450 – 1 Street SW Calgary, Alberta T2P 5H1

Tel: (403) 920-2603 Fax: (403) 920-2347 Email: [email protected] May 14, 2019 Filed Electronically National Energy Board Suite 210, 517 Tenth Avenue SW Calgary, AB T2R 0A8

Attention: Ms. Sheri Young, Secretary of the Board Dear Ms. Young:

Re: Great Lakes Pipeline Canada Ltd. (GLC) Financial Resources Plan File: OF-Gen-06 FRR On February 15, 2019,1 the National Energy Board (NEB or Board) directed all gas and non-major oil companies regulated under the National Energy Board Act (the NEB Act) to file an assessment of their Absolute Liability Limits by March 8, 2019,2 and for all gas companies to file a Financial Resources Plan by May 14, 2019, in accordance with the Pipeline Financial Requirements Regulations (Regulations) and the Pipeline Financial Requirements Guidelines issued on March 29, 2019.3 In response to the Board’s direction, GLC encloses its Financial Resources Plan. The attached information confirms that GLC has access to financial resources in excess of the minimum requirements under the Regulations. If the Board requires additional information regarding this filing, please contact me by phone at 403-920-2603 or by email at [email protected].

Yours truly, Great Lakes Pipeline Canada Ltd. Original signed by Bernard Pelletier Director, Regulatory Tolls and Tariffs Canadian Natural Gas Pipelines

Enclosure

1 Board Letter to all Pipeline Companies regulated under the NEB Act and all Interested Persons: Draft Pipeline Financial Requirements Guidelines, and Implementation of Financial Resource Requirements, dated February 15, 2019. 2 GLC filed its assessment of its Absolute Liability Limits on March 8, 2019. (NEB Filing ID: A98242-1) 3 Board Letter to all Pipeline Companies regulated under the NEB Act and all Interested Persons: Pipeline Financial Requirements Guidelines, and Implementation of Financial Resource Requirements, dated March 29, 2019. Great Lakes Pipeline Canada Ltd. Financial Resources Plan

1.0 FINANCIAL RESOURCES PLAN

Bill C-46, the Pipeline Safety Act amended the National Energy Board Act (the NEB Act) to add absolute liability limits and financial resource requirements. As a result, the NEB Act requires an authorized company operating a pipeline to maintain a minimum level of financial resources equal to its absolute liability limit in the event of an unintended or uncontrolled release from the pipeline.

In its letter dated February 15, 2019,1 the National Energy Board (NEB or Board) directed all companies who have not yet done so to submit a financial resources plan for assessment as it relates to the financial resource requirements in the NEB Act (Financial Resources Plan).

In accordance with the Pipeline Financial Requirements Regulations (Regulations) and the Board’s Pipeline Financial Requirements Guidelines (Guidelines), the Financial Resources Plan for Great Lakes Pipeline Canada Ltd. (GLC) is outlined below and describes the types and amount of financial resources available, key terms and timing of access in order to respond to an unintended or uncontrolled release from its pipelines.

GLC is a “company” as that term is defined in the NEB Act. GLC transports gas to and from a point located on the international border between Canada and the United States below the St. Clair River, where the Facilities interconnect to those of Great Lakes Gas Transmission Limited Partnership (GLGT) into Ontario near Dawn.

The GLC system is subject to federal jurisdiction and regulation by the Board. GLC is a wholly-owned subsidiary of TransCanada PipeLines Limited (TransCanada) which in turn, is a wholly-owned subsidiary of TC Energy Corporation (TC Energy).2 TransCanada operates the GLC system pursuant to an operating agreement between TransCanada and GLC. GLC is the authorization holder for the GLC system.

GLC is a Gas Class 1 Company based on an absolute liability limit assessment submitted on March 8, 2019,3 and is therefore required to maintain $200 million in financial resources.

The GLC Financial Resources Plan is outlined in Table 1 and demonstrates the required financial resources of $200 million; consisting of a parental guarantee for $100 million by its parent, TransCanada (Parental Guarantee), and $100 million in insurance through access to TC Energy’s general liability insurance program.

1 NEB Letter to all Pipeline Companies regulated under the NEB Act and all Interested Persons: Draft Pipeline Financial Requirements Guidelines, and Implementation of Financial Resource Requirements, dated February 15, 2019. 2 On May 3, 2019, TransCanada Corporation filed articles of amendment to change its name to TC Energy. 3 NEB Filing ID: A98242-1.

May 14, 2019 Page 1 of 5

Great Lakes Pipeline Canada Ltd. Financial Resources Plan

This submission includes the following attachments; (i) a corporate structure diagram (Appendix 1), (ii) a draft form of the Parental Guarantee (Appendix 2), (iii) an insurance certificate (Appendix 3) to which GLC is a named insured up to an amount in excess of the $100 million required to be maintained as a financial resource, (iv) TransCanada’s financial statements (Appendix 4) and (v) TransCanada’s most recent credit rating reports (Appendix 5).

Table 1: Financial Resources Plan

Authorization Holder Name: Great Lakes Pipeline Canada Ltd. Capacity Risk Gas Class 1 Value: Absolute Liability $200,000.000 Limit: Timing of Access As at Parent Company Authorization (business December 31, 2018 (TransCanada) Holder (GLC) Total days) Cash $362,000,000 $0 $362,000,000 1 Lines of Credit $3,600,000,0001 $0 $3,600,000,0001 1-3 (undrawn portion) Commercial Paper $4,010,000,0001 $0 $4,010,000,0001 Same Day (undrawn portion of program) Parent/Affiliate $100,000,000 $100,000,000 5 Guarantees (from TransCanada to GLC)2 Total short-term, $7,972,000,000 $100,000,000 $8,072,000,000 accessible within five business days Insurance > $100,000,0003 > $100,000,000 > $100,000,000 N/A4 Total Other > $100,000,000 > $100,000,000 > $100,000,000 Notes: 1. TransCanada either directly or as co-borrower maintains $10,150 million of committed credit facilities, a portion of which is reserved to backstop $6,550 million of commercial paper programs of which $2,540 million was utilized at December 31, 2018. All U.S. dollar amounts have been converted using an exchange rate of 1.30 USD/CAD. 2. Table 1 has been modified from that provided in the Board's Guidelines to include the Parental Guarantee within the Total short-term accessible within five business days section as the Parental Guarantee is available within five business days. 3. TransCanada, through the TC Energy general liability policy, maintains insurance well in excess of the amount identified to which is also available to GLC. 4. The general liability policy is indemnity based, which is normal and customary. Indemnity based policies act to reimburse the insured for covered losses only after it first funds claims.

Page 2 of 5 May 14, 2019

Great Lakes Pipeline Canada Ltd. Financial Resources Plan

1.1 Parental Guarantee

TransCanada is prepared to issue the Parental Guarantee to GLC for $100 million to provide for an explicit mechanism for access to the funds for the purposes of the Financial Resources Plan outlined in Table 1. Access to funds under the Parental Guarantee will be readily available within five business days, such that the GLC Financial Resources Plan will have more than the minimum required readily accessible portion required of $10 million or 5% of the total absolute liability limit. The Parental Guarantee has been drafted in accordance with the Guidelines. The key terms of the agreement are summarized as follows:

• TransCanada will provide GLC with unconditional, on-demand access to funds. • TransCanada will provide funds within five business days of written demand from GLC. • The guarantee will be irrevocable, non-transferrable and non-assignable, except with prior written approval of the Board or any successor administrative body. • The guarantee will not allow termination, amendment, or modification, except with prior written approval of the Board or any successor administrative body. • The guarantee will remain in force unless the Board or any successor administrative body has granted approval to terminate the guarantee or granted approval of alternative types of financial resources. • The Board will be served notice of event of default within two business days.

A draft Parental Guarantee is included in Appendix 2.

1.2 Insurance Coverage

TC Energy has general liability insurance that provides coverage for liabilities that may arise from the GLC system including sudden and accidental pollution coverage. The general liability policy is indemnity based, which is normal and customary. Indemnity based policies act to reimburse the insured for covered losses after expenditures are first made by the insured. However, in the event of a release, insurers will be put on notice of potential claims within 24 hours.

The policy covers liabilities that may arise as a result of the operational and maintenance activities of the pipeline, meter and compressor station facilities. The policy would also respond to the legal liability for third party claims, clean-up and remediation costs.

TC Energy’s general liability insurance program includes GLC as a named insured and is made up of multiple layers of insurance in an amount in excess of US$500 million. While GLC has access to more than $100 million in insurance, it only relies on $100 million as part of its Financial Resources Plan.

May 14, 2019 Page 3 of 5

Great Lakes Pipeline Canada Ltd. Financial Resources Plan

An insurance policy is a commercially negotiated agreement and is influenced by market conditions at the time of placement. The availability and terms of coverage such as exclusions will be negotiated as part of the insurance renewal process. Insurance limits would temporarily erode due to a specific claim or claims within a policy year, but would be reinstated for the balance of the insurance year to the extent available.

1.3 Financial Capacity of TransCanada

In accordance with the requirements for parental guarantees under the Guidelines, this section describes the financial resources of TransCanada. These financial resources are made available to GLC through cash pooling arrangements that contribute to GLC having access to significantly more financial resources than that specified in the Financial Resource Plan and for what is required for a Gas Class 1 Company. TransCanada’s strong financial capacity is illustrated in the audited 2018 consolidated financial statements and unaudited Q1 2019 interim financial statements that are provided in Appendix 4.

TransCanada maintains considerable reserves of cash and cash equivalents associated with its ongoing business requirements. These reserves are available to immediately fund emergency response operations. Short term liquidity is further provided for through $10.15 billion of committed credit facilities, a portion of which is reserved to backstop two well supported commercial paper programs totaling $6.55 billion of which $2.54 billion was outstanding at year end, resulting in total available unused credit capacity of $7.61 billion ($3.60 billion in committed credit facilities and $4.01 billion of unused commercial paper capacity). As at December 31, 2018, there were no outstanding draws on the credit facilities.

TransCanada’s committed credit facilities provide direct access to; (i) $3.0 billion of committed capacity under its 5-year credit facility, (ii) US$1 billion under its 3-year committed credit facility, and (iii) US$4.5 billion under its 364-day committed credit facility (see Table 2). These committed facilities can be drawn at any time on same day notice, the access to which would not be impacted by an uncontrolled or unintended release event.

Table 2: Committed Syndicated, Extendible, Senior Unsecured Credit Facilities

Borrower Description Matures Aggregate Size TransCanada Supports commercial paper program December 2023 $3.0 billion and for general corporate purposes TransCanada as Supports commercial paper programs December 2019 US$4.5 billion co-borrower and for general corporate purposes TransCanada as Used for general corporate purposes December 2021 US$1.0 billion co-borrower

Page 4 of 5 May 14, 2019

Great Lakes Pipeline Canada Ltd. Financial Resources Plan

TransCanada has a long history of conservative financial management and remains well positioned in the marketplace to be able to continue to access capital on an ongoing basis to fund its operations, including the financial capacity to backstop potential obligations in the context of those arising from the NEB Act.

TransCanada has been assigned “A-” level investment grade credit ratings by Fitch Ratings, Inc., and by DBRS Limited. Moody’s Investor Service, Inc., and Standard & Poor’s Financial Services LLC Global Ratings have assigned TransCanada a “BBB+” rating with stable outlook. The most recent rating agency reports are provided in Appendix 5.

May 14, 2019 Page 5 of 5

Great Lakes Pipeline Canada Ltd. Financial Resources Plan Appendix 1

Corporate Structure Diagram

Great Lakes Pipeline Canada Ltd. Financial Resources Plan Appendix 1

Corporate Structure Diagram

TC Energy Corporation (TC Energy)

100%

TransCanada PipeLines Limited (TransCanada)

100%

Great Lakes Pipeline Canada Ltd. (GLC)

May 14, 2019 Page 1 of 1 Great Lakes Pipeline Canada Ltd. Financial Resources Plan Appendix 2

TransCanada Parental Guarantee to GLC GUARANTEE

This Guarantee dated effective July 11, 2019, is made by TransCanada PipeLines Limited, a Canadian corporation (“Guarantor”) in favor of Great Lakes Pipeline Canada Ltd. (“Creditor”).

WITNESSETH:

WHEREAS, pursuant to the National Energy Board Act (the "Act") and the Pipeline Financial Requirements Regulations, (the "Regulations"), as the same may be amended or replaced from time to time, the National Energy Board ("NEB") requires the Creditor to maintain certain financial resources in specific types and amounts (the "Financial Resource Requirement"); and

WHEREAS, the issuance of a parental guarantee evidences satisfaction of a portion of the Financial Resource Requirement; and

WHEREAS, as the parent company of the Creditor, it is in the interest of the Guarantor to ensure that the Creditor complies with the Financial Resource Requirement and the Regulations;

NOW, THEREFORE, Guarantor agrees with Creditor as follows:

1. Guarantee. Guarantor unconditionally, absolutely and irrevocably guarantees to Creditor and its successors and assigns the full and prompt payment when due of the financial obligations for which the Creditor becomes liable under subsection 48.12(5) of the Act and the Regulations, , in relation to an unintended or uncontrolled release of oil, gas or other commodity from the Creditor's pipeline (the “Guaranteed Obligations”). The aggregate amount of Guaranteed Obligations guaranteed under this Guarantee by Guarantor shall not exceed $100 million in CDN currency. This is a guarantee of payment and not of collection.

2. Guarantee absolute. The liability of Guarantor is unconditional, absolute and irrevocable and shall remain in full force and effect without regard to, and shall not be released, suspended, discharged, impaired, terminated, limited or otherwise affected by, any circumstance or occurrence whatsoever.

3. Representations and warranties. Guarantor represents and warrants to Creditor that:

a) Guarantor (i) is duly organized, validly existing and in good standing under the laws of the jurisdiction of its organization or formation and (ii) has the power and authority to own its property and assets, to transact the business in which it is engaged and to enter into and perform its obligations under this Guarantee;

b) the execution, delivery, observance and performance of this Guarantee by Guarantor do not and will not conflict with or result in a breach of the articles, certificate, by-laws, or other organizational or formation documents of Guarantor, or of the terms or provisions of any judgment, law, decree, order, statute, rule, regulation or agreement, indenture or instrument to which Guarantor is a party or by which Guarantor or its assets are bound or to which Guarantor or its assets are subject, or constitute a default under any of them;

c) this Guarantee has been duly authorized, executed and delivered by Guarantor;

d) this Guarantee constitutes a legal, valid and binding obligation of Guarantor enforceable against Guarantor in accordance with its terms, except as enforceability may be limited

by principles of equity, or by bankruptcy, insolvency, reorganization, moratorium or other similar laws; and

e) this Guarantee reasonably may be expected to benefit Guarantor, either directly or indirectly.

4. Demand for payment. Guarantor shall pay to Creditor, within five (5) business days (as determined in the location where payment is to be made) after demand by Creditor and in immediately available funds, all Guaranteed Obligations due under the Agreement. Guarantor shall make all such payments in accordance with the instructions set forth in such demand. There are no other requirements of notice, presentment or demand that are required to be made under this Guarantee.

5. Event of Default. The occurrence of any one or more of the following events or circumstances constitutes an Event of Default under this Guarantee:

a) The Guarantor or the Creditor ceases to carry on business;

b) if the Guarantor or the Creditor shall: (i) apply for or consent to the appointment of a receiver, trustee or liquidator of itself or of all or a substantial part of its assets; (ii) make a general assignment for the benefit of creditors; (iii) commence any cause, proceeding or other action under any existing or future law relating to bankruptcy, insolvency, reorganization or relief of debtors seeking to have an order for relief entered with respect to it, or seeking to adjudicate a bankrupt or insolvent, or seeking reorganization, arrangement, adjustment, winding up, liquidation, dissolution, composition or other relief with respect to it or its debts or an arrangement with creditors or taking advantage of any insolvency law or proceeding for the relief of debtors, or file an answer admitting the material allegations of a petition filed against it in any bankruptcy reorganization or insolvency proceeding; or (iv) take corporate action for the purpose of effecting any of the foregoing;

c) if any cause, proceeding or other action shall be instituted in any court of competent jurisdiction, against the Guarantor or the Creditor seeking an adjudication in bankruptcy, reorganization, dissolution, winding up, liquidation (but for certainty, excluding any reorganization, arrangement, dissolution, winding-up or liquidation by or solely among solvent persons under business corporations statutes), a composition or arrangement with creditors, a readjustment of debts, the appointment of a trustee, receiver, liquidator or the like of the Guarantor or the Creditor or of all or any substantial part of its or their assets, or any other like relief in respect of the Guarantor or the Creditor under any bankruptcy or insolvency law; and such cause, proceeding or other action results in an entry of an order for such relief or any such adjudication or appointment; or if such cause, proceeding or other action is being contested by the Guarantor or the Creditor in good faith, the same shall continue undismissed, or unstayed and in effect, for any period of sixty (60) consecutive days; or

d) if the Creditor has demanded funds under this Guarantee and, subject to Section 4 herein, the Guarantor fails to pay to the Creditor;

Then, upon the occurrence of any Event of Default, the NEB or any successor administrative body, must be served notice of such Event of Default within two (2) business days.

6. Termination. The Guarantor’s liability under this Guarantee shall remain in full force and effect unless: (i) the NEB, or any successor administrative body, has provided prior written approval to Guarantor to terminate this Guarantee; or (ii) the NEB, or any successor administrative body, has approved an alternative type of financial resource in respect of the Creditor.

7. Waivers. Guarantor waives diligence, presentment, protest, notice of acceptance of this Guarantee and notice of any liability to which it may apply, notice of dishonor or nonpayment, and any other notice not expressly required by this Guarantee.

8. No merger. Neither an action or proceeding brought under this Guarantee regarding the Guaranteed Obligations nor any judgment or recovery in consequence of that action or proceeding operates as a bar or defence to any further action or proceeding that may be brought under this Guarantee. Any action, proceeding, judgment or recovery does not constitute a merger of any of Creditor’s rights or remedies under this Guarantee. Any judgment obtained by Creditor in whole or in part of any of the Guaranteed Obligations under this Guarantee does not constitute a merger of this Guarantee into that judgment.

9. Benefit of the Guarantee. Subject to the terms of Section 15, this Guarantee shall be binding upon Guarantor and its successors and permitted assigns and shall inure to the benefit of and be enforceable by Creditor and its successors and assigns.

10. Entire agreement. This Guarantee represents the entire rights and obligations of the parties pertaining to the subject matter hereof and supersedes all prior oral or written agreements, representations and understandings pertaining hereto.

11. No waiver, remedies. No failure or delay on the part of Creditor in exercising any right, power or privilege under this Guarantee and no course of dealing between Guarantor or Creditor shall operate as a waiver thereof, nor shall any single or partial exercise of any right, power or privilege under this Guarantee preclude any other or further exercise thereof or any other right, power or privilege. The rights, powers or remedies in this Guarantee are cumulative and not exclusive of any rights, powers or remedies which Creditor would otherwise have.

12. Amendments. No amendment, modification or waiver of any provision of this Guarantee nor consent to any departure by Guarantor therefrom shall in any event be effective without the prior written approval of the NEB, or any successor administrative body, and unless the same shall be in writing and signed (i) in the case of an amendment or modification, by Guarantor and Creditor and (ii) in the case of a waiver or consent, by Creditor, and then such waiver or consent shall be effective only in the specific instance and for the specific purpose for which given.

13. Severability. If any provision of this Guarantee is determined to be invalid or unenforceable in whole or in part, such invalidity or unenforceability will apply only to that provision and all other provisions of this Guarantee will continue in full force and effect as if such invalid or unenforceable provision were omitted. If this Guarantee is determined to be invalid or unenforceable for any reason, such invalidity or unenforceability will not apply to any of the representations and warranties provided in Section 3, which is deemed to be a separate and independent legal, valid, binding and enforceable agreement between Guarantor and Creditor and will continue in full force. Creditor is entitled to proceed with any remedy available to it as a result of Guarantor’s breach of any of the representations and warranties provided in Section 3.

14. Notices. All notices and other communications hereunder shall be in writing and may be given in any manner described below (except that a demand notice may not be given by facsimile) to the address or facsimile number set forth below or at such other address or facsimile number for

a party as shall be designated in a written notice by such party to the other party and will be deemed effective as indicated:

a) if delivered in person or by courier, on the date it is delivered; b) if sent by mail, registered or certified, postage prepaid and return receipt requested, on the date it is delivered; or c) if sent by facsimile transmission, on the date it is received by the recipient, unless the date of delivery or receipt, as applicable, is not a local business day or that communication is delivered or received, as applicable, after the close of business on a local business day, in which case that communication will be deemed given and effective on the first following day that is a local business day:

If to Guarantor, to:

TransCanada PipeLines Limited 450 – 1st Street SW Calgary, Alberta Canada T2P 5H1

Attention: Vice-President, Risk Management Fax: 403-920-2359

If to Creditor, to:

Great Lakes Pipeline Canada Ltd. 450 – 1st Street SW Calgary, Alberta Canada T2P 5H1

Attention: Vice-President, Risk Management Fax: 403-920-2359

If to the NEB, to:

National Energy Board 

Attention:  Fax: 

15. Assignment. Neither the Guarantor nor the Creditor may assign or transfer its obligations under this Guarantee in part or in whole without the prior written approval of the NEB or any successor administrative body, and any purported assignment or transfer without such consent shall be null, void and of no effect.

16. Governing law. This Guarantee is governed by and to be construed according to the laws applicable in the Province of Alberta without giving effect to any choice or conflict of law rules or provisions that would require the application of the laws of another jurisdiction. Guarantor irrevocably consents to the non-exclusive jurisdiction of the Alberta courts for the purposes of any action or proceeding arising out of or related to this Guarantee. Guarantor agrees that all

claims in respect of such action or proceeding may be heard and determined in any such court and irrevocably waives, to the fullest extent permitted by law, any claim of inconvenient forum or other objection which it may now or hereafter have to the laying of venue in any such court. Guarantor also irrevocably consents to the service of any and all process in any such action or proceeding by the mailing of copies of such process to Guarantor at the address specified by it pursuant to this Guarantee. Guarantor agrees that a final judgment in any such action or proceeding shall be conclusive and may be enforced in other jurisdictions by suit on the judgment or in any other manner provided by law. Nothing in this Section shall affect Creditor’s right to serve legal process in any other manner permitted by law or its right to bring any action or proceeding against Guarantor or its property in the courts of other jurisdictions.

17. Headings and section references. The headings contained in this Guarantee are for reference purposes only and shall not affect the meaning or interpretation of this Guarantee. Unless the context indicates otherwise, all references in this Guarantee to sections shall refer to the corresponding section of this Guarantee.

18. Facsimile signature, counterparts. A signature delivered by facsimile or by any other reliable electronic transmission shall be deemed to be an original signature for purposes of the Guarantee and shall be binding upon Guarantor as an original signature. Notwithstanding that Guarantor may deliver a signature by facsimile or by any other reliable electronic transmission, Guarantor covenants to deliver an originally executed counterpart of this Guarantee to Creditor within a reasonable period of time after executing the Guarantee. This Guarantee may be executed in counterparts, each of which shall be deemed an original but which together will constitute one and the same instrument.

IN WITNESS WHEREOF, the Creditor and the Guarantor have signed and delivered this Guarantee to be effective as of the date first-above written.

TRANSCANADA PIPELINES LIMITED GREAT LAKES PIPELINE CANADA LTD. By: By: Name: Name: Title: Title: By: By: Name: Name: Title: Title:

Great Lakes Pipeline Canada Ltd. Financial Resources Plan Appendix 3

GLC Insurance Certificate and A.M. Best Ratings Certificate of Insurance No.: TCC-2018-1-GLPCL Dated: April 16, 2019 This document supersedes any certificate previously issued under this number

This is to certify that the Policy(ies) of insurance listed below ("Policy" or "Policies") have been issued to the Named Insured identified below for the policy period(s) indicated. This certificate is issued as a matter of information only and confers no rights upon the Certificate Holder named below other than those provided by the Policy(ies). Notwithstanding any requirement, term, or condition of any contract or any other document with respect to which this certificate may be issued or may pertain, the insurance afforded by the Policy(ies) is subject to all the terms, conditions, and exclusions of such Policy(ies). This certificate does not amend, extend, or alter the coverage afforded by the Policy(ies). Limits shown are intended to address contractual obligations of the Named Insured. Limits may have been reduced since Policy effective date(s) as a result of a claim or claims. Certificate Holder: Named Insured and Address: To Whom It May Concern Great Lakes Pipeline Canada Ltd. c/o TransCanada Corporation Insurance Risk Department 450 - 1 Street S.W. Calgary, AB T2P 5H1

Evidence of Insurance

Policy Effective/ Type(s) of Insurance Insurer(s) Number(s) Expiry Dates Sums Insured Or Limits of Liability COMMERCIAL GENERAL Liberty Mutual Insurance Company GLTOAAD53K018 Jun 01, 2018 to Per Occurrence USD 25,000,000 LIABILITY Jun 01, 2019 ● Products & Completed Claims-Made Format Operations Aggregate USD 25,000,000 General Aggregate USD 50,000,000 Self Insured Retention USD 1,000,000 EXCESS LIABILITY Associated Electric & Gas XL5115207P Jun 01, 2018 to Each Occurrence USD 35,000,000 ● Claims-Made Format Insurance Services Ltd Jun 01, 2019 ● General Aggregate USD 70,000,000 Excess of Commercial General Liability EXCESS LIABILITY Energy Insurance Mutual 254023-18GL Jun 01, 2018 to Each Occurrence USD 40,000,000 ● Claims-Made Format Jun 01, 2019 ● Aggregate USD 40,000,000 1st Excess Liability

Notice of cancellation: The insurer(s) affording coverage under the policies described herein will not notify the certificate holder named herein of the cancellation of such coverage.

Marsh Canada Limited Marsh Canada Limited 222 - 3rd Avenue SW Livingston Place, Suite 1100 Calgary, AB T2P 0B4 Telephone: (403)-4763421 Fax: (403)-2943896 [email protected] By: Cheryl Kassai - Bjorn Ostlund Client Executive

F\/IARSH Marsh Canada Limited Livingston Place 222-3rd Avenue S.W., Suite 1100 Calgary, Alberta T2P 0B4 403 476 3359 Fax 403 261 9882 [email protected] www.marsh.ca www.marsh.com

03 May 2019

Subject: TC Energy Corporation Certificate: TCC-2018-1

To Whom It May Concern:

With reference to the above certificate issued on behalf of TC Energy Corporation, please find below the AM Best Insurer Ratings for the following Insurers effective May 3, 2019:

Liberty Mutual Insurance Company AM Best Rating A Associated Electric & Gas Insurance Services Ltd. AM Best Rating A Energy Insurance Mutual AM Best Rating A

Marsh cannot, and does not, guarantee the financial stability of Insurers.

Marsh Canada Limited makes no representations or warranties, expressed or implied, concerning the financial condition or solvency of any insurers or reinsurers. A.M. Best Ratings are under continuous review and subject to change and/or affirmation. For the Latest Best Ratings and Best Company Reports (which include Best Ratings), visit the A.M. Best website at www.ambest.com. Refer to the Guide to Best Ratings for explanation of use and charges. Best Ratings reproduced herein appear under license from A.M. Best and do not constitute, either expressly or impliedly, an endorsement by Marsh. A.M. Best is not responsible for transcription errors made in presenting Best Ratings. Best Rating are proprietary and may not be reproduced or distributed without the express written permission of A.M. Best Company.

We trust the enclosed is found in order. Should you have any questions, please do not hesitate to contact our office.

Regards,

Bjorn Ostlund Client Executive

BO/ck

MARSH&McLENNAN SOLUTIONS..DEFINED,DESIGNED,ANDDELIVERED. • COMPANIES Great Lakes Pipeline Canada Ltd. Financial Resources Plan Appendix 4

TransCanada Financial Statements Management's Report on Internal Control over Financial Reporting

The consolidated financial statements are the responsibility of the management of TransCanada PipeLines Limited (TCPL or the Company) and have been approved by the Board of Directors of the Company. The consolidated financial statements have been prepared by management in accordance with United States generally accepted accounting principles (GAAP) and include amounts that are based on estimates and judgments.

Management is responsible for establishing and maintaining adequate internal control over financial reporting for the Company. Management has designed and maintains a system of internal control over financial reporting, including a program of internal audits to carry out its responsibility. Management believes these controls provide reasonable assurance that financial records are reliable and form a proper basis for the preparation of financial statements. The internal control over financial reporting includes management's communication to employees of policies that govern ethical business conduct.

Under the supervision and with the participation of the President and Chief Executive Officer and the Chief Financial Officer, management conducted an evaluation of the effectiveness of its internal control over financial reporting based on the framework in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Management concluded, based on its evaluation, that internal control over financial reporting was effective as of December 31, 2018, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external reporting purposes.

The Board of Directors is responsible for reviewing and approving the financial statements and ensuring that management fulfills its responsibilities for financial reporting and internal control. The Board of Directors carries out these responsibilities primarily through the Audit Committee, which consists of independent, non-management directors. The Audit Committee meets with management at least five times a year and meets independently with internal and external auditors and as a group to review any significant accounting, internal control and auditing matters in accordance with the terms of the Charter of the Audit Committee, which is set out in the Annual Information Form. The Audit Committee's responsibilities include overseeing management's performance in carrying out its financial reporting responsibilities and reviewing the Annual Report, including the consolidated financial statements, before this document is submitted to the Board of Directors for approval. The internal and independent external auditors have access to the Audit Committee without the requirement to obtain prior management approval.

The Audit Committee approves the terms of engagement of the independent external auditors and reviews the annual audit plan, the Auditors' Report and the results of the audit. It also recommends to the Board of Directors the firm of external auditors to be appointed by the shareholder.

The shareholder has appointed KPMG LLP as independent external auditors to express an opinion as to whether the consolidated financial statements present fairly, in all material respects, the Company's consolidated financial position, results of operations and cash flows in accordance with GAAP. The report of KPMG LLP outlines the scope of its examination and its opinion on the consolidated financial statements.

Russell K. Girling Donald R. Marchand President and Executive Vice-President and Chief Executive Officer Chief Financial Officer February 13, 2019

TCPL Consolidated financial statements 2018 1 Report of Independent Registered Public Accounting Firm

To the Shareholders of TransCanada PipeLines Limited

Opinion on the Consolidated Financial Statements We have audited the accompanying consolidated balance sheets of TransCanada PipeLines Limited (the Company) as of December 31, 2018, and 2017, the related consolidated statements of income, comprehensive income, cash flows and equity for each of the years in the three-year period ended December 31, 2018, and the related notes (collectively, the consolidated financial statements). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2018, and 2017, and the results of its operations and its cash flows for each of the years in the three‑year period ended December 31, 2018, in conformity with U.S. generally accepted accounting principles.

Basis for Opinion These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.

Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.

Chartered Professional Accountants

We have served as the Company's auditor since 1956.

Calgary, Canada February 13, 2019

2 TCPL Consolidated financial statements 2018 Consolidated statement of income

year ended December 31 (millions of Canadian $) 2018 2017 2016

Revenues (Note 5) Canadian Natural Gas Pipelines 4,038 3,693 3,682 U.S. Natural Gas Pipelines 4,314 3,584 2,526 Mexico Natural Gas Pipelines 619 570 378 Liquids Pipelines 2,584 2,009 1,755 Energy 2,124 3,593 4,206 13,679 13,449 12,547 Income from Equity Investments (Note 9) 714 773 514 Operating and Other Expenses Plant operating costs and other 3,591 3,906 3,861 Commodity purchases resold 1,488 2,382 2,172 Property taxes 569 569 555 Depreciation and amortization 2,350 2,055 1,939 Goodwill and other asset impairment charges (Notes 8, 11 and 12) 801 1,257 1,388 8,799 10,169 9,915 Gain/(Loss) on Assets Held for Sale/Sold (Note 25) 170 631 (833) Financial Charges Interest expense (Note 17) 2,379 2,137 1,927 Allowance for funds used during construction (526) (507) (419) Interest income and other 78 (183) (117) 1,931 1,447 1,391 Income before Income Taxes 3,833 3,237 922 Income Tax Expense/(Recovery) (Note 16) Current 316 149 157 Deferred 254 548 192 Deferred – U.S. Tax Reform and 2018 FERC Actions (167) (804) — 403 (107) 349 Net Income 3,430 3,344 573 Net (loss)/income attributable to non-controlling interests (Note 19) (185) 238 252 Net Income Attributable to Controlling Interests and to Common Shares 3,615 3,106 321

The accompanying Notes to the consolidated financial statements are an integral part of these statements.

TCPL Consolidated financial statements 2018 3 Consolidated statement of comprehensive income

year ended December 31 (millions of Canadian $) 2018 2017 2016

Net Income 3,430 3,344 573 Other Comprehensive Income/(Loss), Net of Income Taxes Foreign currency translation gains and losses on net investment in foreign operations 1,358 (749) 3 Reclassification of foreign currency translation gains on disposal of foreign operations — (77) — Change in fair value of net investment hedges (42) — (10) Change in fair value of cash flow hedges (10) 3 30 Reclassification to net income of gains and losses on cash flow hedges 21 (2) 42 Unrealized actuarial gains and losses on pension and other post-retirement benefit plans (114) (11) (26) Reclassification of actuarial gains and losses on pension and other post-retirement benefit plans 15 16 16 Other comprehensive income/(loss) on equity investments 86 (106) (87) Other comprehensive income/(loss) (Note 21) 1,314 (926) (32) Comprehensive Income 4,744 2,418 541 Comprehensive (loss)/income attributable to non-controlling interests (13) 83 241 Comprehensive Income Attributable to Controlling Interests and to Common Shares 4,757 2,335 300

The accompanying Notes to the consolidated financial statements are an integral part of these statements.

4 TCPL Consolidated financial statements 2018 Consolidated statement of cash flows

year ended December 31 (millions of Canadian $) 2018 2017 2016

Cash Generated from Operations Net income 3,430 3,344 573 Depreciation and amortization 2,350 2,055 1,939 Goodwill and other asset impairment charges (Notes 8, 11 and 12) 801 1,257 1,388 Deferred income taxes (Note 16) 254 548 192 Deferred income taxes – U.S. Tax Reform and 2018 FERC Actions (Note 16) (167) (804) — Income from equity investments (Note 9) (714) (773) (514) Distributions received from operating activities of equity investments (Note 9) 985 970 844 Employee post-retirement benefits funding, net of expense (Note 22) (35) (64) (3) (Gain)/loss on assets held for sale/sold (Note 25) (170) (631) 833 Equity allowance for funds used during construction (374) (362) (253) Unrealized losses/(gains) on financial instruments 220 (149) (149) Other (40) 43 55 (Increase)/decrease in operating working capital (Note 24) (99) (272) 251 Net cash provided by operations 6,441 5,162 5,156 Investing Activities Capital expenditures (Note 4) (9,418) (7,383) (5,007) Capital projects in development (Note 4) (496) (146) (295) Contributions to equity investments (Notes 4 and 9) (1,015) (1,681) (765) Acquisitions, net of cash acquired — — (13,608) Proceeds from sales of assets, net of transaction costs 614 4,683 6 Reimbursement of costs related to capital projects in development (Note 12) 470 634 — Other distributions from equity investments (Note 9) 121 362 727 Deferred amounts and other (293) (168) 159 Net cash used in investing activities (10,017) (3,699) (18,783) Financing Activities Notes payable issued/(repaid), net 817 1,038 (329) Long-term debt issued, net of issue costs 6,238 3,643 12,333 Long-term debt repaid (3,550) (7,085) (7,153) Junior subordinated notes issued, net of issue costs — 3,468 1,549 Advances from affiliate 1,066 193 4,523 Dividends on common shares (2,419) (2,121) (1,612) Distributions to non-controlling interests (225) (283) (279) Common shares issued 845 780 4,661 Partnership units of TC PipeLines, LP issued, net of issue costs 49 225 215 Common units of Columbia Pipeline Partners LP acquired — (1,205) — Net cash provided by/(used in) financing activities 2,821 (1,347) 13,908 Effect of Foreign Exchange Rate Changes on Cash and Cash Equivalents 73 (39) (127) (Decrease)/Increase in Cash and Cash Equivalents (682) 77 154 Cash and Cash Equivalents Beginning of year 1,044 967 813 Cash and Cash Equivalents End of year 362 1,044 967

The accompanying Notes to the consolidated financial statements are an integral part of these statements.

TCPL Consolidated financial statements 2018 5 Consolidated balance sheet

at December 31 (millions of Canadian $) 2018 2017 ASSETS Current Assets Cash and cash equivalents 362 1,044 Accounts receivable 2,548 2,537 Inventories 431 378 Assets held for sale (Note 6) 543 — Other (Note 7) 1,180 691 5,064 4,650 Plant, Property and Equipment (Note 8) 66,503 57,277 Equity Investments (Note 9) 7,113 6,366 Regulatory Assets (Note 10) 1,548 1,376 Goodwill (Note 11) 14,178 13,084 Loan Receivable from Affiliate (Note 9) 1,315 919 Intangible and Other Assets (Note 12) 1,887 1,423 Restricted Investments 1,207 915 98,815 86,010 LIABILITIES Current Liabilities Notes payable (Note 13) 2,762 1,763 Accounts payable and other (Note 14) 5,426 4,071 Dividends payable 633 552 Due to affiliate (Note 28) 3,617 2,551 Accrued interest 646 605 Current portion of long-term debt (Note 17) 3,462 2,866 16,546 12,408 Regulatory Liabilities (Note 10) 3,930 4,321 Other Long-Term Liabilities (Note 15) 1,008 727 Deferred Income Tax Liabilities (Note 16) 6,026 5,403 Long-Term Debt (Note 17) 36,509 31,875 Junior Subordinated Notes (Note 18) 7,508 7,007 71,527 61,741 EQUITY Common shares, no par value (Note 20) 22,606 21,761 Issued and outstanding: December 31, 2018 – 887 million shares December 31, 2017 – 872 million shares Additional paid-in capital 20 — Retained earnings 3,613 2,387 Accumulated other comprehensive loss (Note 21) (606) (1,731) Controlling Interests 25,633 22,417 Non-controlling interests (Note 19) 1,655 1,852 27,288 24,269 98,815 86,010

Commitments, Contingencies and Guarantees (Note 26) Corporate Restructuring Costs (Note 27) Variable Interest Entities (Note 29) Subsequent Event (Note 30) The accompanying Notes to the consolidated financial statements are an integral part of these statements. On behalf of the Board:

Russell K. Girling, Director John E. Lowe, Director

6 TCPL Consolidated financial statements 2018 Consolidated statement of equity

year ended December 31 (millions of Canadian $) 2018 2017 2016

Common Shares (Note 20) Balance at beginning of year 21,761 20,981 16,320 Proceeds from shares issued 845 780 4,661 Balance at end of year 22,606 21,761 20,981 Additional Paid-In Capital Balance at beginning of year — 211 210 Issuance of stock options 13 12 15 Dilution from TC PipeLines, LP units issued 7 26 24 Asset drop-downs to TC PipeLines, LP — (202) (38) Columbia Pipeline Partners LP acquisition — (171) — Reclassification of additional paid-in capital deficit to retained earnings — 124 — Balance at end of year 20 — 211 Retained Earnings Balance at beginning of year 2,387 1,577 2,989 Net income attributable to controlling interests 3,615 3,106 321 Common share dividends (2,501) (2,184) (1,733) Adjustment related to income tax effects of asset drop-downs to TC PipeLines, LP (Note 3) 95 — — Reclassification of AOCI to retained earnings resulting from U.S. Tax Reform (Note 3) 17 — — Adjustment related to employee share-based payments — 12 — Reclassification of additional paid-in capital deficit to retained earnings — (124) — Balance at end of year 3,613 2,387 1,577 Accumulated Other Comprehensive Loss Balance at beginning of year (1,731) (960) (939) Other comprehensive income/(loss) attributable to controlling interests (Note 21) 1,142 (771) (21) Reclassification of AOCI to retained earnings resulting from U.S. Tax Reform (Note 3) (17) — — Balance at end of year (606) (1,731) (960) Equity Attributable to Controlling Interests 25,633 22,417 21,809 Equity Attributable to Non-Controlling Interests Balance at beginning of year 1,852 1,726 1,717 Net (loss)/income attributable to non-controlling interests (185) 238 252 Other comprehensive income/(loss) attributable to non-controlling interests 172 (155) (11) Issuance of TC PipeLines, LP units Proceeds, net of issue costs 49 225 215 Decrease in TCPL's ownership of TC PipeLines, LP (9) (41) (40) Distributions declared to non-controlling interests (224) (280) (279) Reclassification from/(to) common units subject to rescission or redemption (Note 19) — 106 (1,179) Impact of Columbia Pipeline Partners LP acquisition — 33 — Acquisition of non-controlling interests in Columbia Pipeline Partners LP — — 1,051 Balance at end of year 1,655 1,852 1,726 Total Equity 27,288 24,269 23,535 The accompanying Notes to the consolidated financial statements are an integral part of these statements.

TCPL Consolidated financial statements 2018 7 Notes to consolidated financial statements

1. DESCRIPTION OF TCPL'S BUSINESS TransCanada PipeLines Limited (TCPL or the Company) is a leading North American energy infrastructure company which operates in five business segments, Canadian Natural Gas Pipelines, U.S. Natural Gas Pipelines, Mexico Natural Gas Pipelines, Liquids Pipelines and Energy, each of which offers different products and services. The Company also has a Corporate segment, consisting of corporate and administrative functions that provide governance, financing and other support to the Company's business segments. The Company is a wholly-owned subsidiary of TransCanada Corporation (TransCanada).

Canadian Natural Gas Pipelines The Canadian Natural Gas Pipelines segment consists of the Company's investments in 40,686 km (25,281 miles) of regulated natural gas pipelines.

U.S. Natural Gas Pipelines The U.S. Natural Gas Pipelines segment consists of the Company's investments in 50,199 km (31,192 miles) of regulated natural gas pipelines, 535 Bcf of regulated natural gas storage facilities, midstream and other assets.

Mexico Natural Gas Pipelines The Mexico Natural Gas Pipelines segment consists of the Company's investments in 1,670 km (1,038 miles) of regulated natural gas pipelines.

Liquids Pipelines The Liquids Pipelines segment consists of the Company's investments in 4,874 km (3,030 miles) of crude oil pipeline systems which connect Alberta and U.S. crude oil supplies to U.S. refining markets in Illinois, Oklahoma and Texas.

Energy The Energy segment primarily consists of the Company's investments in 10 power generation facilities and 118 Bcf of non-regulated natural gas storage facilities. These include assets in Alberta, Ontario, Québec, New Brunswick and Arizona. At December 31, 2018, the Coolidge generating station is classified as Assets held for sale. Refer to Note 6, Assets held for sale, for further information.

2. ACCOUNTING POLICIES The Company's consolidated financial statements have been prepared by management in accordance with U.S. generally accepted accounting principles (GAAP). Amounts are stated in Canadian dollars unless otherwise indicated.

Basis of Presentation These consolidated financial statements include the accounts of TCPL and its subsidiaries. The Company consolidates variable interest entities (VIEs) for which it is considered to be the primary beneficiary as well as voting interest entities in which it has a controlling financial interest. To the extent there are interests owned by other parties, these interests are included in non- controlling interests. TCPL uses the equity method of accounting for joint ventures in which the Company is able to exercise joint control and for investments in which the Company is able to exercise significant influence. TCPL records its proportionate share of undivided interests in certain assets. Certain prior year amounts have been reclassified to conform to current year presentation.

Use of Estimates and Judgments In preparing these consolidated financial statements, TCPL is required to make estimates and assumptions that affect both the amount and timing of recording assets, liabilities, revenues and expenses since the determination of these items may be dependent on future events. The Company uses the most current information available and exercises careful judgment in making these estimates and assumptions. Some of the estimates and judgments the Company has to make have a material impact on the consolidated financial statements, but they do not involve significant subjectivity or uncertainty. Others also have a material impact but the assumptions underlying these accounting estimates also relate to matters that are highly uncertain at the time the estimate or judgment is made or are subjective.

8 TCPL Consolidated financial statements 2018 Significant estimates and judgments used in the preparation of the consolidated financial statements that involve assumptions that are highly uncertain or subjective include, but are not limited to: • 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 25).

Significant estimates and judgments used in the preparation of the consolidated financial statements that are provided by an independent expert or do not involve assumptions that are highly uncertain or subjective include, but are not limited to: • 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 22) • fair value of financial instruments (Note 23) and • provisions for commitments, contingencies, guarantees (Note 26) and restructuring costs (Note 27).

Actual results could differ from these estimates.

Regulation Certain Canadian, U.S. and Mexico natural gas pipeline and storage assets are regulated with respect to construction, operations and the determination of tolls. In Canada, regulated natural gas pipelines and liquids pipelines are subject to the authority of the National Energy Board (NEB), the Alberta Energy Regulator (AER) or the B.C. Oil and Gas Commission (OGC). In the U.S., regulated natural gas pipelines, liquids pipelines and regulated natural gas storage assets are subject to the authority of the Federal Energy Regulatory Commission (FERC). In Mexico, regulated natural gas pipelines are subject to the authority of the Energy Regulatory Commission (CRE). Rate-regulated accounting (RRA) standards may impact the timing of the recognition of certain revenues and expenses in TCPL's rate-regulated businesses which may differ from that otherwise recognized in non-rate-regulated businesses to appropriately reflect the economic impact of the regulators' decisions regarding revenues and tolls. Regulatory assets represent costs that are expected to be recovered in customer rates in future periods and regulatory liabilities represent amounts that are expected to be returned to customers through future rate-setting processes. An asset qualifies for the use of RRA when it meets three criteria: • 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.

TCPL's businesses that apply RRA currently include Canadian, U.S. and Mexico natural gas pipelines, and regulated U.S. natural gas storage. RRA is not applicable to the Company's liquids pipelines as the regulators' decisions regarding operations and tolls on those systems generally do not have an impact on timing of recognition of revenues and expenses. Once in operation, the Coastal GasLink pipeline is not expected to apply RRA.

Revenue Recognition Canadian Natural Gas Pipelines Capacity Arrangements and Transportation Revenues from the Company's Canadian natural gas pipelines are generated from contractual arrangements for committed capacity and from the transportation of natural gas. Revenues earned from firm contracted capacity arrangements are recognized ratably over the term of the contract regardless of the amount of natural gas that is transported. Transportation revenues for interruptible or volumetric-based services are recognized when the service is performed.

TCPL Consolidated financial statements 2018 9 Revenues from the Company's Canadian natural gas pipelines are subject to regulatory decisions by the NEB. The tolls charged on these pipelines are based on revenue requirements designed to recover the costs of providing natural gas capacity for transportation services, which includes a return of and on capital, as approved by the NEB. The Company's Canadian natural gas pipelines are generally not subject to risks related to variances in revenues and most costs. These variances are generally subject to deferral treatment and are recovered or refunded in future tolls. Revenues recognized prior to an NEB decision on rates for that period reflect the NEB's last approved return on equity (ROE) assumptions. Adjustments to revenues are recorded when the NEB decision is received. Canadian natural gas pipelines' revenues are invoiced and received on a monthly basis. The Company does not take ownership of the natural gas that it transports for customers.

U.S. Natural Gas Pipelines Capacity Arrangements and Transportation Revenues from the Company's U.S. natural gas pipelines are generated from contractual arrangements for committed capacity and from the transportation of natural gas. Revenues earned from firm contracted capacity arrangements are generally recognized ratably over the term of the contract regardless of the amount of natural gas that is transported. Transportation revenues for interruptible or volumetric-based services are recognized when the service is performed.

