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•	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.

•	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.

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•	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.

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•	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.

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•	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.

•	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.

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•	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.

•	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.

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•	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.

•	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.

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•	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.

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•	National Instrument 52-110, Audit Committees

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

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

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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.

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

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•	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.

(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,

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(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.

(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.

(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

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(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

(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.

(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.

(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

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(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.

(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.

(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.

(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.

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

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(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.

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•	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 U.S. Tax Reform

•	expected industry, market and economic conditions.

•	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.

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•	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.

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•	comparable earnings

•	comparable earnings per common share

•	comparable EBITDA

•	comparable EBIT

•	funds generated from operations

•	comparable funds generated from operations

•	comparable distributable cash flow

•	comparable distributable cash flow per common share.

•	certain fair value adjustments relating to risk management activities

•	income tax refunds and adjustments and changes to enacted tax rates

•	gains or losses on sales of assets or assets held for sale

•	legal, contractual and bankruptcy settlements

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

•	restructuring costs

•	impairment of goodwill, investments and other assets including certain ongoing maintenance and liquidation costs

•	acquisition and integration costs.

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1	2016 includes U.S. Northeast power assets held for sale.

1	Includes Columbia effective July 2016.

2	Includes U.S. Northeast power and Ontario solar assets until sold in 2017.

1	Includes Columbia effective July 2016.

2	Includes U.S. Northeast power and Ontario solar assets until sold in 2017.

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1	Leach XPress was placed in service in January 2018.

2	Reflects our proportionate share of costs related to Portland Xpress and various expansion projects.

3	Our proportionate share.

4	Amount reflects our proportionate share of the remaining capital costs that Bruce Power expects to incur on its life extension investment programs in advance of the Unit 6 major refurbishment outage which is expected to begin in 2020.

5	Reflects U.S./Canada foreign exchange rate of 1.25 at December 31, 2017.

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1	Regulatory approvals have been obtained; additional commercial support is being pursued.

2	Our proportionate share.

3	Carrying value reflects amount remaining after impairment charge recorded in 2015.

4	Reflects U.S./Canada foreign exchange rate of 1.25 at December 31, 2017.

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1	Includes capital expenditures, capital projects in development and contributions to equity investments.

2	See financial condition on page 78 for details on preferred share dividends.

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•	an $804 million recovery of deferred income taxes as a result of U.S. Tax Reform

•

a $307 million after-tax net gain related to the monetization of our U.S. Northeast power business, which included a $440 million after-tax gain on the sale of TC Hydro, an incremental after-tax loss of $190 million recorded on the sale of the thermal and wind package, $23 million of after-tax third-party insurance proceeds related to a 2017 Ravenswood outage, $14 million of after-tax disposition costs, and income tax adjustments

•	a $136 million after-tax gain related to the sale of our Ontario solar assets

•	a $954 million after-tax impairment charge for the Energy East pipeline and related projects as a result of our decision not to proceed with the project applications

•	a $69 million after-tax charge for integration-related costs associated with the acquisition of Columbia

•	a $28 million after-tax charge related to the maintenance and liquidation of Keystone XL assets which were expensed pending further advancement of the project

•	a $7 million income tax recovery related to the realized loss on a third party sale of Keystone XL project assets. A provision for the expected pre-tax loss on these assets was included in our 2015 impairment charge, but the related income tax recoveries could not be recorded until realized.

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•	a $656 million after-tax impairment of Ravenswood goodwill. As a result of information received during the process to monetize our U.S. Northeast power business in third quarter 2016, it was determined that the fair value of Ravenswood no longer exceeded its carrying value

•	an $873 million after-tax loss on U.S. Northeast power assets held for sale which included an $863 million after-tax loss on the thermal and wind package held for sale and $10 million of after-tax disposition costs

•	a $176 million after-tax impairment charge on the carrying value of our Alberta PPAs (both directly and through our equity investment in ASTC Power Partnership) as a result of our decision to terminate the PPAs and a $68 million after-tax loss on the transfer of environmental credits to the Balancing Pool upon final settlement of the PPA terminations

•

costs associated with the acquisition of Columbia resulting in an after-tax charge of $273 million which included $109 million of dividend equivalent payments on the subscription receipts issued as part of the permanent financing of the transaction, $90 million of retention, severance and integration costs, $36 million of acquisition costs and a $44 million deferred income tax adjustment upon closing of the acquisition, partially offset by $6 million of interest earned on the subscription receipt funds held in escrow prior to their conversion to common shares

•	$28 million of income tax recoveries related to the realized loss on a third party sale of Keystone XL project assets. A provision for the expected pre-tax loss on these assets was included in our fourth quarter 2015 impairment charge, but the related income tax recoveries could not be recorded until realized

•	an after-tax charge of $42 million related to Keystone XL costs for the maintenance and liquidation of project assets which were expensed pending further advancement of the project

•	an after-tax charge of $16 million for restructuring mainly related to expected future losses under lease commitments. These charges formed part of a restructuring initiative, which commenced in 2015, to maximize the effectiveness and efficiency of our existing operations and reduce overall costs

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

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

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

•

a net charge of $74 million after tax for restructuring comprised of $42 million mainly related to 2015 severance costs and a provision of $32 million for 2016 planned severance costs and expected future losses under lease commitments. These charges formed part of a restructuring initiative, which commenced in 2015, to maximize the effectiveness and efficiency of our existing operations and reduce overall costs

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

•	a $34 million adjustment to income tax expense due to the enactment of a two per cent increase in the Alberta corporate income tax rate in June 2015

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

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

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•	higher contribution from U.S. Natural Gas Pipelines due to incremental earnings from Columbia following the July 1, 2016 acquisition and higher ANR transportation revenue resulting from a FERC-approved rate settlement effective August 1, 2016

•	increased earnings from Liquids Pipelines primarily due to higher uncontracted volumes on the Keystone Pipeline System, liquids marketing activities and the commencement of operations on Grand Rapids and Northern Courier

•	higher earnings from Bruce Power mainly due to higher volumes resulting from fewer outage days

•	higher contribution from Mexico Natural Gas Pipelines due to earnings from Topolobampo beginning in July 2016 and Mazatlán beginning in December 2016

•	higher AFUDC on our rate-regulated U.S. natural gas pipelines, as well as the NGTL System, Tula and Villa de Reyes, partially offset by the commercial in-service of Topolobampo and completion of Mazatlán construction

•	higher interest income and other due to income related to recovery of certain Coastal GasLink project costs and the termination of the PRGT project

•	lower contribution from U.S. Power due to the monetization of our U.S. Northeast power generation assets in second quarter 2017 and the continued wind-down of our U.S. power marketing operations

•	higher interest expense as a result of debt assumed in the acquisition of Columbia on July 1, 2016 and long-term debt and junior subordinated note issuances in 2017, net of maturities.

•	higher contribution from U.S. Natural Gas Pipelines primarily due to incremental earnings following the July 1, 2016 Columbia acquisition, higher ANR transportation revenues resulting from a FERC-approved rate settlement effective August 1, 2016, new contracts on ANR Southeast Mainline and lower OM&A expenses

•	higher interest expense from debt issuances and lower capitalized interest

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

•	lower earnings from Liquids Pipelines due to the net effect of higher contracted and lower uncontracted volumes on Keystone, as well as lower volumes on Marketlink

•	higher AFUDC on our rate-regulated projects including those for the NGTL System, Energy East, Columbia and Mexico pipelines

•	higher contribution from Mexico Natural Gas Pipelines primarily due to earnings from Topolobampo beginning in July 2016

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

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1	Capital spending includes capacity capital expenditures, maintenance capital expenditures, capital projects in development and contributions to equity investments.

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•	contributions from new Columbia Gas and Columbia Gulf projects coming into service

•	full year of earnings from Grand Rapids and Northern Courier placed in service in the latter half of 2017

•	completion of the Napanee power plant in Ontario

•	growth in the average investment base for the NGTL System

•	benefit of lower U.S. income tax rates. See U.S. Tax Reform section for further information.

•	lower Energy earnings due to the monetization of the U.S. Northeast power generation assets in second quarter 2017, the sale of the Ontario solar assets in late-2017 and the continued wind-down of our U.S. power marketing operations

•	lower Bruce Power equity income due to a higher number of planned outage days

•	discontinuation of AFUDC on Energy East and related projects

•	decrease in Canadian Mainline average investment base.

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•	wholly-owned natural gas pipelines – 80,800 km (50,100 miles)

•	partially-owned natural gas pipelines – 11,100 km (7,000 miles).

