licenses, permits and other approvals and requirements. Failure to comply could result in administrative, civil or criminal penalties, the imposition of remedial requirements and/or the issuance of orders respecting future operations.

Through the implementation of our Environment Program, we continually monitor our facilities to ensure compliance with all environmental requirements. We routinely monitor the proposed changes in environmental policy, legislation and regulation, and where the risks are uncertain or have the potential to affect our ability to effectively operate our business, we comment on proposals independently or through industry associations.

Social Policies

TransCanada has a number of policies, guiding principles and practices in place to help manage Indigenous and stakeholder relations. We have adopted a Code of Business Ethics (Code) which applies to all employees, officers and directors as well as contract workers of TransCanada and its wholly-owned subsidiaries and operated entities in countries where we conduct business. All employees (including executive officers) and directors must certify their compliance with the Code.

Our approach to Indigenous and stakeholder engagement is based on building relationships, mutual respect and trust while recognizing the unique values, needs and interests of each community. Our Stakeholder Engagement Commitment Statement provides the structure to guide our teams’ behavior and actions, so they understand their responsibility and extend respect, courtesy and the opportunity to respond to every stakeholder.

TransCanada’s Aboriginal Relations and Native American Relations Policies are guided by principles of trust, respect and responsibility. We work together with Indigenous groups to find mutually acceptable solutions and benefits. These Policies recognize the diversity and uniqueness of each Indigenous group, the importance of the land, and the imperative of building relationships based on mutual respect and trust.

TransCanada also has an Avoiding Bribery and Corruption Program which includes an Avoiding Bribery and Corruption Policy, annual online training provided to all personnel, face to face training provided to personnel in higher risk areas of our business, a supplier and contractor due diligence review process, and auditing of certain types of transactions.

We strive for continuous improvement in how we navigate the interconnections and complexity of environmental, social and economic issues related to our business. These issues are of great importance to our stakeholders and Indigenous groups, and have an impact on our ability to build and operate energy infrastructure.

TransCanada Annual information form 2017 22

Risk factors

A discussion of our risk factors can be found in the MD&A in the Natural Gas Pipelines business – Natural Gas Pipelines – Business risks, Liquids Pipelines – Business risks, Energy – Business risks and Other information – Risks and risk management sections, which sections of the MD&A are incorporated by reference herein.

Dividends

Our Board has not adopted a formal dividend policy.The Board reviews the financial performance of TransCanada quarterly and makes a determination of the appropriate level of dividends to be declared in the following quarter. Currently, our payment of dividends is primarily funded from dividends TransCanada receives as the sole common shareholder of TCPL. Provisions of various trust indentures and credit arrangements to which TCPL is a party restrict TCPL's ability to declare and pay dividends to TransCanada under certain circumstances and, if such restrictions apply, they may, in turn, have an impact on our ability to declare and pay dividends. Pursuant to the terms of the trust notes issued by TransCanada Trust (a financing trust subsidiary wholly owned by TCPL) and related agreements, in certain circumstances including where holders of the trust notes receive deferral preferred shares of TCPL in lieu of cash interest payments and where exchange preferred shares are issued to holders of the trust notes as a result of certain bankruptcy related events, TransCanada and TCPL would be prohibited from declaring or paying dividends on or redeeming their outstanding preferred shares (or, if none are outstanding, their respective common shares) until all such exchange or deferral preferred shares are redeemed by TCPL. Further information about such trust notes can be found in the Financial condition – Junior subordinated notes issued section of the MD&A, which section of the MD&A is incorporated by reference herein. In the opinion of TransCanada's management, such provisions do not currently restrict TransCanada's ability to declare or pay dividends.

Dividends on our preferred shares are payable quarterly, as and when declared by the Board. The dividends declared on our common and preferred shares during the past three completed financial years, and the increase to the quarterly dividend on our outstanding common shares per common share for the quarter ending March 31, 2018, are set out in the MD&A under the heading About our business – 2017 financial highlights – Dividends, which section of the MD&A is incorporated by reference herein.

Description of capital structure

SHARE CAPITAL

TransCanada’s authorized share capital consists of an unlimited number of common shares and an unlimited number of first preferred shares and second preferred shares, issuable in series. The number of common shares and preferred shares issued and outstanding as at Year End are set out in the MD&A in the Financial Condition – Share information section, which section of the MD&A is incorporated by reference herein. The following is a description of the material characteristics of each of these classes of shares.

Common shares

The common shares entitle the holders thereof to one vote per share at all meetings of shareholders, except meetings at which only holders of another specified class of shares are entitled to vote, and, subject to the rights, privileges, restrictions and conditions attaching to the first preferred shares and the second preferred shares, whether as a class or a series, and to any other class or series of shares of TransCanada which rank prior to the common shares, entitle the holders thereof to receive (i) dividends if, as and when declared by the Board out of the assets of TransCanada properly applicable to the payment of the dividends in such amount and payable at such times and at such place or places as the Board may from time to time determine, and (ii) the remaining property of TransCanada upon a dissolution.

We have a shareholder rights plan that is designed to ensure, to the extent possible, that all shareholders of TransCanada are treated fairly in connection with any take-over bid for the Company. The plan creates a right attaching to each common share outstanding and to each common share subsequently issued. Each right becomes exercisable ten trading days after a person has acquired (an acquiring person), or commences a take-over bid to acquire, 20 per cent or more of the common shares, other than by an acquisition pursuant to a take-over bid permitted under the terms of the plan (a permitted bid). Prior to a flip-in event (as described below), each right permits registered holders to purchase from the Company common shares of TransCanada at an exercise price equal to three times the market price of such shares, subject to adjustments and anti-dilution provisions (the exercise price). The beneficial acquisition by any person of 20 per cent or more of the common shares, other than by way of permitted bid,

TransCanada Annual information form 2017 23

is referred to as a flip-in event. Ten trading days after a flip-in event, each right will permit registered holders other than an acquiring person to receive, upon payment of the exercise price, the number of common shares with an aggregate market price equal to twice the exercise price.

TransCanada has a dividend reinvestment and share purchase plan (DRP) under which eligible holders of common and preferred shares of TransCanada can reinvest their dividends and make optional cash payments to obtain additional TransCanada common shares. Common shares are currently issued from treasury at a discount of two per cent to market prices rather than purchased on the open markets to satisfy participation in the DRP. Participants may also make additional cash payments of up to $10,000 per quarter to purchase additional common shares, which optional purchases are not eligible for any discount on the price of common shares. Participants are not responsible for payment of brokerage commissions or other transaction expenses for purchases made pursuant to the DRP.

TransCanada also has a stock based compensation plan that allows some employees to acquire common shares of TransCanada upon exercise of options granted thereunder. Option exercise prices are equal to the closing price on the Toronto Stock Exchange (TSX) on the last trading day immediately preceding the grant date. Options granted under the plan are generally fully exercisable after three years and expire seven years after the date of grant.

First preferred shares

Subject to certain limitations, the Board may, from time to time, issue first preferred shares in one or more series and determine for any such series, its designation, number of shares and respective rights, privileges, restrictions and conditions. The first preferred shares as a class have, among others, the provisions described below.

The first preferred shares of each series rank on a parity with the first preferred shares of every other series, and are entitled to preference over the common shares, the second preferred shares and any other shares ranking junior to the first preferred shares with respect to the payment of dividends, the repayment of capital and the distribution of assets of TransCanada in the event of its liquidation, dissolution or winding up.

Except as provided by the CBCA, the holders of the first preferred shares will not have any voting rights nor will they be entitled to receive notice of or to attend shareholders' meetings. The holders of any particular series of first preferred shares will, if the directors so determine prior to the issuance of such series, be entitled to such voting rights as may be determined by the directors if TransCanada fails to pay dividends on that series of preferred shares for any period as may be so determined by the directors.

The provisions attaching to the first preferred shares as a class may be modified, amended or varied only with the approval of the holders of the first preferred shares as a class. Any such approval to be given by the holders of the first preferred shares may be given by the affirmative vote of the holders of not less than sixty-six and two thirds per cent of the first preferred shares represented and voted at a meeting or adjourned meeting of such holders.

The holders of Series 1, 3, 5, 7, 9, 11, 13 and 15 preferred shares will be entitled to receive quarterly fixed rate cumulative preferential cash dividends, as and when declared by the Board, to be reset periodically on established dates to an annualized rate equal to the sum of the then five-year Government of Canada bond yield, calculated at the start of the applicable five-year period, and a spread as set forth in the table below (subject, in the case of the Series 13 and 15 preferred shares, to a fixed minimum reset rate of 5.50 per cent and 4.90 percent, respectively) and have the right to convert their shares into cumulative redeemable Series 2, 4, 6, 8, 10, 12, 14 and 16 preferred shares, respectively, subject to certain conditions, on such conversion dates as set forth in the table below. The Series 1, 3, 5, 7, 9, 11, 13 and 15 preferred shares are redeemable by TransCanada in whole or in part on such redemption dates as set forth in the table below, by the payment of an amount in cash for each share to be redeemed equal to $25.00 plus all accrued and unpaid dividends thereon.

The holders of Series 2, 4, 6, 8, 10, 12, 14 and 16 preferred shares will be entitled to receive quarterly floating rate cumulative preferential cash dividends, as and when declared by the Board, at an annualized rate equal to the sum of the then 90-day Government of Canada treasury bill rate, recalculated quarterly, and a spread as set forth in the table below and have the right to convert their shares into Series 1, 3, 5, 7, 9, 11, 13 and 15 preferred shares, respectively, subject to certain conditions, on such conversion dates as set forth in the table below. The Series 2, 4, 6, 8, 10, 12, 14 and 16 preferred shares are redeemable by TransCanada in whole or in part after their respective initial redemption date as set forth in the table below, by the payment of an amount in cash for each share to be redeemed equal to (i) $25.00 in the case of redemptions on such redemption dates as set out in the table below, or (ii) $25.50 in the case of redemptions on any other date, in each case plus all accrued and unpaid dividends thereon.

