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

•	expectations about strategies and goals for growth and expansion

•	expected cash flows and future financing options available, including portfolio management

•	expected dividend growth

•	expected future credit ratings

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

•	expected capital expenditures and contractual obligations

•	expected regulatory processes and outcomes, including the impact of recent Federal Energy Regulatory Commission (FERC) policy changes (2018 FERC Actions)

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

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

•	expected industry, market and economic conditions.

•	regulatory decisions and outcomes, including final outcomes of the 2018 FERC Actions

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

•	integrity and reliability of our assets

•	anticipated construction costs, schedules and completion dates

•	access to capital markets, including portfolio management

•	expected industry, market and economic conditions

•	inflation rates and commodity prices

•	interest, tax and foreign exchange rates

•	nature and scope of hedging.

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•	our ability to successfully implement our strategic priorities and whether they will yield the expected benefits

•	our ability to implement a capital allocation strategy aligned with maximizing shareholder value

•	the operating performance of our pipeline and energy assets

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

•	the amount of capacity payments and revenues from our energy business due to plant availability

•	production levels within supply basins

•	construction and completion of capital projects

•	costs for labour, equipment and materials

•	the availability and market prices of commodities

•	access to capital markets on competitive terms

•	interest, tax and foreign exchange rates

•	performance and credit risk of our counterparties

•	regulatory decisions and outcomes of legal proceedings, including arbitration and insurance claims

•	changes in environmental and other laws and regulations

•	competition in the pipeline and energy sectors

•	unexpected or unusual weather

•	acts of civil disobedience

•	cyber security and technological developments

•	economic conditions in North America as well as globally

•	our ability to effectively anticipate and assess changes to government policies and regulations.

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

•	expectations about strategies and goals for growth and expansion

•	expected cash flows and future financing options available, including portfolio management

•	expected dividend growth

•	expected future credit ratings

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

•	expected capital expenditures and contractual obligations

•	expected regulatory processes and outcomes, including the impact of recent Federal Energy Regulatory Commission (FERC) policy changes (2018 FERC Actions)

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

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

•	expected industry, market and economic conditions.

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•	regulatory decisions and outcomes, including final outcomes of the 2018 FERC Actions

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

•	integrity and reliability of our assets

•	anticipated construction costs, schedules and completion dates

•	access to capital markets, including portfolio management

•	expected industry, market and economic conditions

•	inflation rates and commodity prices

•	interest, tax and foreign exchange rates

•	nature and scope of hedging.

•	our ability to successfully implement our strategic priorities and whether they will yield the expected benefits

•	our ability to implement a capital allocation strategy aligned with maximizing shareholder value

•	the operating performance of our pipeline and energy assets

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

•	the amount of capacity payments and revenues from our energy business due to plant availability

•	production levels within supply basins

•	construction and completion of capital projects

•	costs for labour, equipment and materials

•	the availability and market prices of commodities

•	access to capital markets on competitive terms

•	interest, tax and foreign exchange rates

•	performance and credit risk of our counterparties

•	regulatory decisions and outcomes of legal proceedings, including arbitration and insurance claims

•	changes in environmental and other laws and regulations

•	competition in the pipeline and energy sectors

•	unexpected or unusual weather

•	acts of civil disobedience

•	cyber security and technological developments

•	economic conditions in North America as well as globally

•	our ability to effectively anticipate and assess changes to government policies and regulations.

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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 HSSE 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

•	prevention, mitigation and management of risks related to HSSE matters, including climate-change related risks which may adversely impact TransCanada

•	sustainability matters, including social, environmental and climate-change related matters

•	management's approach to voluntary public disclosure on HSSE matters.

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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.

•	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;

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(b)	obtain reports from management, the Company’s senior internal auditing executive and the external auditor and report to the Board on the status and adequacy of the Company’s efforts to ensure its businesses are conducted and its facilities are operated in an ethical, legally compliant and socially responsible manner, in accordance with the Company’s COBE;

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

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

(e)

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

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

•	expectations about strategies and goals for growth and expansion

•	expected cash flows and future financing options available, including portfolio management

•	expected dividend growth

•	expected future credit ratings

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

•	expected capital expenditures and contractual obligations

•	expected regulatory processes and outcomes, including the impact of the 2018 FERC Actions

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

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

•	expected industry, market and economic conditions.

•	regulatory decisions and outcomes, including final outcomes of the 2018 FERC Actions

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

•	integrity and reliability of our assets

•	anticipated construction costs, schedules and completion dates

•	access to capital markets, including portfolio management

•	expected industry, market and economic conditions

•	inflation rates and commodity prices

•	interest, tax and foreign exchange rates

•	nature and scope of hedging.

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•	our ability to successfully implement our strategic priorities and whether they will yield the expected benefits

•	our ability to implement a capital allocation strategy aligned with maximizing shareholder value

•	the operating performance of our pipeline and energy assets

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

•	the amount of capacity payments and revenues from our energy business due to plant availability

•	production levels within supply basins

•	construction and completion of capital projects

•	costs for labour, equipment and materials

•	the availability and market prices of commodities

•	access to capital markets on competitive terms

•	interest, tax and foreign exchange rates

•	performance and credit risk of our counterparties

•	regulatory decisions and outcomes of legal proceedings, including arbitration and insurance claims

•	changes in environmental and other laws and regulations

•	competition in the pipeline and energy sectors

•	unexpected or unusual weather

•	acts of civil disobedience

•	cyber security and technological developments

•	economic conditions in North America as well as globally

•	our ability to effectively anticipate and assess changes to government policies and regulations.

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•	comparable EBITDA

•	comparable EBIT

•	comparable earnings

•	comparable earnings per common share

•	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 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	Includes Cartier Wind assets until sold in 2018 and U.S. Northeast power generation assets and Ontario solar assets until sold in 2017.

1	Includes Cartier Wind assets until sold in 2018 and U.S. Northeast power generation assets and Ontario solar assets until sold in 2017.

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1.