•	In 2017, we placed into service approximately $3.3 billion of new facilities including $1.7 billion on the NGTL System, $0.2 billion on the Canadian Mainline and $1.4 billion related to U.S. Natural Gas Pipelines

•	In 2017, we originated an additional US$0.3 billion of capital projects related to U.S. Natural Gas Pipelines

•	In June 2017, we announced a new $2 billion expansion program on our NGTL System based on new contracted customer demand for approximately 3 Bcf/d of incremental firm receipt and delivery services

•

In July 2017, we were notified that Pacific Northwest (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 Prince Rupert Gas Transmission (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.

•	In November 2017, we began delivering volumes under the new Dawn Long-Term Fixed-Price (LTFP) service on the Canadian Mainline

•	In December 2017, we filed, subject to NEB approval, a Supplemental Agreement for the Canadian Mainline to address 2018 to 2020 tolls, to meet a condition of the NEB approval for the 2015 - 2030 Tolls and Tariff Application

•	In January 2018, the Columbia Gas Leach XPress project was placed in service

•	In February 2018, we announced an additional $2.4 billion expansion program on our NGTL System.

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•	natural gas-fired electric-power generation

•	petrochemical and industrial facilities

•	the production of Alberta oil sands, despite new greenfield oil sands projects that have not yet begun construction or have been delayed in the recent low oil price environment

•	exports to Mexico to fuel power generation facilities.

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1	Includes results from Foothills, Ventures LP, Great Lakes Canada, our share of equity income from our investment in TQM, and general and administrative costs related to our Canadian Pipelines.

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1	We completed the acquisition of Columbia on July 1, 2016. Results reflect our effective ownership in these assets from that date.

2

Results from Northern Border and Iroquois reflect our share of equity income from these investments. We acquired additional interests in Iroquois of 4.87 per cent on March 31, 2016 and 0.65 per cent on May 1, 2016. TC PipeLines, LP acquired 49.34 per cent of our 50 per cent interest in Iroquois on June 1, 2017. On January 1, 2016, we sold a 49.9 per cent direct interest in PNGTS to TC PipeLines, LP and the remaining 11.81 per cent to TC PipeLines, LP on June 1, 2017. On April 1, 2015, we sold our remaining 30 per cent direct interest in GTN to TC PipeLines, LP.

3	TC PipeLines, LP periodically conducts at-the-market equity issuances which decrease our ownership in TC PipeLines, LP. The following shows our ownership interest in TC PipeLines, LP and our effective ownership interest of Great Lakes and PNGTS through our ownership interest in TC PipeLines, LP at the dates presented.

4	Represents our 53.6 per cent direct interest in Great Lakes. The remaining 46.4 per cent is held by TC PipeLines, LP.

5	Includes our direct ownership in Iroquois and PNGTS (until June 1, 2017) and GTN (until April 1, 2015), our effective ownership in Millennium and Hardy Storage, and general and administrative costs related to U.S. natural gas assets.

6	Comparable EBITDA for the portions of TC PipeLines, LP, PNGTS (until June 1, 2017), and CPPL we do not own. Effective February 17, 2017, we acquired the remaining publicly held units of CPPL.

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•	a full year contribution from Columbia

•	higher ANR transportation revenue resulting from a FERC-approved rate settlement, effective August 1, 2016.

•	incremental earnings from Columbia as a result of the acquisition on July 1, 2016

•	higher ANR transportation revenue resulting from a FERC-approved rate settlement, effective August 1, 2016, higher Southeast Mainline transportation revenues and lower pipeline integrity work on ANR, partially offset by lower incidental commodity sales and a one time settlement in 2015 with an owner of adjacent facilities for commercial interruption of ANR's service

•	higher contributions from TC PipeLines, LP mainly due to higher GTN transportation revenues.

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1	Represents our 60 per cent equity interest in a joint venture with IEnova to build, own and operate the Sur de Texas pipeline.

•	incremental earnings from Topolobampo beginning July 2016 and Mazatlán beginning December 2016

•	equity earnings from our investment in the Sur de Texas pipeline which records AFUDC during construction, net of interest expense on an inter-affiliate loan from TransCanada. The inter-affiliate loan interest is fully offset in interest income and other in the Corporate segment.

•	the impairment of our equity investment in TransGas.

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•	incremental earnings from Topolobampo. The Topolobampo project experienced a delay in construction which, under the terms of our TSA with the CFE, constitutes a force majeure event with provisions allowing for the collection and recognition of revenue as per the original TSA service commencement date of July 2016

•	incremental earnings from Mazatlán. Construction is complete and the collection and recognition of revenue began per the terms of the TSA in December 2016

•	lower business development costs expensed in 2016 due to the capitalization of costs for work on projects successfully awarded and under construction.

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•	Received the U.S. Presidential Permit for the Keystone XL project

•	Received approval for a Nebraska pipeline route and secured sufficient commercial support to commence construction preparation for the Keystone XL project

•	Secured incremental long-term contractual support following the conclusion of Keystone pipeline and Marketlink open seasons

•	Informed the NEB that we will not be proceeding with the Energy East and Eastern Mainline project applications

•	Completed construction of Grand Rapids and Northern Courier, two new intra-Alberta liquids pipelines

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1	Includes primarily liquids marketing and business development activities.

•	higher uncontracted volumes on the Keystone Pipeline System

•	a higher contribution from the liquids marketing business

•	new intra-Alberta pipelines, Grand Rapids and Northern Courier, which began operations in the second half of 2017

•	higher business development activities, including advancement of Keystone XL

•	a weaker U.S. dollar which had a negative impact on the Canadian dollar equivalent comparable earnings

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•	lower uncontracted volumes on Keystone pipeline

•	lower volumes on Marketlink

•	higher contracted volumes on Keystone pipeline

•	a higher contribution from the liquids marketing business

•	lower business development activities

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

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•	Strong financial results from Bruce Power; work is progressing on the life extension program

•	Completed monetization of the U.S. Northeast generation assets and entered into an agreement to sell U.S. power retail contracts as part of the continued wind down of our U.S. power marketing operations

•	Divestiture of Ontario solar assets to capture robust market value and provide capital to support near-term growth

•	Construction continues on the 900 MW Napanee natural gas-fired power plant with expected in service in fourth quarter 2018.

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1	Our share of power generation capacity.

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•	Canadian Power

•	Natural Gas Storage (Canadian, non-regulated).

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1	Included losses from the Alberta PPAs up to March 2016 when the PPAs were terminated.

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

3	TC Hydro earnings included up to April 19, 2017 sale date; Ravenswood, Ironwood, Ocean State Power and Kibby Wind earnings included up to June 2, 2017 sale date.

4	Depreciation of U.S. Northeast power assets ceased effective November 2016 when classified as assets held for sale.

5	Includes a $21 million impairment charge in 2017 related to obsolete equipment.

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a net gain in 2017 of $484 million (2016 - loss of $844 million) before tax related to the monetization of our U.S. Northeast power assets which included a $715 million gain on the sale of TC Hydro, a loss of $211 million (2016 - $829 million) on the sale of the thermal and wind package and $20 million (2016 - $15 million) of pre-tax disposition costs. See Significant Events section for more details

•	a gain in 2017 of $127 million before tax related to the sale of our Ontario solar assets. See Significant Events section for more details

•	a $1,085 million impairment of Ravenswood goodwill in 2016. As a result of information received during the process to monetize our U.S. Northeast power business in third quarter 2016, it was determined that the fair value of Ravenswood no longer exceeded its carrying value

•	a $332 million pre-tax charge in 2016 which included a $211 million impairment charge on the carrying value of our Alberta PPAs, a $29 million impairment of our equity investment in ASTC Power Partnership, and a $92 million loss on the transfer of environmental credits to the Balancing Pool upon final settlement of the PPA terminations

•	a loss in 2015 of $59 million before tax relating to an impairment in value of turbine equipment previously purchased for a power development project that did not proceed

•	a charge in 2015 of $36 million before tax related to Bruce Power's retirement of debt in conjunction with the merger of the Bruce A and Bruce B partnerships

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

•	lower earnings from U.S. Power due to the monetization of generating assets in second quarter 2017 and the wind down of our U.S. power marketing operations

•	higher earnings from Bruce Power mainly due to higher volumes resulting from fewer outage days

•	higher earnings from Western Power primarily due to the termination of the Alberta PPAs.

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

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

•	lower earnings from U.S. Power

•	lower business development expenses primarily due to decreased business development activity

•	higher earnings from Bruce Power mainly due to lower depreciation as a result of the operating life extensions, our increased ownership interest and higher realized sales price, partially offset by lower volumes and higher operating costs from increased outage days

•	a stronger U.S. dollar and its positive effect on the foreign exchange impact.