24 TransCanada Annual information form2017

In the event of liquidation, dissolution or winding up of TransCanada, the holders of Series 1, 2, 3, 4, 5, 6, 7, 8, 9, 10, 11, 12, 13, 14, 15 and 16 preferred shares shall be entitled to receive $25.00 per preferred share plus all accrued and unpaid dividends thereon in preference over the common shares or any other shares ranking junior to the first preferred shares.

Series of first preferred shares	Initial redemption date	Redemption/conversion dates	Spread (%)
Series 1 preferred shares	December 31, 2014	December 31, 2019 and every fifth year thereafter	1.92
Series 2 preferred shares	—	December 31, 2019 and every fifth year thereafter	1.92
Series 3 preferred shares	June 30, 2015	June 30, 2020 and every fifth year thereafter	1.28
Series 4 preferred shares	—	June 30, 2020 and every fifth year thereafter	1.28
Series 5 preferred shares	January 30, 2016	January 30, 2021 and every fifth year thereafter	1.54
Series 6 preferred shares	—	January 30, 2021 and every fifth year thereafter	1.54
Series 7 preferred shares	April 30, 2019	April 30, 2019 and every fifth year thereafter	2.38
Series 8 preferred shares	—	April 30, 2024 and every fifth year thereafter	2.38
Series 9 preferred shares	October 30, 2019	October 30, 2019 and every fifth year thereafter	2.35
Series 10 preferred shares	—	October 30, 2024 and every fifth year thereafter	2.35
Series 11 preferred shares	November 30, 2020	November 30, 2020 and every fifth year thereafter	2.96
Series 12 preferred shares	—	November 28, 2025 and every fifth year thereafter	2.96
Series 13 preferred shares	May 31, 2021	May 31, 2021 and every fifth year thereafter	4.69
Series 14 preferred shares	—	May 29, 2026 and every fifth year thereafter	4.69
Series 15 preferred shares	May 31, 2022	May 31, 2022 and every fifth year thereafter	3.85
Series 16 Preferred shares	—	May 31, 2027 and every fifth year thereafter	3.85

Except as provided by the CBCA, the respective holders of the first preferred shares of each outstanding series are not entitled to receive notice of, attend at, or vote at any meeting of shareholders unless and until TransCanada shall have failed to pay eight quarterly dividends on such series of preferred shares, whether or not consecutive, in which case the holders of the first preferred shares of such series shall have the right to receive notice of and to attend each meeting of shareholders at which directors are to be elected and which take place more than 60 days after the date on which the failure first occurs, and to one vote with respect to resolutions to elect directors for each of the first preferred share of such series, until all arrears of dividends have been paid. Subject to the CBCA, the series provisions attaching to the first preferred shares may be amended with the written approval of all the holders of such series of shares outstanding or by at least two thirds of the votes cast at a meeting of the holders of such shares duly called for the purpose and at which a quorum is present.

Second preferred shares

The rights, privileges, restrictions and conditions attaching to the second preferred shares are substantially identical to those attaching to the first preferred shares, except that the second preferred shares are junior to the first preferred shares with respect to the payment of dividends, repayment of capital and the distribution of assets of TransCanada in the event of a liquidation, dissolution or winding up of TransCanada.

TransCanada Annual information form 2017 25

Credit ratings

Although TransCanada Corporation has not issued debt to the public, it has been assigned credit ratings by Moody's Investors Service, Inc. (Moody's), S&P Global Ratings (S&P) and Fitch Ratings Inc. (Fitch), and its outstanding preferred shares have also been assigned credit ratings by S&P, Fitch and DBRS Limited (DBRS). Moody's has assigned an issuer rating of Baa1 with a stable outlook, S&P has assigned a long-term corporate credit rating of A- with a negative outlook, and Fitch has assigned a long-term corporate rating of A- with a stable outlook. TransCanada Corporation does not presently intend to issue debt securities to the public in its own name and any future debt financing requirements are expected to continue to be funded primarily through its subsidiary, TCPL, and TransCanada Trust, a wholly owned financing trust subsidiary of TCPL. The following table sets out the current credit ratings assigned to those outstanding classes of securities of the Company, TCPL and TransCanada Trust and our subsidiaries which have been rated by Moody's, S&P, Fitch and DBRS:

	Moody's	S&P	Fitch	DBRS
TCPL - Senior unsecured debt      Debentures      Medium-term notes	A3 A3	A- A-	A- A-	A (low) A (low)
TCPL - Junior subordinated notes	Baa1	BBB	BBB	BBB
TransCanada Trust - Subordinated trust notes	Baa2	BBB	BBB	Not rated
TransCanada Corporation - Preferred shares	Not Rated	P-2	BBB	Pfd-2 (low)
Commercial paper (U.S.) (TCPL and TCPL guaranteed)	P-2	A-2	F2	Not rated
Commercial paper (Canadian) (TCPL and TCPL guaranteed)	P-2	Not Rated	F2	R-1 (low)
Trend/ rating outlook	Stable	Negative	Stable	Stable

Credit ratings are intended to provide investors with an independent measure of credit quality of an issue of securities. Credit ratings are not recommendations to purchase, hold or sell securities and do not address the market price or suitability of a specific security for a particular investor. There is no assurance that any rating will remain in effect for any given period of time or that any rating will not be revised or withdrawn entirely by a rating agency in the future if, in its judgment, circumstances so warrant.

Each of the Company, TCPL, TransCanada Trust and subsidiaries paid fees to each of Moody's, S&P, Fitch and DBRS for the credit ratings rendered in respect of their outstanding classes of securities noted above. In addition to annual monitoring fees for the Company and TCPL and their rated securities, additional payments were made to Moody's, S&P and DBRS in respect of other services provided in connection with the acquisition of Columbia.

The information concerning our credit ratings relates to our financing costs, liquidity and operations. The availability of our funding options may be affected by certain factors, including the global capital markets environment and outlook as well as our financial performance. Our access to capital markets for required capital at competitive rates is influenced by our credit rating and rating outlook, as determined by credit rating agencies such as Moody's, S&P, Fitch and DBRS, and if our ratings were downgraded, TransCanada's financing costs and future debt issuances could be unfavourably impacted. A description of the rating agencies' credit ratings listed in the table above is set out below.

MOODY’S

Moody's has different rating scales for short- and long-term obligations. Numerical modifiers 1, 2 and 3 are appended to each rating classification from Aa through Caa. The modifier 1 indicates that the obligation ranks in the higher end of its generic rating category; the modifier 2 indicates a mid-range ranking; and a modifier 3 indicates a ranking in the lower end of that generic rating category. The A3 rating assigned to TCPL's senior unsecured debt is in the third highest of nine rating categories for long-term obligations. Obligations rated A are judged to be upper medium-grade and are subject to low credit risk. The P-2 rating assigned to TCPL's and TCPL guaranteed U.S. commercial paper programs is the second highest of four rating categories for short-term debt issuers. Issuers rated P-2 have a strong ability to repay short-term debt obligations. The Baa1 and Baa2 ratings assigned to TCPL's junior subordinated notes and to the TransCanada Trust subordinated trust notes, respectively, are in the fourth highest of nine rating categories for long-term obligations, with the junior subordinated notes ranking higher within the Baa rating category with a modifier of 1 as opposed to the modifier of 2 on the subordinated trust notes. Obligations rated Baa are judged to be medium-grade and are subject to moderate credit risk and, as such, may possess certain speculative characteristics.

26 TransCanada Annual information form2017

S&P

S&P has different rating scales for short- and long-term obligations. Ratings from AA through CCC may be modified by the addition of a plus (+) or minus (-) sign to show the relative standing within a particular rating category. The A- rating assigned to TCPL's senior unsecured debt is in the third highest of ten rating categories for long-term obligations. An A rating indicates the obligor's capacity to meet its financial commitment is strong; however, the obligation is somewhat more susceptible to the adverse effects of changes in circumstances and economic conditions than obligations in higher rated categories. TCPL's and TCPL guaranteed U.S. commercial paper programs are each rated A-2 which is the second highest of six rating categories for short-term debt issuers. Short-term debt issuers rated A-2 have satisfactory capacity to meet their financial commitments, however they are somewhat more susceptible to adverse effects of changes in circumstances and economic conditions than obligors in the higher rating categories. The BBB rating assigned to TCPL’s junior subordinated notes and to the TransCanada Trust subordinated trust notes is in the fourth highest of ten rating categories for long-term debt obligations. The P-2 rating assigned to TransCanada’s preferred shares is the second highest of eight rating categories for Canadian preferred shares. There is a direct correspondence between the specific ratings assigned on S&P's Canadian preferred share ratings scale and the global debt ratings scale. The BBB and P-2 ratings assigned to TCPL's junior subordinated notes, the TransCanada Trust subordinated trust notes and TransCanada's preferred shares exhibit adequate protection parameters; however, adverse economic conditions or changing circumstances are more likely to lead to a weakened capacity of the obligor to meet its financial commitment on the obligation.

FITCH

Fitch has different rating scales for short- and long-term obligations. Ratings from AA through D may be modified by the addition of a plus (+) or minus (-) sign to show the relative standing within a particular rating category. The A- rating assigned to TCPL's senior unsecured debt is in the third highest of ten rating categories for long-term obligations. An A rating indicates that expectations of default risk are low and that the obligor's capacity to meet its financial commitment is considered strong; however, the obligation is more vulnerable to the adverse effects of changes in circumstances and economic conditions than obligations in higher rated categories. The F2 rating assigned to TCPL's and TCPL guaranteed U.S. commercial paper programs is the second highest of seven rating categories for short-term debt issuers. Issuers rated F2 have good intrinsic capacity for timely payments of short-term debt obligations. The BBB rating assigned to TCPL's junior subordinated notes and to the TransCanada Trust subordinated trust notes is in the fourth highest of ten rating categories for long-term debt obligations. The BBB ratings assigned to TransCanada's preferred shares, TCPL's junior subordinated notes and the TransCanada Trust subordinated trust notes indicate that expectations of default risk are currently low and that the capacity for payment of financial commitments is considered adequate; however, adverse economic conditions or adverse business conditions are more likely to impair the capacity of the obligor to meet its financial commitment on the obligation.