Make a limited Natural Gas Act (NGA) Section 4 filing to reduce rates by the reduction in its cost-of-service shown in its Form 501-G. For any pipeline electing this option, FERC guarantees a three-year moratorium on NGA Section 5 rate investigations if the pipeline’s Form 501-G shows the pipeline’s estimated ROE as being 12 per cent or less. Under the Final Rule, and notwithstanding the Revised Policy Statement discussed above, a pipeline organized as an MLP is not required to eliminate its income tax allowance, but instead can reduce its rates to reflect the reduction in the federal corporate income tax rate. Alternatively, the MLP pipeline can eliminate its tax allowance along with its ADIT used for rate-making purposes. In situations where the ADIT balance is a liability, this elimination would have the effect of increasing the pipeline’s rate base for rate-making purposes;

2.	Commit to file either a pre-packaged uncontested rate settlement or a general Section 4 rate case if it believes that using the limited Section 4 option will not result in just and reasonable rates. For pipelines that committed to file either by December 31, 2018, FERC would not initiate a Section 5 investigation of its rates prior to that date;

3.	File a statement explaining its rationale for why it does not believe the pipeline's rates must change; or

4.	Take no other action. FERC will consider whether to initiate a Section 5 investigation of any pipeline that has not submitted a limited Section 4 rate filing or committed to file a general Section 4 rate case.

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1	Amounts reflect our proportionate share of joint venture costs where applicable and 100 per cent of costs related to wholly-owned assets and assets held through TC PipeLines, LP.

2	Represents 100 per cent of required capital prior to potential joint venture partners or project financing.

3	Carrying value is net of fourth quarter 2018 receipts from the LNG Canada participants for the reimbursement of approximately $0.5 billion of pre-FID costs pursuant to project agreements. Refer to the Significant Events section in Canadian Natural Gas Pipelines for additional details.

4	The CFE has recognized force majeure events for these pipelines and approved the payment of fixed capacity charges in accordance with their respective TSAs. Payments will be recognized as revenue when the pipelines are placed in service.

5	Reflects our proportionate share of the Unit 6 Major Component Replacement program costs, expected to be in service in 2023, and amounts to be invested under the Asset Management program through 2023.

6	Includes non-recoverable maintenance capital expenditures from all segments and is primarily comprised of our proportionate share of maintenance capital expenditures for Bruce Power and other Energy assets.

7	Reflects U.S./Canada foreign exchange rate of 1.36 at December 31, 2018.

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1	Amounts reflect our proportionate share of joint venture costs where applicable.

2	Carrying value reflects amount remaining after impairment charge recorded in 2015, along with additional amounts capitalized from January 1, 2018.

3	Regulatory approvals have been obtained and additional commercial support is being pursued.

4	Reflects our proportionate share of Major Component Replacement program costs for Units 3, 4, 5, 7 and 8, and the remaining Asset Management program costs beyond 2023.

5	Reflects U.S./Canada foreign exchange rate of 1.36 at December 31, 2018.

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

2	Refer to the Financial condition section on page 74 for details on common and preferred share dividends.

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•	a $143 million after-tax gain related to the sale of our interests in the Cartier Wind power facilities

•	a $115 million deferred income tax recovery from an MLP regulatory liability write-off resulting from the 2018 FERC Actions

•	a $52 million recovery of deferred income taxes as a result of finalizing the impact of U.S. Tax Reform

•	a $27 million income tax recovery related to the sale of our U.S. Northeast power generation assets

•	$25 million of after-tax income recognized on the Bison contract terminations

•	a $140 million after-tax impairment charge on Bison

•	a $15 million after-tax goodwill impairment charge on Tuscarora

•	an after-tax net loss of $4 million related to our U.S. Northeast power marketing contracts. These were excluded from Energy's comparable earnings beginning in 2018 as the wind-down of these contracts is not considered part of our underlying operations.

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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 on the monetization of our U.S. Northeast power generation assets

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

•	a $7 million income tax recovery related to the realized loss on a third party sale of Keystone XL project assets

•	a $954 million after-tax impairment charge for the Energy East pipeline and related projects following 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.

•	an $873 million after-tax loss on U.S. Northeast power generation assets held for sale

•	$28 million of income tax recoveries related to the realized loss on a third party sale of Keystone XL project assets

•	$273 million of after-tax costs associated with the acquisition of Columbia

•	an after-tax charge of $42 million for Keystone XL costs related to the maintenance and liquidation of project assets

•	a $656 million after-tax impairment of Ravenswood goodwill

•	a $244 million after-tax impairment charge on the carrying value and settlement of our Alberta PPAs

•	an after-tax charge of $16 million for restructuring mainly related to expected future losses under lease commitments

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

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•	higher contribution from U.S. Natural Gas Pipelines mainly due to increased earnings from Columbia Gas and Columbia Gulf growth projects placed in service, additional contract sales on ANR and Great Lakes, and amortization of net regulatory liabilities recognized as a result of U.S. Tax Reform

•	higher contribution from Liquids Pipelines primarily due to higher volumes on the Keystone Pipeline System, increased earnings from liquids marketing activities and earnings from intra-Alberta pipelines placed in service in the second half of 2017

•	higher contribution from Canadian Natural Gas Pipelines primarily due to the recovery of increased depreciation as a result of higher rates approved in both the Mainline NEB 2018 Decision and the NGTL 2018-2019 Settlement, as well as higher overall pre-tax rate base earnings, partially offset by lower incentive earnings and flow-through income taxes

•	lower earnings from U.S. Power mainly due to the sales of our U.S. Northeast power generation assets in second quarter 2017

•	lower earnings from Bruce Power primarily due to lower volumes resulting from higher outage days and lower results from contracting activities.

•	changes in comparable EBITDA described above

•

higher depreciation primarily in Canadian Natural Gas Pipelines due to increased depreciation rates approved in the Mainline NEB 2018 Decision and the NGTL 2018-2019 Settlement (these amounts are fully recovered as reflected in the increase in comparable EBITDA described above, having no net impact on comparable earnings) as well as higher depreciation related to new projects placed in service in 2017 and 2018

•	higher interest expense primarily as a result of additional long-term debt issuances in 2018 and the full year impact of long-term debt and junior subordinated notes issuances in 2017, net of maturities, as well as lower capitalized interest, partially offset by the repayment of the Columbia acquisition bridge facilities in June 2017

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•	lower income tax expense primarily due to reduced income tax rates resulting from U.S. Tax Reform and lower flow-through income taxes in Canadian rate-regulated pipelines.

•	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

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

•	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.

•	changes in comparable EBITDA described above

•	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 notes issuances in 2017, net of maturities

•	higher depreciation primarily from the Columbia acquisition in 2016 and projects placed in service

•	higher AFUDC on our rate-regulated U.S. natural gas pipelines as well as on 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 the recovery of certain Coastal GasLink project costs and the termination of the Prince Rupert Gas Transmission (PRGT) project.

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 Columbia Gas and Columbia Gulf projects coming in service

•	higher equity income from Bruce Power due to increased contract pricing

•	growth in the average investment base for the NGTL System

•	completion of the Napanee generating station

•	commencement of operations on the Sur de Texas Pipeline.