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1	Represents our 48.4 per cent (2016 - 48.5 per cent) ownership interest in Bruce Power after the merger on December 4, 2015 and, prior to this, represents our 48.9 per cent ownership interest in Bruce A and 31.6 per cent ownership interest in Bruce B. Sales volumes include deemed generation. Comparable EBITDA in 2015 excludes a $36 million debt retirement charge.

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

3	Calculation based on actual and deemed generation. Realized sales price per MWh includes realized gains and losses from contracting activities and cost flow-through items. Excludes unrealized gains and losses on contracting activities and non-electricity revenues.

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•	lower capacity revenues due to lower realized capacity prices in New York and the impact of lower availability as a result of a unit outage from September 2014 to May 2015, partially offset by insurance recoveries, net of deductibles at Ravenswood

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

•	lower margins on sales to wholesale, commercial and industrial customers partially offset by higher sales to customers in the PJM market

•	higher earnings due to our acquisition of the Ironwood power plant in February 2016

•	insurance recoveries related to an unplanned outage at the Ravenswood facility that occurred in 2008.

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1	Reported in Income from equity investments on the consolidated statement of income.

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•	long-term debt and junior subordinated notes issuances in 2017 and 2016, partially offset by Canadian and U.S. dollar-denominated debt maturities. See the Financial condition section for further details on long-term debt

•	debt assumed in the acquisition of Columbia on July 1, 2016

•	lower amortization expense on debt issuance costs related to the Columbia acquisition bridge facilities, which were fully repaid in June 2017

•	higher foreign exchange on interest expense related to higher levels of U.S. dollar-denominated debt

•	the specific item of $115 million in 2016 included the dividend equivalent payments of $109 million on the subscription receipts issued to partially fund the Columbia acquisition and $6 million of other acquisition related costs.

•	the specific item of $115 million in 2016 discussed above

•	long-term debt issuances in 2016 and 2015, partially offset by Canadian and U.S. dollar-denominated debt maturities

•	debt assumed in the acquisition of Columbia on July 1, 2016

•	higher foreign exchange on interest expense related to a weaker Canadian dollar and higher levels of U.S. dollar-denominated debt

•	amortization expense on debt issuance costs related to the Columbia acquisition bridge facilities

•	higher carrying charges to shippers in 2016 on the net revenue variance for the Canadian Mainline

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

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•	higher unrealized gains on risk management activities in 2017 compared to 2016. These amounts have been excluded from comparable earnings

•	recovery of $32 million related to carrying charges on Coastal GasLink project costs incurred and recognized on the termination of the PRGT project. See the Canadian Natural Gas Pipelines Significant events section for more information

•	foreign exchange impact on the translation of foreign currency denominated working capital balances

•	lower realized gains in 2017 compared to 2016 on derivatives used to manage our net exposure to foreign exchange rate fluctuations on U.S. dollar-denominated income

•

higher interest income along with a $63 million foreign exchange loss related to an inter-affiliate loan receivable from the Sur de Texas joint venture. The corresponding interest expense and foreign exchange gain are reflected in income from equity investments in the Mexico Natural Gas Pipelines and Corporate segments, respectively. Both currency-related amounts are excluded from comparable earnings.

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

•	unrealized gains on risk management activities in 2016 compared to losses in 2015. These amounts have been excluded from comparable earnings

•	foreign exchange impact on the translation of foreign currency denominated working capital

•	interest income on the gross proceeds of the subscription receipts issued to partially fund the Columbia acquisition. These amounts have been excluded from comparable earnings.

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1	Includes non-controlling interests.

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•	our ability to generate predictable and growing cash flow from operations

•	our access to capital markets, including through our DRP and ATM programs

•	approximately $9.0 billion of unused, unsecured credit facilities.

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•	the 2016 acquisitions of Columbia and Ironwood

•	higher capital spending in 2017

•	proceeds from the sales of our U.S. power generation assets and solar assets in 2017

•	recovery of PRGT project costs.

1	Capital spending includes capacity capital expenditures, maintenance capital expenditures, capital projects in development, and contributions to equity investments.

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•	acquired 100 per cent ownership of Columbia for US$10.3 billion in cash

•	acquired the Ironwood power plant for US$653 million in cash after post-acquisition adjustments

•	acquired an additional 5.52 per cent interest in Iroquois for an aggregate purchase price of US$61 million

•	sold TC Offshore for $6 million.

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1	The amounts in this table exclude funding contributions to our pension plans.

2	Demand rates are subject to change. The contractual obligations in the table are based on demand volumes only and exclude variable charges incurred when volumes flow.

3	Amounts are primarily for capital expenditures and contributions to equity investments for capital projects. Amounts are estimates and are subject to variability based on timing of construction and project requirements.

4	Includes estimates of certain amounts which are subject to change depending on plant-fired hours, the consumer price index, actual plant maintenance costs, plant salaries as well as changes in regulated rates for fuel transportation.

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•	senior debt

•	project financing

•	preferred shares

•	hybrid securities

•	additional drop downs of our U.S. natural gas pipeline assets to TC PipeLines, LP

•	asset sales

•	potential involvement of strategic or financial partners

•	common shares issued under our DRP

•	common shares issued under our ATM programs, as appropriate

•	lastly, discrete common equity issuances.

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•	interest rates

•	actual returns on plan assets

•	changes to actuarial assumptions and plan design

•	actual plan experience versus projections

•	amendments to pension plan regulations and legislation.

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•	the Human Resources Committee oversees executive resourcing, organizational capabilities and compensation risk to ensure compensation practices align with our overall business strategy

•	the Health, Safety and Environment Committee oversees operational, safety and environmental risk

•	the Audit Committee oversees management's role in monitoring financial risk.

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•	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.

•	overall HSE corporate governance

•	operational performance and preventive 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.

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•	changing regulations and costs associated with our emissions of air pollutants and GHG

•	product releases, including crude oil, diluent and natural gas, that may cause harm to the environment (land, water and air)

•	use, storage and disposal of chemicals and hazardous materials

•	conformance and compliance with corporate and regulatory policies and requirements and new regulations.

•	environmental laws and regulations (and interpretation and enforcement of them) change

•	new claims can be brought against our existing or discontinued assets

•	our pollution control and clean-up cost estimates may change, especially when our current estimates are based on preliminary site investigation or agreements

•	we may find new contaminated sites, or what we know about existing sites could change

•	where there is potentially more than one responsible party involved in litigation, we cannot estimate our joint and several liability with certainty.

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•	the U.S. Environmental Protection Agency (EPA) published regulations related to fugitive methane emissions for new and modified compressor stations in the natural gas transmission and storage sector in 2015. In 2017, the EPA indicated its intention to reconsider this regulation

•	B.C. has a tax on GHG emissions from fossil fuel combustion. We recover the compliance costs through the tolls our customers pay

•

under the SGER in Alberta, established industrial facilities with GHG emissions above a certain threshold are required to reduce their emissions below an intensity baseline. The SGER program covers our natural gas pipelines and Energy assets. Natural gas pipeline compliance costs are recovered through regulated tolls. A portion of the compliance costs for the Energy assets are recovered through market pricing and hedging activities

•

Québec and California have GHG cap and trade programs linked under the Western Climate Initiative (WCI) GHG emissions market. In Québec, the Bécancour cogeneration plant is subject to this program. The government allocates free emission units for the majority of Bécancour's compliance requirements. The remaining requirements were met with GHG instruments purchased at auctions or secondary markets. The costs of these emissions units were recovered through commercial contracts. The Canadian Mainline natural gas pipeline facilities in Québec are also subject to this program and have purchased compliance instruments. In California, TransCanada has costs associated with the cap and trade program from our electricity marketing activities

•

Ontario launched a cap and trade program under the WCI on January 1, 2017. The Canadian Mainline natural gas pipeline facilities in Ontario are subject to this program and have purchased compliance instruments which are recoverable in tolls. Although TransCanada’s electricity generation facilities in the province are not directly subject to this program, TransCanada contributes to the compliance costs through distribution rates

•	on March 23, 2017, the California Air Resources Board published regulations related to monitoring and repairing methane leaks. Tuscarora Gas Transmission facilities are required to comply with these regulations

•	Washington State adopted emission standards to cap and reduce GHGs from certain stationary sources in September 2016. Some GTN compressor stations in Washington are potentially impacted by the standards beginning in 2020.