DBRS

DBRS has different rating scales for short- and long-term debt and preferred shares. High or low grades are used to indicate the relative standing within all rating categories other than AAA and D and other than in respect of DBRS’ ratings of commercial paper and short-term debt, which utilize high, middle and low subcategories for its R-1 and R-2 rating categories. In respect of long-term debt and preferred share ratings, the absence of either a high or low designation indicates the rating is in the middle of the category. The R-1 (low) rating assigned to TCPL's and TCPL guaranteed short-term debt is in the third highest of ten rating categories and indicates good credit quality. The capacity for payment of short-term financial obligations as they fall due is substantial. The overall strength is not as favourable as higher rating categories. Short-term debt rated R-1 (low) may be vulnerable to future events, but qualifying negative factors are considered manageable. The A (low) rating assigned to TCPL's senior unsecured debt is in the third highest of ten categories for long-term debt. Long-term debt rated A is good credit quality. The capacity for the payment of financial obligations is substantial, but of lesser credit quality than that of AA rated securities. Long-term debt rated A may be vulnerable to future events but qualifying negative factors are considered manageable. The BBB rating assigned to junior subordinated notes is in the fourth highest of the ten categories for long-term debt. Long-term debt rated BBB is of adequate credit quality. The capacity for the payment of financial obligations is considered acceptable, but long-term debt rated BBB may be vulnerable to future events. The Pfd-2 (low) rating assigned to TransCanada's preferred shares is in the second highest of six rating categories for preferred shares. Preferred shares rated Pfd-2 are of satisfactory credit quality. Protection of dividends and principal is still substantial; however, earnings, the balance sheet and coverage ratios are not as strong as Pfd-1 rated companies. In general, Pfd-2 ratings correspond with companies whose long-term debt is rated in the A category.

TransCanada Annual information form 2017 27

Market for securities

TransCanada's common shares are listed on the TSX and the New York Stock Exchange (NYSE) under the symbol TRP. The following table sets out our preferred shares listed on the TSX.

Type	Issue Date	Stock Symbol
Series 1 preferred shares	September 30, 2009	TRP.PR.A
Series 2 preferred shares	December 31, 2014	TRP.PR.F
Series 3 preferred shares	March 11, 2010	TRP.PR.B
Series 4 preferred shares	June 30, 2015	TRP.PR.H
Series 5 preferred shares	June 29, 2010	TRP.PR.C
Series 6 preferred shares	February 1, 2016	TRP.PR.I
Series 7 preferred shares	March 4, 2013	TRP.PR.D
Series 9 preferred shares	January 20, 2014	TRP.PR.E
Series 11 preferred shares	March 2, 2015	TRP.PR.G
Series 13 preferred shares	April 20, 2016	TRP.PR.J
Series 15 preferred shares	November 21, 2016	TRP.PR.K

The following tables set out the reported monthly high, low, and month end closing trading prices and monthly trading volumes of the common shares of TransCanada on the TSX and the NYSE, and the respective Series 1, 2, 3, 4, 5, 6, 7, 9, 11, 13 and 15 preferred shares on the TSX, for the periods indicated:

COMMON SHARES

Month	TSX (TRP)				NYSE (TRP)
	High ($)	Low ($)	Close ($)	Volume traded	High (US$)	Low (US$)	Close (US$)	Volume traded
December 2017	$63.29	$60.61	$61.18	27,863,394	$49.26	$47.70	$48.64	16,561,792
November 2017	$65.18	$60.80	$61.88	33,552,507	$51.07	$47.38	$48.03	25,361,655
October 2017	$63.40	$59.23	$61.25	25,907,314	$50.65	$46.24	$47.48	19,148,833
September 2017	$63.42	$60.61	$61.67	30,997,671	$51.85	$49.14	$49.43	16,885,509
August 2017	$65.11	$61.59	$63.41	23,489,338	$51.77	$48.88	$50.80	16,106,392
July 2017	$64.81	$61.19	$63.70	25,912,413	$51.81	$47.06	$51.12	20,227,907
June 2017	$64.35	$61.32	$61.82	37,258,302	$48.49	$46.42	$47.67	41,976,981
May 2017	$64.69	$61.33	$62.71	31,563,490	$47.73	$45.07	$46.45	23,775,659
April 2017	$64.40	$60.78	$63.38	28,179,483	$48.20	$45.38	$46.44	15,720,604
March 2017	$62.80	$60.54	$61.37	43,585,590	$47.02	$45.16	$46.15	23,525,317
February 2017	$62.88	$60.35	$61.06	34,410,621	$48.29	$45.75	$45.99	18,004,202
January 2017	$65.24	$60.28	$61.39	30,801,086	$49.77	$44.90	$47.22	22,301,648

TransCanada Corporation ATM Issuance Program

In June 2017, we established an at-the-market (ATM) distribution program that allows us to issue common shares from treasury from time to time, at the prevailing market price, when sold through the TSX, the NYSE, or any other existing trading market for TransCanada common shares in Canada or the U.S. The ATM program, which is effective for a 25-month period, will be utilized as appropriate to manage our capital structure over time. Further information about the ATM program can be found in the Financial condition – TransCanada Corporation ATM issuance program section of the MD&A, which section of the MD&A is incorporated by reference herein.

28 TransCanada Annual information form2017

PREFERRED SHARES

Month	Preferred Shares
	Series 1	Series 2	Series 3	Series 4	Series 5	Series 6	Series 7	Series 9	Series 11	Series 13	Series 15
December 2017 High Low Close Volume traded	$ 20.40 $ 19.48 $ 20.11 107,740	$ 19.75 $ 18.69 $ 19.72 95,907	$ 16.43 $ 15.70 $ 16.43 92,605	$ 16.09 $ 15.23 $ 15.61 91,082	$ 17.45 $ 16.57 $ 17.20 160,152	$ 17.43 $ 16.64 $ 16.90 63,363	$ 23.04 $ 22.15 $ 22.65 205,651	$ 23.73 $ 22.50 $ 23.46 137,985	$ 24.50 $ 23.85 $ 24.50 116,915	$ 26.75 $ 26.27 $ 26.66 594,841	$ 26.21 $ 25.75 $ 26.15 296,027
November 2017 High Low Close Volume traded	$ 20.92 $ 20.13 $ 20.56 69,727	$ 20.20 $ 19.50 $ 19.77 87,507	$ 16.60 $ 16.19 $ 16.30 63,309	$ 16.30 $ 15.64 $ 15.82 39,835	$ 17.57 $ 16.90 $ 17.53 196,487	$ 17.45 $ 16.86 $ 17.35 37,104	$ 23.15 $ 22.75 $ 22.99 295,310	$ 23.34 $ 22.76 $ 23.30 532,773	$ 24.80 $ 23.94 $ 24.35 123,619	$ 27.05 $ 26.59 $ 26.63 817,319	$ 26.65 $ 26.16 $ 26.22 711,368
October 2017 High Low Close Volume traded	$ 20.44 $ 20.00 $ 20.43 110,739	$ 20.49 $ 19.70 $ 20.09 216,388	$ 16.66 $ 15.80 $ 16.49 114,783	$ 16.50 $ 15.40 $ 15.80 42,806	$ 17.40 $ 16.75 $ 17.20 552,356	$ 17.37 $ 16.49 $ 17.00 24,562	$ 23.19 $ 22.01 $ 23.00 210,297	$ 23.25 $ 22.34 $ 23.23 189,813	$ 24.57 $ 23.95 $ 24.04 174,291	$ 26.90 $ 26.60 $ 26.72 915,285	$ 26.15 $ 25.94 $ 26.15 1,109,588
September 2017 High Low Close Volume traded	$ 20.21 $ 19.02 $ 20.01 113,495	$ 20.25 $ 19.28 $ 20.05 52,001	$ 16.01 $ 15.00 $ 15.93 308,974	$ 15.80 $ 15.00 $ 15.50 29,751	$ 16.89 $ 16.01 $ 16.81 391,934	$ 16.75 $ 16.40 $ 16.58 6,989	$ 22.52 $ 21.75 $ 22.19 326,801	$ 22.55 $ 22.03 $ 22.35 421,503	$ 24.34 $ 23.72 $ 24.00 348,017	$ 26.79 $ 26.35 $ 26.56 632,004	$ 26.10 $ 25.70 $ 25.95 836,498
August 2017 High Low Close Volume traded	$ 20.36 $ 19.09 $ 19.50 108,599	$ 20.50 $ 19.28 $ 19.39 42,106	$ 15.97 $ 15.05 $ 15.19 39,245	$ 15.84 $ 15.00 $ 15.05 41,059	$ 17.16 $ 16.19 $ 16.44 107,413	$ 17.05 $ 16.24 $ 16.50 18,991	$ 22.85 $ 21.40 $ 22.39 445,621	$ 23.31 $ 21.66 $ 22.40 185,971	$ 24.89 $ 23.56 $ 23.81 77,702	$ 27.07 $ 26.50 $ 26.78 838,430	$ 26.25 $ 24.74 $ 25.99 791,083
July 2017 High Low Close Volume traded	$ 20.60 $ 19.32 $ 20.36 388,352	$ 20.75 $ 19.15 $ 20.70 60,358	$ 15.98 $ 14.87 $ 15.92 169,375	$ 15.68 $ 14.42 $ 15.68 23,750	$ 17.22 $ 15.99 $ 17.13 162,582	$ 17.22 $ 15.60 $ 17.03 12,217	$ 22.87 $ 22.10 $ 22.73 1,054,905	$ 23.25 $ 22.36 $ 23.20 212,533	$ 24.97 $ 24.06 $ 24.85 70,480	$ 27.19 $ 26.75 $ 26.94 721,215	$ 26.28 $ 25.86 $ 26.22 498,610
June 2017 High Low Close Volume traded	$ 19.49 $ 17.81 $ 19.49 300,355	$ 19.30 $ 17.69 $ 19.17 176,734	$ 15.00 $ 13.86 $ 14.96 167,884	$ 14.52 $ 13.20 $ 14.44 69,863	$ 16.22 $ 14.98 $ 16.06 161,550	$ 15.84 $ 14.83 $ 15.60 51,256	$ 22.27 $ 20.00 $ 22.17 559,961	$ 22.49 $ 20.25 $ 22.40 370,252	$ 24.50 $ 22.50 $ 24.42 112,731	$ 27.23 $ 26.51 $ 26.99 354,415	$ 26.40 $ 25.85 $ 26.21 498,096
May 2017 High Low Close Volume traded	$ 19.19 $ 18.32 $ 18.33 77,511	$ 19.24 $ 18.18 $ 18.41 173,915	$ 14.87 $ 14.14 $ 14.36 127,101	$ 14.10 $ 13.43 $ 13.43 62,880	$ 15.85 $ 15.34 $ 15.69 134,603	$ 15.50 $ 15.00 $ 15.01 40,390	$ 21.70 $ 20.51 $ 20.60 466,568	$ 22.19 $ 20.85 $ 22.86 171,850	$ 23.69 $ 22.51 $ 22.80 275,647	$ 27.33 $ 26.65 $ 26.75 270,212	$ 26.30 $ 25.81 $ 26.08 628,148
April 2017 High Low Close Volume traded	$ 19.87 $ 19.06 $ 19.07 291,423	$ 19.44 $ 18.68 $ 18.89 341,202	$ 15.08 $ 14.40 $ 14.41 319,778	$ 14.37 $ 13.70 $ 13.80 163,112	$ 16.57 $ 15.55 $ 15.60 145,831	$ 15.55 $ 15.27 $ 15.39 8,965	$ 22.49 $ 21.43 $ 21.55 369,494	$ 22.85 $ 21.94 $ 22.10 449,997	$ 24.34 $ 23.65 $ 23.65 146,307	$ 27.42 $ 26.62 $ 27.28 181,851	$ 26.48 $ 25.92 $ 26.27 1,103,086
March 2017 High Low Close Volume traded	$ 19.65 $ 18.30 $ 19.40 276,109	$ 19.04 $ 17.54 $ 18.90 294,227	$ 15.17 $ 14.30 $ 14.67 218,414	$ 13.78 $ 12.99 $ 13.72 76,900	$ 16.25 $ 15.59 $ 15.92 156,735	$ 15.54 $ 14.50 $ 15.54 5,348	$ 22.40 $ 21.70 $ 22.37 304,622	$ 23.16 $ 22.35 $ 22.58 455,353	$ 23.92 $ 22.86 $ 23.90 98,207	$ 26.77 $ 26.37 $ 26.71 527,184	$ 26.18 $ 25.61 $ 26.00 1,048,057
February 2017 High Low Close Volume traded	$ 18.99 $ 17.59 $ 18.32 139,957	$ 18.13 $ 16.50 $ 17.84 97,323	$ 14.99 $ 14.00 $ 14.48 205,242	$ 13.47 $ 12.60 $ 13.10 140,335	$ 16.31 $ 15.19 $ 16.00 152,188	$ 15.39 $ 14.75 $ 14.75 3,163	$ 22.37 $ 20.36 $ 22.01 249,246	$ 23.10 $ 21.30 $ 22.74 275,553	$ 23.94 $ 22.74 $ 23.05 247,326	$ 26.64 $ 26.37 $ 26.48 234,969	$ 25.90 $ 25.46 $ 25.73 1,750,501
January 2017 High Low Close Volume traded	$ 17.82 $ 15.78 $ 17.61 234,433	$ 17.25 $ 15.02 $ 16.81 108,774	$ 14.60 $ 13.19 $ 14.35 304,127	$ 13.40 $ 11.96 $ 13.11 68,818	$ 15.54 $ 13.78 $ 15.29 301,751	$ 14.76 $ 13.10 $ 14.76 12,495	$ 20.75 $ 18.62 $ 20.42 1,226,439	$ 21.51 $ 19.51 $ 21.39 806,021	$ 23.52 $ 22.01 $ 22.80 132,391	$ 26.85 $ 26.28 $ 26.60 529,655	$ 25.92 $ 25.32 $ 25.45 4,283,769