The Company's U.S. natural gas pipelines are subject to FERC regulations and, as a result, a portion of revenues collected may be subject to refund if invoiced during an interim period when a rate proceeding is ongoing. Allowances for these potential refunds are recognized using management's best estimate based on the facts and circumstances of the proceeding. Any allowances that are recognized during the proceeding process are refunded or retained at the time a regulatory decision becomes final. U.S. natural gas pipelines' revenues are invoiced and received on a monthly basis. The Company does not take ownership of the natural gas that it transports for customers.

Natural Gas Storage and Other Revenues from the Company's regulated U.S. natural gas storage services are generated mainly from firm committed capacity storage contracts. The performance obligation in these contracts is the reservation of a specified amount of capacity for storage including specifications with regards to the amount of natural gas that can be injected or withdrawn on a daily basis. Revenues are recognized ratably over the contract period for firm committed capacity regardless of the amount of natural gas that is stored, and when gas is injected or withdrawn for interruptible or volumetric-based services. Natural gas storage services revenues are invoiced and received on a monthly basis. The Company does not take ownership of the natural gas that it stores for customers.

Revenues from the Company's midstream natural gas services, including gathering, treating, conditioning, processing, compression and liquids handling services, are generated from contractual arrangements and are recognized ratably over the term of the contract. The Company also owns mineral rights associated with certain natural gas storage facilities. These mineral rights can be leased or contributed to producers of natural gas in return for a royalty interest which is recognized when natural gas and associated liquids are produced. Midstream natural gas service revenues are invoiced and received on a monthly basis. The Company does not take ownership of the natural gas for which it provides midstream services.

Mexico Natural Gas Pipelines Capacity Arrangements and Transportation Revenues from the Company's Mexico natural gas pipelines are primarily collected based on CRE-approved negotiated firm capacity contracts and are generally recognized ratably over the term of the contract. Transportation revenues related to interruptible or volumetric-based services are recognized when the service is performed. Mexico natural gas pipelines' revenues are invoiced and received on a monthly basis. The Company does not take ownership of the natural gas that it transports for customers.

Liquids Pipelines Capacity Arrangements and Transportation Revenues from the Company's liquids pipelines are generated mainly from providing customers with firm capacity arrangements to transport crude oil. The performance obligation in these contracts is the reservation of a specified amount of capacity together with the transportation of crude oil on a monthly basis. Revenues earned from these arrangements are recognized ratably over the term of the contract regardless of the amount of crude oil that is transported. Revenues for interruptible or volumetric-based services are recognized when the service is performed. Liquids pipelines' revenues are invoiced and received on a monthly basis. The Company does not take ownership of the crude oil that it transports for customers.

10 TCPL Consolidated financial statements 2018 Energy Power Generation Revenues from the Company's Energy business are primarily derived from long-term contractual commitments to provide power capacity to meet the demands of the market, and from the sale of electricity to both centralized markets and to customers. Power generation revenues also include revenues from the sale of steam to customers. Revenues and capacity payments are recognized as the services are provided and as electricity and steam is delivered. Power generation revenues are invoiced and received on a monthly basis.

Natural Gas Storage and Other Non-regulated natural gas storage contracts include park, loan and term storage arrangements. Revenues are recognized as the services are provided. Term storage revenues are invoiced and received on a monthly basis. Revenues earned from the sale of proprietary natural gas are recognized in the month of delivery. Revenues from ancillary services are recognized as the service is provided. The Company does not take ownership of the natural gas that it stores for customers.

Cash and Cash Equivalents The Company's Cash and cash equivalents consist of cash and highly liquid short-term investments with original maturities of three months or less and are recorded at cost, which approximates fair value.

Inventories Inventories primarily consist of materials and supplies including spare parts and fuel, crude oil in transit and natural gas inventory in storage. Inventories are carried at the lower of cost and net realizable value.

Assets Held for Sale The Company classifies assets as held for sale when management approves and commits to a formal plan to actively market a disposal group and expects the sale to close within the next twelve months. Upon classifying an asset as held for sale, the asset is recorded at the lower of its carrying amount or its estimated fair value, net of selling costs, and any losses are recognized in net income. Once an asset is classified as held for sale, depreciation expense is no longer recorded.

Plant, Property and Equipment Natural Gas Pipelines Plant, property and equipment for natural gas pipelines is carried at cost. Depreciation is calculated on a straight-line basis once the assets are ready for their intended use. Pipeline and compression equipment are depreciated at annual rates ranging from one per cent to seven per cent, and metering and other plant equipment are depreciated at various rates reflecting their estimated useful lives. The cost of major overhauls of equipment is capitalized and depreciated over the estimated service lives of the overhauls. The cost of regulated natural gas pipelines includes an allowance for funds used during construction (AFUDC) consisting of a debt component and an equity component based on the rate of return on rate base approved by regulators. AFUDC is reflected as an increase in the cost of the assets in plant, property and equipment with a corresponding credit recognized in Allowance for funds used during construction in the Consolidated statement of income. The equity component of AFUDC is a non-cash expenditure. Interest is capitalized during construction of non-regulated natural gas pipelines.

Regulated natural gas storage base gas, which is valued at cost, represents gas volumes that are maintained to ensure adequate reservoir pressure exists to deliver natural gas held in storage. Base gas is not depreciated.

When regulated natural gas pipelines retire plant, property and equipment from service, the original book cost is removed from the gross plant amount and recorded as a reduction to accumulated depreciation. Costs incurred to remove plant, property and equipment from service, net of any salvage proceeds, are also recorded in accumulated depreciation.

Midstream and Other Plant, property and equipment for midstream assets is carried at cost. Depreciation is calculated on a straight-line basis once the assets are ready for their intended use. Gathering and processing facilities are depreciated at annual rates ranging from 1.7 per cent to 2.5 per cent, and other plant and equipment are depreciated at various rates. When these assets are retired from plant, property and equipment, the original book cost and related accumulated depreciation are derecognized and any gain or loss is recorded in net income.

TCPL Consolidated financial statements 2018 11 The Company participates as a working interest partner in the development of certain Marcellus and Utica acreage. The working interest allows the Company to invest in drilling activities in addition to receiving a royalty interest in well production. The Company uses the successful efforts method of accounting for natural gas and crude oil resulting from its portion of drilling activities. Capitalized well costs are depleted based on the units of production method.

Liquids Pipelines Plant, property and equipment for liquids pipelines is carried at cost. Depreciation is calculated on a straight-line basis once the assets are ready for their intended use. Pipeline and pumping equipment are depreciated at annual rates ranging from two per cent to 2.5 per cent, and other plant and equipment are depreciated at various rates. The cost of these assets includes interest capitalized during construction. When liquids pipelines retire plant, property and equipment from service, the original book cost and related accumulated depreciation are derecognized and any gain or loss is recorded in net income.

Energy Plant, property and equipment for Energy assets are recorded at cost and, once the assets are ready for their intended use, depreciated by major component on a straight-line basis over their estimated service lives at average annual rates ranging from two per cent to 20 per cent. Other equipment is depreciated at various rates. The cost of major overhauls of equipment is capitalized and depreciated over the estimated service lives of the overhauls. Interest is capitalized on facilities under construction. When these assets are retired from plant, property and equipment, the original book cost and related accumulated depreciation are derecognized and any gain or loss is recorded in net income.

Non-regulated natural gas storage base gas, which is valued at original cost, represents gas volumes that are maintained to ensure adequate reservoir pressure exists to deliver gas held in storage. Base gas is not depreciated.

Corporate Corporate plant, property and equipment is recorded at cost and depreciated on a straight-line basis over its estimated useful life at average annual rates ranging from three per cent to 20 per cent.

Capitalized Project Costs The Company capitalizes project costs once advancement of the project to a construction stage is probable or costs are otherwise likely to be recoverable. The Company also capitalizes interest costs for non-regulated projects in development and AFUDC for regulated projects in development. Capital projects in development are included in Intangible and other assets on the Consolidated balance sheet. These represent larger projects that generally require regulatory or other approvals before physical construction can begin. Once approvals are received, projects are moved to Plant, property and equipment under construction.

Impairment of Long-Lived Assets The Company reviews long-lived assets such as plant, property and equipment, equity investments and capital projects in development for impairment whenever events or changes in circumstances indicate the carrying value may not be recoverable. If the total of the estimated undiscounted future cash flows that are estimated for an asset within Plant, property and equipment, or the estimated selling price of any long-lived asset, is less than the carrying value of an asset, an impairment loss is recognized for the excess of the carrying value over the estimated fair value of the asset.

Acquisitions and Goodwill The Company accounts for business combinations using the acquisition method of accounting and, accordingly, the assets and liabilities of the acquired entities are primarily measured at their estimated fair values at the date of acquisition. The excess of the fair value of the consideration transferred over the estimated fair value of the net assets acquired is classified as goodwill. Goodwill is not amortized and is tested for impairment on an annual basis or more frequently if events or changes in circumstances indicate that it might be impaired. The annual review for goodwill impairment is performed at the reporting unit level which is one level below the Company's operating segments. The Company can initially assess qualitative factors to determine whether events or changes in circumstances indicate that goodwill might be impaired and if the Company concludes that it is not more likely than not that the fair value of the reporting unit is greater than its carrying value, the Company will then perform the quantitative goodwill impairment test. The Company can elect to proceed directly to the quantitative goodwill impairment test for any of its reporting units. If the quantitative goodwill impairment test is performed, the Company compares the fair value of the reporting unit to its carrying value, including its goodwill. If the carrying value of a reporting unit including its goodwill exceeds its fair value, goodwill impairment is measured at the amount by which the reporting unit’s carrying value exceeds its fair value.

12 TCPL Consolidated financial statements 2018 Loans and Receivables Loans receivable from affiliates and accounts receivable are measured at cost.

Power Purchase Arrangements A power purchase arrangement (PPA) is a long-term contract for the purchase or sale of power on a predetermined basis. TCPL has PPAs for the sale of power that are accounted for as operating leases where TCPL is the lessor. During 2016, the Company terminated its Alberta PPAs under which it purchased power and recorded an impairment charge. Prior to their termination, substantially all of these PPAs were also accounted for as operating leases, where TCPL was the lessee, and initial payments to acquire these PPAs were recognized in Intangible and other assets and amortized on a straight-line basis over the term of the contracts. A portion of these PPAs was subleased to third parties under terms and conditions similar to the PPAs, and was also accounted for as operating leases with the margin earned from the subleases recorded in Revenues. Refer to Note 12, Intangible and other assets, for further information.

Restricted Investments The Company has certain investments that are restricted as to their withdrawal and use. These restricted investments are classified as available for sale and are recorded at fair value on the Consolidated balance sheet.

As a result of the NEB’s Land Matters Consultation Initiative (LMCI), TCPL is required to collect funds to cover estimated future pipeline abandonment costs for all NEB regulated Canadian pipelines. Funds collected are placed in trusts that hold and invest the funds and are accounted for as restricted investments. LMCI restricted investments may only be used to fund the abandonment of the NEB regulated pipeline facilities, therefore, a corresponding regulatory liability is recorded on the Consolidated balance sheet. The Company also has other restricted investments that have been set aside to fund insurance claim losses to be paid by the Company's wholly-owned captive insurance subsidiary.

Income Taxes The Company uses the asset and liability method of accounting for income taxes. This method requires the recognition of deferred income tax assets and liabilities for future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred income tax assets and liabilities are measured using enacted tax rates at the balance sheet date that are anticipated to apply to taxable income in the years in which temporary differences are expected to be reversed or settled. Changes to these balances are recognized in net income in the period which they occur, except for changes in balances related to regulated natural gas pipelines which are deferred until they are refunded or recovered in tolls, as permitted by the regulator. Deferred income tax assets and liabilities are classified as non-current on the Consolidated balance sheet.

Canadian income taxes are not provided on the unremitted earnings of foreign investments that the Company does not intend to repatriate in the foreseeable future.

Asset Retirement Obligations The Company recognizes the fair value of a liability for asset retirement obligations (ARO) in the period in which it is incurred, when a legal obligation exists and a reasonable estimate of fair value can be made. The fair value is added to the carrying amount of the associated asset and the liability is accreted through charges to Operating and other expenses.

For those AROs that the Company records, the following assumptions are used: • 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.

The Company has recorded AROs related to its non-regulated natural gas storage operations, mineral rights and power generation facilities. The scope and timing of asset retirements related to most of the Company's natural gas pipelines and liquids pipelines is indeterminable because the Company intends to operate them as long as there is supply and demand. As a result, the Company has not recorded an amount for ARO related to these assets, with the exception of certain abandoned facilities and certain facilities expected to be retired as part of an ongoing modernization program that will improve system integrity and enhance service reliability and flexibility on its Columbia Gas pipeline.

TCPL Consolidated financial statements 2018 13 Environmental Liabilities The Company records liabilities on an undiscounted basis for environmental remediation efforts that are likely to occur and where the cost can be reasonably estimated. These estimates, including associated legal costs, are based on available information using existing technology and enacted laws and regulations, and are subject to revision in future periods based on actual costs incurred or new circumstances. Amounts expected to be recovered from other parties, including insurers, are recorded as an asset separate from the associated liability.

Emission allowances or credits purchased for compliance are recorded on the Consolidated balance sheet at historical cost and expensed when they are utilized or cancelled/retired by government agencies. Compliance costs are expensed when incurred. Allowances granted to or internally generated by TCPL are not attributed a value for accounting purposes. When required, TCPL accrues emission liabilities on the Consolidated balance sheet upon the generation or sale of power using the best estimate of the amount required to settle the obligation. Allowances and credits not used for compliance are sold and any gain or loss is recorded in Revenues.

Stock Options and Other Compensation Programs TransCanada's Stock Option Plan permits options for the purchase of TransCanada common shares to be awarded to certain employees, including officers. Stock options granted are recorded using the fair value method. Under this method, compensation expense is measured at the grant date based on the fair value as calculated using a binomial model and is recognized on a straight- line basis over the vesting period with an offset to Additional paid-in capital. TCPL records the compensation expense associated with these stock options.

The Company has medium-term incentive plans, under which payments are made to eligible employees. The expense related to these incentive plans is accounted for on an accrual basis. Under these plans, benefits vest when certain conditions are met, including the employees' continued employment during a specified period and achievement of specified corporate performance targets.

Employee Post-Retirement Benefits The Company sponsors defined benefit pension plans (DB Plans), defined contribution plans (DC Plans), a savings plan and other post-retirement benefit plans. Contributions made by the Company to the DC Plans and savings plan are expensed in the period in which contributions are made. The cost of the DB Plans and other post-retirement benefits received by employees is actuarially determined using the projected benefit method pro-rated based on service, and management's best estimate of expected plan investment performance, salary escalation, retirement age of employees and expected health care costs.

The DB Plans' assets are measured at fair value at December 31 of each year. The expected return on the DB Plans' assets is determined using market-related values based on a five-year moving average value for all of the DB Plans' assets. Past service costs are amortized over the expected average remaining service life of the employees. Adjustments arising from plan amendments are amortized on a straight-line basis over the average remaining service life of employees active at the date of amendment. The Company recognizes the overfunded or underfunded status of its DB Plans as an asset or liability, respectively, on its Consolidated balance sheet and recognizes changes in that funded status through Other comprehensive income (OCI) in the year in which the change occurs. The excess of net actuarial gains or losses over 10 per cent of the greater of the benefit obligation and the market-related value of the DB Plans' assets, if any, is amortized out of Accumulated other comprehensive income (AOCI) and into net income over the expected average remaining service life of the active employees. When the restructuring of a benefit plan gives rise to both a curtailment and a settlement, the curtailment is accounted for prior to the settlement.

For certain regulated operations, post-retirement benefit amounts are recoverable through tolls as benefits are funded. The Company records any unrecognized gains or losses or changes in actuarial assumptions related to these post-retirement benefit plans as either regulatory assets or liabilities. The regulatory assets or liabilities are amortized on a straight-line basis over the expected average remaining service life of active employees.

14 TCPL Consolidated financial statements 2018 Foreign Currency Transactions and Translation Foreign currency transactions are those transactions whose terms are denominated in a currency other than the currency of the primary economic environment in which the Company or reporting subsidiary operates. This is referred to as the functional currency. Transactions denominated in foreign currencies are translated into the functional currency using the exchange rate prevailing at the date of the transaction. Monetary assets and liabilities denominated in foreign currencies are translated to the functional currency using the rate of exchange in effect at the balance sheet date whereas non-monetary assets and liabilities are translated at the historical rate of exchange in effect on the date of the transaction. Exchange gains and losses resulting from translation of monetary assets and liabilities are recorded in net income except for exchange gains and losses of the foreign currency debt related to Canadian regulated natural gas pipelines, which are deferred until they are refunded or recovered in tolls, as permitted by the NEB.

Gains and losses arising from translation of foreign operations' functional currencies to the Company's Canadian dollar reporting currency are reflected in OCI until the operations are sold, at which time the gains and losses are reclassified to net income. Asset and liability accounts are translated at the period-end exchange rates while revenues, expenses, gains and losses are translated at the exchange rates in effect at the time of the transaction. The Company's U.S. dollar-denominated debt and certain derivative hedging instruments have been designated as a hedge of the net investment in foreign subsidiaries and, as a result, the unrealized foreign exchange gains and losses on the U.S. dollar denominated debt are also reflected in OCI.

Derivative Instruments and Hedging Activities All derivative instruments are recorded on the Consolidated balance sheet at fair value, unless they qualify for and are designated under a normal purchase and normal sales exemption, or are considered to meet other permitted exemptions.

The Company applies hedge accounting to arrangements that qualify for and are designated for hedge accounting treatment. This includes fair value and cash flow hedges and hedges of foreign currency exposures of net investments in foreign operations. Hedge accounting is discontinued prospectively if the hedging relationship ceases to be effective or the hedging or hedged items cease to exist as a result of maturity, expiry, sale, termination, cancellation or exercise.

In a fair value hedging relationship, the carrying value of the hedged item is adjusted for changes in fair value attributable to the hedged risk and these changes are recognized in net income. Changes in the fair value of the hedged item, to the extent that the hedging relationship is effective, are offset by changes in the fair value of the hedging item, which are also recorded in net income. Changes in the fair value of foreign exchange and interest rate fair value hedges are recorded in Interest income and other and Interest expense, respectively. If hedge accounting is discontinued, the carrying value of the hedged item is no longer adjusted and the cumulative fair value adjustments to the carrying value of the hedged item are amortized to net income over the remaining term of the original hedging relationship.

In a cash flow hedging relationship, the change in the fair value of the hedging derivative is recognized in OCI. When hedge accounting is discontinued, the amounts recognized previously in AOCI are reclassified to Revenues, Interest expense and Interest income and other, as appropriate, during the periods when the variability in cash flows of the hedged item affects net income or as the original hedged item settles. Gains and losses on derivatives are reclassified immediately to net income from AOCI when the hedged item is sold or terminated early, or when it becomes probable that the anticipated transaction will not occur.

In hedging the foreign currency exposure of a net investment in a foreign operation, the foreign exchange gains and losses on the hedging instruments are recognized in OCI. The amounts recognized previously in AOCI are reclassified to net income in the event the Company reduces its net investment in a foreign operation.

In some cases, derivatives do not meet the specific criteria for hedge accounting treatment. In these instances, the changes in fair value are recorded in net income in the period of change.

The recognition of gains and losses on derivatives for Canadian natural gas regulated pipelines exposures is determined through the regulatory process. Gains and losses arising from changes in the fair value of derivatives accounted for as part of RRA, including those that qualify for hedge accounting treatment, are refunded or recovered through the tolls charged by the Company. As a result, these gains and losses are deferred as regulatory assets or regulatory liabilities and are refunded to or collected from ratepayers in subsequent years when the derivative settles.

TCPL Consolidated financial statements 2018 15 Derivatives embedded in other financial instruments or contracts (host instrument) are recorded as separate derivatives. Embedded derivatives are measured at fair value if their economic characteristics are not clearly and closely related to those of the host instrument, their terms are the same as those of a stand-alone derivative and the total contract is not held for trading or accounted for at fair value. When changes in the fair value of embedded derivatives are measured separately, they are included in net income.

Long-Term Debt Transaction Costs and Issuance Costs The Company records long-term debt transaction costs and issuance costs as a deduction from the carrying amount of the related debt liability and amortizes these costs using the effective interest method for all costs except those related to the Canadian natural gas regulated pipelines, which continue to be amortized on a straight-line basis in accordance with the provisions of regulatory tolling mechanisms.

Guarantees Upon issuance, the Company records the fair value of certain guarantees entered into by the Company on behalf of a partially-owned entity or by partially-owned entities for which contingent payments may be made. The fair value of these guarantees is estimated by discounting the cash flows that would be incurred by the Company if letters of credit were used in place of the guarantees as appropriate in the circumstances. Guarantees are recorded as an increase to Equity investments or Plant, property and equipment and a corresponding liability is recorded in Other long-term liabilities. The release from the obligation is recognized either over the term of the guarantee or upon expiration or settlement of the guarantee.

16 TCPL Consolidated financial statements 2018 3. ACCOUNTING CHANGES

Changes in Accounting Policies for 2018 Revenue from contracts with customers In 2014, the FASB issued new guidance on revenue from contracts with customers. The new guidance requires that an entity recognize revenue from these contracts in accordance with a prescribed model. This model is used to depict the transfer of promised goods or services to customers in amounts that reflect the total consideration to which it expects to be entitled during the term of the contract in exchange for those promised goods or services. Goods or services that are promised to a customer are referred to as the Company's "performance obligations." The total consideration to which the Company expects to be entitled can include fixed and variable amounts. The Company has variable revenue that is subject to factors outside the Company’s influence, such as market prices, actions of third parties and weather conditions. The Company considers this variable revenue to be "constrained" as it cannot be reliably estimated, and therefore recognizes variable revenue when the service is provided.

The new guidance also requires additional disclosures about the nature, amount, timing and uncertainty of revenue recognition and related cash flows.

The Company’s accounting policies related to revenue recognition have not substantially changed as a result of adopting the new guidance on revenue from contracts with customers. Results reported for 2018 reflect the application of the new guidance, while the 2017 and 2016 comparative results were prepared and reported under previous revenue recognition guidance which is referred to herein as "legacy U.S. GAAP." Under legacy U.S. GAAP, revenues were recognized when the risk, rewards, and benefits were transferred to the customer by the Company providing the goods or services under the contract, in an amount the Company expected to collect from the customer.

Under the new guidance applied in 2018, revenues are recognized when the Company satisfies its performance obligations by transferring control of the promised goods or services to its customers, in an amount that reflects the consideration the Company expects to be entitled to in exchange for those goods or services. The Company has elected to utilize a practical expedient to recognize revenues from its U.S. and certain Mexico natural gas pipelines contracts as customers are invoiced. The new guidance was effective January 1, 2018, was applied using the modified retrospective transition method, and did not result in any material differences in the amount and timing of revenue recognition. Refer to Note 5, Revenues, for further information related to the impact of adopting the new guidance.

Financial instruments In January 2016, the FASB issued new guidance on the accounting for equity investments and financial liabilities. The new guidance changes the income statement effect of equity investments and the recognition of changes in the fair value of financial liabilities when the fair value option is elected. The new guidance also requires the Company to assess valuation allowances for deferred tax assets related to available for sale debt securities in combination with their other deferred tax assets. This new guidance was effective January 1, 2018 and did not have a material impact on the Company's consolidated financial statements.

Income taxes In October 2016, the FASB issued new guidance on the income tax effects of intra-entity transfers of assets other than inventory. The new guidance requires the recognition of deferred and current income taxes for intra-entity asset transfers when the transfer occurs. The new guidance was effective January 1, 2018, was applied using a modified retrospective approach, and resulted in an adjustment to retained earnings of $95 million.

In February 2018, the FASB issued new guidance that allows a reclassification from AOCI to retained earnings for stranded tax effects resulting from U.S. Tax Reform. This guidance can be applied either in the period of adoption or retrospectively to each period (or periods) in which the effect of the change is recognized. This new guidance is effective January 1, 2019, however, early adoption is permitted. The Company elected to early adopt this guidance effective fourth quarter 2018 and used a portfolio approach for releasing the income tax effects from AOCI to retained earnings. The Company applied this guidance retrospectively, at the beginning of the period of adoption, resulting in an adjustment to retained earnings of $17 million.

TCPL Consolidated financial statements 2018 17 Restricted cash In November 2016, the FASB issued new guidance on restricted cash and cash equivalents on the statement of cash flows. The new guidance requires that the statement of cash flows explain the change during the period in the total cash and cash equivalents balance, and amounts generally described as restricted cash or restricted cash equivalents. Restricted cash and cash equivalents will be included with cash and cash equivalents when reconciling the beginning of period and end of period total amounts on the statement of cash flows. This new guidance was effective January 1, 2018, was applied retrospectively, and did not have an impact on the Company's consolidated financial statements.

Employee post-retirement benefits In March 2017, the FASB issued new guidance that requires entities to disaggregate the current service cost component from the other components of net benefit cost and present it with other current compensation costs for related employees in the income statement. The new guidance also requires that the other components of net benefit cost be presented elsewhere in the income statement and excluded from income from operations if such a subtotal is presented. In addition, the new guidance makes changes to the components of net benefit cost that are eligible for capitalization. Entities must use a retrospective transition method to adopt the requirement for separate presentation in the income statement of the components of net benefit cost, and a prospective transition method to adopt the change to capitalization of benefit costs. This new guidance was effective January 1, 2018 and did not have a material impact on the Company's consolidated financial statements.

Hedge accounting In August 2017, the FASB issued new guidance making more financial and non-financial hedging strategies eligible for hedge accounting. The new guidance also amends the presentation requirements relating to the change in fair value of a derivative and requires additional disclosures including cumulative basis adjustments for fair value hedges and the effect of hedging on individual line items in the statement of income. This new guidance is effective January 1, 2019 with early adoption permitted. This new guidance, which the Company elected to adopt effective January 1, 2018, was applied prospectively and did not have a material impact on the Company's consolidated financial statements.

Derecognition of Nonfinancial Assets In February 2017, the FASB issued new guidance that clarifies the scope provisions of nonfinancial assets and how to allocate consideration to each distinct asset. The FASB also amended the guidance for derecognition of a distinct nonfinancial asset in partial sale transactions. This new guidance was effective January 1, 2018, was applied using the modified retrospective transition method and did not have a material impact on the Company's consolidated financial statements.

Goodwill impairment In January 2017, the FASB issued new guidance on simplifying the test for goodwill impairment by eliminating Step 2 of the impairment test, which is the requirement to calculate the implied fair value of goodwill to measure the impairment charge. Instead, entities will record an impairment charge based on the excess of a reporting unit’s carrying amount over its fair value. This new guidance is effective January 1, 2020 with early adoption permitted. The Company elected to adopt this guidance effective fourth quarter 2018 as it simplified goodwill impairment testing. The guidance was applied prospectively and used in the 2018 annual goodwill impairment test.

Future Accounting Changes Leases In February 2016, the FASB issued new guidance on the accounting for leases. The new guidance amends the definition of a lease such that, in order for an arrangement to qualify as a lease, the lessee is required to have both (1) the right to obtain substantially all of the economic benefits from the use of the asset and (2) the right to direct the use of the asset. The new guidance also establishes a right-of-use (ROU) model that requires a lessee to recognize a ROU asset and corresponding lease liability on the balance sheet for all leases with a term longer than 12 months. Lessees will classify leases as finance or operating, with classification affecting the pattern of expense recognition in the statement of income. The new guidance does not make extensive changes to lessor accounting. The Company currently expects that substantially all of its leases where the Company is the lessor will continue to be classified as operating leases under the new standard.

In January 2018, the FASB issued an optional practical expedient, to be applied upon transition, to omit the evaluation of land easements not previously accounted for as leases that existed or expired prior to the entity's adoption of the new lease guidance. An entity that elects this practical expedient is required to apply it consistently to all of its existing or expired land easements not previously accounted for as leases. The Company will apply this practical expedient upon transition to the new standard.

18 TCPL Consolidated financial statements 2018 The new guidance is effective January 1, 2019, with early adoption permitted. The Company will adopt the new standard on its effective date. A modified retrospective transition approach is required, applying the new standard to all leases existing at the date of initial application being January 1, 2019. In July 2018, the FASB issued a transition option allowing entities to not apply the new guidance, including disclosure requirements, to the comparative periods they present in their financial statements in the year of adoption. The Company will apply this transition option and use the effective date as the date of initial application. Consequently, financial information will not be updated and disclosures required under the new standard will not be provided for dates and periods before January 1, 2019.

The Company will elect the package of practical expedients which permits entities not to reassess prior conclusions about lease identification, lease classification and initial direct costs under the rules of the new standard.

The Company believes that the most significant effects of adoption will relate to the recognition of new ROU assets and lease liabilities on the Company's balance sheet for its operating leases and providing significant new disclosures about the Company's leasing activities. The guidance will not impact the Company's income statement. On adoption, the Company will recognize ROU assets of approximately $606 million and additional operating lease liabilities of approximately $600 million based on the present value of the remaining minimum lease payments for existing operating leases. The new standard also provides practical expedients for a Company’s ongoing accounting. The Company will elect the short-term lease recognition exemption for all eligible leases. This means, for those leases that qualify, the Company will not recognize ROU assets or lease liabilities. The Company will also elect the practical expedient to not separate lease and non-lease components for all leases for which the Company is the lessee and for facility and liquids tank terminals for which the Company is the lessor.

Measurement of credit losses on financial instruments In June 2016, the FASB issued new guidance that significantly changes how entities measure credit losses for most financial assets and certain other financial instruments that are not measured at fair value through net income. The new guidance amends the impairment model of financial instruments basing it on expected losses rather than incurred losses. These expected credit losses will be recognized as an allowance rather than as a direct write down of the amortized cost basis. The new guidance is effective January 1, 2020 and will be applied using a modified retrospective approach. The Company is currently evaluating the impact of the adoption of this guidance and has not yet determined the effect on its consolidated financial statements. Fair value measurement In August 2018, the FASB issued new guidance that amends certain disclosure requirements for fair value measurements. This new guidance is effective January 1, 2020, however, early adoption of certain or all requirements is permitted. The Company is currently evaluating the timing and impact of adoption of this guidance and has not yet determined the effect on its consolidated financial statements.

Defined benefit plans In August 2018, the FASB issued new guidance which amends and clarifies disclosure requirements related to DB pension and other post retirement benefit plans. This new guidance is effective January 1, 2021, and will be applied on a retrospective basis, however early adoption is permitted. The Company is currently evaluating the timing and impact of the adoption of this guidance and has not yet determined the effect on its consolidated financial statements.

Implementation costs of cloud computing arrangements In August 2018, the FASB issued new guidance requiring an entity in a hosting arrangement that is a service contract to follow the guidance for internal-use software to determine which implementation costs should be capitalized as an asset and which costs should be expensed. The guidance also requires the entity to amortize the capitalized implementation costs of a hosting arrangement over the term of the arrangement. This guidance is effective January 1, 2020, however, early adoption is permitted. This guidance can be applied either retrospectively or prospectively to all implementation costs incurred after the date of adoption. The Company is currently evaluating the timing and impact of adoption of this guidance and has not yet determined the effect on its consolidated financial statements.

Consolidation In October 2018, the FASB issued new guidance for determining whether fees paid to decision makers and service providers are variable interests for indirect interests held through related parties under common control. This new guidance is effective January 1, 2020, and will be applied on a retrospective basis, however early adoption is permitted. The Company is currently evaluating the timing and impact of the adoption of this guidance and has not yet determined the effect on its consolidated financial statements.

TCPL Consolidated financial statements 2018 19 4. SEGMENTED INFORMATION

year ended December 31, 2018 Canadian U.S. Mexico Natural Gas Natural Gas Natural Gas Liquids (millions of Canadian $) Pipelines Pipelines Pipelines Pipelines Energy Corporate1 Total

Revenues 4,038 4,314 619 2,584 2,124 — 13,679 Intersegment revenues — 162 — — 56 (218) 2 — 4,038 4,476 619 2,584 2,180 (218) 13,679 Income from equity investments 12 256 22 64 355 5 3 714 Plant operating costs and other (1,405) (1,368) (34) (630) (313) 159 2 (3,591) Commodity purchases resold — — — — (1,488) — (1,488) Property taxes (266) (199) — (98) (6) — (569) Depreciation and amortization (1,129) (664) (97) (341) (119) — (2,350) Goodwill and other asset impairment charges — (801) — — — — (801) Gain on sale of assets — — — — 170 — 170 Segmented earnings/(losses) 1,250 1,700 510 1,579 779 (54) 5,764 Interest expense (2,379) Allowance for funds used during construction 526 Interest income and other3 (78) Income before income taxes 3,833 Income tax expense (403) Net income 3,430 Net loss attributable to non-controlling interests 185 Net income attributable to controlling interests and to common shares 3,615

Capital spending Capital expenditures 2,442 5,591 463 110 767 45 9,418 Capital projects in development 36 1 — 459 — — 496 Contributions to equity investments — 179 334 12 490 — 1,015 2,478 5,771 797 581 1,257 45 10,929

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.

20 TCPL Consolidated financial statements 2018 year ended December 31, 2017 Canadian U.S. Mexico Natural Gas Natural Gas Natural Gas Liquids (millions of Canadian $) Pipelines Pipelines Pipelines Pipelines Energy Corporate1 Total

Revenues 3,693 3,584 570 2,009 3,593 — 13,449 Intersegment revenues — 51 — — — (51) 2 — 3,693 3,635 570 2,009 3,593 (51) 13,449 Income/(loss) from equity investments 11 240 (9) (3) 471 63 3 773 Plant operating costs and other (1,300) (1,340) (42) (623) (550) (51) 2 (3,906) Commodity purchases resold — — — — (2,382) — (2,382) Property taxes (260) (181) — (89) (39) — (569) Depreciation and amortization (908) (594) (93) (309) (151) — (2,055) Goodwill and other asset impairment charges — — — (1,236) (21) — (1,257) Gain on sale of assets — — — — 631 — 631 Segmented earnings/(losses) 1,236 1,760 426 (251) 1,552 (39) 4,684 Interest expense (2,137) Allowance for funds used during construction 507 Interest income and other3 183 Income before income taxes 3,237 Income tax recovery 107 Net income 3,344 Net income attributable to non-controlling interests (238) Net income attributable to controlling interests and to common shares 3,106

Capital spending Capital expenditures 2,106 3,712 833 341 350 41 7,383 Capital projects in development 75 — — 71 — — 146 Contributions to equity investments — 118 1,121 117 325 — 1,681 2,181 3,830 1,954 529 675 41 9,210

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.

TCPL Consolidated financial statements 2018 21 year ended December 31, 2016 Canadian U.S. Mexico Natural Gas Natural Gas Natural Gas Liquids (millions of Canadian $) Pipelines Pipelines Pipelines Pipelines Energy Corporate1 Total

Revenues 3,682 2,526 378 1,755 4,206 — 12,547 Intersegment revenues — 56 — — — (56) 2 — 3,682 2,582 378 1,755 4,206 (56) 12,547 Income/(loss) from equity investments 12 214 (3) (1) 292 — 514 Plant operating costs and other (1,245) (1,057) (43) (568) (884) (64) 2 (3,861) Commodity purchases resold — — — — (2,172) — (2,172) Property taxes (267) (120) — (88) (80) — (555) Depreciation and amortization (875) (425) (45) (292) (302) — (1,939) Goodwill and other asset impairment charges — — — — (1,388) — (1,388) Loss on assets held for sale/sold — (4) — — (829) — (833) Segmented earnings/(losses) 1,307 1,190 287 806 (1,157) (120) 2,313 Interest expense (1,927) Allowance for funds used during construction 419 Interest income and other 117 Income before income taxes 922 Income tax expense (349) Net income 573 Net income attributable to non-controlling interests (252) Net income attributable to controlling interests and to common shares 321

Capital spending Capital expenditures 1,372 1,517 944 668 473 33 5,007 Capital projects in development 153 — — 142 — — 295 Contributions to equity investments — 5 198 327 235 — 765 1,525 1,522 1,142 1,137 708 33 6,067

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.

22 TCPL Consolidated financial statements 2018 at December 31 (millions of Canadian $) 2018 2017

Total Assets by segment Canadian Natural Gas Pipelines 18,407 16,904 U.S. Natural Gas Pipelines 44,115 35,898 Mexico Natural Gas Pipelines 7,058 5,716 Liquids Pipelines 17,352 15,438 Energy 8,475 8,503 Corporate 3,408 3,551 98,815 86,010

Geographic Information

year ended December 31 (millions of Canadian $) 2018 2017 2016

Revenues Canada – domestic 4,187 3,618 3,697 Canada – export 1,075 1,255 1,177 United States 7,798 8,006 7,295 Mexico 619 570 378 13,679 13,449 12,547

at December 31 (millions of Canadian $) 2018 2017

Plant, Property and Equipment Canada 23,226 21,632 United States 37,385 30,693 Mexico 5,892 4,952 66,503 57,277

TCPL Consolidated financial statements 2018 23 5. REVENUES On January 1, 2018, the Company adopted new FASB guidance on revenue from contracts with customers using the modified retrospective transition method for all contracts that were in effect on the date of adoption. Results reported for 2018 reflect the application of the new guidance, while the 2017 and 2016 comparative results were prepared and reported under previous revenue recognition guidance which is referred to herein as "legacy U.S. GAAP."

Disaggregation of Revenues The following tables summarizes total Revenues for the year ended December 31, 2018.

Canadian U.S. Mexico Natural Natural Natural Gas Gas Gas Liquids (millions of Canadian $) Pipelines Pipelines Pipelines Pipelines Energy Total

Revenues from contracts with customers Capacity arrangements and transportation 4,038 3,549 614 2,079 — 10,280 Power generation — — — — 1,771 1,771 Natural gas storage and other — 654 5 3 81 743 4,038 4,203 619 2,082 1,852 12,794 Other revenues1,2 — 111 — 502 272 885 4,038 4,314 619 2,584 2,124 13,679

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 23, 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.

Revenues from contracts with customers are recognized net of any taxes collected from customers which are subsequently remitted to governmental authorities. The Company's contracts with customers include natural gas and liquids pipelines capacity arrangements and transportation contracts, power generation contracts, natural gas storage and other contracts.

Financial Statement Impact of Adopting Revenue from Contracts with Customers The Company adopted the new guidance using the modified retrospective transition method. As a practical expedient under this transition method, the Company is not required to analyze completed contracts at the date of adoption. As a result, of adopting the new guidance, the Company made the adjustments described below on January 1, 2018.

Capacity Arrangements and Transportation For certain natural gas pipeline capacity contracts, amounts are invoiced to the customer in accordance with the terms of the contract, however, the related revenues are recognized when the Company satisfies its performance obligation to provide committed capacity ratably over the term of the contract. This difference in timing between revenue recognition and amounts invoiced creates a contract asset or contract liability under the new revenue recognition guidance. Under legacy U.S. GAAP, these differences were recorded as Accounts receivable. Under the new guidance, contract assets are included in Other current assets and Intangibles and other assets and contract liabilities are included in Accounts payable and other and Other long-term liabilities.

24 TCPL Consolidated financial statements 2018 Impact of New Revenue Recognition Guidance on Date of Adoption The following table illustrates the impact of the adoption of the new revenue recognition guidance on the Company's previously reported consolidated balance sheet line items:

As reported (millions of Canadian $) December 31, 2017 Adjustment January 1, 2018

Current Assets Accounts receivable 2,537 (62) 2,475 Other1 691 79 770 Current Liabilities Accounts payable and other2 4,071 17 4,088

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

Pro-forma Financial Statements under Legacy U.S. GAAP As required by the new revenue recognition guidance, the following tables illustrate the pro-forma impact on the affected line items on the Consolidated balance sheet, as at December 31, 2018, using legacy U.S. GAAP:

December 31, 2018 Pro-forma using legacy U.S. (millions of Canadian $) As reported GAAP

Current Assets Accounts receivable 2,548 2,707 Other 1,180 1,021

Contract Balances

(millions of Canadian $) December 31, 2018 January 1, 2018

Receivables from contracts with customers 1,684 1,736 Contract assets1 159 79 Long-term contract assets2 21 — Contract liabilities3 11 17 Long-term contract liabilities4 121 —

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, $17 million of revenue was recognized that was included in the contract liability at the beginning of the year. 4 Comprised of deferred revenue recorded in Other long-term liabilities on the Consolidated balance sheet.

Contract assets and long-term contract assets primarily relate to the Company’s right to revenues for services completed but not invoiced at the reporting date on long-term committed capacity natural gas pipelines contracts. The change in contract assets is primarily related to the transfer to Accounts receivable when these rights become unconditional and the customer is invoiced, as well as the recognition of additional revenues that remain to be invoiced. Contract liabilities and long-term contract liabilities primarily relate to force majeure fixed capacity payments received on long-term capacity arrangements in Mexico.

TCPL Consolidated financial statements 2018 25 Future Revenues from Remaining Performance Obligations As required by the new revenue recognition guidance, the following provides disclosure on future revenues allocated to remaining performance obligations representing contracted revenues that have not yet been recognized. Certain contracts that qualify for the use of one of the following practical expedients are excluded from the future revenues disclosures: 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.

The following provides a discussion of the transaction price allocated to future performance obligations as well as practical expedients used by the Company.

Capacity Arrangements and Transportation As at December 31, 2018, future revenues from long-term pipeline capacity arrangements and transportation contracts extending through 2043 are approximately $30.1 billion, of which approximately $6.0 billion is expected to be recognized in 2019.

Future revenues from long-term capacity arrangements and transportation contracts do not include constrained variable revenues or arrangements to which the right to invoice practical expedient has been applied. As a result, these amounts are not representative of potential total future revenues expected from these contracts.

Future revenues from the Company's Canadian natural gas pipelines' regulated firm capacity contracts include fixed revenues for the time periods that tolls under current rate settlements are in effect, which is approximately one to three years. Many of these contracts are long-term in nature and revenues from the remaining performance obligations that extend beyond the current rate settlement term are considered to be fully constrained since future tolls remain unknown. Revenues from these contracts will be recognized once the performance obligation to provide capacity has been satisfied and the regulator has approved the applicable tolls. In addition, the Company considers interruptible transportation service revenues to be variable revenues since volumes cannot be estimated. These variable revenues are recognized on a monthly basis when the Company satisfies the performance obligation and have been excluded from the future revenues disclosure as the Company applies the practical expedient related to variable revenues to these contracts. The future variable revenues earned under these contracts are allocated entirely to unsatisfied performance obligations at December 31, 2018.

The Company also applies the right to invoice practical expedient to all of its U.S. and certain of its Mexico regulated natural gas pipeline capacity arrangements and flow-through revenues. Revenues from regulated capacity arrangements are recognized based on current rates and flow-through revenues are earned from the recovery of operating expenses. These revenues are recognized on a monthly basis as the Company performs the services and are excluded from future revenues disclosures.

Revenues from liquids pipelines capacity arrangements have a variable component based on volumes transported. As a result, these variable revenues are excluded from the future revenues disclosures as the Company applies the practical expedient related to variable revenues to these contracts. The future variable revenues earned under these contracts are allocated entirely to unsatisfied performance obligations at December 31, 2018.

Power Generation The Company has long-term power generation contracts extending through 2030. Revenues from power generation have a variable component related to market prices that are subject to factors outside the Company’s influence. These revenues are considered to be fully constrained and are recognized on a monthly basis when the Company satisfies the performance obligation. The Company applies the practical expedient related to variable revenues to these contracts. As a result, future revenues from these contracts are excluded from the disclosures.

26 TCPL Consolidated financial statements 2018 Natural Gas Storage and Other As at December 31, 2018, future revenues from long-term natural gas storage and other contracts extending through 2033 are approximately $1.2 billion, of which approximately $283 million is expected to be recognized in 2019. The Company applies the practical expedients related to contracts that are for a duration of one year or less and where it recognizes variable consideration, and therefore excludes the related revenues from the future revenues disclosure. As a result, this amount is lower than the potential total future revenues from these contracts.

6. ASSETS HELD FOR SALE Coolidge Generating Station On December 14, 2018, TCPL entered into an agreement to sell its Coolidge generating station in Arizona to SWG Coolidge Holdings, LLC for approximately US$465 million, subject to timing of the close and related adjustments. In January 2019, pursuant to the terms of the Coolidge PPA, Salt River Project Agriculture Improvement and Power District, the counterparty to this arrangement, exercised their right of first refusal on this sale.

The sale will result in an estimated gain of approximately $65 million ($50 million after tax) including the impact of an estimated $10 million of foreign currency translation gains. This gain will be recognized upon closing of the sale transaction, which is expected to occur mid-2019.

At December 31, 2018, the related assets and liabilities were classified as held for sale in the Energy segment as follows:

(millions of Canadian $)

Assets held for sale Accounts receivable 6 Plant, property and equipment 537 Total assets held for sale 543 Liabilities related to assets held for sale Other long-term liabilities (3) Total liabilities related to assets held for sale1 (3)

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

7. OTHER CURRENT ASSETS

at December 31 (millions of Canadian $) 2018 2017

Fair value of derivative contracts (Note 23) 737 332 Contract assets (Note 5) 159 — Regulatory assets (Note 10) 83 23 Cash provided as collateral 55 99 Prepaid expenses 41 109 Other 105 128 1,180 691

TCPL Consolidated financial statements 2018 27 8. PLANT, PROPERTY AND EQUIPMENT

2018 2017 at December 31 Accumulated Net Accumulated Net (millions of Canadian $) Cost Depreciation Book Value Cost Depreciation Book Value

Canadian Natural Gas Pipelines NGTL System Pipeline 10,764 4,500 6,264 10,153 4,190 5,963 Compression 3,289 1,677 1,612 3,021 1,593 1,428 Metering and other 1,247 613 634 1,188 569 619 15,300 6,790 8,510 14,362 6,352 8,010 Under construction 2,111 — 2,111 940 — 940 17,411 6,790 10,621 15,302 6,352 8,950 Canadian Mainline Pipeline 10,077 6,777 3,300 9,763 6,455 3,308 Compression 3,642 2,656 986 3,605 2,499 1,106 Metering and other 652 241 411 655 207 448 14,371 9,674 4,697 14,023 9,161 4,862 Under construction 149 — 149 156 — 156 14,520 9,674 4,846 14,179 9,161 5,018 Other Canadian Natural Gas Pipelines1 Other 1,842 1,420 422 1,815 1,363 452 Under construction 124 — 124 4 — 4 1,966 1,420 546 1,819 1,363 456 33,897 17,884 16,013 31,300 16,876 14,424 U.S. Natural Gas Pipelines Columbia Gas Pipeline 6,711 251 6,460 3,550 125 3,425 Compression 2,932 132 2,800 1,547 64 1,483 Metering and other 2,884 75 2,809 2,306 37 2,269 12,527 458 12,069 7,403 226 7,177 Under construction 4,347 — 4,347 3,332 — 3,332 16,874 458 16,416 10,735 226 10,509 ANR Pipeline 1,600 443 1,157 1,427 365 1,062 Compression 1,978 388 1,590 1,582 286 1,296 Metering and other 1,217 324 893 961 268 693 4,795 1,155 3,640 3,970 919 3,051 Under construction 272 — 272 358 — 358 5,067 1,155 3,912 4,328 919 3,409

28 TCPL Consolidated financial statements 2018 2018 2017 at December 31 Accumulated Net Accumulated Net (millions of Canadian $) Cost Depreciation Book Value Cost Depreciation Book Value

Other U.S. Natural Gas Pipelines GTN 2,322 951 1,371 2,107 822 1,285 Great Lakes 2,180 1,251 929 1,988 1,113 875 Columbia Gulf 1,753 74 1,679 1,115 37 1,078 Midstream 1,212 91 1,121 1,085 54 1,031 Other2 1,190 474 716 1,950 574 1,376 8,657 2,841 5,816 8,245 2,600 5,645 Under construction 846 — 846 699 — 699 9,503 2,841 6,662 8,944 2,600 6,344 31,444 4,454 26,990 24,007 3,745 20,262 Mexico Natural Gas Pipelines Pipeline 3,172 301 2,871 2,872 214 2,658 Compression 506 41 465 448 30 418 Metering and other 640 91 549 573 65 508 4,318 433 3,885 3,893 309 3,584 Under construction 1,990 — 1,990 1,368 — 1,368 6,308 433 5,875 5,261 309 4,952 Liquids Pipelines Keystone Pipeline System Pipeline 9,780 1,271 8,509 9,002 992 8,010 Pumping equipment 1,065 184 881 1,022 152 870 Tanks and other3 3,598 488 3,110 3,314 385 2,929 14,443 1,943 12,500 13,338 1,529 11,809 Under construction4 18 — 18 456 — 456 14,461 1,943 12,518 13,794 1,529 12,265 Intra-Alberta Pipelines5 Pipeline 762 22 740 748 3 745 Pumping equipment 104 3 101 104 — 104 Tanks and other 291 8 283 259 1 258 1,157 33 1,124 1,111 4 1,107 Under construction 84 — 84 47 — 47 1,241 33 1,208 1,158 4 1,154 15,702 1,976 13,726 14,952 1,533 13,419 Energy Natural Gas6 2,062 708 1,354 2,645 743 1,902 Wind7 — — — 673 204 469 Natural Gas Storage and Other 741 169 572 734 156 578 2,803 877 1,926 4,052 1,103 2,949 Under construction 1,735 — 1,735 1,028 — 1,028 4,538 877 3,661 5,080 1,103 3,977 Corporate 448 210 238 411 168 243 92,337 25,834 66,503 81,011 23,734 57,277

TCPL Consolidated financial statements 2018 29 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 25, Acquisitions and dispositions, for further information.