•	the dilutive impact of common shares issued in 2018 under our DRP and Corporate ATM Program and expected to be issued in 2019 under our DRP

•	higher interest expense as a result of long-term debt issuances, net of maturities, and lower capitalized interest after placing assets in service

•	the sale of our interests in the Cartier Wind power facilities

•	the expected sale of our Coolidge generating station

•	the uncertain impact of recent U.S. Tax Reform legislation and proposed regulations on the cost of financing certain of our U.S. operations.

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•	wholly-owned natural gas pipelines – 81,500 km (50,500 miles); and

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

•	placed approximately $0.6 billion of projects in service

•	announced four new expansion programs on our NGTL System totaling $4.1 billion with in-service dates between 2019 and 2022

•	received an amending order and Certificate of Public Convenience and Necessity (CPCN) from the NEB approving construction of the North Montney Mainline facilities and guidance on related tolling matters

•	received NEB approval on the NGTL 2018-2019 Revenue Requirement Settlement (2018-2019 Settlement), as filed

•	received the NEB Decision on the Canadian Mainline 2018-2020 Tolls Application (NEB 2018 Decision) approving all elements of the filing except for the amortization period of the LTAA

•	secured 670 TJ/d (625 MMcf/d) of new natural gas transportation contracts on the Canadian Mainline for North Bay Junction Long Term Fixed Price (NBJ LTFP) service from the WCSB to markets in Ontario, Québec, New Brunswick, Nova Scotia and the Northeastern U.S.

•	proceeding with the estimated $6.2 billion Coastal GasLink pipeline project.

•	placed in service in 2018 and early 2019 approximately US$5.8 billion of projects including Leach XPress, WB XPress, Cameron Access and partial in-service of Mountaineer XPress

•	originated an additional US$0.5 billion of growth projects

•	filed Form 501-Gs and uncontested rate settlements in response to the 2018 FERC Actions, which impacted rates for our U.S. natural gas pipelines and storage assets to varying degrees. Refer to the 2018 FERC Actions section for more detail.

•	placed Topolobampo in operational service

•	continued construction on our Sur de Texas, Villa de Reyes and Tula pipeline projects.

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•	natural gas-fired electric-power generation

•	petrochemical and industrial facilities

•	Alberta oil sands

•	exports to Mexico to fuel power generation facilities.

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1	Includes results from Foothills, Ventures LP, Great Lakes Canada, and our share of equity income from our investment in TQM, as well as general and administrative and business development costs related to our Canadian Natural Gas 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 reflect our earnings from TC PipeLines, LP's ownership interests in GTN, Great Lakes, Iroquois, Northern Border, Bison, Portland, North Baja and Tuscarora, as well as general and administrative costs related to TC PipeLines, LP. 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 Portland to TC PipeLines, LP and the remaining 11.81 per cent to TC PipeLines, LP on June 1, 2017.

3	TC PipeLines, LP periodically conducted ATM issuances which decreased our ownership in TC PipeLines, LP. Effective March 2018, this program ceased to be utilized. Our ownership interest in TC PipeLines, LP was 25.5 per cent as at December 31, 2018 compared to 25.7 per cent and 26.8 per cent at December 31, 2017 and December 31, 2016, respectively.

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	Results reflect earnings from our direct ownership interests in Crossroads, as well as Iroquois and Portland until June 1, 2017, our effective ownership in Millennium and Hardy Storage, and general and administrative and business development costs related to U.S. natural gas pipelines.

6	Results reflect earnings attributable to portions of TC PipeLines, LP, Portland (until June 1, 2017) and Columbia Pipeline Partners LP (CPPL) (until February 17, 2017) that we do not own.

7	These amounts were recorded in TC PipeLines, LP. The pre-tax impact to us is 25.5 per cent of these amounts net of non-controlling interests.

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•	a $722 million non-cash asset impairment charge related to Bison

•	a $79 million non-cash goodwill impairment charge related to Tuscarora

•	$130 million of termination payments received on two of Bison’s transportation contracts, which was recorded in Revenues.

•	increased earnings from Columbia Gas and Columbia Gulf growth projects placed in service, additional contract sales on ANR and Great Lakes, and improved commodity prices and throughput volumes in Midstream

•	increased earnings due to the amortization of the net regulatory liabilities that were recorded at the end of 2017, partially offset by a reduction in certain rates on Columbia Gas as a result of U.S. Tax Reform

•	a US$10 million refund from GTN to its recourse rate customers as per the 2018 GTN Settlement. Refer to the 2018 FERC Actions section for additional details.

•	a full year contribution from the Columbia assets acquired in 2016

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

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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.

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•	higher revenues from operations as a result of changes in timing of revenue recognition

•	incremental earnings from a CRE tariff increase

•	the $12 million impairment of our equity investment in TransGas in 2017, recorded in Other above

•	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 interest expense on this inter-affiliate loan is fully offset in Interest income and other in the Corporate segment.

•	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 which is fully offset in Interest income and other in the Corporate segment.

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•	commenced construction on the White Spruce pipeline

•	obtained shipper commitments on all available Keystone XL project capacity

•	completed construction of an additional one million barrels of crude oil storage at our Cushing Terminal in Oklahoma.

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•	expanding and leveraging our existing infrastructure

•	protecting and optimizing the value of our existing assets

•	expanding the transportation services that we offer and extend into adjacent jurisdictions

•	extending into emerging growth opportunities.

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•	a $1,256 million pre-tax impairment charge for the Energy East pipeline and related projects

•	$34 million (2016 – $52 million) of pre-tax costs related to Keystone XL for the maintenance and liquidation of project assets which were expensed pending further advancement of the project.

•	higher contracted and uncontracted volumes on the Keystone Pipeline System

•	higher contribution from liquids marketing activities from improved margins and volumes

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

•	lower business development costs as a result of capitalizing Keystone XL expenditures in 2018.

•	higher uncontracted volumes on the Keystone Pipeline System

•	a higher contribution from liquids marketing activities from improved margins and volumes

•	contributions from 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 for which costs were expensed

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

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•	advanced the life extension program at Bruce Power with the final Unit 6 Major Component Replacement (MCR) cost and schedule duration estimate verified by the IESO. The Unit 6 MCR outage is scheduled to begin in early 2020

•	completed the sale of our interests in the Cartier Wind power facilities

•	entered into an agreement to sell our Coolidge power generation station for approximately US$465 million

•	completed monetization of the U.S. Northeast power retail contracts as part of the continued wind-down of our U.S. Northeast power marketing business

•	construction is substantially complete on the Napanee natural gas-fired power plant with expected in-service in second quarter 2019.