TransCanada Annual information form 2017 29

Directors and officers

As of February 14, 2018, the directors and officers of TransCanada as a group beneficially owned, or exercised control or direction over, directly or indirectly, an aggregate of 588,310 common shares of TransCanada. This constitutes less than one per cent of TransCanada's common shares. The Company collects this information from our directors and officers but otherwise we have no direct knowledge of individual holdings of TransCanada's securities.

DIRECTORS

The following table sets forth the names of the directors who serve on the Board as of February 14, 2018 (unless otherwise indicated), together with their jurisdictions of residence, all positions and offices held by them with TransCanada, their principal occupations or employment during the past five years and the year from which each director has continually served as a director of TransCanada and, prior to the Arrangement, with TCPL. Positions and offices held with TransCanada are also held by such person at TCPL. Each director holds office until the next annual meeting or until his or her successor is earlier elected or appointed.

Name and place of residence	Principal occupation during the five preceding years	Director since
Kevin E. Benson Heritage Point, Alberta Canada	Corporate director. Director, Winter Sport Institute (non-profit) since February 2015. Director, Calgary Airport Authority from January 2010 to December 2013.	2005
Derek H. Burney, O.C. Ottawa, Ontario Canada	Senior strategic advisor, Norton Rose Fulbright (law firm). Chairman, GardaWorld International Advisory Board (risk management and security services) since April 2008. Advisory Board member, Paradigm Capital Inc. (investment dealer) since May 2011. Director (Chair), Liquor Stores N.A. Ltd. since June 2017.	2005
Stéphan Crétier Dubai, United Arab Emirates	Chairman, President and Chief Executive Officer of Garda World Security Corporation (Garda World) (private security services) and director of a number of Garda World’s direct and indirect subsidiaries, since 1999. Director, ORTHOsoft Inc. (formerly ORTHOsoft Holdings Inc.) (medical software technology) from August 2004 to November 2004. Director, BioEnvelop Technologies Corp. (manufacturing) from 2001 to 2003. Director, President and Chief Executive Officer, Rafale Capital Corp. (manufacturing) from 1999 to 2001.	2017
Russell K. Girling1 Calgary, Alberta Canada	President and Chief Executive Officer, TransCanada since July 2010. Chief Operating Officer from July 2009 to June 2010, and President, Pipelines from June 2006 to June 2010. Director, American Petroleum Institute since January 2015. Director, Nutrien Ltd. (formerly Agrium Inc.) (agriculture) since May 2006.	2010
S. Barry Jackson Calgary, Alberta Canada	Corporate director. Director, WestJet Airlines Ltd. (airline) since February 2009. Director, Laricina Energy Ltd. (oil and gas, exploration and production) from December 2005 to November 2017. Director, Nexen Inc. (Nexen) (oil and gas, exploration and production) from 2001 to June 2013, and Chair of the Board, Nexen from 2012 to June 2013.	2002
John E. Lowe Houston, Texas U.S.A.	Non-executive Chairman of the Board, Apache Corporation (Apache) (oil and gas) since May 2015. Director, Phillips 66 Company (energy infrastructure) since May 2012. Director, Apache since July 2013. Senior Executive Adviser at Tudor, Pickering, Holt & Co. LLC (energy investment and merchant banking) since September 2012.	2015
Paula Rosput Reynolds Seattle, Washington U.S.A.	President and Chief Executive Officer, PreferWest, LLC (business advisory group) since October 2009. Director, CBRE Group, Inc. (commercial real estate) since March 2016. Director, BP p.l.c. (oil and gas) since May 2015. Director, BAE Systems plc. (aerospace, defence, information security) since April 2011. Director, Siluria Technologies Inc. (natural gas) from February 2015 to June 2017. Director, Delta Air Lines, Inc. (airline) from August 2004 to June 2015. Director, Anadarko Petroleum Corporation (oil and gas, exploration and production) from August 2007 to May 2014.	2011
Mary Pat Salomone Naples, Florida U.S.A.	Corporate director. Director, Herc Rentals (equipment rental) since July 2016. Director, Intertape Polymer Group (manufacturing) since November 2015. Senior Vice-President and Chief Operating Officer, The Babcock & Wilcox Company (energy infrastructure) from January 2010 to June 2013. Director, United States Enrichment Corporation (basic materials, nuclear) from December 2011 to October 2012.	2013
Indira Samarasekera Vancouver, British Columbia Canada	Senior Advisor, Bennett Jones LLP (law firm) since September 2015. Director, Magna International Inc. (automotive manufacturing) since May 2014 and the Bank of Nova Scotia (Scotiabank) (chartered bank) since May 2008. Member, selection panel for Canada's outstanding chief executive officer. Member, The TriLateral Commission since August 2016.	2016
D. Michael G. Stewart Calgary, Alberta Canada	Corporate director. Director, Pengrowth Energy Corporation (oil and gas, exploration and production) since December 2010. Director, CES Energy Solutions Corp. (oilfield services) since January 2010. Director, Northpoint Resources Ltd. (oil and gas, exploration and production) from July 2013 to February 2015. Director, C&C Energia Ltd. (oil and gas) from May 2010 to December 2012.	2006

30 TransCanada Annual information form2017

Name and place of residence	Principal occupation during the five preceding years	Director since
Siim A. Vanaselja Toronto, Ontario Canada	Corporate director. Chair of the Board, TransCanada since May 2017. Director, RioCan Real Estate Investment Trust (real estate) since May 2017. Director, Great-West Lifeco Inc. (financial services) since May 2014. Director, Maple Leaf Sports and Entertainment Ltd. (sports, property management) from August 2012 to June 2017. Executive Vice-President and Chief Financial Officer, BCE Inc. and Bell Canada (telecommunications and media) from January 2001 to June 2015.	2014
Thierry Vandal Mamaroneck, New York U.S.A.	President, Axium Infrastructure US, Inc. (independent infrastructure fund management firm) and Director, Axium infrastucture Inc. since 2015. Director, Royal Bank of Canada (chartered bank) since 2015. Member, International Advisory Board of École des Hautes Etudes Commerciales Montréal from 2006 to October 2017.	20172
Richard E. Waugh Calgary, Alberta Canada	Corporate director. Advisor, Acasta Enterprises Inc. (asset management/investment) since June 2015. President and Chief Executive Officer, Scotiabank from March 2003 to November 2013 and Deputy Chairman from November 2013 to January 2014. Director, Catalyst Inc. (non-profit) from February 2007 to November 2013 and Chair, Canadian Advisory Board, Catalyst Canada Inc. from February 2007 to October 2013.	2012

Notes:

(1) As President and CEO of TransCanada, Mr. Girling is not a member of any Board Committees, but is invited to attend committee meetings as required.