Bison Impairment At December 31, 2018, the Company evaluated its investment in its Bison natural gas pipeline for impairment in connection with the termination of certain customer transportation agreements. The termination of these agreements released the Company from providing any future services. With the loss of these future cash flows and the persistence of unfavourable market conditions which have inhibited system flows on the pipeline, the Company determined that the asset’s remaining carrying value was no longer recoverable and recognized a non-cash impairment charge of $722 million pre-tax in its U.S. Natural Gas Pipelines segment. The non-cash charge was recorded in Goodwill and other asset impairment charges on the Consolidated statement of income. As Bison is a TC PipeLines, LP asset, in which the Company has a 25.5 per cent interest, the Company's share of the impairment charge, after tax and net of non-controlling interests, was $140 million.

The termination of the transportation agreements resulted in the receipt of $130 million in termination payments which were recorded in Revenues in 2018. The Company's share of this amount, after tax and net of non-controlling interests, was $25 million.

Energy East and Related Projects Impairment On October 5, 2017, the Company informed the NEB that it will not proceed with the Energy East, Eastern Mainline and Upland projects. Based on this decision, the Company evaluated the carrying value of its Property, plant and equipment related to the Eastern Mainline project including AFUDC. Due to the inability to reach a regulatory decision for this project, there were no recoveries of costs from third parties. As a result, the Company recognized a non-cash impairment charge of $83 million ($64 million after tax) in the Liquids Pipelines segment. The non-cash charge was recorded in Goodwill and other asset impairment charges on the Consolidated statement of income.

Energy Turbine Impairment At December 31, 2017, the Company recognized a non-cash impairment charge of $21 million ($16 million after tax) in the Energy segment related to the remaining carrying value of certain equipment after determining that it was no longer recoverable. This turbine equipment was previously purchased for a power development project that did not proceed. The non-cash charge was recorded in Goodwill and other asset impairment charges on the Consolidated statement of income.

30 TCPL Consolidated financial statements 2018 9. EQUITY INVESTMENTS

Income/(Loss) from Equity Equity Investments Investments Ownership year ended December 31 at December 31 Interest at (millions of Canadian $) December 31, 2018 2018 2017 2016 2018 2017

Canadian Natural Gas Pipelines TQM 50.0% 12 11 12 71 68 U.S. Natural Gas Pipelines Northern Border1 50.0% 87 87 92 677 641 Iroquois2 50.0% 60 59 54 291 280 Millennium3 47.5% 75 66 33 511 291 Pennant Midstream3 47.0% 17 11 6 256 228 Other Various 17 17 29 113 92 Mexico Natural Gas Pipelines Sur de Texas4 60.0% 27 66 (3) 627 399 TransGas nil — (12) — — — Liquids Pipelines Grand Rapids5 50.0% 65 17 (1) 1,028 996 Other6 Various (1) (20) — 21 20 Energy Bruce Power7 48.3% 311 434 293 3,166 2,987 Portlands Energy8 50.0% 36 31 33 289 301 ASTC Power Partnership 50.0% — — (37) — — Other Various 8 6 3 63 63 714 773 514 7,113 6,366

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 TCPL 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.

TransGas de Occidente S.A. Impairment In August 2017, TCPL recognized an impairment charge of $12 million on its 46.5 per cent equity investment in TransGas de Occidente S.A. (TransGas). TransGas constructed and operated a natural gas pipeline in Colombia for a 20-year contract term. As per the terms of the agreement, upon completion of the 20-year contract in August 2017, TransGas transferred its pipeline assets to Transportadora de Gas Internacional S.A. The non-cash impairment charge represented the write-down of the remaining carrying value of the equity investment which was recognized in Income from equity investments in the Consolidated statement of income.

TCPL Consolidated financial statements 2018 31 Canaport Energy East Marine Terminal Limited Partnership Impairment On October 5, 2017, the Company informed the NEB that it will not be proceeding with the Energy East, Eastern Mainline and Upland projects. As a result, in October 2017, the Company recognized a non-cash impairment charge of $20 million in Income from equity investments in its Liquids Pipelines segment which represented the carrying value of the equity investment in the Canaport Energy East Marine Terminal Limited Partnership. Due to the inability to reach a regulatory decision for this project, there were no recoveries of costs from third parties.

ASTC Power Partnership Impairment In March 2016, TCPL issued notice to the Balancing Pool of the decision to terminate its Sundance B PPA held through ASTC Power Partnership. In accordance with a provision in the PPA, a buyer was permitted to terminate the arrangement if a change in law occurs that makes the arrangement unprofitable or more unprofitable. As a result of changes in law surrounding the Alberta Specified Gas Emitters Regulation, the Company expected increasing costs related to carbon emissions to continue throughout the remaining term of the PPA resulting in increasing unprofitability. As a result, in first quarter 2016, the Company recognized a non-cash impairment charge of $29 million ($21 million after tax) in its Energy segment Income from equity investments which represented the carrying value of the equity investment in ASTC Partnership. The PPA termination was settled in December 2016.

Distributions and Contributions Distributions received from equity investments for the year ended December 31, 2018 were $1,106 million (2017 – $1,332 million; 2016 – $1,571 million) of which $121 million (2017 – $362 million; 2016 – $727 million) was included in Investing activities in the Consolidated statement of cash flows with respect to distributions received from Bruce Power from its financing program.

Contributions made to equity investments for the year ended December 31, 2018 were $1,015 million (2017 – $1,681 million; 2016 – $765 million) and are included in Investing activities in the Consolidated statement of cash flows. For 2018, contributions include $179 million (2017 – $977 million) related to TCPL's proportionate share of the Sur de Texas debt financing requirements.

Summarized Financial Information of Equity Investments

year ended December 31 (millions of Canadian $) 2018 2017 2016

Income Revenues 4,836 4,913 4,336 Operating and other expenses (3,545) (2,993) (3,068) Net income 1,515 1,636 1,080 Net income attributable to TCPL 714 773 514

at December 31 (millions of Canadian $) 2018 2017

Balance Sheet Current assets 2,209 2,176 Non-current assets 20,647 17,869 Current liabilities (2,049) (1,577) Non-current liabilities (9,042) (8,217)

Loan receivable from affiliate TCPL holds a 60 per cent equity interest in a joint venture with IEnova to build, own and operate the Sur de Texas pipeline. In 2017, TCPL entered into a MXN$21.3 billion unsecured revolving credit facility with the joint venture, which bears interest at a floating rate and matures in March 2022. At December 31, 2018, the Company’s consolidated balance sheet included a MXN $18.9 billion or $1.3 billion (2017 – MXN$14.4 billion or $0.9 billion) loan receivable from the Sur de Texas joint venture which represents TCPL’s proportionate share of long-term debt financing requirements related to the joint venture. Interest income and other included interest income of $120 million in 2018 (2017 – $34 million) from this joint venture with a corresponding proportionate share of interest expense recorded in Income from equity investments.

32 TCPL Consolidated financial statements 2018 10. RATE-REGULATED BUSINESSES TCPL's businesses that apply RRA currently include certain Canadian, U.S. and Mexico natural gas pipelines, and certain regulated U.S. natural gas storage operations. Rate-regulated businesses account for and report assets and liabilities consistent with the resulting economic impact of the regulators' established rates, provided the rates are designed to recover the costs of providing the regulated service and the competitive environment makes it probable that such rates can be charged and collected. Certain expenses and credits subject to utility regulation or rate determination that would otherwise be reflected in the statement of income are deferred on the balance sheet and are expected to be included in future service rates and recovered from or refunded to customers in subsequent years.

Canadian Regulated Operations TCPL's Canadian natural gas pipelines are regulated by the NEB under the National Energy Board Act. The NEB regulates the construction and operation of facilities, and the terms and conditions of services, including rates, for the Company's Canadian regulated natural gas transmission systems.

TCPL's Canadian natural gas transmission services are supplied under natural gas transportation tariffs that provide for cost recovery, including return of and return on capital as approved by the NEB. Rates charged for these services are typically set through a process that involves filing an application with the regulator wherein forecasted operating costs, including a return of and on capital, determine the revenue requirement for the upcoming year or multiple years. To the extent actual costs and revenues are more or less than forecasted costs and revenues, the regulators generally allow the difference to be deferred to a future period and recovered or refunded in rates at that time. Differences between actual and forecasted costs that the regulator does not allow to be deferred are included in the determination of net income in the year they occur. The Company's most significant regulated Canadian natural gas pipelines are described below.

NGTL System NGTL's 2018 results reflect the terms of the 2018-2019 Revenue Requirement Settlement (the 2018-2019 Settlement) approved by the NEB in June 2018. This two-year settlement includes an ROE of 10.1 per cent on 40 per cent deemed common equity, a composite depreciation rate of approximately 3.5 per cent, a mechanism for sharing variances above and below a fixed annual operating, maintenance and administration (OM&A) cost amount and flow-through treatment of all other costs.

Canadian Mainline The Canadian Mainline currently operates under the terms of the 2015-2030 Tolls Application approved in 2014 (the NEB 2014 Decision). The terms of the settlement include an ROE of 10.1 per cent on deemed common equity of 40 per cent, an incentive mechanism that has both upside and downside risk and a $20 million after-tax annual TCPL contribution to reduce the revenue requirement. Toll stabilization is achieved through the use of deferral accounts, namely the bridging amortization account and the long-term adjustment account (LTAA), to capture the surplus or shortfall between the Company's revenues and cost of service for each year over the 2015-2020 six-year fixed toll term of the NEB 2014 Decision. The NEB 2014 Decision also directed TCPL to file an application to review tolls for the 2018-2020 period. In December 2018, an NEB decision was received on the 2018-2020 Tolls Review (NEB 2018 Decision) which included an accelerated amortization of the December 31, 2017 LTAA balance and an increase to the composite depreciation rate from 3.2 per cent to 3.9 per cent.

U.S. Regulated Operations TCPL's U.S. regulated natural gas pipelines operate under the provisions of the Natural Gas Act of 1938, the Natural Gas Policy Act of 1978 (NGA) and the Energy Policy Act of 2005, and are subject to the jurisdiction of the FERC. The NGA grants the FERC authority over the construction and operation of pipelines and related facilities, including the regulation of tariffs which incorporates maximum and minimum rates for services and allows U.S. regulated natural gas pipelines to discount or negotiate rates on a non-discriminatory basis. The Company's most significant regulated U.S. natural gas pipelines, based on effective ownership and total operated pipe length, are described below.

In 2018, FERC prescribed changes (2018 FERC Actions) related to U.S. Tax Reform and income taxes for rate-making purposes in a master limited partnership (MLP) that impact future earnings and cash flows of FERC-regulated pipelines. The 2018 FERC Actions also established a process and schedule by which all FERC-regulated interstate pipelines and natural gas storage facilities had to either (i) file a new uncontested rate settlement or (ii) file a FERC Form 501-G that quantifies the isolated impact of U.S. Tax Reform on FERC-regulated pipelines and natural gas storage assets as well as the impact of the 2018 FERC Actions on pipelines held by MLPs.

TCPL Consolidated financial statements 2018 33 The impact of the 2018 FERC Actions on the Company's more significant U.S. regulated natural gas pipelines is included below.

Columbia Gas Columbia Gas' natural gas transportation and storage services are provided under a tariff at rates subject to FERC approval. In 2013, the FERC approved a modernization settlement which provides for cost recovery and return on investment of up to US$1.5 billion over a five-year period to modernize the Columbia Gas system to improve system integrity and enhance service reliability and flexibility. In March 2016, an extension of this settlement was approved by the FERC, which will allow for the cost recovery and return on additional expanded scope investment of US$1.1 billion over a three-year period through 2020.

In response to the 2018 FERC Actions, Columbia Gas filed a Form 501-G including a statement explaining its rationale why the pipeline’s rates are not required to change.

ANR Pipeline ANR Pipeline operates under rates established under a FERC-approved rate settlement in 2016. Under terms of the 2016 settlement, neither ANR Pipeline nor the settling parties could file for new rates to become effective earlier than August 1, 2019. However, ANR Pipeline is required to file for new rates to be effective no later than August 1, 2022.

In December 2018, ANR Pipeline filed a Form 501-G including a statement explaining its rationale why the pipeline’s rates are not required to change.

Columbia Gulf Columbia Gulf’s natural gas transportation services are provided under a tariff at rates subject to FERC approval. In September 2016, FERC issued an order approving an uncontested settlement following a FERC-initiated rate proceeding pursuant to Section 5 of the NGA, which required a reduction in Columbia Gulf’s daily maximum recourse rate and addressed treatment of post-retirement benefits other than pensions, pension expense and regulatory expenses. The FERC order also required Columbia Gulf to file a general rate case under section 4 of the NGA by January 31, 2020, for rates to take effect by August 1, 2020.

In response to the 2018 FERC Actions, Columbia Gulf filed a Form 501-G including a statement explaining its rationale why the pipeline’s rates are not required to change.

TC PipeLines, LP TCPL owns a 25.5 per cent interest in TC PipeLines, LP, which has ownership interests in eight wholly-owned or partially-owned natural gas pipelines serving major markets in the U.S. As TC PipeLines, LP is an MLP, all pipelines it owns wholly or in part were potentially impacted by the 2018 FERC Actions which creates a presumption that entities whose earnings are not taxed through a corporation should not be permitted to recover an income tax allowance in their regulated cost-of-service rates. Additionally, to the extent an entity’s income tax allowance is eliminated from rates, it must also eliminate its existing accumulated deferred income tax (ADIT) balance from its rate base. Refer to Note 16, Income Taxes for further information regarding the impact of these changes to TCPL.

Great Lakes Great Lakes reached a rate settlement with its customers, which was approved by FERC on February 22, 2018, decreasing Great Lakes' maximum transportation rates by 27 per cent effective October 1, 2017. This settlement does not contain a moratorium and Great Lakes will be required to file for new rates no later than March 31, 2022, with new rates to be effective October 1, 2022. As a result of the 2018 FERC Actions, Great Lakes made a limited Section 4 filing which had the effect of reducing rates by 2 per cent from what was in place prior to the FERC changes in 2018. The reduction in rates became effective on February 1, 2019 after the limited Section 4 filing was accepted by FERC on January 31, 2019.

Mexico Regulated Operations TCPL's Mexico natural gas pipelines are regulated by the CRE and operate in accordance with CRE-approved tariffs. The rates in effect on TCPL's Mexico natural gas pipelines were established based on CRE-approved contracts that provide for the recovery of costs of providing services and a return on and of invested capital.

34 TCPL Consolidated financial statements 2018 Regulatory Assets and Liabilities

Remaining at December 31 Recovery/ Settlement (millions of Canadian $) 2018 2017 Period (years)

Regulatory Assets Deferred income taxes1 1,051 940 n/a Operating and debt-service regulatory assets2 12 — 1 Pensions and other post-retirement benefits1,3 379 388 n/a Foreign exchange on long-term debt1,4 46 — 1-11 Other 143 71 n/a 1,631 1,399 Less: Current portion included in Other current assets (Note 7) 83 23 1,548 1,376

Regulatory Liabilities Operating and debt-service regulatory liabilities2 96 188 1 Pensions and other post-retirement benefits3 53 164 n/a ANR related post-employment and retirement benefits other than pension5 54 66 n/a Long term adjustment account6 1,015 1,142 2-45 Bridging amortization account6 305 202 12 Pipeline abandonment trust balance 1,113 825 n/a Cost of removal7 261 216 n/a Deferred income taxes 165 75 n/a Deferred income taxes – U.S. Tax Reform8 1,394 1,659 n/a Other 65 47 n/a 4,521 4,584 Less: Current portion included in Accounts payable and other (Note 14) 591 263 3,930 4,321

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.

TCPL Consolidated financial statements 2018 35 11. GOODWILL The Company has recorded the following Goodwill on its acquisitions:

U.S. Natural (millions of Canadian $) Gas Pipelines

Balance at January 1, 2017 13,958 Columbia adjustment (Note 25) 71 Foreign exchange rate changes (945) Balance at December 31, 2017 13,084 Tuscarora impairment charge (79) Foreign exchange rate changes 1,173 Balance at December 31, 2018 14,178

Tuscarora In the fourth quarter of 2018, the Company finalized its regulatory filing for Tuscarora in response to the 2018 FERC Actions and Form 501-G requirements. In January 2019, Tuscarora reached a settlement-in-principle with its customers which was filed with FERC. As a result of these developments, as well as changes to other valuation assumptions responsive to Tuscarora’s commercial environment, it was determined that the fair value of Tuscarora did not exceed its carrying value, including goodwill. The fair value of the reporting unit was determined using a discounted cash flow analysis. The expected cash flows were discounted using a risk-adjusted discount rate to determine the fair value. As a result, the Company recorded a goodwill impairment charge of $79 million pre-tax within the U.S. Natural Gas Pipelines segment. This non-cash charge was recorded in Goodwill and other asset impairment charges on the Consolidated statement of income. As Tuscarora is a TC PipeLines, LP asset, the Company's share of this amount, after tax and net of non-controlling interests, was $15 million. The goodwill balance related to Tuscarora at December 31, 2018 was US$23 million (2017 – US$82 million).

Great Lakes At December 31, 2018, the estimated fair value of Great Lakes exceeded its carrying value by less than 10 per cent. The fair value of this reporting unit was measured using a discounted cash flow analysis in its most recent valuation. Assumptions used in the analysis regarding Great Lakes’ ability to realize long-term value in the North American energy market included the impact of its 501-G election, revenue opportunities on the system as well as changes to other valuation assumptions responsive to Great Lakes’ commercial environment. Although evolving market conditions and other factors relevant to Great Lakes’ long term financial performance have been positive, there is a risk that reductions in future cash flow forecasts or adverse changes in other key assumptions could result in a future impairment of a portion of the goodwill balance relating to Great Lakes. The goodwill balance related to Great Lakes at December 31, 2018 was US$573 million (2017 – US$573 million).

Ravenswood As a result of information received during the process to monetize the Company's U.S. Northeast power business in third quarter 2016, it was determined that the fair value of Ravenswood did not exceed its carrying value, including goodwill. The fair value of the reporting unit was determined using a combination of methods including a discounted cash flow analysis and a range of expected consideration from a potential sale. The expected cash flows were discounted using a risk-adjusted discount rate to determine the fair value. As a result, in 2016, the Company recorded a goodwill impairment charge on the full carrying value of Ravenswood goodwill of $1,085 million ($656 million after tax) within the Energy segment.

36 TCPL Consolidated financial statements 2018 12. INTANGIBLE AND OTHER ASSETS

at December 31 (millions of Canadian $) 2018 2017

Capital projects in development 1,051 596 Deferred income tax assets (Note 16) 288 255 Employee post-retirement benefits (Note 22) 192 193 Fair value of derivative contracts (Note 23) 61 73 Other 295 306 1,887 1,423

Capital projects in development Keystone XL In January 2018, the Company recommenced capitalizing development costs related to Keystone XL. In addition, certain project costs that were recorded in Plant, property and equipment at December 31, 2017 were transferred to Capital projects in development in 2018. These costs were related to the net realizable value of Keystone XL assets after an impairment charge was recorded in 2015. As a result, at December 31, 2018, Capital projects in development for this project were $0.8 billion (2017 – nil).

Reimbursement of Coastal GasLink pipeline costs In accordance with provisions in the agreements with the LNG Canada joint venture participants, all five parties elected to reimburse TCPL for their share of costs incurred prior to receiving the Final Investment Decision (FID) on the Coastal GasLink pipeline project. In November 2018, the Company received payments totaling $470 million which were recorded as a reduction of the carrying value of Coastal GasLink.

Prince Rupert Gas Transmission In July 2017, the Company was notified that Pacific Northwest LNG would not be proceeding with its proposed LNG project and that Progress Energy (Progress) would be terminating its agreement with TCPL for the development of the PRGT project effective August 10, 2017. In accordance with the terms of the agreement, all project costs incurred to advance the project, including carrying charges, were fully recoverable upon termination. In October 2017, the Company received full payment of the $634 million reimbursement from Progress.

Energy East and Related Projects Impairment On October 5, 2017, the Company informed the NEB that it will not proceed with the Energy East, Eastern Mainline and Upland projects. Based on this decision, the Company evaluated its Capital projects in development balance related to the Energy East and Upland projects including AFUDC. As a result, the Company recognized a non-cash impairment charge of $1,153 million ($870 million after tax) in the Liquids Pipelines segment. Due to the inability to reach a regulatory decision for this project, there were no recoveries of costs from third parties. The non-cash charge was recorded in Goodwill and other asset impairment charges on the Consolidated statement of income.

Power Purchase Arrangements Impairment In March 2016, TCPL terminated its Sheerness and Sundance A PPAs. In accordance with a provision in the PPAs, a buyer was permitted to terminate the arrangement if a change in law occurs that makes the arrangement unprofitable or more unprofitable. The Company expected increasing costs related to carbon emissions to continue throughout the remaining terms of the PPAs resulting in increasing unprofitability. As such, in 2016, the Company recognized a non-cash impairment charge of $211 million ($155 million after tax) in its Energy segment, representing the carrying value of the PPAs which was recorded in Intangible and other assets. In December 2016, TCPL transferred to the Balancing Pool a package of environmental credits that were being held to offset the PPA emissions costs and recorded a non-cash charge of $92 million ($68 million after tax) related to the carrying value of these environmental credits.

TCPL Consolidated financial statements 2018 37 13. NOTES PAYABLE

2018 2017 Weighted Weighted Average Average Interest Rate Interest Rate Outstanding at per Annum Outstanding at per Annum (millions of Canadian $, unless otherwise noted) December 31 at December 31 December 31 at December 31

Canada 2,117 2.5% 884 1.6% U.S. (2018 – US$448; 2017 – US$688) 611 3.1% 862 2.2% Mexico (2018 – US$25; 2017 – MXN$275) 34 3.3% 17 8.0% 2,762 1,763

At December 31, 2018, Notes payable consists of short-term borrowings in Canada by TCPL, in the U.S. by TransCanada PipeLine USA Ltd. (TCPL USA) and TransCanada American Investments Ltd. (TAIL), and in Mexico by a Mexican subsidiary.

At December 31, 2018, total committed revolving and demand credit facilities were $12.9 billion (2017 – $11.0 billion). When drawn, interest on these lines of credit is charged at negotiated floating rates of Canadian and U.S. banks, and at other negotiated financial bases. These unsecured credit facilities included the following:

at December 31 (billions of Canadian $, unless otherwise noted) 2018 2017 Total Unused Total Borrower Description Matures Facilities Capacity Facilities Committed, syndicated, revolving, extendible, senior unsecured credit facilities1: TCPL Supports TCPL's Canadian dollar commercial paper December 3.0 3.0 3.0 program and for general corporate purposes 2023 TCPL/TCPL USA/ Supports TCPL, TCPL USA and TAIL's U.S. dollar December US 4.5 US 4.5 — Columbia/TAIL commercial paper programs and is used for general 2019 corporate purposes of the borrowers, guaranteed by TCPL TCPL/TCPL USA/ Used for general corporate purposes of the December US 1.0 US 1.0 — Columbia/TAIL borrowers, guaranteed by TCPL 2021 TCPL Supports TCPL's U.S. dollar commercial paper — — US 2.0 program and for general corporate purposes TCPL USA Used for TCPL USA general corporate purposes, — — US 1.0 guaranteed by TCPL Columbia Used for Columbia general corporate purposes, — — US 1.0 guaranteed by TCPL TAIL Supports TAIL's U.S. dollar commercial paper — — US 0.5 program and for general corporate purposes, guaranteed by TCPL

Demand senior unsecured revolving credit facilities1: TCPL/TCPL USA Supports the issuance of letters of credit and Demand 2.1 1.0 1.9 provides additional liquidity, TCPL USA facility guaranteed by TCPL

Mexico subsidiary Used for Mexico general corporate purposes, Demand MXN 5.0 MXN 4.5 MXN 5.0 guaranteed by TCPL

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 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.

38 TCPL Consolidated financial statements 2018 For the year ended December 31, 2018, the cost to maintain the above facilities was $12 million (2017 – $7 million; 2016 – $10 million).

At December 31, 2018, the Company's operated affiliates had an additional $0.8 billion (2017 – $0.4 billion) of undrawn capacity on committed credit facilities.

14. ACCOUNTS PAYABLE AND OTHER

at December 31 (millions of Canadian $) 2018 2017

Trade payables 3,224 2,847 Fair value of derivative contracts (Note 23) 922 387 Unredeemed shares of Columbia 357 312 Regulatory liabilities (Note 10) 591 263 Other 332 262 5,426 4,071

15. OTHER LONG-TERM LIABILITIES

at December 31 (millions of Canadian $) 2018 2017

Employee post-retirement benefits (Note 22) 569 389 Asset retirement obligations 90 98 Fair value of derivative contracts (Note 23) 42 72 Guarantees (Note 26) 12 16 Other 295 152 1,008 727

16. INCOME TAXES U.S. Tax Reform On December 22, 2017, the President of the United States signed H.R.1, the Tax Cuts and Jobs Act (U.S. Tax Reform or the Act) into law. As a result, among other things, the enacted U.S. federal corporate income tax rate was reduced from 35 per cent to 21 per cent effective January 1, 2018 and resulted in a remeasurement of existing deferred income tax assets and deferred income tax liabilities related to the Company's U.S. businesses to reflect the new lower income tax rate as at December 31, 2017.

For the Company’s U.S. businesses not subject to RRA, the reduction in enacted income tax rates resulted in a decrease in net deferred income tax liabilities and a deferred income tax recovery of $816 million in 2017. For the Company’s U.S. businesses subject to RRA, the reduction in income tax rates resulted in a reduction in net deferred income tax liabilities and the recognition of a net regulatory liability of $1,686 million on the Consolidated balance sheet at December 31, 2017.

Net deferred income tax liabilities related to the cumulative remeasurements of employee post-retirement benefits included in AOCI were also adjusted with a corresponding increase in deferred income tax expense of $12 million in 2017.

Given the significance of the legislation, the U.S. Securities and Exchange Commission (SEC) staff issued guidance which allowed registrants to record provisional amounts at December 31, 2017 which may be adjusted as information becomes available, prepared or analyzed during a measurement period not to exceed one year. The SEC guidance summarized a three-step process to be applied at each reporting period to identify: (1) where the accounting is complete; (2) provisional amounts where the accounting is not yet complete, but a reasonable estimate has been determined; and (3) where a reasonable estimate cannot yet be determined and therefore income taxes are reflected in accordance with law prior to the enactment of the Act.

TCPL Consolidated financial statements 2018 39 At December 31, 2017, the Company considered amounts recorded related to U.S. Tax Reform to be reasonable estimates, however, certain amounts were provisional as the Company’s interpretation, assessment and presentation of the impact of the tax law change were further clarified with additional guidance from regulatory, tax and accounting authorities received in 2018. With additional guidance provided during the one-year measurement period and upon finalizing its 2017 annual tax return for its U.S. businesses, in fourth quarter 2018 the Company recognized further adjustments to its deferred income tax liability and net regulatory liability balances as well as a deferred income tax recovery of $52 million in fourth quarter 2018.

In addition, the 2018 FERC Actions established that, to the extent an entity’s income tax allowance should be eliminated from rates, it must also eliminate its existing ADIT balance from its rate base. In accordance with the FERC Form 501-G and uncontested rate settlement filings, the ADIT balances for all pipelines held wholly or in part by TC PipeLines, LP were eliminated from their respective rate bases. As a result, net regulatory liabilities recorded for these assets pursuant to U.S. Tax Reform were written off, resulting in a further deferred income tax recovery of $115 million in fourth quarter 2018.

Commencing January 1, 2018, the Company amortized the net regulatory liabilities, recorded per U.S. Tax Reform, using the Reverse South Georgia methodology. Under this methodology, rate-regulated entities determine and immediately begin recording amortization based on their composite depreciation rates. In 2018, amortization of these net regulatory liabilities in the amount of $58 million was recorded and included in Revenues in the Consolidated statement of income. The net regulatory liability related to U.S. Tax Reform at December 31, 2018 was $1,394 million (2017 – $1,686 million).

Further to U.S. Tax Reform, the U.S. Treasury and the U.S. Internal Revenue Service issued proposed regulations in November and December of 2018 which provided administrative guidance and clarified certain aspects of the new laws with respect to interest deductibility, base erosion and anti-abuse tax, the new dividend received deduction and anti-hybrid rules. Based on the Company's review and analysis of these proposed regulations, no material adjustments were recorded in the 2018 Consolidated financial statements. The proposed regulations are complex and comprehensive, and considerable uncertainty continues to exist until the final regulations are released, which is expected to occur later in 2019. TCPL continues to review and analyze these proposed regulations as well as assess their potential impact on the Company.

Provision for Income Taxes

year ended December 31 (millions of Canadian $) 2018 2017 2016

Current Canada 66 113 117 Foreign 250 36 40 316 149 157 Deferred Canada 19 (203) 97 Foreign 235 751 95 Foreign – U.S. Tax Reform and 2018 FERC Actions (167) (804) — 87 (256) 192 Income Tax Expense/(Recovery) 403 (107) 349

Geographic Components of Income before Income Taxes

year ended December 31 (millions of Canadian $) 2018 2017 2016

Canada 317 (408) 304 Foreign 3,516 3,645 618 Income before Income Taxes 3,833 3,237 922

40 TCPL Consolidated financial statements 2018 Reconciliation of Income Tax Expense/(Recovery)

year ended December 31 (millions of Canadian $) 2018 2017 2016

Income before income taxes 3,833 3,237 922 Federal and provincial statutory tax rate 27% 27% 27% Expected income tax expense 1,035 874 249 U.S. Tax Reform and 2018 FERC Actions (167) (804) — Foreign income tax rate differentials (432) (81) (196) Loss/(income) from equity investments and non-controlling interests 50 (64) (68) Income tax differential related to regulated operations (54) (42) 81 Non-taxable portion of capital gains (11) (42) — Asset impairment charges1 — 34 242 Non-deductible amounts — 4 18 Other (18) 14 23 Income Tax Expense/(Recovery) 403 (107) 349

1 Net of nil (2017 – nil, 2016 – $112 million) attributed to higher foreign tax rates.

Deferred Income Tax Assets and Liabilities

at December 31 (millions of Canadian $) 2018 2017

Deferred Income Tax Assets Tax loss and credit carryforwards 1,238 1,365 Difference in accounting and tax bases of impaired assets and assets held for sale 574 651 Regulatory and other deferred amounts 858 512 Unrealized foreign exchange losses on long-term debt 491 216 Financial instruments — 10 Other 258 180 3,419 2,934 Less: valuation allowance 1,159 832 2,260 2,102 Deferred Income Tax Liabilities Difference in accounting and tax bases of plant, property and equipment and PPAs 6,449 6,240 Equity investments 1,069 632 Taxes on future revenue requirement 300 238 Other 180 140 7,998 7,250 Net Deferred Income Tax Liabilities 5,738 5,148

The above deferred tax amounts have been classified in the Consolidated balance sheet as follows:

at December 31 (millions of Canadian $) 2018 2017

Deferred Income Tax Assets Intangible and other assets (Note 12) 288 255 Deferred Income Tax Liabilities Deferred income tax liabilities 6,026 5,403 Net Deferred Income Tax Liabilities 5,738 5,148

TCPL Consolidated financial statements 2018 41 At December 31, 2018, the Company has recognized the benefit of unused non-capital loss carryforwards of $1,867 million (2017 – $1,231 million) for federal and provincial purposes in Canada, which expire from 2030 to 2038. The Company has not recognized the benefit of capital loss carry forwards of $821 million (2017 – $668 million) for federal and provincial purposes in Canada. The Company also has recognized the benefit of Ontario minimum tax credits of $91 million (2017 – $82 million), which expire from 2026 to 2038.

At December 31, 2018, the Company has recognized the benefit of unused net operating loss carryforwards of US$889 million (2017 – US$1,800 million) for federal purposes in the U.S., which expire from 2029 to 2037. The Company has not recognized the benefit of unused net operating loss carryforwards of US$706 million (2017 – US$710 million) for federal purposes in the U.S. The Company also has recognized the benefit of alternative minimum tax credits of US$1 million (2017 – US$56 million).

At December 31, 2018, the Company has recognized the benefit of unused net operating loss carryforwards of US$3 million (2017 – US$7 million) in Mexico, which expire from 2024 to 2028.

Unremitted Earnings of Foreign Investments Income taxes have not been provided on the unremitted earnings of foreign investments that the Company does not intend to repatriate in the foreseeable future. Deferred income tax liabilities would have increased at December 31, 2018 by approximately $619 million (2017 – $569 million) if there had been a provision for these taxes.

Income Tax Payments Income tax payments of $338 million, net of refunds, were made in 2018 (2017 – payments, net of refunds, of $247 million; 2016 – payments, net of refunds, of $105 million).

Reconciliation of Unrecognized Tax Benefit Below is the reconciliation of the annual changes in the total unrecognized tax benefit:

at December 31 (millions of Canadian $) 2018 2017 2016

Unrecognized tax benefit at beginning of year 13 15 13 Gross increases – tax positions in prior years 13 — 3 Gross decreases – tax positions in prior years (5) (1) — Gross increases – tax positions in current year — 2 2 Settlement — — (1) Lapse of statutes of limitations (3) (3) (2) Unrecognized Tax Benefit at End of Year 18 13 15

Subject to the results of audit examinations by taxing authorities and other legislative amendments, TCPL does not anticipate further adjustments to the unrecognized tax benefits during the next 12 months that would have a material impact on its financial statements.

TCPL and its subsidiaries are subject to either Canadian federal and provincial income tax, U.S. federal, state and local income tax or the relevant income tax in other international jurisdictions. The Company has substantially concluded all Canadian federal and provincial income tax matters for the years through 2010. Substantially all material U.S. federal, state and local income tax matters have been concluded for years through 2011.

TCPL's practice is to recognize interest and penalties related to income tax uncertainties in Income tax expense. Income tax expense for the year ended December 31, 2018 reflects nil of interest expense and nil for penalties (2017 – nil of interest expense and nil for penalties; 2016 – nil of interest expense and nil for penalties). At December 31, 2018, the Company had $3 million accrued for interest expense and nil accrued for penalties (December 31, 2017 – $4 million accrued for interest expense and nil accrued for penalties).

42 TCPL Consolidated financial statements 2018 17. LONG-TERM DEBT

2018 2017 Outstanding amounts Maturity Outstanding at Interest Outstanding at Interest (millions of Canadian $, unless otherwise noted) Dates December 31 Rate1 December 31 Rate1

TRANSCANADA PIPELINES LIMITED Debentures Canadian 2019 to 2020 350 11.4% 500 10.8% U.S. (2018 and 2017 – US$400) 2021 546 9.9% 501 9.9% Medium Term Notes Canadian 2019 to 2048 7,504 4.8% 6,504 4.9% Senior Unsecured Notes U.S. (2018 – US$17,192; 2017 – US$14,892) 2019 to 2049 23,456 5.1% 18,644 5.1% 31,856 26,149 NOVA GAS TRANSMISSION LTD. Debentures and Notes Canadian 2024 100 9.9% 100 9.9% U.S. (2018 and 2017 – US$200) 2023 273 7.9% 250 7.9% Medium Term Notes Canadian 2025 to 2030 504 7.4% 504 7.4% U.S. (2018 and 2017 – US$33) 2026 44 7.5% 41 7.5% 921 895 COLUMBIA PIPELINE GROUP, INC. Senior Unsecured Notes U.S. (2018 – US$2,250; 2017 – US$2,750)2 2020 to 2045 3,070 4.4% 3,443 4.0% TC PIPELINES, LP Unsecured Loan Facility U.S. (2018 – US$40; 2017 – US$185) 2021 55 3.8% 232 2.7% Unsecured Term Loan U.S. (2018 – US$500; 2017 – US$670)3 2022 682 3.6% 839 2.7% Senior Unsecured Notes U.S. (2018 and 2017 – US$1,200) 2021 to 2027 1,637 4.4% 1,502 4.4% 2,374 2,573 ANR PIPELINE COMPANY Senior Unsecured Notes U.S. (2018 and 2017 – US$672) 2021 to 2026 918 7.2% 842 7.2% GAS TRANSMISSION NORTHWEST LLC Unsecured Term Loan U.S. (2018 – US$35; 2017 – US$55) 2019 48 3.3% 69 1.1% Senior Unsecured Notes U.S. (2018 and 2017 – US$250) 2020 to 2035 341 5.6% 313 5.6% 389 382 GREAT LAKES GAS TRANSMISSION LIMITED PARTNERSHIP Senior Unsecured Notes U.S. (2018 – US$240; 2017 – US$259) 2021 to 2030 327 7.7% 324 7.7%

TCPL Consolidated financial statements 2018 43 2018 2017 Outstanding amounts Maturity Outstanding at Interest Outstanding at Interest (millions of Canadian $, unless otherwise noted) Dates December 31 Rate1 December 31 Rate1

PORTLAND NATURAL GAS TRANSMISSION SYSTEM Unsecured Loan Facility U.S. (2018 – US$19; 2017 – nil) 2023 26 3.6% — — Senior Secured Notes4 U.S. (2018 – nil; 2017 – US$30) — — 38 6.0% 26 38 TUSCARORA GAS TRANSMISSION COMPANY Unsecured Term Loan U.S. (2018 – US$24; 2017 – US$25) 2020 33 3.5% 31 1.1% NORTH BAJA PIPELINE, LLC Unsecured Term Loan U.S. (2018 – US$50; 2017 – nil) 2021 68 3.5% — — 39,982 34,677 Current portion of long-term debt (3,462) (2,866) Unamortized debt discount and issue costs (241) (174) 5 Fair value adjustments 230 238 36,509 31,875

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 23, Risk management and financial instruments, for further information.

Principal Repayments At December 31, 2018, principal repayments for the next five years on the Company's long-term debt are approximately as follows:

(millions of Canadian $) 2019 2020 2021 2022 2023

Principal repayments on long-term debt 3,465 2,834 2,098 2,100 1,930

44 TCPL Consolidated financial statements 2018 Long-Term Debt Issued The Company issued long-term debt over the three years ended December 31, 2018 as follows:

(millions of Canadian $, unless otherwise noted) Company Issue Date Type Maturity Date Amount Interest Rate

TRANSCANADA PIPELINES LIMITED October 2018 Senior Unsecured Notes March 2049 US 1,000 5.10% October 2018 Senior Unsecured Notes May 2028 US 400 4.25% 1 July 2018 Medium Term Notes July 2048 800 4.18% July 2018 Medium Term Notes March 2028 200 3.39% 2 May 2018 Senior Unsecured Notes May 2028 US 1,000 4.25% May 2018 Senior Unsecured Notes May 2048 US 1,000 4.875% May 2018 Senior Unsecured Notes May 2038 US 500 4.75% November 2017 Senior Unsecured Notes November 2019 US 550 Floating November 2017 Senior Unsecured Notes November 2019 US 700 2.125% September 2017 Medium Term Notes March 2028 300 3.39% September 2017 Medium Term Notes September 2047 700 4.33% June 2016 Acquisition Bridge Facility3 June 2018 US 5,213 Floating June 2016 Medium Term Notes July 2023 300 3.69% 4 June 2016 Medium Term Notes June 2046 700 4.35% January 2016 Senior Unsecured Notes January 2026 US 850 4.875% January 2016 Senior Unsecured Notes January 2019 US 400 3.125% NORTH BAJA PIPELINE, LLC December 2018 Unsecured Term Loan December 2021 US 50 Floating PORTLAND NATURAL GAS TRANSMISSION SYSTEM April 2018 Unsecured Loan Facility April 2023 US 19 Floating TUSCARORA GAS TRANSMISSION COMPANY August 2017 Unsecured Term Loan August 2020 US 25 Floating April 2016 Unsecured Term Loan April 2019 US 10 Floating TC PIPELINES, LP May 2017 Senior Unsecured Notes May 2027 US 500 3.90% TRANSCANADA PIPELINE USA LTD. June 2016 Acquisition Bridge Facility3 June 2018 US 1,700 Floating ANR PIPELINE COMPANY June 2016 Senior Unsecured Notes June 2026 US 240 4.14%

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.

TCPL Consolidated financial statements 2018 45 Long-Term Debt Retired The Company retired/repaid long-term debt over the three years ended December 31, 2018 as follows:

(millions of Canadian $, unless otherwise noted) Retirement/ Company Repayment Date Type Amount Interest Rate

TRANSCANADA PIPELINES LIMITED August 2018 Senior Unsecured Notes US 850 6.50% March 2018 Debentures 150 9.45% January 2018 Senior Unsecured Notes US 500 1.875% January 2018 Senior Unsecured Notes US 250 Floating December 2017 Debentures 100 9.80% November 2017 Senior Unsecured Notes US 1,000 1.625% June 2017 Acquisition Bridge Facility1 US 1,513 Floating February 2017 Acquisition Bridge Facility1 US 500 Floating January 2017 Medium Term Notes 300 5.10% November 2016 Acquisition Bridge Facility1 US 3,200 Floating October 2016 Medium Term Notes 400 4.65% June 2016 Senior Unsecured Notes US 84 7.69% June 2016 Senior Unsecured Notes US 500 Floating January 2016 Senior Unsecured Notes US 750 0.75% TC PIPELINES, LP December 2018 Unsecured Term Loan US 170 Floating COLUMBIA PIPELINE GROUP, INC. June 2018 Senior Unsecured Notes US 500 2.45% PORTLAND NATURAL GAS TRANSMISSION SYSTEM May 2018 Senior Secured Notes US 18 5.90% GREAT LAKES GAS TRANSMISSION LIMITED PARTNERSHIP March 2018 Senior Unsecured Notes US 9 6.73% TUSCARORA GAS TRANSMISSION COMPANY August 2017 Senior Secured Notes US 12 3.82% TRANSCANADA PIPELINE USA LTD. June 2017 Acquisition Bridge Facility1 US 630 Floating April 2017 Acquisition Bridge Facility1 US 1,070 Floating NOVA GAS TRANSMISSION LTD. February 2016 Debentures 225 12.20%

1 These facilities were put in place to finance a portion of the Columbia acquisition and were fully retired in second quarter 2017.

46 TCPL Consolidated financial statements 2018 Interest Expense Interest expense in the three years ended December 31 was as follows: year ended December 31 (millions of Canadian $) 2018 2017 2016

Interest on long-term debt 1,877 1,794 1,765 Interest on junior subordinated notes 391 348 180 Interest on short-term debt 187 101 56 Capitalized interest (124) (173) (176) Amortization and other financial charges1 48 67 102 2,379 2,137 1,927

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.

The Company made interest payments of $2,268 million in 2018 (2017 – $2,055 million; 2016 – $1,757 million) on long-term debt, junior subordinated notes and short-term debt, net of interest capitalized.

18. JUNIOR SUBORDINATED NOTES

2018 2017 Outstanding loan amount Maturity Outstanding at Effective Outstanding at Effective (millions of Canadian $, unless otherwise noted) Date December 31 Interest Rate1 December 31 Interest Rate1

TRANSCANADA PIPELINES LIMITED2 US$1,000 notes issued 2007 at 6.35%3 2067 1,364 5.6% 1,252 5.0% US$750 notes issued 2015 at 5.875%4,5 2075 1,024 6.5% 939 5.9% US$1,200 notes issued 2016 at 6.125%4,5 2076 1,637 7.2% 1,502 6.6% US$1,500 notes issued 2017 at 5.55%4,5 2077 2,047 6.2% 1,878 5.6% $1,500 notes issued 2017 at 4.90%4,5 2077 1,500 5.5% 1,500 5.1% 7,572 7,071 Unamortized debt discount and issue costs (64) (64) 7,508 7,007

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 TCPL'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.

In March 2017, TransCanada Trust (the Trust) issued US$1.5 billion of Trust Notes – Series 2017-A to third party investors with a fixed interest rate of 5.30 per cent for the first ten years converting to a floating rate thereafter. All of the proceeds of the issuance by the Trust were loaned to TCPL for US$1.5 billion of junior subordinated notes of TCPL at an initial fixed rate of 5.55 per cent, including a 0.25 per cent administration charge. The rate will reset commencing March 2027 until March 2047 to the then three month LIBOR plus 3.458 per cent per annum; from March 2047 until March 2077, the interest rate will reset to the then three month LIBOR plus 4.208 per cent per annum. The junior subordinated notes are redeemable at TCPL's option at any time on or after March 15, 2027 at 100 per cent of the principal amount plus accrued and unpaid interest to the date of redemption.

TCPL Consolidated financial statements 2018 47 In May 2017, the Trust issued $1.5 billion of Trust Notes – Series 2017-B to third party investors with a fixed interest rate of 4.65 per cent for the first ten years converting to a floating rate thereafter. All of the proceeds of the issuance by the Trust were loaned to TCPL for $1.5 billion of junior subordinated notes of TCPL at an initial fixed rate of 4.90 per cent, including a 0.25 per cent administration charge. The rate will reset commencing May 2027 until May 2047 to the then three month Bankers' Acceptance rate plus 3.33 per cent per annum; from May 2047 until May 2077, the interest rate will reset to the then three month Bankers' Acceptance rate plus 4.08 per cent per annum. The junior subordinated notes are redeemable at TCPL's option at any time on or after May 18, 2027 at 100 per cent of the principal amount plus accrued and unpaid interest to the date of redemption.

In August 2016, the Trust issued US$1.2 billion of Trust Notes – Series 2016-A to third party investors at a fixed interest rate of 5.875 per cent for the first ten years, converting to a floating rate thereafter. All of the issuance proceeds of the Trust were loaned to TCPL for US$1.2 billion of junior subordinated notes of TCPL at an initial fixed rate of 6.125 per cent, including a 0.25 per cent administration charge. The rate will reset commencing August 2026 until August 2046 to the then three month LIBOR plus 4.89 per cent per annum; from August 2046 to August 2076 the interest rate will reset to the then three month LIBOR plus 5.64 per cent per annum. The junior subordinated notes are redeemable at TCPL's option at any time on or after August 15, 2026 at 100 per cent of the principal amount plus accrued and unpaid interest to the date of redemption.