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1	Our share of power generation capacity.

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•	Power

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

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1	Includes 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	In second quarter 2017, we completed the sales of our U.S. Northeast power generation assets.

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

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•	a pre-tax gain in 2018 of $170 million related to the sale of our interests in the Cartier Wind power facilities. Refer to the Significant events section for more details

•

a pre-tax net loss of $5 million in 2018 related to our U.S. Northeast power marketing contracts, including a gain in first quarter 2018 on the sale of our retail contracts. These results have been excluded from Energy's comparable earnings in 2018 as we do not consider the wind-down of the remaining contracts part of our underlying operations. The contract portfolio is scheduled to run-off through to mid-2020. Refer to the Significant events section for more details on the sale of our retail contracts

•	a pre-tax net gain in 2017 of $484 million (2016 – loss of $844 million) related to the monetization of our U.S. Northeast power generation 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

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

•	a $1,085 million pre-tax 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

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

•	lower earnings from U.S. Power mainly due to the sales of the U.S. Northeast power generation assets in second quarter 2017

•	decreased earnings from Bruce Power primarily due to lower volumes resulting from higher outage days and lower results from contracting activities. Additional financial and operating information on Bruce Power is provided below

•	decreased Natural Gas Storage results due to pipeline constraints in the Alberta natural gas market which limited our ability to access our storage facilities and resulted in lower realized natural gas storage price spreads

•	lower earnings from Western and Eastern Power due to the sales of our Ontario solar assets in December 2017 and our interest in the Cartier Wind power facilities in October 2018, partially offset by higher Western Power realized margins on higher generation volumes.

•	lower earnings from U.S. Power mainly due to the sales of the U.S. Northeast power generation assets in second quarter 2017 and the wind-down of our U.S. power marketing contracts

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

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

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1	Net of amounts recorded to reflect operating cost efficiencies shared with the IESO.

2	Represents our 48.3 per cent (2017 – 48.4 per cent; 2016 – 48.5 per cent) ownership interest in Bruce Power. Sales volumes include deemed generation.

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

4	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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1	Reported in Income from equity investments on the Consolidated statement of income.

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1	At December 31, 2018, we recorded an additional $21 million in Plant operating costs and other in the Consolidated statement of income and $21 million as a regulatory asset on the Consolidated balance sheet related to costs that are expected to be recovered through regulatory and tolling structures in future periods (2017 – $3 million and $3 million, respectively).

•	long-term debt and junior subordinated note issuances in 2018 and 2017, net of maturities. See the Financial condition section for further details on long-term debt

•	lower capitalized interest primarily due to the completion of Grand Rapids and Northern Courier in the second half of 2017, partially offset by ongoing construction at Napanee and the recommencement of capitalization of Keystone XL costs in 2018

•	higher levels of short-term borrowing

•	final repayment of the Columbia acquisition bridge facilities in June 2017 resulting in lower interest and debt amortization expense.

•	long-term debt and junior subordinated notes issuances in 2017 and 2016, net of maturities. Refer to 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.

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•	unrealized losses on risk management activities in 2018 compared to unrealized gains in 2017, reflecting the strengthening of the U.S. dollar at the end of 2018. These amounts have been excluded from comparable earnings

•

higher interest income combined with a lower 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, resulting in no impact on net income. The offsetting currency-related gain and loss amounts are excluded from comparable earnings

•	realized losses in 2018 compared to realized gains in 2017 on derivatives used to manage our net exposure to foreign exchange rate fluctuations on U.S. dollar-denominated income

•	lower recovery in 2018 related to carrying charges on Coastal GasLink project costs incurred

•	$10 million recognized on the termination of the PRGT project in 2017.

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

•	recovery of $32 million related to carrying charges on Coastal GasLink project costs incurred, and amounts recognized on the termination of the PRGT project in 2017

•	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 in 2017 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, resulting in no impact on net income. The offsetting currency-related gain and loss amounts are excluded from comparable earnings.

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•	a $538 million charge related to the non-controlling interests portion of a $722 million Bison asset impairment charge recorded by TC PipeLines, LP

•	a $59 million charge related to the non-controlling interests portion of a $79 million Tuscarora goodwill impairment charge recorded by TC PipeLines, LP

•	$97 million in income related to the non-controlling interests portion of Bison contract termination payments of $130 million received from certain customers and recorded by TC PipeLines, LP.

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1	Includes non-controlling interests.

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

•	approximately $11.8 billion of unutilized, unsecured credit facilities

•	our access to capital markets, including through our DRP and Corporate ATM programs, if deemed appropriate.

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•	the 2016 acquisitions of Columbia and Ironwood

•	higher capital spending in 2017

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

•	recovery of PRGT project costs.

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

•	sold Ravenswood, Ironwood, Kibby Wind and Ocean State Power for proceeds of approximately US$2.029 billion, before post-closing adjustments

•	sold TC Hydro for proceeds of approximately US$1.07 billion, before post-closing adjustments

•	sold our Ontario solar assets for proceeds of approximately $541 million, before post-closing adjustments.

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1	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.

2	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.

3	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.

•	senior debt

•	hybrid securities

•	preferred shares

•	asset sales

•	project financing

•	potential involvement of strategic or financial partners.

•	common shares issued under our DRP

•	common shares issued under our Corporate ATM program

•	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 HSSE Committee oversees operational, health, safety, sustainability and environmental risk

•	the Audit Committee oversees management's role in managing 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.

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•	overall HSSE 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

•	prevention, mitigation and management of risks related to HSSE matters, including climate change related risks which may adversely impact TransCanada

•	sustainability matters, including social, environmental and climate-change related matters

•	management's approach to voluntary public disclosure on HSSE matters.

•	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 as well as new regulations.