•	future legislative and regulatory programs could significantly restrict emissions of GHGs including methane across our operations

•	the Government of Canada has proposed a federal plan to have carbon pricing in place in all Canadian jurisdictions in 2018. The plan would expand GHG pricing coverage of TransCanada assets to Saskatchewan, Manitoba and New Brunswick and is within the bounds of our previously anticipated changes to GHG regulations

•	the Alberta government announced a climate change policy, the Climate Leadership Plan (CLP), in 2015. This policy will see the replacement of the SGER program with the Carbon Competitiveness Incentive Regulation, a performance standard-based GHG pricing program, on January 1, 2018

•	Environment and Climate Change Canada issued a draft Methane Reduction Regulation on May 27, 2017. The draft regulations detail requirements to reduce methane emissions through operational and capital modifications

•	the Government of Canada has proposed a federal plan, the Clean Fuel Standard, to implement a single national standard encompassing all fuel types and applications

•	the Pennsylvania Department of Environmental Protection has proposed new operating permits for oil and gas facilities that include numerous requirements including methane leak detection and repair

•	New York State announced its intent to adopt regulations to reduce methane from existing, new and modified facilities

•	Maryland announced its intent to establish fugitive methane regulations for compressor stations

•	the Government of Mexico has proposed to implement a carbon tax for all companies that exceed an annual emissions threshold

•	the Saskatchewan and Manitoba governments each announced that large industrial emitters will be subject to a yet to be developed carbon pricing system.

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•	forwards and futures contracts – agreements to buy or sell a financial instrument or commodity at a specified price and date in the future

•	swaps – agreements between two parties to exchange streams of payments over time according to specified terms

•	options – agreements that give the purchaser the right (but not the obligation) to buy or sell a specific amount of a financial instrument or commodity at a fixed price, either at a fixed date or at any time within a specified period.

•	committing a portion of expected power supply to fixed-price medium-term or long-term sales contracts, while reserving an amount of unsold supply to manage operational and price risks in our asset portfolio

•	purchasing a portion of the natural gas required to fuel certain of our power plants or entering into contracts that base the sale price of electricity on the cost of natural gas, effectively locking in a margin

•	meeting power sales commitments using power generation or fixed price purchase contracts, thereby reducing our exposure to fluctuating commodity prices.

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1	Excludes interest expense on our inter-affiliate loan with Sur de Texas which is offset in interest income and other.

1	Fair values equal carrying values.

2	In 2017, consolidated net income includes net realized gains of $4 million (2016 – gains of $6 million) related to the interest component of cross-currency swap settlements which are reported within interest expense.

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•	accounts receivable

•	the fair value of derivative assets

•	cash and cash equivalents.

•	dealing with creditworthy counterparties – a significant amount of our credit exposure is with investment grade counterparties or, if not, is generally partially supported by financial assurances from investment grade parties

•	setting limits on the amount we can transact with any one counterparty – we monitor and manage the concentration of risk exposure with any one counterparty, and reduce our exposure when we feel we need to and when it is allowed under the terms of our contracts

•	using contract netting arrangements and obtaining financial assurances such as guarantees, letters of credit or cash when we believe it is necessary.

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•	a regulator must establish or approve the rates for the regulated services or activities

•	the regulated rates must be designed to recover the cost of providing the services or products

•	it is reasonable to assume that rates set at levels to recover the cost can be charged to (and collected from) customers because of the demand for services or products and the level of direct and indirect competition.

•	a $954 million after-tax charge on the carrying value of our investment in Energy East and related projects

•	a $16 million after-tax charge on the remaining carrying value of certain Energy turbine equipment

•	a $12 million after-tax charge related to the remaining carrying value of our investment in TransGas.

•	a goodwill impairment charge on the full carrying value of Ravenswood goodwill of $656 million after tax

•	a $244 million after-tax charge with respect to the Alberta PPA terminations.

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1.	First, we compare the fair value of the reporting unit to its book value, including its goodwill. If fair value is less than book value, we consider our goodwill to be impaired.

2.	Next, we measure the amount of the impairment by calculating the implied fair value of the reporting unit's goodwill. We do this by deducting the fair value of the tangible and intangible net assets of the reporting unit from the fair value we calculated in the first step. To the extent the goodwill's carrying value exceeds its implied fair value, we record an impairment charge.

•	when we expect to retire the asset

•	the scope of abandonment and reclamation activities that are required

•	inflation and discount rates.

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

2	In 2017, there were no gains or losses included in net income relating to discontinued cash flow hedges where it was probable that the anticipated transaction would not occur (2016 - net loss of $42 million).

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1	No amounts have been excluded from the assessment of hedge effectiveness. In 2017 and 2016, there were no gains or losses included in net income related to ineffective portions. Amounts in parentheses indicate losses recorded to OCI and AOCI.

2	Reported within revenues on the consolidated statement of income.

3	Reported within interest expense on the consolidated statement of income.

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•	regulators' decisions

•	negotiated settlements with shippers

•	acquisitions and divestitures

•	developments outside of the normal course of operations

•	newly constructed assets being placed in service.

•	developments outside of the normal course of operations

•	newly constructed assets being placed in service

•	regulatory decisions.

•	weather

•	customer demand

•	market prices for natural gas and power

•	capacity prices and payments

•	planned and unplanned plant outages

•	acquisitions and divestitures

•	certain fair value adjustments

•	developments outside of the normal course of operations

•	newly constructed assets being placed in service.

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•	an $804 million recovery of deferred income taxes as a result of U.S. Tax Reform

•	a $136 million after-tax gain related to the sale of our Ontario solar assets

•	a $64 million net after-tax gain related to the monetization of our U.S. Northeast power business, which included an incremental after-tax loss of $7 million recorded on the sale of the thermal and wind package, $23 million of after-tax third-party insurance proceeds related to a 2017 Ravenswood outage and income tax adjustments

•	a $954 million after-tax impairment charge for the Energy East pipeline and related projects as a result of our decision not to proceed with the project applications

•	a $9 million after-tax charge related to the maintenance and liquidation of Keystone XL assets which were expensed pending further advancement of the project.

•	an incremental net loss of $12 million related to the monetization of our U.S. Northeast power business which included an incremental loss of $7 million after tax on the sale of the thermal and wind package and $14 million of after-tax disposition costs and income tax adjustments

•	an after-tax charge of $30 million for integration-related costs associated with the acquisition of Columbia

•	an after-tax charge of $8 million related to the maintenance of Keystone XL assets which were being expensed pending further advancement of the project.

•	a $265 million net after-tax gain related to the monetization of our U.S. Northeast power business which included a $441 million after-tax gain on the sale of TC Hydro and a loss of $176 million after tax on the sale of the thermal and wind package

•	an after-tax charge of $15 million for integration-related costs associated with the acquisition of Columbia

•	an after-tax charge of $4 million related to the maintenance of Keystone XL assets which were being expensed pending further advancement of the project.

•	a charge of $24 million after tax for integration-related costs associated with the acquisition of Columbia

•	a charge of $10 million after tax for costs related to the monetization of our U.S. Northeast power business

•	a charge of $7 million after tax related to the maintenance of Keystone XL assets which were being expensed pending further advancement of the project

•	a $7 million income tax recovery related to the realized loss on a third party sale of Keystone XL project assets. A provision for the expected pre-tax loss on these assets was included in our 2015 impairment charge, but the related income tax recoveries could not be recorded until realized.

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•	an $870 million after-tax charge related to the loss on U.S. Northeast power assets held for sale which included an $863 million after-tax loss on the thermal and wind package held for sale and $7 million of after-tax costs related to the monetization

•	an additional $68 million after-tax loss on the transfer of environmental credits to the Balancing Pool upon final settlement of the Alberta PPA terminations

•	an after-tax charge of $67 million for costs associated with the acquisition of Columbia which included a $44 million deferred tax adjustment upon acquisition and $23 million of retention, severance and integration costs

•	an after-tax charge of $18 million related to Keystone XL costs for the maintenance and liquidation of project assets which were being expensed pending further advancement of the project

•	an after-tax restructuring charge of $6 million for additional expected future losses under lease commitments. These charges formed part of a restructuring initiative, which commenced in 2015, to maximize the effectiveness and efficiency of our existing operations and reduce overall costs.