(2) Effective November 6, 2017.

Cease Trade Orders, Bankruptcies, Penalties or Sanctions

Except as indicated below, no other director or executive officer of the Corporation is or was a director, chief executive officer or chief financial officer of another company in the past ten years that:

• was the subject of a cease trade or similar order, or an order denying that company any exemption under securities legislation, that was in effect for a period of more than 30 consecutive days

• was involved in an event that resulted in the company being subject to one of the above orders after the director or executive officer no longer held that role with the company, which resulted from an event that occurred while that person was acting in the capacity as director, chief executive officer or chief financial officer

• while acting in that capacity, or within a year of acting in that capacity, became bankrupt, made a proposal under any legislation relating to bankruptcy or insolvency or was subject to or instituted any proceedings, arrangement or compromise with creditors or had a receiver, receiver manager or trustee appointed to hold the assets of that company.

Canwest Global Communications Corp. voluntarily entered into the Companies’ Creditors Arrangement Act (CCAA) and obtained an order from the Ontario Superior Court of Justice to start proceedings on October 6, 2009. Although no cease trade orders were issued, Canwest shares were de-listed by the TSX after the filing and started trading on the TSX Venture Exchange. Canwest emerged from CCAA protection and Postmedia Network acquired its newspaper business on July 13, 2010 while Shaw Communications Inc. acquired its broadcast media business on October 27, 2010. Mr. Burney was a director of Canwest from April 2005 to October 2010.

Laricina Energy (Laricina) voluntarily entered into the CCAA and obtained an order from the Court of Queen's Bench of Alberta, Judicial Centre of Calgary for creditor protection and stay of proceedings effective March 26, 2015. A final court order was granted on January 28, 2016, allowing Laricina to exit from protection under the CCAA and concluding the stay of proceedings against Laricina and its subsidiaries. Mr. Jackson was a director of Laricina from December 2005 to November 2017.

On May 6, 2009, Crucible Materials Corp. (Crucible) and one of its affiliates filed voluntary petitions for relief under Chapter 11 of the U.S. Bankruptcy Code in the U.S. Bankruptcy Court for the District of Delaware (the Bankruptcy Court). On August 26, 2010, the Bankruptcy Court entered an order confirming Crucible’s Second Amended Chapter 11 Plan of Liquidation. Ms. Salomone was a director of Crucible from May 2008 to May 1, 2009.

No director or executive officer of the Corporation has within the past ten years:

• become bankrupt

• made a proposal under any legislation relating to bankruptcy or insolvency

• become subject to or launched any proceedings, arrangement or compromise with any creditors, or

• had a receiver, receiver manager or trustee appointed to hold any of their assets.

TransCanada Annual information form 2017 31

No director or executive officer of the Corporation has been subject to:

• any penalties or sanctions imposed by a court relating to securities legislation or by a securities regulatory authority or has entered into a settlement agreement with a securities regulatory authority, or

• any other penalties or sanctions imposed by a court or regulatory body that would likely be considered important to a reasonable investor in making an investment decision.

BOARD COMMITTEES

TransCanada has four committees of the Board: the Audit committee, the Governance committee, the Health, Safety and Environment committee and the Human Resources committee. The voting members of each of these committees, as of February 14, 2018 (unless otherwise indicated), are identified below. Information about the Audit committee can be found in this AIF under the heading Audit committee.

Director	Audit committee	Governance committee	Health, Safety & Environment committee	Human Resources committee
Kevin E. Benson	ü	Chair
Derek H. Burney	ü	ü
Stéphan Crétier	ü		ü
S. Barry Jackson		ü		ü
John E. Lowe	Chair		ü
Paula Rosput Reynolds		ü		Chair
Mary Pat Salomone			ü	ü
Indira Samarasekera	ü	ü
D. Michael G. Stewart	ü		Chair
Siim A. Vanaselja (Chair)		ü		ü
Thierry Vandal	ü		ü
Richard E. Waugh			ü	ü

32 TransCanada Annual information form2017

OFFICERS

With the exception of Stanley G. Chapman, III, all of the executive officers and corporate officers of TransCanada reside in Calgary, Alberta, Canada. Positions and offices held with TransCanada are also held by such person at TCPL. As of the date hereof, the officers of TransCanada, their present positions within TransCanada and their principal occupations during the five preceding years are as follows:

Executive officers

Name	Present position held	Principal occupation during the five preceding years
Russell K. Girling	President and Chief Executive Officer	President and Chief Executive Officer.
Stanley G. Chapman, III	Executive Vice-President and President, U.S. Natural Gas Pipelines	Prior to April 2017, Senior Vice-President and General Manager, U.S. Natural Gas Pipelines. Prior to July 2016 Executive Vice-President and Chief Commercial Officer of Columbia Pipeline Group, Inc.
Kristine L. Delkus	Executive Vice-President, Stakeholder Relations and Technical Services and General Counsel	Prior to April 2017, Executive Vice-President, Stakeholder Relations and General Counsel. Prior to October 2015, Executive Vice-President, General Counsel and Chief Compliance Officer. Prior to March 2014, Senior Vice-President, Pipelines Law and Regulatory Affairs (TCPL).
Wendy L. Hanrahan	Executive Vice-President, Corporate Services	Executive Vice-President, Corporate Services.
Karl R. Johannson	Executive Vice-President and President, Canada and Mexico Natural Gas Pipelines and Energy	Prior to April 2017, Executive Vice-President, Natural Gas Pipelines.
Donald R. Marchand	Executive Vice-President and Chief Financial Officer	Prior to February 1, 2017, Executive Vice-President, Corporate Development and Chief Financial Officer. Prior to October 2015, Executive Vice-President and Chief Financial Officer.
Paul E. Miller	Executive Vice-President and President, Liquids Pipelines	Prior to March 2014, Senior Vice-President, Oil Pipelines.
Dean C. Patry	Senior Vice-President, Liquids Pipelines	Prior to November 2017, Senior Vice-President, Liquids Pipelines (TCPL). Prior to February 2017, Senior Vice-President, Business Transformation (TCPL). Prior to October 2015, Vice-President, Major Projects Development (TCPL). Prior to July 2014, Vice-President, U.S. Natural Gas Pipelines Central (TCPL). Prior to March 2014, Vice-President, U.S. Pipelines Central (TCPL).
Francois L. Poirier	Executive Vice-President, Strategy and Corporate Development	Prior to February 1, 2017, Senior Vice-President, Strategy and Corporate Development. Prior to October 2015, President, Energy East Pipeline. Prior to September 2015, President, Wells Fargo Securities Canada, Ltd.
Tracy A. Robinson	Senior Vice-President, Canadian Natural Gas Pipelines	Prior to November 2017, Senior Vice-President, Canada, Natural Gas Pipelines Division, Canada (TCPL). Prior to April 2017, Senior Vice-President, Canada, Natural Gas Pipelines Division (TCPL). Prior to March 2017, Vice-President, Supply Chain (TCPL). Prior to October 2015, Vice-President, Transportation, Liquids Pipelines Division (TCPL). Prior to September 2014, Vice-President, Marketing and Sales, Canadian Pacific Railway Limited.

Corporate officers

Name	Present position held	Principal occupation during the five preceding years
Sean M. Brett	Vice-President, Risk Management	Prior to August 2015, Vice-President and Treasurer.
Dennis P. Hebert	Vice-President, Taxation	Prior to June 2017, Vice-President, Tax and Insurance, Spectra Energy (Spectra). Prior to June 2014, General Manager, Tax (Spectra).
R. Ian Hendy	Vice-President and Treasurer	Prior to December 2017, Director, Financial Trading and Assistant Treasurer (TCPL).
Joel E. Hunter	Senior Vice-President, Capital Markets	Prior to December 2017, Vice-President, Finance and Treasurer. Prior to August 2015, Vice-President, Finance.
Christine R. Johnston	Vice-President, Law and Corporate Secretary	Prior to June 2014, Vice-President and Corporate Secretary. Prior to March 2012, Vice-President, Finance Law.
G. Glenn Menuz	Vice-President and Controller	Vice-President and Controller.

TransCanada Annual information form 2017 33

CONFLICTS OF INTEREST

Directors and officers of TransCanada and its subsidiaries are required to disclose any existing or potential conflicts in accordance with TransCanada policies governing directors and officers and in accordance with the CBCA. The Code covers potential conflicts of interest.

Serving on other boards

The Board believes that it is important for it to be composed of qualified and knowledgeable directors. As a result, due to the specialized nature of the energy infrastructure business, some of our directors are associated with or sit on the boards of companies that ship natural gas or liquids through our pipeline systems. Transmission services on most of TransCanada’s pipeline systems in Canada and the U.S. are subject to regulation and accordingly we generally cannot deny transportation services to a creditworthy shipper. The Governance committee monitors relationships among directors to ensure that business associations do not affect the Board’s performance.

The Board considers whether directors serving on the boards of other entities including public and private companies, Crown corporations and other state-owned entities, and non-profit organizations pose any potential conflict. The Board reviews these relationships annually to determine that they do not interfere with any of our director’s ability to act in our best interests. If a director declares a material interest in any material contract or material transaction being considered at the meeting, the director is not present during the discussion and does not vote on the matter.

Our Code requires employees to receive consent before accepting a directorship with an entity that is not an affiliate. The chief executive officer and executive vice-presidents (our executive leadership team) must receive the consent of the Governance committee. All other employees must receive the consent of the Corporate Secretary or her delegate.

Affiliates

The Board oversees relationships between TransCanada and any affiliates to avoid any potential conflicts of interest. This includes our relationship with TCLP, a master limited partnership listed on the NYSE.

Corporate governance

Our Board and management are committed to the highest standards of ethical conduct and corporate governance.