Pursuant to the terms of the Trust Notes and related agreements, in certain circumstances (1) TCPL may issue deferral preferred shares to holders of the Trust Notes in lieu of interest; and (2) TransCanada and TCPL would be prohibited from declaring or paying dividends on or redeeming their outstanding preferred shares (or, if none are outstanding, their respective common shares) until all deferral preferred shares are redeemed by TCPL. The Trust Notes may also be automatically exchanged for preferred shares of TCPL upon certain kinds of bankruptcy and insolvency events. All of these preferred shares would rank equally with any other outstanding first preferred shares of TCPL.

19. NON-CONTROLLING INTERESTS The Company's Non-controlling interests included in the Consolidated balance sheet are as follows:

at December 31 (millions of Canadian $) 2018 2017

Non-controlling interest in TC PipeLines, LP 1,655 1,852

The Company's Net (loss)/income attributable to non-controlling interests included in the Consolidated statement of income are as follows:

year ended December 31 (millions of Canadian $) 2018 2017 2016

Non-controlling interest in TC PipeLines, LP (185) 220 215 Non-controlling interest in Portland Natural Gas Transmission System1 — 9 20 Non-controlling interest in Columbia Pipeline Partners LP2 — 9 17 (185) 238 252

1 Non-controlling interest in 2017 for the period January 1 to May 31 when TCPL sold its remaining interest in Portland to TC PipeLines, LP. Refer to Note 25, 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.

TC PipeLines, LP During 2018, the non-controlling interest in TC PipeLines, LP increased from 74.3 per cent to 74.5 per cent due to periodic issuances of common units in TC PipeLines, LP to third parties under an at-the-market issuance program. In 2017, the non-controlling interest in TC PipeLines, LP ranged between 73.2 per cent and 74.3 per cent, and in 2016, between 72.0 per cent and 73.2 per cent.

48 TCPL Consolidated financial statements 2018 Portland Natural Gas Transmission System On June 1, 2017, TCPL sold its remaining 11.81 per cent directly held interest in Portland to TC PipeLines, LP and, as a result, at December 31, 2017 and 2018, non-controlling interest in Portland was nil. On January 1, 2016, TCPL sold 49.9 per cent of Portland to TC PipeLines, LP. Refer to Note 25, Acquisitions and dispositions for further information.

Columbia Pipeline Partners LP On July 1, 2016, TCPL acquired Columbia, which included a 53.5 per cent non-controlling interest in Columbia Pipeline Partners LP (CPPL). On February 17, 2017, TCPL acquired all outstanding publicly held common units of CPPL at a price of US$17.00 and a stub period distribution payment of US$0.10 per common unit for an aggregate transaction value of US$921 million. As this was a transaction between entities under common control, it was recognized in equity.

At December 31, 2016, the entire $1,073 million (US$799 million) of TCPL's non-controlling interest in CPPL was recorded as Common units subject to rescission or redemption on the Consolidated balance sheet. The Company classified this non-controlling interest outside of equity as the potential redemption rights of the units were not within the control of the Company.

Common Units of TC PipeLines, LP Subject to Rescission In connection with a late filing of an employee-related Form 8-K with the SEC, in March 2016, TC PipeLines, LP became ineligible to use the then effective shelf registration statement upon filing of its 2015 Annual Report. As a result, it was determined that the purchasers of the 1.6 million common units that were issued from March 8, 2016 to May 19, 2016 under the TC PipeLines, LP at-the-market issuance program may have had a rescission right for an amount equal to the purchase price paid for the units, plus statutory interest and less any distributions paid, upon the return of such units to TC PipeLines, LP within one year of purchase.

As a result, at December 31, 2016, $106 million (US$82 million) was recorded as Common units subject to rescission or redemption on the Consolidated balance sheet. The Company classified these 1.6 million common units outside equity because the potential rescission rights of the units were not within the control of the Company. At December 31, 2017, all rescission rights previously classified outside of equity had lapsed and been reclassified to equity. These rights expired one year from the date of purchase of each unit and no unitholder claimed or attempted to exercise any of these rescission rights while they remained outstanding.

20. COMMON SHARES

Number of Shares Amount (thousands) (millions of Canadian $)

Outstanding at January 1, 2016 779,479 16,320 Issuance of common shares for cash1 79,656 4,661 Outstanding at December 31, 2016 859,135 20,981 Issuance of common shares for cash 12,499 780 Outstanding at December 31, 2017 871,634 21,761 Issuance of common shares for cash 15,572 845 Outstanding at December 31, 2018 887,206 22,606

1 Proceeds of $2.5 billion were used to finance the acquisition of Columbia and proceeds of $2.0 billion were used to repay a portion of the US$6.9 billion acquisition bridge facilities

Common Shares Issued and Outstanding The Company is authorized to issue an unlimited number of common shares without par value. TCPL issued the following common shares to TransCanada during 2018: • 3.4 million shares on January 31, 2018 for proceeds of $192 million • 4.3 million shares on April 30, 2018 for proceeds of $234 million • 3.6 million shares on July 31, 2018 for proceeds of $207 million • 4.3 million shares on October 31, 2018 for proceeds of $212 million.

TCPL Consolidated financial statements 2018 49 Restrictions on Dividends 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 shares. At December 31, 2018, the Company had no restrictions to declare or pay dividends.

Stock Options TransCanada's Stock Option Plan permits options for the purchase of TransCanada common shares to be awarded to certain employees, including officers. The contractual life of options granted is seven years. Options may be exercised at a price determined at the time the option is awarded and vest on the anniversary date in each of the three years following the award. Forfeiture of stock options results from their expiration and, if not previously vested, upon resignation or termination of the option holder's employment.

TransCanada used a binomial model for determining the fair value of options granted applying the following weighted average assumptions:

year ended December 31 2018 2017 2016

Weighted average fair value $5.80 $7.22 $5.67 Expected life (years)1 5.7 5.7 5.8 Interest rate 2.1% 1.2% 0.7% Volatility2 16% 18% 21% Dividend yield 4.2% 3.6% 4.9% Forfeiture rate3 — — 5%

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.

The amount expensed for TransCanada stock options, with a corresponding increase in Additional paid-in capital, was $13 million in 2018 (2017 – $12 million; 2016 – $15 million). At December 31, 2018, unrecognized compensation costs related to non-vested stock options was $16 million. The cost is expected to be fully recognized over a three-year period.

The following table summarizes additional stock option information:

year ended December 31 (millions of Canadian $, unless otherwise noted) 2018 2017 2016

Total intrinsic value of options exercised 10 28 31 Fair value of options that have vested 101 140 126 Total options vested 2.1 million 2.3 million 2.1 million

As at December 31, 2018, the aggregate intrinsic value of the total options exercisable was $8 million and the total intrinsic value of options outstanding was $9 million.

50 TCPL Consolidated financial statements 2018 21. OTHER COMPREHENSIVE INCOME/(LOSS) AND ACCUMULATED OTHER COMPREHENSIVE LOSS Components of OCI, including the portion attributable to non-controlling interests and related tax effects, are as follows:

year ended December 31, 2018 Income Tax Before Tax Recovery/ Net of Tax (millions of Canadian $) Amount (Expense) Amount

Foreign currency translation gains on net investment in foreign operations 1,323 35 1,358 Change in fair value of net investment hedges (57) 15 (42) Change in fair value of cash flow hedges (14) 4 (10) Reclassification to net income of gains and losses on cash flow hedges 27 (6) 21 Unrealized actuarial gains and losses on pension and other post-retirement benefit plans (153) 39 (114) Reclassification of actuarial gains and losses on pension and other post-retirement benefit plans 20 (5) 15 Other comprehensive income on equity investments 113 (27) 86 Other Comprehensive Income 1,259 55 1,314

year ended December 31, 2017 Income Tax Before Tax Recovery/ Net of Tax (millions of Canadian $) Amount (Expense) Amount

Foreign currency translation losses on net investment in foreign operations (746) (3) (749) Reclassification of foreign currency translation gains on disposal of foreign operations (77) — (77) Change in fair value of cash flow hedges 3 — 3 Reclassification to net income of gains and losses on cash flow hedges (3) 1 (2) Unrealized actuarial gains and losses on pension and other post-retirement benefit plans (14) 3 (11) Reclassification of actuarial gains and losses on pension and other post-retirement benefit plans 21 (5) 16 Other comprehensive loss on equity investments (141) 35 (106) Other Comprehensive Loss (957) 31 (926)

year ended December 31, 2016 Income Tax Before Tax Recovery/ Net of Tax (millions of Canadian $) Amount (Expense) Amount Foreign currency translation gains on net investment in foreign operations 3 — 3 Change in fair value of net investment hedges (14) 4 (10) Change in fair value of cash flow hedges 44 (14) 30 Reclassification to net income of gains and losses on cash flow hedges 71 (29) 42 Unrealized actuarial gains and losses on pension and other post-retirement benefit plans (38) 12 (26) Reclassification of actuarial gains and losses on pension and other post-retirement benefit plans 22 (6) 16 Other comprehensive loss on equity investments (117) 30 (87) Other Comprehensive Loss (29) (3) (32)

TCPL Consolidated financial statements 2018 51 The changes in AOCI by component are as follows:

Pension and Other Post- Currency Cash Retirement Translation Flow Benefit Plan Equity Adjustments Hedges Adjustments Investments Total1

AOCI balance at January 1, 2016 (383) (97) (198) (261) (939) Other comprehensive income/(loss) before reclassifications2 7 27 (26) (101) (93) Amounts reclassified from AOCI — 42 16 14 72 Net current period other comprehensive income/(loss) 7 69 (10) (87) (21) AOCI balance at December 31, 2016 (376) (28) (208) (348) (960) Other comprehensive (loss)/income before reclassifications2,3 (590) (1) (11) (117) (719) Amounts reclassified from AOCI (77) (2) 16 11 (52) Net current period other comprehensive (loss)/income (667) (3) 5 (106) (771) AOCI balance at December 31, 2017 (1,043) (31) (203) (454) (1,731) Other comprehensive income/(loss) before reclassifications2 1,150 (9) (114) 72 1,099 Amounts reclassified from AOCI4,5 — 16 15 12 43 Net current period other comprehensive income/(loss) 1,150 7 (99) 84 1,142 Reclassification of AOCI to retained earnings resulting from U.S. Tax Reform — 1 (12) (6) (17) AOCI balance at December 31, 2018 107 (23) (314) (376) (606)

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.

52 TCPL Consolidated financial statements 2018 Details about reclassifications out of AOCI into the Consolidated statement of income are as follows:

Amounts Reclassified 1 From AOCI Affected Line Item year ended December 31 in the Consolidated Statement of (millions of Canadian $) 2018 2017 2016 Income

Cash flow hedges Commodities (4) 20 (57) Revenues (Energy) Interest (18) (17) (14) Interest expense (22) 3 (71) Total before tax 6 (1) 29 Income tax expense (16) 2 (42) Net of tax1,3 Pension and other post-retirement benefit plan adjustments Amortization of actuarial gains and losses (16) (15) (22) Plant operating costs and other2 2 Settlement charge (4) (2) — Plant operating costs and other (20) (17) (22) Total before tax 5 5 6 Income tax expense (15) (12) (16) Net of tax1 Equity investments Equity income (16) (15) (19) Income from equity investments 4 4 5 Income tax expense (12) (11) (14) Net of tax1,3 Currency translation adjustments Realization of foreign currency translation gains on Gain/(loss) on assets held for disposal of foreign operations — 77 — sale/sold — — — Income tax expense — 77 — Net of tax1

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 22, 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.

TCPL Consolidated financial statements 2018 53 22. EMPLOYEE POST-RETIREMENT BENEFITS

The Company sponsors DB Plans for its employees. Pension benefits provided under the DB Plans are based on years of service and highest average earnings over three consecutive years of employment. Upon commencement of retirement, pension benefits in the Canadian DB Plan increase annually by a portion of the increase in the Consumer Price Index. Net actuarial gains or losses are amortized out of AOCI over the expected average remaining service life of employees, which is approximately nine years at December 31, 2018 (2017 and 2016 – nine years).

On December 31, 2017, the Columbia DB Plan merged with TCPL's U.S. DB Plan. Members accruing benefits in the Columbia DB Plan as of December 31, 2017 were provided an option to either continue receiving benefits in the Columbia DB Plan or instead participate in the existing U.S. DC plan. In addition, on January 1, 2018, the Columbia other post-retirement benefit plan merged with TCPL's U.S. other post-retirement benefit plan.

The Company also provides its employees with a savings plan in Canada, DC Plans consisting of 401(k) Plans in the U.S., and post-employment benefits other than pensions, including termination benefits and life insurance and medical benefits beyond those provided by government-sponsored plans. Net actuarial gains or losses for the plans are amortized out of AOCI over the expected average remaining service life of employees, which was approximately 12 years at December 31, 2018 (2017 and 2016 – 12 years). In 2018, the Company expensed $59 million (2017 – $42 million; 2016 – $52 million) for the savings and DC Plans.

Effective April 1, 2017, the Company closed its U.S. DB Plan to non-union new entrants. As of April 1, 2017, all non-union hires participate in the existing DC plan. Non-union U.S. employees who participated in the DC Plan, had one final election opportunity to become a member of the U.S. DB Plan as of January 1, 2018.

Total cash contributions by the Company for employee post-retirement benefits were as follows:

year ended December 31 (millions of Canadian $) 2018 2017 2016

DB Plans 103 163 111 Other post-retirement benefit plans 23 7 8 Savings and DC Plans 59 42 52 185 212 171

Current Canadian pension legislation allows for partial funding of solvency requirements over a number of years through letters of credit in lieu of cash contributions, up to certain limits. As such, in addition to the cash contributions noted above, the Company provided a $17 million letter of credit to the Canadian DB Plan in 2018 (2017 – $27 million; 2016 – $20 million), resulting in a total of $277 million provided to the Canadian DB Plan under letters of credit at December 31, 2018.

The most recent actuarial valuation of the pension plans for funding purposes was as at January 1, 2018 and the next required valuation will be as at January 1, 2019.

In December 2018, the Company recorded a settlement resulting from lump sum payments made in 2018 to certain terminated non-union vested participants in the Company's U.S. DB Plan related to voluntary cash settlement options available to these participants. The impact of the settlement was determined using assumptions consistent with those employed at December 31, 2017. The settlement reduced the Company's U.S. DB Plan's unrealized actuarial losses by $4 million which was included in OCI and resulted in a settlement charge of$4 million which was recorded in net benefit costs in 2018. Effective December 1, 2018, the plan was amended to include this unlimited lump sum payment option for certain union employees who were not previously eligible.

54 TCPL Consolidated financial statements 2018 In 2017, as a result of settlements and curtailments that occurred upon the completion of the U.S. Northeast power generation asset sales, interim remeasurements were performed on TCPL’s U.S. DB Plan and other post-retirement benefit plans using a weighted average discount rate of 4.10 per cent. All other assumptions were consistent with those employed at December 31, 2016. The impact of these remeasurements reduced the U.S. DB Plan's unrealized actuarial losses by $3 million, which was included in OCI, and resulted in a settlement charge of $2 million which was recorded in net benefit cost in 2017. These remeasurements had no impact on the other post-retirement benefit plan's unrealized actuarial losses.

Also in 2017, lump sum payouts exceeded service and interest costs for the Columbia DB Plan. As a result, an interim remeasurement was performed on the Columbia DB Plan at September 30, 2017 using a discount rate of 3.70 per cent. The interim remeasurement of the Columbia DB Plan increased the Company’s unrealized actuarial gains by $16 million, of which $14 million was recorded in Regulatory assets and $2 million was recorded in OCI. All other assumptions were consistent with those employed at December 31, 2016.

The Company's funded status at December 31 is comprised of the following:

Pension Other Post-Retirement at December 31 Benefit Plans Benefit Plans (millions of Canadian $) 2018 2017 2018 2017

Change in Benefit Obligation1 Benefit obligation – beginning of year 3,646 3,456 375 372 Service cost 121 113 4 4 Interest cost 134 135 14 14 Employee contributions 5 5 — 3 Benefits paid (177) (166) (23) (19) Actuarial (gain)/loss (92) 253 43 19 Curtailment — (14) — (2) Settlement (71) (66) — — Foreign exchange rate changes 87 (70) 17 (16) Benefit obligation – end of year 3,653 3,646 430 375 Change in Plan Assets Plan assets at fair value – beginning of year 3,451 3,208 365 354 Actual return on plan assets (73) 358 (15) 45 Employer contributions2 103 163 23 7 Employee contributions 5 5 — 3 Benefits paid (176) (166) (27) (19) Settlement (71) (57) — — Foreign exchange rate changes 82 (60) 30 (25) Plan assets at fair value – end of year 3,321 3,451 376 365 Funded Status – Plan Deficit (332) (195) (54) (10)

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).

TCPL Consolidated financial statements 2018 55 The amounts recognized in the Company's Consolidated balance sheet for its DB Plans and other post-retirement benefits plans are as follows:

Pension Other Post-Retirement at December 31 Benefit Plans Benefit Plans (millions of Canadian $) 2018 2017 2018 2017

Intangible and other assets (Note 12) — — 192 193 Accounts payable and other (1) (1) (8) (8) Other long-term liabilities (Note 15) (331) (194) (238) (195) (332) (195) (54) (10)

Included in the above benefit obligation and fair value of plan assets were the following amounts for plans that are not fully funded:

Pension Other Post-Retirement at December 31 Benefit Plans Benefit Plans (millions of Canadian $) 2018 2017 2018 2017

Projected benefit obligation1 (3,653) (3,646) (246) (203) Plan assets at fair value 3,321 3,451 — — Funded Status – Plan Deficit (332) (195) (246) (203)

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.

The funded status based on the accumulated benefit obligation for all DB Plans is as follows:

at December 31 (millions of Canadian $) 2018 2017

Accumulated benefit obligation (3,347) (3,372) Plan assets at fair value 3,321 3,451 Funded Status (26) 79

Included in the above accumulated benefit obligation and fair value of plan assets are the following amounts in respect of plans that are not fully funded.

at December 31 (millions of Canadian $) 2018 2017

Accumulated benefit obligation (3,347) (944) Plan assets at fair value 3,321 925 Funded Status – Plan Deficit (26) (19)

The Company pension plans' weighted average asset allocations and target allocations by asset category were as follows:

Percentage of Plan Assets Target Allocations at December 31 2018 2017 2018

Debt securities 33% 30% 25% to 45% Equity securities 56% 64% 40% to 70% Alternatives 11% 6% 5% to 15% 100% 100%

56 TCPL Consolidated financial statements 2018 Debt and equity securities include the Company's debt and common shares as follows:

Percentage of at December 31 Plan Assets (millions of Canadian $) 2018 2017 2018 2017

Debt securities 8 7 0.3% 0.2% Equity securities 7 3 0.2% 0.1%

Pension plan assets are managed on a going concern basis, subject to legislative restrictions, and are diversified across asset classes to maximize returns at an acceptable level of risk. Asset mix strategies consider plan demographics and may include traditional equity and debt securities, as well as alternative assets such as infrastructure, private equity, real estate and derivatives to diversify risk. Derivatives are not used for speculative purposes and the use of leveraged derivatives is prohibited.

All investments are measured at fair value using market prices. Where the fair value cannot be readily determined by reference to generally available price quotations, the fair value is determined by considering the discounted cash flows on a risk-adjusted basis and by comparison to similar assets which are publicly traded. In Level I, the fair value of assets is determined by reference to quoted prices in active markets for identical assets that the Company has the ability to access at the measurement date. In Level II, the fair value of assets is determined using valuation techniques, such as option pricing models and extrapolation using significant inputs which are observable directly or indirectly. In Level III, the fair value of assets is determined using a market approach based on inputs that are unobservable and significant to the overall fair value measurement.

TCPL Consolidated financial statements 2018 57 The following table presents plan assets for DB Plans and other post-retirement benefits measured at fair value, which have been categorized into the three categories based on a fair value hierarchy. For further information on the fair value hierarchy, refer to Note 23, Risk management and financial instruments.

Significant Other Significant Quoted Prices in Observable Unobservable Active Markets Inputs Inputs Percentage of at December 31 (Level I) (Level II) (Level III) Total Total Portfolio (millions of Canadian $) 2018 2017 2018 2017 2018 2017 2018 2017 2018 2017

Asset Category Cash and Cash Equivalents 48 44 — 17 — — 48 61 1 2 Equity Securities: Canadian 355 410 138 151 — — 493 561 13 15 U.S. 460 543 116 354 — — 576 897 16 24 International 40 45 281 322 — — 321 367 9 10 Global 116 — 268 301 — — 384 301 10 8 Emerging 8 8 138 147 — — 146 155 4 4 Fixed Income Securities: Canadian Bonds: Federal — — 186 193 — — 186 193 5 5 Provincial — — 198 194 — — 198 194 5 5 Municipal — — 8 8 — — 8 8 1 — Corporate — — 112 122 — — 112 122 3 3 U.S. Bonds: Federal 350 — — 244 — — 350 244 9 6 State — — — 41 — — — 41 — 1 Municipal — — — 4 — — — 4 — — Corporate 145 — 51 234 — — 196 234 5 6 International: Government 6 — 4 4 — — 10 4 1 — Corporate 19 — 18 5 — — 37 5 1 — Mortgage backed 128 — — 73 — — 128 73 3 2 Other Investments: Real estate — — — — 196 140 196 140 5 4 Infrastructure — — — — 163 70 163 70 4 2 Private equity funds — — — — 3 6 3 6 1 — Funds held on deposit 142 136 — — — — 142 136 4 3 1,817 1,186 1,518 2,414 362 216 3,697 3,816 100 100

The following table presents the net change in the Level III fair value category:

(millions of Canadian $, pre-tax)

Balance at December 31, 2016 199 Purchases and sales 11 Realized and unrealized gains 6 Balance at December 31, 2017 216 Purchases and sales 127 Realized and unrealized gains 19 Balance at December 31, 2018 362

58 TCPL Consolidated financial statements 2018 The Company's expected funding contributions in 2019 are approximately $113 million for the DB Plans, approximately $7 million for the other post-retirement benefit plans and approximately $61 million for the savings plan and DC Plans. The Company expects to provide an additional estimated $17 million letter of credit to the Canadian DB Plan for the funding of solvency requirements.

The following are estimated future benefit payments, which reflect expected future service:

Other Post- Pension Retirement (millions of Canadian $) Benefits Benefits

2019 190 24 2020 193 23 2021 198 23 2022 203 23 2023 207 23 2024 to 2028 1,081 114

The rate used to discount pension and other post-retirement benefit plan obligations was developed based on a yield curve of corporate AA bond yields at December 31, 2018. This yield curve is used to develop spot rates that vary based on the duration of the obligations. The estimated future cash flows for the pension and other post-retirement obligations were matched to the corresponding rates on the spot rate curve to derive a weighted average discount rate.

The significant weighted average actuarial assumptions adopted in measuring the Company's benefit obligations were as follows:

Pension Other Post-Retirement Benefit Plans Benefit Plans at December 31 2018 2017 2018 2017

Discount rate 3.90% 3.60% 4.10% 3.70% Rate of compensation increase 3.00% 3.00% — —

The significant weighted average actuarial assumptions adopted in measuring the Company's net benefit plan costs were as follows:

Pension Other Post-Retirement Benefit Plans Benefit Plans year ended December 31 2018 2017 2016 2018 2017 2016

Discount rate 3.60% 3.95% 4.20% 3.70% 4.15% 4.30% Expected long-term rate of return on plan assets 6.70% 6.50% 6.70% 4.00% 6.05% 5.95% Rate of compensation increase 3.00% 1.20% 0.80% — — —

The overall expected long-term rate of return on plan assets is based on historical and projected rates of return for the portfolio in aggregate and for each asset class in the portfolio. Assumed projected rates of return are selected after analyzing historical experience and estimating future levels and volatility of returns. Asset class benchmark returns, asset mix and anticipated benefit payments from plan assets are also considered in determining the overall expected rate of return. The discount rate is based on market interest rates of high-quality bonds that match the timing and benefits expected to be paid under each plan.

A six per cent weighted average annual rate of increase in the per capita cost of covered health care benefits was assumed for 2019 measurement purposes. The rate was assumed to decrease gradually to 4.50% by 2028 and remain at this level thereafter. A one per cent change in assumed health care cost trend rates would have the following effects:

(millions of Canadian $) Increase Decrease

Effect on total of service and interest cost components 1 (1) Effect on post-retirement benefit obligation 25 (21)

TCPL Consolidated financial statements 2018 59 The net benefit cost recognized for the Company’s pension benefit plans and other post-retirement benefit plans is as follows:

Pension Other Post-Retirement at December 31 Benefit Plans Benefit Plans (millions of Canadian $) 2018 2017 2016 2018 2017 2016

Service cost1 121 108 107 4 4 3 Other components of net benefit cost1 Interest cost 134 122 127 14 14 13 Expected return on plan assets (221) (178) (175) (16) (21) (11) Amortization of actuarial loss 15 14 20 1 1 2 Amortization of regulatory asset 18 37 27 — 1 1 Amortization of transitional obligation related to regulated business — — — — — 2 Settlement charge – regulatory asset — 2 — — — — Settlement charge – AOCI 4 2 — — — — (50) (1) (1) (1) (5) 7 Net Benefit Cost Recognized 71 107 106 3 (1) 10

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

Pre-tax amounts recognized in AOCI were as follows:

2018 2017 2016 at December 31 Other Post- Other Post- Other Post- Pension Retirement Pension Retirement Pension Retirement (millions of Canadian $) Benefits Benefits Benefits Benefits Benefits Benefits Net loss 364 53 273 11 270 21

The estimated net loss for the DB Plans and for the other post-retirement benefit plans that will be amortized from AOCI into net periodic benefit cost in 2019 is $12 million and $2 million, respectively.

Pre-tax amounts recognized in OCI were as follows:

2018 2017 2016 at December 31 Other Post- Other Post- Other Post- Pension Retirement Pension Retirement Pension Retirement (millions of Canadian $) Benefits Benefits Benefits Benefits Benefits Benefits

Amortization of net loss from AOCI to OCI (15) (1) (18) (1) (20) (2) Curtailment — — (14) (2) — — Settlement (4) — (11) — — — Funded status adjustment 110 43 46 (7) 43 (5) 91 42 3 (10) 23 (7)

23. RISK MANAGEMENT AND FINANCIAL INSTRUMENTS Risk Management Overview TCPL has exposure to market risk and counterparty credit risk, and has strategies, policies and limits in place to manage the impact of these risks on earnings, cash flow and shareholder value.

Risk management strategies, policies and limits are designed to ensure TCPL's risks and related exposures are in line with the Company's business objectives and risk tolerance. Market risk and counterparty credit risk are managed within limits established by the Company's Board of Directors, implemented by senior management and monitored by the Company's risk management and internal audit groups. The Board of Directors' Audit Committee oversees how management monitors compliance with market risk and counterparty credit risk management policies and procedures, and oversees management's review of the adequacy of the risk management framework.

60 TCPL Consolidated financial statements 2018 Market Risk The Company constructs and invests in energy infrastructure projects, purchases and sells commodities, issues short-term and long-term debt, including amounts in foreign currencies, and invests in foreign operations. Certain of these activities expose the Company to market risk from changes in commodity prices, foreign exchange rates and interest rates, which may affect the Company's earnings and the value of the financial instruments it holds. The Company assesses contracts used to manage market risk to determine whether all, or a portion, meets the definition of a derivative.

Derivative contracts the Company uses to assist in managing the exposure to market risk may consist of the following: • 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.

Commodity price risk The following strategies may be used to manage exposure to commodity price risk in the Company's non-regulated businesses: • In the Company's power generation business, TCPL 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, TCPL'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, TCPL enters into pipeline and storage terminal capacity contracts. TCPL 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.

The Company's exposure to electricity price risk has been greatly reduced following the sales of its U.S. Northeast power generation assets in 2017 and its U.S. Northeast power retail contracts on March 1, 2018 as well as the continued wind-down of its remaining U.S. Power marketing contracts.

Interest rate risk TCPL utilizes short-term and long-term debt to finance its operations which exposes the Company to interest rate risk. TCPL typically pays fixed rates of interest on its long-term debt and floating rates on its commercial paper programs and amounts drawn on its credit facilities. A small portion of TCPL's long-term debt is at floating interest rates. In addition, the Company is exposed to interest rate risk on financial instruments and contractual obligations containing variable interest rate components. The Company manages its interest rate risk using a combination of interest rate swaps and option derivatives.

Foreign exchange risk TCPL generates revenues and incurs expenses that are denominated in currencies other than Canadian dollars. As a result, the Company's earnings and cash flows are exposed to currency fluctuations.

A portion of TCPL's businesses generate earnings in U.S. dollars, but since its financial results are reported in Canadian dollars, changes in the value of the U.S. dollar against the Canadian dollar can affect its net income. As the Company's U.S. dollar-denominated operations continue to grow, this exposure increases. A portion of this risk is offset by interest expense on U.S. dollar-denominated debt. The balance of the exposure is hedged on a rolling one-year basis using foreign exchange derivatives, but the exposure remains beyond that period.

Net investment hedges The Company hedges its net investment in foreign operations (on an after-tax basis) with U.S. dollar-denominated debt, cross-currency swaps and foreign exchange options.

TCPL Consolidated financial statements 2018 61 The fair values and notional amounts for the derivatives designated as a net investment hedge were as follows:

2018 2017 at December 31 Fair Notional Fair Notional (millions of Canadian $, unless otherwise noted) Value1,2 Amount Value1,2 Amount

U.S. dollar cross-currency interest rate swaps (maturing 2019)3 (43) US 300 (199) US 1,200 U.S. dollar foreign exchange options (maturing 2019 to 2020) (47) US 2,500 5 US 500 (90) US 2,800 (194) US 1,700

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.

The notional amounts and fair value of U.S. dollar-denominated debt designated as a net investment hedge were as follows:

at December 31 (millions of Canadian $, unless otherwise noted) 2018 2017

Notional amount 31,000 (US 22,700) 25,400 (US 20,200) Fair value 31,700 (US 23,200) 28,900 (US 23,100)

Counterparty Credit Risk TCPL's maximum counterparty credit exposure with respect to financial instruments at December 31, 2018, without taking into account security held, consisted of cash and cash equivalents, accounts receivable, available-for-sale assets, derivative assets and a loan receivable.

Counterparty credit risk represents the financial loss the Company would experience if a counterparty to a financial instrument failed to meet its obligations in accordance with the terms and conditions of the related contract or agreement with the Company.

The Company manages its exposure to this potential loss by dealing with creditworthy counterparties, obtaining financial assurances such as guarantees, letters of credit or cash where considered necessary, and setting limits on the amount TCPL can transact with any one counterparty. There is no guarantee that these techniques will protect the Company from material losses.

The Company monitors its counterparties and regularly reviews its accounts receivable. The Company records an allowance for doubtful accounts as necessary using the specific identification method. At December 31, 2018 and 2017, there were no significant amounts past due or impaired, no significant credit risk concentration and no significant credit losses during the year.

TCPL has significant credit and performance exposures to financial institutions as they hold cash deposits and provide committed credit lines and letters of credit that help manage the Company's exposure to counterparties and provide liquidity in commodity, foreign exchange and interest rate derivative markets.

Fair Value of Non-Derivative Financial Instruments Available-for-sale assets are recorded at fair value which is calculated using quoted market prices where available. Certain non-derivative financial instruments included in cash and cash equivalents, accounts receivable, intangible and other assets, notes payable, accounts payable and other, due to affiliate, accrued interest and other long-term liabilities have carrying amounts that approximate their fair value due to the nature of the item or the short time to maturity and would also be classified in Level II of the fair value hierarchy.

Credit risk has been taken into consideration when calculating the fair value of non-derivative financial instruments.

62 TCPL Consolidated financial statements 2018 Balance Sheet Presentation of Non-Derivative Financial Instruments The following table details the fair value of non-derivative financial instruments, excluding those where carrying amounts approximate fair value, and would be classified in Level II of the fair value hierarchy:

2018 2017 at December 31 Carrying Fair Carrying Fair (millions of Canadian $) Amount Value Amount Value

Long-term debt, including current portion1,2 (Note 17) (39,971) (42,284) (34,741) (40,180) Junior subordinated notes (Note 18) (7,508) (6,665) (7,007) (7,233) (47,479) (48,949) (41,748) (47,413)

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.

Available-for-Sale Assets Summary The following tables summarize additional information about the Company's restricted investments that are classified as available- for-sale assets:

2018 2017 at December 31 LMCI Restricted Other Restricted LMCI Restricted Other Restricted (millions of Canadian $) Investments Investments1 Investments Investments1

Fair value of fixed income securities2 Fixed income securities (maturing within 1 year) — 22 — 23 Fixed income securities (maturing within 1-5 years) — 110 — 107 Fixed income securities (maturing within 5-10 years) 140 — 14 — Fixed income securities (maturing after 10 years) 952 — 790 — 1,092 132 804 130

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.

2018 2017 2016 LMCI Other LMCI Other LMCI Other year ended December 31 restricted restricted restricted restricted restricted restricted (millions of Canadian $) investments1 investments investments1 investments investments1 investments

Net unrealized gains/(losses) 11 — (3) 1 (28) (1) Net realized losses2 (4) — (1) — — —

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.

Fair Value of Derivative Instruments The fair value of foreign exchange and interest rate derivatives has been calculated using the income approach which uses year- end market rates and applies a discounted cash flow valuation model. The fair value of commodity derivatives has been calculated using a market approach. The market approach bases the fair value measures on a comparable transaction using quoted market prices, or in the absence of quoted market prices, third-party broker quotes or other valuation techniques. The fair value of options has been calculated using the Black-Scholes pricing model. Credit risk has been taken into consideration when calculating the fair value of derivative instruments. Unrealized gains and losses on derivative instruments are not necessarily representative of the amounts that will be realized on settlement.

TCPL Consolidated financial statements 2018 63 In some cases, even though the derivatives are considered to be effective economic hedges, they do not meet the specific criteria for hedge accounting treatment or are not designated as a hedge and are accounted for at fair value with changes in fair value recorded in net income in the period of change. This may expose the Company to increased variability in reported earnings because the fair value of the derivative instruments can fluctuate significantly from period to period.

The recognition of gains and losses on derivatives for Canadian natural gas regulated pipeline exposures is determined through the regulatory process. Gains and losses arising from changes in the fair value of derivatives accounted for as part of RRA, including those that qualify for hedge accounting treatment, can be recovered or refunded through the tolls charged by the Company. As a result, these gains and losses are deferred as regulatory assets or regulatory liabilities and are refunded to or collected from the ratepayers in subsequent years when the derivative settles.

Balance Sheet Presentation of Derivative Instruments The balance sheet classification of the fair value of derivative instruments as at December 31, 2018 is as follows:

Total Fair at December 31, 2018 Net Value of Cash Flow Fair Value Investment Held for Derivative (millions of Canadian $) Hedges Hedges Hedges Trading Instruments1

Other current assets (Note 7) Commodities2 1 — — 716 717 Foreign exchange — — 16 1 17 Interest rate 3 — — — 3 4 — 16 717 737 Intangible and other assets (Note 12) Commodities2 1 — — 50 51 Foreign exchange — — 1 — 1 Interest rate 8 1 — — 9 9 1 1 50 61 Total Derivative Assets 13 1 17 767 798

Accounts payable and other (Note 14) Commodities2 (4) — — (622) (626) Foreign exchange — — (105) (188) (293) Interest rate — (3) — — (3) (4) (3) (105) (810) (922) Other long-term liabilities (Note 15) Commodities2 — — — (28) (28) Foreign exchange — — (2) — (2) Interest rate (11) (1) — — (12) (11) (1) (2) (28) (42) Total Derivative Liabilities (15) (4) (107) (838) (964) Total Derivatives (2) (3) (90) (71) (166)

1 Fair value equals carrying value. 2 Includes purchases and sales of power, natural gas and liquids.

64 TCPL Consolidated financial statements 2018 The balance sheet classification of the fair value of derivative instruments as at December 31, 2017 is as follows:

Total Fair Net at December 31, 2017 Value of Cash Flow Fair Value Investment Held for Derivative (millions of Canadian $) Hedges Hedges Hedges Trading Instruments1

Other current assets (Note 7) Commodities2 1 — — 249 250 Foreign exchange — — 8 70 78 Interest rate 3 — — 1 4 4 — 8 320 332 Intangible and other assets (Note 12) Commodities2 — — — 69 69 Interest rate 4 — — — 4 4 — — 69 73 Total Derivative Assets 8 — 8 389 405

Accounts payable and other (Note 14) Commodities2 (6) — — (208) (214) Foreign exchange — — (159) (10) (169) Interest rate — (4) — — (4) (6) (4) (159) (218) (387) Other long-term liabilities (Note 15) Commodities2 (2) — — (26) (28) Foreign exchange — — (43) — (43) Interest rate — (1) — — (1) (2) (1) (43) (26) (72) Total Derivative Liabilities (8) (5) (202) (244) (459) Total Derivatives — (5) (194) 145 (54)

1 Fair value equals carrying value. 2 Includes purchases and sales of power, natural gas and liquids.

The majority of derivative instruments held for trading have been entered into for risk management purposes and all are subject to the Company's risk management strategies, policies and limits. These include derivatives that have not been designated as hedges or do not qualify for hedge accounting treatment but have been entered into as economic hedges to manage the Company's exposures to market risk.

Derivatives in fair value hedging relationships The following table details amounts recorded on the Consolidated balance sheet in relation to cumulative adjustments for fair value hedges included in the carrying amount of the hedged liabilities:

at December 31 Carrying amount Fair value hedging adjustments1 (millions of Canadian $) 2018 2017 2018 2017

Current portion of long-term debt (748) (688) 3 1 Long-term debt (273) (685) — 4 (1,021) (1,373) 3 5

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

TCPL Consolidated financial statements 2018 65 Notional and Maturity Summary The maturity and notional amount or quantity outstanding related to the Company's derivative instruments excluding hedges of the net investment in foreign operations is as follows:

Foreign Interest at December 31, 2018 Power Natural Gas Liquids Exchange Rate

Purchases1 23,865 44 59 — — Sales1 17,689 56 79 — — Millions of U.S. dollars — — — 3,862 1,650 Maturity dates 2019-2023 2019-2027 2019 2019 2019-2030

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

Foreign Interest at December 31, 2017 Power Natural Gas Liquids Exchange Rate

Purchases1 66,132 133 6 — — Sales1 42,836 135 7 — — Millions of U.S. dollars — — — 2,931 2,300 Millions of Mexican pesos — — — 100 — Maturity dates 2018-2022 2018-2021 2018 2018 2018-2022

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

Unrealized and Realized Gains/(Losses) on Derivative Instruments The following summary does not include hedges of the net investment in foreign operations.

year ended December 31 (millions of Canadian $) 2018 2017 2016

Derivative instruments held for trading1 Amount of unrealized gains/(losses) in the year Commodities2 28 62 123 Foreign exchange (248) 88 25 Interest rate — (1) — Amount of realized gains/(losses) in the year Commodities 351 (107) (204) Foreign exchange (24) 18 62 Interest rate — 1 — Derivative instruments in hedging relationships Amount of realized (losses)/gains in the year Commodities (1) 23 (167) Foreign exchange — 5 (101) Interest rate (1) 1 4

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).

66 TCPL Consolidated financial statements 2018 Derivatives in cash flow hedging relationships The components of OCI (Note 21) related to derivatives in cash flow hedging relationships including the portion attributable to non-controlling interests are as follows:

year ended December 31 (millions of Canadian $, pre-tax) 2018 2017 2016

Change in fair value of derivative instruments recognized in OCI1 Commodities (1) (1) 39 Interest rate (13) 4 5 (14) 3 44

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

Effect of fair value and cash flow hedging relationships The following table details amounts presented on the Consolidated statement of income in which the effects of fair value or cash flow hedging relationships are recorded.

year ended December 31 Revenues (Energy) Interest Expense (millions of Canadian $) 2018 2017 2016 2018 2017 2016

Total Amount Presented in the Consolidated Statement of Income 2,124 3,593 4,206 (2,379) (2,137) (1,927) Fair Value Hedges Interest rate contracts Hedged items — — — (71) (74) (74) Derivatives designated as hedging instruments — — — (4) 1 8 Cash Flow Hedges Reclassification of gains/(losses) on derivative instruments from AOCI to net income1,2 Interest rate contracts — — — 22 17 14 Commodity contracts 5 (20) 57 — — —

1 Refer to Note 21, 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.

TCPL Consolidated financial statements 2018 67 Offsetting of derivative instruments The Company enters into derivative contracts with the right to offset in the normal course of business as well as in the event of default. TCPL has no master netting agreements, however, similar contracts are entered into containing rights to offset. The Company has elected to present the fair value of derivative instruments with the right to offset on a gross basis in the Consolidated balance sheet. The following table shows the impact on the presentation of the fair value of derivative instrument assets and liabilities had the Company elected to present these contracts on a net basis as at December 31, 2018:

at December 31, 2018 Gross Derivative Amounts Available (millions of Canadian $) Instruments for Offset1 Net Amounts

Derivative – Asset Commodities 768 (626) 142 Foreign exchange 18 (18) — Interest rate 12 (4) 8 798 (648) 150 Derivative – Liability Commodities (654) 626 (28) Foreign exchange (295) 18 (277) Interest rate (15) 4 (11) (964) 648 (316)

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

The following table shows the impact on the presentation of the fair value of derivative instrument assets and liabilities had the Company elected to present these contracts on a net basis as at December 31, 2017:

at December 31, 2017 Gross Derivative Amounts Available (millions of Canadian $) Instruments for Offset1 Net Amounts

Derivative – Asset Commodities 319 (198) 121 Foreign exchange 78 (56) 22 Interest rate 8 (1) 7 405 (255) 150 Derivative – Liability Commodities (242) 198 (44) Foreign exchange (212) 56 (156) Interest rate (5) 1 (4) (459) 255 (204)

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

With respect to the derivative instruments presented above, the Company provided cash collateral of $143 million and letters of credit of $22 million (2017 – $165 million and $30 million) to its counterparties. At December 31, 2018, the Company held nil in cash collateral and $1 million in letters of credit (2017 – nil and $3 million) from counterparties on asset exposures.

68 TCPL Consolidated financial statements 2018 Credit-risk-related contingent features of derivative instruments Derivative contracts entered into to manage market risk often contain financial assurance provisions that allow parties to the contracts to manage credit risk. These provisions may require collateral to be provided if a credit-risk-related contingent event occurs, such as a downgrade in the Company's credit rating to non-investment grade. The company may also need to provide collateral if the fair value of its derivative financial instruments exceeds pre-defined exposure limits.

Based on contracts in place and market prices at December 31, 2018, the aggregate fair value of all derivative instruments with credit-risk-related contingent features that were in a net liability position was $6 million (2017 – $2 million), for which the Company has provided no collateral in the normal course of business. If the credit-risk-related contingent features in these agreements were triggered on December 31, 2018, the Company would have been required to provide collateral of $6 million (2017 – $2 million) to its counterparties. Collateral may also need to be provided should the fair value of derivative instruments exceed pre-defined contractual exposure limit thresholds.

The Company has sufficient liquidity in the form of cash and undrawn committed revolving bank lines to meet these contingent obligations should they arise.

Fair Value Hierarchy The Company's financial assets and liabilities recorded at fair value have been categorized into three categories based on a fair value hierarchy.

Levels How fair value has been determined Level I Quoted prices in active markets for identical assets and liabilities that the Company has the ability to access at the measurement date. An active market is a market in which frequency and volume of transactions provides pricing information on an ongoing basis.

Level II Valuation based on the extrapolation of inputs, other than quoted prices included within Level I, for which all significant inputs are observable directly or indirectly.

Inputs include published exchange rates, interest rates, interest rate swap curves, yield curves and broker quotes from external data service providers.

This category includes interest rate and foreign exchange derivative assets and liabilities where fair value is determined using the income approach and commodity derivatives where fair value is determined using the market approach.

Transfers between Level I and Level II would occur when there is a change in market circumstances.

Level III Valuation of assets and liabilities are measured using a market approach based on extrapolation of inputs that are unobservable or where observable data does not support a significant portion of the derivative's fair value. This category includes long-dated commodity transactions in certain markets where liquidity is low and the Company uses the most observable inputs available or, if not available, long-term broker quotes to estimate the fair value for these transactions. Valuation of options is based on the Black-Scholes pricing model.

Assets and liabilities measured at fair value can fluctuate between Level II and Level III depending on the proportion of the value of the contract that extends beyond the time frame for which significant inputs are considered to be observable. As contracts near maturity and observable market data becomes available, they are transferred out of Level III and into Level II.

TCPL Consolidated financial statements 2018 69 The fair value of the Company's derivative assets and liabilities measured on a recurring basis, including both current and non-current portions for 2018, are categorized as follows:

Significant Significant at December 31, 2018 Quoted Prices in Other Unobservable Active Markets Observable Inputs (millions of Canadian $) (Level I)1 Inputs (Level II)1 (Level III)1 Total

Derivative Instrument Assets: Commodities 581 187 — 768 Foreign exchange — 18 — 18 Interest rate — 12 — 12 Derivative Instrument Liabilities: Commodities (555) (95) (4) (654) Foreign exchange — (295) — (295) Interest rate — (15) — (15) 26 (188) (4) (166)

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.

The fair value of the Company's derivative assets and liabilities measured on a recurring basis, including both current and non-current portions for 2017, are categorized as follows:

Significant Significant at December 31, 2017 Quoted Prices in Other Unobservable Active Markets Observable Inputs (millions of Canadian $) (Level I)1 Inputs (Level II)1 (Level III)1 Total

Derivative Instrument Assets: Commodities 21 283 15 319 Foreign exchange — 78 — 78 Interest rate — 8 — 8 Derivative Instrument Liabilities: Commodities (27) (193) (22) (242) Foreign exchange — (212) — (212) Interest rate — (5) — (5) (6) (41) (7) (54)

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.

The following table presents the net change in fair value of derivative assets and liabilities classified in Level III of the fair value hierarchy:

(millions of Canadian $, pre-tax) 2018 2017

Balance at beginning of year (7) 16 Transfers out of Level III 5 (19) Total gains/(losses) included in Net income 8 (17) Settlements (9) 18 Sales — (5) Foreign exchange (1) — Balance at end of year1 (4) (7)

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).

A 10 per cent increase or decrease in commodity prices, with all other variables held constant, would result in a $2 million decrease or increase, respectively, in the fair value of outstanding derivative instruments included in Level III as at December 31, 2018.

70 TCPL Consolidated financial statements 2018 24. CHANGES IN OPERATING WORKING CAPITAL

year ended December 31 (millions of Canadian $) 2018 2017 2016

Increase in Accounts receivable (68) (573) (487) Increase in Inventories (49) (38) (87) Decrease/(increase) in Assets held for sale — 14 (13) Decrease in Other current assets 45 189 328 (Decrease)/increase in Accounts payable and other (68) 149 432 Increase in Accrued interest 41 12 62 (Decrease)/increase in Liabilities related to assets held for sale — (25) 16 (Increase)/decrease in Operating Working Capital (99) (272) 251

25. ACQUISITIONS AND DISPOSITIONS

U.S. Natural Gas Pipelines Iroquois Gas Transmission System and Portland Natural Gas Transmission System On June 1, 2017, TCPL closed the sale of 49.34 per cent of its 50 per cent interest in Iroquois, along with an option to sell the remaining 0.66 per cent at a later date, to TC PipeLines, LP. At the same time, TCPL closed the sale of its remaining 11.81 per cent interest in Portland to TC PipeLines, LP. Proceeds from these transactions were US$765 million, before post-closing adjustments, and were comprised of US$597 million in cash and US$168 million representing a proportionate share of Iroquois and Portland debt.

In January 2016, TCPL closed the sale of a 49.9 per cent interest in Portland to TC PipeLines, LP for an aggregate purchase price of US$223 million. Proceeds were comprised of US$188 million in cash and the assumption of US$35 million of a proportional share of Portland debt.