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•	environmental laws and regulations and their interpretations and enforcement 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 investigations or agreements

•	new contaminated sites may be found, 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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•

Environment and Climate Change Canada (ECCC) issued the final Methane Reduction Regulation on April 26, 2018. The regulations detail requirements to reduce methane emissions through operational and capital modifications. There are multiple timeframes for compliance depending on the provision, beginning in 2020. Alberta, British Columbia and Saskatchewan have drafted their own methane regulations which take the place of the federal regulation in those jurisdictions. However, for the federally regulated facilities in these jurisdictions, the federal methane regulation will be applicable. For most of TransCanada’s Canadian pipeline assets, it is likely that the federal regulation will be applicable. Compliance will involve equipment retrofits, frequent leak detection and repair surveys and measurements to quantify emission reductions and associated annual reporting. Power facilities are not affected by 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

•

in Alberta, the CCIR replaced the SGER effective January 1, 2018. This regulation requires established industrial facilities with GHG emissions above a certain threshold to reduce their emissions below an intensity baseline. The CCIR covers our natural gas pipelines and Energy assets in Alberta. Canadian 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 has a GHG cap-and-trade program 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 are recovered through commercial contracts. The Canadian Mainline natural gas pipeline facilities in Québec are also subject to this program and compliance instruments have been purchased in order to comply with the requirements of this initiative

•

Ontario repealed its cap-and-trade program in 2018. The compliance credits purchased under the previous cap-and-trade program have been retired by the new government. With the repeal of the cap-and-trade program, Ontario does not have carbon pricing regulation, therefore, TransCanada’s electricity and pipeline facilities in this jurisdiction are subject to the Canadian Federal OBPS as of January 1, 2019. Federal OBPS applies to electric generation facilities with annual emissions greater than 50,000 tonnes of CO2 equivalent. At this time we do not anticipate any material impact to the financial performance of our Ontario natural gas facilities as a result of this program.

•

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. In 2018, with direction from the Trump administration, the EPA is working on reducing the requirements of this regulation

•	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

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

•	California has a GHG cap-and-trade program under the WCI GHG emissions market. In California, TransCanada has costs associated with the cap-and-trade program with respect to our electricity marketing activities.

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on November 6, 2018, the Government of Mexico published a new regulation that established guidelines for the prevention and control of methane emissions in the hydrocarbon sector, which will impact our Mexico natural gas pipelines. Companies will have one year to comply with the regulations which include equipment requirements such as installation of vapor recovery systems and detection and repair of leaks, as well as administrative requirements including the identification of methane emissions and implementation of a program for emissions reporting.

•

the Government of Canada has finalized a Federal plan to have carbon pricing in place in all Canadian jurisdictions. ECCC is in the process of finalizing the Federal OBPS regulation to impose carbon pricing for larger industrial facilities and will set federal benchmarks for GHG emissions for various industry sectors. This new federal regulation will apply to the provinces of Ontario, Manitoba, Saskatchewan, and New Brunswick as those jurisdictions do not currently have a provincial plan in place for carbon pricing or meet the criteria of the Federal plan. This may result in increased costs for current pipeline and energy facilities in those jurisdictions

•

the Government of Canada has proposed a Federal plan, the Clean Fuel Standard (CFS), to implement a single national standard encompassing all fuel types and applications. As part of the CFS, compressor station electrification is proposed by the Federal Government as a mechanism to reduce natural gas transmission GHG emissions. This could have negative impacts to our Canadian natural gas compression assets. Efforts to influence this policy are being managed through CEPA and CGA. Different components of the CFS regulations are expected to be released through 2019

•

the Government of Saskatchewan has announced that certain large industrial emitters will be subject to a provincially proposed carbon pricing system based on an OBPS approach, which has potential to impact our Canadian natural gas pipelines in that province. This proposed system only partially meets the Federal plan and, therefore, the Federal OBPS will apply to emission sources not covered by the proposed system, including electricity generation and natural gas pipelines

•

New York State announced its intent to adopt regulations to reduce methane from existing, new and modified facilities. New York has not yet proposed regulations, but the Governor announced the State’s plan to achieve its clean energy goals by 2030, which includes a 40% reduction from 1990 emissions levels. Impacts to our facilities are dependent on the specifics of the regulations once they are proposed, but it is likely that our compression facilities in New York State would be affected

•	Maryland announced its intent to establish fugitive methane regulations for compressor stations. Maryland has been working with operators, including TransCanada, to develop regulations to reduce greenhouse gases. TransCanada has only one compressor station in Maryland, and it is electric, therefore, no significant impact is expected.

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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.

•	in our power generation business, we manage our exposure to fluctuating commodity prices through long-term contracts and hedging activities including selling and purchasing power and natural gas in forward markets

•	in our non-regulated natural gas storage business, our exposure to seasonal natural gas price spreads is managed with a portfolio of third-party storage capacity contracts and through offsetting purchases and sales of natural gas in forward markets to lock in future positive margins

•	in our liquids marketing business, we enter into pipeline and storage terminal capacity contracts. We fix a portion of our exposure on these contracts by entering into derivative instruments to manage our variable price fluctuations that arise from physical liquids transactions.

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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.

2	Effective January 1, 2018, U.S. Power is no longer included in comparable EBIT.

•	cash and cash equivalents

•	accounts receivable

•	available-for-sale assets

•	the fair value of derivative assets

•	a loan receivable.

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•	a $722 million pre-tax impairment of the carrying value of our investment in Bison ($140 million after-tax and net of non-controlling interests)

•	a $79 million pre-tax impairment of the carrying value of Tuscarora's goodwill ($15 million after-tax and net of non-controlling interests).

•	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.

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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 on a net basis in Revenues. Realized and unrealized gains and losses on interest rate and foreign exchange held-for-trading derivative instruments are included on a net basis in interest expense and interest income and other, respectively.

2	In 2018 and 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	There are no amounts recognized in earnings that were excluded from effectiveness testing. Refer to the notes to our Consolidated financial statements.

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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.

•	regulatory decisions

•	developments outside of the normal course of operations

•	newly constructed assets being placed in service

•	demand for uncontracted transportation services

•	liquids marketing activities

•	certain fair value adjustments.

•	weather

•	customer demand

•	market prices for natural gas and power

•	planned and unplanned plant outages

•	acquisitions and divestitures

•	certain fair value adjustments

•	developments outside of the normal course of operations

•	newly constructed assets being placed in service.

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•	a $143 million after-tax gain related to the sale of our interests in the Cartier Wind power facilities

•	a $115 million deferred income tax recovery from an MLP regulatory liability write-off resulting from the 2018 FERC Actions

•	a $52 million recovery of deferred income taxes as a result of finalizing the impact of U.S. Tax Reform

•	a $27 million income tax recovery related to the sale of our U.S. Northeast power generation assets

•	$25 million of after-tax income recognized on the Bison contract terminations

•	a $140 million after-tax impairment charge on Bison

•	a $15 million after-tax goodwill impairment charge on Tuscarora

•	an after-tax net loss of $7 million related to our U.S. Northeast power marketing contracts.

•	after-tax income of $8 million related to our U.S. Northeast power marketing contracts.

•	an after-tax loss of $11 million related to our U.S. Northeast power marketing contracts.