•	a $656 million after-tax impairment on the Ravenswood goodwill. As a result of information received during the process to monetize our U.S. Northeast power business in third quarter 2016, it was determined that the fair value of Ravenswood no longer exceeded its carrying value

•	costs associated with the acquisition of Columbia including a charge of $67 million after tax primarily relating to retention, severance and integration expenses

•	$28 million of income tax recoveries related to the realized loss on a third party sale of Keystone XL plant and equipment. A provision for the expected loss on these assets was included in our fourth quarter 2015 impairment charge but the related tax recoveries could not be recorded until realized

•	a charge of $9 million after tax related to Keystone XL costs for the maintenance and liquidation of project assets which were being expensed pending further advancement of the project

•	a $3 million after-tax charge related to the monetization of our U.S. Northeast power business.

•	a charge of $113 million related to costs associated with the acquisition of Columbia which included $109 million related to dividend equivalent payments on the subscription receipts

•	a charge of $9 million after tax related to Keystone XL costs for the maintenance and liquidation of project assets which were being expensed pending further advancement of the project

•	a charge of $10 million after tax for restructuring charges mainly related to expected future losses under lease commitments.

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

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

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

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

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•	an $804 million recovery of deferred income taxes as a result of U.S. Tax Reform

•	a $136 million after-tax gain related to the sale of our Ontario solar assets

•	a $64 million net after-tax gain related to the monetization of our U.S. Northeast power business, which included an incremental after-tax loss of $7 million recorded on the sale of the thermal and wind package, $23 million of after-tax third-party insurance proceeds related to a 2017 Ravenswood outage and income tax adjustments

•	a $954 million after-tax impairment charge for the Energy East pipeline and related projects as a result of our decision not to proceed with the project applications

•	a $9 million after-tax charge related to the maintenance and liquidation of Keystone XL assets which were expensed pending further advancement of the project.

•	an $870 million after-tax charge related to the loss on U.S. Northeast power assets held for sale which included an $863 million after-tax loss on the thermal and wind package held for sale and $7 million of after-tax costs related to the monetization

•	an additional $68 million after-tax loss on the transfer of environmental credits to the Balancing Pool upon final settlement of the Alberta PPA terminations

•	an after-tax charge of $67 million for costs associated with the acquisition of Columbia which included a $44 million deferred tax adjustment upon closing of the acquisition and $23 million of retention, severance and integration costs

•	an $18 million after-tax charge related to the maintenance and liquidation of Keystone XL assets which were expensed pending further advancement of the project

•	an after-tax restructuring charge of $6 million for additional expected future losses under lease commitments. These charges form part of a restructuring initiative, which commenced in 2015, to maximize the effectiveness and efficiency of our existing operations and reduce overall costs.

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•	increased earnings from Liquids Pipelines primarily due to higher uncontracted volumes on the Keystone Pipeline System, liquids marketing activities, and the commencement of operations on new intra-Alberta pipelines Grand Rapids and Northern Courier

•	higher contribution from U.S. Natural Gas Pipelines due to lower operating costs including synergies achieved from the Columbia acquisition

•	higher AFUDC on our rate-regulated U.S. natural gas pipelines, partially offset by our decision not to proceed with the Energy East Pipeline

•	higher earnings from Bruce Power mainly due to higher volumes resulting from fewer outage days

•	lower contribution from U.S. Power due to the monetization of our U.S. Northeast power generation assets in second quarter 2017 and the continued wind-down of our U.S. power marketing operations

•	an after-tax impairment charge in 2017 of $16 million related to obsolete Energy equipment.

•	incremental earnings from Mazatlán beginning December 2016

•	equity earnings from our investment in the Sur de Texas pipeline which records AFUDC during construction, net of interest expense on an inter-affiliate loan from TransCanada. The inter-affiliate loan interest is fully offset in interest income and other in the Corporate segment.

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•	higher uncontracted volumes on the Keystone Pipeline System

•	new intra-Alberta pipelines, Grand Rapids and Northern Courier, which began operations in the second half of 2017

•	a higher contribution from the liquids marketing business

•	higher business development activities, including advancement of Keystone XL

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

•	a gain in 2017 of $127 million before tax related to the sale of our Ontario solar assets

•	a net gain in 2017 of $15 million before tax related to the monetization of our U.S. Northeast power assets which consisted primarily of insurance recoveries for a portion of repair costs incurred during an unplanned outage at Ravenswood prior to its sale

•	in 2016, a loss of $839 million before tax related to the sale of the U.S. Northeast power assets which included an $829 million pre-tax loss on the thermal and wind package and $10 million of pre-tax disposition costs

•	in 2016, a $92 million before tax loss on the transfer of environmental credits to the Balancing Pool upon final settlement of the Alberta PPA terminations

•	unrealized gains and losses in both years from changes in the fair value of derivatives used to reduce our exposure to certain commodity price risks.

•	in 2017, a foreign exchange gain on a peso-denominated inter-affiliate loan to the Sur de Texas project for our proportionate share of the project's financing. There is a corresponding foreign exchange loss included in interest income and other on the inter-affiliate loan receivable which fully offsets this gain

•	in 2016, pre-tax integration and acquisition costs associated with the acquisition of Columbia and restructuring costs.

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•	fair value of assets and liabilities acquired in a business combination (Note 5)

•	fair value and depreciation rates of plant, property and equipment (Note 8)

•	carrying value of regulatory assets and liabilities (Note 10)

•	fair value of goodwill (Note 11)

•	fair value of intangible assets (Note 12)

•	carrying value of asset retirement obligations (Note 15)

•	provisions for income taxes, including U.S. Tax Reform (Note 16)

•	assumptions used to measure retirement and other post-retirement obligations (Note 23)

•	fair value of financial instruments (Note 24) and

•	provision for commitments, contingencies, guarantees (Note 27) and restructuring costs (Note 28).

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1	The Company records intersegment sales at contracted rates. For segmented reporting, these transactions are included as revenues in the segment providing the service, as expenses in the segment receiving the service and are eliminated on consolidation within the Corporate segment. Intersegment profit is recognized when the product or service has been provided to third parties.

2	This Income from equity investments relates to foreign exchange gains on the Company's inter-affiliate loan with Sur de Texas. The peso-denominated loan to the Sur de Texas joint venture represents the Company's proportionate share of debt financing for this joint venture. Refer to Note 9, Equity investments, for further information.

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1	The Company records intersegment sales at contracted rates. For segmented reporting, these transactions are included as revenues in the segment providing the service, as expenses in the segment receiving the service and are eliminated on consolidation within the Corporate segment. Intersegment profit is recognized when the product or service has been provided to third parties.

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1	The Company records intersegment sales at contracted rates. For segmented reporting, these transactions are included as revenues in the segment providing the service, as expenses in the segment receiving the service and are eliminated on consolidation within the Corporate segment. Intersegment profit is recognized when the product or service has been provided to third parties.

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1	At July 1, 2016 exchange rate of $1.30.

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1	Includes Foothills, Ventures LP and Great Lakes Canada.

2	Includes Bison, Portland Natural Gas Transmission System, North Baja, Tuscarora and Crossroads.

3	Includes Northern Courier, placed in-service on November 1, 2017 and White Spruce.

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4

Includes facilities with long-term PPAs that are accounted for as operating leases. The cost and accumulated depreciation of these facilities was $1,264 million and $354 million, respectively, at December 31, 2017 (2016 – $1,319 million and $335 million, respectively). Revenues of $215 million were recognized in 2017 (2016 – $212 million; 2015 – $235 million) through the sale of electricity under the related PPAs.

5	Includes Coolidge, Grandview, and Bécancour assets which operate under operating leases, along with Halton Hills and Alberta cogeneration natural gas-fired facilities.

6	Ontario solar assets are excluded from the Wind and Solar net book value at December 31, 2017 as they were sold on December 19, 2017. Refer to Note 26, Other acquisitions and dispositions, for further information.

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1	At December 31, 2017, the difference between the carrying value of the investment and the underlying equity in the net assets of Northern Border Pipeline Company was US$115 million (2016 – US$116 million) due to the fair value assessment of assets at the time of acquisition.

2	At December 31, 2017, the difference between the carrying value of the investment and the underlying equity in the net assets of Iroquois was US$41 million (2016 – US$48 million) due mainly to the fair value assessment of the assets at the time of acquisition.

3	Acquired as part of Columbia on July 1, 2016. Income from Equity investments reflects equity earnings from the date of acquisition.

4	TransCanada has an ownership interest of 60.0 per cent in Sur de Texas, which as a jointly controlled entity applies the equity method of accounting. Income from equity investments includes amounts recorded in the Corporate segment.

5	Grand Rapids was placed in service in August 2017. At December 31, 2017, the difference between the carrying value of the investment and the underlying equity in the net assets of Grand Rapids was $105 million (2016 – $86 million) due mainly to interest capitalized during construction and the fair value of guarantees.