In March 2016, TCPL acquired a 4.87 per cent interest in Iroquois for an aggregate purchase price of US$54 million, increasing TCPL’s interest in Iroquois to 49.35 per cent. On May 1, 2016, the Company acquired an additional 0.65 per cent interest for an aggregate purchase price of US$7 million, further increasing TCPL’s interest in Iroquois to 50 per cent.

Acquisition of Columbia On July 1, 2016, TCPL acquired 100 per cent ownership of Columbia for a purchase price of US$10.3 billion in cash, based on US $25.50 per share for all of Columbia's outstanding common shares as well as all outstanding restricted and performance stock units. The acquisition was financed through the issuance of TCPL common shares to TransCanada, an intercompany loan due to TransCanada in connection with proceeds received from the sale of TransCanada subscription receipts and draws on acquisition bridge facilities in the aggregate amount of US$6.9 billion. The sale of the subscription receipts was completed on April 1, 2016 through a public offering, and gross proceeds of approximately $4.4 billion were transferred to TCPL prior to the closing of the acquisition. Refer to Note 20, Common shares, Note 28, Related party transactions and Note 17, Long-term debt for further information on the common shares issued to TransCanada, the intercompany loan due to TransCanada and the acquisition bridge facilities.

At the date of acquisition, Columbia operated a portfolio of approximately 24,500 km (15,200 miles) of regulated natural gas pipelines, 285 Bcf of natural gas storage facilities and midstream and other assets in various regions in the U.S. TCPL acquired Columbia to expand the Company’s natural gas business in the U.S. market, positioning the Company for additional long-term growth opportunities.

The goodwill arising from the acquisition principally reflects the opportunities to expand the Company’s U.S. Natural Gas Pipelines segment and to gain a stronger competitive position in the North American natural gas business. The goodwill resulting from the acquisition is not deductible for income tax purposes. The acquisition was accounted for as a business combination using the acquisition method where the acquired tangible and intangible assets and assumed liabilities were recorded at their estimated fair values at the date of acquisition. The purchase price equation reflects management’s estimate of the fair value of Columbia’s assets and liabilities as at July 1, 2016.

TCPL Consolidated financial statements 2018 71 July 1, 2016 (millions of $) U.S. Canadian1

Purchase Price Consideration 10,294 13,392 Fair Value Current assets 658 856 Plant, property and equipment 7,560 9,835 Equity investments 441 574 Regulatory assets 190 248 Intangible and other assets 135 175 Current liabilities (597) (777) Regulatory liabilities (294) (383) Other long-term liabilities (144) (187) Deferred income tax liabilities (1,613) (2,098) Long-term debt (2,981) (3,878) Non-controlling interests (808) (1,051) Fair Value of Net Assets Acquired 2,547 3,314 Goodwill 7,747 10,078

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

The fair values of current assets including cash and cash equivalents, accounts receivable, and inventories and the fair values of current liabilities including notes payable and accrued interest approximated their carrying values due to the short-term nature of these items. Certain acquisition-related working capital items resulted in an adjustment to accounts payable.

Columbia’s natural gas pipelines are subject to FERC regulations and, as a result, their rate bases are expected to be recovered with a reasonable rate of return over the life of the assets. These assets, as well as related regulatory assets and liabilities, had fair values equal to their carrying values on acquisition. The fair value of mineral rights included in Columbia's plant, property and equipment was determined using a discounted cash flow approach which resulted in a fair value increase of $241 million (US$185 million). On acquisition date, the fair value of base gas included in Columbia’s plant, property and equipment was determined by using a quoted market price multiplied by the estimated volume of base gas in place which resulted in a fair value increase of $840 million (US$646 million).

In second quarter 2017, the Company completed its procedures over measuring the volume of base gas acquired and, as a result, decreased its fair value by $116 million (US$90 million). This impacted the purchase price equation by decreasing property, plant and equipment by $116 million (US$90 million), decreasing deferred income tax liabilities by $45 million (US$35 million) and increasing goodwill by $71 million (US$55 million) to a total of US$7,802 million (2016 – US$7,747 million) at December 31, 2017. This adjustment did not impact the Company's net income.

The fair value of Columbia’s long-term debt was estimated using an income approach based on observable market rates for similar debt instruments from external data service providers. This resulted in a fair value increase of $300 million (US$231 million).

The following table summarizes the acquisition date fair value of Columbia's debt acquired by TCPL.

(millions of $) Maturity Date Type Fair Value Interest Rate

COLUMBIA PIPELINE GROUP, INC. June 2018 Senior Unsecured Notes (US$500) US$506 2.45% June 2020 Senior Unsecured Notes (US$750) US$779 3.30% June 2025 Senior Unsecured Notes (US$1,000) US$1,092 4.50% June 2045 Senior Unsecured Notes (US$500) US$604 5.80% US$2,981

72 TCPL Consolidated financial statements 2018 The fair values of Columbia's DB plan and other post-retirement benefit plans were based on an actuarial valuation of the funded status of the plans as of the acquisition date which resulted in an increase of $15 million (US$12 million) and $5 million (US$4 million) to Regulatory assets and Other long-term liabilities, respectively, and a decrease of $14 million (US$11 million) and $2 million (US$2 million) to Intangible and other assets and Regulatory liabilities, respectively.

Temporary differences created as a result of the fair value changes described above resulted in deferred income tax assets and liabilities that were recorded at the Company's then U.S. effective tax rate of 39 per cent.

The fair value of Columbia’s non-controlling interests was based on the approximately 53.8 million CPPL common units outstanding to the public as of June 30, 2016, and valued at the June 30, 2016 closing price of US$15.00 per common unit. On February 17, 2017, TCPL acquired all outstanding publicly held common units of CPPL. Refer to Note 19, Non-controlling interests, for further information.

In 2016, acquisition expenses of approximately $36 million were included in Plant operating costs and other in the Consolidated statement of income.

Upon completion of the acquisition, the Company began consolidating Columbia. Columbia’s significant accounting policies were consistent with TCPL’s and continued to be applied. Columbia contributed $929 million to the Company's Revenues and $132 million to the Company's net income from July 1, 2016 to December 31, 2016.

The following supplemental pro forma consolidated financial information of the Company for the years ended December 31, 2016 and 2015 includes the results of operations for Columbia as if the acquisition had been completed on January 1, 2015.

year ended December 31 (millions of Canadian $) 2016 2015

Revenues 13,404 13,007 Net Income/(Loss) 715 (820) Net Income/(Loss) Attributable to Controlling Interests and to Common Shares 431 (877)

Energy Cartier Wind On October 24, 2018, the Company completed the sale of its 62 per cent interest in the Cartier Wind power facilities to Innergex Renewable Energy Inc for proceeds of $630 million, before post-closing adjustments. As a result, the Company recorded a gain on sale of $170 million ($143 million after tax) which is included in Gain/(loss) on assets held for sale/sold in the Consolidated statement of income.

Ontario Solar Assets On December 19, 2017, the Company completed the sale of its Ontario solar assets to a third party for proceeds of $541 million, before post-closing adjustments. As a result, the Company recorded a gain on sale of $127 million ($136 million after tax) which is included in Gain/(loss) on assets held for sale/sold in the Consolidated statement of income.

U.S. Northeast Power Assets In 2018, upon finalizing its 2017 annual tax return for its U.S. operations, the Company recorded a $27 million income tax recovery related to the sale of its U.S. Northeast power generation assets.

On April 19, 2017, the Company completed the sale of TC Hydro for proceeds of approximately US$1.07 billion, before post-closing adjustments. As a result, in 2017 the Company recorded a gain on sale of $715 million ($440 million after tax) including the impact of $5 million of foreign currency translation gains which were reclassified from AOCI to net income.

On June 2, 2017, TCPL completed the sale of Ravenswood, Ironwood, Kibby Wind and Ocean State Power for proceeds of approximately US$2.029 billion, before post-closing adjustments. In 2016, the Company recorded a loss of $829 million ($863 million after tax) which included the impact of $70 million of foreign currency translation gains that were reclassified from AOCI to net income on close. The Company recorded an additional loss on sale of $211 million ($167 million after tax) in 2017 which included $2 million in foreign currency translation gains. This additional loss primarily related to adjustments to the purchase price and repair costs for an unplanned outage at Ravenswood prior to close of the sale.

TCPL Consolidated financial statements 2018 73 Gains and losses from these sales are included in Gain/(loss) on assets held for sale/sold in the Consolidated statement of income. The proceeds received from the sale of the U.S. Northeast Power assets were used to repay the outstanding balances on the Company's acquisition bridge facilities that partially funded the acquisition of Columbia.

Ironwood In February 2016, TCPL acquired the Ironwood natural gas fired, combined cycle power plant for US$653 million in cash after post-closing adjustments. The evaluation of assigned fair value of acquired assets and liabilities did not result in the recognition of goodwill. The Company began consolidating Ironwood as of the date of acquisition which did not have a material impact on the Revenues and Net income of the Company. In addition, the pro forma incremental impact of Ironwood on the Company’s Revenues and Net income from the date of acquisition to the date of sale was not material.

26. COMMITMENTS, CONTINGENCIES AND GUARANTEES Commitments Operating leases Future annual payments under the Company's operating leases for various premises, services and equipment, net of sublease receipts, are approximately as follows:

year ended December 31 Amounts Minimum Recoverable Lease under Net (millions of Canadian $) Payments Subleases Payments

2019 81 7 74 2020 78 7 71 2021 76 4 72 2022 69 3 66 2023 67 3 64 2024 and thereafter 390 8 382 761 32 729

The operating lease agreements for premises, services and equipment expire at various dates through 2052, with an option to renew certain lease agreements for periods of one year to 25 years. Net rental expense on operating leases in 2018 was $84 million (2017 – $93 million; 2016 – $145 million).

Other commitments TCPL and its affiliates have long-term natural gas transportation and natural gas purchase arrangements as well as other purchase obligations, all of which are transacted at market prices and in the normal course of business.

Capital expenditure commitments include obligations related to the construction of growth projects and are based on the projects proceeding as planned. Changes to these projects, including cancellation, would reduce or possibly eliminate these commitments as a result of cost mitigation efforts. At December 31, 2018, TCPL had the following capital expenditure commitments: • 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.

74 TCPL Consolidated financial statements 2018 Contingencies TCPL is subject to laws and regulations governing environmental quality and pollution control. As at December 31, 2018, the Company had accrued approximately $40 million (2017 – $34 million) related to operating facilities, which represents the present value of the estimated future amount it expects to spend to remediate the sites. However, additional liabilities may be incurred as assessments take place and remediation efforts continue.

TCPL and its subsidiaries are subject to various legal proceedings, arbitrations and actions arising in the normal course of business. The amounts involved in such proceedings are not reasonably estimable as the final outcome of such legal proceedings cannot be predicted with certainty. It is the opinion of management that the ultimate resolution of such proceedings and actions will not have a material impact on the Company's consolidated financial position or results of operations.

Guarantees TCPL and its partner on the Sur de Texas pipeline, IEnova, have jointly guaranteed the financial performance of this entity. Such agreements include a guarantee and a letter of credit which are primarily related to construction services and the delivery of natural gas.

TCPL and its joint venture partner on Bruce Power, BPC Generation Infrastructure Trust, have each severally guaranteed certain contingent financial obligations of Bruce Power related to a lease agreement and contractor and supplier services.

The Company and its partners in certain other jointly owned entities have either (i) jointly and severally, (ii) jointly or (iii) severally guaranteed the financial performance of these entities. Such agreements include guarantees and letters of credit which are primarily related to delivery of natural gas, construction services and the payment of liabilities. For certain of these entities, any payments made by TCPL under these guarantees in excess of its ownership interest are to be reimbursed by its partners.

The carrying value of these guarantees has been recorded in Other long-term liabilities on the Consolidated balance sheet. Information regarding the Company’s guarantees is as follows:

2018 2017 at December 31 Potential Potential (millions of Canadian $) Term Exposure1 Carrying Value Exposure1 Carrying Value

Sur de Texas ranging to 2020 183 1 315 2 Bruce Power ranging to 2021 88 — 88 1 Other jointly owned entities ranging to 2059 104 11 104 13 375 12 507 16

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

27. CORPORATE RESTRUCTURING COSTS In mid-2015, the Company commenced a business restructuring and transformation initiative to reduce overall costs and maximize the effectiveness and efficiency of its existing operations. The Company incurred corporate restructuring costs and recorded a provision to allow for planned severance costs in future years, as well as expected future losses under lease commitments.

Cumulatively to December 31, 2018, the Company has incurred costs of $86 million for employee severance and $60 million for lease commitments, net of $157 million related to costs that were recoverable through regulatory and tolling structures. The Company recorded additional provisions in 2018 to reflect the changes in expected future losses under lease commitments. The remaining lease commitments provision at December 31, 2018 is expected to be fully realized by 2027.

TCPL Consolidated financial statements 2018 75 Changes in the restructuring liability were as follows:

Employee Lease (millions of Canadian $) Severance Commitments Total

Restructuring liability as at December 31, 2016 36 63 99 Restructuring charges1 — 6 6 Accretion expense — 1 1 Cash payments (27) (17) (44) Restructuring liability as at December 31, 2017 9 53 62 Restructuring charges1 — 42 42 Accretion expense — 1 1 Cash payments (9) (15) (24) Restructuring Liability as at December 31, 2018 — 81 81

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).

28. RELATED PARTY TRANSACTIONS Related party transactions are conducted in the normal course of business and are measured at the exchange amount, which is the amount of consideration established and agreed to by the related parties.

In 2018, Interest income and other included nil as a result of inter-affiliate lending to TransCanada (2017 - nil; 2016 - $19 million).

The following amounts are included in Due to affiliates:

2018 2017 Outstanding Effective Outstanding Effective (millions of Canadian $) Maturity Date December 31 Interest Rate December 31 Interest Rate

Credit Facility1 Demand 3,617 3.95% 2,551 3.2%

1 TCPL has an unsecured $4.5 billion credit facility with TransCanada. Interest on this facility is charged at the prime rate per annum.

In 2018, Interest expense included $114 million of interest charges as a result of inter-affiliate borrowing (2017 - $68 million; 2016 - $38 million).

At December 31, 2018, Accounts payable and other included $19 million due to TransCanada (December 31, 2017 - $16 million).The company made interest payments of $99 million to TransCanada in 2018 (2017 - $68 million; 2016 - $36 million).

29. VARIABLE INTEREST ENTITIES A VIE is a legal entity that does not have sufficient equity at risk to finance its activities without additional subordinated financial support or is structured such that equity investors lack the ability to make significant decisions relating to the entity’s operations through voting rights or do not substantively participate in the gains and losses of the entity.

In the normal course of business, the Company consolidates VIEs in which it has a variable interest and for which it is considered to be the primary beneficiary. VIEs in which the Company has a variable interest but is not the primary beneficiary are accounted for as equity investments.

76 TCPL Consolidated financial statements 2018 Consolidated VIEs The Company's consolidated VIEs consist of legal entities where the Company is the primary beneficiary. As the primary beneficiary, the Company has the power, through voting or similar rights, to direct the activities of the VIE that most significantly impact economic performance including purchasing or selling significant assets; maintenance and operations of assets; incurring additional indebtedness; or determining the strategic operating direction of the entity. In addition, the Company has the obligation to absorb losses or the right to receive benefits from the consolidated VIE that could potentially be significant to the VIE.

A significant portion of the Company’s assets are held through VIEs in which the Company holds a 100 per cent voting interest, the VIE meets the definition of a business and the VIE’s assets can be used for general corporate purposes. The Consolidated VIEs whose assets cannot be used for purposes other than for the settlement of the VIE’s obligations are as follows:

at December 31 (millions of Canadian $) 2018 2017

ASSETS Current Assets Cash and cash equivalents 45 41 Accounts receivable 79 63 Inventories 24 23 Other 13 11 161 138 Plant, Property and Equipment 3,026 3,535 Equity Investments 965 917 Goodwill 453 490 Intangible and Other Assets 8 3 4,613 5,083 LIABILITIES Current Liabilities Accounts payable and other 88 137 Dividends payable — 1 Accrued interest 24 23 Current portion of long-term debt 79 88 191 249 Regulatory Liabilities 43 34 Other Long-Term Liabilities 3 3 Deferred Income Tax Liabilities 13 13 Long-Term Debt 3,125 3,244 3,375 3,543

TCPL Consolidated financial statements 2018 77 Non-Consolidated VIEs The Company’s non-consolidated VIEs consist of legal entities where the Company is not the primary beneficiary as it does not have the power to direct the activities that most significantly impact the economic performance of these VIEs or where this power is shared with third parties. The Company contributes capital to these VIEs and receives ownership interests that provide it with residual claims on assets after liabilities are paid.

The carrying value of these VIEs and the maximum exposure to loss as a result of the Company's involvement with these VIEs are as follows:

at December 31 (millions of Canadian $) 2018 2017

Balance sheet Equity investments 4,575 4,372 Off-balance sheet Potential exposure to guarantees 170 171 Maximum exposure to loss 4,745 4,543

30. SUBSEQUENT EVENT Common Share Issuance On January 31, 2019, the Company issued 3.8 million common shares to TransCanada for proceeds of $214 million.

78 TCPL Consolidated financial statements 2018 TRANSCANADA PIPELINES LIMITED [1 FIRST QUARTER 2019

Condensed consolidated statement of income

three months ended March 31 (unaudited - millions of Canadian $) 2019 2018

Revenues Canadian Natural Gas Pipelines 967 884 U.S. Natural Gas Pipelines 1,304 1,091 Mexico Natural Gas Pipelines 152 151 Liquids Pipelines 728 623 Power and Storage 336 675 3,487 3,424 Income from Equity Investments 155 80 Operating and Other Expenses Plant operating costs and other 929 874 Commodity purchases resold 252 597 Property taxes 187 150 Depreciation and amortization 608 535 1,976 2,156 Financial Charges Interest expense 621 548 Allowance for funds used during construction (139) (105) Interest income and other (163) (63) 319 380 Income before Income Taxes 1,347 968 Income Tax Expense Current 160 50 Deferred 71 65 231 115 Net Income 1,116 853 Net income attributable to non-controlling interests 101 94 Net Income Attributable to Controlling Interests and to Common Shares 1,015 759 See accompanying notes to the Condensed consolidated financial statements. TRANSCANADA PIPELINES LIMITED [2 FIRST QUARTER 2019

Condensed consolidated statement of comprehensive income

three months ended March 31 (unaudited - millions of Canadian $) 2019 2018

Net Income 1,116 853 Other Comprehensive (Loss)/Income, Net of Income Taxes Foreign currency translation losses and gains on net investment in foreign operations (370) 432 Change in fair value of net investment hedges 20 (2) Change in fair value of cash flow hedges (17) 7 Reclassification to net income of gains and losses on cash flow hedges 3 3 Reclassification of actuarial gains and losses on pension and other post-retirement benefit plans 3 (2) Other comprehensive income on equity investments 1 6 Other comprehensive (loss)/income (360) 444 Comprehensive Income 756 1,297 Comprehensive income attributable to non-controlling interests 61 160 Comprehensive Income Attributable to Controlling Interests and to Common Shares 695 1,137

See accompanying notes to the Condensed consolidated financial statements. TRANSCANADA PIPELINES LIMITED [3 FIRST QUARTER 2019

Condensed consolidated statement of cash flows

three months ended March 31 (unaudited - millions of Canadian $) 2019 2018 Cash Generated from Operations Net income 1,116 853 Depreciation and amortization 608 535 Deferred income taxes 71 65 Income from equity investments (155) (80) Distributions received from operating activities of equity investments 277 234 Employee post-retirement benefits funding, net of expense 3 3 Equity allowance for funds used during construction (94) (78) Unrealized (gains)/losses on financial instruments (32) 188 Other (22) (122) Decrease/(increase) in operating working capital 137 (206) Net cash provided by operations 1,909 1,392 Investing Activities Capital expenditures (2,022) (1,702) Capital projects in development (164) (36) Contributions to equity investments (145) (358) Other distributions from equity investments 120 121 Deferred amounts and other (26) 110 Net cash used in investing activities (2,237) (1,865) Financing Activities Notes payable issued, net 2,852 1,812 Long-term debt issued, net of issue costs 24 93 Long-term debt repaid (1,708) (1,226) Advances from affiliate 60 215 Dividends on common shares (634) (551) Distributions to non-controlling interests (56) (69) Common shares issued 214 192 Partnership units of TC PipeLines, LP issued, net of issue costs — 49 Net cash provided by financing activities 752 515 Effect of Foreign Exchange Rate Changes on Cash and Cash Equivalents (7) 29 Increase in Cash and Cash Equivalents 417 71 Cash and Cash Equivalents Beginning of period 362 1,044 Cash and Cash Equivalents End of period 779 1,115

See accompanying notes to the Condensed consolidated financial statements. TRANSCANADA PIPELINES LIMITED [4 FIRST QUARTER 2019

Condensed consolidated balance sheet

March 31, December 31, (unaudited - millions of Canadian $) 2019 2018 ASSETS Current Assets Cash and cash equivalents 779 362 Accounts receivable 2,220 2,548 Inventories 407 431 Assets held for sale 533 543 Other 879 1,180 4,818 5,064 net of accumulated depreciation of $26,181 Plant, Property and Equipment and $25,834, respectively 67,520 66,503 Equity Investments 6,966 7,113 Regulatory Assets 1,557 1,548 Goodwill 13,881 14,178 Loan Receivable from Affiliate 1,336 1,315 Intangible and Other Assets 1,837 1,887 Restricted Investments 1,315 1,207 99,230 98,815 LIABILITIES Current Liabilities Notes payable 5,587 2,762 Accounts payable and other 4,697 5,426 Dividends payable 693 633 Due to affiliate 3,677 3,617 Accrued interest 613 646 Current portion of long-term debt 1,757 3,462 17,024 16,546 Regulatory Liabilities 3,971 3,930 Other Long-Term Liabilities 1,492 1,008 Deferred Income Tax Liabilities 5,994 6,026 Long-Term Debt 35,857 36,509 Junior Subordinated Notes 7,380 7,508 71,718 71,527 EQUITY Common shares, no par value 22,820 22,606 Issued and outstanding: March 31, 2019 – 891 million shares December 31, 2018 – 887 million shares Additional paid-in capital 23 20 Retained earnings 3,935 3,613 Accumulated other comprehensive loss (926) (606) Controlling Interests 25,852 25,633 Non-controlling interests 1,660 1,655 27,512 27,288 99,230 98,815

Contingencies and Guarantees (Note 13) Variable Interest Entities (Note 15) Subsequent Event (Note 16)

See accompanying notes to the Condensed consolidated financial statements. TRANSCANADA PIPELINES LIMITED [5 FIRST QUARTER 2019

Condensed consolidated statement of equity

three months ended March 31 (unaudited - millions of Canadian $) 2019 2018 Common Shares Balance at beginning of period 22,606 21,761 Proceeds from shares issued 214 192 Balance at end of period 22,820 21,953 Additional Paid-In Capital Balance at beginning of period 20 — Issuance of stock options 3 4 Dilution from TC PipeLines, LP units issued — 7 Balance at end of period 23 11 Retained Earnings Balance at beginning of period 3,613 2,387 Net income attributable to controlling interests 1,015 759 Common share dividends (693) (614) Adjustment related to income tax effects of asset drop-downs to TC PipeLines, LP — 95 Balance at end of period 3,935 2,627 Accumulated Other Comprehensive Loss Balance at beginning of period (606) (1,731) Other comprehensive (loss)/income attributable to controlling interests (320) 378 Balance at end of period (926) (1,353) Equity Attributable to Controlling Interests 25,852 23,238 Equity Attributable to Non-Controlling Interests Balance at beginning of period 1,655 1,852 Net income attributable to non-controlling interests 101 94 Other comprehensive (loss)/income attributable to non-controlling interests (40) 66 Issuance of TC PipeLines, LP units Proceeds, net of issue costs — 49 Decrease in TCPL's ownership of TC PipeLines, LP — (9) Distributions declared to non-controlling interests (56) (71) Balance at end of period 1,660 1,981 Total Equity 27,512 25,219 See accompanying notes to the Condensed consolidated financial statements. TRANSCANADA PIPELINES LIMITED [6 FIRST QUARTER 2019

Notes to Condensed consolidated financial statements (unaudited)

1. Basis of presentation

These Condensed consolidated financial statements of TransCanada PipeLines Limited (TCPL or the Company) have been prepared by management in accordance with U.S. GAAP. The accounting policies applied are consistent with those outlined in TCPL’s annual audited Consolidated financial statements for the year ended December 31, 2018, except as described in Note 2, Accounting changes. Capitalized and abbreviated terms that are used but not otherwise defined herein are identified in the 2018 audited Consolidated financial statements. As of first quarter 2019, the previously disclosed Energy segment has been renamed the Power and Storage segment. These Condensed consolidated financial statements reflect adjustments, all of which are normal recurring adjustments that are, in the opinion of management, necessary to reflect fairly the financial position and results of operations for the respective periods. These Condensed consolidated financial statements do not include all disclosures required in the annual financial statements and should be read in conjunction with the 2018 audited Consolidated financial statements. Certain comparative figures have been reclassified to conform with the current period’s presentation. Earnings for interim periods may not be indicative of results for the fiscal year in the Company’s natural gas pipelines segments due to the timing of regulatory decisions and seasonal fluctuations in short-term throughput volumes on U.S. pipelines. Earnings for interim periods may also not be indicative of results for the fiscal year in the Company’s Power and Storage segment due to the impact of seasonal weather conditions on customer demand and market pricing in certain of the Company’s investments in electrical power generation plants and non-regulated gas storage facilities.

USE OF ESTIMATES AND JUDGMENTS In preparing these financial statements, TCPL is required to make estimates and assumptions that affect both the amount and timing of recording assets, liabilities, revenues and expenses since the determination of these items may be dependent on future events. The Company uses the most current information available and exercises careful judgment in making these estimates and assumptions. In the opinion of management, these Condensed consolidated financial statements have been properly prepared within reasonable limits of materiality and within the framework of the Company’s significant accounting policies included in the annual audited Consolidated financial statements for the year ended December 31, 2018, except as described in Note 2, Accounting changes. 2. Accounting changes

CHANGES IN ACCOUNTING POLICIES FOR 2019

Leases In February 2016, the FASB issued new guidance on the accounting for leases. The new guidance amends the definition of a lease such that, in order for an arrangement to qualify as a lease, the lessee is required to have both (1) the right to obtain substantially all of the economic benefits from the use of the asset and (2) the right to direct the use of the asset. The new guidance also establishes a right-of-use (ROU) model that requires a lessee to recognize a ROU asset and corresponding lease liability on the balance sheet for all leases with a term longer than twelve months. Leases will be classified as finance or operating, with classification affecting the pattern of expense recognition in the consolidated statement of income. The new guidance does not make extensive changes to lessor accounting. TRANSCANADA PIPELINES LIMITED [7 FIRST QUARTER 2019

The new guidance was effective January 1, 2019 and was applied using optional transition relief which allowed entities to initially apply the new lease standard at adoption (January 1, 2019) and recognize a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption. This transition option allowed the Company to not apply the new guidance, including disclosure requirements, to the comparative periods presented. The Company elected available practical expedients and exemptions upon adoption which allowed the Company: • not to reassess prior conclusions on existing leases regarding lease identification, lease classification and initial direct costs under the new standard • to carry forward the historical lease classification and its accounting treatment for land easements on existing agreements • to not recognize ROU assets or lease liabilities for leases that qualify for the short-term lease recognition exemption • to not separate lease and non-lease components for all leases for which the Company is the lessee and for facility and liquids tank terminals for which the Company is the lessor • to use hindsight in determining the lease term and assessing ROU assets for impairment. The new guidance had a significant impact on the Company's Condensed consolidated balance sheet, but did not have an impact on the Company's Condensed consolidated statements of income and cash flows. The most significant impact was the recognition of ROU assets and lease liabilities for operating leases and providing significant new disclosures about the Company's leasing activities. Refer to Note 7, Leases, for further information related to the impact of adopting the new guidance and the Company's updated accounting policies related to leases.

In the application of the new guidance, significant assumptions and judgments are used to determine the following: • whether a contract contains a lease • the duration of the lease term including exercising lease renewal options. The lease term for all of the Company’s leases includes the noncancellable period of the lease plus any additional periods covered by either a Company option to extend (or not to terminate) the lease that the Company is reasonably certain to exercise, or an option to extend (or not to terminate) the lease controlled by the lessor • the discount rate for the lease.

Fair value measurement In August 2018, the FASB issued new guidance that amends certain disclosure requirements for fair value measurements. This new guidance is effective January 1, 2020, however, early adoption of certain or all requirements is permitted. The Company elected to adopt this guidance effective first quarter 2019. The guidance was applied retrospectively and did not have a material impact on the Company's consolidated financial statements.

FUTURE ACCOUNTING CHANGES

Measurement of credit losses on financial instruments In June 2016, the FASB issued new guidance that significantly changes how entities measure credit losses for most financial assets and certain other financial instruments that are not measured at fair value through net income. The new guidance amends the impairment model of financial instruments, basing it on expected losses rather than incurred losses. These expected credit losses will be recognized as an allowance rather than as a direct write down of the amortized cost basis. The new guidance is effective January 1, 2020 and will be applied using a modified retrospective approach. The Company is currently evaluating the impact of the adoption of this guidance and has not yet determined the effect on its consolidated financial statements. TRANSCANADA PIPELINES LIMITED [8 FIRST QUARTER 2019

Defined benefit plans In August 2018, the FASB issued new guidance which amends and clarifies disclosure requirements related to defined benefit pension and other post-retirement benefit plans. This new guidance is effective January 1, 2021 and will be applied on a retrospective basis, however, early adoption is permitted. The Company is currently evaluating the timing and impact of the adoption of this guidance and has not yet determined the effect on its consolidated financial statements.

Implementation costs of cloud computing arrangements In August 2018, the FASB issued new guidance requiring an entity in a hosting arrangement that is a service contract to follow the guidance for internal-use software to determine which implementation costs should be capitalized as an asset and which costs should be expensed. The guidance also requires the entity to amortize the capitalized implementation costs of a hosting arrangement over the term of the arrangement. This guidance is effective January 1, 2020, however, early adoption is permitted. This guidance can be applied either retrospectively or prospectively to all implementation costs incurred after the date of adoption. The Company is currently evaluating the timing and impact of adoption of this guidance and has not yet determined the effect on its consolidated financial statements.

Consolidation In October 2018, the FASB issued new guidance for determining whether fees paid to decision makers and service providers are variable interests for indirect interests held through related parties under common control. This new guidance is effective January 1, 2020 and will be applied on a retrospective basis, however, early adoption is permitted. The Company is currently evaluating the timing and impact of the adoption of this guidance and has not yet determined the effect on its consolidated financial statements. TRANSCANADA PIPELINES LIMITED [9 FIRST QUARTER 2019

3. Segmented information

three months ended Canadian U.S. Mexico March 31, 2019 Natural Natural Natural Power Liquids and Gas Gas Gas 1 (unaudited - millions of Canadian $) Pipelines Pipelines Pipelines Pipelines Storage Corporate2 Total Revenues 967 1,304 152 728 336 — 3,487 Intersegment revenues — 42 — — 5 (47) 3 — 967 1,346 152 728 341 (47) 3,487 Income/(loss) from equity investments 1 76 6 14 72 (14) 4 155 Plant operating costs and other (343) (362) (12) (166) (88) 42 3 (929) Commodity purchases resold — — — — (252) — (252) Property taxes (69) (88) — (28) (2) — (187) Depreciation and amortization (287) (180) (30) (88) (23) — (608) Segmented Earnings/(Loss) 269 792 116 460 48 (19) 1,666 Interest expense (621) Allowance for funds used during construction 139 Interest income and other4 163 Income before income taxes 1,347 Income tax expense (231) Net Income 1,116 Net income attributable to non-controlling interests (101) Net Income Attributable to Controlling Interests and to Common Shares 1,015

1 Previously referred to as Energy. 2 Includes intersegment eliminations. 3 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. 4 Income/(loss) from equity investments includes foreign exchange losses on the Company's inter-affiliate loan with Sur de Texas. The offsetting foreign exchange gains 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. TRANSCANADA PIPELINES LIMITED [10 FIRST QUARTER 2019

three months ended Canadian U.S. Mexico March 31, 2018 Natural Natural Natural Power Gas Gas Gas Liquids and (unaudited - millions of Canadian $) Pipelines Pipelines Pipelines Pipelines Storage1 Corporate2 Total

Revenues 884 1,091 151 623 675 — 3,424 Intersegment revenues — 25 — — 42 (67) 3 — 884 1,116 151 623 717 (67) 3,424 Income/(loss) from equity investments 3 67 11 15 63 (79) 4 80 Plant operating costs and other (323) (324) (2) (191) (99) 65 3 (874) Commodity purchases resold — — — — (597) — (597) Property taxes (70) (55) — (23) (2) — (150) Depreciation and amortization (241) (156) (23) (83) (32) — (535) Segmented Earnings/(Loss) 253 648 137 341 50 (81) 1,348 Interest expense (548) Allowance for funds used during construction 105 Interest income and other4 63 Income before income taxes 968 Income tax expense (115) Net Income 853 Net income attributable to non-controlling interests (94) Net Income Attributable to Controlling Interests and to Common Shares 759

1 Previously referred to as Energy. 2 Includes intersegment eliminations. 3 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. 4 Income/(loss) from equity investments includes foreign exchange losses on the Company's inter-affiliate loan with Sur de Texas. The offsetting foreign exchange gains 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.

TOTAL ASSETS BY SEGMENT

(unaudited - millions of Canadian $) March 31, 2019 December 31, 2018

Canadian Natural Gas Pipelines 19,287 18,407 U.S. Natural Gas Pipelines 43,532 44,115 Mexico Natural Gas Pipelines 6,858 7,058 Liquids Pipelines 17,025 17,352 Power and Storage 8,331 8,475 Corporate 4,197 3,408 99,230 98,815 TRANSCANADA PIPELINES LIMITED [11 FIRST QUARTER 2019

4. Revenues

DISAGGREGATION OF REVENUES The following tables summarize total Revenues for the three months ended March 31, 2019 and 2018:

Canadian U.S. Mexico Natural Natural Natural Power three months ended March 31, 2019 Gas Gas Gas Liquids and (unaudited - millions of Canadian $) Pipelines Pipelines Pipelines Pipelines Storage Total Revenues from contracts with customers Capacity arrangements and transportation 967 1,100 151 593 — 2,811 Power generation — — — — 343 343 Natural gas storage and other — 180 1 1 28 210 967 1,280 152 594 371 3,364 Other revenues1 — 24 — 134 (35) 123 967 1,304 152 728 336 3,487

1 Other revenues include income from the Company's marketing activities, financial instruments and lease arrangements. These arrangements are not in the scope of the revenue guidance. Refer to Note 7, Leases, and Note 12, Risk management and financial instruments, for further information on income from lease arrangements and financial instruments, respectively.

Canadian U.S. Mexico Natural Natural Natural Power three months ended March 31, 2018 Gas Gas Gas Liquids and (unaudited - millions of Canadian $) Pipelines Pipelines Pipelines Pipelines Storage Total Revenues from contracts with customers Capacity arrangements and transportation 884 884 150 534 — 2,452 Power generation — — — — 590 590 Natural gas storage and other — 192 1 1 30 224 884 1,076 151 535 620 3,266 Other revenues1 — 15 — 88 55 158 884 1,091 151 623 675 3,424

1 Other revenues include income from the Company's marketing activities, financial instruments and lease arrangements. These arrangements are not in the scope of the revenue guidance. Refer to Note 12, Risk management and financial instruments, for further information on income from financial instruments.

CONTRACT BALANCES

(unaudited - millions of Canadian $) March 31, 2019 December 31, 2018

Receivables from contracts with customers 1,382 1,684 Contract assets1 249 159 Long-term contract assets2 11 21 Contract liabilities3 39 11 Long-term contract liabilities4 119 121

1 Recorded as part of Other current assets on the Condensed consolidated balance sheet. 2 Recorded as part of Intangibles and other assets on the Condensed consolidated balance sheet. 3 Comprised of deferred revenue recorded in Accounts payable and other on the Condensed consolidated balance sheet. During the three months ended March 31, 2019, $6 million of revenue was recognized that was included in contract liabilities at the beginning of the period. 4 Comprised of deferred revenue recorded in Other long-term liabilities on the Condensed consolidated balance sheet. TRANSCANADA PIPELINES LIMITED [12 FIRST QUARTER 2019

Contract assets and long-term contract assets primarily relate to the Company’s right to revenues for services completed but not invoiced at the reporting date on long-term committed capacity natural gas pipelines contracts. The change in contract assets is primarily related to the transfer to Accounts receivable when these rights become unconditional and the customer is invoiced as well as the recognition of additional revenues that remain to be invoiced. Contract liabilities and long-term contract liabilities primarily relate to force majeure fixed capacity payments received on long-term capacity arrangements in Mexico.

FUTURE REVENUES FROM REMAINING PERFORMANCE OBLIGATIONS

Capacity Arrangements and Transportation As at March 31, 2019, future revenues from long-term pipeline capacity arrangements and transportation contracts extending through 2045 are approximately $32.3 billion, of which approximately $5.4 billion is expected to be recognized during the remainder of 2019.

Power Generation The Company has long-term power generation contracts extending through 2030. Revenues from power generation contracts have a variable component related to market prices that are subject to factors outside the Company’s influence. These revenues are considered to be fully constrained and are recognized on a monthly basis when the Company satisfies the performance obligation.

Natural Gas Storage and Other As at March 31, 2019, future revenues from long-term natural gas storage and other contracts extending through 2033 are approximately $1.7 billion, of which approximately $366 million is expected to be recognized during the remainder of 2019. 5. Income taxes

Effective Tax Rates The effective income tax rates for the three-month periods ended March 31, 2019 and 2018 were 17 per cent and 12 per cent, respectively. The higher effective tax rate in 2019 was primarily the result of lower foreign tax rate differentials partially offset by lower flow-through tax in Canadian rate-regulated pipelines. Further to U.S. Tax Reform, the U.S. Treasury and the U.S. Internal Revenue Service issued proposed regulations in November and December of 2018 which provided administrative guidance and clarified certain aspects of the new laws with respect to interest deductibility, base erosion and anti-abuse tax, the new dividend received deduction and anti- hybrid rules. The proposed regulations are complex and comprehensive, and considerable uncertainty continues to exist pending release of the final regulations which is expected to occur later in 2019. As these proposed regulations have not been enacted as at March 31, 2019, their impact has not been reflected in income tax expense. If the proposed regulations are enacted as currently drafted, the resulting income tax expense should not have a material impact on the Company's financial statements. TRANSCANADA PIPELINES LIMITED [13 FIRST QUARTER 2019

6. Assets held for sale

Coolidge Generating Station In December 2018, TCPL entered into an agreement to sell its Coolidge generating station in Arizona to SWG Coolidge Holdings, LLC (SWG). Salt River Project Agriculture Improvement and Power District (SRP), the PPA counterparty, subsequently exercised its contractual right of first refusal on a sale to a third party. On March 20, 2019, TCPL terminated the agreement with SWG after entering into an agreement with SRP to sell the Coolidge generating station for approximately US$465 million, subject to timing of the close and related adjustments. The sale will result in an estimated gain of approximately $70 million ($55 million after tax) including the release of an estimated $10 million of foreign currency translation gains. The gain will be recognized upon closing of the sale transaction, which is expected to occur mid-2019. At March 31, 2019, the related assets and liabilities in the Power and Storage segment were classified as held for sale as follows:

(unaudited - millions of Canadian $)

Assets held for sale Accounts receivable 6 Other current assets 1 Plant, property and equipment 526 Total assets held for sale 533 Liabilities related to assets held for sale Other long-term liabilities (3) Total liabilities related to assets held for sale1 (3)

1 Included in Accounts payable and other on the Condensed consolidated balance sheet. 7. Leases

In 2016, the FASB issued new guidance on leases. The Company adopted the new guidance on January 1, 2019 using optional transition relief. Results reported for 2019 reflect the application of the new guidance, while the 2018 comparative results were prepared and reported under previous leases guidance.

Lessee Accounting Policy The Company determines if an arrangement is a lease at inception of the contract. Operating leases are recognized as ROU assets and included in Plant, property and equipment while corresponding liabilities are included in Accounts payable and other, and Other long-term liabilities on the Condensed consolidated balance sheet. Operating lease ROU assets and operating lease liabilities are recognized based on the present value of the future minimum lease payments over the lease term at the commencement date of the lease agreement. As the Company’s lease contracts do not provide an implicit interest rate, the Company uses its incremental borrowing rate based on the information available at commencement date in determining the present value of future payments. The operating lease ROU asset also includes any lease payments made and initial direct costs incurred and excludes lease incentives. Lease terms may include options to extend or terminate the lease when it is reasonably certain that the Company will exercise that option. Operating lease expense is recognized on a straight-line basis over the lease term and included in Plant operating costs and other in the Condensed consolidated statement of income. TRANSCANADA PIPELINES LIMITED [14 FIRST QUARTER 2019

Lessor Accounting Policy The Company is the lessor for certain contracts and these contracts are accounted for as operating leases. The Company recognizes lease payments as income over the lease term on a straight-line basis. Variable lease payments are recognized as income in the period in which the changes in facts and circumstances on which these payments are based occur.

Impact of New Lease Guidance on Date of Adoption The following table illustrates the impact of the adoption of the new lease guidance on the Company's previously reported consolidated balance sheet line items:

(unaudited - millions of Canadian $) As reported December 31, 2018 Adjustment January 1, 2019 Plant, property and equipment 66,503 585 67,088 Accounts payable and other 5,426 57 5,483 Other long-term liabilities 1,008 528 1,536

As a Lessee The Company has operating leases for corporate offices, other various premises, equipment and land. Some leases have an option to renew for periods of one to 25 years, and some may include options to terminate the lease within one year. Payments due under lease contracts include fixed payments plus, for many of the Company's leases, variable payments such as proportionate share of the buildings' property taxes, insurance and common area maintenance. The Company subleases some of the leased premises. Operating lease cost is as follows:

(unaudited - millions of Canadian $) three months ended March 31, 2019 Operating lease cost1 28 Sublease income (2) Net operating lease cost 26

1 Includes short-term leases and variable lease costs.

Other information related to operating leases is noted in the following table:

(unaudited - millions of Canadian $) three months ended March 31, 2019 Cash paid for amounts included in the measurement of operating lease liabilities 19 Weighted average remaining lease term 10.8 years Weighted average discount rate 3.56% TRANSCANADA PIPELINES LIMITED [15 FIRST QUARTER 2019

Maturities of operating lease liabilities on a prospective 12-month basis and where they are disclosed on the Condensed consolidated balance sheet as at March 31, 2019 are as follows:

(unaudited - millions of Canadian $) 2020 72 2021 69 2022 64 2023 58 2024 57 Thereafter 355 Total operating lease payments 675 Imputed interest (110) Operating lease liabilities recorded on the Condensed consolidated balance sheet 565 Reported as follows: Accounts payable and other 55 Other long-term liabilities 510 565

Future payments reported under previous lease guidance for the Company’s operating leases as at December 31, 2018 were as follows:

(unaudited - millions of Canadian $) Minimum operating lease payments 2019 81 2020 78 2021 76 2022 69 2023 67 Thereafter 390 761

As at March 31, 2019, the carrying value of the ROU assets recorded under operating leases was $570 million and is included in Plant, property and equipment on the Condensed consolidated balance sheet.

As a Lessor Coolidge, Grandview and Bécancour power plants in the Power and Storage segment and the Northern Courier pipeline in the Liquids Pipelines segment are accounted for as operating leases. As Coolidge is classified as Assets held for sale, it is not included in the following lease disclosures. The Company has long-term PPAs for the sale of power for the Power and Storage lease assets which expire between 2024 and 2026. Northern Courier pipeline transports bitumen and diluent between the Fort Hills mine site and Suncor Energy’s terminal, with a contract expiring in 2042. Some leases contain variable lease payments that are based on operating hours and the reimbursement of variable costs, options to purchase the underlying asset at fair value or based on a formula considering the remaining fixed payments, and options to extend a lease up to five years. Lessees have rights under some leases to terminate under certain circumstances. The Company also leases liquids tanks which are accounted for as operating leases. Operating lease income recorded by the Company for the three months ended March 31, 2019 was $55 million. TRANSCANADA PIPELINES LIMITED [16 FIRST QUARTER 2019

Future lease payments to be received under operating leases as at March 31, 2019 are as follows:

(unaudited - millions of Canadian $) Future lease payments Remainder of 2019 183 2020 226 2021 223 2022 218 2023 224 Thereafter 1,940 3,014

The cost and accumulated depreciation for facilities accounted for as operating leases was $2,023 million and $338 million, respectively, at March 31, 2019 (December 31, 2018 – $2,007 million and $324 million, respectively). 8. Long-term debt

LONG-TERM DEBT REPAID The Company retired long-term debt in the three months ended March 31, 2019 as follows:

(unaudited - millions of Canadian $, unless otherwise noted) Company Retirement date Type Amount Interest rate

TRANSCANADA PIPELINES LIMITED March 2019 Debentures 100 10.50% January 2019 Senior Unsecured Notes US 750 7.125% January 2019 Senior Unsecured Notes US 400 3.125%

CAPITALIZED INTEREST In the three months ended March 31, 2019, TCPL capitalized interest related to capital projects of $37 million (2018 – $26 million). 9. Common shares

On January 31, 2019, the Company issued 3.8 million common shares to TransCanada for proceeds of $214 million, resulting in 891 million shares outstanding at March 31, 2019 (December 31, 2018 – 887 million). TRANSCANADA PIPELINES LIMITED [17 FIRST QUARTER 2019

10. Other comprehensive (loss)/income and accumulated other comprehensive loss

Components of other comprehensive (loss)/income, including the portion attributable to non-controlling interests and related tax effects, are as follows:

three months ended March 31, 2019 Income Tax Before Tax Recovery/ Net of Tax (unaudited - millions of Canadian $) Amount (Expense) Amount Foreign currency translation losses on net investment in foreign operations (364) (6) (370) Change in fair value of net investment hedges 27 (7) 20 Change in fair value of cash flow hedges (22) 5 (17) Reclassification to net income of gains and losses on cash flow hedges 4 (1) 3 Reclassification of actuarial gains and losses on pension and other post-retirement benefit plans 4 (1) 3 Other comprehensive income on equity investments 1 — 1 Other Comprehensive Loss (350) (10) (360)

three months ended March 31, 2018 Income Tax Before Tax Recovery/ Net of Tax (unaudited - millions of Canadian $) Amount (Expense) Amount Foreign currency translation gains on net investment in foreign operations 416 16 432 Change in fair value of net investment hedges (3) 1 (2) Change in fair value of cash flow hedges 6 1 7 Reclassification to net income of gains and losses on cash flow hedges 4 (1) 3 Reclassification of actuarial gains and losses on pension and other post-retirement benefit plans 4 (6) (2) Other comprehensive income on equity investments 7 (1) 6 Other Comprehensive Income 434 10 444

The changes in AOCI by component are as follows:

three months ended March 31, 2019 Currency Pension and Cash Flow Equity Translation OPEB Plan 1 (unaudited - millions of Canadian $) Adjustments Hedges Adjustments Investments Total AOCI balance at January 1, 2019 107 (23) (314) (376) (606) Other comprehensive loss before reclassifications2 (315) (12) — (1) (328) Amounts reclassified from AOCI3,4 — 2 3 3 8 Net current period other comprehensive (loss)/ income (315) (10) 3 2 (320) AOCI balance at March 31, 2019 (208) (33) (311) (374) (926)

1 All amounts are net of tax. Amounts in parentheses indicate losses recorded to OCI. 2 Other comprehensive loss before reclassifications on currency translation adjustments and cash flow hedges are net of non-controlling interests losses of $35 million and $5 million, respectively. 3 Losses related to cash flow hedges reported in AOCI and expected to be reclassified to net income in the next 12 months are estimated to be $16 million ($12 million, net of tax) at March 31, 2019. 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. 4 Amounts reclassified from AOCI on cash flow hedges and equity investments are net of non-controlling interests gains of $1 million and nil, respectively. TRANSCANADA PIPELINES LIMITED [18 FIRST QUARTER 2019

Details about reclassifications out of AOCI into the Condensed consolidated statement of income are as follows:

Amounts Reclassified From AOCI Affected line item three months ended in the Condensed March 31 consolidated statement of (unaudited - millions of Canadian $) 2019 2018 income

Cash flow hedges Commodities — 1 Revenues (Power and Storage) Interest (3) (5) Interest expense (3) (4) Total before tax 1 1 Income tax expense (2) (3) Net of tax1,3 Pension and other post-retirement benefit plan adjustments Amortization of actuarial losses (4) (4) Plant operating costs and other2 1 6 Income tax expense (3) 2 Net of tax1 Equity investments Equity income (3) (7) Income from equity investments — 1 Income tax expense (3) (6) Net of tax1,3

1 All amounts in parentheses indicate expenses to the Condensed consolidated statement of income. 2 These AOCI components are included in the computation of net benefit cost. Refer to Note 11, Employee post-retirement benefits, for further information. 3 Amounts reclassified from AOCI on cash flow hedges and equity investments are net of non-controlling interests gains of $1 million and nil, respectively, for the three months ended March 31, 2019 (2018 – nil and nil). 11. Employee post-retirement benefits

The net benefit cost recognized for the Company’s pension benefit plans and other post-retirement benefit plans is as follows:

three months ended March 31 Pension benefit plans Other post-retirement benefit plans (unaudited - millions of Canadian $) 2019 2018 2019 2018

Service cost1 33 30 1 1 Other components of net benefit cost1 Interest cost 35 33 4 3 Expected return on plan assets (58) (55) (4) (4) Amortization of actuarial losses 3 4 1 — Amortization of regulatory asset 3 5 — — (17) (13) 1 (1) Net Benefit Cost 16 17 2 —

1 Service cost and other components of net benefit cost are included in Plant operating costs and other in the Condensed consolidated statement of income. TRANSCANADA PIPELINES LIMITED [19 FIRST QUARTER 2019

12. Risk management and financial instruments

RISK MANAGEMENT OVERVIEW TCPL has exposure to market risk and counterparty credit risk, and has strategies, policies and limits in place to manage the impact of these risks on earnings, cash flow and shareholder value.