•	an after-tax gain of $6 million related to our U.S. Northeast power marketing contracts, primarily due to income recognized on the sale of our retail contracts.

•	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 generation 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 $9 million after-tax charge related to the maintenance and liquidation of Keystone XL assets.

•	an incremental net loss of $12 million after tax related to the monetization of our U.S. Northeast power generation assets

•	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.

•	a $265 million net after-tax gain related to the monetization of our U.S. Northeast power generation assets 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.

•	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 generation assets

•	a charge of $7 million after tax related to the maintenance of Keystone XL assets

•	a $7 million income tax recovery related to the realized loss on a third party sale of Keystone XL project assets.

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•	a $143 million after-tax gain related to the sale of our interests in the Cartier Wind power facilities

•	a $115 million deferred income tax recovery from an MLP regulatory liability write-off resulting from the 2018 FERC Actions

•	a $52 million recovery of deferred income taxes as a result of finalizing the impact of U.S. Tax Reform

•	a $27 million income tax recovery related to the sale of our U.S. Northeast power generation assets

•	$25 million of after-tax income recognized on the Bison contract terminations

•	a $140 million after-tax impairment charge on Bison

•	a $15 million after-tax goodwill impairment charge on Tuscarora

•	an after-tax net loss of $7 million related to our U.S. Northeast power marketing contracts.

•	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 generation 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 $9 million after-tax charge related to the maintenance and liquidation of Keystone XL assets.

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•	higher contribution from Canadian Natural Gas Pipelines primarily due to the recovery of increased depreciation as a result of higher rates approved in both the Mainline NEB 2018 Decision and the NGTL 2018-2019 Settlement, as well as higher flow-through taxes and incentive earnings

•	higher contribution from U.S. Natural Gas Pipelines mainly due to increased earnings from Columbia Gas and Columbia Gulf growth projects placed in service, additional contract sales on ANR and Great Lakes, and amortization of net regulatory liabilities recognized as a result of U.S. Tax Reform

•	higher contribution from Liquids Pipelines primarily due to higher volumes on the Keystone Pipeline System, increased earnings from liquids marketing activities and earnings from intra-Alberta pipelines placed in service in the second half of 2017

•	higher revenues from Mexico Natural Gas Pipelines as a result of changes in timing of revenue recognition

•	lower earnings from Bruce Power primarily due to lower volumes resulting from higher outage days.

•	changes in comparable EBITDA described above

•

higher depreciation primarily in Canadian Natural Gas Pipelines due to increased depreciation rates approved in the Mainline NEB 2018 Decision and the NGTL 2018-2019 Settlement (these amounts are fully recovered as reflected in the increase in comparable EBITDA described above, having no net impact on comparable earnings) as well as higher depreciation related to new projects placed in service in 2017 and 2018

•	higher interest expense primarily as a result of long-term debt and junior subordinated notes issuances, net of maturities

•	lower interest income and other as a result of realized losses in 2018 compared to realized gains in 2017 on derivatives used to manage net exposure to foreign exchange rate fluctuations on U.S. dollar-denominated income.

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•	a $722 million non-cash asset impairment charge related to Bison

•	a $79 million non-cash goodwill impairment charge related to Tuscarora

•	$130 million of termination payments received on two of Bison’s transportation contracts which was recorded in Revenues.

•	increased earnings from Columbia Gas and Columbia Gulf growth projects placed in service and additional contract sales on ANR and Great Lakes

•	increased earnings due to the amortization of the net regulatory liabilities recognized in 2017, partially offset by a reduction in certain rates on Columbia Gas, as a result of U.S. Tax Reform.

•	higher revenues from operations as a result of changes in timing of revenue recognition

•	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 interest expense on this inter-affiliate loan is fully offset in Interest income and other in the Corporate segment

•	incremental earnings from a CRE tariff increase.

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•	a $1,256 million pre-tax impairment charge in 2017 for the Energy East pipeline and related projects

•	$11 million of pre-tax costs in 2017 related to Keystone XL for the maintenance and liquidation of project assets which were expensed pending further advancement of the project

•	unrealized gains from changes in the fair value of derivatives related to our liquids marketing business.

•	higher contracted and uncontracted volumes on the Keystone Pipeline System

•	higher contribution from liquids marketing activities from improved margins and volumes

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

•	lower business development costs as a result of capitalizing Keystone XL expenditures in 2018

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

•	a pre-tax gain in 2018 of $170 million related to the sale of our interests in the Cartier Wind power facilities

•	a pre-tax net loss of $10 million related to our U.S. Northeast power marketing contracts. These results have been excluded from Energy's comparable earnings in 2018 as we do not consider the wind-down of the remaining contracts part of our underlying operations. The contract portfolio is scheduled to run-off through to mid-2020

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

•	a pre-tax net gain of $15 million in 2017 related to the monetization of our U.S. Northeast power generation assets

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

•	decreased earnings from Bruce Power primarily due to lower volumes resulting from higher outage days

•	decreased Western and Eastern Power results due to the sales of our Cartier Wind power facilities in October 2018 and our Ontario solar assets in December 2017, partially offset by higher Western Power realized margins on higher generation volumes

•	lower Natural Gas Storage results primarily due to pipeline constraints in the Alberta natural gas market which limited our ability to access our storage facilities and resulted in lower realized natural gas storage price spreads.

•	foreign exchange gains 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.

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•	fair value of plant, property and equipment and equity investments (Notes 8 and 9)

•	fair value of goodwill (Note 11)

•	fair value of intangible assets (Note 12) and

•	fair value of assets and liabilities acquired in a business combination (Note 26).

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

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

•	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

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

•	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 and

•	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 or indirect competition.

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•	when the asset is expected to be retired

•	the scope and cost of abandonment and reclamation activities that are required and

•	appropriate inflation and discount rates.

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1	Includes intersegment eliminations.

2

The Company records intersegment sales at contracted rates. For segmented reporting, these transactions are included as Intersegment revenues in the segment providing the service and Plant operating costs and other in the segment receiving the service. These transactions are eliminated on consolidation. Intersegment profit is recognized when the product or service has been provided to third parties or otherwise realized.

3

Income from equity investments includes foreign exchange gains on the Company's inter-affiliate loan with Sur de Texas. The offsetting foreign exchange losses on the inter-affiliate loan are included in Interest income and other. The peso-denominated loan to the Sur de Texas joint venture represents the Company's proportionate share of long-term debt financing for this joint venture. Refer to Note 9, Equity investments, for further information.

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1	Includes intersegment eliminations.