6	Includes investments in Canaport Energy East Marine Terminal Limited Partnership and HoustonLink Pipeline Company LLC. At December 31, 2017, the Canaport Energy East Marine Terminal Limited Partnership investment was nil.

7	At December 31, 2017, the difference between the carrying value of the investment and the underlying equity in the net assets of Bruce Power was $902 million (2016 – $942 million) due to the fair value assessment of assets at the time of acquisitions.

8	At December 31, 2017, the difference between the carrying value of the investment and the underlying equity in the net assets of Portlands Energy was $73 million (2016 – $70 million) due mainly to interest capitalized during construction.

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1	These regulatory assets are underpinned by non-cash transactions or are recovered without an allowance for return as approved by the regulator. Accordingly, these regulatory assets are not included in rate base and do not yield a return on investment during the recovery period.

2	These balances represent the impact of U.S. Tax Reform. The regulatory assets and regulatory liabilities will be amortized over varying terms that approximate the expected reversal of the underlying deferred tax assets and liabilities that gave rise to the regulatory assets and liabilities. See Note 16, Income taxes, for further information.

3	Operating and debt-service regulatory assets and liabilities represent the accumulation of cost and revenue variances approved by the regulatory authority for inclusion in determining tolls for the following calendar years.

4	These balances represent the regulatory offset to pension plan and other post-retirement obligations to the extent the amounts are expected to be collected from customers in future rates.

5

Foreign exchange on long-term debt of the NGTL System represents the variance resulting from revaluing foreign currency-denominated debt instruments to the current foreign exchange rate from the historical foreign exchange rate at the time of issue. Foreign exchange gains and losses realized when foreign debt matures or is redeemed early are expected to be recovered or refunded through the determination of future tolls.

6

This balance represents the amount ANR estimates it would be required to refund to its customers for post-retirement and post-employment benefit amounts collected through its FERC-approved rates that have not been used to pay benefits to its employees. Pursuant to a FERC-approved September 2016 rate settlement, $26 million (US$21 million) of the regulatory liability balance at December 31, 2017 (2016 – $46 million, US$34 million) which accumulated between January 2007 and July 2016 will be fully amortized at July 31, 2019. The remaining $40 million (US$32 million) balance accumulated prior to 2007 is subject to resolution through future regulatory proceedings and, accordingly, a settlement period cannot be determined at this time.

7	These regulatory accounts are used to capture Canadian Mainline revenue and cost variances plus toll stabilization during the 2015-2030 settlement term.

8	This balance represents anticipated costs of removal that have been, and continue to be, included in depreciation rates and collected in the service rates of certain rate-regulated subsidiaries for future costs to be incurred.

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1

Provisions of various credit arrangements with the Company's subsidiaries can restrict their ability to declare and pay dividends or make distributions under certain circumstances. If such restrictions apply, they may, in turn, have an impact on the Company's ability to declare and pay dividends on common and preferred shares. These credit arrangements also require the Company to comply with various affirmative and negative covenants and maintain certain financial ratios. At December 31, 2017, the Company was in compliance with all debt covenants.

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1	Net of nil (2016 – $112 million; 2015 – $311 million) attributed to higher foreign tax rates.

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1	Interest rates are the effective interest rates except for those pertaining to long-term debt issued for the Company's Canadian regulated natural gas operations, in which case the weighted average interest rate is presented as approved by the regulators. Weighted average and effective interest rates are stated as at the respective outstanding dates.

2	Certain subsidiaries of Columbia have guaranteed the principal payments of Columbia’s senior unsecured notes. Each guarantor of Columbia’s obligations is required to comply with covenants under the debt indenture and in the event of default, the guarantors would be obligated to pay the principal and related interest.

3	The US$170 million and US$500 million term loan facilities were amended in September 2017 to extend the maturity dates from 2018 to 2020 and 2022, respectively.

4	These notes are secured by shipper transportation contracts, existing and new guarantees, letters of credit and collateral requirements.

5	The fair value adjustments include $242 million (2016 – $293 million) related to the acquisition of Columbia. Refer to Note 5, Acquisition of Columbia, for further information. The fair value adjustments also include a decrease of $4 million (2016 – nil) related to hedged interest rate risk. Refer to Note 24, Risk management and financial instruments, for further information.

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1	These facilities were put in place to finance a portion of the Columbia acquisition and bear interest at LIBOR plus an applicable margin. Proceeds from the issuance of common shares in fourth quarter 2016 and proceeds from the sale of the U.S. Northeast power assets were used to fully retire the remaining acquisition bridge facilities in the second quarter 2017.

2	Reflects coupon rate on re-opening of a pre-existing medium term notes (MTN) issue. The MTNs were issued at premium to par, resulting in a re-issuance yield of 2.69 per cent.

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1	These facilities were put in place to finance a portion of the Columbia acquisition and bear interest at LIBOR plus an applicable margin. Proceeds from the issuance of common shares in fourth quarter 2016 and proceeds from the sale of the U.S. Northeast power assets were used to fully retire the remaining acquisition bridge facilities in the second quarter 2017.

1

Amortization and other financial charges includes amortization of transaction costs and debt discounts calculated using the effective interest method and changes in the fair value of derivatives used to manage the Company's exposure to changes in interest rates. In 2016, this amount includes dividend equivalent payments of $109 million on the subscription receipts issued to partially fund the Columbia acquisition. Refer to Note 20, Common shares, for further information.

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1	The Junior subordinated notes are subordinated in right of payment to existing and future senior indebtedness or other obligations of TCPL.

2

The Junior subordinated notes were issued to TransCanada Trust, a financing trust subsidiary wholly-owned by TCPL. While the obligations of the Trust are fully and unconditionally guaranteed by TCPL on a subordinated basis, the Trust is not consolidated in TransCanada's financial statements since TCPL does not have a variable interest in the Trust and the only substantive assets of the Trust are junior subordinated notes of TCPL.

3	In May 2017, Junior subordinated notes of US$1 billion converted from fixed rate of 6.35 per cent to a floating rate that is reset quarterly to the three month LIBOR plus 2.21 per cent.

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1	Non-controlling interest in 2017 for the period January 1 to May 31 when TransCanada sold its remaining interest in PNGTS to TC PipeLines, LP. Refer to Note 26, Other acquisitions and dispositions for further information.

2	Non-controlling interest up to February 17, 2017 acquisition of all publicly held common units of CPPL.

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1	Net of underwriting commissions and deferred income taxes.

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1	Volatility is derived based on the average of both the historical and implied volatility of the Company's common shares.

2	On January 1, 2017, TransCanada made an election to account for forfeitures when they occur as a result of new GAAP guidance. Refer to Note 3, Accounting changes, for further information.

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1

Each of the even numbered series of preferred shares, if in existence, will be entitled to receive floating rate cumulative quarterly preferential dividends per share at an annualized rate equal to the 90-day Government of Canada Treasury bill rate (T-bill rate) plus 1.92 per cent (Series 2), 1.28 per cent (Series 4), 1.54 per cent (Series 6), 2.38 per cent (Series 8), 2.35 per cent (Series 10), 2.96 per cent (Series 12), 4.69 per cent (Series 14) and 3.85 per cent (Series 16). These rates reset quarterly with the then current T-Bill rate.

2

The odd numbered series of preferred shares, if in existence, will be entitled to receive fixed rate cumulative quarterly preferential dividends, which will reset on the redemption and conversion option date and every fifth year thereafter, at an annualized rate equal to the then five-year Government of Canada bond yield plus 1.92 per cent (Series 1), 1.28 per cent (Series 3), 1.54 per cent (Series 5), 2.38 per cent (Series 7), 2.35 per cent (Series 9), 2.96 per cent (Series 11), 4.69 per cent, subject to a minimum of 5.50 per cent (Series 13) and 3.85 per cent, subject to a minimum of 4.90 per cent (Series 15).

3	Net of underwriting commissions and deferred income taxes.

4

The floating quarterly dividend rate for the Series 2 preferred shares is 2.792 per cent and for the Series 4 preferred shares is 2.152 per cent for the period starting December 29, 2017 to, but excluding, March 29, 2018. The floating quarterly dividend rate for the Series 6 preferred shares is 2.549 per cent for the period starting October 30, 2017 to, but excluding, January 30, 2018. These rates will reset each quarter going forward.

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

2	In 2017, other comprehensive (loss)/income before reclassifications on currency translation adjustments and cash flow hedges is net of non-controlling interest losses of $159 million (2016 – $14 million losses; 2015 – $306 million gains) and gains of $4 million (2016 – $3 million gains and 2015 – nil), respectively.