TransCanada is a public company listed on the TSX and the NYSE, and we recognize and respect rules and regulations in both Canada and the U.S.

Our corporate governance practices comply with the Canadian governance guidelines, which include the governance rules of the TSX and Canadian Securities Administrators:

• National Instrument 52-110, Audit Committees

• National Policy 58-201, Corporate Governance Guidelines, and

• National Instrument 58-101, Disclosure of Corporate Governance Practices.

We also comply with the governance listing standards of the NYSE and the governance rules of the SEC that apply, in each case, to foreign private issuers.

Our governance practices comply with the NYSE standards for U.S. companies in all significant respects, except as summarized on our website (www.transcanada.com). As a non-U.S. company, we are not required to comply with most of the governance listing standards of the NYSE. As a foreign private issuer, however, we must disclose how our governance practices differ from those followed by U.S. companies that are subject to the NYSE standards.

We benchmark our policies and procedures against major North American companies to assess our standards and we adopt best practices as appropriate. Some of our best practices are derived from the NYSE rules and comply with applicable rules adopted by the SEC to meet the requirements of the Sarbanes-Oxley Act of 2002 and the Dodd-Frank Wall Street Reform and Consumer Protection Act.

34 TransCanada Annual information form2017

Audit committee

The Audit committee is responsible for assisting the Board in overseeing the integrity of our financial statements and our compliance with legal and regulatory requirements. It is also responsible for overseeing and monitoring the internal accounting and reporting process and the process, performance and independence of our internal and external auditors. The charter of the Audit committee can be found in Schedule B of this AIF.

RELEVANT EDUCATION AND EXPERIENCE OF MEMBERS

The members of the Audit committee as of February 14, 2018 are John E. Lowe (Chair), Kevin E. Benson, Derek H. Burney, Stéphan Crétier, Indira Samarasekera, D. Michael G. Stewart and Thierry Vandal. Mr. Vandal joined the committee effective November 8, 2017.

The Board believes that the composition of the Audit committee reflects a high level of financial literacy and expertise. Each member of the Audit committee has been determined by the Board to be independent and financially literate within the meaning of the definitions under Canadian and U.S. securities laws and the NYSE rules. In addition, the Board has determined that Mr. Lowe, Mr. Benson and Mr. Vandal are Audit Committee Financial Experts as that term is defined under U.S. securities laws. The Board has made these determinations based on the education and breadth and depth of experience of each member of the Audit committee. The following is a description of the education and experience, apart from their respective roles as directors of TransCanada, of each member of the Audit committee that is relevant to the performance of his responsibilities as a member of the Audit committee.

John E. Lowe (Chair)

Mr. Lowe holds a Bachelor of Science degree in Finance and Accounting from Pittsburg State University and is a Certified Public Accountant (inactive). He has been the non-executive Chairman of Apache Corporation's board of directors since May 2015. He also currently serves on the board of directors for Phillips 66 Company and has been the Senior Executive Adviser at Tudor, Pickering, Holt & Co. LLC since September 2012. Mr. Lowe has previously served on the audit committees for Agrium Inc. and DCP Midstream LLC. He has also held various executive and management positions with ConocoPhillps for more than 25 years.

Kevin E. Benson

Mr. Benson is a Chartered Accountant (South Africa) and was a member of the South African Society of Chartered Accountants. He serves as a director of the Winter Sport Institute, and was the President and Chief Executive Officer of Laidlaw International, Inc. until October 2007. In prior years, he has held several executive positions including as President and Chief Executive Officer of The Insurance Corporation of British Columbia and has served on other public company boards and on the audit committees of all of those boards.

Derek H. Burney

Mr. Burney earned a Bachelor of Arts (Honours) and Master of Arts from Queen’s University. He is currently a senior strategic advisor at Norton Rose Fulbright. He has also been the Chairman of GardaWorld's International Advisory Board since April 2008, a member of the Paradigm Capital Inc. Advisory Board since May 2011, and has served as Chair of the board of directors of Liquor Stores N.A. Ltd. since June 2017. He previously served as President and Chief Executive Officer of CAE Inc. and as Chair and Chief Executive Officer of Bell Canada International Inc. Mr. Burney was the lead director at Shell Canada Limited from April 2001 until May 2007 and was the Chair of Canwest Global Communications Corp. from August 2006 until October 2010. He has served on one other organization’s audit committee and has participated in Financial Reporting Standards Training offered by KPMG.

Stéphan Crétier

Mr. Crétier earned a Master of Business Administration from the University of California (Pacific). He is the Chairman, President and CEO of a multinational corporation, Garda World, with over 20 years of experience in providing company-wide operational and financial oversight. Mr. Crétier also serves as director of a number of Garda World’s direct and indirect subsidiaries. He previously served as a director of three public companies, ORTHOsoft Inc. (formerly ORTHOsoft Holdings Inc.), BioEnvelop Technologies Corp. and Rafale Capital Corp.

Indira Samarasekera

Dr. Samarasekera earned a Master of Science from the University of California and was granted a PhD in metallurgical engineering from the University of British Columbia. She also holds honorary degrees from the Universities of Alberta, British Columbia, Toronto, Waterloo, Montreal and Western in Canada and Queen’s University in Belfast, Ireland. Dr. Samaraskera is currently a senior advisor for Bennett Jones LLP and serves on the board of directors of the Bank of Nova Scotia, Magna International Inc.,

TransCanada Annual information form 2017 35

Asia-Pacific Foundation, and the Rideau Hall Foundation. She is also a member of the TriLateral Commission and sits on the selection panel for Canada's outstanding chief executive officer of the year.

D. Michael G. Stewart

Mr. Stewart earned a Bachelor of Science in Geological Sciences with First Class Honours from Queen’s University. He currently serves on the board of directors of Pengrowth Energy Corporation and CES Energy Solutions Corp. He has also previously served on the board of directors of several other public companies and organizations and was on the audit committee and the Chair of the audit committee of certain of those boards. Mr. Stewart held a number of senior executive positions with Westcoast Energy Inc. including Executive Vice-President, Business Development. He has been active in the Canadian energy industry for over 40 years.

Thierry Vandal

Mr. Vandal earned a Masters of Business Administration in Finance from the École des Hautes Etudes Commerciales Montréal. He is the President of Axium Infrastructure US, Inc. and serves on the board of directors for Axium Infrastructure Inc. and on the international advisory board of École des Hautes Études Commerciale Montréal. He also serves on the board of directors for the Royal Bank of Canada (RBC) where he is designated as RBC’s audit committee’s financial expert. Mr. Vandal previously served on the audit committee for Veresen Inc. until July 2017 and has over nine years’ experience of serving with Hydro-Québec where he also held the position of President and Chief Executive Officer until May 2015.

PRE-APPROVAL POLICIES AND PROCEDURES

TransCanada's Audit committee has adopted a pre-approval policy with respect to permitted non-audit services. Under the policy, the Audit committee has granted pre-approval for specified non-audit services. For engagements of up to $250,000, approval of the Audit committee Chair is required, and the Audit committee is to be informed of the engagement at the next scheduled Audit committee meeting. For all engagements of $250,000 or more, pre-approval of the Audit committee is required. In all cases, regardless of the dollar amount involved, where there is a potential for conflict of interest involving the external auditor to arise on an engagement, the Audit committee must pre-approve the assignment.

To date, all non-audit services have been pre-approved by the Audit committee in accordance with the pre-approval policy described above.

EXTERNAL AUDITOR SERVICE FEES

The table below shows the services KPMG provided during the last two fiscal years and the fees we paid them:

($ millions)	2017	2016
Audit fees	$9.7(1)	$8.2
• audit of the annual consolidated financial statements
• services related to statutory and regulatory filings or engagements
• review of interim consolidated financial statements and information contained in various prospectuses and other securities offering documents
Audit-related fees	$0.1	$0.1
• services related to the audit of the financial statements of certain TransCanada post-retirement and post-employment plans, and pipeline abandonment trusts
Tax fees(2)	$0.8	$0.6
• Canadian and international tax planning and tax compliance matters, including the review of income tax returns and other tax filings
All other fees	$0.2	–
• French translation services
Total fees	$10.8	$8.9

Notes:

(1) The increase in audit fees from 2016 reflects the transfer of the Columbia audit to KPMG, following TransCanada's acquisition of Columbia in 2016.

(2) The tax fees principally related to fees incurred on account of compliance matters.

36 TransCanada Annual information form2017

Legal proceedings and regulatory actions

Legal proceedings, arbitrations and actions are part of doing business. While we cannot predict the final outcomes of proceedings and actions with certainty, management does not expect any potential or current proceeding or action to have a material impact on our consolidated financial position or results of operations.

Transfer agent and registrar

TransCanada's transfer agent and registrar is Computershare Trust Company of Canada with its Canadian transfer facilities in the cities of Vancouver, Calgary, Toronto, Halifax and Montréal.

Material contracts

Other than as disclosed in the MD&A, which is incorporated by reference herein, TransCanada did not enter into any material contracts outside the ordinary course of business during the year ended December 31, 2017, nor has it entered into any material contracts outside the ordinary course of business prior to the year ended December 31, 2017 which are still in effect as at the date of this AIF.

Interest of experts

KPMG LLP are the auditors of TransCanada and have confirmed with respect to TransCanada, that they are independent within the meaning of the relevant rules and related interpretations prescribed by the relevant professional bodies in Canada and any applicable legislation or regulations and also that they are independent accountants with respect to TransCanada under all relevant U.S. professional and regulatory standards.

Additional information

1. Additional information in relation to TransCanada may be found under TransCanada's profile on SEDAR (www.sedar.com).

2. Additional information including directors' and officers' remuneration and indebtedness, principal holders of TransCanada's securities and securities authorized for issuance under equity compensation plans (all where applicable), is contained in TransCanada's Management information circular for its most recent annual meeting of shareholders that involved the election of directors and can be obtained upon request from the Corporate Secretary of TransCanada.

3. Additional financial information is provided in TransCanada's audited consolidated financial statements and MD&A for its most recently completed financial year.