2

The Company records intersegment sales at contracted rates. For segmented reporting, these transactions are included as Intersegment revenues in the segment providing the service and Plant operating costs and other in the segment receiving the service. These transactions are eliminated on consolidation. Intersegment profit is recognized when the product or service has been provided to third parties or otherwise realized.

3

Income/(loss) from equity investments includes foreign exchange gains on the Company's inter-affiliate loan with Sur de Texas. The offsetting foreign exchange losses on the inter-affiliate loan are included in Interest income and other. The peso-denominated loan to the Sur de Texas joint venture represents the Company's proportionate share of long-term debt financing for this joint venture. Refer to Note 9, Equity investments, for further information.

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1	Includes intersegment eliminations.

2

The Company records intersegment sales at contracted rates. For segmented reporting, these transactions are included as Intersegment revenues in the segment providing the service and Plant operating costs and other in the segment receiving the service. These transactions are eliminated on consolidation. Intersegment profit is recognized when the product or service has been provided to third parties or otherwise realized.

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1

Other revenues include income from the Company's marketing activities, financial instruments and lease arrangements within each operating segment. Income from lease arrangements includes certain long term PPAs, as well as certain liquids pipelines capacity and transportation arrangements. These arrangements are not in the scope of the new guidance, therefore, revenues related to these contracts are excluded from revenues from contracts with customers. Refer to Note 24, Risk management and financial instruments, for further information on income from financial instruments.

2	Other revenues from U.S. Natural Gas Pipelines include the amortization of the net regulatory liabilities resulting from U.S. Tax Reform. Refer to Note 16, Income taxes, for further information.

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1	Adjustment relates to contract assets previously included in Accounts receivable.

2	Adjustment relates to contract liabilities previously included in Accounts receivable.

1	Recorded as part of Other current assets on the Consolidated balance sheet.

2	Recorded as part of Intangibles and other assets on the Consolidated balance sheet.

3	Comprised of deferred revenue recorded in Accounts payable and other on the Consolidated balance sheet. During the year ended December 31, 2018,

4	Comprised of deferred revenue recorded in Other long-term liabilities on the Consolidated balance sheet.

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1.	The original expected duration of the contract is one year or less.

2.	The Company recognizes revenue from the contract that is equal to the amount invoiced, where the amount invoiced represents the value to the customer of the service performed to date. This is referred to as the "right to invoice" practical expedient.

3.

The variable revenue generated from the contract is allocated entirely to a wholly unsatisfied performance obligation or to a wholly unsatisfied promise to transfer a distinct good or service that forms part of a single performance obligation in a series. A single performance obligation in a series occurs when the promises under a contract are a series of distinct services that are substantially the same and have the same pattern of transfer to the customer over time.

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1	Included in Accounts payable and other on the Consolidated balance sheet.

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1	Includes Foothills, Ventures LP, Great Lakes Canada and Coastal GasLink.

2	Includes Portland, North Baja, Tuscarora and Crossroads as well as Bison for 2017. Bison's remaining carrying value was fully impaired at December 31, 2018.

3	Includes tanks that are accounted for as operating leases. The cost and accumulated depreciation of these facilities were $194 million and $23 million, respectively, at December 31, 2018 (2017 – $184 million and $19 million, respectively), while revenues of $15 million were recognized in 2018 (2017 – $16 million; 2016 – $16 million).

4	Certain costs related to the Keystone XL project were recorded in Plant, property and equipment at December 31, 2017. In 2018, these costs were reclassified to Capital projects in development as the Company recommenced capitalizing Keystone XL development costs.

5

Includes Northern Courier and White Spruce. Northern Courier is accounted for as an operating lease and was placed in service on November 1, 2017. The cost and accumulated depreciation of this facility were $1,130 million and $32 million, respectively, at December 31, 2018 (2017 – $1,111 million and $4 million, respectively), while revenues of $142 million were recognized in 2018 (2017 – $20 million).

6

Includes Coolidge, Grandview, Bécancour, Halton Hills and the Alberta cogeneration natural gas-fired facilities. Coolidge, Grandview and Bécancour have long-term PPAs that are accounted for as operating leases. The cost and accumulated depreciation of these facilities were $655 million and $268 million, respectively, at December 31, 2018 (2017 – $1,264 million and $354 million, respectively). At December 31, 2018, the cost and accumulated depreciation of Coolidge were reclassified to Assets held for sale. Refer to Note 6, Assets held for sale, for further information. Revenues of $216 million were recognized in 2018 (2017 – $215 million; 2016 – $212 million) through the sale of electricity under the related PPAs for these assets.

7	The Company closed the sale of its Cartier Wind power assets on October 24, 2018. Refer to Note 26, Acquisitions and dispositions, for further information.

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1	At December 31, 2018, 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 (2017 – US$115 million) due to the fair value assessment of assets at the time of acquisition.

2	At December 31, 2018, the difference between the carrying value of the investment and the underlying equity in the net assets of Iroquois was US$41 million (2017 – US$41 million) due mainly to the fair value assessment of the assets at the time of acquisition.

3	Acquired as part of Columbia Pipeline Group, Inc. (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 foreign exchange gains and losses recorded in the Corporate segment which are fully offset in Interest income and other in the Consolidated statement of income.

5	Grand Rapids was placed in service in August 2017. At December 31, 2018, the difference between the carrying value of the investment and the underlying equity in the net assets of Grand Rapids was $102 million (2017 – $105 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, 2018 and 2017, the Canaport Energy East Marine Terminal Limited Partnership investment was nil.

7	At December 31, 2018, the difference between the carrying value of the investment and the underlying equity in the net assets of Bruce Power was $870 million (2017 – $902 million) due to the fair value assessment of assets at the time of acquisitions.

8	At December 31, 2018, the difference between the carrying value of the investment and the underlying equity in the net assets of Portlands Energy was $73 million (2017 – $73 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	Operating and debt-service regulatory assets and liabilities represent the accumulation of cost and revenue variances approved by the regulator for inclusion in determining tolls for the following calendar year.

3	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 or refunded to customers in future rates.

4

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.

5

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, $11 million (US$8 million) of the regulatory liability balance at December 31, 2018 (2017 – $26 million; US$21 million) which accumulated between January 2007 and July 2016 will be fully amortized at July 31, 2019. The remaining $43 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.

6	These regulatory accounts are used to capture Canadian Mainline revenue and cost variances plus toll stabilization during the 2015-2030 settlement term. The 2018 LTAA balance of $1,015 million consists of $932 million to be amortized over two years with the remaining balance to be amortized over 45 years.

7	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 operations for future costs to be incurred.

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

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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, 2018, the Company was in compliance with all debt covenants.