3	Other comprehensive (loss)/income before reclassification on pension and other post-retirement benefit plan adjustments includes a $27 million reduction on settlements and curtailments.

4

Losses related to cash flow hedges reported in AOCI and expected to be reclassified to net income in the next 12 months are estimated to be $19 million ($14 million, net of tax) at December 31, 2017. These estimates assume constant commodity prices, interest rates and foreign exchange rates over time, however, the amounts reclassified will vary based on the actual value of these factors at the date of settlement.

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

2	These AOCI components are included in the computation of net benefit cost. Refer to Note 23, Employee post-retirement benefits for further information.

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1	The benefit obligation for the Company’s pension benefit plans represents the projected benefit obligation. The benefit obligation for the Company’s other post-retirement benefit plans represents the accumulated post-retirement benefit obligation.

2	Excludes $260 million in letters of credit provided to the Canadian DB Plan for funding purposes (2016 – $233 million).

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1	The projected benefit obligation for the pension benefit plan differs from the accumulated benefit obligation in that it includes an assumption with respect to future compensation levels.

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•	Forwards and futures contracts – agreements to purchase or sell a specific financial instrument or commodity at a specified price and date in the future

•	Swaps – agreements between two parties to exchange streams of payments over time according to specified terms

•	Options – agreements that convey the right, but not the obligation of the purchaser to buy or sell a specific amount of a financial instrument or commodity at a fixed price, either at a fixed date or at any time within a specified period.

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•	committing a portion of its expected power supply to fixed-price medium-term or long-term sales contracts, while reserving an amount of unsold supply to manage operational and price risks in its asset portfolio

•	purchasing a portion of the natural gas required to fuel certain of its power plants or entering into contracts that base the sale price of electricity on the cost of natural gas, effectively locking in a margin

•	meeting power sales commitments using power generation or fixed price purchase contracts, thereby reducing the Company's exposure to fluctuating commodity prices.

1	Fair value equals carrying value.

2	In 2017, Net income includes net realized gains of $4 million (2016 – gains of $6 million) related to the interest component of cross-currency swap settlements which are reported within Interest expense.

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•	dealing with creditworthy counterparties – a significant amount of the Company’s credit exposure is with investment grade counterparties or, if not, is generally partially supported by financial assurances from investment grade parties

•	setting limits on the amount TransCanada can transact with any one counterparty – the Company monitors and manages the concentration of risk exposure with any one counterparty, and reduces the exposure when necessary and when it is allowed under the terms of the contracts

•	using contract netting arrangements and obtaining financial assurances such as guarantees, letters of credit or cash when deemed necessary.

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1	Long-term debt is recorded at amortized cost, except for US$1.1 billion (2016 – US$850 million) that is attributed to hedged risk and recorded at fair value.

2

Net income in 2017 included unrealized gains of $4 million (2016 – gains of $2 million) for fair value adjustments attributable to the hedged interest rate risk associated with interest rate swap fair value hedging relationships on US$1.1 billion of long-term debt at December 31, 2017 (2016 – US$850 million). There were no other unrealized gains or losses from fair value adjustments to the non-derivative financial instruments.

1	Available for sale assets are recorded at fair value and included in Other current assets and Restricted investments on the Company's Consolidated balance sheet.

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

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

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

3	The realized gains or losses on the sale of LMCI restricted investment securities are determined using the average cost basis.

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1	Fair value equals carrying value.

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

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1	Fair value equals carrying value.

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

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

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

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

2	In 2017, there were no gains or losses included in Net Income relating to discontinued cash flow hedges where it was probable that the anticipated transaction would not occur (2016 – net loss of $42 million).

1	No amounts have been excluded from the assessment of hedge effectiveness. In 2017 and 2016, there were no gains or losses included in Net Income related to ineffective portions. Amounts in parentheses indicate losses recorded to OCI and AOCI.

2	Reported within Revenues on the Consolidated statement of income.

3	Reported within Interest expense on the Consolidated statement of income.

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

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

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1	There were no transfers from Level I to Level II or from Level II to Level III for the year ended December 31, 2017.

1	There were no transfers from Level I to Level II or from Level II to Level III for the year ended December 31, 2016.

1	Revenues include unrealized losses attributed to derivatives in the Level III category that were still held at December 31, 2017 of $7 million (2016 — gains of $7 million).

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

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1.	I have reviewed this annual report on Form 40-F of TransCanada Corporation;

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

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

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

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

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

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

(d)	Disclosed in this report any change in the issuer's internal control over financial reporting that occurred during the period covered by the annual report that has materially affected, or is reasonably likely to materially affect, the issuer's internal control over financial reporting.

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

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

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

1.	I have reviewed this annual report on Form 40-F of TransCanada Corporation;

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

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

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

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

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

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

(d)	Disclosed in this report any change in the issuer's internal control over financial reporting that occurred during the period covered by the annual report that has materially affected, or is reasonably likely to materially affect, the issuer's internal control over financial reporting.

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

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

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

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

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

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

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

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•	We report all health, safety and environment related hazards, potential hazards, incidents, near hits, and unsafe acts.

•	We comply with the applicable legal requirements and corporate policies that impact us in our daily work.

•	We follow the principles set out in COBE.

•	We report, through appropriate internal channels, any instances of actual or potential non-compliance with legal requirements or with COBE that we become aware of.

•	We do not retaliate against anyone for the good-faith reporting of an incident or issue.

•	We support others in making the right choices and doing the right thing.

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•	Work safely

•	Act with integrity

•	Act responsibly

•	Collaborate

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•	Audit Committee of Board of Directors

•	Chief Compliance Officer

•	Compliance Committee

•	Compliance Coordinators

•	Corporate Compliance Department

•	Human Resources and Harassment Investigation Coordinator

•	Internal Audit

•	Inspire your Personnel to act ethically by setting an ethical tone within your team.

•	Reinforce the importance of making the right choices and doing the right thing relative to other corporate objectives (for example, profits and cost management).

•	Set an example by modeling exemplary ethical business conduct.

•	Create a safe environment in which individuals are encouraged to speak up if they are aware of or suspect a legal or ethical violation through both your words and your actions.

•	Accept reports of violations that individuals may bring to you, and understand your obligation to report these issues, as appropriate, to your Compliance Coordinator, the Corporate Compliance Department, Internal Audit, the Harassment Investigation Coordinator, Privacy Officer, or the Ethics Help Line.

•	Ensure that your direct reports understand and act in accordance with all legal and ethical requirements that impact them in their jobs, that they know how to report actual or potential non-compliance with the law or COBE or to ask questions regarding ethical or legal matters, and that they complete all required ethics and compliance-related training.

•	Assist and support individuals who are unsure how to make the right choices and do the right thing.

•	Work with Human Resources, your Compliance Coordinator, the Corporate Compliance Department and Internal Audit to ensure violations of legal requirements or COBE by your direct reports are addressed appropriately (including discipline as appropriate).

•	Work with your Compliance Coordinator and the Corporate Compliance Department to reward individuals who have demonstrated exceptional positive ethical behaviour or actions that reduce the risk of legal violations.

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•	Your leader

•	Your Human Resources Consultant

•	Your Compliance Coordinator

•	Corporate Compliance Department

•	Internal Audit

•	Law Department

•	Privacy Officer

•	Harassment Investigation Coordinator

•	Safety Personnel

•	TransCanada’s EHSM Incident Management System

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Mexico	001.800.840.7907

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QUESTION:	I suspect one of my colleagues has violated part of COBE, but I’m not sure my suspicions are correct. I’m concerned I’ll be labeled a tattle-tale (or worse) if I report it. What should I do?

ANSWER:

If you suspect misconduct, you should report it so it can be investigated. If it turns out not to be an issue, there will be no harm done. Violations of the law or COBE that are not reported, however, cannot be addressed, and that can seriously undermine the Company. If that happens, we all suffer. If you report the issue, your confidentiality and identity will also be protected and if any retaliation is found to occur, it will be taken very seriously.

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•	We will work towards an incident free workplace because we believe that Zero is Real.

•	We will learn the nine Life Saving Rules and follow the, always.

•	We will SHARE our observations of safe and unsafe acts with our colleagues whether they occur at work, home or play.