TransCanada Annual information form 2017 37

Glossary

Units of measure
Bbl/d	Barrel(s) per day
Bcf	Billion cubic feet
Bcf/d	Billion cubic feet per day
GJ	Gigajoule
hp	horsepower
km	Kilometres
MMcf/d	Million cubic feet per day
MW	Megawatt(s)
MWh	Megawatt hours
PJ/d	Petajoules per day
TJ/d	Terajoules per day
General terms and terms related to our operations
AFUDC	Allowance of funds used during construction
ATM	An at-the-market distribution program allowing us to issue common shares from treasury at the prevailing market price
B.C.	British Columbia
bitumen	A thick, heavy oil that must be diluted to flow (also see: diluent). One of the components of the oil sands, along with sand, water and clay
diluent	A thinning agent made up of organic compounds. Used to dilute bitumen so it can be transported through pipelines
FID	Final investment decision
FEIS	Final Environmental Impact Statement
force majeure	Unforeseeable circumstances that prevent a party to a contract from fulfilling it
GHG	Greenhouse gas
investment base	Includes rate base as well as assets under construction
LDC	Local distribution company
LNG	Liquefied natural gas
PJM Interconnection area (PJM)	A regional transmission organization that coordinates the movement of wholesale electricity in all or parts of 13 states and the District of Columbia
PPA	Power purchase arrangement
rate base	Our annual average investment used
WCSB	Western Canada Sedimentary Basin
Year End	Year ended December 31, 2017

Accounting terms
AFUDC	Allowance for funds used during construction
DRP	Dividend reinvestment plan
GAAP	U.S. generally accepted accounting principles
OM&A	Operating, maintenance & administration
ROE	Rate of return on common equity
Government and regulatory bodies terms
AER	Alberta Energy Regulator
BCEAO	Environmental Assessment Office (British Columbia)
CCAA	Companies' Creditors Arrangement Act
CBCA	Canada Business Corporations Act
CFE	Comisión Federal de Electricidad (Mexico)
CRE	Comisión Reguladora de Energía (Mexico)
CQDE	Québec Environmental Law Centre/ Centre québécois du droit de l'environnement
DOS	U.S. Department of State
FERC	Federal Energy Regulatory Commission (U.S.)
MDDELCC	Ministère du Développement durable, de l'Environnement et la Lutte contre les changements climatiques (Québec)
NAFTA	North American Free Trade Agreement
NEB	National Energy Board (Canada)
NRC	National Response Center
NYSE	New York Stock Exchange
OGC	Oil and Gas Commission (British Columbia)
PHMSA	Pipeline and Hazardous Materials Safety and Administration
PSC	Nebraska Public Service Commission
PUC	Public Utilities Commission
SEC	U.S. Securities and Exchange Commission
SGER	Specified Gas Emitters Regulations
TSX	Toronto Stock Exchange

38 TransCanada Annual information form2017

Schedule A

Metric conversion table

The conversion factors set out below are approximate factors. To convert from Metric to Imperial multiply by the factor indicated. To convert from Imperial to Metric divide by the factor indicated.

Metric	Imperial	Factor
Kilometres (km)	Miles	0.62
Millimetres	Inches	0.04
Gigajoules	Million British thermal units	0.95
Cubic metres*	Cubic feet	35.3
Kilopascals	Pounds per square inch	0.15
Degrees Celsius	Degrees Fahrenheit	to convert to Fahrenheit multiply by 1.8, then add 32 degrees; to convert to Celsius subtract 32 degrees, then divide by 1.8

* The conversion is based on natural gas at a base pressure of 101.325 kilopascals and at a base temperature of 15 degrees Celsius.

TransCanada Annual information form 2017 39

Schedule B

CHARTER OF THE AUDIT COMMITTEE

1.    PURPOSE

The Audit Committee shall assist the Board of Directors (the Board) in overseeing and monitoring, among other things, the:

• Company’s financial accounting and reporting process;

• integrity of the financial statements;

• Company’s internal control over financial reporting;

• external financial audit process;

• compliance by the Company with legal and regulatory requirements; and

• independence and performance of the Company’s internal and external auditor.

To fulfill its purpose, the Audit Committee has been delegated certain authorities by the Board that it may exercise on behalf of the Board.

2.    ROLES AND RESPONSIBILITIES

I.    Appointment of the Company’s External Auditor

Subject to confirmation by the external auditor of their compliance with Canadian and U.S. regulatory registration requirements, the Audit Committee shall recommend to the Board the appointment of the external auditor, such appointment to be confirmed by the Company’s shareholders at each annual meeting. The Audit Committee shall also recommend to the Board the compensation to be paid to the external auditor for audit services. The Audit Committee shall also be directly responsible for the oversight of the work of the external auditor (including resolution of disagreements between management and the external auditor regarding financial reporting) for the purpose of preparing or issuing an audit report or related work. The external auditor shall report directly to the Audit Committee.

The Audit Committee shall review and approve the audit plan of the external auditor. The Audit Committee shall also receive periodic reports from the external auditor regarding the auditor’s independence, discuss such reports with the auditor, consider whether the provision of non‑audit services is compatible with maintaining the auditor’s independence and take appropriate action to satisfy itself of the independence of the external auditor.

II.    Oversight in Respect of Financial Disclosure

The Audit Committee shall, to the extent it deems it necessary or appropriate:

(a) review, discuss with management and the external auditor and recommend to the Board for approval, the Company’s audited annual consolidated financial statements, annual information form, management’s discussion and analysis (MD&A), all financial information in prospectuses and other offering memoranda, financial statements required by securities regulators, all prospectuses and all documents which may be incorporated by reference into a prospectus, including, without limitation, the annual management information circular, but excluding any pricing or prospectus supplement relating to the issuance of debt securities of the Company;

(b) review, discuss with management and the external auditor and recommend to the Board for approval, the release to the public of the Company’s interim reports, including the consolidated financial statements, MD&A and press releases on quarterly financial results;

(c) review and discuss with management and the external auditor the use of non-GAAP information and the applicable reconciliation;

(d) review and discuss with management any financial outlook or future-oriented financial information disclosure in advance of its public release; provided, however, that such discussion may be done generally (consisting of discussing the types of information to be disclosed and the types of presentations to be made). The Audit Committee need not discuss in advance each instance in which the Company may provide financial projections or presentations to credit rating agencies;

(e) review with management and the external auditor major issues regarding accounting policies and auditing practices,

40 TransCanada Annual information form2017

including any significant changes in the Company’s selection or application of accounting policies, as well as major issues as to the adequacy of the Company’s internal controls and any special audit steps adopted in light of material control deficiencies that could significantly affect the Company’s financial statements;

(f)review and discuss quarterly findings reports from the external auditor on:

(i)all critical accounting policies and practices to be used;

(ii) all alternative treatments of financial information within generally accepted accounting principles that have been discussed with management, ramifications of the use of such alternative disclosures and treatments, and the treatment preferred by the external auditor; and

(iii) other material written communications between the external auditor and management, such as any management letter or schedule of unadjusted differences.

(g) review with management and the external auditor the effect of regulatory and accounting developments on the Company’s financial statements;

(a) review with management and the external auditor the effect of any off-balance sheet structures on the Company’s financial statements;

(i) review with management, the external auditor and, if necessary, legal counsel, any litigation, claim or contingency, including arbitration and tax assessments, that could have a material effect upon the financial position of the Company, and the manner in which these matters have been disclosed in the financial statements;

(j) review disclosures made to the Audit Committee by the Company’s Chief Executive Officer (CEO) and Chief Financial Officer (CFO) during their certification process for the periodic reports filed with securities regulators about any significant deficiencies in the design or operation of internal controls or material weaknesses therein and any fraud involving management or other employees who have a significant role in the Company’s internal controls; and

(k) discuss with management the Company’s material financial risk exposures and the steps management has taken to monitor and control such exposures, including the Company’s risk assessment and risk management policies.

III.    Oversight in Respect of Legal and Regulatory Matters

(a) review with the Company’s General Counsel legal matters that may have a material impact on the financial statements, the Company’s compliance policies and any material reports or inquiries received from regulators or governmental agencies.

IV.    Oversight in Respect of Internal Audit

(a) review and approve the audit plans of the internal auditor of the Company including the degree of coordination between such plans and those of the external auditor and the extent to which the planned audit scope can be relied upon to detect weaknesses in internal control, fraud or other illegal acts;

(b) review the significant findings prepared by the internal audit department and recommendations issued by it or by any external party relating to internal audit issues, together with management’s response thereto;

(c) review compliance with the Company’s policies and avoidance of conflicts of interest;

(d) review the report prepared by the internal auditor on officers’ expenses and aircraft usage;

(e) review the adequacy of the resources of the internal auditor to ensure the objectivity and independence of the internal audit function, including reports from the internal audit department on its audit process with subsidiaries and affiliates; and

(f) ensure the internal auditor has access to the Chair of the Audit Committee, the Board and the CEO and meet separately with the internal auditor to review with him or her any problems or difficulties he or she may have encountered and specifically:

(i) any difficulties which were encountered in the course of the audit work, including restrictions on the scope of activities or access to required information, and any disagreements with management;

(ii) any changes required in the planned scope of the internal audit; and

(iii)the internal audit department responsibilities, budget and staffing; and to report to the Board on such

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meetings.

V.    Oversight in Respect of the External Auditor

(a) review any letter, report or other communication from the external auditor in respect of any identified weakness in internal control or unadjusted difference and management’s response and follow‑up, inquire regularly of management and the external auditor of any significant issues between them and how they have been resolved, and intervene in the resolution if required;

(b) receive and review annually the external auditor’s formal written statement of independence delineating all relationships between itself and the Company;

(c) meet separately with the external auditor to review any problems or difficulties the external auditor may have encountered and specifically:

(i) any difficulties which were encountered in the course of the audit work, including any restrictions on the scope of activities or access to required information, and any disagreements with management; and

(ii)any changes required in the planned scope of the audit and to report to the Board on such meetings.

(d) meet with the external auditor prior to the audit to review the planning and staffing of the audit;

(e) receive and review annually the external auditor's written report on their own internal quality control procedures; any material issues raised by the most recent internal quality control review, or peer review, of the external auditor, or by any inquiry or investigation by governmental or professional authorities, within the preceding five years, and any steps taken to deal with such issues;

(f) review and evaluate the external auditor, including the lead partner of the external auditor team; and

(g) ensure the rotation of the lead (or coordinating) audit partner having primary responsibility for the audit and the audit partner responsible for reviewing the audit as required by law, but at least every five years.