COUNTERPARTY CREDIT RISK TCPL’s maximum counterparty credit exposure with respect to financial instruments at March 31, 2019, without taking into account security held, consisted of cash and cash equivalents, accounts receivable, available-for-sale assets, derivative assets and a loan receivable. The Company monitors its counterparties and regularly reviews its accounts receivable. The Company records an allowance for doubtful accounts as necessary using the specific identification method. At March 31, 2019, there were no significant credit losses, no significant credit risk concentration and no significant amounts past due or impaired.

LOAN RECEIVABLE FROM AFFILIATE The Company holds a 60 per cent equity interest in a joint venture with IEnova to build, own and operate the Sur de Texas pipeline. The Company accounts for its interest in the joint venture as an equity investment. In 2017, the Company entered into a MXN$21.3 billion unsecured revolving credit facility with the joint venture, which bears interest at a floating rate and matures in March 2022. At March 31, 2019, the Company's Condensed consolidated balance sheet included a MXN$19.4 billion or $1.3 billion (December 31, 2018 – MXN$18.9 billion or $1.3 billion) loan receivable from the Sur de Texas joint venture which represents TCPL's proportionate share of long-term debt financing requirements related to the joint venture. Interest income and other included interest income of $35 million for the three months ended March 31, 2019 (2018 – $27 million) from this joint venture with a corresponding proportionate share of interest expense recorded in Income from equity investments.

NET INVESTMENT IN FOREIGN OPERATIONS The Company hedges its net investment in foreign operations (on an after-tax basis) with U.S. dollar-denominated debt, cross-currency swaps and foreign exchange options. The fair values and notional amounts for the derivatives designated as a net investment hedge were as follows:

March 31, 2019 December 31, 2018

1,2 Notional 1,2 Notional (unaudited - millions of Canadian $, unless otherwise noted) Fair value amount Fair value amount U.S. dollar cross-currency swaps (maturing 2019)3 (12) US 100 (43) US 300 U.S. dollar foreign exchange options (maturing 2019 to 2020) (13) US 2,500 (47) US 2,500 (25) US 2,600 (90) US 2,800

1 Fair value equals carrying value. 2 No amounts have been excluded from the assessment of hedge effectiveness. 3 In the three months ended March 31, 2019, Net income includes net realized gains of nil (2018 – $1 million) related to the interest component of cross-currency swap settlements which are reported within Interest expense on the Company's Condensed consolidated statement of income.

The notional amounts and fair value of U.S. dollar-denominated debt designated as a net investment hedge were as follows:

(unaudited - millions of Canadian $, unless otherwise noted) March 31, 2019 December 31, 2018 Notional amount 30,800 (US 23,100) 31,000 (US 22,700) Fair value 32,900 (US 24,600) 31,700 (US 23,200) TRANSCANADA PIPELINES LIMITED [20 FIRST QUARTER 2019

FINANCIAL INSTRUMENTS

Non-derivative financial instruments

Fair value of non-derivative financial instruments Available-for-sale assets are recorded at fair value which is calculated using quoted market prices where available. Certain non-derivative financial instruments included in Cash and cash equivalents, Accounts receivable, Intangible and other assets, Notes payable, Accounts payable and other, Due to affiliate, Accrued interest and Other long-term liabilities have carrying amounts that approximate their fair value due to the nature of the item or the short time to maturity. Each of these instruments are classified in Level II of the fair value hierarchy. Credit risk has been taken into consideration when calculating the fair value of non-derivative instruments.

Balance sheet presentation of non-derivative financial instruments The following table details the fair value of the Company's non-derivative financial instruments, excluding those where carrying amounts approximate fair value, which are classified in Level II of the fair value hierarchy:

March 31, 2019 December 31, 2018 Carrying Fair Carrying Fair (unaudited - millions of Canadian $) amount value amount value Long-term debt including current portion1,2 (37,614) (41,737) (39,971) (42,284) Junior subordinated notes (7,380) (7,006) (7,508) (6,665) (44,994) (48,743) (47,479) (48,949)

1 Long-term debt is recorded at amortized cost except for US$450 million (December 31, 2018 – US$750 million) that is attributed to hedged risk and recorded at fair value. 2 Net income for the three months ended March 31, 2019 includes unrealized losses of $3 million (2018 – gains of $5 million) for fair value adjustments attributable to the hedged interest rate risk associated with interest rate swap fair value hedging relationships on US$450 million of long-term debt at March 31, 2019 (December 31, 2018 – US$750 million). There were no other unrealized gains or losses from fair value adjustments to the non-derivative financial instruments.

Available-for-sale assets summary The following tables summarize additional information about the Company's restricted investments that are classified as available-for-sale assets:

March 31, 2019 December 31, 2018 LMCI restricted Other restricted LMCI restricted Other restricted (unaudited - millions of Canadian $) investments investments1 investments investments1 Fair values of fixed income securities2 Maturing within 1 year — 24 — 22 Maturing within 1-5 years — 94 — 110 Maturing within 5-10 years 156 — 140 — Maturing after 10 years 1,053 — 952 — 1,209 118 1,092 132

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 Condensed consolidated balance sheet. TRANSCANADA PIPELINES LIMITED [21 FIRST QUARTER 2019

March 31, 2019 March 31, 2018 LMCI restricted Other restricted LMCI restricted Other restricted (unaudited - millions of Canadian $) investments1 investments2 investments1 investments2 Net unrealized gains in the period three months ended 51 1 2 1

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 Gains and losses on other restricted investments are included in Interest income and other on the Condensed consolidated statement of income.

Derivative instruments

Fair value of derivative instruments The fair value of foreign exchange and interest rate derivatives has been calculated using the income approach which uses period-end market rates and applies a discounted cash flow valuation model. The fair value of commodity derivatives has been calculated using quoted market prices where available. In the absence of quoted market prices, third-party broker quotes or other valuation techniques have been used. The fair value of options has been calculated using the Black-Scholes pricing model. Credit risk has been taken into consideration when calculating the fair value of derivative instruments. Unrealized gains and losses on derivative instruments are not necessarily representative of the amounts that will be realized on settlement. In some cases, even though the derivatives are considered to be effective economic hedges, they do not meet the specific criteria for hedge accounting treatment or are not designated as a hedge and are accounted for at fair value with changes in fair value recorded in net income in the period of change. This may expose the Company to increased variability in reported earnings because the fair value of the derivative instruments can fluctuate significantly from period to period. TRANSCANADA PIPELINES LIMITED [22 FIRST QUARTER 2019

Balance sheet presentation of derivative instruments The balance sheet classification of the fair value of derivative instruments is as follows:

Total Fair at March 31, 2019 Net Value of Cash Flow Fair Value Investment Held for Derivative (unaudited - millions of Canadian $) Hedges Hedges Hedges Trading Instruments1

Other current assets Commodities2 — — — 294 294 Foreign exchange — — 14 3 17 Interest rate 2 — — — 2 2 — 14 297 313 Intangible and other assets Commodities2 — — — 28 28 Foreign exchange — — 1 — 1 Interest rate 4 2 — — 6 4 2 1 28 35 Total Derivative Assets 6 2 15 325 348 Accounts payable and other Commodities2 (4) — — (273) (277) Foreign exchange — — (39) (71) (110) Interest rate — (2) — — (2) (4) (2) (39) (344) (389) Other long-term liabilities Commodities2 (1) — — (23) (24) Foreign exchange — — (1) — (1) Interest rate (24) — — — (24) (25) — (1) (23) (49) Total Derivative Liabilities (29) (2) (40) (367) (438) Total Derivatives (23) — (25) (42) (90)

1 Fair value equals carrying value. 2 Includes purchases and sales of power, natural gas and liquids. TRANSCANADA PIPELINES LIMITED [23 FIRST QUARTER 2019

Total Fair Net at December 31, 2018 Value of Cash Flow Fair Value Investment Held for Derivative (unaudited - millions of Canadian $) Hedges Hedges Hedges Trading Instruments1

Other current assets Commodities2 1 — — 716 717 Foreign exchange — — 16 1 17 Interest rate 3 — — — 3 4 — 16 717 737 Intangible and other assets Commodities2 1 — — 50 51 Foreign exchange — — 1 — 1 Interest rate 8 1 — — 9 9 1 1 50 61 Total Derivative Assets 13 1 17 767 798 Accounts payable and other Commodities2 (4) — — (622) (626) Foreign exchange — — (105) (188) (293) Interest rate — (3) — — (3) (4) (3) (105) (810) (922) Other long-term liabilities Commodities2 — — — (28) (28) Foreign exchange — — (2) — (2) Interest rate (11) (1) — — (12) (11) (1) (2) (28) (42) Total Derivative Liabilities (15) (4) (107) (838) (964) Total Derivatives (2) (3) (90) (71) (166)

1 Fair value equals carrying value. 2 Includes purchases and sales of power, natural gas and liquids.

The majority of derivative instruments held for trading have been entered into for risk management purposes and all are subject to the Company's risk management strategies, policies and limits. These include derivatives that have not been designated as hedges or do not qualify for hedge accounting treatment but have been entered into as economic hedges to manage the Company's exposures to market risk.

Derivatives in fair value hedging relationships The following table details amounts recorded on the Condensed consolidated balance sheet in relation to cumulative adjustments for fair value hedges included in the carrying amount of the hedged liabilities:

Carrying amount Fair value hedging adjustments1 (unaudited - millions of Canadian $) March 31, 2019 December 31, 2018 March 31, 2019 December 31, 2018 Current portion of long-term debt (332) (748) 2 3 Long-term debt (269) (273) (2) — (601) (1,021) — 3

1 At March 31, 2019 and December 31, 2018, adjustments for discontinued hedging relationships included in these balances were nil. TRANSCANADA PIPELINES LIMITED [24 FIRST QUARTER 2019

Notional and Maturity Summary The maturity and notional amount or quantity outstanding related to the Company's derivative instruments excluding hedges of the net investment in foreign operations is as follows:

at March 31, 2019 Natural Foreign Interest (unaudited) Power Gas Liquids Exchange Rate

Purchases1 17,374 34 63 — — Sales1 14,243 43 82 — — Millions of U.S. dollars — — — 3,900 1,400 Maturity dates 2019-2024 2019-2027 2019-2020 2019-2020 2019-2030

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

at December 31, 2018 Natural Foreign Interest (unaudited) Power Gas Liquids Exchange Rate

Purchases1 23,865 44 59 — — Sales1 17,689 56 79 — — Millions of U.S. dollars — — — 3,862 1,650 Maturity dates 2019-2023 2019-2027 2019 2019 2019-2030

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

Unrealized and realized (losses)/gains on derivative instruments The following summary does not include hedges of the net investment in foreign operations.

three months ended March 31 (unaudited - millions of Canadian $) 2019 2018

Derivative Instruments Held for Trading1 Amount of unrealized (losses)/gains in the period Commodities2 (88) (109) Foreign exchange 120 (79) Amount of realized gains/(losses) in the period Commodities 107 110 Foreign exchange (29) 15 Derivative Instruments in Hedging Relationships Amount of realized (losses)/gains in the period Commodities (7) 3 Interest rate — 1

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 the three months ended March 31, 2019 and 2018, 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. TRANSCANADA PIPELINES LIMITED [25 FIRST QUARTER 2019

Derivatives in cash flow hedging relationships The components of OCI (Note 10) related to the change in fair value of derivatives in cash flow hedging relationships before tax and including the portion attributable to non-controlling interests are as follows:

three months ended March 31 (unaudited - millions of Canadian $) 2019 2018

Change in fair value of derivative instruments recognized in OCI (effective portion)1 Commodities (3) (3) Interest rate (19) 9 (22) 6

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

Effect of fair value and cash flow hedging relationships The following table details amounts presented on the Condensed consolidated statement of income in which the effects of fair value or cash flow hedging relationships are recorded.

three months ended March 31 Revenues (Power and Storage) Interest Expense (unaudited - millions of Canadian $) 2019 2018 2019 2018 Total Amount Presented in the Condensed Consolidated Statement of Income 336 675 (621) (548) Fair Value Hedges Interest rate contracts Hedged items — — (6) (20) Derivatives designated as hedging instruments — — (1) — Cash Flow Hedges Reclassification of gains/(losses) on derivative instruments from AOCI to net income1, 2 Interest rate contracts — — 4 5 Commodity contracts — (1) — —

1 Refer to Note 10, Other comprehensive (loss)/income 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. TRANSCANADA PIPELINES LIMITED [26 FIRST QUARTER 2019

Offsetting of derivative instruments The Company enters into derivative contracts with the right to offset in the normal course of business as well as in the event of default. TCPL has no master netting agreements, however, similar contracts are entered into containing rights to offset. The Company has elected to present the fair value of derivative instruments with the right to offset on a gross basis in the Condensed consolidated balance sheet. The following table shows the impact on the presentation of the fair value of derivative instrument assets and liabilities had the Company elected to present these contracts on a net basis: at March 31, 2019 Gross derivative Amounts available (unaudited - millions of Canadian $) instruments for offset1 Net amounts

Derivative instrument assets Commodities 322 (267) 55 Foreign exchange 18 (18) — Interest rate 8 (3) 5 348 (288) 60 Derivative instrument liabilities Commodities (301) 267 (34) Foreign exchange (111) 18 (93) Interest rate (26) 3 (23) (438) 288 (150)

1 Amounts available for offset do not include cash collateral pledged or received. at December 31, 2018 Gross derivative Amounts available (unaudited - millions of Canadian $) instruments for offset1 Net amounts

Derivative instrument assets Commodities 768 (626) 142 Foreign exchange 18 (18) — Interest rate 12 (4) 8 798 (648) 150 Derivative instrument liabilities Commodities (654) 626 (28) Foreign exchange (295) 18 (277) Interest rate (15) 4 (11) (964) 648 (316)

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

With respect to the derivative instruments presented above, the Company provided cash collateral of $118 million and letters of credit of $37 million as at March 31, 2019 (December 31, 2018 – $143 million and $22 million) to its counterparties. At March 31, 2019, the Company held no cash collateral and $1 million in letters of credit (December 31, 2018 – nil and $1 million) from counterparties on asset exposures. TRANSCANADA PIPELINES LIMITED [27 FIRST QUARTER 2019

Credit-risk-related contingent features of derivative instruments Derivative contracts entered into to manage market risk often contain financial assurance provisions that allow parties to the contracts to manage credit risk. These provisions may require collateral to be provided if a credit-risk-related contingent event occurs, such as a downgrade in the Company’s credit rating to non-investment grade. The Company may also need to provide collateral if the fair value of its derivative financial instruments exceeds pre-defined exposure limits. Based on contracts in place and market prices at March 31, 2019, the aggregate fair value of all derivative instruments with credit-risk-related contingent features that were in a net liability position was $4 million (December 31, 2018 – $6 million), for which the Company has provided no collateral in the normal course of business. If the credit-risk-related contingent features in these agreements were triggered on March 31, 2019, the Company would have been required to provide collateral of $4 million (December 31, 2018 – $6 million) to its counterparties. Collateral may also need to be provided should the fair value of derivative instruments exceed pre-defined contractual exposure limit thresholds. The Company has sufficient liquidity in the form of cash and undrawn committed revolving credit facilities to meet these contingent obligations should they arise.

FAIR VALUE HIERARCHY The Company’s financial assets and liabilities recorded at fair value have been categorized into three categories based on a fair value hierarchy.

Levels How fair value has been determined Level I Quoted prices in active markets for identical assets and liabilities that the Company has the ability to access at the measurement date. An active market is a market in which frequency and volume of transactions provides pricing information on an ongoing basis. Level II This category includes interest rate and foreign exchange derivative assets and liabilities where fair value is determined using the income approach and commodity derivatives where fair value is determined using the market approach.

Inputs include published exchange rates, interest rates, interest rate swap curves, yield curves and broker quotes from external data service providers. Level III This category mainly includes long-dated commodity transactions in certain markets where liquidity is low and the Company uses the most observable inputs available or, if not available, long-term broker quotes to estimate the fair value for these transactions.

There is uncertainty caused by using unobservable market data which may not accurately reflect possible future changes in fair value. TRANSCANADA PIPELINES LIMITED [28 FIRST QUARTER 2019

The fair value of the Company’s derivative assets and liabilities measured on a recurring basis, including both current and non-current portions are categorized as follows:

Significant Quoted prices in Significant other unobservable at March 31, 2019 active markets observable inputs inputs (unaudited - millions of Canadian $) (Level I) (Level II)1 (Level III)1 Total Derivative instrument assets Commodities 235 86 1 322 Foreign exchange — 18 — 18 Interest rate — 8 — 8 Derivative instrument liabilities Commodities (229) (67) (5) (301) Foreign exchange — (111) — (111) Interest rate — (26) — (26) 6 (92) (4) (90)

1 There were no transfers from Level II to Level III for the three months ended March 31, 2019.

Significant Quoted prices in Significant other unobservable at December 31, 2018 active markets observable inputs inputs 1 1 (unaudited - millions of Canadian $) (Level I) (Level II) (Level III) Total Derivative instrument assets Commodities 581 187 — 768 Foreign exchange — 18 — 18 Interest rate — 12 — 12 Derivative instrument liabilities Commodities (555) (95) (4) (654) Foreign exchange — (295) — (295) Interest rate — (15) — (15) 26 (188) (4) (166)

1 There were no transfers from Level II to Level III for the year ended December 31, 2018.

The following table presents the net change in fair value of derivative assets and liabilities classified as Level III of the fair value hierarchy:

three months ended March 31 (unaudited - millions of Canadian $) 2019 2018 Balance at beginning of period (4) (7) Total losses included in Net income — (2) Settlements — (9) Balance at end of period1 (4) (18)

1 For the three months ended March 31, 2019, Revenues included unrealized gains of less than $1 million attributed to derivatives in the Level III category that were still held at March 31, 2019 (2018 – unrealized losses of $11 million). TRANSCANADA PIPELINES LIMITED [29 FIRST QUARTER 2019

13. Contingencies and guarantees

CONTINGENCIES TCPL and its subsidiaries are subject to various legal proceedings, arbitrations and actions arising in the normal course of business. While the final outcome of such legal proceedings and actions cannot be predicted with certainty, it is the opinion of management that the resolution of such proceedings and actions will not have a material impact on the Company’s consolidated financial position or results of operations.

GUARANTEES TCPL and its partner on the Sur de Texas pipeline, IEnova, have jointly guaranteed the financial performance of this entity. Such agreements include a guarantee and a letter of credit which are primarily related to construction services and the delivery of natural gas. TCPL and its joint venture partner on Bruce Power, BPC Generation Infrastructure Trust, have each severally guaranteed certain contingent financial obligations of Bruce Power related to a lease agreement and contractor and supplier services. The Company and its partners in certain other jointly owned entities have either (i) jointly and severally, (ii) jointly or (iii) severally guaranteed the financial performance of these entities. Such agreements include guarantees and letters of credit which are primarily related to delivery of natural gas, construction services and the payment of liabilities. For certain of these entities, any payments made by TCPL under these guarantees in excess of its ownership interest are to be reimbursed by its partners. The carrying value of these guarantees has been included in Other long-term liabilities on the Condensed consolidated balance sheet. Information regarding the Company’s guarantees is as follows:

at March 31, 2019 at December 31, 2018 Potential Carrying Potential Carrying (unaudited - millions of Canadian $) Term exposure1 value exposure1 value Sur de Texas ranging to 2020 174 1 183 1 Bruce Power ranging to 2021 88 — 88 — Other jointly-owned entities ranging to 2059 102 11 104 11 364 12 375 12

1 TCPL’s share of the potential estimated current or contingent exposure. 14. Related party transactions

Related party transactions are conducted in the normal course of business and are measured at the exchange amount, which is the amount of consideration established and agreed to by the related parties.

The following amounts are included in Due to affiliate:

2019 2018 Outstanding Effective Outstanding Effective (millions of Canadian $) Maturity Date March 31 Interest Rate December 31 Interest Rate

Credit Facility1 Demand 3,677 3.95% 3,617 3.95%

1 TCPL has an unsecured $4.5 billion credit facility with TransCanada. Interest on this facility is charged at the prime rate per annum. TRANSCANADA PIPELINES LIMITED [30 FIRST QUARTER 2019

In the three months ended March 31, 2019, Interest expense included $35 million of interest charges as a result of inter-affiliate borrowing (March 31, 2018 – $21 million). At March 31, 2019, Accounts payable and other included $7 million due to TransCanada (December 31, 2018 – $19 million). In the three months ended March 31, 2019, the Company made interest payments of $36 million to TransCanada (March 31, 2018 – $21 million). 15. Variable interest entities

A VIE is a legal entity that does not have sufficient equity at risk to finance its activities without additional subordinated financial support or is structured such that equity investors lack the ability to make significant decisions relating to the entity’s operations through voting rights or do not substantively participate in the gains and losses of the entity. In the normal course of business, the Company consolidates VIEs in which it has a variable interest and for which it is considered to be the primary beneficiary. VIEs in which the Company has a variable interest but is not the primary beneficiary are considered non-consolidated VIEs and are accounted for as equity investments.

Consolidated VIEs The Company's consolidated VIEs consist of legal entities where the Company is the primary beneficiary. As the primary beneficiary, the Company has the power, through voting or similar rights, to direct the activities of the VIE that most significantly impact economic performance including purchasing or selling significant assets; maintenance and operations of assets; incurring additional indebtedness; or determining the strategic operating direction of the entity. In addition, the Company has the obligation to absorb losses or the right to receive benefits from the consolidated VIE that could potentially be significant to the VIE. A significant portion of the Company’s assets are held through VIEs in which the Company holds a 100 per cent voting interest, the VIE meets the definition of a business and the VIE’s assets can be used for general corporate purposes. The Consolidated VIEs whose assets cannot be used for purposes other than the settlement of the VIE’s obligations are as follows: TRANSCANADA PIPELINES LIMITED [31 FIRST QUARTER 2019

March 31, December 31, (unaudited - millions of Canadian $) 2019 2018

ASSETS Current Assets Cash and cash equivalents 69 45 Accounts receivable 69 79 Inventories 26 24 Other 9 13 173 161 Plant, Property and Equipment 2,949 3,026 Equity Investments 847 965 Goodwill 444 453 Intangible and Other Assets 3 8 4,416 4,613 LIABILITIES Current Liabilities Accounts payable and other 79 88 Accrued interest 31 24 Current portion of long-term debt 76 79 186 191 Regulatory Liabilities 42 43 Other Long-Term Liabilities 4 3 Deferred Income Tax Liabilities 12 13 Long-Term Debt 3,003 3,125 3,247 3,375

Non-Consolidated VIEs The Company’s non-consolidated VIEs consist of legal entities where the Company is not the primary beneficiary as it does not have the power to direct the activities that most significantly impact the economic performance of these VIEs or where this power is shared with third parties. The Company contributes capital to these VIEs and receives ownership interests that provide it with residual claims on assets after liabilities are paid. The carrying value of these VIEs and the maximum exposure to loss as a result of the Company's involvement with these VIEs are as follows:

March 31, December 31, (unaudited - millions of Canadian $) 2019 2018 Balance sheet Equity investments 4,487 4,575 Off-balance sheet Potential exposure to guarantees 168 170 Maximum exposure to loss 4,655 4,745 TRANSCANADA PIPELINES LIMITED [32 FIRST QUARTER 2019

16. Subsequent Event

Long-term debt issuance On April 10, 2019, TCPL issued $1.0 billion of Medium Term Notes, due in October 2049, bearing interest at a fixed rate of 4.34 per cent. Great Lakes Pipeline Canada Ltd. Financial Resources Plan Appendix 5

TransCanada Credit Ratings Reports INFRASTRUCTURE AND PROJECT FINANCE

CREDIT OPINION TransCanada PipeLines Limited 5 April 2019 Update following downgrade to Baa1; outlook changed to Update stable Summary TransCanada PipeLines Limited's (TCPL) credit profile is driven by its predictable and growing cash flow, owing to the regulated and contracted nature of its businesses, and its large size and portfolio diversification benefits. Cash flow is typically underpinned by either cost of RATINGS service regulation or long term contracts. Offsetting these strengths are weak financial TransCanada PipeLines Limited metrics and a large CAD36 billion capital program that has experienced execution challenges. Domicile Alberta, Canada This has led to delays in EBITDA growth and some cost overruns. Long Term Rating Baa1 Type LT Issuer Rating Moody’s sees financial metrics improving as the company continues to execute this capital Outlook Stable program over the period 2019-2023, which we expect to be primarily funded with cash

Please see the ratings section at the end of this report flow from operations, assets sales, equity, hybrids and some incremental debt. TCPL’s rating for more information. The ratings and outlook shown incorporates our expectation that EBITDA will grow towards CAD10 billion over this period reflect information as of the publication date. from CAD8.9 billion in 2018, that debt will remain close to CAD50 billion, and that debt to EBITDA will improve from 5.6x in 2018 to about 5x in 2019.

Contacts Our forecasts exclude about CAD20 billion of projects that have not yet been fully Gavin Macfarlane +1.416.214.3864 committed, most notably Keystone XL, and have risks that either make construction VP-Sr Credit Officer uncertain or have a long term spending profile. Large projects like Keystone XL could place [email protected] pressure on financial metrics during construction. Lesley Ritter +1.212.553.1607 AVP-Analyst Exhibit 1 [email protected] Historical Total Debt, EBITDA and Total Debt to EBITDA (CAD Million)

Jim Hempstead +1.212.553.4318 Total Debt EBITDA Debt / EBITDA Downgrade trigger Upgrade trigger $60,000 7.0x

MD-Utilities 6.6x [email protected] 6.0x $49,820 6.0x $50,000 5.8x $46,267 5.6x 5.4x Yulia Rakityanskaya +1.416.214.3627 $43,159 5.0x Associate Analyst $40,000

$36,780 [email protected] 4.0x $30,622 $30,000 CLIENT SERVICES 3.0x

$20,000 Americas 1-212-553-1653 2.0x

$8,923 $10,000 $7,491 Asia Pacific 852-3551-3077 $6,991 1.0x $5,645 $6,107 Japan 81-3-5408-4100 $- 0.0x Dec-14 Dec-15 Dec-16 Dec-17 Dec-18 EMEA 44-20-7772-5454 Based on consolidated financial data of TransCanada Corporation. Source: Moody's Financial Metrics™ MOODY'S INVESTORS SERVICE INFRASTRUCTURE AND PROJECT FINANCE

Credit Strengths » Scale of the company provides financial and operating flexibility

» Portfolio diversification benefits reduce the volatility of the company's overall performance

» Low business risk drives predictable and growing EBITDA

Credit Challenges » Large capital program that has experienced execution challenges

» Weak financial metrics that we expect to improve

» Moderate carbon transition risk

Rating Outlook TCPL’s stable outlook reflects Moody’s expectation that debt to EBITDA will be about 5x in 2019. The stable outlook does not reflect any incremental growth capital projects, including the proposed Keystone XL pipeline. The stable outlook of parent TransCanada, and affiliates NGTL and TransCanada Trust reflects either guarantees or strategic relationships with TCPL. Moody’s has revised the financial metrics it associates with TCPL following the downgrade to reflect changes in its credit profile. Factors that Could Lead to an Upgrade A rating upgrade would require the successful completion of the capital program and a ratio of debt to EBITDA below 4.5x on a sustained basis. Factors that Could Lead to a Downgrade TCPL’s ratings could be downgraded if leverage remains at or above 5.5x. The rating could also be downgraded if there are material changes or additions to the capital program; if the company experiences increased cash flow variability in its core businesses or if the company changes its financial policies. Key Indicators

Exhibit 2 TransCanada PipeLines Limited [1] Dec-14 Dec-15 Dec-16 Dec-17 Dec-18 Net Property Plant and Equipment (USD Million) 36,827 32,866 41,154 46,101 49,038 EBITDA (USD Million) 5,114 4,785 5,279 5,777 6,888 EBITDA / Interest Expense 3.7x 3.6x 3.2x 3.4x 3.8x Debt / EBITDA 5.4x 6.0x 6.6x 5.8x 5.6x (FFO - Maintenance CAPEX) / Distributions 2.0x 2.0x 1.9x 2.1x 3.2x

[1] Based on consolidated financial data of TransCanada Corporation. All ratios are based on 'Adjusted' financial data and incorporate Moody's Global Standard Adjustments for Non- Financial Corporations. Source: Moody's Financial Metrics™

Profile TCPL is the principal subsidiary and debt issuer of TransCanada, headquartered in Calgary, Alberta. TransCanada is an energy infrastructure company with three business segments: Natural Gas Pipelines (70% of 2018 EBITDA including regulated gas storage of 535 Bcf), Liquids Pipelines (21% of 2018 EBITDA), and Energy (9% of 2018 EBITDA including unregulated gas storage of 118 Bcf). TCPL is the General Partner of and owner of a 25.5% interest in TC PipeLines, LP (TCP: Baa2 stable), a publicly traded master limited partnership (MLP) that owns a portfolio of TransCanada's US interstate gas pipelines.

This publication does not announce a credit rating action. For any credit ratings referenced in this publication, please see the ratings tab on the issuer/entity page on www.moodys.com for the most updated credit rating action information and rating history.

2 5 April 2019 TransCanada PipeLines Limited: Update following downgrade to Baa1; outlook changed to stable MOODY'S INVESTORS SERVICE INFRASTRUCTURE AND PROJECT FINANCE

Exhibit 3 Exhibit 4 TransCanada Corporation's 2018 Comparable EBITDA by segment TransCanada's rated subsidiaries

% of 2018 Comparable Subsidiary Rating EBITDA Segment Nova Gas Transmission Ltd Baa1/Stable 14% Canadian Natural Gas Pipelines Gas Transmission Northwest LLC A3/Stable 3% U.S. Natural Gas Pipelines Energy ANR Pipeline Company A3/Stable 8% U.S. Natural Gas Pipelines 9% Canadian TC PipeLines, LP Baa2/Stable 6% U.S. Natural Gas Pipelines Natural Gas Columbia Pipeline Group, Inc. Baa1/Positive 17% U.S. Natural Gas Pipelines Pipelines Iroquois Gas Transmission System, L.P. [1] A3/Stable 1% U.S. Natural Gas Pipelines 28% Bruce Power L.P. [1] Baa2/Stable 4% Energy TransCanada Trust Baa3/Stable 0% Corporate TransCanada American Inv. Ltd. P-2 0% Corporate TransCanada PipeLine USA Ltd P-2 0% Corporate Liquids Pipelines 21% [1] % of EBITDA was calculated based on Income/(Loss) from Equity Investments from the respective entity Source: Moody's Investors Service, TransCanada Corporation's 2018 annual report

Mexico Natural Gas Pipelines U.S. Natural Gas 7% Pipelines 35%

Source: TransCanada Corporation's 2018 annual report

Detailed Credit Considerations Scale and portfolio diversification benefits Substantial financial resources with last twelve months adjusted EBITDA of about CAD8.5 billion, economies of scale from its large and diverse asset base with CAD67 billion of net property, plant and equipment, and strong market access all support current credit quality. Portfolio diversification by geography, business line and counterparty reduces overall cash flow volatility, a key credit strength. While some assets may have moderate levels of correlation, substantial portions of the portfolio are uncorrelated due to the specific business line fundamentals.

Predictable and growing cash flow Cash flow from low business risk assets that are primarily regulated or contracted provides a high degree of certainty, a key credit strength. The regulated NGTL system will continue to expand its rate base of CAD10 billion at FYE 2018, compared to less than CAD4 billion currently for the Mainline. These pipelines are expected to generate stable and growing returns driven by ongoing rate base investments. We expect that a cost of service framework, supported by contracts and a favorable competitive position, will enable the Mainline to continue to earn its allowed ROE. US pipeline earnings should continue to grow with significant investments in the Columbia Pipeline Group driving earnings growth. The US gas pipeline segment generally benefits from a mix of contracts and a strong underlying competitive position. While small, the Mexican gas business is expected to continue to grow and it is not immune to execution risk as evidenced by delays on several projects. Despite these construction delays, the company is receiving payments, highlighting both challenges in completing pipelines and the strong contractual profile often associated with TransCanada's projects.

The liquids segment, currently dominated by the Keystone Base system, is expected to provide relatively stable cash flow until the end of the 20 year contracts in 2030. Key contract terms that support our assumption of stable cash flow generation are the take or pay nature of the contracts covering more than 90%, or 555kbpd, of the 590kbpd pipeline capacity. TCPL is not exposed to underlying commodity prices and key variable costs including power, property taxes and maintenance are flow through costs to shippers. At the end of the contract term TCPL will have fully recovered the capital costs of its initial investment. However the smaller, marketlink portion of the liquids system has short term contracts and more exposure to volume risk. The company was successfully able to monetize capacity driving more than a CAD200 million increase in EBITDA in 2018. The business risk profile of the energy segment has improved significantly over the past several years with the sale and turnback of riskier assets. The remaining power assets are largely contracted. The company has moderate exposure to carbon transition risk that does not have a meaningful impact on operating assets, however they do contribute to an increasingly challenging framework for the development of new projects.

3 5 April 2019 TransCanada PipeLines Limited: Update following downgrade to Baa1; outlook changed to stable MOODY'S INVESTORS SERVICE INFRASTRUCTURE AND PROJECT FINANCE

Large capital program has experienced execution challenges The company continues to move forward with its large capital program that supports the company's low business risk profile. The large slate of secured capital projects total about CAD36 billion over the period 2019-2023, of which CAD13 billion has already been spent. These figures are inflated by projects that were originally expected to be placed in service in 2018.

Of the remaining capital expenditure, more than half consists of lower risk NGTL, maintenance modernization and other capacity capital that generally have a lower execution risk profile. Other projects have more execution risk, including the Bruce nuclear refurbishment (CAD2.2 billion), Coastal Gaslink (CAD6.2 billion) and the in-service of three Mexican natural gas pipeline assets (USD3 billion).

Exhibit 5 TransCanada Corporation's Near-term capital projects as of 31 December 2018

Carrying value at (unaudited - billions of CAD) Expected in-service date Estimated project cost December 31, 2018 Canadian Natural Gas Pipelines Canadian Mainline 2019 - 2021 0.3 - NGTL System 2019 2.8 1.4 2020 1.7 0.2 2021 2.8 - 2022 1.3 - Coastal GasLink 2023 6.2 0.1 Regulated maintenance capital expenditures 2019 - 2021 1.8 - U.S. Natural Gas Pipelines Columbia Gas Mountaineer XPress 2019 US 3.2 US 2.9 Modernization II 2019 - 2020 US 1.1 US 0.5 Columbia Gulf Gulf XPress 2019 US 0.6 US 0.5 Other capacity capital 2019 - 2022 US 0.9 US 0.1 Regulated maintenance capital expenditures 2019 - 2021 US 2.0 - Mexico Natural Gas Pipelines Sur de Texas 2019 US 1.5 US 1.4 Villa de Reyes 2019 US 0.8 US 0.6 Tula 2020 US 0.7 US 0.6 Liquids Pipelines White Spruce 2019 0.2 0.1 Other capacity capital 2020 0.1 - Recoverable maintenance capital expenditures 2019 - 2021 0.1 - Energy Napanee 2019 1.7 1.6 Bruce Power – life extension 2019 - 2023 2.2 0.6 Other Non- recoverable maintenance capital expenditures 2019 - 2021 0.7 0.2 32.7 10.8 Foreign exchange impact on secured projects 3.9 2.4 Total near-term projects (billions of CAD) 36.6 13.2

Reflects U.S./Canada foreign exchange rate of 1.36 at December 31, 2018. Source: TransCanada Corporation's 2018 annual report

We have not included in our forecasts about CAD20 billion of projects under development that either do not have a clear path to execution or have an investment horizon beyond 2023. Accounting for about half of the total is the very high profile Keystone XL (KXL) pipeline project. This project, similar to other large infrastructure projects, is exposed to very high levels of environmental, social and governance (ESG) risks that makes the ultimate in-service prospects of the project uncertain. Large projects like it may be harder to

4 5 April 2019 TransCanada PipeLines Limited: Update following downgrade to Baa1; outlook changed to stable MOODY'S INVESTORS SERVICE INFRASTRUCTURE AND PROJECT FINANCE

execute on time and within budget and will put pressure on key financial metrics during construction, both negatives for credit quality. KXL continues to make progress, and received a new presidential permit on 29 March 2019 that may mitigate challenges the project has faced in Montana. The next significant step could be a decision from the Nebraska Supreme Court, on an appeal of the Nebraska PSC route approval as the only significant legal/regulatory challenge to the pipeline outstanding. The decision appears likely early in the second quarter of 2019.

The company has been challenged to execute its capital program. In March of 2018, the company expected to complete discrete projects totaling about CAD10 billion during the remainder of 2018 that would contribute EBITDA. However, only CAD2 billion of those projects were fully complete and in service contributing EBITDA in 2018. The CAD10 billion of projects had cost-overruns of 15-20%. These projects were generally smaller projects with a lower profile that we would generally have expected to be completed on time and budget. The rationale for the projects delays and overruns vary, but clearly the company has been challenged to execute its capital program. The company is receiving payments on all of its Mexican assets under terms of the contracts. However because Force Majeure has been declared on these 3 projects and the assets are not yet in service the payments will not be reflected in revenue and EBITDA until the assets are placed into service. Cost recovery provisions, if any, vary among the projects and are often reflected as higher tolls.

Exhibit 6 2018 Discrete projects forecast to be completed as of March 2018

March 2018 Estimated cost expected in (bn) as of March Estimated cost service date 2018 (bn) FYE 2018 Currency Full in service date of assets NGTL System 2018 0.6 0.6 CAD on time

Columbia Gas WB Express 2018 0.8 0.9 USD Q4 2018 Mountaineer Express 2018 2.6 3.2 USD Mar-19 Cameron Access 2018 0.3 0.3 USD Q1 2018 Gulf Express 2018 0.6 0.6 USD Mar-19

Mexico Sur de Texas 2018 1.3 1.5 USD Q2 2019 Villa de Reyes 2018 0.6 0.8 USD 2019 Tula 2019 0.7 0.7 USD 2020

Energy Napanee Q4 2018 1.3 1.7 CAD Q2 2019

Discrete projects expected to be completed in 2018 (as 10.3 12.2 of March 2018)

Projects fully completed and contributing to EBITDA in 2.1 2018 For simplicity this assumes a constant FX rate of 1.3 Source: Moody's Investors Service, TransCanada Corporation

Weak financial metrics expected to improve Financial metrics are currently weak with a ratio of Debt/EBITDA of 5.6x at FYE 2018, above our previous expectations for year-end and above the revised downgrade threshold of 5.5x. Our analysis incorporates our expectation that Debt/EBITDA will improve to about 5x in 2019. Adjusting to eliminate EBITDA associated with the CAD630 milllion sale of Cartier wind in October of 2018 has a negligible impact on financial metrics.

We expect projects going into service to drive transparent increases in EBITDA over the next few years. Moody’s has assumed that the majority of the capital program is funded with cash from operations and equity in the form of a DRIP or further hybrid issuance, assets sales (including joint ventures) and some incremental debt financing. Key variables that could change our forecasts include a positive final investment decision on KXL, material assets sales, clarity on financing for Coastal Gaslink and new additions to the capital program. The company has indicated that they have identified CAD500 million of EBITDA generating assets that could be sold to support the balance sheet, however currently only the sale of the Coolidge Generating Station for US465 million has been announced

5 5 April 2019 TransCanada PipeLines Limited: Update following downgrade to Baa1; outlook changed to stable MOODY'S INVESTORS SERVICE INFRASTRUCTURE AND PROJECT FINANCE

and is expected to close in mid-2019. Our analysis also incorporates some foreign exchange movements that had a negative impact on financial metrics at FYE 2018.

In our forward calculations of maintenance capex we have assumed maintenance capex of CAD1.7 billion. This figure includes both recoverable and non-recoverable capex, while the company reported only non-recoverable capex of CAD254 million for FYE 2018 which is reflected in FYE 2018 calculations. Inclusive of the DRIP, our distribution metric declines to 1.7x from 2.5x and declines further to 1.5x when using depreciation instead of maintenance capex. We consider these other metrics and place greater emphasis on these other metrics in the future. Directionally, distribution coverage metrics are expected to decline, leading to less financial metric flexibility on a forecast basis. Prior to 2018 the company reported both non-recoverable and recoverable maintenance capex and the change led to the significant improvement in the distribution coverage metric in 2018.

Moderate exposure to carbon transition risk We view the midstream sector, including TCPL, as having moderate risk exposure to carbon transition risks. TCPL’s exposure is indirect as change in commodity prices affect its shippers, which may then have an impact on volumes through its systems and counterparty risks. A key issue for the sector is that regulations can drive competitive changes among basins. TCPL is somewhat insulated from this issue as a result of its diversification.

Structural considerations TCPL is the sole source of funds to support hybrids at TransCanada, and as such we include these hybrids (CAD2.5 billion) in our consolidated financial analysis of TCPL. We do not notch TCPL down for structural subordination and complexity given the relatively straightforward organizational structure and structural subordination that is partially offset by unlevered assets, assets with low levels of leverage and diversity. However the company does plan to increase its complexity and structural subordination with, for example, the planned sell-down of its 100% interest and subsequent project finance of Coastal Gaslink and plans to issue incremental new debt at the Columbia Pipeline Group (Baa1 positive) in the next few years. These actions may lead us to reassess our view of structural subordination and lead us to emphasize a proportionately consolidated approach to financial metrics. At FYE 2018 proportionately consolidated debt/EBITDA was very similar to consolidated debt/EBITDA.

TransCanada’s Baa2 Issuer Rating reflects a 1-notch adjustment below the rating of TCPL as a result of its structural subordination to TCPL. The rated obligations of TransCanada Trust, TransCanada Pipelines USA Ltd (TCPL USA) and TransCanada American Investments Ltd reflect a guarantee provided by TCPL. The TransCanada Trust Baa3 rating is two notches lower than TCPL’s Baa1 senior unsecured rating and is consistent with a 2-notch differential we apply to preferred shares with investment grade companies. The TransCanada Trust notes are guaranteed by TCPL on a subordinated basis however the TransCanada Trust notes have an automatic exchange provision that converts the notes into preferred shares of TCPL in the event of financial distress. The Prime-2 short-term commercial paper rating for TCPL USA and TransCanada American Investments Ltd reflects the guarantee provided by TCPL. NGTL’s rating is strongly correlated with that of TCPL based on its strategic importance and TCPL’s position as a key creditor. Liquidity Analysis TransCanada currently has an adequate liquidity profile; however, its current committed sources of alternate liquidity are modest relative to its capital program and the company relies in part on a short-term facility that must be renewed annually. This liquidity arrangement is based on the company's continued ability to extend its expiring 364-day facility and refinance its upcoming debt maturities, which is a liquidity weakness. For example, TransCanada has a US$4.5 billion credit facility expiring at the end of 2019. The company has historically not experienced difficulty in extending its facilities and we believe that it continues to have strong access to the capital markets a key consideration in our adequate assessment of the company's liquidity profile.

At the end of December 2018, TransCanada reported cash on hand of CAD 446 million. In 2018, the company generated negative free cash flow of CAD 5.3 billion as a result of CFO of CAD6.6 billion, capital expenses of CAD9.9 billion, and dividends of CAD2 billion (all figures are Moody's adjusted). In accordance with the reference above, TransCanada continues to have a large slate of secured capital projects totaling about CAD36 billion over the period 2019-2023.

At 11 February 2019, TransCanada had CAD10.5 billion (CAD10.5 billion of unused capacity) of committed revolving credit facilities.