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1.	Drive safely and without distraction

2.	Use the appropriate Personal Protective Equipment

3.	Conduct a pre Job Safety Analysis (JSA)

4.	Work with a valid work permit when required

5.	Obtain authorization before entering a confined space

6.	Verify isolation before work begins

7.	Protect ourselves against a fall when working at heights

8.	Follow prescribed lift plans and techniques

9.	Control excavations and ground disturbances

•	Environment

•	Health & Industrial Hygiene

•	Safety

QUESTION:	I’m working on a big project and it’s very important to the Company that it be completed on-time and on-budget. I’m concerned that I might be injured if I rush my work, but I’m feeling a lot of pressure to do so. What should I do?

ANSWER:	You should never compromise your or anyone else’s safety. If someone is pressuring you to do so, you should report the issue.

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•	Fix prices

•	Decrease capacity or volume available to customers

•	Allocate customers or markets among competitors

•	Boycott certain customers or suppliers

QUESTION:	While at a trade association meeting recently, a few competitors I was sitting with at dinner started talking about their pricing. I knew it wasn’t appropriate, so I didn’t say anything. Did I do the right thing?

ANSWER:

While you were right not to participate in the discussion, when in such a situation, it’s a good idea to take the further step of making clear to everyone that the discussion is inappropriate and that you will not participate. If the inappropriate discussion continues, you should physically remove yourself from the situation. You should also document what happened and report the matter. This will help to protect you and TransCanada in case anyone ever points to the fact that you were part of a group in which an inappropriate discussion took place.

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•

We should never give, offer, promise, or approve a gift/entertainment/benefit that could violate anti-bribery/anti-corruption legislation. Gifts/entertainment/benefits given to government officials and employees of government or government-owned entities are particularly sensitive. For more information on the provision of gifts to government officials, please refer to Gifts, Meals, Entertainment and Travel for Government Officials Standard.

•	We should never give a gift/entertainment/benefit in exchange for a business advantage (including entering into a contract or other business relationship, obtaining or giving more favourable business terms, or obtaining consent or approval), or where giving the gift/entertainment/benefit could even create the appearance that it might be for such purpose.

•	We should never give cash, cash equivalents, shares, or other securities.

•	We should never give a gift/entertainment/benefit that could be considered offensive or in poor taste, or that could damage TransCanada’s reputation.

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QUESTION:	I am very politically active. Is that allowed?

ANSWER:	TransCanada encourages you to participate in the political process as an individual, in accordance with your own political views and the laws and regulations governing this activity. In doing so, however, you may not use TransCanada’s name, nor indicate that you represent TransCanada, unless you have been authorized to do so.

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QUESTION:	I’m not a lawyer. How can I be expected to know all of the laws that might apply to my job or even be able to understand them?

ANSWER:

While you are not expected to know all of the ins and outs of every law, you do need to have a basic understanding of the different areas of law that impact you in your job, so that you can spot potential issues and seek help from an expert. Your leaders and the ethics and compliance organization (particularly your Compliance Coordinator, the Corporate Compliance Department and the Law Department) are also available to help you if you have questions about your legal obligations and are available to provide training on legal requirements that may be applicable to your team.

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•	Regulated transmission providers may not give undue preference to any customer, whether it is an affiliated TransCanada entity or not - all customers must be treated equally.

•	Regulated Personnel must function independently of non-regulated Personnel (e.g. they cannot perform the same jobs or report to the same leaders).

•	Regulated and shared Personnel must not share, or act as a conduit for the sharing of regulated information* with non-regulated Personnel.

•	Any violations of the Inter-Affiliate Codes/Standards of Conduct must be reported to the Corporate Compliance Department, since TransCanada is legally required to either publicly post such information on its web site or report it to our regulators.

•	Non-regulated entities must pay their fair share of any costs incurred by our regulated transmission providers, so as not to burden our transmission customers with costs our non-regulated entities benefit from.

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•	Invitations to events and trips, including but not limited to sporting events, golf rounds, skiing or fishing trips, and other special events should not be accepted, except as provided for below. Attendance at such events may provide an opportunity to network with suppliers, but could be mistaken as a sign of a preferential relationship.

•	Invitations to events which may be considered lavish in nature should not be accepted.

•	Frequency of attendance at events with the same supplier should be carefully considered and discussed with your leader prior to attendance to avoid the perception of any preferential treatment.

•	Occasional promotional gifts (such as pens, coffee mugs, calendars) may be accepted as a customary business courtesy, provided that the frequency of gift must not exceed 4 times per calendar year and a value of $50 per gift or total more than $100 in aggregate for the calendar year.

•	Invitations to industry events such as conferences and conventions have not changed and continue to require leader approval.

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•	Owning, controlling or directing a material financial interest (greater than one per cent) in a competitor, or in a vendor, supplier, customer or other business which does or seeks to do business with TransCanada

•	Being involved in a business that competes with TransCanada or that does or seeks to do business with TransCanada

•	Outside business activities that interfere with your day-to-day responsibilities at TransCanada. Unless specifically approved by your leader, you are expected to spend your full time and attention performing your job during your hours of work

•	An outside business activity that requires you to violate your confidentiality or other obligations to TransCanada

•	An outside business activity that would be detrimental to TransCanada’s reputation

•	Any outside directorship including a charitable or non-profit organization, sporting organization, or school board, if that activity is detrimental to TransCanada

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QUESTION:	I want to hire someone who I know has a family member already working for TransCanada. Is that allowed?

ANSWER:

Yes, it is acceptable to hire a person (Employees and CWCs) that has a family member already working for TransCanada provided the new hire is not in a Direct or Indirect Reporting relationship with their family member. The onus is on all Personnel to notify Corporate Compliance when they become aware of a Family or Other Significant Personal Relationship where there is a Direct or Indirect Reporting relationship within the Company.

QUESTION:	I own units of a mutual fund that invests in shares of one of our suppliers. Is that a problem?

ANSWER:	If your investment in the supplier is through a mutual fund, it is unlikely that you would own more than one per cent of the stock of the supplier. Because of the indirect nature of the investment, it is also less of a concern than if you owned the shares directly. Your ownership of mutual fund units is not a problem.

QUESTION:	I have been invited by a supplier to attend the rodeo at the Calgary Stampede. Can I accept the invitation and attend the event?

ANSWER:

All TransCanada Personnel must ensure they are acting in a manner which is fair and impartial to our supplier community and which does not create a real or perceived conflict of interest with those with whom we do business. As such, attendance at this event would only be acceptable if the supplier had invited customers from other companies as well. Prior written approval must be received from your Vice-President to ensure that the number of TransCanada Personnel and other customers at the event is appropriate.

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QUESTION:	I have been invited to a movie event by a company that is a supplier to TransCanada or has the potential to become a supplier to TransCanada that I have a relationship with. Can I attend this event?

ANSWER:	Employees can accept invitations from suppliers/potential suppliers for events where multiple clients are in attendance provided they have received approval from their Vice-President prior to attending.

QUESTION:

One of TransCanada’s existing auto leasing suppliers has invited me to attend their annual product roll-out, which will be held in Las Vegas. It is a big event that all customers are invited to. The supplier has offered to pay for all flights and accommodation, in addition to the meals that will be provided as part of the event. The supplier’s contract is not currently up for renewal, and I am not the person responsible for making the decision whether to renew. Can I attend?

ANSWER:

Since TransCanada has an existing business relationship with the supplier and is not currently involved in any renewal or other negotiations and since the event is a business-related event attended by many customers as well as supplier representatives, you may attend with your leader’s approval. However, given the location of the event, the business benefit to TransCanada should be carefully considered and discussed with your leader. Additionally, since the value of the event is significant, the supplier’s payment for flights and accommodation could create a perception of conflict and/or an obligation on the part of TransCanada. As a result, flights and accommodation should be paid for by TransCanada. You may accept the meals provided by the supplier as part of the event.

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QUESTION:	I sometimes use my Company computer to access Facebook or Twitter during my lunch break and I talk about my personal life. Is that allowed?

ANSWER:

Limited personal use of corporate assets to access social media on your own time is acceptable; however, you need to keep in mind that you are using a corporate computer and accessing the Internet through a TransCanada IP address. So, you must be careful to ensure that you do not post inappropriate or offensive content, nor do or say anything that could reflect poorly on TransCanada. TransCanada also has the right to monitor your personal use of its equipment and systems and you should not expect your use of TransCanada assets for these purposes to be private. TransCanada regularly monitors employee use of its equipment and systems and you may be subject to disciplinary action for any inappropriate or offensive use that comes to TransCanada’s attention as a result of such monitoring.

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•	Your leader

•	Your Human Resources Consultant

•	Your Compliance Coordinator

•	Corporate Compliance Department

•	Internal Audit

•	Law Department

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