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1	Net of nil (2017 – nil, 2016 – $112 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. The effective interest rate is calculated by discounting the expected future interest payments, adjusted for loan fees, premium and discounts. 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$500 million term loan facility was amended in September 2017 to extend the maturity dates from 2018 to 2022.

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

5	The fair value adjustments include $232 million (2017 – $242 million) related to the acquisition of Columbia. The fair value adjustments also include a decrease of $2 million (2017 – $4 million) related to hedged interest rate risk. Refer to Note 24, Risk management and financial instruments, for further information.

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1	Reflects coupon rate on re-opening of a pre-existing senior unsecured notes issue. The notes were issued at a discount to par, resulting in a re-issuance yield of 4.439 per cent.

2	Reflects coupon rate on re-opening of a pre-existing medium term notes (MTN) issue. The MTNs were issued at a discount to par, resulting in a re-issuance yield of 3.41 per cent.

3	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 second quarter 2017.

4	Reflects coupon rate on re-opening of a pre-existing 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 were fully retired in second quarter 2017.

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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.

1	The effective interest rate is calculated by discounting the expected future interest payments using the coupon rate and any estimated future rate resets, adjusted for loan fees and discounts.

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

3	In May 2017, Junior subordinated notes of US$1 billion converted from a 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.

4

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.

5	The coupon rate is initially a fixed interest rate for the first ten years and converts to a floating rate thereafter.

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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 Portland to TC PipeLines, LP. Refer to Note 26, Acquisitions and dispositions for further information.

2	Non-controlling interest up to February 17, 2017 acquisition of all publicly held common units of Columbia Pipeline Partners LP.

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1	Net of issue costs and deferred income taxes.

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1	Expected life is based on historical exercise activity.

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

3	On January 1, 2017, TransCanada made an election to account for forfeitures when they occur as a result of new GAAP guidance.

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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 3.633 per cent and for the Series 4 preferred shares is 2.993 per cent for the period starting December 31, 2018 to, but excluding, March 29, 2019. The floating quarterly dividend rate for the Series 6 preferred shares is 3.086 per cent for the period starting October 30, 2018 to, but excluding, January 30, 2019. 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 2018, other comprehensive income before reclassifications on currency translation adjustments and cash flow hedges are net of non-controlling interest gains of $166 million (2017 – $159 million losses; 2016 – $14 million losses) and losses of $1 million (2017 – $4 million gains and 2016 – $3 million gains), 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 $15 million ($11 million, net of tax) at December 31, 2018. 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.

5	Amounts reclassified from AOCI on cash flow hedges and equity investments are net of non-controlling interest gains of $5 million and $2 million, respectively.

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1	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.

3	Amounts reclassified from AOCI on cash flow hedges and equity investments are net of non-controlling interest gains of $5 million (2017 – nil , 2016 – nil) and $2 million (2017 – nil, 2016 – nil), respectively.

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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 a $17 million letter of credit provided to the Canadian DB Plan for funding purposes (2017 – $27 million).

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

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1	Service cost and other components of net benefit cost are included in Plant operating costs and other in the Consolidated statement of income.

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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.

•	In the Company's power generation business, TransCanada manages the exposure to fluctuating commodity prices through long-term contracts and hedging activities including selling and purchasing power and natural gas in forward markets

•	In the Company's non-regulated natural gas storage business, TransCanada's exposure to seasonal natural gas price spreads is managed with a portfolio of third-party storage capacity contracts and through offsetting purchases and sales of natural gas in forward markets to lock in future positive margins

•	In the Company's liquids marketing business, TransCanada enters into pipeline and storage terminal capacity contracts. TransCanada fixes a portion of its exposure on these contracts by entering into derivative instruments to manage its variable price fluctuations that arise from physical liquids transactions.

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1	Fair value equals carrying value.

2	No amounts have been excluded from the assessment of hedge effectiveness.

3	In 2018, Net income includes net realized gains of $2 million (2017 – gains of $4 million) related to the interest component of cross-currency swap settlements which are reported within Interest expense.

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1	Long-term debt is recorded at amortized cost, except for US$750 million (2017 – US$1.1 billion) that is attributed to hedged risk and recorded at fair value.

2

Net income in 2018 included unrealized losses of $2 million (2017 – gains of $4 million) for fair value adjustments attributable to the hedged interest rate risk associated with interest rate swap fair value hedging relationships on US$750 million of long-term debt at December 31, 2018 (2017 – US$1.1 billion). There were no other unrealized gains or losses from fair value adjustments to the non-derivative financial instruments.

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

2	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.

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	The realized gains and 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	At December 31, 2018 and 2017, adjustments for discontinued hedging relationships included in these balances were nil.

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

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 on a net basis in Revenues. Realized and unrealized gains and losses on interest rate and foreign exchange held-for-trading derivative instruments are included on a net basis in Interest expense and Interest income and other, respectively.

2	In 2018 and 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. Amounts in parentheses indicate losses recorded to OCI and AOCI.

1	Refer to Note 22, Other comprehensive income/(loss) and accumulated other comprehensive loss, for the components of OCI related to derivatives in cash flow hedging relationships including the portion attributable to non-controlling interests.

2	There are no amounts recognized in earnings that were excluded from effectiveness testing.

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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, 2018.

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	Revenues include unrealized losses of $5 million attributed to derivatives in the Level III category that were still held at December 31, 2018 (2017 – unrealized losses of $7 million).

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

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•	approximately $4.6 billion for its Canadian natural gas pipelines, primarily related to construction costs associated with the construction of the Coastal GasLink and NGTL System pipeline projects

•	approximately $0.1 billion for its U.S. natural gas pipelines, primarily related to construction costs associated with Columbia Gas and Columbia Gulf growth projects

•	approximately $0.3 billion for its Mexico natural gas pipelines, primarily related to construction of the Sur de Texas, Villa de Reyes and Tula pipeline projects

•	approximately $0.4 billion for its Liquids pipelines, primarily related to the development of Keystone XL and construction of White Spruce

•	approximately $0.7 billion for its Energy business, primarily related to its proportionate share of commitments for Bruce Power's life extension program

•	approximately $0.1 billion for its Corporate segment related to various information technology services agreements.

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

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1	At December 31, 2018, the Company recorded an additional $21 million in Plant operating costs and other in the Consolidated statement of income and $21 million as a regulatory asset on the Consolidated balance sheet related to costs that are recoverable through regulatory and tolling structures in future periods (2017 – $3 million and $3 million, respectively).

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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.

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

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.

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

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.

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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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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.