6 5 April 2019 TransCanada PipeLines Limited: Update following downgrade to Baa1; outlook changed to stable MOODY'S INVESTORS SERVICE INFRASTRUCTURE AND PROJECT FINANCE

Exhibit 7 Available committed revolving credit facilities as of 11 February 2019

Borrower Amount Unused capacity Description Matures TCPL CAD3.0 billion CAD3.0 billion Supports TCPL's Canadian dollar commercial paper program and December 2023 is used for general corporate purposes TCPL/TCPL US$4.5 billion US$4.5 billion Supports TCPL and TCPL USA's U.S. dollar commercial paper December 2019 USA/Columbia/TAIL programs, and is used for general corporate purposes of the borrowers, guaranteed by TCPL TCPL/TCPL US$1.0 billion US$1.0 billion Used for general corporate purposes of the borrowers, December 2021 USA/Columbia/TAIL guaranteed by TCPL Total CAD10.5 billion CAD10.5 billion

Source: TransCanada Corporation's 2018 annual report

The facilities do not require the company to represent and warrant as to a material adverse event at each borrowing, which supports liquidity. These facilities include a single financial covenant setting the maximum consolidated debt/capitalization at 75%. TransCanada has ample headroom under that covenant. In the next 12 months TransCanada has about CAD1.7 billion of long-term debt coming due and we expect TransCanada to refinance these debt obligations as they mature. Rating Methodology and Scorecard Factors

Exhibit 8 Rating Factors TransCanada PipeLines Limited

Current Moody's 12-18 Month Forward View Energy, Oil & Gas - Midstream [MLP] Industry Grid [1][2] FY 12/31/2018 As of Date Published [3] Factor 1 : Scale (25%) Measure Score Measure Score a) Net Property Plant and Equipment (USD Million) $49,037.8 Aa $51,000 - $55,000 Aa b) EBITDA (USD Million) $6,887.7 Aa $7,300 - $7,700 Aaa Factor 2 : Business Profile (25%) a) Estimated Price & Volume Risk Exposure A A A A Factor 3 : Financial Leverage & Distribution Profile (40%) a) EBITDA / Interest Expense 3.8x Ba 3.9x - 4.2x Ba b) Debt / EBITDA 5.6x B 5x Ba c) (FFO - Maintenance CAPEX) / Distributions 3.2x A 2.3x A Factor 4 : Financial Policy (10%) a) Financial Policy Baa Baa Baa Baa Rating: a) Indicated Outcome from Scorecard Baa1 A3 b) Actual Rating Assigned Baa1 Baa1

[1] Based on consolidated financial data of TransCanada Corporation. All ratios are based on 'Adjusted' financial data and incorporate Moody's Global Standard Adjustments for Non- Financial Corporations. [2] As of 12/31/2018. [3] This represents Moody's forward view; not the view of the issuer; and unless noted in the text, does not incorporate significant acquisitions and divestitures. Source: Moody's Financial Metrics™

7 5 April 2019 TransCanada PipeLines Limited: Update following downgrade to Baa1; outlook changed to stable MOODY'S INVESTORS SERVICE INFRASTRUCTURE AND PROJECT FINANCE

Appendix

Exhibit 9 Peer Comparison Table [1]

TransCanada PipeLines Limited (based on TransCanada Enbridge Inc. Kinder Morgan, Inc. Corporation's financial statements)

Baa1 Stable Baa2 Positive Baa2 Stable

FYE FYE FYE FYE FYE FYE FYE FYE FYE (in US millions) Dec-16 Dec-17 Dec-18 Dec-16 Dec-17 Dec-18 Dec-16 Dec-17 Dec-18 Revenue 9,381 10,324 10,537 26,118 33,617 36,141 13,058 13,705 14,144 EBITDA 5,279 5,777 6,888 5,505 7,471 9,661 7,638 7,640 8,063 Net Property Plant and Equipment 41,154 46,101 49,038 48,261 72,809 69,631 39,319 40,756 38,598 EBITDA / Interest Expense 3.2x 3.4x 3.8x 3.5x 3.2x 4.0x 4.1x 4.1x 4.1x Debt / EBITDA 6.6x 5.8x 5.6x 6.2x 7.0x 5.2x 5.8x 5.5x 5.1x (FFO - Maintenance CAPEX) / Distributions 1.9x 2.1x 3.2x 2.0x 1.3x 1.6x 3.5x 3.1x 2.2x [1] All figures & ratios calculated using Moody’s estimates & standard adjustments. FYE = Financial Year-End. LTM = Last Twelve Months. RUR* = Ratings under Review, where UPG = for upgrade and DNG = for downgrade. Source: Moody’s Financial Metrics™

Exhibit 10 TransCanada PipeLines Limited Moody's-Adjusted Debt Breakdown FYE FYE FYE FYE FYE FYE (In CN $ Millions) Dec-13 Dec-14 Dec-15 Dec-16 Dec-17 Dec-18 As Reported Debt 25,770.0 28,384.0 35,083.0 44,855.0 43,511.0 50,241.0 Pensions 72.0 260.0 189.0 248.0 195.0 332.0 Operating Leases 651.7 1,140.0 1,117.5 890.7 657.9 596.9 Hybrid Securities 737.8 837.5 390.5 345.3 -1,200.5 -1,423.0 Non-Standard Adjustments 0.0 0.0 0.0 -72.0 -4.0 73.0 Moody's - Adjusted Debt 27,231.5 30,621.5 36,780.0 46,266.9 43,159.4 49,819.9

2018 non-standard adjustments number includes an adjustment for the following items: unamortized debt discount and issue costs, fair value adjustment related to the acquisition of Columbia. Based on consolidated financial data of TransCanada Corporation. All figures are calculated using Moody’s estimates and standard adjustments. Source: Moody’s Financial Metrics™

Exhibit 11 TransCanada PipeLines Limited Moody's-Adjusted EBITDA Breakdown FYE FYE FYE FYE FYE FYE (In CN $ Millions) Dec-13 Dec-14 Dec-15 Dec-16 Dec-17 Dec-18 As Reported Debt 5,013.0 5,633.0 2,029.0 4,774.0 7,430.0 8,564.0 Pensions 38.0 15.0 20.0 -1.0 -1.0 -50.0 Operating Leases 98.0 114.0 131.0 145.0 93.0 84.0 Stock Compensation 0.0 0.0 56.8 0.0 0.0 0.0 Unusual 0.0 -117.0 3,870.0 2,073.0 -31.0 325.0 Moody's - Adjusted Debt 5,149.0 5,645.0 6,106.8 6,991.0 7,491.0 8,923.0

2018 unusual adjustments number includes an adjustment for the following unusual items: unrealized gains/losses from commodities and foreign exchange derivative instruments, gain/ (loss) on assets held for sale/sold, impairment losses and allowance for funds used during construction. Based on consolidated financial data of TransCanada Corporation. All figures are calculated using Moody’s estimates and standard adjustments. Source: Moody’s Financial Metrics™

8 5 April 2019 TransCanada PipeLines Limited: Update following downgrade to Baa1; outlook changed to stable MOODY'S INVESTORS SERVICE INFRASTRUCTURE AND PROJECT FINANCE

Exhibit 12 TransCanada PipeLines Limited Selected Historic Moody's Adjusted Financial Data

FYE FYE FYE FYE FYE CAD (Million) Dec-14 Dec-15 Dec-16 Dec-17 Dec-18 INCOME STATEMENT Revenue 10,185.0 11,300.0 12,424.0 13,387.0 13,651.0 EBITDA 5,645.0 6,106.8 6,991.0 7,491.0 8,923.0 EBIT 3,957.9 4,250.7 4,938.8 5,364.6 6,515.9 Interest expense 1,527.2 1,695.8 2,167.5 2,192.9 2,330.7 BALANCE SHEET Cash & Cash Equivalents 489.0 850.0 1,016.0 1,089.0 446.0 Total Debt 30,621.5 36,780.0 46,266.9 43,159.4 49,819.9 Total Liabilities 41,356.3 49,468.0 63,778.9 60,515.4 68,815.3 CASH FLOW Capital Expenditures (CAPEX) 4,154.1 4,240.1 5,239.2 7,427.4 9,847.1 Cash from Investing Activities (3,961.1) (4,690.1) (18,720.2) (3,597.4) (9,952.1) Dividends 1,586.9 1,764.3 1,859.6 1,855.5 2,048.9 Retained Cash Flow (RCF) 2,431.1 2,735.1 2,949.2 3,677.4 4,671.1 RCF / Debt 7.9% 7.4% 6.4% 8.5% 9.4% Free Cash Flow (FCF) (1,875.0) (1,807.0) (2,044.0) (4,021.0) (5,313.0) FCF / Debt -6.1% -4.9% -4.4% -9.3% -10.7% PROFITABILITY % Change in Sales (YoY) 15.8% 10.9% 9.9% 7.8% 2.0% EBIT Margin % 38.9% 37.6% 39.8% 40.1% 47.7% EBITA Margin % 38.9% 37.6% 39.8% 40.1% 47.7% EBITDA Margin % 55.4% 54.0% 56.3% 56.0% 65.4% INTEREST COVERAGE EBIT / Interest Expense 2.6x 2.5x 2.3x 2.4x 2.8x EBITDA / Interest Expense 3.7x 3.6x 3.2x 3.4x 3.8x (EBITDA - CAPEX) / Interest Expense 1.0x 1.1x 0.8x 0.0x -0.4x LEVERAGE Debt / EBITDA 5.4x 6.0x 6.6x 5.8x 5.6x Net Debt/EBITDA 5.3x 5.9x 6.5x 5.6x 5.5x Debt / (EBITDA - CAPEX) 20.5x 19.7x 26.4x 678.6x -53.9x Avg.Assets / Avg.Equity 3.2x 3.7x 3.8x 3.4x 3.3x

Based on consolidated financial data of TransCanada Corporation. All figures are calculated using Moody’s estimates and standard adjustments. Source: Moody’s Financial Metrics™

9 5 April 2019 TransCanada PipeLines Limited: Update following downgrade to Baa1; outlook changed to stable MOODY'S INVESTORS SERVICE INFRASTRUCTURE AND PROJECT FINANCE

Ratings

Exhibit 13 Category Moody's Rating TRANSCANADA PIPELINES LIMITED Outlook Stable Issuer Rating Baa1 Senior Unsecured Baa1 Jr Subordinate Baa2 Commercial Paper P-2 PARENT: TRANSCANADA CORPORATION Outlook Stable Issuer Rating Baa2 TRANSCANADA TRUST Outlook Stable Bkd Subordinate Baa3 COLUMBIA PIPELINE GROUP, INC. Outlook Positive Senior Unsecured Baa1 TC PIPELINES, LP Outlook Stable Senior Unsecured Baa2 NOVA GAS TRANSMISSION LTD. Outlook Stable Senior Unsecured Baa1 ANR PIPELINE COMPANY Outlook Stable Senior Unsecured A3 GAS TRANSMISSION NORTHWEST LLC Outlook Stable Senior Unsecured A3 TRANSCANADA AMERICAN INV. LTD. Outlook No Outlook Bkd Commercial Paper P-2 TRANSCANADA PIPELINE USA LTD. Outlook No Outlook Bkd Commercial Paper P-2 Source: Moody's Investors Service

10 5 April 2019 TransCanada PipeLines Limited: Update following downgrade to Baa1; outlook changed to stable MOODY'S INVESTORS SERVICE INFRASTRUCTURE AND PROJECT FINANCE

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REPORT NUMBER 1162361

11 5 April 2019 TransCanada PipeLines Limited: Update following downgrade to Baa1; outlook changed to stable MOODY'S INVESTORS SERVICE INFRASTRUCTURE AND PROJECT FINANCE

CLIENT SERVICES

Americas 1-212-553-1653 Asia Pacific 852-3551-3077 Japan 81-3-5408-4100 EMEA 44-20-7772-5454

12 5 April 2019 TransCanada PipeLines Limited: Update following downgrade to Baa1; outlook changed to stable Corporates

Energy (Oil & Gas) / U.S.A. TransCanada Corporation/TransCanada PipeLines Limited Full Rating Report

Ratings Key Rating Drivers Long-Term IDR A– Short Term IDR F2 Low Business Risk: Over 90% of TransCanada Corporation’s (TRP) EBITDA is derived from Commercial Paper F2 regulated assets or assets supported by long-term contracts. Regulated assets are under the Senior Unsecured A– jurisdiction of well-regarded governmental bodies. The roster of counterparties for contracted IDR – Issuer Default Rating. assets is diversified and strong. The regulatory- and contract-based cash flows remove almost Rating Outlook all customer demand variability from TRP’s earnings. Stable Significant Size and Scale: TRP is one of the most important midstream energy infrastructure providers in North America, with EBITDA comparable to the largest members of the Alerian Financial Data TransCanada Corporation Master Limited Partnership index. TRP’s pipelines access significant and growing supply and (CAD Mil.) 12/31/16 12/31/15 demand areas for natural gas. Company scale matters in the midstream infrastructure industry Revenues 12,505.0 11,300.0 and often provides the ability to weather weak capital markets, the expertise to develop and Adjusted EBITDA 5,959.0 5,296.0 FFO 4,721.0 4,421.0 construct greenfield projects for customers, or the network flexibility to reverse flows or change Adjusted the product shipped. EBITDA/Interest Expense (x) 4.0 4.6 Large Capital Spending Program: The large capex program underway requires external Debt/Adjusted EBITDA (x) 6.6 6.0 financing, which is forecast to come from debt and equity issuances. Management intends to

finance these projects while maintaining a 60/40 debt/equity capital structure. Maintenance

capital spending on most of its pipeline divisions is supported relatively promptly in customer

Related Research rates. North American Midstream: Fourth- Quarter Earnings Wrap-Up (EBITDA Structural Subordination: Certain of TRP’s operating subsidiary companies utilize leverage, Growth Days Are Here Again) as is commonly the case for regulated utility companies. Debt at TransCanada PipeLines (March 2017) 2017 Outlook: North American Limited (TCPL) is structurally subordinate to debt at its operating subsidiaries. Subsidiary debt Midstream Energy (Sector is relatively nominal at approximately 15% of total debt outstanding. The stable cash flow Stabilizing) (November 2016) generation inherent in these pipeline assets largely mitigates concerns around structural

subordination. The Mainline pipeline is an operating division inside TCPL, providing some

direct asset coverage.

Rating Sensitivities

Positive Action: Sustained leverage below 3.5x could lead to a positive rating action, but

positive rating action is not anticipated in the medium term.

Future developments that may, individually or collectively, lead to negative Negative Action:

rating action include materially adverse regulatory outcomes at any of TRP’s major regulated

businesses, or an acquisition that represents a change in the current business strategy of

operating businesses based on cost-of-service principles or very long-term take-or-pay

contracts.

Sustained adjusted debt/adjusted EBITDA above 5.5x at TRP or new projects experiencing

cost overruns, unreliable operations or customer defaults, so the company is not on a path to

significantly reducing adjusted debt/adjusted EBITDA could also lead to negative rating actions.

Analysts Negative action could also occur if the company is unable to sanction its current slate of Thomas Brownsword development projects and leverage is not reduced to 4.5x in 2019, or if large new projections +1 646 582-4881 [email protected] are sanctioned, the leverage is not reduced to 5.5x. Peter Molica +1 212 908-0288 [email protected]

www.fitchratings.com June 12, 2017

Corporates

Financial Overview

Liquidity and Debt Structure

Liquidity is adequate. TRP had approximately CAD8.3 billion of available capacity under

committed revolving credit facilities as of May 4, 2017 (note: all currency references in this

report are to Canadian dollars).

TRP’s maturities are manageable over the next few years. Four credit facilities mature in

December 2017, but these facilities are extendible on lenient terms. The 2018 figure in the

Debt Maturities and Liquidity table below has a large number that has been reduced over the

course of 2017. Accordingly, the company’s maturity schedule does not present a challenge.

Besides credit facilities, liquidity is amply furnished by the company’s predictable cash flow

generated from operations, its proven ability to access debt and equity markets in both Canada

and the U.S., and its portfolio management, including additional dropdowns of U.S. natural gas

pipeline assets into TC PipeLines, LP.

Leverage measured at year-end 2016 is elevated in part due to the effect of acquiring

Columbia Pipeline Group, Inc. (CPG) in the middle of the year in a partly debt-financed

transaction.

Total Debt and Leverage Debt Maturities and Liquidity Total Adjusted Debt (LHS) (CAD Mil., As of Dec. 31, 2016) 2,521.7 Debt/Adjusted EBITDA (RHS) 2017 (CAD Mil.) (x) 50,000 7.0 2018 8,959.2 40,000 6.0 2019 1,722.9 5.0 30,000 4.0 2020 2,699.9 20,000 3.0 Thereafter 28,420.5 2.0 10,000 1.0 Cash and Cash Equivalents 1,016.0 0 0.0 6,085.1 2012 2013 2014 2015 2016 Undrawn Committed Facilities

Source: Company data, Fitch. Source: Company data, Fitch.

Cash Flow Analysis

Like other midstream companies connected to production regions characterized by

expectations for long-term growth, TRP is expected to remain FCF negative.

CFO and Cash Use

CFO Capex Distribution (CAD Mil.)

6,000

5,000

4,000

3,000

2,000 Related Criteria 1,000 Criteria for Rating Non-Financial Corporates (March 2017) 0 2012 2013 2014 2015 2016 Parent and Subsidiary Rating Linkage (August 2016) Source: Company data, Fitch.

TransCanada Corporation/TransCanada PipeLines Limited 2 June 12, 2017 Corporates

Peer and Sector Analysis

Peer Group Peer Group Analysis Issuer Country Enterprise TransCanada Products Kinder Spectra Energy BBB+ a a a Enterprise Products (CAD Mil. Unless Otherwise Noted) Corporation Operating LLC Morgan, Inc. Partners, LP Operating LLC U.S. LTM Ending 12/31/16 12/31/16 12/31/16 12/31/16 Long-Term IDR A– BBB+ BBB– BBB BBB Outlook Stable Stable Stable Stable Spectra Energy Partners, LP U.S. Financial Statistics BBB– Revenue 12,505.0 23,022.3 13,058.0 4,916.0 Kinder Morgan, Inc. U.S. Adjusted EBITDA 5,959.0 5,255.9 6,168.0 2,384.0 Adjusted EBITDA Margin (%) 47.7 22.8 47.2 48.5 Debt with Equity Credit 44,879.5 23,164.4 38,573.2 16,247.0 Issuer Rating History FFO 4,721.0 4,435.8 4,494.0 1,999.0 Outlook/ Capex 5,302.0 3,025.1 2,882.0 3,703.0 Date LT IDR Watch 4/6/17 A– New Rating Credit Metrics (x) Adjusted EBITDA/Gross Interest LT IDR – Long-Term Issuer Default Coverage 4.0 5.3 3.2 4.4 Rating. FFO-Adjusted Leverage 7.0 4.4 5.8 6.3 Source: Fitch. Debt with Equity Credit/Adjusted EBITDA 6.6 4.4 5.8 6.5 FFO Interest Coverage 3.5 5.7 3.0 4.5 aFinancial Statistics in USD. IDR – Issuer Default Rating. Source: Company data, Fitch.

Key Rating Issues

Canadian Midstream Companies Have Higher Leverage TRP has higher leverage relative to similarly rated U.S. peer companies. For most of the company’s existence, this leverage was due in part to the approved capital structure and ROE on TRP’s Canadian operations. With approved equity of between 30% and 40%, and approved ROEs in the 8%–10% range, TRP’s Canadian operations are going to be more levered than in the U.S. A long-held utility industry policy is to show regulators, shareholders and other key stakeholders leverage that is neither significantly more nor significantly less than the leverage embedded in customer rates.

This legacy of high national home country leverage is offset in part by the lower business risk on the Canadian pipeline operations compared with the U.S., due to more constructive regulation, less competition and the higher importance of long-distance energy transportation to the national economy.

Significant Capital Spending Program TRP has a rather robust and ambitious growth spending plan for 2017–2020, with roughly CAD23 billion in growth capital projects moving forward. These projects are generally low risk, supported by contracts that will help them generate consistent, stable cash flows once completed. There is some construction risk around the projects moving forward, but outside recent history (Keystone XL), TRP has a strong history of completing projects on time, and on or under budget with little regulatory interference.

The high level of growth spending will push already high leverage metrics higher in the near term, but the company is willing to tolerate higher near-term leverage if there is no significant

TransCanada Corporation/TransCanada PipeLines Limited 3 June 12, 2017 Corporates

deterioration in profitability on existing assets or coverage metrics. Management believes TRP has enough financing levers to pull to complete its spending program without putting too much stress on its financial position. This includes two closed asset sales (U.S. Merchant hydro and thermal power station portfolios), increased potential of further asset sales, preferred equity issuances, junior subordinated debt issuances and TCP dropdowns, with one dropdown recently agreed upon.

The CAD23 billion in capital spending excludes a CAD15.7 billion Energy East project. It also excludes the Keystone XL pipeline, which has been given another chance to move through the remaining regulatory process with the departure of the Obama administration.

Simplified Organizational Structure — TransCanada Corporation (CAD Mil., Except Where Noted, As of Dec. 31, 2016)

TransCanada Corporation (TSE:TRP) IDR — A–/Stable Amount Rating Preferred Equity 3,980 BBB

100.0%

TransCanada PipeLines Limited IDR — A–/Stable Amount Rating Issuer-Level Senior Debt 26,443 A– Issuer-Level Bridge Loan 2,693 A–

100.0% 100.0% 100.0% 100.0% Nova Gas Transmission Ltd. Columbia Pipeline Group, Inc. TransCanada Trust IDR — BBB+/Stable Amount Rating TransCanada Pipeline Amount Rating Amount Rating Senior Unsecured USA Ltd. Total Debt (USD) 2,750 BBB+ Junior Notes 914 NR Subordinated Debt 3,931 BBB

TransCanada Oil Pipeline Inc. TransCanada Northern Ltd.

TransCanada Keystone TC PipeLines GP Pipeline LLC

53.5% 100.0%

TC Pipelines, LP (NYSE: TCP) Great Lakes Transmission ANR Pipeline Amount Rating 46.5% Amount Rating Amount Rating Issuer-Level Senior Unsecured Senior Unsecured Senior Debt 2,044 NR Notes 373 NR Notes 901 NR

IDR – Issuer Default Rating. NR – Not publicly rated. Source: Company filings, Fitch.

TransCanada Corporation/TransCanada PipeLines Limited 4 June 12, 2017 Corporates

Definitions Key Metrics • Leverage: Total debt adjusted for equity credit divided by Leverage Interest Coverage Ratio Fitch-adjusted EBITDA accounting for master limited (x) (x) partnership’s cash flow and 7.0 6.0 extraordinary items. • Interest Coverage: Adjusted 6.5 EBITDA plus gross interest 5.0 paid plus preferred dividends 6.0 divided by gross interest paid plus preferred dividends. 4.0 5.5 • CFO/Capex: Cash flow from operations divided by total capex (maintenance plus 5.0 3.0 growth capex). 2012 2013 2014 2015 2016 2012 2013 2014 2015 2016

• FFO-Adjusted Leverage: Debt Source: Company data, Fitch. Source: Company data, Fitch. less equity credit for hybrid securities plus preferred stock CFO/Capex FFO-Adjusted Leverage and adjusted for rental expense divided by FFO plus gross (x) (x) interest expense plus preferred 8.0 dividends plus rental expense. 1.5

1.0 7.0

0.5 6.0

0.0 5.0 2012 2013 2014 2015 2016 2012 2013 2014 2015 2016

Source: Company data, Fitch. Source: Company data, Fitch.

TransCanada Corporation/TransCanada PipeLines Limited 5 June 12, 2017 Corporates

Company Profile TRP is the ultimate parent of the TransCanada family of companies. The primary debt issuer in the family is TCPL, which operates through three segments: Natural Gas Pipelines, Liquids Pipelines and Energy. The Natural Gas Pipelines segment handles about 27% of continental natural gas demand and consists of the company’s investments in approximately 56,900 miles of regulated natural gas pipelines and over 650 billion cubic feet of regulated natural gas storage facilities. These assets are located in Canada, the U.S. and Mexico. The Natural Gas Pipelines segment provided about 65% of adjusted EBIT for fourth-quarter 2016 — a quarter in which newly acquired CPG was present the entire quarter.

The Liquids Pipelines segment consists of approximately 2,700 miles of crude oil pipeline systems connecting Alberta and the U.S. crude oil supplies to the U.S. refining markets in Illinois, Oklahoma and Texas. The Liquids Pipelines division generated about 15% of adjusted EBIT for fourth-quarter 2016.

The Energy segment at Dec. 31, 2016 consisted of the company’s investments in 17 electric power generating stations and two nonregulated Alberta natural gas storage facilities. The Energy division produced about 25% of adjusted EBIT in fourth-quarter 2016. Energy’s percentage share will decline as a result of recently closed divestments related to power generating stations in deregulated markets in the northeast U.S. The sale of these plants reduces TRP’s already low business risk.

Revenues for the Natural Gas Pipeline segment are predominantly provided under regulatory rate orders. These rate orders come from two bodies, Canada’s National Energy Board (NEB) and the Federal Energy Regulatory Commission (FERC). The sizeable presence of the NEB and the FERC in TRP’s business is a differentiating credit factor for the company.

The roster of counterparties for contracted assets is diversified and strong. The company’s supply access improved due to recently acquired CPG’s Marcellus formation region franchise.

TransCanada Corporation/TransCanada PipeLines Limited 6 June 12, 2017 Corporates

Annual Historical Financials — TransCanada Corporation (CAD Mil., Years Ended Dec. 31) 2012 2013 2014 2015 2016 Profitability (%) Operating EBITDAR Margin 50.3 50.7 49.3 48.0 48.8 Operating EBITDA Margin 49.3 49.6 48.1 46.9 47.7 Operating EBIT Margin 32.1 32.7 32.3 31.2 32.1 FFO Margin 39.3 45.5 41.0 39.1 37.8 FCF Margin (5.5) (24.4) (16.9) (16.4) (14.1)

Gross Leverage (x) Total Adjusted Debt/Operating EBITDAR 5.4 5.3 5.3 6.0 6.6 FFO-Adjusted Leverage 5.5 5.3 5.5 6.3 7.0 FCF/Total Adjusted Debt (%) (1.9) (8.0) (5.8) (5.1) (3.8) Total Debt with Equity Credit/Operating EBITDA 5.3 5.3 5.3 6.0 6.6 Total Adjusted Debt/(CFO Before Lease Expense – Maintenance Capex) 24.8 (39.1) (115.7) (132.0) (244.9)

Coverage (x) Operating EBITDAR/(Interest Paid + Lease Expense) 4.1 4.7 4.5 4.3 3.7 Operating EBITDA/Interest Paid 4.3 5.0 4.9 4.6 4.0 FFO Fixed-Charge Coverage 3.8 4.4 4.1 3.9 3.3 FFO Interest Coverage 4.0 4.7 4.4 4.1 3.5 CFO/Capex 1.3 0.8 0.9 0.9 0.9

Debt Summary Total Debt with Equity Credit 22,297 26,145 28,932 35,263 44,880 Total Adjusted Debt with Equity Credit 22,969 26,929 29,844 36,311 46,040 Lease-Equivalent Debt 672 784 912 1,048 1,160 Interest (Paid) (966) (985) (1,123) (1,266) (1,721)

Cash Flow Summary FFO 3,149 4,000 4,174 4,421 4,721 Change in Working Capital (Fitch Defined) 287 (326) (189) (398) 248 CFO 3,436 3,674 3,985 4,023 4,969 Capex (2,595) (4,461) (4,357) (4,429) (5,302) Common Dividends (Paid) (1,281) (1,356) (1,345) (1,446) (1,436) FCF (440) (2,143) (1,717) (1,852) (1,769) Acquisitions and Divestitures (214) (216) (45) (236) (13,602) Net Debt Proceeds 960 2,475 878 2,475 6,400 Net Equity Proceeds 53 841 366 31 9,422 Other Investing and Financing Cash Flows (462) (581) 80 (57) (285) Total Change in Cash and Equivalents (103) 376 (438) 361 166

Liquidity Readily Available Cash and Equivalents 551 927 489 850 1,016 Availability Under Committed Credit Lines 2,398 3,358 3,433 6,482 8,826

Working Capital Net Working Capital (Fitch Defined) (15) 119 (443) (315) (595) Trade Accounts Receivable (Days) 48.0 46.6 47.1 44.8 60.6 Inventory Turnover (Days) 22.5 23.0 22.2 21.5 22.4 Trade Accounts Payable (Days) 92.9 79.2 123.3 100.2 148.8 Capital Intensity (%) 32.4 50.7 42.8 39.2 42.4

Income Statement Revenue 8,007 8,797 10,185 11,300 12,505 Operating EBITDAR 4,031 4,459 5,017 5,427 6,104 Operating EBITDAR After Dividends to Associates and Minorities 4,272 5,064 5,596 6,003 6,948 Operating EBITDA 3,947 4,361 4,903 5,296 5,959 Operating EBITDA After Dividends to Associates and Minorities 4,188 4,966 5,482 5,872 6,803 Operating EBIT 2,572 2,876 3,292 3,531 4,020 Source: Company reports, Fitch.

TransCanada Corporation/TransCanada PipeLines Limited 7 June 12, 2017 Corporates

The ratings above were solicited by, or on behalf of, the issuer, and therefore, Fitch has been compensated for the provision of the ratings.

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TransCanada Corporation/TransCanada PipeLines Limited 8 June 12, 2017 Rating Report TransCanada Corporation & TransCanada PipeLines Limited

Ram Vadali, CFA, CPA Ravikanth Rai, CFA Jay Gu, MBA +1 416 597 7526 +1 416 597 7388 +1 416 597 7357 Ratings [email protected] [email protected] [email protected]

Debt Issuing Entity Rating Rating Action Trend Issuer Rating TransCanada PipeLines Limited A (low) Confirmed Stable Unsecured Debentures & Notes TransCanada PipeLines Limited A (low) Confirmed Stable Junior Subordinated Notes* TransCanada PipeLines Limited BBB Confirmed Stable Commercial Paper TransCanada PipeLines Limited R-1 (low) Confirmed Stable Preferred Shares - Cumulative TransCanada Corporation Pfd-2 (low) Confirmed Stable * The Junior Subordinated Notes rating of TransCanada PipeLines Limited pertains to the Junior Subordinated Notes that are due in 2067.

Rating Update

On June 5, 2018, DBRS Limited (DBRS) confirmed the above rat- approximately 6,100 megawatts (MW) of power generation, ings of TransCanada Corporation (TCC or the Company) and with an additional 900 MW contracted generation capacity com- its wholly owned subsidiary, TransCanada PipeLines Limited ing into service when the Napanee gas-fired generation project is (TCPL). All ratings are being confirmed with Stable trends. The expected to be commissioned in late 2018. Preferred Shares - Cumulative rating of TCC, which owns 100% of TCPL and holds no other material assets, is based on the strength DBRS notes the regulatory uncertainty caused by the recent of TCPL and the expectation that no debt will be issued by TCC. Federal Energy Regulatory Commission (FERC) actions and no- tice of proposed rulemaking to flow through the benefit of lower Calgary-based TCC’s ratings reflect the relatively stable cash flow corporate taxes to shippers through pipeline tariffs. TCC has in- generation supported by the Company’s diversified energy infra- dicated that the impact to earnings is not expected to be material structure asset portfolio of natural gas pipelines, liquids pipe- given its relatively simple corporate structure, and as nearly 55% lines and power generation assets in Canada, the United States of the U.S. natural gas pipeline revenues in 2018 are based either and Mexico. A majority of the Company’s operating cash flow on discounted or negotiated rate contracts, this percentage is is underpinned by rate-regulated assets and long-term contracts likely to increase to over 60% as new projects come into service with no commodity risk. TCC has one of the largest natural gas in 2019. However, because of the FERC rulings, funding through pipeline networks in North America, with access to key produc- periodic asset drop-downs to TC Pipeline LP, a U.S. Midstream ing basins and connectivity to strong demand markets. Demand Limited Partnership (MLP) owned 25.5% by TCC, is no longer for natural gas remains strong as natural gas continues to replace considered to be a viable funding option by the Company. coal for power generation, liquified natural gas (LNG) exports grow in the United States and natural gas exports to Mexico rise. DBRS notes the execution risk in near- to medium-term capital TCC’s liquids pipelines handle approximately 20% of western intensity and the consequent pressure on credit metrics as TCC Canadian crude oil exported to the United States. TCC is also continues to execute on $21.3 billion of commercially secured one of the largest independent power generators in Canada, with capital projects (excluding Keystone XL) largely in the Natural

Continued on P.2

Financial Information 12 mos. 3 mos. ended March 31 ended March 31 Year ended December 31

2018 2017 2018 2017 2016 2015 Cash flow/total debt & equivalents 14.6% 12.7% 12.7% 12.8% 10.8% 13.6% Total debt & equivalents/capital 59.5% 62.4% 59.5% 59.5% 61.1% 64.2%

EBIT interest coverage (times) 1 3.03 2.88 2.60 2.56 2.55 2.75 1 Includes dividends/distributions received from equity investments in numerator of each ratio.

Issuer Description TCPL is a leading integrated energy services company in North America involved in natural gas and liquids transmission as well as electricity generation. TCC is TCPL’s parent company and holds no material assets other than TCPL’s common shares.

Corporate Finance: Energy June 18, 2018 Rating Report | TransCanada Corporation & TransCanada PipeLines Limited DBRS.COM 2

Rating Update (CONTINUED)

Gas Pipelines segment in the 2018-2020 timeframe ($7.3 billion Company is expected to benefit from cash flow growth from ma- spent as at Q1 2018), including approximately $10.0 billion fore- jor projects in Canada and the United States that are expected casted for 2018. The Company completed and placed $5.0 billion to be placed in service in the next two years. DBRS does not ex- of growth projects in service in 2017. Going forward, DBRS ex- pect a positive momentum to TCC’s ratings in the next two years. pects the Company to fund its significant capital program with However, the ratings could be negatively affected by delays in ex- its growing operating cash flow and a balance of equity and debt. ecution of capital projects, adverse changes to regulatory frame- TCC’s credit metrics have modestly improved since the works, weaker counterparty credit profiles and if TCC fails to USD 13.0 billion acquisition of the Columbia Pipeline Group maintain operating cash flow to debt at or above 15% by the end (CPG) in 2016 and sale of merchant power assets in 2017. DBRS of 2019 and beyond, while consistently maintaining debt to capi- expects to see gradual improvement in credit metrics, as the tal at or below 60%.

Rating Considerations

which is estimated to enter service in late 2018, is expected to add Strengths 900 MW of additional contracted generation capacity.

1. Regulated and contractual earnings 3. Reasonable balance sheet and credit metrics The Company benefits from the regulatory and/or contractual The Company’s financial profile remains reasonable, with debt- framework within its three operating segments. Approximately to-capital at 59.5%, cash flow-to-debt at 12.7% and EBIT-to- 95% of TCC’s EBITDA is derived from regulated assets and long- interest at 2.60 times (x) for the last 12 months (LTM) ended term contracts. The Company’s $21.3 billion of near-to-medium- March 31, 2018. Recent acquisitions, including CPG and a minor- term growth projects, including USD 5.8 billion of projects at ity interest in Columbia Pipeline Limited Partnership (CPPL), CPG, are underpinned by long-term contracts or cost of service have been funded prudently with meaningful issuance of equity regulation. Mexican pipelines are underpinned by 25-year take- and asset sales. or-pay contracts with Mexico’s state-owned utility Comisión Federal de Electricidad. The National Energy Board (NEB) and Federal Energy Regulatory Commission (FERC) — although the Challenges latter to a lesser extent — have been relatively supportive in pro- 1. Competition in Natural Gas Pipelines segment viding the regulatory framework necessary for pipelines to have Changing gas flow dynamics resulting from large-scale shale gas the opportunity to recover their costs and earn an adequate re- production and demand levels have resulted in a highly competi- turn on equity (ROE) over a reasonable time frame. A substantial tive market for natural gas pipelines in North America. Increased proportion of the EBITDA from TCC’s Energy segment is sup- connectivity to new supply basins closer to markets traditionally ported by long-term power contracts with creditworthy parties supplied by TCC has resulted in higher basin-on-basin com- (e.g., the Independent Electricity System Operator (IESO) and petition, negatively affecting netbacks for Western Canadian Hydro-Québec, both rated A (high) with Stable trends by DBRS). Sedimentary Basin (WCSB) producers and volumes flowing on DBRS notes, however, that CPG has a weaker counterparty risk TCC’s Canadian Mainline. CPG faces competition from exist- profile and shorter-duration contracts, which include a material ing pipelines in the Marcellus and Utica basins — namely Texas percentage of non-investment-grade shippers. Eastern Transmission, Tennessee Gas, the Vector Pipeline and Dominion Transmission. Energy Transfer Partners’ new Rover 2. Well-diversified infrastructure portfolio Pipeline project, which has long-term commitments, was placed The Company’s diversified infrastructure assets cover the in service in May 2018 to transport up to 3.25 billion cubic feet Canadian, U.S. and Mexican Natural Gas Pipelines, Liquids (bcf ) of Appalachian natural gas to markets in the Midwest, Pipelines and Energy segments. With the acquisition of CPG, Northeast, East Coast, Gulf Coast and Canada. A number of new TCC has one of the largest natural gas pipeline networks in North natural gas pipeline projects are coming into service in the next America, with access to key producing basins and connectivity two years in the Appalachian basin to expand connectivity to to strong demand markets. CPG’s major asset, the Columbia Gas demand markets. Competition in the near term could also come Transmission (CGT) system, is located within the Marcellus and from the 1.5 bcf/d NEXUS Gas Transmission Pipeline, which is Utica shale gas production regions and services demand from expected to be complete in late 2018, connecting the Marcellus utility demand in the Northeastern United States. TCC’s liquids and Utica basins to Ohio, Michigan and Ontario. pipelines handle approximately 20% of western Canadian crude oil exported to the United States. TCC is also one of the largest in- 2. Potential medium-term pressure on credit metrics dependent power generators in Canada, with approximately 6,100 TCC’s capital program consists of $21.3 billion of near-term megawatts (MW) of power generation. The Napanee project, projects (including USD 5.8 billion at CPG) and $24.2 billion of

Corporate Finance: Energy June 18, 2018 Rating Report | TransCanada Corporation & TransCanada PipeLines Limited DBRS.COM 3

Rating Considerations (CONTINUED) commercially secured medium- and longer-term projects. DBRS and legal proceedings brought against the regulatory bodies and believes that the high capital expenditures (capex) combined government agencies overseeing the project. In Canada, TCC’s with 8% to 10% dividend growth could pressure credit metrics. Energy East project was cancelled because of unclear regulatory TCC’s credit metrics will likely be pressured in the medium term, policies and delays. These issues raise the possibility that future particularly if final investment decisions are made on some of pipeline project development could entail longer lead times and its large-scale projects such as Keystone XL in late 2018 or early construction costs, potentially affecting other projects. 2019. DBRS expects that the length of time of underperformance with respect to these metrics would be dependent on the timing 4. Volume risk of approval, the capex spending pattern of the projects and the The Company faces moderate volume risk within some of its date on which projects are placed into service. assets. Volumes flowing on the southern end of the Keystone Pipeline System in the United States (Marketlink Pipeline) are 3. Rising environmental, regulatory and political risks underpinned by short-term contracts or move on an uncontract- TCC faces environmental, regulatory and political risks with ed (spot) basis, while Gulf Coast Pipeline’s long-term contracts respect to several projects. Political and environmental oppo- only come into effect when Keystone XL is completed. In the sition to liquids pipeline projects are more pronounced than Energy segment, there could be variability at Bruce Power as a natural gas pipelines, as demonstrated recently for the Trans result of plant availability, which will fluctuate as Bruce Power Mountain Expansion Project, Keystone XL and Enbridge Line performs work under its life-extension agreement with the 3 Replacement. The long-delayed Keystone XL Pipeline project Ontario IESO. CPG revenues can be affected by contracted vol- received approval from the Nebraska Public Service Commission umes, volumes delivered and seasonality. There is volume risk for an alternate route in November 2017. The Company is working associated with CPG’s fee-based storage and midstream opera- with landowners along the approved route to obtain easements tions and the Columbia Gulf transmission system has some un- and continues to monitor and participate in the various appeals contracted volumes.

Corporate Finance: Energy June 18, 2018 Rating Report | TransCanada Corporation & TransCanada PipeLines Limited DBRS.COM 4

Earnings and Outlook

12 mos. Income Statement 3 mos. ended March 31 ended March 31 Year ended December 31

(CAD millions, US GAAP, DBRS-adjusted) 2018 2017 2018 2017 2016 2015 Canadian Natural Gas Pipelines 494 504 2,134 2,144 2,182 2,216 U.S. Natural Gas Pipelines 804 720 2,441 2,357 1,682 970 Mexico Natural Gas Pipelines 160 140 539 519 332 213 Liquids Pipelines EBITDA before extras 431 312 1,467 1,348 1,152 1,308 Energy EBITDA before extras 184 305 909 1,030 1,281 1,254 Segment EBITDA before extras 2,073 1,981 7,490 7,398 6,629 5,961 Corporate and other (161) (171) (733) (743) (525) (529) Distributions from equity investments 234 219 985 970 844 793 EBITDA before extras 1 2,146 2,029 7,742 7,625 6,948 6,225 Depreciation & amortization (535) (510) (2,073) (2,048) (1,939) (1,765) EBIT before extras 1 1,611 1,519 5,669 5,577 5,009 4,460 Interest expense, net (505) (483) (2,024) (2,002) (1,787) (1,339) Net income before extras and taxes 1,106 1,036 3,645 3,575 3,222 3,121 Other income (expense) (23) (46) 144 121 (164) (369) Income taxes recovered (paid) (173) (244) (768) (839) (841) (903) Net Income before extraordinary items 910 746 3,021 2,857 2,217 1,849 Extraordinary items (136) (62) 226 300 (1,984) (2,995) Reported net income 774 684 3,247 3,157 233 (1,146)

Segment EBITDA Breakdown % Canadian Natural Gas Pipelines 24% 25% 28% 29% 33% 37% % U.S. Natural Gas Pipes 39% 36% 33% 32% 25% 16% % Mexico Natural Gas Pipes 8% 7% 7% 7% 5% 4% % Liquids Pipelines 21% 16% 20% 18% 17% 22% % Energy 9% 15% 12% 14% 19% 21% 1 Includes dividends/distributions received from equity investments.

2017 Summary • TCC’s earnings are supported by a diversified infrastructure were placed in service in 2017, as well as higher contribution asset portfolio of pipelines and power assets in Canada, the from liquids marketing. United States and Mexico. • Energy segment earnings reduced modestly because of the sale • Net income (before extras) were higher compared with 2016 of U.S. Northeast power assets in Q2 2017, partially offset by mainly driven by higher contribution from U.S. Natural Gas (1) higher earnings from Bruce Power because of fewer outage Pipelines because of the full year contribution from CPG, partially days and (2) higher earnings from Western Power because of the offset by lower Energy earnings and higher interest expense. termination of the Alberta power purchase arrangements (PPAs). • Canadian Natural Gas Pipelines earnings (EBITDA) were slightly lower, largely reflecting the lower average investment 2018 Outlook base in Canadian Mainline, partially offset by higher average • Q1 2018 earnings before extras increased slightly, driven by investment base in Nova Gas Transmission Limited (NGTL). higher earnings from the Mexico Natural Gas Pipelines and • U.S. Natural Gas Pipelines earnings were significantly higher Liquids segments, partially offset by a lower contribution from because of the full-year contribution from CPG in 2017 and the Energy segment. higher earnings from the ANR Pipeline following the FERC- • DBRS expects TCC’s earnings to be higher in 2018 because of approved rate settlement effective August 1, 2016. (1) full year contributions from the Northern Courier and Grand • Mexico Natural Gas Pipelines earnings also rose significantly, Rapids pipelines and higher equity earning from Sur de Texas; driven by the full-year contribution from the Topolobampo (2) incremental revenues from the completion of expansion and Mazatlán Pipelines, which were placed into service in projects on the Columbia Gas and Columbia Gulf systems; and July 2016 and December 2016, respectively. (3) growth in the average investment base, resulting from expan- sion projects on the NGTL System, partially offset by lower earn- • Liquids Pipelines earnings were higher primarily because of ings in Energy segment because of the sale of the U.S. Northeast higher uncontracted volumes on the Keystone Pipeline and power generation assets in Q2 2017 and lower equity earning incremental contributions from intra-Alberta pipelines that from Bruce Power because of higher planned outage days.

Corporate Finance: Energy June 18, 2018 Rating Report | TransCanada Corporation & TransCanada PipeLines Limited DBRS.COM 5

Financial Profile

12 mos. Consolidated Financial Profile 3 mos. ended March 31 ended March 31 Year ended December 31

(CAD millions, US GAAP, DBRS-adjusted) 2018 2017 2018 2017 2016 2015 Net income before extras 910 746 3,021 2,857 2,217 1,849 Depreciation and amortization 535 517 2,073 2,055 1,939 1,765 Deferred income taxes, NCI and other 174 194 571 591 665 1,116 Cash Flow from Operations 1,619 1,457 5,665 5,503 4,821 4,730 Capex and equity investments (1,975) (1,431) (9,392) (8,848) (5,340) (4,913) Dividends (common, preferred & NCI) (483) (440) (1,882) (1,839) (1,889) (1,792) Gross free cash flow (before working capital) (839) (414) (5,609) (5,184) (2,408) (1,975) Changes in non-cash working capital items (207) (155) (325) (273) 248 (346) Gross Free Cash Flow (1,046) (569) (5,934) (5,457) (2,160) (2,321) Business acquisitions, net of cash 0 0 0 0 (13,608) (236) Proceeds on sale of invest. and other 139 (80) 5,329 5,110 38 382 Net Free Cash Flow (907) (649) (605) (347) (15,730) (2,175)

Inc. (dec.) in total debt 679 (381) (1,344) (2,404) 4,851 1,558 Inc. (dec.) in non-controlling int. financing 49 92 182 225 215 55 Inc. (dec.) in hybrid debt securities 0 1,982 1,486 3,468 1,549 917 Inc. (dec.) in preferred shares 0 0 0 0 1,474 243 Inc. (dec.) in common shares 357 (1,166) 654 (869) 7,807 (237) Inc. (Dec.) in other 0 0 0 0 0 0 Dec. (inc.) in cash balances (178) 122 (373) (73) (166) (361) Funding Sources 907 649 605 347 15,730 2,175

Cash flow/total debt & equivalents 14.6% 12.7% 12.7% 12.8% 10.8% 13.6% Total debt & equivalents/capital 59.5% 62.4% 59.5% 59.5% 61.1% 64.2% EBIT interest coverage (times) 1 3.03 2.88 2.60 2.56 2.55 2.75 Cash flow interest coverage (times) 4.05 3.76 3.60 3.53 3.46 3.92 Fixed-charges coverage (times; EBIT-based) 1 2.75 2.60 2.37 2.33 2.37 2.55 Common & pref divs/net income (before extras) 71.9% 78.2% 79.9% 82.0% 83.1% 84.6%

Note: NCI = Noncontrolling Interests. Common equity and total capital exclude accumulated other comprehensive income for ratio calculations. 1 Includes dividends/distributions received from equity investments in numerator of each ratio.

2017 Summary 2018 Outlook TCC’s financial profile remains reasonable, as it is supported by • TCC has $21.3 billion (excluding maintenance capital) the Company’s diversified infrastructure asset portfolio of pipe- of short- to medium-term capital projects under execu- lines and power assets in Canada, the United States and Mexico. tion, which are expected to provide meaningful cash flow • Cash flow-to-debt at 12.8% improved in 2017, reflecting the growth. TCPL expects to spend approximately $10 billion higher operating cash flow because of a full-year cash flow (including equity investment) for growth capex in 2018 re- contribution from CPG, despite higher debt. lated to Natural Gas Pipeline projects, including CPG, NGTL, • While trending lower, TCC’s dividend payout ratio remains Canadian Mainline, ANR and Mexico; Liquids Pipelines proj- elevated (82% of net income before extras in 2017) as earn- ects, including White Spruce; and Energy projects, including ings growth has not kept pace with common and preferred Bruce Power and Napanee. share issuances. • TCC expects to grow its dividends by 8% to 10% annually. • DBRS expects gradual improvement in credit metrics as capi- tal projects are placed into service over the next two years.

Corporate Finance: Energy June 18, 2018 Rating Report | TransCanada Corporation & TransCanada PipeLines Limited DBRS.COM 6

Bank Lines and Long-Term Debt Maturities

TCPL has adequate financing and cash flows available to meet its • TransCanada PipeLine USA Ltd. has a USD 1.0 billion facility liquidity needs. As at April 27, 2018, TCPL and its consolidated maturing in December 2018 for general corporate purposes, subsidiaries had the following committed revolving credit fa- which is guaranteed by TCPL. cilities, part of which were allocated to backstop its commercial • TransCanada American Investments Ltd. has a USD 0.5 billion paper (CP) programs. facility maturing in December 2018 to backstop its U.S.-dollar • TCPL has a $3.0 billion facility maturing in CP program and for general corporate purposes, which is December 2022 to backstop its $1.0 billion CP program and a guaranteed by TCPL. USD 2.0 billion facility maturing in December 2018 to back- stop its USD 2.0 billion CP program. • CPG has a USD 1.0 billion credit facility maturing in December 2018 for general corporate purposes, which is guaranteed by TCPL.

Long-Term Debt Maturities As at December 31, 2017 2018 2019 2020 2021 2022+ Total Long-term debt maturities* (C$ millions) 2,866 3,189 2,834 2,085 23,767 34,741 % of long-term debt 8.2% 9.2% 8.2% 6.0% 68.4% 100.0% * Excludes the CPs backstopped by various credit facilities.