VI.    Oversight in Respect of Audit and Non‑Audit Services

(a) pre-approve all audit services (which may entail providing comfort letters in connection with securities underwritings) and all permitted non‑audit services, other than non‑audit services where:

(i) the aggregate amount of all such non‑audit services provided to the Company that were not pre-approved constitutes not more than five percent of the total fees paid by the Company and its subsidiaries to the external auditor during the fiscal year in which the non‑audit services are provided;

(ii) such services were not recognized by the Company at the time of the engagement to be non‑audit services; and

(iii) such services are promptly brought to the attention of the Audit Committee and approved, prior to the completion of the audit, by the Audit Committee or by one or more members of the Audit Committee to whom authority to grant such approvals has been delegated by the Audit Committee.

(b) approval by the Audit Committee of a non‑audit service to be performed by the external auditor shall be disclosed as required under securities laws and regulations;

(c) the Audit Committee may delegate to one or more designated members of the Audit Committee the authority to grant pre-approvals required by this subsection. The decisions of any member to whom authority is delegated to pre-approve an activity shall be presented to the Audit Committee at its first scheduled meeting following such pre-approval; and

(d) if the Audit Committee approves an audit service within the scope of the engagement of the external auditor, such audit service shall be deemed to have been pre-approved for purposes of this subsection.

VII.    Oversight in Respect of Certain Policies

(a) review and recommend to the Board for approval the implementation of, and significant amendments to, policies and program initiatives deemed advisable by management or the Audit Committee with respect to the Company’s code of business ethics (COBE), risk management and financial reporting policies;

(b) obtain reports from management, the Company’s senior internal auditing executive and the external auditor and

42 TransCanada Annual information form2017

report to the Board on the status and adequacy of the Company’s efforts to ensure its businesses are conducted and its facilities are operated in an ethical, legally compliant and socially responsible manner, in accordance with the Company’s COBE;

(c) establish a non‑traceable, confidential and anonymous system by which callers may ask for advice or report any ethical or financial concern, ensure that procedures for the receipt, retention and treatment of complaints in respect of accounting, internal controls and auditing matters are in place, and receive reports on such matters as necessary;

(d) annually review and assess the adequacy of the Company’s public disclosure policy; and

(e) review and approve the Company’s hiring policy for partners, employees and former partners and employees of the present and former external auditor (recognizing the Sarbanes-Oxley Act of 2002 does not permit the CEO, controller, CFO or chief accounting officer to have participated in the Company’s audit as an employee of the external auditor during the preceding one-year period) and monitor the Company’s adherence to the policy.

VIII.    Oversight in Respect of Financial Aspects of the Company’s Canadian Pension Plans (the Company’s pension plans), specifically:

(a) review and approve annually the Statement of Investment Beliefs for the Company’s pension plans;

(b) delegate the ongoing administration and management of the financial aspects of the Canadian pension plans to the Pension Committee comprised of members of the Company’s management team appointed by the Human Resources Committee, in accordance with the Pension Committee Charter, which terms shall be approved by both the Audit Committee and the Human Resources Committee, and the terms of the Statement of Investment Beliefs;

(c) monitor the financial management activities of the Pension Committee and receive updates at least annually from the Pension Committee on the investment of the Plan assets to ensure compliance with the Statement of Investment Beliefs;

(d) provide advice to the Human Resources Committee on any proposed changes in the Company’s pension plans in respect of any significant effect such changes may have on pension financial matters;

(e) review and consider financial and investment reports and the funded status relating to the Company’s pension plans and recommend to the Board on pension contributions;

(f) receive, review and report to the Board on the actuarial valuation and funding requirements for the Company’s pension plans;

(g) approve the initial selection or change of actuary for the Company’s pension plans; and

(h) approve the appointment or termination of the pension plans’ auditor.

IX.    U.S. Stock Plans

(a) review and approve the engagement and related fees of the auditor for any plan of a U.S. subsidiary that offers Company stock to employees as an investment option under the plan.

X.    Oversight in Respect of Internal Administration

(a) review annually the reports of the Company’s representatives on certain audit committees of subsidiaries and affiliates of the Company and any significant issues and auditor recommendations concerning such subsidiaries and affiliates; and

(b) oversee succession planning for the senior management in finance, treasury, tax, risk, internal audit and the controllers’ group.

XI.    Information Security

(a) review quarterly, the report of the Chief Information Officer (or such other appropriate Company representative) on information security controls, education and awareness.

XII.    Oversight Function

While the Audit Committee has the responsibilities and powers set forth in this Charter, it is not the duty of the Audit Committee to plan or conduct audits or to determine that the Company’s financial statements and disclosures are complete and accurate or are in accordance with generally accepted accounting principles and applicable rules and regulations. These are the responsibilities of management and the external auditor. The Audit Committee, its Chair and any of its members

TransCanada Annual information form 2017 43

who have accounting or related financial management experience or expertise, are members of the Board, appointed to the Audit Committee to provide broad oversight of the financial disclosure, financial risk and control related activities of the Company, and are specifically not accountable nor responsible for the day to day operation of such activities. Although designation of a member or members as an “audit committee financial expert” is based on that individual’s education and experience, which that individual will bring to bear in carrying out his or her duties on the Audit Committee, designation as an “audit committee financial expert” does not impose on such person any duties, obligations or liability that are greater than the duties, obligations and liability imposed on such person as a member of the Audit Committee and Board in the absence of such designation. Rather, the role of any audit committee financial expert, like the role of all Audit Committee members, is to oversee the process and not to certify or guarantee the internal or external audit of the Company’s financial information or public disclosure.

3.    COMPOSITION OF AUDIT COMMITTEE

The Audit Committee shall consist of three or more directors, a majority of whom are resident Canadians (as defined in the Canada Business Corporations Act), and all of whom are unrelated and/or independent for the purposes of applicable Canadian and United States securities law and applicable rules of any stock exchange on which the Company's securities are listed. Each member of the Audit Committee shall be financially literate and at least one member shall have accounting or related financial management expertise (as those terms are defined from time to time under the requirements or guidelines for audit committee service under securities laws and the applicable rules of any stock exchange on which the Company’s securities are listed for trading or, if it is not so defined, as that term is interpreted by the Board in its business judgment).

4.    APPOINTMENT OF AUDIT COMMITTEE MEMBERS

The members of the Audit Committee shall be appointed by the Board from time to time on the recommendation of the Governance Committee and shall hold office until the next annual meeting of shareholders or until their successors are earlier appointed or until they cease to be directors of the Company.

5.    VACANCIES

Where a vacancy occurs at any time in the membership of the Audit Committee, it may be filled by the Board on the recommendation of the Governance Committee.

6.    AUDIT COMMITTEE CHAIR

The Board shall appoint a Chair of the Audit Committee who shall:

(a) review and approve the agenda for each meeting of the Audit Committee and, as appropriate, consult with members of management;

(b) preside over meetings of the Audit Committee;

(c) make suggestions and provide feedback from the Audit Committee to management regarding information that is or should be provided to the Audit Committee;

(d) report to the Board on the activities of the Audit Committee relative to its recommendations, resolutions, actions and concerns; and

(e) meet as necessary with the internal and external auditor.

7.    ABSENCE OF AUDIT COMMITTEE CHAIR

If the Chair of the Audit Committee is not present at any meeting of the Audit Committee, one of the other members of the Audit Committee present at the meeting shall be chosen by the Audit Committee to preside at the meeting.

8.    SECRETARY OF AUDIT COMMITTEE

The Corporate Secretary shall act as Secretary to the Audit Committee.

9.    MEETINGS

The Chair, or any two members of the Audit Committee, or the internal auditor, or the external auditor, may call a meeting of the Audit Committee. The Audit Committee shall meet at least quarterly. The Audit Committee shall meet periodically with management, the internal auditor and the external auditor in separate executive sessions.

10.    QUORUM

A majority of the members of the Audit Committee, present in person or by telephone or other telecommunication device that permit all persons participating in the meeting to speak to each other, shall constitute a quorum.

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11.    NOTICE OF MEETINGS

Notice of the time and place of every meeting shall be given in writing, facsimile communication or by other electronic means to each member of the Audit Committee at least 24 hours prior to the time fixed for such meeting; provided, however, that a member may in any manner waive a notice of a meeting. Attendance of a member at a meeting is a waiver of notice of the meeting, except where a member attends a meeting for the express purpose of objecting to the transaction of any business on the grounds that the meeting is not lawfully called.

12.    ATTENDANCE OF COMPANY OFFICERS AND EMPLOYERS AT MEETING

At the invitation of the Chair of the Audit Committee, one or more officers or employees of the Company may attend any meeting of the Audit Committee.

13.    PROCEDURE, RECORDS AND REPORTING

The Audit Committee shall fix its own procedure at meetings, keep records of its proceedings and report to the Board when the Audit Committee may deem appropriate but not later than the next meeting of the Board.

14.    REVIEW OF CHARTER AND EVALUATION OF AUDIT COMMITTEE

The Audit Committee shall review its Charter annually or otherwise, as it deems appropriate and, if necessary, propose changes to the Governance Committee and the Board. The Audit Committee shall annually review the Audit Committee’s own performance.

15.    OUTSIDE EXPERTS AND ADVISORS

The Audit Committee is authorized, when deemed necessary or desirable, to retain and set and pay the compensation forindependent counsel, outside experts and other advisors, at the Company’s expense, to advise the Audit Committee or its members independently on any matter.

16.    RELIANCE

Absent actual knowledge to the contrary (which shall be promptly reported to the Board), each member of the Audit Committee shall be entitled to rely on (i) the integrity of those persons or organizations within and outside the Company from which it receives information, (ii) the accuracy of the financial and other information provided to the Audit Committee by such persons or organizations and (iii) representations made by management and the external auditor, as to any information technology, internal audit and other non-audit services provided by the external auditor to the Company and its subsidiaries.

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