• TCPL’s debt maturities are staggered and refinancing risk • In 2017, TCPL issued USD 1.25 billion of Senior Unsecured is manageable. Notes and $1.0 billion of medium-term notes (MTNs) and re- • In 2017, TCPL fully repaid USD 3.7 billion of acquisition paid USD 1.00 billion of Senior Unsecured Notes, $100 million bridge facilities. Debentures and $300 million of MTNs. TC PipeLines, LP is- sued USD 500 million of Senior Unsecured Notes. • In 2017, TransCanada Trust issued USD 1.5 billion Series 2017-A and $1.5 billion Series 2017-B Junior Subordinated Notes. • In Q1 2018, TCPL repaid USD 500 million of Senior Unsecured Notes, USD 250 million of Senior Unsecured Notes and $150 million of Debentures.

Simplified Ownership Structure

Long-Term Debt as at December 31, 2017 (100% Owned Unless Otherwise Indicated)

TransCanada Corporation (TCC) Canada Pfd 2 (low) Preferred Shares: CAD 4.0 Billion

TransCanada PipeLines Limited (TCPL) Canada A (low), BBB, R1 (low) Total LT Debt: CAD 34.7 Billion Direct LT Debt: CAD 26.1 Billion Junior Subordinated Notes: CAD 7.1 Billion CAD 3.0 Billion & USD 2.0 Billion committed credit facility

NOVA Gas Transmission Ltd. 701671 Alberta Ltd. TransCanada PipeLine USA Ltd. (NGTL) Alberta Alberta (TCPL USA) Nevada USD 1.0 Billion Committed Credit Facility A (low) Direct External Debt: CAD 0.9 Billion

TransCanada TransCanada Oil TransCanada Columbia Pipeline Group Inc. Energy Ltd. PipeLine Inc. American Investments Ltd. (TAIL) Direct External Debt: USD 2.75 Billion Canada Delaware Delaware USD 1.0 Billion Committed Credit Facility USD 0.5 Billion Committed Credit Facility

TransCanada Keystone PipeLine, LLC Delaware

Corporate Finance: Energy June 18, 2018 Rating Report | TransCanada Corporation & TransCanada PipeLines Limited DBRS.COM 7

Regulation – Canadian Mainline and NGTL System

The Canadian Mainline, NGTL System and other Canadian nat- Niagara, Ontario, regions. ural gas pipelines owned and/or operated by TCPL are regulat- • Provides a market-driven, stable, long-term accommoda- ed by the NEB, which regulates the construction and operation tion of future demand in the region in combination with the of facilities and the terms and conditions of service (including anticipated lower demand for transportation on the Prairies rates) that are expected to provide TCPL with the opportunity Line and the Northern Ontario Line while providing a rea- to recover the costs of transporting natural gas, including both sonable opportunity for TCPL to recover related Canadian return of and return on capital. Mainline costs.

Canadian Mainline • TCPL retains pricing flexibility for discretionary services to In November 2014, the NEB approved the Canadian Mainline’s implement certain toll changes and new services as required 2015–2030 Tolls and Tariff Application, under which TCPL and by the terms of the settlement. the three largest Canadian local distribution companies agreed • TCPL has also commenced the offering the Dawn Long-Term to the following terms: Fixed-Price (LTFP) service from November 1, 2017. The ser- • New fixed tolls for 2015 to 2020, as well as certain parameters vice enables Western Canadian producers to transport up to for a toll-setting methodology to 2030. 1.4 bcf/d of natural gas at a simplified toll of $0.77/gigajoule • Tolls to be calculated on a 10.1% base allowed ROE on 40% from the Empress receipt point in Alberta to the Dawn hub in deemed common equity. Southern Ontario. The service is underpinned by ten-year con- tracts that have early termination rights after five years. Any • Includes an incentive mechanism that requires a $20 million early termination will result in an increased toll for the last (after-tax) annual contribution by TCPL from 2015 to 2020, two years of the contract. which could result in ROE outcomes ranging from 8.7% to 11.5%. • Toll stabilization through continued use of deferral accounts — NGTL System namely the Long-Term Adjustment Account and the Bridging In March 2018, NGTL filed the TCPL 2018–2019 Revenue Amortization Account — to capture the surplus (or shortfall) Requirement Settlement Application with a decision from between revenues and cost of service for each year over the NEB expected in Q2 2018. The settlement structure is similar six-year term of the decision. to the previous 2016–2017 Revenue Requirement Settlement • TCPL was required to file a compliance filing with the NEB in Application, with fixed annual operating, maintenance and 2015 (filed March 31, 2015; currently operating under interim administration (OM&A) costs; allowed ROE; and deemed tolls) and a toll review for the 2018 to 2020 period prior to common equity. December 31, 2017. • Allowed ROE was fixed at 10.1% on 40% deemed common eq- • A Supplement Agreement, which proposed lower tolls with uity in 2018 and 2019 (same as for 2016 to 2017). incentive mechanism to provide a 10.1% or higher return on • Depreciation expense was increased to the forecast composite 40% deemed equity, for the 2018 to 2020 period was execut- rate of 3.45% in 2018 and 2019 compared with the composite ed between TCPL and eastern local distribution companies rate of 3.18% in 2017. (LDCs) in December 2017. The NEB provided its Notice of • OM&A costs for $225 million for 2018 and $230 for 2019 were Public Hearing for the Supplement Agreement. TCPL’s reply fixed, with any variances above and below the fixed amounts evidence is due September 2018. to be 50/50 shared. All other costs were passed through to the • TCPL committed to increasing pipeline capacity to eastern shippers on a flow-through basis. Canadian markets for supplies from the Dawn, Ontario, and

Corporate Finance: Energy June 18, 2018 Rating Report | TransCanada Corporation & TransCanada PipeLines Limited DBRS.COM 8

Major Capital Projects

The following table summarizes TCC’s small- to medium-sized Natural Gas Pipelines (35%), U.S. Natural Gas Pipelines (37%), projects as at March 31, 2018. The capital cost composition of Mexico Natural Gas Pipelines (17%) and Energy (10%). The total these projects by segment is Liquids Pipelines (1%), Canadian estimated capital cost is $21.3 billion.

Near-Term Projects (CAD billions) Capital Invested Status as at Expected Revenue Cost to Date Mar. 31, 2017 In-Service Date Stream Columbia Pipeline Group (U.S.) (Gas Pipe) (USD) -WB Xpress 0.9 0.5 Construction 2018 Cost of Service -Mountaineer Xpress 3.0 0.7 Construction 2018 Cost of Service -Buckeye XPress 0.2 0.0 Construction 2020 Cost of Service -Gulf Xpress 0.6 0.3 Construction 2018 Cost of Service -Modernization II 1.1 0.2 Development 2018-2020 Cost of Service Other (U.S. Gas Pipe) 0.3 0.1 Construction 2018-2020 Cost of Service White Spruce (Liquids Pipe) 0.2 - Development 2019 Contracted Canadian Mainline - Other (Gas Pipe) 0.2 - Development 2018-2021 Cost of Service

NGTL System -2018 Facilities (Canadian Gas Pipe) 0.6 0.4 Development 2019 Cost of Service -2019 Facilities (Canadian Gas Pipe) 2.4 0.4 Development 2020 Cost of Service -2020 Facilities (Canadian Gas Pipe) 1.7 0.1 Development 2021+ Cost of Service -2021 Facilities (Canadian Gas Pipe) 2.5 - Development 2018 Cost of Service Napanee Generating Station (Ontario) (Energy) 1.3 1.1 Construction 2018 Fully contracted Bruce Power - life extension (Energy) 0.9 0.3 Development up to 2020 Fully contracted Tula (Mexican Gas Pipe) (USD) 0.7 0.5 Construction 2019 Fully contracted Villa de Reyes (Mexico Gas Pipe) (USD) 0.8 0.5 Development 2018 Contracted Sur de Texas-Tuxpan (Mexico Gas Pipe) (USD) 1.3 1.1 Development 2018 Contracted Small to Medium-Sized, Shorter Term Projects 18.7 6.2 Foreign Exchange impact 2.6 1.1 Total (CAD) 21.3 7.3

• The WB XPress project is a 47 kilometre (km; 29 mile) natural • The White Spruce project is a 20-inch, 72 km (45 mile) crude gas pipeline between Virginia and West Virginia. It includes oil pipeline to transport light synthetic crude oil from the construction of 5 km (3 miles) of new pipeline, two compres- Canadian Natural Resources Limited’s Horizon facility in sor stations and replacement of 42 km (26 miles) of existing northeast Alberta into the Grand Rapids pipelines. It received pipeline to increase capacity by approximately 1.3 bcf/d, and is a permit for the construction from Alberta Energy Regulator expected to be in service in late 2018. in February 2018 and is expected to be in service in Q2 2019. • The Mountaineer XPress project is a 36-inch, 275 km (171 mile) • The NGTL System currently has a $7.2 billion near-term capi- natural gas pipeline in West Virginia to transport approximate- tal programs for completion by 2021. This includes recently an- ly 2.7 bcf/d of Marcellus and Utica gas supply and is expected nounced $2.4 billion new NGTL expansion, including 375 km to be in service in late 2018. (233 miles) of 16- to 48-inch pipeline, four compression units • The Buckeye XPress project is a 36-inch 103 km (64 miles) totaling 120 MW and associated meter stations and facilities. natural gas pipeline in Ohio and is expected to be in service In March 2017, TCPL filed an application with the NEB for a in 2020. variance to the existing approvals for North Montney project in northeast British Columbia to remove the condition that the • The Gulf XPress project includes construction of seven new project could only proceed once a positive final investment de- compressor stations in Kentucky, Tennessee and Mississippi. cision (FID) is made for the Pacific NorthWest LNG project. In December 2017, it received its certificate of public conve- North Montney is now underpinned by restructured 20-year nience and necessity from the FERC authorizing construction commercial contracts with shippers and is not dependent on, to proceed. It is expected to be in service in late 2018. but still accommodates, the Pacific NorthWest LNG project

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Major Capital Projects (CONTINUED)

proceeding. In May 2018, NEB approved a variance to the pre- • The Tula-Villa de Reyes Pipeline project is a 36-inch, 420 vious issued certificate, which would allow construction to km (261 mile) natural gas pipeline in Mexico, supported by a start on the $1.4 billion North Montney project. The in-service 25-year contract with Mexico’s state-owned power utility. It is date is planned for mid-2019. expected to be in service in late 2018. • The Napanee Generating Station is a 900 MW natural gas– • The Sur de Texas Pipeline project (60% ownership interest) is fired combined-cycle power plant in Eastern Ontario sup- a 42-inch, 800 km (497 mile) natural gas pipeline in Mexico, ported by a 20-year contract with the IESO, with completion supported by a 25-year contract with Mexico’s state-owned expected in Q4 2018. power utility. It is expected to be in service in late 2018. • Bruce Power entered into an agreement in December 2015 with the IESO to extend the operating life of the facility to the end The following table summarizes TCC’s medium- to longer-term of 2064. The share of near-term capital program is $0.9 billion. large-scale projects. The capital cost composition of these proj- • The Tuxpan-Tula Pipeline project is a 36-inch 300 km ects by segment is Liquids Pipelines (50%), Canadian Natural (186 mile) natural gas pipeline in Mexico with 866 million cu- Gas Pipelines (28%) and Energy (22%). bic feet per day of contracted capacity, supported by a 25-year contract with Mexico’s state-owned utility. It is expected to be in service in 2019.

Medium- to Longer-Term Projects Expected

($ billions) Capital Invested Status as at In-Service Cost to Date Mar. 31, 2018 Date Revenue Stream Heartland Pipeline & TC Terminals (Liquids Pipe) 0.9 0.1 Development 2019+ Largely contracted Grand Rapids Phase 2 (Liquids Pipe) 0.7 - Development 2019+ Largely contracted Bruce Power (Energy) 5.3 - Development 2020-2033 Largely contracted Keystone XL* (Liquids Pipe) (USD) 8.0 0.3 Development To be determined Largely contracted Keystone Hardisty Terminal (Liquids Pipe) 0.3 0.1 Development To be determined Largely contracted Coastal GasLink (B.C.) (Canadian Gas Pipe) 4.8 0.4 Development 2019+ Fully contracted NGTL System- Merrick (Canadian Gas Pipe) 1.9 - Development 2021+ Largely contracted Total Large Scale Projects 21.9 0.9 Foreign Exchange impact 2.3 0.1 Total (CAD) 24.2 1.0 Small to Medium-Sized & Large Scale Projects (CAD) 45.5 8.3 * Invested to date reflects amount remaining after impairment charge.

• The Heartland Pipeline and TC Terminals will consist of a LNG Canada joint venture participants announced a delay to 200 km (125 mile) crude oil pipeline to connect the new TCC FID for the proposed LNG facility. In November 2017, Coastal Terminals facility in the Edmonton/Heartland crude oil mar- GasLink files an amendment to the Environmental Assessment ket region to facilities in Hardisty, Alberta. The construction Certificate for an alternate route on portion of the pipeline. A has been delayed from the previous in-service expected date decision from B.C. Environment Assessment Office is expected in 2017. in 2018. • The Coastal GasLink Pipeline project will initially transport • The NGTL System Merrick Mainline Pipeline (Merrick) project up to 1.7 bcf/d of natural gas 670 km (416 miles) from the North would be an extension from the existing Groundbirch Mainline Montney gas-producing region near Dawson Creek, British section of the NGTL System, beginning near Dawson Creek to Columbia, to the proposed LNG Canada liquefied natural gas its endpoint near Summit Lake, British Columbia. NGTL has (LNG) export facility near Kitimat, British Columbia, to be signed agreements for 1.9 bcf/d of firm service to ship natural owned by Shell Canada Limited and its partners. The project gas to the inlet of the proposed Pacific Trail Pipeline terminat- is dependent on regulatory approval and a positive final invest- ing near Kitimat. Merrick is dependent on regulatory approval ment decision from the Kitimat LNG project. In July 2016, the and a positive FID from the Kitimat LNG project.

Corporate Finance: Energy June 18, 2018 Rating Report | TransCanada Corporation & TransCanada PipeLines Limited DBRS.COM 10

Business Segments

12 mos. ended Segmented EBITDA 3 mos. ended March. 31 March. 31 Year ended December 31

(CAD millions, US GAAP, DBRS-adjusted) 2018 2017 2018 2017 2016 2015 Natural Gas Pipelines Canadian Mainline 193 9% 247 12% 989 13% 1,043 14% 1,105 17% 1,193 20% NGTL System 271 13% 230 12% 1,037 14% 996 13% 968 15% 900 15% Other Canadian pipelines 30 1% 27 1% 113 2% 110 1% 116 2% 131 2% Business Development Costs 0 0% 0 0% (5) 0% (5) 0% (7) 0% (8) 0% Cdn Gas Pipe EBITDA before extras 494 24% 504 25% 2,134 28% 2,144 29% 2,182 33% 2,216 37% Columbia Pipeline 363 18% 300 15% 1,093 15% 1,030 14% 443 7% ANR Pipeline and Storage 178 9% 162 8% 537 7% 520 7% 425 6% 282 5% Great Lakes (66.7% owned) 44 2% 36 2% 92 1% 83 1% 80 1% 81 1% TC Pipelines, LP (25.5% owned) 49 2% 42 2% 150 2% 143 2% 156 2% 136 2% Other (Bison, GTN, Iroquis, Portland) 19 1% 37 2% 122 2% 140 2% 98 1% 112 2% Other (non-controlling interests) 149 7% 143 7% 450 6% 443 6% 484 7% 375 6% Business Development Costs 0 0% 0 0% (3) 0% (3) 0% (4) 0% (15) 0% U.S. Gas Pipe EBITDA bef. Extras 804 39% 720 36% 2,441 33% 2,357 32% 1,682 25% 970 16% Tamazunchale 39 2% 38 2% 147 2% 146 2% 140 2% 140 2% Topolobampo 56 3% 53 3% 207 3% 204 3% 108 2% (4) 0% Guadalajara 24 1% 22 1% 90 1% 88 1% 89 1% 90 2% Mazatlan 25 1% 21 1% 89 1% 85 1% 7 0% (3) 0% Sur de Texas 11 1% 5 0% 16 0% 10 0% 0 0% 0 0% Other Mexico pipelines 5 0% 0 0% (9) 0% (14) 0% (4) 0% 5 0% Business Development Costs 0 0% 0 0% 0 0% 0 0% (7) 0% (16) 0% Mexico Gas Pipe EBITDA bef. Extras 160 8% 140 7% 539 7% 519 7% 332 5% 213 4% Keystone Pipeline System 340 16% 306 15% 1,317 18% 1,283 17% 1,155 17% 1,332 22% Intra-Alberta pipelines 39 2% 0 0% 72 1% 33 0% 0 0% 0 0% Liquids marketing & BD 52 3% 6 0% 78 1% 32 0% (3) 0% (24) 0% Subtotal (Liquids Pipelines) 431 21% 312 16% 1,467 20% 1,348 18% 1,152 17% 1,308 22%

Energy Western Power 37 2% 30 2% 107 1% 100 1% 74 1% 71 1% Eastern Power 82 4% 94 5% 332 4% 344 5% 349 5% 389 7% Bruce Power 54 3% 91 5% 397 5% 434 6% 293 4% 285 5% Cdn Power EBITDA before extras 173 8% 215 11% 836 11% 878 12% 716 11% 745 12% U.S. Power EBITDA before extras 8 0% 72 4% 66 1% 130 2% 522 8% 525 9% Gas Storage EBITDA before extras 7 0% 21 1% 41 1% 55 1% 58 1% 14 0% Business Development Costs (4) 0% (3) 0% (34) 0% (33) 0% (15) 0% (30) -1% Subtotal (Energy) 184 9% 305 15% 909 12% 1,030 14% 1,281 19% 1,254 21% Subtotal of segments 2,073 100% 1,981 100% 7,490 100% 7,398 100% 6,629 100% 5,961 100% Corporate and Other 73 48 252 227 319 264 EBITDA before extras 1 2,146 2,029 7,742 7,625 6,948 6,225 Extraordinary items (136) (62) 226 300 (1,984) (2,995) EBITDA 1 2,010 1,967 7,968 7,925 4,964 3,230 1 EBITDA includes dividends/distributions received from equity investments.

Corporate Finance: Energy June 18, 2018 Rating Report | TransCanada Corporation & TransCanada PipeLines Limited DBRS.COM 11

Business Segments (CONTINUED)

1. Natural Gas Pipelines – Canada (28% of EBITDA for the services are provided under tariffs that set limits on the rates LTM ending March 31, 2018) for services and allow for non-discriminatory negotiations and discounts. The value of ANR’s storage services is based on Canadian Mainline (13% of segment EBITDA; 7% of net in- market conditions that could result in reduced rates and terms. come before extras) In January 2016, ANR Pipeline filed a Section 4 Rate Case that • The Canadian Mainline extends 14,077 km (8,747 miles) from requests an increase to ANR’s maximum transportation rates. the Alberta/Saskatchewan border to the Québec/Vermont In February 2016, FERC issued an order that accepted and border and connects with other pipelines in Canada and in the suspended the rate and tariff changes effective August 1, 2016, United States. subject to a refund and the outcome of a hearing. ANR reached a settlement with its shippers effective August 1, 2016. Per the • Natural gas throughput was 4.4 bcf/d in 2017, in line with settlement, transmission reservation rates will increase by 4.5 bcf/d in 2016. 34.8% and storage rates will remain the same for contracts one • Canadian Mainline net income (before extras) and EBITDA to three years in length, while increasing slightly for contracts decreased by 4% and 6%, respectively, in 2017 compared with of less than one year and decreasing slightly for contracts more 2016 primarily because of a lower average investment base, than three years in duration. partially offset by higher incentive earnings. • ANR’s EBITDA rose significantly by 25% on a U.S.-dollar ba- • Canadian Mainline net income (before extras) and EBITDA sis (22% on a Canadian-dollar basis) in 2017 compared with decreased by 29% and 22%, respectively, in Q1 2018 compared 2016 mainly driven by higher ANR transportation revenue as with Q1 2017 primarily because of no incentive earnings in a result of favorable FERC-approved rate settlement, effective 2018 pending a NEB decision on the 2018-2020 Tolls Review. August 1, 2016. • ANR’s EBITDA increased by 16% on a U.S.-dollar basis (10% NGTL System (14% of segment EBITDA; 12% of net income on a Canadian-dollar basis) in Q1 2018 compared with Q1 2017 before extras) mainly because of additional contract sales. • The NGTL System connects the Canadian Mainline and Foothills systems, along with third-party natural gas pipelines, CPG (15% of segmented EBITDA for the LTM ending through 24,320 km (15,112 miles) of pipeline, mostly within March 31, 2018) Alberta and partly in British Columbia. • Columbia operates approximately 24,500 km (15,200 miles) of • NGTL is well positioned to link WCSB supply to proposed natural gas pipelines, 285 bcf of natural gas storage facilities Canadian West Coast LNG projects. and related midstream assets. • Natural gas throughput on the NGTL System remained elevat- • CPG’s EBITDA rose significantly in 2017 compared with 2016 ed at 11.4 bcf/d in 2017 (11.1 bcf/d in 2016). The increase was mainly because of a full year contribution from CPG. largely a result of rising WCSB shale gas production and com- • CPG’s EBITDA increased by 16% on a U.S.-dollar basis (10% pleted expansion projects. on a Canadian-dollar basis) in Q1 2018 compared with Q1 2017 • NGTL System net income (before extras) and EBITDA were mainly because of Columbia Gas and Columbia Gulf growth higher by 11% and 3%, respectively, in 2017 compared with projects placed in service. 2016 mainly as a result of a higher average investment base. • NGTL System net income (before extras) and EBITDA rose by Columbia Gas Transmission owns and operates an interstate 12% and 18%, respectively, in Q1 2018 compared with Q1 2017 natural gas transportation pipeline and storage system, which mainly because of a higher average investment base reflecting operates from the Gulf Coast and from the Appalachian region to continued expansion of the system. markets in the Midwest, Atlantic and Northeast regions.

Columbia Gulf owns and operates a long-haul interstate natu- 2. Natural Gas Pipelines – United States (33% of EBITDA for the LTM ending March 31, 2018) ral gas transportation pipeline system now transitioning and expanding to accommodate supply from the Appalachian basin ANR (7% of segment EBITDA) and its interconnect with Columbia Gas and other pipelines to • ANR consists of 15,109 km (9,388 miles) of pipeline transporting deliver gas across Gulf Coast markets. natural gas primarily from Texas and Oklahoma on its southwest leg and in the Gulf of Mexico on its southeast leg to Wisconsin, Millennium operates and owns 47.5% of Millennium pipeline, Michigan, Illinois, Ohio and Indiana. ANR also connects with which transports natural gas from Marcellus shale to markets in other pipelines, providing access to other gas sources. New York and the Hudson Valley, New York. • ANR owns and operates underground gas-storage facilities in Crossroads owns and operates an interstate natural gas pipeline Michigan, with 250 bcf of capacity. in Indiana and Ohio. • ANR is regulated by FERC on a complaint basis with an esti- mated 15% ROE. The last rate settlement began in 1997. Pipeline

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Business Segments (CONTINUED)

Columbia Midstream provides natural gas services, including • Liquids Pipelines EBIT and EBITDA increased by 21% gathering, treating, conditioning, processing, compressing and and 17%, respectively, in 2017 compared with 2016 primar- liquids handling in the Appalachian basin. ily because of (1) higher uncontracted volumes on Keystone Pipeline, (2) higher earnings from the liquids marketing busi- Hardy Storage operates and owns 50% of Hardy Storage, a nat- ness and (3) contribution from intra-Alberta pipelines, Grand ural gas storage field in the Hardy and Hampshire counties in Rapids and Northern Courier, which were placed in service in West Virginia. second half of 2017, partially offset by higher business develop- ment activities on Keystone XL and a weaker U.S. dollar. 3. Natural Gas Pipelines – Mexico (7% of EBITDA in the LTM • Liquids Pipelines EBIT and EBITDA increased significant- ending March 31, 2018) ly by 48% and 38%, respectively, in Q1 2018 compared with • The 315 km (196 mile) Guadalajara Pipeline transports natural Q1 2017 for the same reasons above. gas from Manzanillo, Colima, to Guadalajara, Jalisco. • The 430 km (267 mile) Mazatlán Pipeline transports natural 5. Energy (12% of EBITDA for the LTM ending March 31, 2018) gas from El Oro, Sinaloa, to Mazatlán, Sinaloa, in Mexico. As at the end of March 31, 2018, TCPL’s operating power plants • The 375 km (233 mile) Tamazunchale Pipeline transports nat- have net capacity of approximately 7,000 MW supported by ural gas from Naranjos, Veracruz, to El Sauz, Querétaro. low-cost base-load generation and long-term contracts with • The 560 km (348 mile) Topolobampo Pipeline transports natu- relatively stable earnings and cash flow. In addition, the segment ral gas from interconnections with third-party pipelines in El includes 118 bcf in total of unregulated natural gas storage capac- Oro and El Encino, Chihuahua, to Topolobampo. ity in Alberta contracted with a third party, with about one-third of all storage capacity in the province. • EBITDA rose significantly in 2017 compared with 2016 mainly a. Canadian Power (11% of segment EBITDA) because of an incremental contribution from Topolobampo and Maztlan, which were placed in service in second half of 2016. Bruce Power (Ontario) (5% of segment EBITDA) • Bruce Power is a nuclear power generation facility com- • EBITDA rose modestly in Q1 2018 mainly because of higher prising eight nuclear units with a combined total capacity revenue from operations and higher equity income from Sur of approximately 6,400 MW. de Texas pipeline. • On December 3, 2015, Bruce Power entered into an agree- ment with the IESO to extend the expected useful life of 4. Liquids Pipelines (20% of EBITDA for the LTM ending the facility to 2064. The amended agreement allows in- March 31, 2018) vestment in life-extension activities for Units 3 through 8 Keystone Pipeline System (Base Keystone) and Gulf Coast to support a long-term refurbishment program. • Phase 1 of Base Keystone, which extends from Hardisty to Wood River, Illinois, and Patoka, Illinois, had an initial nomi- • The estimated share of investment of the Asset nal capacity of 435,000 b/d and was placed into commercial Management program is approximately $2.5 billion. Over service on June 30, 2010. the 2020 to 2033 timeframe, the investment in the Major Component Replacement for Unit 3 through Unit 8 is ap- • Phase 2 of Base Keystone, which expanded nominal capacity to proximately a further $4.0 billion. 591,000 b/d and extended the pipeline to Cushing, Oklahoma, was placed into commercial service in Q1 2011. • As part of the life-extension agreement, Bruce Power be- gan receiving a fixed price $59.75 per MW hour for all • The Gulf Coast Pipeline, which is an extension of Base units effective April 1, 2018. The price is subject to adjust- Keystone from Cushing to Nederland, Texas, in the U.S. Gulf ments for return of and on capital invested, along with Coast, was placed into service in January 2014 with an initial other pricing adjustments that allow for better matching crude oil capacity of up to 700,000 b/d and an ultimate capac- revenues and costs over the long term. ity of 830,000 b/d. • Bruce Power equity income rose significantly by • Construction of the Cushing Marketlink project facilities, $141 million (48%) in 2017 compared with 2016 mainly be- which transport crude oil from Cushing to the U.S. Gulf Coast cause of higher volumes as a result of fewer outage days. refining market and form part of Base Keystone, was complet- ed in September 2014. • Bruce Power equity income decreased modestly by $37 million (41%) in Q1 2018 compared with Q1 2017, • The Houston Lateral extends the Keystone Pipeline System mainly reflecting lower volumes because of increased both to Houston-area refineries, and the Houston Terminal has ini- tial storage capacity for 700,000 barrels of crude oil upon, was planned and unplanned outage days. placed in service in August 2016. • On November 16, 2017, the Keystone pipeline was temporarily shut down after a leak was detected in Marshall County, South Dakota. On November 29, 2017, the pipeline was returned to service at a reduced pressure in affected section.

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Business Segments (CONTINUED)

Power Generation Capacity at Mar. 31, 2018 Western Power* (MW) Fuel Type Bruce Power (MW) Fuel Type Bear Creak 100 Natural gas Bruce Power 3 3,099 Nuclear Carseland 95 Natural gas Total Power Generation 6,983 Coolidge (Arizona) (contract to 2031) 575 Natural gas MacKay River 205 Natural gas Natural gas 3,519 50% Redwater 46 Natural gas Nuclear 3,099 44% Western Power 1,021 Wind 365 5% * All Western Power (except Coolidge) is in Alberta. Total Power Generation 6,983 100% Eastern Power Napanee (20-year contract)** 900 Natural gas Halton Hills (contract to 2030) 683 Natural gas Western Power 1,021 15% Bécancour (contract to 2026) 550 Natural gas Eastern Power 5,962 85% Cartier Wind (contracts to 2032) 1 365 Wind Total Power Generation 6,983 100% Portlands Energy (contract to 2029) 2 275 Natural gas Grandview (contract to 2025) 90 Natural gas Eastern Power 2,863

** Under construction; contract is from in-service date. 1 62% share of the total 590 MW capacity. 2 50% share of the total 550 MW capacity. 3 48.4% share of power generation capacity after the merger of Bruce A and Bruce B through Bruce Power LP.

Eastern Power (4% of segment EBITDA) Western Power (1% of segment EBITDA) • All Eastern Power assets are supported by long-term • Western Power EBITDA increased by $26 million (35%) in contractual arrangements. 2017 compared with 2016 because of the termination of the • Eastern Power EBITDA decreased marginally by Alberta PPAs. $5 million (1%) in 2017 compared with 2016 mainly be- • Western Power EBITDA increased by $7 million in Q1 2018 cause of lower contributions from the sale of unused natu- compared with Q1 2017 largely because of higher realized ral gas transportation. prices on higher volumes. • Eastern Power EBITDA decreased by $12 million (13%) in Q1 2018 compared with Q1 2017 mainly as a result of the b. U.S. Power (1% of segment EBITDA) sale of Ontario solar assets in December 2017. • U.S Power EBITDA decreased materially in 2017 and Q1 2018 as a result of the sales of U.S. Power generation assets in Q2 2017.

Corporate Finance: Energy June 18, 2018 Rating Report | TransCanada Corporation & TransCanada PipeLines Limited DBRS.COM 14

TransCanada Corporation Consolidated Balance Sheet (CAD millions, US GAAP, DBRS-adjusted) March 31 December 31 March 31 December 31 Assets 2018 2017 2016 Liabilities and Equity 2018 2017 2016 Cash and equivalents 1,267 1,089 1,016 Notes payable 3,658 1,763 774 Accounts receivable 2,208 2,522 2,075 A/P and accrued liab. 4,880 5,248 5,068 Inventories 384 378 368 L.t. debt due in one year 3,406 2,866 1,838 Other current assets 718 691 4,625 Current liabilities 11,944 9,877 7,680 Current Assets 4,577 4,680 8,084 Other long-term liabs. 5,185 5,048 3,304 Deferred income taxes 5,529 5,403 7,662 Property, plant and equip., net 59,313 57,277 54,475 Long-term debt 30,995 31,875 38,312 Equity investments 6,362 6,366 6,544 Jnr. subordinated notes 7,177 7,007 3,931 Goodwill 13,483 13,084 13,958 Noncontrolling interests 1,981 1,852 2,905 Regulatory assets 1,334 1,376 1,322 Preferred shares 3,980 3,980 3,980 Intangibles and other assets 3,941 3,318 3,668 Common equity 22,219 21,059 20,277 Total 89,010 86,101 88,051 Total 89,010 86,101 88,051

12 mos. ended Balance Sheet and Liquidity Ratios 3 mos. ended March 31 March 31 Year ended December 31 (CAD millions, US GAAP, DBRS-adjusted) 2018 2017 2018 2017 2016 2015 Current ratio 0.38 0.88 0.38 0.47 1.05 0.53 Net debt & equivalents/capital 58.8% 61.9% 58.8% 58.9% 60.5% 63.6% Total debt & equivalents/capital 59.5% 62.4% 59.5% 59.5% 61.1% 64.2% Adj. total debt & equivalents/capital 2 n/a n/a n/a 59.8% 61.5% 65.5% Common equity/capital 31.5% 29.3% 31.5% 31.6% 29.1% 27.5% Cash flow/total debt & equivalents 14.6% 12.7% 12.7% 12.8% 10.8% 13.6% Adj. cash flow/total debt & equivalents 2 n/a n/a n/a 12.8% 10.9% 13.1% (Cash flow - total dividends)/capex 0.56 0.55 0.42 0.42 0.56 0.71 Common divs./net income (before extras) 67.5% 72.7% 74.7% 76.4% 78.2% 79.6% Pref. share divs./net income (before extras) 4.4% 5.5% 5.3% 5.6% 4.9% 5.1% Common & pref. divs./net income (before extras) 71.9% 78.2% 79.9% 82.0% 83.1% 84.6% Dividends (common, pref. & NCI)/cash flow 29.8% 30.2% 33.2% 33.4% 39.2% 37.9%

Coverage Ratios (Times) EBIT interest coverage 1 3.03 2.88 2.60 2.56 2.55 2.75 EBITDA interest coverage 1 4.04 3.84 3.55 3.51 3.54 3.84 Fixed-charges coverage (EBIT based) 1 2.75 2.60 2.37 2.33 2.37 2.55 Cash flow interest coverage 4.05 3.76 3.60 3.53 3.46 3.92

Profitability Ratios (before extras.) Operating margin 40.2% 38.2% 34.8% 34.3% 33.2% 32.3% Profit margin 26.6% 21.9% 22.4% 21.2% 17.7% 16.3% Return on common equity 16.1% 13.8% 13.4% 13.0% 12.3% 11.4% Return on capital 7.0% 6.0% 6.1% 6.0% 5.6% 5.4% Note: NCI = Noncontrolling Interests. n/a = not available. 1 EBIT and EBITDA include dividends/distributions received from equity investments. 2 Includes operating leases treated as debt.

Corporate Finance: Energy June 18, 2018 Rating Report | TransCanada Corporation & TransCanada PipeLines Limited DBRS.COM 15

12 mos. ended Segmented EBIT 3 mos. ended March 31 March 31 Year ended December 31 ($ millions) 2018 2017 2018 2017 2016 2015 Natural Gas Pipelines 253 282 1,207 1,236 1,307 1,367 Liquids Pipelines 348 235 1,152 1,039 860 1,025 Energy 152 265 766 879 979 913 Corporate 858 737 2,544 2,423 1,863 1,155 EBIT before extras 1 1,611 1,519 5,669 5,577 5,009 4,460

Selected Operating Statistics Canadian Mainline average investment base $3,817 $4,103 n/a $4,184 $4,441 $4,784 NGTL System average investment base $9,091 $7,853 n/a $8,385 $7,451 $6,698 Canadian Mainline volumes (Bcf/day) 0.0 0.0 n/a 4.4 4.5 4.4 NGTL System volumes (Bcf/day) 0.0 0.0 n/a 11.4 11.1 10.6 ANR System volumes (Bcf/day) 5,696 5,983 n/a 24,368 61,543 65,345 Energy sales volumes (GWh) 14,346 12,862 n/a 61,543 65,345 57,348 Note: NCI = Noncontrolling Interests. n/a = not available. 1 EBIT and EBITDA include dividends/distributions received from equity investments. 2 Includes operating leases treated as debt.

Corporate Finance: Energy June 18, 2018 Rating Report | TransCanada Corporation & TransCanada PipeLines Limited DBRS.COM 16

Rating History

Current 2013–2017 2012 2009–2011 2007–2008 2006 TransCanada PipeLines Limited Issuer Rating A (low) A (low) A NR NR NR Unsecured Debentures & Notes A (low) A (low) A A A A Junior Subordinated Notes* BBB BBB BBB (high) BBB (high) BBB (high) NR Commercial Paper R-1 (low) R-1 (low) R-1 (low) R-1 (low) R-1 (low) R-1 (low) TransCanada Corporation Preferred Shares - Cumulative Pfd-2 (low) Pfd-2 (low) Pfd-2 (low) Pfd-2 (low) NR NR

* The Junior Subordinated Notes rating of TransCanada PipeLines Limited pertains to the Junior Subordinated Notes that are due in 2067.

Previous Action • “DBRS Confirms Ratings of TransCanada Corporation and Subsidiaries,” June 9, 2017.

Related Research • “DBRS Comments on Nebraska PSC Decision on TransCanada’s Keystone XL,” November 20, 2017. • “DBRS Comments on TransCanada’s Decision to Cancel Energy East,” October 5, 2017. • “DBRS Comments on TransCanada’s Strategic Initiatives Announcement,” November 1, 2016. • Trans Québec & Maritimes Pipeline Inc.: Rating Report, November 20, 2017. • NOVA Gas Transmission Ltd.: Rating Report, July 5, 2017.

Authorized Principal CP Limit Authorized Principal CP Limit

• TCPL: $1.0 billion and USD 2.0 billion.

Previous Report

• TransCanada Corporation and TransCanada PipeLines Limited: Rating Report, June 16, 2017.

Corporate Finance: Energy June 18, 2018 Rating Report | TransCanada Corporation & TransCanada PipeLines Limited DBRS.COM 17

Notes: All figures are in Canadian dollars unless otherwise noted.

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Corporate Finance: Energy June 18, 2018 Research Update: TransCanada Corp., TransCanada PipeLines Ltd. Downgraded To 'BBB+' From 'A-'; Outlook Stable

Primary Credit Analyst: Gerald F Hannochko, Toronto + (416) 507-2589; [email protected]

Secondary Contact: Yousaf Siddique, CFA, Toronto (1) 416-507-2559; [email protected]

Table Of Contents

Overview

Rating Action

Rationale

Outlook

Ratings Score Snapshot

Related Criteria

Ratings List

WWW.STANDARDANDPOORS.COM/RATINGSDIRECT MAY 1, 2018 1 Research Update: TransCanada Corp., TransCanada PipeLines Ltd. Downgraded To 'BBB+' From 'A-'; Outlook Stable

Overview

• We believe that TransCanada Corp. (TCC) will not achieve adjusted funds from operations (AFFO)-to-debt of 18%, a requirement we set for the 'A-' rating. • In addition, the company has an increasing U.S. asset portfolio that will account for 35%-40% of EBITDA by 2020, and that TCC's credit measures are weaker than many lower-rated diversified U.S. peers. • As a result, we are lowering our ratings on TCC and its subsidiary TransCanada PipeLines Ltd., including our long-term corporate credit rating on each to 'BBB+' from 'A-'. • The stable outlook reflects our view that, over the next two years, AFFO-to-debt will be in the 15%-17% range, and debt-to-EBITDA will be approximately 4.5x.

Rating Action

On May 1, 2018, S&P Global Ratings lowered its ratings on TransCanada Corp. (TCC) and its subsidiary TransCanada PipeLines Ltd., including its long-term corporate credit rating on both to 'BBB+' from 'A-'. The outlook is stable.

At the same time, we lowered our global and Canadian national scale preferred share ratings to 'BBB-' and 'P-2(Low)' from 'BBB' and 'P-2' respectively. We also lowered our ratings on the senior unsecured debt to 'BBB+' from 'A-' and the junior subordinated debt to 'BBB-' from 'BBB'.

Finally, we affirmed our short term and commercial paper rating at 'A-2'.

Rationale

The downgrade reflects our view that TCC in the next two years will not achieve adjusted funds from operations (AFFO)-to-debt of 18%, a requirement we set for the 'A-' rating, after the company acquired Columbia Pipeline Group Inc. in 2016. This increased requirement resulted from the Columbia assets' somewhat weaker contract profile and higher counterparty risk relative to TCC's existing regulated natural gas pipelines, which dilutes the quality of the midstream asset base's quality. The downgrade also reflects that the company has an increasing U.S. asset portfolio that will account for 35%-40% of EBITDA by 2020, and that TCC's credit measures are weaker than many of its

WWW.STANDARDANDPOORS.COM/RATINGSDIRECT MAY 1, 2018 2 Research Update: TransCanada Corp., TransCanada PipeLines Ltd. Downgraded To 'BBB+' From 'A-'; Outlook Stable lower-rated diversified U.S. peers.

While we expect that TCC's cash flows will improve from the expanding Columbia assets along with a number of projects entering service in the next few years, we believe the company's very large capital program over the next three years of about C$19 billion prevents it from hitting the 18% metric. We expect the funding mix of these expenditures could include additional leverage along with equity issuance and assets sales; and would be largely based on management's internal target of 5x debt to EBITDA and 15% FFO-to-debt.

We expect AFFO-to-debt to improve to 15%-17% in the next two years from approximately 13% in 2017, mainly stemming from higher contracted revenues from the Mainline and Nova Gas Transmission LTd. systems, and growth in the Columbia Pipeline. However, our forecast excludes large growth projects such as Keystone XL and Coastal GasLink, which have a combined budget of about C$13 billion. We expect TCC to fund these projects in a manner that would keep the balance sheet in line with its stated financial targets.

Our base-case scenario includes the following assumption: • Dividends of C$2.5 billion-C$3.0 billion from 2018 to 2020 • Capital expenditures of C$9.0 billion in 2018, C$5.1 billion in 2019, and C$5.0 billion in 2020 • Real GDP growth in Canada of about 1.9% in 2017 and 2018 • Issuance of common stock in 2018, either through the at-the-market equity program or the company's dividend reinvestment program

Based on these assumptions, we arrive at the following credit measures: • Debt-to-EBITA of 4.5x-5.0x in 2018, 4.0x-4.5x in 2019, and 4.0x-4.5x in 2020. • FFO-to-debt of 14.75%-15.25% in 2018, 17.0%-17.5% in 2019, and 17.0%-17.5% in 2020.

We continue to view TransCanada as having an excellent business risk profile due to its very strong competitive positioning emanating from its highly diversified assets strategically located in North America. Most of TCC's cash flows come from regulated assets and long-term, fee-based contracts. We expect robust growth of cash flow from assets entering service in the next few years, which supports our business risk profile assessment. We further expect long-term commercial arrangements will support most of these new assets.

TCPL is the ultimate parent to a number of subsidiaries. TCC is TCPL's parent and we consider it core to TCPL, so we equalize the ratings on TCC with those on TCPL. TCC has modest hybrid securities and TCPL represents 100% of TCC's revenues and cash flows.

WWW.STANDARDANDPOORS.COM/RATINGSDIRECT MAY 1, 2018 3 Research Update: TransCanada Corp., TransCanada PipeLines Ltd. Downgraded To 'BBB+' From 'A-'; Outlook Stable

Liquidity We view TransCanada's liquidity as adequate. Sources over uses are greater than 1.2x over the next 12 months. We believe the company will continue to have solid relationships with its banks, a high standing in credit markets, and generally prudent risk management.

Principal liquidity sources include: • AFFO of C$6.0 billion-C$7.0 billion • Cash and short-term investments of about C$1.1 billion as of Dec. 31, 2017 • Credit facility availability of approximately C$9.0 billion • Asset sales, net of acquisitions, of about C$1.0 billion-C$2.0 billion

Principal liquidity uses include: • Committed capital expenditures of about C$9 billion • Dividends of about C$2.4 billion in 2017 • Debt maturities of approximately C$3 billion in 2018

Outlook

The stable outlook reflects our view that AFFO-to-debt over the next two years will be in the 15%-17% range and debt-to-EBITDA will be approximately 4.5x. The outlook also reflects our assumption that the large capital program in 2018 will proceed as planned, which will fuel an increase in EBITDA and lead to improving financial metrics. Our outlook does not include potential projects like Keystone XL or the Coastal GasLink, both of which can significantly affect metrics through the construction period.

Downside scenario A downgrade could occur if AFFO-to-debt declines to 13% and debt-to-EBITDA increases to 5x, which could result from increased debt to finance capital projects or significant delays in projects entering service.

Upside scenario We could upgrade TransCanada if AFFO to debt stays above 18% and debt-to-EBITDA below 4x. This could occur if the company's financial policy is more focused on de-leveraging over the next two years, or if debt financed capital expenditures is lower than expected.

Ratings Score Snapshot

Corporate Credit Rating: BBB+/Stable/--

Business risk: Excellent

WWW.STANDARDANDPOORS.COM/RATINGSDIRECT MAY 1, 2018 4 Research Update: TransCanada Corp., TransCanada PipeLines Ltd. Downgraded To 'BBB+' From 'A-'; Outlook Stable

• Country risk: Very low • Industry risk: Low • Competitive position: Excellent

Financial risk: Significant • Cash flow/Leverage: Significant

Anchor: a-

Modifiers • Diversification/Portfolio effect: Neutral (no impact) • Capital structure: Neutral (no impact) • Financial policy: Neutral (no impact) • Liquidity: Adequate (no impact) • Management and governance: Satisfactory (no impact) • Comparable rating analysis: Negative (-1 notch)

Related Criteria

• Criteria - Corporates - General: Reflecting Subordination Risk In Corporate Issue Ratings, March 28, 2018 • General Criteria: Methodology For Linking Long-Term And Short-Term Ratings , April 7, 2017 • Criteria - Corporates - General: Methodology And Assumptions: Liquidity Descriptors For Global Corporate Issuers, Dec. 16, 2014 • Criteria - Corporates - Industrials: Key Credit Factors For The Unregulated Power And Gas Industry, March 28, 2014 • Criteria - Corporates - Industrials: Key Credit Factors For The Midstream Energy Industry, Dec. 19, 2013 • General Criteria: Methodology: Industry Risk, Nov. 19, 2013 • General Criteria: Country Risk Assessment Methodology And Assumptions, Nov. 19, 2013 • General Criteria: Group Rating Methodology, Nov. 19, 2013 • Criteria - Corporates - General: Corporate Methodology, Nov. 19, 2013 • Criteria - Corporates - General: Corporate Methodology: Ratios And Adjustments, Nov. 19, 2013 • General Criteria: Methodology: Management And Governance Credit Factors For Corporate Entities And Insurers, Nov. 13, 2012 • General Criteria: Criteria Clarification On Hybrid Capital Step-Ups, Call Options, And Replacement Provisions, Oct. 22, 2012

WWW.STANDARDANDPOORS.COM/RATINGSDIRECT MAY 1, 2018 5 Research Update: TransCanada Corp., TransCanada PipeLines Ltd. Downgraded To 'BBB+' From 'A-'; Outlook Stable

• General Criteria: Use Of CreditWatch And Outlooks, Sept. 14, 2009 • Criteria - Insurance - General: Hybrid Capital Handbook: September 2008 Edition, Sept. 15, 2008

Ratings List

Downgraded; Outlook Action To From TransCanada Corp. NOVA Gas Transmission Ltd. ANR Pipeline Co. Corporate Credit Rating BBB+/Stable/-- A-/Negative/--

TransCanada PipeLines Ltd. TransCanada PipeLine USA Ltd. Corporate Credit Rating BBB+/Stable/A-2 A-/Negative/A-2

Ratings Lowered To From TransCanada Corp. Preferred Stock Global Scale BBB- BBB Canada Scale P-2(Low) P-2

ANR Pipeline Co. NOVA Gas Transmission Ltd. TransCanada PipeLines Ltd. Senior Unsecured BBB+ A-

TransCanada PipeLines Ltd. TransCanada Trust Junior Subordinated BBB- BBB

Ratings Affirmed

TransCanada American Investments Ltd TransCanada PipeLines Ltd. Commercial Paper A-2

Certain terms used in this report, particularly certain adjectives used to express our view on rating relevant factors, have specific meanings ascribed to them in our criteria, and should therefore be read in conjunction with such criteria. Please see Ratings Criteria at www.standardandpoors.com for further information. Complete ratings information is available to subscribers of RatingsDirect at www.capitaliq.com. All ratings affected by this rating action can be found on S&P Global Ratings' public website at

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